20180215INT to Staff Attach 26 AGA Report Aldyl A Piping.pdf

Information about Aldyl® “A” Piping

This AGA White Paper provides a compilation of information publicly available regarding Aldyl® “A” piping.

Copyright © 2017 American Gas Association
All Rights Reserved

White Paper
Aldyl A Task Group
12-02 Prepared by the AGA Operating Section
Aldyl A Task Group
400 North Capitol St., N.W., 4th Floor
Washington, DC 20001
U.S.A.
Phone: [phone]
Fax: [phone]
Web site: www.aga.org
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Copyright © 2017, American Gas Association, All Rights Reserved.
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Prepared by
PLASTIC MATERIALS COMMITTEE
ALDYL A TASK GROUP
Mary A. Bartholomew, Southwest Gas Corporation
Kris Busko, formerly with Avista Utilities
Hamet Diop, Pacific Gas and Electric Company
Kevin Dugan, Vectren Corporation
Richard H. Hauter, New Jersey Natural Gas Company
E. Reid Hess, Questar Gas Company
John A. Kasinski, National Fuel Gas Distribution Corporation
Saadat U. Khan, National Grid
Tim Lauder, Public Service Electric and Gas Company
Joel Martell, Southwest Gas Corporation
Conrad A. Miller, Xcel Energy Inc.
Stephen Misketis, Enbridge Gas Distribution Inc.
Brian W. Moidel, Dominion East Ohio
Edward Newton, San Diego Gas & Electric Co. /Southern California Gas Co.
Edward Ostrovich, Atmos Energy Corporation
Steven E. Powell, ONE Gas
Matteo Rossi, Pacific Gas and Electric Company
Parashar N. Sheth, National Grid
Michael Whitby, Avista Corporation
Michael B. Zandaroski, CenterPoint Energy
AGA Staff
Philip Bennett (Retired)
Vanessa George
Andrew Lu
Kate Miller
The Task Group acknowledges the work of Southern California Gas Company and Avista Utilities for
accumulating and summarizing information contained in this paper. Mr. Gene Palermo, Palermo Plastics
Pipe Consulting also provided information for this document.
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I. EXECUTIVE SUMMARY .......................................................................................................... 7
II. HISTORY OF DUPONT ALDYL® A PIPING ........................................................................... 7
III. DUPONT COMMUNICATES POTENTIAL ISSUES TO ALDYL A CUSTOMERS ................. 9
IV. NATIONAL TRANSPORTATION SAFETY BOARD ............................................................. 11
NTSB CONCLUSIONS........................................................................................................... 12
V. PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION ......................... 12
VI. PLASTIC PIPING DATABASE COLLECTION INITIATIVE STATUS REPORT................... 14
VII. POTENTIAL ALDYL A PIPING SYSTEM THREATS............................................................ 14
TOWERS & CAPS..................................................................................................................14
ROCK CONTACT AND SQUEEZE-OFF................................................................................ 14
SERVICES TAPPED FROM STEEL MAINS ......................................................................... 15
VIII. VII. SUMMARY ....................................................................................................................... 15
IX. APPENDIX 1: 1966-1967 DUPONT PHYSICAL PROPERTIES OF ALDYL A PIPE ..........1
X. APPENDIX 2: 1967 AGA PG&E ALDYL-A GAS DISTRIBUTION SYSTEM FROM DESIGN
THROUGH INSTALLATION ……………………………………………………………………………………...
XI. APPENDIX 3: FULL PACKAGE OF ALL DUPONT TECHNICAL BULLETINS
THROUGHOUT THE YEARS……………….
XII. APPENDIX 4: "ALDYL ® "A" PIPING SYSTEMS CONTINUOUS IMPROVEMENTS"
REPORT FROM GENE PALERMO, UPONOR ALDYL COMPANY, CIRCA 1992 ..................................
XIII. APPENDIX 5: DECEMBER 5, 1985 LETTER FROM DUPONT EXPLAINING THE CHANGE
FROM PE 2306 TO PE 2406…………………………….
XIV. APPENDIX 6: SINGLE POINT 80 C, 600 PSI ELEVATED TEMPERATURE TEST FOR
ALDYL ® "A" AND IMPROVED ALDYL ® A………………………….
XV. APPENDIX 7: ALDYL ® A TEHCNICAL DATA BULLETIN 100-200 (1975)………………..
XVI. APPENDIX 8: 1981 LETTER FROM DEPONT INDICATING CHANGE IN ADDITIVE
PACKAGE THAT OCCURRED IN 1980 ………………
XVII. APPENDIX 9: 1982 DUPONT ANNOUNCEMENT AND PRODUCT INFORMATION ON THE
NEW 8" ALDYL "A" PIPING SYSTEM ……………………….
XVIII. APPENDIX 10: 1986 LETTER FROM DUPONT INDICATING THE CHANGE IN UV
EXPOSURE TIME FROM 1 YEAR TO 2 YEARS ( IN 1984) AND FROM 2 YEARS TO 3 YEARS
( IN 1986)…………………………..
XIX. APPENDIX 11: PLASTIC PIPE FAILURE, RISK, AND THREAT ANALYSIS - GTI REPORT
…………………………………
XX. APPENDIX 12: 1982 LETTER FROM DUPONT TO ITS CUSTOMERS REGARDING LEAKS
DUE TO SLITS IN ALDYL "A" PIPE MADE BEFORE 1973 ………………
XXI. APPENDIX 13: NTSB SPECIAL INVESTIGATION REPORT ……………..
XXII. APPENDIX 14: PHMSA ADVISORY ADB -99-02……………………………
XXIII. APPENDIX 15: PHMSA ADVISORY ADB- 02-07……………
XXIV. APPENDIX 16: PHMSA ADVISORY ADB 07-01 ………………
XXV. APPENDIX 17: US DOT CALL TO ACTION ………………………
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XXVI. APPENDIX 18: 1983 LETTER FORM DUPONT REGARDING THE IMPROVED ALDYL "A"
SERVICE381&+7((
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I. Executive Summary
The Pipeline and Hazardous Materials Safety Administration (PHMSA) has identified some older
polyethylene (PE) materials as being susceptible to brittle-like cracking. Certain vintages of Aldyl®
“A” (Aldyl A) pipe are included in PHMSA’s Advisory Bulletin, ADB-02-07. This report provides a
history of DuPont's Aldyl A natural gas pipe and summarizes DuPont and Federal Agency
communications about the pipe in an effort to increase awareness of natural gas Aldyl A piping
systems.
While Aldyl A was being produced information about various resin names and changes were not
widely distributed. It has only been in recent years that this information has become available. This
document pulls together currently available information to assist operators with understanding
Aldyl A piping.
II. Production History of DuPont Aldyl® A Piping
DuPont began producing and testing medium density Polyethylene (PE) pipe made from the “Aldyl”
A resin in 19611. DuPont's product was designed specifically for use in the natural gas industry. In
the mid-1960’s, there was a great deal of gas industry activity in North America evaluating DuPont’s
Aldyl A Piping System.2 This resulted in DuPont introducing Aldyl A pipe to gas utilities in 19653. PE
pipe was marketed under the Aldyl A name from its introduction in 1965 until production ended in
1999. During that time it underwent several changes to the resin formulation4 and a change in
manufacturer5.
The first resin used to manufacturer Aldyl A pipe was Alathon® 5040, and it was used from 1965 to
1971.
In 1971, DuPont changed the resin to improve resistance to rupture during quick burst testing. This
improved formulation, known as Alathon® 5043, was the primary resin used in DuPont's Aldyl A pipe
from 1971 until 1983. For the Alathon® 5043 resin, DuPont recommended an outdoor storage (UV
exposure) limit of one year.6
1 See Appendix 1, 1966-1967 DuPont Physical Properties for Aldyl A Pipe, Page 5, for the stated year
of the production and testing of the Aldyl A resin.
2 See Appendix 2, 1967 AGA PG&E Aldyl-A Gas Distribution System from Design through Installation,
for gas industry activity in mid-1960’s.
3 See Appendix 3 for full set of Technical Bulletins from DuPont throughout the years. On Page 2 of
the package, DuPont states that Aldyl “A” piping systems have been providing gas utilities with service
since 1965.
4 See Appendix 4, Aldyl® “A” Piping Systems Continuous Improvements, page 21, for chronology of
Resin Formulation Changes for Pipe and Fittings.
5 DuPont produced PE 2306/2406/3406 pipe and fittings from 1965-1999, with the Aldyl A brand name.
Major Resin formulation changes occurred in 1971, 1983, 1989, and 1992. The business was sold to
Uponor in 1991, who produced PE pipe under the Aldyl brand name until 1999.
6 See Appendix 7, Aldyl “A” Technical Bulletin 100-200 (1975), page 11, for outdoor exposure
requirement of one year (for 1965-1983 vintage pipe).
8
In 1980, the additive package was changed from Molybdate Orange to Krolor to improve color
stabilization and UV resistance.7
In November of 1982, DuPont announced the expansion of their Aldyl A PE Piping Systems to include
8” pipe and fitting sizes.8
In 1983, DuPont made another significant change to its Aldyl A resin formulation. The improved
resin, known as Alathon® 5046-C, was marketed as "Improved Aldyl A", and significantly improved
the performance of Aldyl A pipe in its resistance to Slow Crack Growth (SCG) and overall long-term
integrity.
In 1984 DuPont’s recommended outdoor storage (UV exposure) time of the Alathon® 5046-C resin
was changed from one year to two years.9
In 1985, the material designation of Aldyl A pipe was changed from PE 2306 to PE 2406. This change
was the result ASTM creating a new PE resin grade and did not correspond to a change in the Aldyl-A
resin formulation10.
In 1986, the additive package was changed from Krolor to LPIO, which increased the recommended
outdoor storage (UV exposure) time from two years to three years.11
In 1988, DuPont announced another advance in its Aldyl A pipe resin with the introduction of
Alathon 5046-U. This change in resin formulation increased the resistance of the pipe resin to SCG
by another order of magnitude. This product was also marketed as Improved Aldyl A. One utility has
documentation that this formulation did not go into production until 1989, which explains why both
years are referenced.
Uponor Company purchased the Aldyl-A pipe product line during the period of 1991-1992 and Aldyl
A pipe and fittings were marketed under the Uponor name beginning in 1992.
In 1992, Uponor made the final improvement to the Aldyl-A pipe resin with the introduction of
Alathon 5046-O. This change in resin formulation increased the resistance of the pipe resin to SCG
to three times that of the most recently used resin formulation, 5046-U.12
In 1999, Uponor stopped producing Aldyl A pipe.13 Aldyl A fittings were produced for some time
later.
7 See Appendix 8 for 1981 letter from DuPont indicating the change in additive package that occurred
in 1980.
8 See Appendix 9 for 1982 DuPont announcement and product information on the new 8” Aldyl “A”
piping system.
9 See Appendix 10 for 1986 letter from DuPont indicating the change in UV Exposure time from 1 year
to 2 years.
10 See Appendix 5 for December 5, 1985 letter from DuPont explaining change from PE 2306 to PE
2406.
11 See Appendix 4, Aldyl® “A” Piping Systems Continuous Improvements, pages 52-53, for DuPont’s
indication of the change in additive package that occurred in 1986 as well as the change from 2 to 3
year UV exposure time. Also, see Appendix 10 for 1986 letter from DuPont indicating the change in
UV Exposure time from 2 year to 3 years.
12 See Appendix 4, Aldyl® “A” Piping Systems Continuous Improvements, pages 13, for reference.
13 See Appendix 11, Plastic Pipe Failure, Risk, and Threat Analysis, Page 50, for reference.
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The resins used in the production of Aldyl A pipe through 1999 are denoted in Table 1 and includes
the year of manufacture, resin formulation, relative resistance to slow crack growth (stress rupture
testing at 80° C / 120 psig for accelerated life testing), and summary notes.
Years of
Manufacture Pipe Resin Relative Resistance
to Slow Crack Growth Summary Notes
1965 – 1971 Alathon® 5040 Low Initial Product Marketed as AldyI
A*
1971 – 198314 Alathon® 5043 Low15
Resin Improvement. Low Ductile
Inner Wall (LDIW) pipe
manufacturing defect (’70-72)*
1983 – 198917 Alathon® 5046-C Medium18 Resin Improvement-- Sold as
"Improved Aldyl A"
1989 – 1992 Alathon® 5046-U High Resin Improvement --"Improved
AIdyl A"
1992 – 1999 Alathon® 5046-O Very High Resin Improvement
*Note: Low Ductile Inner Wall (LDIW) manufacturing defect primarily
occurring in some pipe manufactured in years 1970 through 1972 and
resulting in possible lower slow crack resistance.
Table 1. DuPont Aldyl A Pipe Resins 1965 – 1999
III. Known Issues with Aldyl A Piping Systems
Shortly after changing its Aldyl A resin in 1971, DuPont detected a manufacturing issue highlighted
during laboratory testing. DuPont learned that its manufacturing process was resulting in some of
the pipe having a property described as "Low Ductile Inner Wall" (LDIW).
Pipe with the LDIW condition has a degraded surface on the inner-wall of the pipe which is less
ductile than the rest of the pipe material. Under certain conditions this less ductile inner-wall
surface layer of material can form micro-cracks in response to stresses acting on the pipe, which in
turn can propagate through the remaining pipe wall resulting in premature failure. In early 1972,
DuPont changed its manufacturing process to eliminate this phenomenon, but estimated that 30 -
40% of the pipe it produced primarily in 1970, 1971 and early 1972 was affected, primarily in pipe
diameters from 1-1/4 inches to 4 inches.
14 See Appendix 4, Aldyl® “A” Piping Systems Continuous Improvements, page 21, for changes in the
additive packages occurring in 1980 and 1986.
15 See Appendix 6 for Single Point 80oC, 600 psi Elevated Temperature Test Data for Aldyl® “A” and
Improved Aldyl® “A”.
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Small-diameter (less than 1-1/4 inches) Aldyl A service piping is often treated or managed differently
than larger-diameter Aldyl A pipe of the same vintage. This is because the small-diameter pipe
generally has a thicker wall in relation to its outer diameter than larger-diameter pipe, and is much
less likely to be subject to high localized stresses from rock impingement and tight radius bends due
to its size. Further, small-diameter Aldyl A pipe has not been reported with LDIW properties present
in pipe manufactured late 1970 through early 1972.
However, small-diameter service pipe can still be subject to Slow Crack Growth (SCG) due to high
localized stresses under certain operating conditions.
Slow Crack Growth (SCG) describes the progression of a crack that begins with the formation of a
crack that then progresses through the pipe wall (usually over a period of many years) until it finally
breaks through the opposite surface of the pipe.16 SCG has been described as “Brittle-Like cracking”
by PHMSA and the National Transportation Safety Board (NTSB), and also as “Slit Failure”. The term
“Brittle-Like” was used to convey the fact that the short-term ductile properties of the material
remain essentially unchanged in spite of the apparent brittle appearance of the failure. Hence the
two modes of failure of PE are describe as “Ductile Failure” (short-term failure mode), and “Slit
Failure” (long-term failure mode). It should be noted that “Brittle-Like” cracking can also occur in
pipe or fittings that do not have the LDIW condition due to other factors that contribute to this type
of material failure.
DuPont issued several letters to customers notifying them about possible Aldyl A piping issues. Of
note was the letter sent in 198217. The letter explained “slits” occurring where the pipe was in
“point contact with rocks.” DuPont noted that two utilities who reported the phenomenon had
increased the frequency of leak surveys where rock may have been part of the backfill around the
pipe, and encouraged other Aldyl A customers to consider the same. This letter was the genesis of
what would become a continuing focus on the pipe vintage known as "pre-1973 Aldyl A18."
DuPont's 1986 letter to its Aldyl A pipe customers also focused on pre-1973 Aldyl A pipe. The letter
conveyed results of newly developed (elevated temperature) testing methods, including the Rate
Process Method, that allowed DuPont to estimate the longevity of this vintage pipe, in diameters of
1¼ inches and larger. These newer test results showed that Aldyl A pipe installed prior to 1973 had
certain limitations that were not previously known. The limitations were described as a reduction in
pipe service life caused by:
1) Rock impingement or pressure from rock points directly on the pipe (as mentioned in their
1982 letter)
2) The use of squeeze-off practices. The term "squeeze-off” refers to the current and long-
standing practice of mechanically pressing together PE pipe walls to temporarily stop the flow
of gas on a line that is in service.
16 In 1984, resistance to stress cracking was assessed using ASTM D1693 Standard Test Method for
Environmental Stress-Cracking of Ethylene Plastics. Regression models were later developed using
elevated temperature test data to assess resistance to slow crack growth and establish long-term
performance of plastic pipe and fittings (per ASTM D2513).
17 See Appendix 12 for December 1982 letter from DuPont to its customers.
18 Pre-1973 Aldyl A refers to pipe installed prior to 1973. The date of manufacture may have been
different. Continued references to this pipe throughout the document are for pipe installed prior to 1973
regardless of manufacture date.
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DuPont further noted that average ground temperature surrounding the pipe had a major bearing
on its ultimate expected service life. Finally, DuPont recommended that operators should reinforce
the pipe, using clamps that surround the pipe at squeeze points in order to extend the life of its pre-
1973 Aldyl A.
Based on the characteristics of the different vintages of Aldyl A pipe there would emerge over time,
from DuPont's 1982 letter going forward, three age-groupings recognized by the manufacturer,
natural gas industry, and regulators as relevant in the reliability management of this pipe. These
groupings are based on manufacture dates and/or estimated installation dates.
x Pre-1973 Aldyl A - Pipe installed prior to 1973, from the first two resin formulations, and
including pipe having low ductile inner wall. Susceptible to brittle-like failures due to rock
impingement or squeeze-off.
x 1973-1983 Aldyl A - Aldyl A pipe manufactured from Alathon® 5043 resin, but only that pipe
manufactured after 1972 and through 1983. Susceptible to brittle-like failures due to rock
impingement.
x 1984 and Later Aldyl A - Pipe manufactured from the improved Alathon® 5046-C, 5046-U and
5046-O resins.
Note: Not all gas companies received the notification letters from DuPont. Only those gas
companies that were direct customers of DuPont were notified. Also, the letters did not specify
the resin changes or designations. These resin changes and designations were provided later in
communications from Mr. Gene Palermo of Palermo Plastics Pipe Consulting.
Pipe and fittings are not installed immediately after manufacture, thus installation and
manufacturing dates may differ.
IV. National Transportation Safety Board (NTSB)
In April 1998, twelve years after DuPont's second letter to customers, the NTSB published a
comprehensive safety report describing their investigation of natural gas pipeline accidents
involving PE pipe that had cracked in a "brittle-like" manner.19
The objective of the review was to address three safety issues related to PE gas service pipe:
1. The vulnerability of plastic piping to premature failures due to brittle-like cracking
2. The adequacy of available guidance relating to the installation and protection of plastic
piping connections to steel main
3. Performance monitoring of plastic pipeline systems as a way of detecting unacceptable
performance in piping systems
19 See Appendix 13 for April 1998 NTSB Special Investigation Report on Brittle-Like Cracking in Plastic
Pipe for Gas Service.
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NTSB Conclusions
The NTSB concluded that early plastic piping manufactured from the 1960s through the early 1980s
may be "susceptible to premature brittle-like cracking under conditions of stress intensification. The
stress intensification was attributed to localized pressure on the pipe wall created by such
conditions as rock contact or significant bending of the pipe. The phenomenon of brittle-like
cracking was characterized by the failure processes described above, beginning with the initiation of
cracks on the inner wall of the pipe at the pressure or stress point, followed by slow crack growth
that progressed under normal pipeline operating pressures (much lower than the pressure required
to rupture the pipe). The process culminated with the crack reaching the outside wall of the pipe,
showing up as a very tight, slit-like opening on the surface.
The NTSB also noted that premature brittle-like cracking was a complex phenomenon that had not
been systematically communicated to the industry, and hence, had not been fully-appreciated by
pipeline operators. The NTSB recognized pipe manufacturers as commonly offering technical and
safety assistance to operators, and occasionally, formal reports on their materials. However, the
information on the potential weakness of their products was also mixed with information publicizing
its best performance characteristics. As a result, the message was not clear. The NTSB also noted
that the Federal Government had not provided relevant information to gas system operators, and
concluded that operators had insufficient notification that much of their early PE pipe may have
been susceptible to premature brittle-like cracking. Finally, the NTSB went on to recommend that
the Plastics Pipe Institute advise its members to notify pipeline operators if any of their materials
indicate poor resistance to brittle-like failure.
In addition, the NTSB concluded that pipeline operators had insufficient guidance on the overall
issue of the vulnerability of plastic pipe to brittle-like cracking, as noted above, the NTSB also
observed that much of the available guidance to operators on how to limit stress on the pipe during
installation was inadequate or ambiguous. This was the case with stresses associated with
connections of plastic service piping to steel mains, where the NTSB concluded that many of those
connections may have been installed without adequate protection from external stress. The NTSB
went on to note cases where the inadequacy of pipe manufacturers' instructions also contributed to
the lack of a clear understanding of methods to limit stress on plastic pipe during installation.
Lastly, The NTSB focused on performance monitoring of pipeline systems as the key to effectively
managing the vulnerable piping types identified in the report. It concluded that the systems
operators had developed for tracking, identifying, and statistically treating plastic piping failures did
not permit an effective analysis of system failures and leak history.
V. Pipeline and Hazardous Materials Safety Administration
The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration
(PHMSA) has issued several safety advisory bulletins and regulations dealing with plastic piping
issues including Aldyl A.
1. Advisory Bulletins
13
The first two of several advisory bulletins related to the NTSB's 1998 Safety Report were published
by the Office of Pipeline Safety, part of PHMSA, in March 1999.20 The advisory bulletins to pipeline
owners and operators provided an abstract of the findings of the NTSB's 1998 investigation and
advised that much of the plastic pipe manufactured from the 1960s through the early 1980s may be
susceptible to brittle-like cracking. The advisories concluded with the recommendation to owners
and operators to identify all pre-1982 plastic pipe installations, analyze leak histories, evaluate
potential stresses to pipe, and to develop appropriate remedial actions, including pipe replacement,
to mitigate any risks to public safety.
Another advisory bulletin was issued in 2002.21 This advisory bulletin reiterated to natural gas
pipeline owners and operators the susceptibility of older plastic pipe to premature brittle-like
cracking. However, this advisory specifically named DuPont's pre-1973 Aldyl A pipe (LDIW) as being
susceptible to brittle-like cracking. The bulletin also depicted several environmental and installation
conditions that could lead to premature, brittle-like cracking failure of the subject pipe, and
described recommended practices to aid operators in identifying and managing brittle-like cracking
problems.
A fourth advisory bulletin issued in 2007, served to review and recap the findings of the prior
bulletins, advising natural gas system operators to review the earlier statements.22 In addition, the
advisory bulletin recapped results of the ongoing effort of the Plastic Pipe Database Committee to
identify trends in the performance of older plastic pipe. The advisory reported that the data, at that
point, could not assess failure rates of individual plastic pipe materials, but did support what was
historically known about the susceptibility of older plastic piping to brittle-like failure, including the
addition of specific materials to the list, such as Delrin insert tap tees.
2. 2009 Distribution Integrity Management Program
PHMSA published the final rule establishing integrity management requirements for gas distribution
pipeline operators in December 2009 giving operators until August 2011 to write and implement
their Distribution Integrity Management Plan.
Among other objectives, the program was intended to overcome two key weaknesses in pipeline
safety management that were identified in the NTSB's 1998 report: 1) correct weaknesses in federal
regulations, by establishing true measurement criteria for establishing safety compliance, and 2)
establish systematic protocols for pipeline data collection, analysis, and interpretation, that helps
ensure accurate integrity assessment and appropriate remediation.
Integrity management requires operators to write and implement Integrity Management Programs
(IMPs) to evaluate their systems, implement measures to address risk, and monitor results. The
program contains the following elements:
x Knowledge
x Identify Threats
x Evaluate and Rank Risks
x Identify and implement Measures to Address Risks
20 See Appendix 14 for March 1999 PHMSA Advisory Bulletin ADB-99-01
21 See Appendix 15 for 2002 PHMSA Advisory Bulletin ADB-02-07
22 See Appendix 16 for 2007 PHMSA Advisory Bulletin ADB-07-01
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x Measure Performance, Monitor Results, and Evaluate Effectiveness
x Periodically Evaluate and Improve Program
x Report Results
3. 2011 Call to Action - Transportation Secretary LaHood
In April 2011, U.S. Transportation Secretary LaHood issued a Call to Action to all pipeline
stakeholders.23 The Call to Action was aimed at the more than 2.5 million miles of liquid and gas
pipelines of both federal and state jurisdiction, including transmission and distribution facilities,
calling on owners and operators, the pipeline industry, utility regulators and state and federal
partners to evaluate risks on pipeline systems and take appropriate actions to address those risks.
The centerpiece of the Call to Action is the "Action Plan." The focus of the Action Plan is to
accelerate the rehabilitation, repair, and replacement of high-risk pipeline infrastructure, calling on
pipeline operators and owners to "focus on identifying pipeline risks to accelerate the repair,
rehabilitation, and replacement of the highest risk gas and liquid pipeline infrastructure."
VI. Plastic Piping Database Collection Initiative Status Report
The Plastic Piping Database Collection (PPDC) Initiative Status Report contains an analysis of the
data submitted to the database on pipe and fittings manufactured by DuPont and Uponor. The
Status Report includes information from the latest analysis including causes, year of failure and
years in service. However, the PPDC Report Form provides for collection of information by
manufacturer. Therefore, the PPDC analysis is the data reported as being manufactured by DuPont
and Uponor which may also include materials other than Aldyl A. The Status Report also cautions
that failure causes demonstrate that installation practices and the operating environment can
greatly impact the service life of Aldyl piping and that operators should look at the performance of
their own piping systems.
VII. Potential Aldyl A Piping System Threats
Listed below are some of the threats that operator should consider when evaluating the integrity of
their Aldyl A piping systems.
1.Towers & Caps
AGA member companies have noted that in their experience the largest percentage of material
failures that occurred on Aldyl-A piping systems were related to failures involving the “tapping
tees”, also commonly referred to as a “Punch Tees.” In these cases, the stress applied to the tee
insert as the cap was tightened onto the body during initial installation resulted in slow crack growth
and failure of the Delrin® insert many years later. In November 1983, DuPont introduced an
improved Aldyl “A” Service Punch Tee said to have improved sealing and punching systems and
simplified installation procedures resulting from its overcap design24.
2.Rock Contact and Squeeze-Off
23 See Appendix 17 for US DOT Call to Action Document
24 See Appendix 18 for 1983 Letter from DuPont regarding the Improved Aldyl “A” Service Punch Tee
15
The second-most common material failure observed in Aldyl A pipe is due to localized, brittle-like
cracking in Aldyl A mains that resulted from rock impingement (i.e., rock pressure directly on the
pipe) or places where the pipe had been 'squeezed-off'. These failures may occur on certain resins of
Aldyl A main pipe, having been consistently reported by other utilities since before the time of
DuPont's 1986 letter. As described earlier, when these external stresses (rock impingement or
squeeze-off) cause the pipe to fail, it begins with crack initiation on the inside surface of the pipe
wall, eventually resulting in slow crack growth that propagates toward the outer wall of the pipe,
and finally, through-wall failure. A typical failure in Aldyl A main pipe, showing a crack through the
pipe wall as it appears on both the inner and outer surfaces, is shown below in Figure 3.
Other sources of external stress that can result in brittle-like failure of Aldyl A pipe, as mentioned
earlier in the report, include bending the pipe beyond the manufacturer’s approved bending radius,
soil settlement, dents or gouges to the pipe, and improper installation of fittings.
3.Services Tapped from Steel Mains
A failure can occur where small diameter Aldyl A service pipe is tapped from steel main pipe. In this
application, a steel service tee is welded to the steel main pipe and the small-diameter Aldyl A
service pipe is then connected to a mechanical transition fitting on the tee, as pictured below in
Figure 4.
Figure 4. Typical PE service tapped from a steel main.
It is at this transition point, between the rigid steel fitting and the more-flexible Aldyl A service pipe,
that brittle-like cracking has been observed. This failure mode occurs when the steel to plastic
transition has not been supported, using a sleeving material, prior to backfill. This failure mode in
older plastic pipe is well understood, and was one of the three study objectives reported by the
NTSB in its 1998 report.
VIII. Summary
This paper documents the history of Aldyl A pipe and known risks that may be present in Aldyl A
piping systems. The paper is intended as a guide to assist operators with the identification of
potential threats to their Aldyl A distribution systems. Since installation practices appear to have a
significant effect on the reliability of Aldyl A systems, Operators should review their installation
records, where possible to determine if the risks identified apply to their systems and are accounted
for in their respective distribution integrity plans.
16
APPENDIX 1: 1966-1967 DUPONT PHYSICAL PROPERTIES OF ALDYL A PIPE

APPENDIX 2: 1967 AGA PG&E ALDYL-A GAS DISTRIBUTION SYSTEM FROM DESIGN THROUGH
INSTALLATION

APPENDIX 3: FULL PACKAGE OF ALL DUPONT TECHNICAL BULLETINS THROUGHOUT THE YEARS
19
APPENDIX 4: "ALDYL ® "A" PIPING SYSTEMS CONTINUOUS IMPROVEMENTS" REPORT FROM GENE
PALERMO, UPONOR ALDYL COMPANY, CIRCA 1992
2
APPENDIX 5: DECEMBER 5, 1985 LETTER FROM DUPONT EXPLAINING THE CHANGE FROM PE
2306 TO PE 2406
2
APPENDIX 6: SINGLE POINT 80 C, 600 PSI ELEVATED TEMPERATURE TEST FOR ALDYL ® "A"
AND IMPROVED ALDYL ® A
22
APPENDIX 7: ALDYL ® A TEHCNICAL DATA BULLETIN 100-200 (1975)

APPENDIX 8: 1981 LETTER FROM DhPONT INDICATING CHANGE IN ADDITIVE PACKAGE
THAT OCCURRED IN 1980

APPENDIX 9: 1982 DUPONT ANNOUNCEMENT AND PRODUCT INFORMATION ON THE NEW 8"
ALDYL "A" PIPING SYSTEM

APPENDIX 10: 1986 LETTER FROM DUPONT INDICATING THE CHANGE IN UV EXPOSURE TIME
FROM 1 YEAR TO 2 YEARS ( IN 1984) AND FROM 2 YEARS TO 3 YEARS ( IN 1986)

APPENDIX 11: PLASTIC PIPE FAILURE, RISK, AND THREAT ANALYSIS - GTI REPORT
This research was funded in part under the Department of Transportation, Pipeline and Hazardous
Materials Safety Administration’s Pipeline Safety Research and Development Program. The views and
conclusions contained in this document are those of the authors and should not be interpreted as
representing the official policies, either expressed or implied, of the Pipeline and Hazardous Materials
Safety Administration, or the U.S. Government
GTI PROJECT NUMBER 20385
Plastic Pipe Failure, Risk, and Threat Analysis
DOT Project# 194
Contract Number: DTPH56-06-T-0004
Reporting Period:
May 1, 2006 through January 31, 2009
Report Issued:
March 31, 2009
Revised:
April 29, 2009
Revision No.:
01
Prepared For:
Ms. Terri Binns
Senior Engineer
PHMSA
713-272-2825
[e-mail]
Prepared By:
Gas Technology Institute
Ms. Julie Maupin
Dr. Michael Mamoun
Gas Technology Institute
1700 S. Mount Prospect Rd.
Des Plaines, Illinois 60018
www.gastechnology.org
FINAL REPORT
Title: DTPH56-06-T-0004 Final Report Page i
Signature Page
Print or typed
First M. Last Signature Date
AUTHOR: Michael M. Mamoun March 31, 2009
Title:Senior Institute Engineer
AUTHOR: Julie K. Maupin March 31, 2009
Title:Engineer
AUTHOR: Michael J. Miller March 31, 2009
Title:Engineer
Title: DTPH56-06-T-0004 Final Report Page ii
Legal Notice
This information was prepared by Gas Technology Institute (“GTI”) for the U.S.
Department of Transportation, Pipeline and Hazardous Materials Safety Administration
(“DOT/PHMSA”) (Contract Number: DTPH56-06-T-0004).
Neither GTI, the members of GTI, the Sponsor(s), nor any person acting on behalf of any of
them:
a. Makes any warranty or representation, express or implied with respect to the accuracy,
completeness, or usefulness of the 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. Inasmuch as this project is experimental in nature, the technical information,
results, or conclusions cannot be predicted. Conclusions and analysis of results by GTI
represent GTI's opinion based on inferences from measurements and empirical relationships,
which inferences and assumptions are not infallible, and with respect to which competent
specialists may differ.
b. Assumes any liability with respect to the use of, or for any and all damages resulting
from the use of, any information, apparatus, method, or process disclosed in this report; any
other use of, or reliance on, this report by any third party is at the third party's sole risk.
c. The results within this report relate only to the items tested.
Title: DTPH56-06-T-0004 Final Report Page iii
Table of Contents
Signature Page .............................................................................................................................. i
Legal Notice .................................................................................................................................. ii
Table of Contents ......................................................................................................................... iii
Table of Figures ........................................................................................................................... xi
List of Tables .............................................................................................................................. xxi
Abstract ......................................................................................................................................... 1
Executive Summary ...................................................................................................................... 2
Introduction ................................................................................................................................... 3
Classification of Failures and Their Causes .............................................................................. 6
Ductile Rupture Failure Mechanism ...................................................................................... 6
Slow Crack Growth Failure Mechanism ................................................................................ 7
Rapid Crack Propagation (RCP) Failure Mechanism ............................................................ 8
Types of PE Failures ............................................................................................................. 9
Project Structure ..................................................................................................................... 10
Literature Review on Severity and Frequency of Plastic Pipe Failures ...................................... 11
DOT/PHMSA Natural Gas Distribution Incident Data Discussion ........................................... 11
Severity of Failures ................................................................................................................. 11
Frequency of Failures ............................................................................................................. 19
Susceptibility of PE to Slow Crack Growth Failures .................................................................... 26
Objective ................................................................................................................................. 26
Types of PE Gas Pipe Materials in GTI Database .................................................................. 26
Detailed List of PE Resin and Pipe Manufacturers ............................................................. 26
Visual and Optical Examinations of Slow Crack Growth Failures ........................................... 26
SCG Failures Due to Rock Impingement Loads ............................................................. 27
SCG Failures Due to Squeeze-Off Operations ............................................................... 30
Short-Term Laboratory Tests .................................................................................................. 33
Melt Index ............................................................................................................................ 33
ALDYL-A Melt Index and Density Data (1965 – 1992) .................................................... 33
Tensile Strength .................................................................................................................. 35
Quick Burst .......................................................................................................................... 36
PENT ................................................................................................................................... 36
Bend Back ........................................................................................................................... 45
Title: DTPH56-06-T-0004 Final Report Page iv
Bend-Back Test Conducted on a LDIW Material from February 1971 ............................ 46
Bend-Back Test Conducted on a LDIW Material from March 1971 ................................ 46
Bend-Back Tests Conducted on Non-LDIW Materials (1970, 1972-1993)...................... 47
Accelerated Long Term Hydrostatic Stress-Rupture (LTHS) Tests ........................................ 52
Accelerated LTHS Tests with Secondary Stresses ............................................................. 52
Squeeze-Off .................................................................................................................... 52
Rock Impingement .......................................................................................................... 53
Bending ........................................................................................................................... 54
Transverse Deflections or Soil Loads ............................................................................. 54
GTI Database on Accelerated LTHS Tests ......................................................................... 55
Stresses that Drive Crack Initiation and Growth through Pipe Walls ...................................... 56
Effects of Elevated Test Temperatures ............................................................................... 58
Engineering Methods to Predict Life Expectancy ................................................................... 61
Original Bi-Directional Shift Functions Model ...................................................................... 62
Modified Bi-Directional Shift Functions Equations .............................................................. 62
Original Three-Coefficient Rate Process Method ................................................................ 63
Modified Three-Coefficient Rate Process Method .............................................................. 63
Sample Set on the Predicted Remaining Life Expectancy .................................................. 64
Secondary Stress Effects ................................................................................................ 66
Field Temperature Effects ............................................................................................... 67
Slow Crack Growth Conclusion .............................................................................................. 69
Root Cause Analysis of Field Failures ........................................................................................ 71
Failure Categories ................................................................................................................... 71
Laboratory Field Failure Analysis Procedure .......................................................................... 72
Impingement – #602533 ..................................................................................................... 72
Visual Examination .......................................................................................................... 73
Density ............................................................................................................................ 77
Melt Flow ......................................................................................................................... 77
Thermal Analysis ............................................................................................................. 78
Infrared Analysis ............................................................................................................. 79
Conclusions ..................................................................................................................... 81
Research Approach ................................................................................................................ 81
Material Failures ..................................................................................................................... 82
Tap Tee – #678156 ............................................................................................................. 82
Visual Examination .......................................................................................................... 83
Title: DTPH56-06-T-0004 Final Report Page v
Density ............................................................................................................................ 88
Melt Flow ......................................................................................................................... 88
Thermal Analysis ............................................................................................................. 88
Infrared Analysis ............................................................................................................. 90
Conclusions ..................................................................................................................... 91
Impingement - #00590 ........................................................................................................ 92
Visual Examination .......................................................................................................... 93
Density and Melt Flow ..................................................................................................... 95
Conclusions ..................................................................................................................... 95
Impingement - #04020731 .................................................................................................. 96
Visual Examination .......................................................................................................... 97
External Loading - #26020806 ............................................................................................ 98
Visual Examination .......................................................................................................... 99
Tee Caps ........................................................................................................................... 101
Cap –#50020726 ........................................................................................................... 101
Visual Examination .................................................................................................... 102
Infrared Analysis ....................................................................................................... 104
Differential Scanning Calorimetry .............................................................................. 105
Thermogravimetric Analysis and Energy Dispersive X-ray ....................................... 105
Conclusions ............................................................................................................... 107
Cap - #20020447 .......................................................................................................... 108
Visual Examination .................................................................................................... 109
Cap - #21020739 .......................................................................................................... 110
Visual Examination .................................................................................................... 111
Cap - #22020733 .......................................................................................................... 112
Visual Examination .................................................................................................... 113
Cap - #23020464 .......................................................................................................... 114
Visual Examination .................................................................................................... 115
Cap - #24020499 .......................................................................................................... 116
Visual Examination .................................................................................................... 117
Caps - #25020718 and #49020718 ............................................................................... 118
Visual Examination .................................................................................................... 119
Cap - #31020649 .......................................................................................................... 120
Visual Examination .................................................................................................... 121
Thread Inserts ................................................................................................................... 122
Title: DTPH56-06-T-0004 Final Report Page vi
Service Tee Threads - #15020650 ................................................................................ 122
Visual Examination .................................................................................................... 122
Service Tee Threads - #29020510 ................................................................................ 124
Visual Examination .................................................................................................... 125
Socket Couplings .............................................................................................................. 126
Socket Coupling - #30020542 ....................................................................................... 126
Visual Examination .................................................................................................... 127
Socket Coupling - #35020485 ....................................................................................... 128
Visual Examination .................................................................................................... 129
Socket Coupling - #39020605 ....................................................................................... 131
Visual Examination ........................................................................................................ 132
Socket Tees ...................................................................................................................... 133
Socket Tee - #19020414 ............................................................................................... 133
Visual Examination .................................................................................................... 134
Socket Tee - #33020602 ............................................................................................... 135
Visual Examination .................................................................................................... 136
Supplemental Inspection ........................................................................................... 136
Socket Tee - #34020623 ........................................................................................... 137
Visual Examination .................................................................................................... 138
Supplemental Inspection ........................................................................................... 139
Procedural Failures ............................................................................................................... 140
High Volume Tapping Tee - #00632 ................................................................................. 140
Visual Examination ........................................................................................................ 141
Density .......................................................................................................................... 145
Melt Flow ....................................................................................................................... 145
Thermal Analysis ........................................................................................................... 145
Infrared Analysis ........................................................................................................... 148
Conclusions ................................................................................................................... 151
Butt Fusions ...................................................................................................................... 152
Butt Fusion - #060204100 ............................................................................................. 152
Visual Examination .................................................................................................... 153
Butt Fusion - #07020714 ............................................................................................... 155
Visual Examination .................................................................................................... 156
Butt Fusion - #08020601 ............................................................................................... 157
Visual Examination .................................................................................................... 158
Title: DTPH56-06-T-0004 Final Report Page vii
Butt Fusion - #09020552 ............................................................................................... 159
Visual Examination .................................................................................................... 160
Butt Fusion - #10020477 ............................................................................................... 161
Visual Examination .................................................................................................... 162
Butt Fusion - #11020511 ............................................................................................... 163
Visual Examination .................................................................................................... 164
Butt Fusion - #12020550 ............................................................................................... 166
Visual Examination .................................................................................................... 167
Butt Fusion - #13020706 ............................................................................................... 168
Visual Examination .................................................................................................... 169
Butt Fusion - #45020551 ............................................................................................... 170
Visual Examination .................................................................................................... 171
Multiple Fusion Joints - #40020413 .................................................................................. 173
Visual Examination ........................................................................................................ 174
Socket Couplings .............................................................................................................. 176
Socket Coupling - #16020611 ....................................................................................... 176
Visual Examination .................................................................................................... 177
Socket Coupling - #31020649 ....................................................................................... 178
Visual Examination .................................................................................................... 179
Socket Tees ...................................................................................................................... 180
Socket Tee - #36020713 ............................................................................................... 180
Visual Examination .................................................................................................... 181
Socket Tee - #47020565 ............................................................................................... 182
Visual Examination .................................................................................................... 183
Squeeze-offs ..................................................................................................................... 185
Squeeze-Off - #02020717 ............................................................................................. 185
Visual Examination .................................................................................................... 186
Squeeze-off - #03020647 .............................................................................................. 187
Visual Examination .................................................................................................... 188
Squeeze-off - #05020548 .............................................................................................. 189
Visual Examination .................................................................................................... 190
Tap Tees ........................................................................................................................... 192
Tap Tee - #28020502 .................................................................................................... 192
Visual Examination .................................................................................................... 193
Tap Tee - #42020711 .................................................................................................... 195
Title: DTPH56-06-T-0004 Final Report Page viii
Visual Examination .................................................................................................... 196
Tap Tee - #43020555 .................................................................................................... 198
Visual Examination .................................................................................................... 199
Tap Tee - #44020539 .................................................................................................... 200
Visual Examination .................................................................................................... 201
Tap Tee – Socket Fusion - #32020543 ......................................................................... 202
Visual Examination .................................................................................................... 203
Transition Fitting ................................................................................................................ 204
Transition Fitting - #18020538 ...................................................................................... 204
Visual Examination .................................................................................................... 205
Quality Control Problems ...................................................................................................... 206
3” Elbow - #675540 ........................................................................................................... 206
Visual Examination ........................................................................................................ 207
Density .......................................................................................................................... 213
Melt Flow ....................................................................................................................... 214
Thermal Analysis- Pipe Wall ......................................................................................... 214
Thermal Analysis - Elbow .............................................................................................. 214
Infrared Analysis ........................................................................................................... 217
Conclusions ................................................................................................................... 220
¾” Valve – #642535 .......................................................................................................... 221
Visual Examination ........................................................................................................ 222
Infrared Analysis and Hardness Testing ....................................................................... 227
Conclusions ................................................................................................................... 228
Miscellaneous Problems ....................................................................................................... 229
Charred Pipe – #01020436 ............................................................................................... 229
Visual Examination .................................................................................................... 230
Tap Tee – #642909 ........................................................................................................... 231
Visual Examination ........................................................................................................ 232
Density .......................................................................................................................... 237
Melt Flow ....................................................................................................................... 237
Thermal Analysis ........................................................................................................... 237
Infrared Analysis ........................................................................................................... 239
Conclusions ................................................................................................................... 241
Electrofusion Tee – #642430 ............................................................................................ 242
Visual Examination ........................................................................................................ 243
Title: DTPH56-06-T-0004 Final Report Page ix
Thermal Analysis ........................................................................................................... 243
Infrared Analysis ........................................................................................................... 247
Conclusions ................................................................................................................... 249
Material / Quality ................................................................................................................... 250
Compression Fitting - #17020701 ..................................................................................... 250
Visual Examination ........................................................................................................ 251
Procedural / Material ............................................................................................................. 252
Mechanical Fitting - #41020409 ........................................................................................ 252
Visual Examination ............................................................................................................ 253
Tap Tee - #27020640 ........................................................................................................ 254
Visual Examination ........................................................................................................ 255
Bolt-on Tap Tee - #14020742 ........................................................................................... 256
Visual Examination ............................................................................................................ 257
Root Cause Failure Results .................................................................................................. 258
Characterizing the Resistance of PE to RCP through S-4 Testing ........................................... 267
Rapid Crack Propagation ...................................................................................................... 267
S-4 Background .................................................................................................................... 270
Test Requirements ............................................................................................................ 270
Full-Scale RCP Field Tests ............................................................................................... 270
S-4 Testing ........................................................................................................................ 271
ISO Specification (ISO 13477) .......................................................................................... 272
Initiation Tests ............................................................................................................... 272
Critical Pressure Testing ............................................................................................... 273
Correlation of the S-4 Critical Pressure to the Full-Scale Field Test ............................. 273
Critical Temperature Testing ......................................................................................... 274
GTI S-4 Test Apparatus ........................................................................................................ 275
Shaft, Anvil, Baffles and Pipe Assembly ........................................................................... 275
External Containment Cage and Frame ............................................................................ 278
Striking Blade Assembly ................................................................................................... 280
PE Materials Subjected to S-4 Test s ................................................................................... 281
6 Inch MDPE – Critical Pressure and Critical Temperature .............................................. 282
6” Inch HDPE Critical Pressure and Critical Temperature ................................................ 287
6” PE100 Critical Pressure and Critical Temperature ....................................................... 292
8” MDPE Critical Pressure ................................................................................................ 297
8” PE100 Critical Pressure ................................................................................................ 300
Title: DTPH56-06-T-0004 Final Report Page x
12” MDPE Critical Pressure .............................................................................................. 303
RCP Results, Correlations, and Conclusions ....................................................................... 306
Conclusion ................................................................................................................................ 307
Recommendations .................................................................................................................... 308
References................................................................................................................................ 309
List of Acronyms ....................................................................................................................... 313
Title: DTPH56-06-T-0004 Final Report Page xi
Table of Figures
Page
Figure 1. Percentage of Miles of Main, 1995 ............................................................................... 3
Figure 2. Percentage of Miles of Main, 2006 ............................................................................... 4
Figure 3. Percentage of Services, 1995 ....................................................................................... 4
Figure 4. Percentage of Services, 2006 ....................................................................................... 5
Figure 5. Comparison of Total Services, Plastic Services, and PE Services in 2005 .................. 5
Figure 6. Ductile Failure Resulting From a Quick Burst Test ....................................................... 6
Figure 7. Ductile Failure Resulting From a Quick Burst Test ....................................................... 7
Figure 8. SCG Failure Morphology .............................................................................................. 8
Figure 9. RCP Rupture in a PE Pipe Subjected To a Small-Scale Steady State (S-4) Test ........ 8
Figure 10. Cost of damages categorized by cause from 1984 - March 2004 ............................ 14
Figure 11. Cost of Outside Force Damages by Secondary Cause from 1984 - March 2004 ..... 14
Figure 12. Cost of Damages Categorized By Cause from March 2004 - 2006 .......................... 15
Figure 13. Cost of Excavation Damages by Secondary Cause from March 2004 - 2006 .......... 15
Figure 14. Fatalities by Primary Cause As Reported From 1984 - March 2004 ........................ 16
Figure 15. Fatalities by Primary Cause As Reported From March 2004 - 2006 ........................ 17
Figure 16. Injuries by Primary Cause As Reported From 1984 - March 2004 ........................... 18
Figure 17. Injuries by Primary Cause As Reported From March 2004 - 2006 ........................... 18
Figure 18. Total Cost of Reported Incidents for Each Data Period ............................................ 19
Figure 19. Frequency of Failures by Cause from 1984 - March 2004 ........................................ 20
Figure 20. Frequency of Failures by Cause from March 2004 - 2006........................................ 20
Figure 21. Frequency of Failures by Type of PE and Cause for 1984 - 2004 ............................ 21
Figure 22. Frequency of Failures by Type of PE and Cause for 2004 - 2006 ............................ 22
Figure 23. Frequency of Incidents by Manufacturer and Cause for 1984 - March 2004 ............ 23
Figure 24. Frequency of Incidents by Manufacturer and Cause for March 2004 - 2006 ............ 24
Figure 25. Frequency of Plastic Incidents by Time of Day from 1984 - March 2004 ................. 25
Figure 26. Frequency of Plastic Incidents by Time of Day from March 2004 – 2006................. 25
Figure 27. Pipe Exhibited Through Wall Axial Slit While Under Internal Pressure..................... 27
Figure 28. Rock Impingement Failure ........................................................................................ 28
Figure 29. Off-Axis Slit Failure that Initiated on the ID Due to an Impinging Rock..................... 28
Figure 30. Rock Impingement Failure Induced in Field Service ................................................ 29
Figure 31. Micrograph of the SCG Fracture Surface of a Rock Impingement Failure ............... 29
Title: DTPH56-06-T-0004 Final Report Page xii
Figure 32. Failure of an Aldyl-A Pipe at Squeeze Ears .............................................................. 30
Figure 33. Inner Surface of an Aldyl-A Pipe Subjected to About 15% Squeeze ........................ 30
Figure 34. MDPE Pipe that Failed in Field Service Due to a Squeeze-Off ................................ 31
Figure 35. End View Depicting Large-Scale Deformations Due to a Squeeze-Off .................... 31
Figure 36. Pipe ID with Axial Slit at the Ears of Pipe Shown in Figure 34 ................................. 32
Figure 37. Schematic Illustration of the Rectangular PENT Test Specimen ............................... 37
Figure 38. Notched MDPE Test Specimens ............................................................................... 37
Figure 39. Brittle SCG Failure of a PLEXCO MDPE 2406 PENT Test Specimen ...................... 38
Figure 40. Brittle SCG Failure of HDPE Performance Pipe PENT Test Specimen .................... 39
Figure 41. Ring Sector Specimen Before and After the Bend Back Test ................................... 45
Figure 42. Bend-Back Test Exhibiting LDIW Surface Features .................................................. 46
Figure 43. Bend-Back Test Exhibiting LDIW Surface Features .................................................. 47
Figure 44. Bend Back Test of a 1970 Aldyl-A Material ............................................................... 47
Figure 45. Bend Back Test of a 1972 Aldyl-A Material (During and After) .................................. 48
Figure 46. Bend Back Test of a 1973 Aldyl-A Material (During and After) .................................. 48
Figure 47. Bend Back Test of a 1974 Aldyl-A Material ............................................................... 49
Figure 48. Bend Back Test of a 1976 Aldyl-A Material ............................................................... 49
Figure 49. Bend Back Test of a 1986 Aldyl-A Material ............................................................... 50
Figure 50. Bend Back Test of a 1991 Aldyl-A Material ............................................................... 50
Figure 51. Bend Back Test of a 1993 Aldyl-A Material ............................................................... 51
Figure 52. Double Bar Squeeze-Off Tool .................................................................................... 52
Figure 53. Rock Impingement Loading Fixture ........................................................................... 53
Figure 54. Indentation unto the Pipe Using Ball Bearing ............................................................ 53
Figure 55. Pipe Bending Fixture ................................................................................................. 54
Figure 56. PE Pipe Test Specimens Installed in Earth Load Fixtures ........................................ 55
Figure 57. Circumferential Residual Stress Component as a Function of the Wall Depth .......... 57
Figure 58. Effect of Test Temperature and Time on Residual Hoop Stress Component ............ 58
Figure 59. Predicted Remaining Life Expectancy of an Older Aldyl-A Pipe ............................... 67
Figure 60. Predicted Remaining Life Expectancy as a Function of Temperature ....................... 68
Figure 61. As Received Sample with Attached 4” X 2” Electrofusion Tapping Tee ................... 72
Figure 62. Slit Failure Growing Away From Impingement Point ................................................ 73
Figure 63. View of the Slit from the Inner Wall ........................................................................... 74
Figure 64. Pipe Was Force Fractured to Reveal the Fracture Faces......................................... 74
Figure 65. Close Up View of the Fracture Faces ....................................................................... 75
Figure 66. Microscopy ................................................................................................................ 76
Title: DTPH56-06-T-0004 Final Report Page xiii
Figure 67. Differential Scanning Calorimetry ............................................................................. 78
Figure 68. Oxidative Induction Time .......................................................................................... 79
Figure 69. FT-IR Outer Wall ....................................................................................................... 80
Figure 70. FT-IR Middle Wall ..................................................................................................... 80
Figure 71. FT-IR Inner Wall ....................................................................................................... 81
Figure 72. As Received Sample with Two Tees. Leak Occurred At Untapped Tee, Left ........... 82
Figure 73. Untapped Tee with Circumferential Slit .................................................................... 82
Figure 74. Underwater Leak Test Revealing Leak Location ...................................................... 84
Figure 75. Sample Was Cut to Show Inner Pipe Wall ............................................................... 84
Figure 76. Close Up of the Circumferential Slit on the Inner Wall .............................................. 85
Figure 77. Length of Fracture Faces Identified with Red Marker ............................................... 85
Figure 78. Close up of the Fracture Face Away from the Tee ................................................... 86
Figure 79. Close up of the Fracture Face towards the Tee with Area of Interest Identified ....... 86
Figure 80. Microscopy of the Fracture Face Away From the Tee .............................................. 87
Figure 81. Microscopy of the Fracture Face towards the Tee ................................................... 87
Figure 82. Differential Scanning Calorimetry ............................................................................. 89
Figure 83. Oxidative Induction Time .......................................................................................... 89
Figure 84. FT-IR Outer Wall ....................................................................................................... 90
Figure 85. FT-IR Middle Wall ..................................................................................................... 91
Figure 86. FT-IR Inner Wall ....................................................................................................... 91
Figure 87. As Received Condition ............................................................................................. 92
Figure 88. Crack on Outer Wall ................................................................................................. 93
Figure 89. Close Up, Dimple and Crack .................................................................................... 93
Figure 90. Crack As Seen On Inner Wall ................................................................................... 94
Figure 91. Fracture Origin .......................................................................................................... 94
Figure 92. Composite Photo, Fracture Surface - Outer Wall at Top .......................................... 95
Figure 93. Bottom Side of as Received Sample ........................................................................ 96
Figure 94. Axial Slit on Outer Wall ............................................................................................. 97
Figure 95. Axial Slit on Inner Pipe Wall ...................................................................................... 97
Figure 96. As Received Sample ................................................................................................ 98
Figure 97. Side and Bottom View of Sample ............................................................................. 99
Figure 98. Slit on Outer Wall .................................................................................................... 100
Figure 99. Slit on Inner Wall ..................................................................................................... 100
Figure 100. As Received Cap .................................................................................................. 101
Figure 101. Topside Fracture Surface ..................................................................................... 102
Title: DTPH56-06-T-0004 Final Report Page xiv
Figure 102. Bottom Side Fracture Surface .............................................................................. 103
Figure 103. Cap Threads ......................................................................................................... 103
Figure 104. Topside Fracture Surface ..................................................................................... 104
Figure 105. FT-IR Spectrum of the Cap Material ..................................................................... 104
Figure 106. DSC Thermogram of the Cap Material ................................................................. 105
Figure 107. TGA Plot ............................................................................................................... 106
Figure 108. EDX Spectrum of the Cap Material Ash ............................................................... 106
Figure 109. As Received Cap .................................................................................................. 108
Figure 110. Crack Seen Inside the Cap. .................................................................................. 109
Figure 111. As Received Cap .................................................................................................. 110
Figure 112. Soil on Interior Surface ......................................................................................... 111
Figure 113. As Received Cap .................................................................................................. 112
Figure 114. Dirty Interior Surface ............................................................................................. 113
Figure 115. As Received Cap .................................................................................................. 114
Figure 116. Cracked Cap with Wrench Marks ......................................................................... 115
Figure 117. As Received Cap .................................................................................................. 116
Figure 118. Yellow Tee Visible Through the Crack .................................................................. 117
Figure 119. As Received Service Tee with Broken Cap .......................................................... 118
Figure 120. Fracture Surfaces of Cap ...................................................................................... 119
Figure 121. Fracture Surface of the Top of the Cap ................................................................ 119
Figure 122. As Received Cap .................................................................................................. 120
Figure 123. Cap, Underside Left and Topside Right ................................................................ 121
Figure 124. Internal Threads of the Saddle Tee ...................................................................... 121
Figure 125. As Received Tee .................................................................................................. 122
Figure 126. Close-up View of Thread Insert ............................................................................ 123
Figure 127. As Received Tee .................................................................................................. 124
Figure 128. Close up of Severed Insert ................................................................................... 125
Figure 129. Cap with Insert Attached ....................................................................................... 125
Figure 130. As Received .......................................................................................................... 126
Figure 131. Severed Coupling ................................................................................................. 127
Figure 132. Fracture Face ....................................................................................................... 127
Figure 133. As Received Service Tee with Socket Coupling ................................................... 128
Figure 134. Side View .............................................................................................................. 129
Figure 135. Bottom View .......................................................................................................... 129
Figure 136. 1 - ¾” Circumferential Slit on Underside of Coupling ............................................ 130
Title: DTPH56-06-T-0004 Final Report Page xv
Figure 137. As Received Coupling .......................................................................................... 131
Figure 138. Crack in Pipe Wall on ID ....................................................................................... 132
Figure 139. Side View of Socket Fusion .................................................................................. 132
Figure 140. As Received Socket Tee ...................................................................................... 133
Figure 141. Circumferential Slit in Fitting ................................................................................. 134
Figure 142. As Received Socket Tee ...................................................................................... 135
Figure 143. Circumferential Slit in Socket ................................................................................ 136
Figure 144. As Received Socket Tee ...................................................................................... 137
Figure 145. Crack on Socket Surface ...................................................................................... 138
Figure 146. Features on ID ...................................................................................................... 138
Figure 147: Photograph of Tee Showing Location of Leak ...................................................... 139
Figure 148. Close-up of Pipe Section with Tee as Seen in the Field. ...................................... 140
Figure 149. Left Side with No Bead Rollback and Right Side with Uneven Bead Rollback ..... 141
Figure 150. Close-up of Gap between Pipe Surface and Fitting .............................................. 141
Figure 151. Pressure Test to Identify Leak Location ............................................................... 142
Figure 152. Pipe Segment Surface from Under the Tee on the Side Containing the Leak ..... 143
Figure 153. Mating Surfaces of the Tee and Pipe ................................................................... 144
Figure 154. OIT and DSC – Outer Wall – Pipe ........................................................................ 146
Figure 155. OIT and DSC – Middle Wall – Pipe ...................................................................... 146
Figure 156. OIT and DSC – Inner Wall – Pipe ......................................................................... 147
Figure 157. FT-IR - Outer Wall – Pipe ..................................................................................... 148
Figure 158. FT-IR - Middle Wall – Pipe .................................................................................... 149
Figure 159. FT-IR - Inner Wall – Pipe ...................................................................................... 149
Figure 160. FT-IR – Good Fusion Area ................................................................................... 150
Figure 161. FT-IR - Poor Fusion Area ..................................................................................... 150
Figure 162. As Received Butt Fusion ...................................................................................... 152
Figure 163. Side View of Butt Fusion ....................................................................................... 153
Figure 164. Fusion Faces ........................................................................................................ 154
Figure 165. Inside Bead on One Side of Fusion ...................................................................... 154
Figure 166. As Received Butt Fusion ...................................................................................... 155
Figure 167. Incomplete Bead Rollover ..................................................................................... 156
Figure 168. As Received Butt Fusion ...................................................................................... 157
Figure 169. Fusion Faces Showing Cold Fusion Area ............................................................. 158
Figure 170. As Received Butt Fusion ...................................................................................... 159
Figure 171. Uneven Rollback ................................................................................................... 160
Title: DTPH56-06-T-0004 Final Report Page xvi
Figure 172. Side of Bead ......................................................................................................... 160
Figure 173. As Received .......................................................................................................... 161
Figure 174. Area of Cold Fusion .............................................................................................. 162
Figure 175. Fusion Faces ........................................................................................................ 162
Figure 176. As Received Butt Fusion ...................................................................................... 163
Figure 177. Leak Location at the Bead Weld ........................................................................... 164
Figure 178. View down the Inside of the Pipe Section ............................................................. 164
Figure 179. Close-up of the Inner Weld Bead .......................................................................... 165
Figure 180. As Received .......................................................................................................... 166
Figure 181. Weld Separation along ~3” Arc Length ................................................................. 167
Figure 182. Uneven Beads ...................................................................................................... 167
Figure 183. As Received .......................................................................................................... 168
Figure 184. Fusion Faces ........................................................................................................ 169
Figure 185. As Received 6” Butt Fusion .................................................................................. 170
Figure 186. Fusion Face, Valve ............................................................................................... 171
Figure 187. Fusion Face, Pipe ................................................................................................. 172
Figure 188. As Received .......................................................................................................... 173
Figure 189. Close Up View of Specimen ................................................................................. 174
Figure 190. Misalignment and Poor Bead Rollover at the Reducing Coupling ........................ 175
Figure 191. Back to Back Couplings ........................................................................................ 175
Figure 192. As Received .......................................................................................................... 176
Figure 193. Leak Location ....................................................................................................... 177
Figure 194. As Received .......................................................................................................... 178
Figure 195. End View of Pipe .................................................................................................. 179
Figure 196. Leak Location as Identified by Utility .................................................................... 179
Figure 197. As Received .......................................................................................................... 180
Figure 198. Leak Location as Identified by Utility .................................................................... 181
Figure 199. End View on Leak Side ......................................................................................... 181
Figure 200. As Received Socket Tee ...................................................................................... 182
Figure 201. Radial Distortion ................................................................................................... 183
Figure 202. Leak at Pipe/Socket Interface ............................................................................... 184
Figure 203. Close up of Pipe/Socket Interface ........................................................................ 184
Figure 204. Top and Side View of as Received Squeeze-off .................................................. 185
Figure 205. End View Showing Deformation ........................................................................... 186
Figure 206. Slit as Viewed from Inner Wall .............................................................................. 186
Title: DTPH56-06-T-0004 Final Report Page xvii
Figure 207. Top and Side View of as Received Sample .......................................................... 187
Figure 208. Dimpling and Buckling .......................................................................................... 188
Figure 209. Two of Three Squeeze Points Visible on the Inner Wall ....................................... 188
Figure 210. As Received Squeeze-off Sample ........................................................................ 189
Figure 211. Top and Sides of Squeeze Location ..................................................................... 190
Figure 212. Cavity and Deformation on Inner Wall .................................................................. 191
Figure 213. As Received Tap Tee ........................................................................................... 192
Figure 214. Underside of the Pipe and Saddle ........................................................................ 193
Figure 215. Side View of the Saddle ........................................................................................ 194
Figure 216. Leak Location ....................................................................................................... 194
Figure 217. As Received Tap Tee ........................................................................................... 195
Figure 218. Backside of Saddle Tee ........................................................................................ 196
Figure 219. Close-up of Backside of Tee ................................................................................. 197
Figure 220. Side of Tee ........................................................................................................... 197
Figure 221. As Received Tap Tee ........................................................................................... 198
Figure 222. Saddle Face .......................................................................................................... 199
Figure 223. Pipe Surface ......................................................................................................... 199
Figure 224. As Received Tap Tee ........................................................................................... 200
Figure 225. Backside of Tee .................................................................................................... 201
Figure 226. As Received Tap Tee ........................................................................................... 202
Figure 227. Socket of Tee, Side View ...................................................................................... 203
Figure 228. Ductile Tearing ...................................................................................................... 203
Figure 229. As Received .......................................................................................................... 204
Figure 230. Side and Bottom View of Transition ...................................................................... 205
Figure 231. As Received Sample - 3” Elbow ............................................................................ 206
Figure 232. Leak Location As Identified By a Soap Solution ................................................... 207
Figure 233. Cut Sample to Expose Inner Wall ......................................................................... 208
Figure 234. Portion of Elbow Containing Leak ......................................................................... 208
Figure 235. Inner Fusion Interface with Area of Observed Lack of Fusion .............................. 209
Figure 236. Fusion Interface .................................................................................................... 209
Figure 237. Force Fracture of the Sample, Showing Area of Observed Lack of Fusion .......... 210
Figure 238. Fractured Sample with the Elbow Side, Top, and Pipe Side, Bottom. .................. 210
Figure 239. Close up of the Fracture Faces with the Elbow Side on the Right ........................ 211
Figure 240. Fracture Face on the Elbow Side. Ductile Failure Region .................................... 211
Figure 241. Close up of the Fracture Face on the Pipe Side ................................................... 212
Title: DTPH56-06-T-0004 Final Report Page xviii
Figure 242. Fracture Face on the Pipe Side with an Area of Interest Identified....................... 212
Figure 243. Microscopy - Fracture Face of Elbow – Toward the Elbow Side ......................... 213
Figure 244. Microscopy – Fracture Face of Elbow – Toward the Pipe Side ............................ 213
Figure 245. Differential Scanning Calorimetry – Pipe .............................................................. 215
Figure 246. Oxidative Induction Time – Pipe ........................................................................... 215
Figure 247. Differential Scanning Calorimetry - Elbow ............................................................ 216
Figure 248. Oxidative Induction Time - Elbow ......................................................................... 216
Figure 249. FT-IR Outer Wall – Pipe ....................................................................................... 217
Figure 250. FT-IR Middle Wall – Pipe ...................................................................................... 218
Figure 251. FT-IR Inner Wall – Pipe ........................................................................................ 218
Figure 252. FT-IR - Outer Wall - Elbow ................................................................................... 219
Figure 253. FT-IR - Middle Wall - Elbow .................................................................................. 219
Figure 254. FT-IR - Inner Wall - Elbow .................................................................................... 220
Figure 255. As Received Sample Shown Leaking from Under the Cap .................................. 221
Figure 256. Valve with Leak Pinpointed ................................................................................... 222
Figure 257. Valve Was Halved to Help Expose O-Ring ........................................................... 223
Figure 258. Close up of the Core and Seal .............................................................................. 223
Figure 259. Valve Core with Indexing Marks ........................................................................... 224
Figure 260. Valve Core Removed from Housing ..................................................................... 224
Figure 261. Valve Core. Lower O-Ring Bottom ...................................................................... 225
Figure 262. O-Ring Damage. Upper O-Ring, Foreground. Lower O-Ring, Background. ....... 225
Figure 263. Imbedded Fragment Between Upper O-Ring and Core Land. .............................. 226
Figure 264. O-Ring Fragment Removed from the Upper O-ring Land Area. ........................... 226
Figure 265. Higher Magnification of Figure 264 ....................................................................... 227
Figure 266. FT-IR - Lower O-Ring Nitrile Rubber .................................................................... 227
Figure 267. FT-IR - Upper O-Ring Nitrile Rubber .................................................................... 228
Figure 268. As Received .......................................................................................................... 229
Figure 269. Up Close View of Damaged Pipe Section ............................................................ 230
Figure 270. As Received Sample of a Leaking Tee ................................................................. 231
Figure 271. Circumferential Slit on the Backside of the Tee .................................................... 231
Figure 272. Pipe Was Cut Away to Reveal the Inner Pipe Wall .............................................. 233
Figure 273. Damage on the Inner Wall .................................................................................... 233
Figure 274. Damage on the Inner Wall .................................................................................... 234
Figure 275. Tee Separated from Pipe during Force Fracture .................................................. 234
Figure 276. Fracture Face on the Pipe No Longer Attached to the Tee .................................. 235
Title: DTPH56-06-T-0004 Final Report Page xix
Figure 277. Opposing Fracture Face ....................................................................................... 235
Figure 278. Fracture Face Microscopy on the Pipe No Longer Attached to the Tee ............... 236
Figure 279. Opposing Fracture Face Microscopy .................................................................... 236
Figure 280. Differential Scanning Calorimetry ......................................................................... 238
Figure 281. Oxidative Induction Time ...................................................................................... 238
Figure 282. FT-IR - Outer Wall ................................................................................................ 239
Figure 283. FT-IR - Middle Wall ............................................................................................... 240
Figure 284. FT-IR - Inner Wall ................................................................................................. 240
Figure 285. As Received Sample ............................................................................................ 242
Figure 286. Brittle Plastic Seepage from the Tee .................................................................... 242
Figure 287. Oxidative Induction Time - Pipe ............................................................................ 244
Figure 288. Oxidative Induction Time - Tee ............................................................................. 244
Figure 289. Oxidative Induction Time - Seepage Material ....................................................... 245
Figure 290. Differential Scanning Calorimetry – Pipe .............................................................. 245
Figure 291. Differential Scanning Calorimetry – Tee ............................................................... 246
Figure 292. Differential Scanning Calorimetry – Seepage Material ......................................... 246
Figure 293. FT-IR Spectrum – Pipe Material ........................................................................... 247
Figure 294. FT-IR Spectrum – Tee Material ............................................................................ 248
Figure 295. FT-IR Spectrum – Seepage Material: Note ketone absorbance ........................... 248
Figure 296. As Received Fitting ............................................................................................... 250
Figure 297. Slit at Knit Line ...................................................................................................... 251
Figure 298. As Received Sample ............................................................................................ 252
Figure 299. Close up View of AMP Fitting ............................................................................... 253
Figure 300. As Received Sample ............................................................................................ 254
Figure 301. Socket Joint .......................................................................................................... 255
Figure 302. Area Identified as Leaking .................................................................................... 255
Figure 303. As Received Tee .................................................................................................. 256
Figure 304. Side View of Mechanical Tee ............................................................................... 257
Figure 305: Schematic of Growing RCP Crack. (Kanninen, Et Al., 1997) ................................ 268
Figure 306: Full Scale RCP Testing Result (Kanninen Et Al., 1997) ........................................ 271
Figure 307: S-4 Crack Initiation Result ..................................................................................... 273
Figure 308: GTI’s S-4 Testing Apparatus ................................................................................. 275
Figure 309: End Cap Contains a Port to Fill/Monitor Pipe Specimen. ...................................... 276
Figure 310: Assembly Anvil Prevents Excessive Pipe Wall Deformation during Impact........... 277
Figure 311: Schematic of Pipe Assembly Used at GTI ............................................................. 277
Title: DTPH56-06-T-0004 Final Report Page xx
Figure 312: Baffles and Anvil That Are Contained Within the Pipe Specimen .......................... 278
Figure 313: FET Analysis Showing the Extensive Deformation of a Pipe during RCP ............. 279
Figure 314: External Cage ........................................................................................................ 279
Figure 315: Blade Resting in the Crack It Initiated .................................................................... 280
Figure 316: 6” MDPE Critical Pressure Test Results: Critical Pressure: 15.5 Psig ................... 283
Figure 317: 6” MDPE Critical Temperature Test Results: Critical Temperature: 65.5 °F.......... 285
Figure 318: 6” MDPE S-4 Tests: Left, Crack Arrest; Right, Crack Propagation ........................ 286
Figure 319: 6” HDPE Critical Pressure Test Results: Critical Pressure: 17.0 Psig ................... 288
Figure 320: 6” HDPE Critical Temperature Test Results: Critical Temperature: 50.8 °F .......... 291
Figure 321: 6”HDPE S-4 Tests: Left, an Insufficient Crack Length; Right, Crack Propagation . 291
Figure 322: 6” PE100 Critical Pressure Test Results: Critical Pressure: 27.6 Psig .................. 293
Figure 323: 6” PE 100 Critical Temperature Test Results: Critical Temperature: 36.9 °F ........ 295
Figure 324: 6”PE100 S-4 Tests: Left, Initiation Test; Right, Crack Propagation ....................... 296
Figure 325: 8” MDPE Critical Pressure Test Results: Critical Pressure: 11.5 Psig ................... 298
Figure 326: 8” MDPE S-4 Tests: Left, Crack Arrest; Right, Crack Propagation ........................ 299
Figure 327: 8” PE 100 Critical Pressure Test Results: Critical Pressure: 27.0 Psig ................. 301
Figure 328: 8” PE 100 S-4 Tests: Left, Crack Arrest; Right, Crack Propagation ...................... 302
Figure 329: 12” MDPE Critical Pressure Test Results: Critical Pressure: 18.5 Psig ................. 304
Figure 330: 12” MDPE S-4 Tests: Left, Crack Arrest; Right, Crack Propagation ...................... 305
Title: DTPH56-06-T-0004 Final Report Page xxi
List of Tables
Table 1. NTSB Reported Brittle-Like Cracking Incidents ............................................................ 12
Table 2. Aldyl-A Melt Index Data 1965 - 1992 (DuPont) ............................................................. 33
Table 3. Aldyl-A Density Data, 1965 -1992 (unconfirmed by DuPont) ....................................... 33
Table 4. Comparative of Melt Index Test Data .......................................................................... 34
Table 5. Comparative of Average Tensile Strength Test Data .................................................. 35
Table 6. Comparative of Average Quick Burst Pressure Test Data ........................................... 36
Table 7. PENT Test Failure Time of Aldyl-A Pipe Lots (1973 - 1975) ....................................... 40
Table 8. PENT Test Failure Time of Aldyl-A Pipe Lots (1976 – 1979) ....................................... 41
Table 9. PENT Test Failure Time of Aldyl-A Pipe Lots (1979 – 1982) ....................................... 42
Table 10. PENT Test Failure Time of Aldyl-A Pipe Lots (1983 – 1985) ..................................... 43
Table 11. PENT Test Failure Times for Polypipe 4810 and Driscopipe 8100 ............................ 44
Table 12. Test Data for a 2 Inch Aldyl-A Pipe Manufactured In 1973 and Removed From Gas
Service in 1983. .......................................................................................................................... 59
Table 13. Predicted remaining life expectancy for PE gas pipe ................................................. 65
Table 14. Impingement Background ........................................................................................... 73
Table 15: Test Methods Used in Root-Cause Evaluation ........................................................... 77
Table 16: Melt Flow Measurements ............................................................................................ 77
Table 17. Tap Tee Background .................................................................................................. 83
Table 18: Melt Flow Measurements - Pipe ................................................................................. 88
Table 19. Impingement Background ........................................................................................... 92
Table 20. Slit Failure Background ............................................................................................... 96
Table 21. External Loading Background ..................................................................................... 98
Table 22. Cap Background ....................................................................................................... 108
Table 23. Cap Background ....................................................................................................... 110
Table 24. Cap Background ....................................................................................................... 112
Table 25.Cap Background ........................................................................................................ 114
Table 26. Cap Background ....................................................................................................... 116
Table 27. Cap Background ....................................................................................................... 118
Table 28. Cap Background ....................................................................................................... 120
Table 29. Service Tee Threads Background ............................................................................ 124
Table 30. Coupling Background ................................................................................................ 126
Table 31. Socket Coupling Background .................................................................................... 128
Table 32. Socket Coupling Background .................................................................................... 131
Title: DTPH56-06-T-0004 Final Report Page xxii
Table 33. Socket Tee Background ............................................................................................ 133
Table 34. Socket Tee Background ............................................................................................ 135
Table 35. Socket Tee Background ............................................................................................ 137
Table 36. 4” x 2” HVTT Background ......................................................................................... 140
Table 37: Melt Flow Measurements - Pipe ............................................................................... 145
Table 38: Melt Flow Measurements - Tee ................................................................................ 145
Table 39. 2” Butt Fusion Background ....................................................................................... 152
Table 40. 4” Butt Fusion Background ....................................................................................... 155
Table 41. 3” Butt Fusion Background ....................................................................................... 157
Table 42. 2” Butt Fusion Background ....................................................................................... 159
Table 43. 4” Butt Fusion Background ....................................................................................... 161
Table 44. 4” Butt Fusion Background ....................................................................................... 163
Table 45. 4” Butt Fusion Background ....................................................................................... 166
Table 46. 4” Butt Fusion Background ....................................................................................... 168
Table 47. Poly Valve Butt Fusion Background .......................................................................... 170
Table 48. Multiple Fusion Joints Background ........................................................................... 173
Table 49. Socket Fusion Coupling Background ........................................................................ 176
Table 50. Coupling Background ................................................................................................ 178
Table 51. Socket Tee Background ............................................................................................ 180
Table 52. Socket Tee Background ............................................................................................ 182
Table 53. 4” Single Bar Squeeze-off Background ..................................................................... 185
Table 54. 2” Squeeze-off Background ...................................................................................... 187
Table 55. Squeeze-off Background .......................................................................................... 189
Table 56. 1 – ¼” x 1” Tap Tee Background .............................................................................. 192
Table 57. 2” x 3/4” Tap Tee Background .................................................................................. 195
Table 58. 2” x 3/4” Tap Tee Background .................................................................................. 198
Table 59. 1 – ¼” x 1” Tap Tee Background .............................................................................. 200
Table 60. 2” x ½” Tap Tee - Socket Fusion Background .......................................................... 202
Table 61. Transition Fitting Background ................................................................................... 204
Table 62. 3” Elbow Background ................................................................................................ 206
Table 63: Melt Flow Measurements - Pipe ............................................................................... 214
Table 64: Melt Flow Measurements - Elbow ............................................................................. 214
Table 65. ¾” Valve Background ................................................................................................ 221
Table 66. Charred ¾” Pipe Background ................................................................................... 229
Table 67. 1 - Tap Tee Background ........................................................................................... 232
Title: DTPH56-06-T-0004 Final Report Page xxiii
Table 68: Melt Flow Measurements .......................................................................................... 237
Table 69. 4” x 4” Electrofusion Tee Background ....................................................................... 243
Table 70. 1 – ¼” Amp Fitting Background ................................................................................ 250
Table 71. 1 – ¼” x 1” Fitting Background .................................................................................. 252
Table 72. Tap Tee Background ................................................................................................ 254
Table 73. Bolt-on Tap Tee Background .................................................................................... 256
Table 74. Material Failures ....................................................................................................... 258
Table 75. Procedural Failures ................................................................................................... 260
Table 76. Quality Control Failures ............................................................................................ 261
Table 77. Miscellaneous Failures ............................................................................................. 261
Table 78. Other Failures ........................................................................................................... 261
Table 79. All Failures ................................................................................................................ 262
Table 80. Received Failures ..................................................................................................... 266
Table 81: Pipe Materials Used For the S-4 Testing .................................................................. 281
Table 82: 6'' MDPE Critical Pressure Test Results ................................................................... 282
Table 83: 6'' MDPE: Critical Temperature Test Results ............................................................ 284
Table 84: 6'' IPS HDPE Critical Pressure Test Results............................................................. 287
Table 85: 6'' HDPE Critical Temperature Test Results ............................................................. 289
Table 86: 6'' PE100 Critical Pressure Test Results .................................................................. 292
Table 87: 6'' HDPE Critical Temperature Test Results ............................................................. 294
Table 88: 8' MDPE Critical Pressure Test Results .................................................................... 297
Table 89: 8'' PE 100 Critical Pressure Test Results.................................................................. 300
Table 90: 12'' MDPE Critical Pressure Test Results ................................................................. 303
Table 91: Summary of S-4 Test Results ................................................................................... 306
Title: DTPH56-06-T-0004 Final Report Page 1
Abstract
The three primary failure modes that may be exhibited by polyethylene (PE) gas pipe
materials were described in detail. The modes are: ductile rupture, slow crack growth (SCG), and
rapid crack propagation (RCP). Short term mechanical tests were evaluated for usefulness in
determining the relative resistance of PE materials to SCG failures. Long-term hydrostatic stress-
rupture test data was used with various models to predict the remaining life expectancy of a few
older PE materials under specific field conditions. More than 50 field failures were classified by
cause. Small scale steady state (S-4) testing was conducted on six large diameter PE materials to
determine the critical pressure and/or the critical temperature.
Title: DTPH56-06-T-0004 Final Report Page 2
Executive Summary
Reports, publications, papers, and databases were reviewed to better define risks and threats
to plastic gas distribution piping. Failure modes were described for plastic PE piping with the
most significant being slow crack growth (SCG). Short-term mechanical tests such as tensile,
quick burst, melt index, and density tests did not show correlation with a material’s susceptibility
to SCG failure. The bend-back test was able to visually identify 1971 low-ductile inner wall
materials. PENT test failure times were reported for materials manufactured during the
period1972-1985. The PENT test did not show correlations with the material’s susceptibility to
SCG failure for these materials.
Life expectancy was determined to be a key measure of the susceptibility of PE gas pipe
materials to SCG field failures. Long term hydrostatic stress-rupture data combined with the Rate
Process Method or with the Bi-Directional Shift Functions predicted the remaining life
expectancy of several PE materials at 60°F average field temperature under varying loading
conditions. Data showed rock impingement loads and pipe squeeze offs can result in the greatest
reduction in remaining life expectancy. Lower operating field temperatures and pressures
significantly increased the predicted remaining life expectancy of PE materials.
Fifty-five PE pipe samples that failed in field service were examined in the laboratory to
identify the root cause of the failures. Eight of the samples underwent in-depth analysis, which
included density and melt index tests and differential scanning calorimetry, infrared
spectroscopy, and microscopic examination of the fracture surfaces. The samples were combined
with another set of additional data resulting in 45 material, 36 procedural, 12 quality control, and
7 miscellaneous failures. A separate categorization method attributed a total of 321 failures to
their respective pipe/component, with most occurring at joints.
RCP in large diameter PE materials was investigated through laboratory testing. Critical
pressure was determined for 6 pipe materials. Critical temperature was determined for 3
materials.
Title: DTPH56-06-T-0004 Final Report Page 3
Introduction
Statistics from the United States Department of Transportation (DOT) show more than
619,000 miles of plastic gas mains were in service at the end of 2006, up 75% since 1995. Of
these plastic pipes, polyethylene (PE) makes up nearly 97% and polyvinyl chloride (PVC) and
acrylonitrile butadiene styrene (ABS) make up the other 3%. In 1995, plastic pipe accounted for
just 35% of the total mileage of gas distribution mains. In 2006 that number grew to more than
50%. The percent contribution of each material to the total number of miles in the U.S.
distribution system is shown in Figure 1 and Figure 2 for 1995 and 2006 respectively. Comparison
of the data show that the increase in system size is largely due to plastic pipe installations. The
decline in steel and cast iron indicates these mains are being removed from service and are being
replaced by plastic materials.
Figure 1. Percentage of Miles of Main, 1995
Steel/Unprotected/Bare7%
Steel/Unprotected/Coated2%
Steel/Cathodically
Protected/Bare2%
Steel/Cathodically
Protected/Coated49%
Plastic Pipe35%
Cast Iron, Wrought Iron5%Ductile Iron
0%
Copper
0%Other(1)
0%
Other(2)
0%
Percentage of Main by Material, 1995
Source: PHMSA Distribution Annuals Reports
Title: DTPH56-06-T-0004 Final Report Page 4
Figure 2. Percentage of Miles of Main, 2006
From 1995 to 2006, the number of services in the U.S. grew by 8M to a total of 63.5M. In
1995, there were 26M plastic services. That number rose to 39.6M by the end of 2006. In terms
of the market share, plastic services represented ~48% of the total in 1995 as seen in Figure 3 and
61% of the total in 2006 as seen in Figure 4. PE makes up the majority of plastic services at
99.38%.
Figure 3. Percentage of Services, 1995
Steel/Unprotected/Bare
5%
Steel/Unprotected/Coated2%
Steel/Cathodically
Protected/Bare1%
Steel/Cathodically Protected/Coated41%
Plastic Pipe48%
Cast Iron, Wrought Iron
3%Ductile Iron0%
Copper0%
Other(1)
0%
Other(2)0%
Percentage of Main by Material, 2006
Source: PHMSA Distribution Annuals Reports
Steel/Unprotected/Bare8%
Steel/Unprotected/
Coated3%
Steel/Cathodically Protected/Bare1%
Steel/Cathodically Protected/Coated36%
Plastic Pipe48%Cast Iron, Wrought Iron
0%
Ductile Iron
0%
Copper3%
Other(1)1%
Other(2)0%
Percentage of Services by Material, 1995
Source: PHMSA
Distribution Annuals Reports
Title: DTPH56-06-T-0004 Final Report Page 5
Figure 4. Percentage of Services, 2006
Figure 5. Comparison of Total Services, Plastic Services, and PE Services in 2005
Steel/Unprotected/Bare
6%
Steel/Unprotected/Coated3%
Steel/Cathodically
Protected/Bare1%
Steel/Cathodically Protected/Coated25%
Plastic Pipe61%Cast Iron, Wrought Iron
0%
Ductile Iron
0%
Copper
2%Other(1)
2%Other(2)
0%
Percentage of Services by Material, 2006
Source: PHMSA
Distribution Annuals Reports
Number of Services, Total, Plastic, and PE
0
10,000,000
20,000,000
30,000,000
40,000,000
50,000,000
60,000,000
70,000,000
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005
Year
Se
r
v
i
c
e
s
Numbers of Services, Plastic Pipe Services, Total Plastic - PE Total Numbers of Services
Source: PHMSA
Distribution Annuals Reports
Title: DTPH56-06-T-0004 Final Report Page 6
The large magnitude of polyethylene pipes in the gas distribution system is undeniable. The
low life cycle cost and reliability will continue to encourage the installation of polyethylene
mains and services. In order to continue providing safe and reliable energy to gas distribution
customers, the failures, risks, and threats associated with polyethylene piping must be well
understood and that information needs to be available to gas distribution providers. Continued
laboratory testing of failures and material properties should provide additional benefits. The
findings must influence the pursuit to improve methods, procedures, and practices as they have
in the past.
Classification of Failures and Their Causes
Many published reports and surveys estimated that about 65% of all failures in PE gas pipes
are due to excavation damage. Outside of excavation damage, evaluations and laboratory
analyses have shown that plastic polyethylene (PE) gas pipe materials fail by one of three modes.
These modes are ductile rupture, brittle-like slow crack growth (SCG) failures, or rapid crack
propagation (RCP) failures. The majority of plastic PE pipe in-field failures are typically the
result of slow crack growth. About 1% of failures are ductile ruptures resulting from pipe over-
pressurization.
Ductile Rupture Failure Mechanism
Plastic pipes experience ductile rupture failures due to the presence of high internal
pressures. The failure mode is manifested in large localized plastic permanent deformations of
the pipe wall. For PE pipes, they occur as a result of increasing pressure to levels greater than
400psig. Increasing pressures cause the pipe to undergo large diametric expansions typically
resulting in wall thinning and stretching until a point where the remaining wall ligament is not
sufficiently large to withstand the induced high circumferential hoop stresses. Figure 6 and
Figure 7 show typical ductile failures in PE gas pipe materials subjected to high pressures.
Figure 6. Ductile Failure Resulting From a Quick Burst Test
Title: DTPH56-06-T-0004 Final Report Page 7
Figure 7. Ductile Failure Resulting From a Quick Burst Test
Slow Crack Growth Failure Mechanism
Slow crack growth (SCG) failures occur over long periods of time at relatively low loads
below the yield point of the material and are characterized by brittle (slit) fractures which exhibit
very little material flow or deformation. Using high-magnification scanning electron microscopy,
surface morphology of an SCG fracture can be characterized. Examinations show cracks initiate
and radiate from an initiation point. Initiation points are stress risers caused by inclusions,
contaminants, scratches, defects, cavities, dimples, high stress risers, etc. SCG failures grow
stepwise and are associated with the sequential formation and fracture of the craze damage zone
formed ahead of the crack tip. The damage zone consists of a main craze with a continuous
membrane at the crack tip. The duration of each craze corresponds to arrest periods for the
developed craze. At the end of an arrest period, the main part of the craze fractures. After a
period of time following the craze fracture, the membrane ruptures and leaves fibrils creating
visible and prominent striations indicative of the advancing crack front. The number of striations
formed during the SCG process corresponds to the number of step jumps in the progressive craze
formation and fracture process. Newer PE materials that are more resistant to SCG will show
many more striations as the process of craze formation and fracture occurs repeatedly until the
crack grows through the pipe wall.
Figure 8 shows an optical micrograph of the SCG failure process in the PE pipe specimen.
The SCG failure initiated on the inner diameter (ID) and grew in a SCG manner along the axial
direction and through the pipe wall to the outer diameter (OD) surface. The observed step-wise
growth of the SCG process, exhibited in the form of striation marks (or tidal waves) from ID to
OD, is typical of the SCG failure morphology observed for most of the PE gas pipe materials that
fail in service.

Title: DTPH56-06-T-0004 Final Report Page 8
Figure 8. SCG Failure Morphology
Rapid Crack Propagation (RCP) Failure Mechanism
RCP failures are manifested in the form of a large-scale brittle crack that propagates at high
speeds exceeding 300 ft/sec over a long span of polyethylene pipe. RCP failures could be
catastrophic due the rapid release of high volumes of gas over long spans. In order for RCP to
occur, a “critical” initial axial notch must exist in the pipe wall and the driving force has to
exceed the dynamic fracture resistance of the material. The dynamic fracture resistance decreases
with decreasing temperatures making PE materials more susceptible to RCP ruptures at lower
field temperatures. The susceptibility to RCP also increases with increasing field service
pressure, increasing pipe diameter, increasing dimension ratio, SDR, and decreasing modulus of
elasticity of the PE. Figure 9 shows an RCP rupture induced in a Small-Scale Steady State S-4
test.
Figure 9. RCP Rupture in a PE Pipe Subjected To a Small-Scale Steady State (S-4) Test
Title: DTPH56-06-T-0004 Final Report Page 9
Types of PE Failures
Failure types in PE gas pipe materials that are relevant to the project are:
x Internal Pressure – The pipe ruptures (ductile) from inability to sustain the internal
pressure.
x Plow-in, Insert Renewal, Installation Related – A failure of this sort may result from
high tensile pull loads exceeding the yield strength; excessive pipe bending; deep
surface scratches; or degradation due to excessive weathering, thermal degradation,
and/or absorption of hydrocarbons.
x Squeeze Off – Pipes damaged in squeeze-off operations can be attributed to very
high localized plastic deformations and cold-flow resulting from “over-squeezing”.
Brittle slit failures occur in the axial direction and usually initiate in the “ears” of the
squeeze-off at the inner pipe wall as micro-cracks before propagating through the
wall.
x Bending – The pipe experiences high bending stresses; a crack initiates on the outer
pipe wall at the section subjected to a maximum bending moment and grows through
the wall resulting in a circumferential slit.
x Earth Settlement –Transverse loads due to earth settlement can cause axial slow
crack growth slit failures to initiate along the axial direction on the inner pipe wall.
These slit failures grow through the wall and longitudinally.
x Rock Impingement – Impinging rocks induce high localized stresses leading to slit
SCG failures that initiate on the inner pipe surface and grow through the wall along
an off-axis direction.
x Material: Quality Control, Other Defects – Quality control issues include the
presence of inclusions, dimples, and cavities, etc. in the pipe wall; these defects act
as initiation sites for SCG failures.
x Butt Fusion – Lack of fusion or partial lack of fusion penetration is generally the
primary cause of failures in butt fusion joints. Inadequate fusion practices including
low heater temperature, insufficient heating time, low interfacial pressure, improper
squaring or misalignment of the pipe ends, contaminants, smudges, or lack of
cleaning can all cause failures within a butt fused joint.
x Mechanical Fitting Failures – Ground movement, improper installations, and
deterioration of components, e.g. gaskets can contribute to failures within
mechanical saddles and sockets. Seasonal temperature changes causing high tensile
thermal stresses may lead to pull-out failures.
x Fusion Fitting Failures – In general, the main reason for failures in fittings installed
using fusion methods are attributable to improper fusion conditions such as low
heater temperature, insufficient heating time, low interfacial pressure, inclusions,
dimples, cavities, contaminants, finger smudges, or lack of proper cleaning. These
causes can result in cold joints and lack of bonding.
Title: DTPH56-06-T-0004 Final Report Page 10
o End Caps and Tapping Tee Caps – End cap failures result from improper
bonding or material quality control defects within the cap. Tapping Tee caps
sometimes suffer from leaking o-rings, fracture of the cap at the threads, or
material quality control defects in the cap.
o Tees and Ells – Tees and ells generally fail from lack of bonding. Tees may
also fail from large external secondary stresses due to excessive bending and
high soil/earth loads. Manufacturing and material quality control defects
could also cause failures in both types of fittings.
o Socket Fusion – Lack of proper fusion bonding combined with excessive
external loads result in slit failures at the socket / pipe interface. Quality
control defects within the socket can cause failures.
o Saddle Fusion – Saddle fusions can suffer separation and/or blow out.
Quality control defects and improper fusion practices causing lack of fusion
can both contribute to failures in saddle fusion joints.
Project Structure
The project activities were performed under four major tasks. The task titles and major
objectives are:
x Literature Search – identify types, causes, frequency, and severity of plastic pipe
failures
x Slow Crack Growth – characterize SCG and predict remaining life expectancy of
materials and joints susceptible to premature SCG failures
x Root Cause Analysis – conduct laboratory examinations on field failures to
determine failure mode and identify cause
x S-4 RCP Testing – evaluate susceptibility of large diameter PE pipes to RCP failure
by performing S-4 tests
Title: DTPH56-06-T-0004 Final Report Page 11
Literature Review on Severity and Frequency of Plastic Pipe Failures
GTI performed a literature search of available publications to classify the frequency and
consequences associated with plastic pipe failures. The consequence of a plastic pipe failure can
range from a small amount of lost gas to substantial property damages or loss of life. Many
failures result in leaks that are so small they can go without repair and not pose a threat. There
was a lack of publically available data to classify these low consequence failures. Other failures
can cause explosions and fires which can result in serious events. Events resulting in loss of life
or $50,000 in property damages are reported in PHMSA’s “Natural Gas Distribution Incident
Data”. GTI obtained and analyzed the incident dataset from PHMSA’s “FOIA On-Line Library”
located at the website: http://ops.dot.gov/stats/IA98.htm.
DOT/PHMSA Natural Gas Distribution Incident Data Discussion
All records classified as “Other” for material type were reviewed for any information that
would justify changing the material type. For example, if the material was “other” and the
material specification was “PE2306” or “2306”, the material would be reclassified as
polyethylene. The remainder of “other” was left alone. Primary and secondary cause categories
were also reclassified if assumptions could be inferred. Usually, the records lacked enough
useful information to determine them to be anything but what they were: “Unknown” or “No
Data”.
Another difficulty of analyzing the data is the change in the reporting requirements in March
2004. The data from 1984 to 2004 had 5 primary cause categories. They are: Corrosion, Damage
by Outside Forces, Construction/Operating Error, Accidentally Caused by Operator, and Other.
The introduction of the new reporting format expands the primary cause to 7 categories, each
with sub-level or secondary causes. The major categories are: Corrosion, Natural Forces,
Excavation, Other Outside Force Damage, Materials or Welds, Equipment or Operations, and
Other. Some of the secondary causes have sub-causes. Without having the actual reports, it is
impossible to reclassify the old incidents into the new categories. A study done by Allegro
Energy Consulting actually used the operator’s reports to reclassify all the incidents from 1999 to
2003 to the new format. Incidents previously classified as “Damage by Outside Forces” were
reassigned into 5 of 7 of the new categories. “Other/No data” incidents fell into 6 of 7 of the new
categories.
The dataset for March 2004 to 2006 was a huge improvement over the previous years but
with less than 2 years of data, the sample of incidents is not large enough to deduce much. From
1984 to early 2004, more than 700 incidents involving plastic pipe were reported. More than 200
(nearly 30%) incidents were recorded as being of “Unknown” cause. Only 6% of the 2004 to
2006 data was reported as “Unknown.” It is unclear why some of the incidents had even been
reported as a number of records reported no injuries, loss of life, or property damages. A few of
the records were removed from the dataset because they were erroneous.
Severity of Failures
Some of the most significant incidents resulting from plastic pipe failures have been
attributed to brittle-like cracking. The National Transportation Safety Board published a Special
Investigation Report titled “Brittle-like Cracking in Plastic Pipe for Gas Service” in 1998. The
Title: DTPH56-06-T-0004 Final Report Page 12
Safety Board found the occurrence of slow crack growth (SCG) was second only to excavation
damage for older plastic pipe materials. A number of the incidents mentioned in the report are
shown in Table 1. The date, location, number of deaths and injuries, pipe manufacturer, and the
cause of the cracking are noted.
Table 1. NTSB Reported Brittle-Like Cracking Incidents
Date Location Deaths Injuries Manufacturer Cause
10/94 Waterloo, IA 6 7 Century Stress intensification
11/96 San Juan,
Puerto Rico 33 69 DuPont Inadequate support
08/97 Lake Dallas,
TX Nipak Loading by metal pipe
‘71 TX 1 Not Specified Loading on a
connection
‘73 MD 3 1 Not Specified Occluded particle
‘75 NC Not Specified Concrete drain resting
on service
‘78 AZ 1 5 Not Specified
‘78 NE 1 Century Inadequate support at
a fitting
12/81 AZ 3 Not Specified At a fitting
07/82 CA Not Specified Not Specified
09/83 MN 5 Century Rock Impingement
12/83 TX 1 1 Not Specified Squeeze
‘78, ‘79,
‘83 IL, IL, IA 5 Century Not Specified
‘95 MI Century Not Specified
In December 2002, the U.S. Department of Transportation issued an Advisory Bulletin titled
“Notification of the Susceptibility to Premature Brittle-Like Cracking of Older Plastic Pipe.” The
older polyethylene piping materials identified as being susceptible to premature SCG were:
x Century Utility Products, Inc. products.
x Low-ductile inner wall “Aldyl A” piping manufactured by DuPont Company before
1973.
x Polyethylene gas pipe designated PE 3306.
Another significant pipeline accident involving plastic piping occurred in DuBois,
Pennsylvania in August of 2004. It was investigated and subsequently, an NTSB report (PAB-
06-01) was issued. The leak, explosion, and fire resulted in $800,000 in property damages and 2
fatalities. Excavation of the 2-inch main uncovered a faulty butt-fusion joint with mitering of the
pipe ends. Further examination indicated the fracture initiation site was consistent with
inadequate fusion. As a result of the investigation, the NTSB recommended butt-fusion
procedures to “include a requirement for the avoidance of mitering” and the distribution
company to revise butt-fusion procedures and qualification procedures.
Title: DTPH56-06-T-0004 Final Report Page 13
An NTSB report (PAR-01-01), “Pipeline Accident Report: Natural Gas Explosion and Fire,
South Riding, Virginia, July 7, 1998” documents an explosion and fire that killed one person,
seriously injured another, leveled two houses, and damaged four other houses. The cause of the
failed gas pipe was determined to be heat damage from an electrical service. The gas company
has since revised their standards for minimum separation of PE pipes and electrical facilities to
be 12 inches. The report also referred to two other incidents involving electric line failures. In
Georgia in 1998, a 2-inch PE pipe was melted supposedly by a failed splice connector. During an
excavation of the pipe, the gas ignited and burned an employee. The other accident occurred in
Illinois in 1999. A fault in the electric cable supposedly melted a hole in the PE service.
Fortunately, nobody was injured but the sustained damages totaled $250,000.
“Pipeline Accident Report: Natural Gas Pipeline Rupture and Subsequent Explosion”
authored by the NTSB details an accident involving third party damage. A communications
network installation crew unintentionally cut a 1”, high pressure plastic gas service. Within 40
minutes of striking the line, an explosion occurred. There were 4 deaths and 11 injuries,
including 1 serious. Six buildings were obliterated. The estimated property damages totaled
$399,000.
Despite reports of failures attributed to materials or procedures, statistics show that the
number one cause of failures in plastic materials is caused by excavation damage. Excavation
damage is the largest contributor to the cost of damages, fatalities, and injuries as reported in
DOT/PHMSA natural gas distribution incident data. The same is true for steel materials. Failures
that could be considered plastic pipe failures as a result of material or components cost the
industry less than $5M from 1984 to 2006. Figure 10 and Figure 12 break down the cost of
damages by the primary cause of the incident for various material types. Third party damage is
considered a secondary cause and is categorized under “Damage by Outside Forces” in the 1984
dataset and “Excavation” in the 2004 dataset. Figure 11 and Figure 13 show the cost of third
party damages by material. In the last 22 years, third party damages cost the industry more than
$49M for plastic pipe and $79M for steel. These costs are only those associated with reportable
incidents and the actual total cost of third party damages would be larger if non-reportable
damages were counted.
Title: DTPH56-06-T-0004 Final Report Page 14

Figure 10. Cost of damages categorized by cause from 1984 - March 2004
Figure 11. Cost of Outside Force Damages by Secondary Cause from 1984 - March 2004
Cost by Cause and Material
0
10
20
30
40
50
60
70
80
90
Steel Plastic Iron Copper Other No data
Material
Co
s
t

i
n

M
i
l
l
i
o
n
s

o
f

D
o
l
l
a
r
s
Accidentally Caused by Operator (Total)
Const/Oper Error (Total)
Corrosion (Total)
Damage by Outside Forces (Total)
No Data (Total)
Other (Total)
Source: PHMSA Natural Gas
Distribution Incident Data 1984-2004
Cost of Damage by Outside Forces and Secondary Causes by Material
0
10
20
30
40
50
60
70
80
90
Steel Plastic Iron Copper Other No data
Material
Co
s
t

i
n

M
i
l
l
i
o
n
s

o
f

D
o
l
l
a
r
s
Damage by Outside Forces (Total)
Earth Movement: Frost
Earth Movement: Landslide/Washout
Earth Movement: Other
Earth Movement: Subsidence
Lightning or Fire
No Data
Operator Action
Outside/ Third Party
Source: PHMSA Natural Gas
Distribution Incident Data 1984-2004
Title: DTPH56-06-T-0004 Final Report Page 15
Figure 12. Cost of Damages Categorized By Cause from March 2004 - 2006
Figure 13. Cost of Excavation Damages by Secondary Cause from March 2004 - 2006
Cost by Cause and Material
0
2
4
6
8
10
12
Steel Plastic Iron Other
Material
Co
s
t

i
n

M
i
l
l
i
o
n
s

o
f

D
o
l
l
a
r
s
Corrosion (Total)
Equipment or Operations (Total)
Excavation (Total)
Material or Welds (Total)
Natural Forces (Total)
Other (Total)
Other Outside Force (Total)
No Data (Total)
Source: PHMSA Natural Gas
Distribution Incident Data 2004-2006
Cost of Excavation Damage and Secondary Causes by Material
0
2
4
6
8
10
12
Steel Plastic Iron Other No data
Material
Co
s
t

i
n

M
i
l
l
i
o
n
s

o
f

D
o
l
l
a
r
s
Excavation (Total)
Operator
Third Party
Source: PHMSA Natural Gas
Distribution Incident Data 2004-2006
Title: DTPH56-06-T-0004 Final Report Page 16
Figure 14 through Figure 17 show the total number of deaths and injuries reported to DOT
since 1984. Figure 14 and Figure 15 demonstrate the number of fatalities reported by primary
cause and material. Third party damage caused more than 60 deaths involving steel piping and
about 40 deaths in plastic. Figure 15 shows 7 deaths with “Natural Forces” as the primary cause.
Four of these fatalities occurred because of lightning. The other three fatalities were related to
temperature or frost/thaw cycles. In both incidents, there was ignition and explosion. Only a
handful of fatalities were caused by a compromised plastic pipe segment, joint, or component.
“Other” is the second largest category, especially from the 1984 to 2004 dataset. A discussion of
the datasets follows Figure 18.
Figure 14. Fatalities by Primary Cause As Reported From 1984 - March 2004
Primary Cause of Fatalities by Material
0
10
20
30
40
50
60
70
Steel Plastic Iron Copper Other No data
Material
Fa
t
a
l
i
t
i
e
s
Accidentally Caused by Operator (Total)
Const/Oper Error
Corrosion
Damage by Outside Forces
No Data
Other
Source: PHMSA Natural Gas
Distribution Incident Data 1984-2004
Title: DTPH56-06-T-0004 Final Report Page 17
Figure 15. Fatalities by Primary Cause As Reported From March 2004 - 2006
Figure 16 and Figure 17 show the primary cause of injuries for each of the datasets.
“Damage by Outside Forces” dominates the 1984 dataset. The bulk of these injuries were
reported as third party damage. The 2004 dataset also shows 20+ injuries from “Excavation.”
“Corrosion” was responsible for approximately 75 injuries related to steel piping. “Other” was
also reported often in both datasets. Material, joints, and components attributed for a small
number of injuries in any given material. Figure 18 demonstrates the total cost of the reported
incidents per material. The cost of damages to steel was greater than damages to plastic materials
for both datasets. Hurricane Katrina caused more than $450M in damages. It was classified as
“No data” for material type. The incident was reported for the entire city of New Orleans and
likely included multiple material types.
Primary Cause of Fatalities by Material
0
1
2
3
4
5
6
7
8
Steel Plastic Iron Other
Material
Fa
t
a
l
i
t
i
e
s
Corrosion (Total)
Equipment or Operations (Total)
Excavation (Total)
Material or Welds (Total)
Natural Forces (Total)
Other (Total)
Other Outside Force (Total)
No Data (Total)
Source: PHMSA Natural Gas
Distribution Incident Data 2004-2006
Title: DTPH56-06-T-0004 Final Report Page 18
Figure 16. Injuries by Primary Cause As Reported From 1984 - March 2004
Figure 17. Injuries by Primary Cause As Reported From March 2004 - 2006
Primary Cause of Injuries by Material
0
50
100
150
200
250
300
350
Steel Plastic Iron Copper Other No data
Material
In
j
u
r
i
e
s
Accidentally Caused by Operator (Total)
Const/Oper Error
Corrosion
Damage by Outside Forces
No Data
Other
Source: PHMSA Natural Gas
Distribution Incident Data 1984-2004
Primary Cause of Injuries by Material
0
2
4
6
8
10
12
14
16
Steel Plastic Iron Other
Material
In
j
u
r
i
e
s
Corrosion (Total)
Equipment or Operations (Total)
Excavation (Total)
Material or Welds (Total)
Natural Forces (Total)
Other (Total)
Other Outside Force (Total)
No Data (Total)
Source: PHMSA Natural Gas
Distribution Incident Data 2004-2006
Title: DTPH56-06-T-0004 Final Report Page 19
Figure 18. Total Cost of Reported Incidents for Each Data Period
Frequency of Failures
Looking at the statistical data from 1984 to 2006, the predominant cause of plastic and steel
pipe failures was third party damage. Fire is the next significant cause of incidents in plastic
piping. Reports on earth movement from the 1984 to 2004 dataset may be slightly high because
they include items that were described as “object in backfill”, “settling”, and “tree roots”.
Operator excavation and earth movement were about equally common and when combined cause
roughly the same number of failures as fire. Beyond that, little can be said with any certainty
based on the data other than without third party damage and fire; gas transport via plastic piping
is incredibly safe. The frequencies of failures are categorized by primary cause and material in
Figure 19 and Figure 20.
Cost of Incidents by Material
0
50
100
150
200
250
300
350
400
450
500
Steel Plastic Iron Other No data
Material
Co
s
t

i
n

M
i
l
l
i
o
n
s

o
f

D
o
l
l
a
r
s
Total 04-06
Total 84-04
Source: PHMSA Natural Gas Distribution
Incident Data 1984-2004 & 2004-2006
Hurricane
Katrina
Title: DTPH56-06-T-0004 Final Report Page 20
Figure 19. Frequency of Failures by Cause from 1984 - March 2004
Figure 20. Frequency of Failures by Cause from March 2004 - 2006
Primary Causes by Material
0
100
200
300
400
500
600
700
800
900
Steel Plastic Iron Copper Other No data
Material
In
c
i
d
e
n
t
s
Accidentally Caused by Operator (Total)
Const/Oper Error (Total)
Corrosion (Total)
Damage by Outside Forces (Total)
No Data (Total)
Other (Total)
Source: PHMSA Natural Gas
Distribution Incident Data 1984-2004
Primary Cause by Material
0
10
20
30
40
50
60
70
80
90
Steel Plastic Iron Other No data
Material
In
c
i
d
e
n
t
s
Corrosion (Total)
Equipment or Operations (Total)
Excavation (Total)
Material or Welds (Total)
Natural Forces (Total)
Other (Total)
Other Outside Force (Total)
No Data (Total)
Source: PHMSA Natural Gas
Distribution Incident Data 2004-2006
Title: DTPH56-06-T-0004 Final Report Page 21
Failure by PE type was also analyzed. Unfortunately, the material specification was not
consistently reported. Roughly one-third of the 1984 to 2004 data was specified. The chart
generated from this data is shown in Figure 21. The most common material specified was PE
2306 which may represent the amount of the material installed or the crew member’s familiarity
with the material making it recognizable, resulting in the ability to report this particular PE. PE
2406 was also highly reported. The failures by PE type are shown in Figure 21 and Figure 22for
1984 to 2004 and 2004 to 2006 respectively. In the latter chart, only a small number of types
were reported. PE 2406 and 3406 were reported more often than other material designations.
Figure 21. Frequency of Failures by Type of PE and Cause for 1984 - 2004
Incidents by Primary Cause and PE Designation
0
50
100
150
200
250
300
2306 2406 3306 3406 3408 Unknown
PE
In
c
i
d
e
n
t
s
Accidentally Caused by Operator
Const/Oper Error
Damage by Outside Forces
No Data
Other
Source: PHMSA Natural Gas
Distribution Incident Data 1984-2004
Title: DTPH56-06-T-0004 Final Report Page 22
Figure 22. Frequency of Failures by Type of PE and Cause for 2004 - 2006
Incidents by Primary Cause and PE Designation
0
10
20
30
40
50
60
70
80
2306 2406 3306 3406 3408 Unknown
PE
In
c
i
d
e
n
t
s
Equipment or Operations
Excavation
Material or Welds
Natural Forces
Other
Other Outside Force
Source: PHMSA Natural Gas
Distribution Incident Data 2004-2006
Title: DTPH56-06-T-0004 Final Report Page 23
A chart was also created to look at the failures by manufacturer and cause for the 1984
dataset. Drisco Phillips, DuPont, and Plexco were the top three reported. This should correlate to
the amount of these materials in the ground but cannot be concluded without knowing how much
of these materials are still in operation. The chart is shown in Figure 23.
Figure 23. Frequency of Incidents by Manufacturer and Cause for 1984 - March 2004
Primary Cause by Manufacturer
0
20
40
60
80
100
120
Drisco Dupont Nipak Phillips Plexco Uponor Not Specified Others
Manufacturer
In
c
i
d
e
n
t
s
Accidentally Caused by Operator
Const/Oper Error
Corrosion
Damage by Outside Forces
No Data
Other
Source: PHMSA Natural Gas
Distribution Incident Data 1984-2004
Title: DTPH56-06-T-0004 Final Report Page 24
A chart was also created for the failures by manufacturer and cause for the second dataset. It
is shown in Figure 24. Again, Drisco and Plexco were among the top. Most of the plastic piping
damaged by third party was not specified by manufacturer in either chart.
Figure 24. Frequency of Incidents by Manufacturer and Cause for March 2004 - 2006
Another analysis made was the failure types by time of day. The number of incidents peaked
between 8 A.M. and 6 P.M. Most of these failures are reported as damage by outside forces and
excavation. Third party damage as a secondary failure was included in the charts in Figure 25
and Figure 26. Fire and lightning and fire or explosion as secondary causes were also included
and are more common in the hours after midnight and around lunchtime.
Primary Cause by Manufacturer
0
5
10
15
20
25
30
35
40
45
50
Drisco Dupont Nipak Perfomance Plexco PolyPipe Uponor Not Specified Others
Manufacturer
In
c
i
d
e
n
t
s
Equipment orOperations
Excavation
Material or Welds
Natural Forces
Other
Other OutsideForce
Source: PHMSA Natural Gas
Distribution Incident Data 2004-2006
Title: DTPH56-06-T-0004 Final Report Page 25
Figure 25. Frequency of Plastic Incidents by Time of Day from 1984 - March 2004
Figure 26. Frequency of Plastic Incidents by Time of Day from March 2004 – 2006
Plastic Incidents by Cause and Time of Day
0
20
40
60
80
100
120
0:00 - 1:59 2:00-3:59 4:00-5:59 6:00-7:59 8:00-9:59 10:00-11:59 12:00-13:59 14:00-15:59 16:00-17:59 18:00-19:59 20:00-21:59 22:00-23:59
Time of Day
In
c
i
d
e
n
t
s
Accidentally Caused by Operator
Const/Oper Error
Damage by Outside Forces
No Data
Other
Lightning or Fire (Secondary)
Outside/Third Party (Secondary)
Source: PHMSA Natural Gas
Distribution Incident Data 1984-2004
Plastic Incidents by Cause and Time of Day
0
2
4
6
8
10
12
14
16
18
20
0:00 - 1:59 2:00-3:59 4:00-5:59 6:00-7:59 8:00-9:59 10:00-11:59 12:00-13:59 14:00-15:59 16:00-17:59 18:00-19:59 20:00-21:59 22:00-23:59
Time of Day
In
c
i
d
e
n
t
s
Equipment or Operations
Excavation
Material or Welds
Natural Forces
Other
Other Outside Force
Fire/Explosion (Secondary)
Third Party Excavation (Secondary)
Source: PHMSA Natural Gas
Distribution Incident Data 2004-2006
Title: DTPH56-06-T-0004 Final Report Page 26
Susceptibility of PE to Slow Crack Growth Failures
Objective
The objectives of the slow crack growth task were to utilize GTI’s database to determine the
susceptibility of plastic gas pipe materials and fusion joints to slow crack growth and to predict
their remaining life expectancies using engineering models.
Types of PE Gas Pipe Materials in GTI Database
The plastic pipe materials comprising GTI database were of different diameters and SDR’s
and were manufactured during the period extending from about 1965 to about 2003. A few of the
pipe materials were manufactured during the same year but in different months and were
installed by different gas companies. The PE gas pipes comprising the GTI database were
installed in many different geographical regions throughout the U.S.
The GTI database includes many plastic PE gas pipes that were made from different PE
resin materials and extruded into pipe form by several different pipe manufacturers. Many of
these PE resin manufacturers and pipe extruders are no longer in business. The plastic gas pipe
materials in the database were made from several different medium-density polyethylene
(MDPE) and high-density polyethylene (HDPE) gas-grade resin materials.
The DuPont Company began manufacturing Aldyl-A MDPE pipe materials for gas
distribution applications in the 1960’s. DuPont continued to manufacture Aldyl-A pipe materials
until about 1991. Uponor Company purchased the Aldyl-A pipe product line during the period
1991-1992. Uponor continued to manufacture and market Aldyl-A pipe product line until about
1999. Uponor began using their company name during the period 1992.
Aldyl-A pipe materials are medium-density polyethylene (MDPE) gas-grade pipe materials.
From the 1960’s to about 1986, Aldyl-A MDPE pipe materials were categorized/designated by
ASTM as PE 2306 grade. In 1986, the Aldyl-A MDPE pipe materials were designated by ASTM
as PE 2406 grade.
During the period 1965 to 1987, DuPont was one of the largest PE pipe manufacturers and
had more than 40% of the market share. Many gas distribution companies installed Aldyl-A
pipes in their system. Because of this, this report presents substantial information on Aldyl-A PE
gas pipe materials.
Detailed List of PE Resin and Pipe Manufacturers
A detailed list of the names of many PE resin producers and pipe extruders that
manufactured the largest percentage of the PE pipe materials comprising GTI database, is
presented in GTI Report Number GRI-98/0355 entitled “Handbook of Hydrostatic Stress-
Rupture Data for Plastic Pipe Materials Used for Gas Distribution”.
Visual and Optical Examinations of Slow Crack Growth Failures
Figure 27 shows an Aldyl-A MDPE pipe sample that experienced a SCG axial slit
failure/leak while in a standard long-term laboratory test under a constant internal pressure.
Microscopic examinations showed that the failure initiated at a very small (less than 5-mills in
depth) surface pin-size hole on the inner pipe surface. The examination also showed that the pin-
Title: DTPH56-06-T-0004 Final Report Page 27
size hole grew in an SCG mode along the axial direction and through the pipe wall. The final
failure was in the form of an axial slit visible on the pipe outer surface.
Figure 27. Pipe Exhibited Through Wall Axial Slit While Under Internal Pressure
The SCG fracture morphology depicted above in Figure 8 is typical of failures that occur in
PE gas pipes subjected to internal pressure and/or internal pressure combined with a secondary
stress such as those induced by an impinging rock, a squeeze-off, or an earth or soil load.
However, under a combined load involving an internal pressure and a secondary stress, the
location and orientation of the SCG axial slit are different than that shown in Figure 27.
SCG Failures Due to Rock Impingement Loads
Visual examinations show that rock impingement field failures exhibit a surface indentation
on the outer pipe surface. Typically, the failure in a pipe specimen subjected to both internal
pressure and a rock impingement load is visually observed to be a slit through the wall. The slit
is oriented slightly off the pipe axis.
Figure 28 shows a slit on the outer surface of an Aldyl-A pipe sample that experienced
failure as a result of internal pressure combined with a rock impingement indentation load. The
failure initiated on the inner pipe surface underneath the impinging rock/indenter. The failure
grew though the pipe wall and in a direction that was oriented at an angle of about 20-degree
relative to the pipe longitudinal axis.
Title: DTPH56-06-T-0004 Final Report Page 28
Figure 28. Rock Impingement Failure
Figure 29 shows that a slit failure induced by an impinging rock load, initiated on the inner
pipe surface. Examinations of pipes that failed due to rock impingement loads clearly show that
the failure morphology is SCG brittle slit processes similar to that observed in pipes subjected to
internal pressure as shown in Figure 8.
Figure 29. Off-Axis Slit Failure that Initiated on the ID Due to an Impinging Rock
Figure 30 shows a PLEXCO PE 2306 MDPE gas pipe specimen that failed in field service
due to an impinging rock. Visual and microscopic examinations showed that this rock-
impingement field failure resulted in a slit that initiated on the inner pipe surface and grew
Title: DTPH56-06-T-0004 Final Report Page 29
through the pipe wall to the outer surface. The orientation of the slit was slightly off the pipe
longitudinal axis.
Figure 30. Rock Impingement Failure Induced in Field Service
The fracture surface was examined using optical microscopy. Figure 31 shows the fracture
surface morphology under magnification. This figure shows the crack initiation point on the ID
and the progressive SCG growth of the damage zone and the crack. This SCG failure process is
manifested in the form of the striation marks corresponding to the progressive incubation,
initiation and growth of the crazed material over several periods.
Figure 31. Micrograph of the SCG Fracture Surface of a Rock Impingement Failure
Title: DTPH56-06-T-0004 Final Report Page 30
SCG Failures Due to Squeeze-Off Operations
When a pipe is subjected to a squeeze-off, for instance along the 6 o’clock-12 o’clock
direction, the amount or percent of squeeze is measured from the point at which the two inner
pipe surfaces first establish surface-to-surface contact. Laboratory examinations of some older
MDPE gas pipe materials that failed due to a squeeze-off show that between about 15% and 25%
squeeze, damage initiates on the inner pipe surface at the squeeze “ears” that are produced along
the 3 o’clock-9 o’clock direction.
Figure 32 is a photograph of an Aldyl-A pipe sample that exhibited SCG failure/leak at the
ears of the squeeze-off. Figure 33 shows the inner surface of the Aldyl-A pipe sample shown in
Figure 32.
Figure 32 and Figure 33 demonstrate that the squeeze-off caused material crazing
manifested in the form of material whitening, discoloration, and some surface roughening. The
craze initiated first on the inner surface at the squeeze “ears”. Then the damage grew through the
wall and unto the outer surface. As the amount of squeeze, or pipe wall compression increased,
more of the material experienced crazing/damage.
Figure 32. Failure of an Aldyl-A Pipe at Squeeze Ears
Figure 33. Inner Surface of an Aldyl-A Pipe Subjected to About 15% Squeeze
Title: DTPH56-06-T-0004 Final Report Page 31
With excessive squeeze-off, large voids, whitening, and cracks develop at the squeeze ears
on the inner pipe surface. At the ears, the pipe undergoes permanent localized large plastic
deformations and wall thinning. Also, an axial slit can initiate on the inner pipe surface at the
“ears” and grow axially through the pipe wall. Photographs of a MDPE 2306 pipe that failed in
field service due to excessive squeeze-off are shown in Figure 34 to Figure 36.
Figure 34. MDPE Pipe that Failed in Field Service Due to a Squeeze-Off
Figure 35. End View Depicting Large-Scale Deformations Due to a Squeeze-Off
Title: DTPH56-06-T-0004 Final Report Page 32
Figure 36. Pipe ID with Axial Slit at the Ears of Pipe Shown in Figure 34
The observed SCG slit failure mode in the squeezed pipe specimen is similar to failures
exhibited by specimens subjected to internal pressure or internal pressure combined with a rock
impingement load. The SCG failure mode observed in squeeze-off involves the progressive
striations indicative of incubation and growth of the crack-tip-opening displacement (CTOD)
through the pipe wall.
Title: DTPH56-06-T-0004 Final Report Page 33
Short-Term Laboratory Tests
A number of short-term tests have been performed on plastic pipe materials received from
different gas companies and resin and pipe manufacturers. The short-term tests were performed
to determine whether or not the material properties and/or the short-term mechanical strength
properties of PE gas pipe materials have undergone any detrimental changes due to aging in field
service. Melt Index, Tensile Strength, Quick Burst, PENT, and Bend-Back Tests were conducted
to determine whether or not they can provide information on the relative susceptibility of PE
pipe materials to SCG failures.
Melt Index
Table 2 presents the Melt Index data published by DuPont on Aldyl-A pipe materials
manufactured during the period 1965 to 1992. However, other sources of information
(unconfirmed by DuPont) reported that DuPont made several changes to the PE resin, the co-
polymer, and/or polymerization catalyst used for manufacturing Aldyl-A gas pipe materials
during the period 1965 to 1992. Table 3 presents data made available to GTI by other sources
(unconfirmed by DuPont) on the various Aldyl-A pipe materials manufactured by DuPont. Table
2 lists the Aldyl-A material density, the name and type of resin, and the amount or the type of the
co-polymer used for manufacturing Aldyl-A pipe materials during the period 1965 to 1992.
ALDYL-A Melt Index and Density Data (1965 – 1992)
Table 2. Aldyl-A Melt Index Data 1965 - 1992 (DuPont)
Manufacturing Period Manufacturer Reported Melt Index (g/10 min)
1965 – 1970 1.9
1971 - 1983 1.2
1983 - 1987 1.1
1988 - 1991 1.1
1992 1.1
Table 3. Aldyl-A Density Data, 1965 -1992 (unconfirmed by DuPont)
Manufacturing
Period of an Aldyl-A
Pipe Group
Density
(g/cm3)
Resin Trade
Name/Number
Co-Monomer
Type
1965 to 1969 0.933 Alathon/5040 Butene
1970 to 1983 0.938 Alathon/5043 Butene
1984 to 1987 0.938 Alathon/5046 Octane
1988 0.938 Alathon/5046 C Octane (increased amount)
1989 0.933 Alathon/5046 U Octane (increased amount)
1990 to 1991 0.933 Alathon/5046 O Octane (changed amount
and type)
1992 0.933 UAC 2000 / TR-418 Hexene
The melt index and density are important material properties of the resin. Changes in these
properties are indicative of changes in the resin, co-polymer, catalyst and crystallinity, molecular
structure, aging, or potential degradation of the PE material.
Title: DTPH56-06-T-0004 Final Report Page 34
Changes in the PE monomer resin, the co-polymer, and or the catalysts used during
polymerization have direct effect on the Melt Index (MI), the density, and the molecular weight,
number, and distributions. The MI is related to the PE material molecular weight and
distribution. The MI is an important material property of a PE pipe material. Changes in the MI
can have a direct and important effect on the amount of melted material and flow rates, bonding,
and solidification rates during heat-fusion or electro-fusion joining of PE gas pipe materials.
Changes in the MI of a PE pipe material are indicative of changes in density and
crystallinity. Tests have shown that as the density increases, the amount of crystallinity of PE
materials increases and the melt flow index decreases.
GTI database includes laboratory test data on the melt flow index of a several Aldyl-A pipe
lot materials. The melt index data were obtained per ASTM D 1238 Specifications.
GTI’s MI test data presented in Table 4 is the average of three replicate test specimens
prepared from pipe samples removed from field service. The MI test data presented in Table 4
was measured by GTI for several Aldyl-A pipe materials made of 4-inch and 6-inch pipe sizes
and manufactured during different periods including 1971, 1983, and 1988 (see Table 2). For
comparative evaluations, Table 4 also gives the MI data generated by DuPont for similar
unexposed (virgin) resins or pipe materials.
Table 4. Comparative of Melt Index Test Data
Test Sample # Pipe Diameter
(Inches)
Pipe
Manufacturing
Year
Manufacturing
Period of the
Resin Group
Melt Index-
GTI Lab Data
(g/10min)
Melt Index-
DuPont Data
(g/10min)
1a 4 1980 1971 1.28 1.2
2a 4 1984 1983 1.09 1.1
3a 4 1986 1983 1.08 1.1
4a 4 1988 1988 1.00 1.1
1b 6 1980 1971 1.12 1.2
2b 4 1981 1971 1.24 1.2
3b 6 1982 1971 1.18 1.2
1c 4 1983 1983 1.08 1.1
2c 6 1984 1983 0.93 1.1
3c 4 1985 1983 1.08 1.1
4c 6 1985 1983 1.02 1.1
1d 4 1986 1983 1.19 1.1
2d 6 1986 1983 0.91 1.1
Comparative evaluations show negligible difference between the average MI of the Aldyl-A
pipes that were in underground gas service for about 25 years and the average MI data of the
virgin unexposed pipe materials that were published by DuPont. The negligible differences in the
MI measurements are most likely due to laboratory-to-laboratory variability.
Therefore, it may be concluded that aging in field service had negligible effects on the
MI of the listed Aldyl-A materials even though DuPont used different resins and
copolymers in processing these materials (see Table 3).
Title: DTPH56-06-T-0004 Final Report Page 35
It may be concluded that Melt Index test data may not provide information on the
relative susceptibility of PE gas pipe materials to SCG field failures.
Tensile Strength
GTI database includes data obtained from several short-term mechanical strength tests. One
of these tests is the Tensile Test conducted in accordance with ASTM D638. Tensile tests were
conducted on Aldyl-A pipe samples that were removed from gas service. Table 5 presents the
average tensile strength data (of several replicate samples) obtained on the listed Aldyl-A
MDPE pipe samples and on a newer shelf-aged “virgin” MDPE gas pipe material manufactured
in 2001. It may be noted that these pipe material were manufactured during different years
spanning the period 1970 to 1991 and were installed in different geographical regions throughout
the U.S. Hence, some samples were in gas service for 30 years and others were in service for 12
years. One of the Aldyl-A pipe materials listed in Table 5 was in gas service for about 10 years.
Since any changes in the tensile strength properties may be indicative of aging in field
service and consequently increased susceptibility to SCG failures, one may compare the tensile
strength properties of the Aldyl-A MDPE gas pipe materials listed in Table 5.
Table 5. Comparative of Average Tensile Strength Test Data
Pipe Material
/Year of Manufacture
Tensile
Strength
(psi)
%
Elongation
at Break
%
Elongation
at Yield
Modulus
(psi)
Stress at
Break
(psi)
3” IPS SDR 11.5 DuPont Aldyl A
/1970 2,775 635 15 121,000 1,947
3” IPS SDR 11.5 DuPont Aldyl A
/1977 2,773 588 13 141,000 1,767
4” IPS SDR 11.5 DuPont Aldyl A 2,758 534 12 136,000 1,683
3” IPS SDR 11.5 DuPont Aldyl A
/1983 2,862 605 14 139,00 1,885
4” IPS SDR 11.5 DuPont Aldyl A
/1991 2,799 625 14 131,000 2,324
2” SDR 11 Aldyl-A Pipe /1973
(Removed from Service in 1983) 2,275 105,000
Uponor UAC 2000 MDPE /2001 3,180 619 12 122,000 3,179
It should be noted that the newer Uponor MDPE pipe manufactured in the year 2001 was compounded using a
totally different resin and processing methods. The Uponor material is listed to show the significantly increased
tensile strength and the stress at break compared to the other older Aldyl-A materials.
On the basis of the comparative evaluations, it may be noted that there are negligible
differences between materials in the tensile strength, percent elongation at break and at yield, and
Title: DTPH56-06-T-0004 Final Report Page 36
tensile modulus. The stress at break of the 1991 pipe material is about 10-15% greater than the
average of other samples.
Hence, aging in field service had negligible effects on the tensile strength properties
even though DuPont used different resins and copolymers in processing these materials (see
Table 3).
It may be concluded that short-term tensile strength properties may not provide
information on the relative susceptibility of PE gas pipe materials to SCG field failures.
Quick Burst
Another short-term mechanical strength test performed is the Hydrostatic Quick Burst Test.
It is performed in accordance with ASTM D1599 on pipe samples removed from gas service.
Table 6 presents the average Quick Burst (QB) pressure test data, as an average of several
replicate specimens, determined for the listed pipe materials. Again, it should be noted that these
pipe material were manufactured during different years spanning the period 1970 to 1991. Some
of the pipe materials were in gas service for about 30 years and others were in service for about
12 years.
Table 6 also presents the average hoop stress corresponding to the measured QB pressure.
The hoop stress is computed using a simple formula developed in books on mechanics of
materials for thin-wall pipe. This formula is given as Equation 1 in a subsequent section.

Table 6. Comparative of Average Quick Burst Pressure Test Data
Pipe Material Average Ductile Quick
Burst Pressure, psig
Average Ductile Hoop
Stress, psi
3” IPS SDR 11.5 DuPont Aldyl-A (1970) 627 3,145
4” IPS SDR 11.5 DuPont Aldyl-A (1980) 659 3,232
3” IPS SDR 11.5 DuPont Aldyl-A (1983) 667 3,294
4” IPS SDR 11.5 DuPont Aldyl-A (1988) 647 3109
2”SDR11 Aldyl-A Pipe (1973)
Removed from Gas Service in 1983 668 3,340
Uponor UAC 2000 (2001) 592 2,866
Comparative evaluations of the QB pressure test data or the average hoop stress show
negligible differences in the average QB pressure determined for the various pipes.
Therefore, it may be concluded that aging in field service had negligible effects on the
quick burst pressure properties of the listed Aldyl-A materials even though DuPont used
different resins and copolymers in processing these materials (see Table 3).
It may also be concluded that Quick Burst Pressure test data may not provide
information on the relative susceptibility of PE gas pipe materials to SCG field failures.
PENT
The “PENT” test was developed to measure the resistance of PE gas pipe materials to SCG
failure. It is performed in accordance with ASTM F 1473 Specification entitled “Notch Tensile
Test to Measure the Resistance to SCG of polyethylene pipes and resins”. It is conducted on
Title: DTPH56-06-T-0004 Final Report Page 37
notched rectangular specimens cut from either a PE pipe or from a compression molded PE
plaque material. Figure 37 shows a schematic illustration of the PENT test specimen. Figure 38
shows three notched PE PENT test samples.
Figure 37. Schematic Illustration of the Rectangular PENT Test Specimen
Figure 38. Notched MDPE Test Specimens
The rectangular specimens are carefully notched and placed under a constant tensile load.
The PENT test is conducted at a temperature of 80ºC and under a tensile stress of 2.4 MPa. The
time to failure of a specimen in the PENT test is a measure of the resistance of the PE material to
SCG-failure. The greater the PENT failure time, the greater is the resistance to SCG failure. The
Title: DTPH56-06-T-0004 Final Report Page 38
PENT test failure time is measured from the instant that the tensile load is applied and until the
PENT test specimen experiences complete SCG fracture.
To simulate field failures, the PENT test specimens should exhibit brittle SCG failures.
Thus, in PENT tests, the magnitude of the tensile test loads should be properly determine and
applied in order to mitigate any bending. In the PENT test, the fracture initiates at the tip of the
main notch and grows step-wise in a brittle SCG manner through the specimen thickness. The
brittle SCG crack growth continues and finally the outermost (skin) layer of the PENT specimen
experiences ductile cleavage/fracture.
Figure 39 and Figure 40 show the mating fractured surfaces, at low magnification, of two
PENT test specimens, that experienced SCG brittle fracture in the PENT test. The two specimens
were prepared from two different PE gas pipe materials. The brittle SCG failure mode in the
PENT test specimen is evident from the observed discoloration, whitening and the crack-growth
striations (rings) that are observed in the fractured surface.
Figure 39. Brittle SCG Failure of a PLEXCO MDPE 2406 PENT Test Specimen
Title: DTPH56-06-T-0004 Final Report Page 39
Figure 40. Brittle SCG Failure of HDPE Performance Pipe PENT Test Specimen
GTI database includes a large body of PENT test data on many different MDPE and HDPE
gas pipe materials including Aldyl-A pipes. GTI performed PENT tests on many different Aldyl-
A pipe materials. A few of these pipe materials were manufactured in the same year but were
installed at different geographical regions through-out the U.S.
Table 7 through Table 10 present the PENT test data including the PENT failure times, at a
test temperature of 80ºC for 14 different Aldyl-A pipe materials. The Tables also give the
specimen and notch dimensions. For each pipe material, the PENT test failure time is the average
of a minimum of three replicate test specimens.
Title: DTPH56-06-T-0004 Final Report Page 40
Table 7 presents the measured PENT test failure times of three different Aldyl-A pipe
materials manufactured in 1973, 1974, and 1975, respectively.
Table 7. PENT Test Failure Time of Aldyl-A Pipe Lots (1973 - 1975)
Ye
a
r

o
f

P
i
p
e

Pr
o
d
u
c
t
i
o
n

Sp
e
c
i
m
e
n

Fa
i
l
u
r
e

T
i
m
e

(
H
r
s
)

Le
n
g
t
h

(
m
m
)

Wi
d
t
h

(
m
m
)

Th
i
c
k
n
e
s
s

(
m
m
)

Cr
o
s
s
-
S
e
c
t
.

A
r
e
a

(m
m
)
2
No
t
c
h

D
e
p
t
h

(
m
m
)

Si
d
e

N
o
t
c
h

De
p
t
h

(
m
m
)

We
i
g
h
t

G
r
a
m
s

St
a
t
i
o
n

A
r
m

R
a
t
i
o

(I
n
.
)

Av
g
.

F
a
i
l
u
r
e

(
H
r
s
)

1973 3A 1.4 49.97 14.89 5.95 88.60 2.49 0.50 4327 5.015
1973 3B 1.4 49.94 14.92 5.90 88.03 2.48 0.50 4299 5.015
1973 3C 1.4 49.92 14.94 5.91 88.30 2.48 0.50 4323 5.003 1.4
1973 4A 1.2 49.92 14.93 5.84 87.19 2.46 0.50 4259 5.015
1973 4B 1.3 49.91 14.89 5.80 86.36 2.46 0.50 4225 5.007
1973 4C 1.3 49.91 14.92 5.93 88.48 2.48 0.50 4321 5.015 1.3
1974 1A 0.8 50.03 15.04 5.88 88.44 2.47 0.50 4319 5.015
1974 1B 1.6 50.01 14.96 5.80 86.77 2.46 0.50 4238 5.015
1974 1C 1.4 49.98 14.87 5.77 85.80 2.45 0.50 4191 5.015 1.3
1974 5A 1.7 49.99 14.97 5.89 88.17 2.48 0.50 4307 5.015
1974 5B 1.6 49.92 14.99 5.70 85.44 2.43 0.50 4173 5.015
1974 5C 1.3 49.97 14.97 5.88 88.02 2.47 0.50 4299 5.015 1.5
1975 2A 1.2 49.97 14.98 5.88 88.08 2.47 0.50 4302 5.015
1975 2B 1.3 49.99 14.96 5.90 88.26 2.48 0.50 4311 5.015
1975 2C 1.1 49.99 15.08 5.77 87.01 2.45 0.50 4250 5.015 1.2
1975 6A 3.4 49.92 15.11 6.01 90.81 2.50 0.50 4435 5.015
1975 6B 2.7 49.92 15.08 5.86 88.37 2.47 0.50 4316 5.015
1975 6C 2.6 49.84 15.10 5.86 88.49 2.47 0.50 4322 5.015
1975 6D 3.2 49.85 15.09 6.02 90.84 2.50 0.50 4437 5.015 3.0
Title: DTPH56-06-T-0004 Final Report Page 41
Table 8 lists the measured PENT failure times for four different Aldyl-A pipe materials
manufactured in 1976, 1977, 1978, and 1979.
Table 8. PENT Test Failure Time of Aldyl-A Pipe Lots (1976 – 1979)
Ye
a
r

o
f

P
i
p
e

Pr
o
d
u
c
t
i
o
n

Sp
e
c
i
m
e
n

Fa
i
l
u
r
e

T
i
m
e

(H
r
s
)

Le
n
g
t
h

(
m
m
)

Wi
d
t
h

(
m
m
)

Th
i
c
k
n
e
s
s

(m
m
)

Cr
o
s
s
-
S
e
c
t
.

Ar
e
a

(m
m
)
2

No
t
c
h

D
e
p
t
h

(m
m
)

No
t
c
h

D
e
p
t
h

(m
m
)

We
i
g
h
t

L
b
s
.

We
i
g
h
t

Gr
a
m
s

St
a
t
i
o
n

A
r
m

Ra
t
i
o

(
I
n
.
)

Av
g
.

F
a
i
l
u
r
e

(H
r
s
)

1976 A 1.3 49.94 15.01 5.76 86.46 2.45 0.50 9.31 4223 5.015
1976 B 1.1 49.96 14.99 5.75 86.19 2.45 0.50 9.28 4210 5.015
1976 C 1.1 49.94 15.04 5.74 86.33 2.44 0.50 9.32 4227 5.003 1.2
1977 A 0.5 49.89 15.11 5.73 86.58 2.44 0.50 9.32 4229 5.015
1977 B 0.6 49.94 15.01 5.74 86.16 2.44 0.50 9.29 4215 5.007
1977 C 0.6 49.89 15.09 5.76 86.92 2.45 0.50 9.36 4245 5.015 0.6
1978 A 2.9* 49.94 14.99 5.75 86.19 2.45 0.50 9.28 4210 5.015 *
1978 B 0.6 49.91 14.99 5.72 85.74 2.44 0.50 9.23 4188 5.015
1978 C 0.8 49.91 15.06 5.72 86.14 2.44 0.50 9.28 4207 5.015 0.7
1979 A 1.2 49.86 24.92 8.28 206.34 3.00 0.50 22.22 10078 5.015
1979 B 1.0 49.91 25.04 8.14 203.83 2.97 0.50 21.95 9955 5.015
1979 C 1.1 49.89 24.87 3.00 74.61 1.84 0.50 8.03 3644 5.015 1.1
Title: DTPH56-06-T-0004 Final Report Page 42
Table 9 lists the PENT test failure times for four Aldyl-A pipe materials manufactured in
1979, 1980, 1981, and 1982.
Table 9. PENT Test Failure Time of Aldyl-A Pipe Lots (1979 – 1982)
Ye
a
r

o
f

P
i
p
e

Pr
o
d
u
c
t
i
o
n

Sp
e
c
i
m
e
n

Fa
i
l
u
r
e

T
i
m
e

(H
r
s
)

Le
n
g
t
h

(
m
m
)

Wi
d
t
h

(
m
m
)

Th
i
c
k
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e
s
s

(m
m
)

Cr
o
s
s
-
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e
c
t
.

Ar
e
a

(
m
m
)
2
No
t
c
h

D
e
p
t
h

(m
m
)

Si
d
e

N
o
t
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h

De
p
t
h

(
m
m
)

We
i
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t

L
b
s
.

We
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t

Gr
a
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s

St
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A
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m

Ra
t
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o

(
I
n
.
)

Av
g
.

F
a
i
l
u
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e

(H
r
s
)

1979 A 0.9 49.78 15.24 5.73 87.33 2.44 0.50 9.40 4265 5.015
1979 B 0.9 49.91 15.06 5.74 86.44 2.44 0.50 9.31 4222 5.015
1979 C 0.9 49.86 15.01 5.74 86.16 2.44 0.50 9.30 4218 5.003 0.9
1980 A 0.8 49.81 15.01 5.76 86.46 2.45 0.50 9.31 4223 5.015
1980 B 0.9 49.86 15.09 5.73 86.47 2.44 0.50 9.33 4230 5.007
1980 C 0.9 49.91 14.96 5.76 86.17 2.45 0.50 9.28 4209 5.015 0.9
1981 A 0.5 49.86 15.01 5.74 86.16 2.44 0.50 9.28 4208 5.015
1981 B 0.7 49.86 15.01 5.76 86.46 2.45 0.50 9.31 4223 5.015
1981 C 1.1 49.86 15.06 5.74 86.44 2.44 0.50 9.31 4222 5.015 0.8
1982 A 0.6 49.81 14.91 5.74 85.58 2.44 0.50 9.22 4180 5.015
1982 B 0.7 49.83 14.94 5.74 85.76 2.44 0.50 9.23 4188 5.015
1982 C 1.6 49.94 15.06 5.74 86.44 2.44 0.50 9.31 4222 5.015 1.0
Title: DTPH56-06-T-0004 Final Report Page 43
Table 10 lists the PENT test failure times for three Aldyl-A pipe materials manufactured in
1983, 1984, and 1985.
Table 10. PENT Test Failure Time of Aldyl-A Pipe Lots (1983 – 1985)
Ye
a
r

o
f

P
i
p
e

Pr
o
d
u
c
t
i
o
n

Sp
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i
m
e
n

Fa
i
l
u
r
e

T
i
m
e

(
H
r
s
)

Le
n
g
t
h

(
m
m
)

Wi
d
t
h

(
m
m
)

Th
i
c
k
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e
s
s

(
m
m
)

Cr
o
s
s
-
S
e
c
t
.

A
r
e
a

(m
m
)
2
No
t
c
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D
e
p
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h

(
m
m
)

Si
d
e

N
o
t
c
h

D
e
p
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(m
m
)

We
i
g
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t

L
b
s
.

We
i
g
h
t

G
r
a
m
s

St
a
t
i
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A
r
m

R
a
t
i
o

(I
n
.
)

Av
g
.

F
a
i
l
u
r
e

(
H
r
s
)

1983 A 0.9 49.86 15.06 5.75 86.60 2.45 0.50 9.32 4229 5.015
1983 B 0.8 49..81 15.14 5.77 87.36 2.45 0.50 9.41 4267 5.015
1983 C 1.0 49.89 14.91 5.76 85.88 2.45 0.50 9.27 4205 5.003 0.9
1984 A 6.5 49.89 15.06 5.72 86.14 2.44 0.50 9.28 4207 5.015
1984 B 8.5 49.86 15.04 5.73 86.18 2.44 0.50 9.29 4216 5.007
1984 C 6.9 49.99 14.96 5.74 85.87 2.44 0.50 9.25 4194 5.015 7.3
1985 A 22.6 49.83 14.86 5.73 85.15 2.44 0.50 9.17 4159 5.015
1985 B 20.0 49.81 14.88 5.75 85.56 2.45 0.50 9.21 4179 5.015
1985 C 21.7 49.76 15.11 5.75 86.88 2.45 0.50 9.36 4244 5.015 21.4
From Table 7 through Table 10, it may be noted that the PENT failure time for Aldyl –A pipe
materials manufactured during the period 1973 to 1983 ranged between 0.6 hours and 3.0 hours.
The PENT failure time for the Aldyl-A pipe materials manufactured in 1984 and 1985 increased
to about 7.3 hours and 21.4 hours, respectively.
It should be noted that all the Aldyl-A pipe materials presented in Table 7 through Table 10
have a PENT failure time ranging between 0.6 hours and 21.4 hours. However these Aldyl-A
pipe materials continue to remain in gas service. Some of these materials have been in gas
service for more than 35 years.
Title: DTPH56-06-T-0004 Final Report Page 44
Table 11 lists the PENT failure times for two newer “virgin” un-exposed PE gas pipe
materials that were manufactured in 2001 and 2002, namely: Polypipe 4810 HDPE 3408 and
Driscopipe 8100 HDPE 3408. Neither of these pipe materials was installed in gas service. The
average PENT failure time of the Polypipe material was about 229.1 hours. The Driscopipe had
an average PENT test time of 524 hours. The PENT failure times for both of these materials is
significantly improved compared to the above listed Aldyl-A pipes.
Table 11. PENT Test Failure Times for Polypipe 4810 and Driscopipe 8100
Sp
e
c
i
m
e
n

Fa
i
l
u
r
e

T
i
m
e

(H
r
s
)

Le
n
g
t
h

(
m
m
)

Wi
d
t
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(
m
m
)

Th
i
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k
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s

(m
m
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Cr
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s
-
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.

Ar
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a

(
m
m
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2

No
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D
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(m
m
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Si
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(m
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)

We
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t

L
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We
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Gr
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St
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t
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A
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m

Ra
t
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(
I
n
.
)

Print line: POLYPIPE 4810 GAS PE 3408 2" IPS SDR11 ASTM D2513 CDC API 15 LE
X33 LO4 3GD 03APR02
D4 220.9 50.00 15.00 6.02 90.30 2.50 0.50 9.72 4410.46 5.015
D5 250.8 50.02 15.08 6.03 90.93 2.51 0.50 9.79 4441.35 5.015
D6 215.7 50.06 15.04 6.01 90.39 2.50 0.50 9.73 4414.87 5.015
Print line: 2" IPS DR11 DRISCOPIPE 8100® GAS PE 3408 CEC ASTM D2513 WT11 12
DEC 01 A3 R ( WITH YELLOW JACKET REMOVED)
G4 528.1 50.07 15.02 6.03 90.57 2.51 0.50 9.75 4423.67 5.015
G5 503.1 50.00 15.02 6.03 90.57 2.51 0.50 9.75 4423.67 5.015
G6 540.9 50.00 15.04 6.03 90.69 2.51 0.50 9.81 4451.76 4.990
The applicability of the PENT test has been the subject of several investigations that were
conducted by different organizations. The Plastics Pipe Institute (PPI) published its report
number TN-21/2000 entitled “PPI PENT Test Investigation”. This report presented the test
results of a “round-robin” study on the PENT test performed by several different laboratories.
This report stated that the test data showed that there is no apparent correlation between the
PENT results and those of the Accelerated LTHS Rupture Test per ASTM D 1598. The ASTM
D 1598 test is used to determine the long-term strength and the corresponding Hydrostatic
Design Basis (HDB) of PE pipe materials. The results of the PPI investigation have shown
significant laboratory-to-laboratory variability in the PENT test data.
It should be noted that the PENT test is not considered a short-term test. PENT test failure
times for some newer PE pipe materials may exceed 10,000 hours. However, for the Aldyl-A
pipe materials presented above, the PENT Failure time was less than about 25 hours; this is why
in this section the PENT test is considered a short-term test.
Correlations between the PENT failure time and the field failure time of PE gas pipe
materials are currently inconclusive. Therefore, it may be concluded that the PENT failure
time may provide some useful relative reference on the susceptibility of PE gas pipe
materials to SCG field failures.
Title: DTPH56-06-T-0004 Final Report Page 45
Bend Back
The purpose of the bend-back test is to visually determine whether or not a PE pipe material
is a problematic low ductile inner wall (LDIW) pipe material. LDIW materials were the result of
improper extrusion and/or cooling during manufacturing during the period 1971-1972. This
improper processing caused a few Aldyl-A pipe lots to be manufactured with inferior material
and poor physical properties. These inferior Aldyl-A pipe lot materials consisted of a coarse
“granular-like” microstructure referred to as a spherulitic microstructure.
The LDIW type of PE material has low fracture resistance and is highly susceptible to
premature brittle slow-crack-growth (SCG) failure. Several inferior LDIW pipe lot materials
exhibited pre-mature brittle SCG failure in gas service. During the period 1972-1973, the pipe
manufacturer (DuPont) identified this problematic pipe material and introduced corrective pipe
processing and cooling methods.
To perform a bend-back test on a PE pipe material, 1-inch wide rings are cut from the pipe
material. Each ring is then cut into two sectors. Each ring sector or strip is bent-back on itself
(i.e. inside surface is bent outwards). Figure 41 shows a typical ring-sector before and after the
bend-back test.
During the bend-back test, the bent test sector specimen is visually inspected to determine if
any surface crazing or damage manifested in the form of whitening, discoloration, and/or surface
roughening is visible on the inside surface of the sector-strip. The crazing consisting of
whitening and surface roughening indicates material damage and is indicative of the presence of
“LDIW” material and the high probability that the PE pipe material will experience pre-mature
SCG field failure.
Figure 41. Ring Sector Specimen Before and After the Bend Back Test
Title: DTPH56-06-T-0004 Final Report Page 46
Bend-Back Test Conducted on a LDIW Material from February 1971
For comparative purposes, the results of the bend-back test are presented to visually
illustrate the presence of LDIW material. Sector specimens prepared from an Aldyl-A PE 2306
material manufactured in February 1971 were subjected to bend-back tests. Figure 42 shows the
surface crazing consisting of discoloration, whitening, and surface roughening. The observed
material crazing is typical of a LDIW pipe material and is indicative of an inferior spherulitic
microstructure that is susceptible to pre-mature brittle SCG failure.
Figure 42 can be used as a reference to compare with other PE pipe materials.
Figure 42. Bend-Back Test Exhibiting LDIW Surface Features
Bend-Back Test Conducted on a LDIW Material from March 1971
The results of the Bend-Back test on this LDIW material are also presented for comparative
evaluations. Figure 43 shows a sector specimen made from the Aldyl-A PE 2306 pipe material
manufactured in March 1971. Figure 43 shows the surface crazing consisting of discoloration,
whitening, and surface roughening. The observed crazing is indicative of an inferior LDIW
Aldyl-A pipe material due to a spherulitic microstructure that is susceptible to pre-mature brittle
SCG failure.
Title: DTPH56-06-T-0004 Final Report Page 47
Figure 43. Bend-Back Test Exhibiting LDIW Surface Features
Bend-Back Tests Conducted on Non-LDIW Materials (1970, 1972-1993)
Bend-back tests were performed on many other Aldyl-A pipe materials that were
manufactured in 1970 and during the period 1972 to 1993. Figure 44 through Figure 51 show
photographs of bend-back tests performed on ring-sector specimens prepared from pipe materials
manufactured in 1970, 1972, 1973, 1974, 1976, 1986, 1991, and 1993, respectively. Tests results
showed that none of these pipe materials exhibited any surface discoloration, whitening, or
surface roughening suggesting that none of these test samples have the LDIW material.
Figure 44. Bend Back Test of a 1970 Aldyl-A Material
Title: DTPH56-06-T-0004 Final Report Page 48
Figure 45. Bend Back Test of a 1972 Aldyl-A Material (During and After)
Figure 46. Bend Back Test of a 1973 Aldyl-A Material (During and After)
Title: DTPH56-06-T-0004 Final Report Page 49
Figure 47. Bend Back Test of a 1974 Aldyl-A Material
Figure 48. Bend Back Test of a 1976 Aldyl-A Material
Title: DTPH56-06-T-0004 Final Report Page 50
Figure 49. Bend Back Test of a 1986 Aldyl-A Material
Figure 50. Bend Back Test of a 1991 Aldyl-A Material
Title: DTPH56-06-T-0004 Final Report Page 51
Figure 51. Bend Back Test of a 1993 Aldyl-A Material
Comparative evaluations of Figure 41 through Figure 51 show that Aldyl-A pipe materials
manufactured in 1970, 1972, 1973, 1974, 1976, 1986, 1991, and 1993 do not exhibit any of the
surface characteristics typical of materials having the LDIW inferior microstructure.
The test data and information presented above show that the Bend-Back test may be
used to visually observe and identify qualitatively PE gas pipe materials that have the
inferior LDIW material and hence a high probability that these materials will experience
brittle SCG field failure.
Title: DTPH56-06-T-0004 Final Report Page 52
Accelerated Long Term Hydrostatic Stress-Rupture (LTHS) Tests
Extensive accelerated LTHS test data have been generated by GTI and others on PE gas pipe
materials removed from service. The LTHS tests are conducted in accordance with ASTM
D1598 Specification entitled: Standard Test Method for Time-to-Failure of Plastic Pipe under
Constant Internal Pressure. Time-to-failure is measured for test specimens held at a constant
internal pressure in a controlled environment. LTHS test data is used to determine hydrostatic
design basis (HDB) by establishing a relationship between hoop stress and failure time.
GTI database includes accelerated LTHS test data generated at several elevated test
temperatures including 80°C and 90°C and at several internal test pressures.
Accelerated LTHS Tests with Secondary Stresses
In addition to internal pressure, field operations and service conditions cause pipes to be
subjected to secondary stresses or external loads. The secondary stresses include those due to
impinging rocks, squeeze-offs, soil loads and subsidence, or pipe bending.
GTI database includes accelerated LTHS test data generated at several elevated test
temperatures including 80°C and 90°C and several test pressures combined with a secondary
stress simulating a rock impingement load, a squeeze-off, a pipe bending moment, or a
transverse earth or soil load.
Squeeze-Off
To subject PE pipe test specimens to squeeze-off, GTI used commercially available double-
bar squeeze-off tools. Figure 52 shows one of the commercial tools used to squeeze-off PE pipes.
The commercial squeeze-off tool was used to squeeze the pipe test specimens to the stops built-
into the tool, along the 12 o’clock-six o’clock direction. The pipe specimen was maintained in
the maximum squeezed-off position for a period of about four hours. Then, the squeeze-off bar
was released and the squeezed specimen was subjected to accelerated LTHS tests. Pipe squeeze-
offs were performed on each of the pipe test specimens in accordance with ASTM F 1041 -
Standard Guide for Squeeze-Off of Polyolefin Gas Pressure Pipe and Tubing.
Figure 52. Double Bar Squeeze-Off Tool
Title: DTPH56-06-T-0004 Final Report Page 53
Rock Impingement
The laboratory fixture shown in Figure 53 was utilized in LTHS tests to subject PE pipes to
a surface load that simulated a rock impingement load. The PE pipe test sample was inserted
between the two parallel steel plates. A threaded bolt was installed in the center hole of the top
plate. A ball bearing was inserted between the pipe outer surface and the tip of the center
threaded bolt as shown in Figure 54. The center threaded bolt was turned until the ball bearing
was just tight enough to prevent it from slipping. Four outer bolts were then tightened just
enough so as not to increase the indentation depth. Then, by turning the center threaded bolt a
few additional pre-specified number of turns, an indentation with the required depth was induced
in the pipe wall.
Using the rock impingement fixture, several laboratory experiments have been performed to
determine the indentation depth that is required to induce the necessary rock impingement load
for different pipe sizes and PE pipe materials. GTI has also conducted several analytical
evaluations and field experiments to determine the range of magnitude of the rock impingement
field loads.
Figure 53. Rock Impingement Loading Fixture
Figure 54. Indentation unto the Pipe Using Ball Bearing
Title: DTPH56-06-T-0004 Final Report Page 54
Bending
Figure 55 shows the four-point pipe bending fixture that GTI used to subject PE pipe
samples to bending stresses in LTHS tests. The pipe bending fixture consists of two inner
adjustable support brackets and two outer adjustable loading brackets. In this laboratory fixture,
the pipe test specimen is simply supported by the two inner brackets. The two outer brackets are
used to apply a pre-specified bending moment or load on the test specimen.
For testing, the PE pipe test specimens were subjected to a bending radius of about 20 times
the pipe outer diameter. While in the fixture under bending, the pipe specimen was pressurized
and subjected to accelerated LTHS tests.
Figure 55. Pipe Bending Fixture
Transverse Deflections or Soil Loads
The laboratory fixtures shown in Figure 56 were used to subject PE pipe specimens to
transverse deflections secondary stresses. The fixtures consist of two parallel steel plates held
together with six threaded bolts. The pipe test specimen was inserted between the two plates,
centered and aligned. The six threaded bolts were turned equally until the top plate was slightly
pressing against the pipe test specimen. Then, each of the bolts was turned a few additional turns
to induce a transverse pipe deflection/deformation of about 5% of the pipe (OD).1
The end-capped pipe test specimens were maintained in the soil loading fixture when
subjected to accelerated LTHS tests.
1 Pipe manufacturers recommend that in field installations, the pipe transverse vertical deflection due to
earth loads should not exceed 5% of the pipe outside diameter OD.
Title: DTPH56-06-T-0004 Final Report Page 55
Figure 56. PE Pipe Test Specimens Installed in Earth Load Fixtures
GTI Database on Accelerated LTHS Tests
Utilizing the above described test fixtures and protocols, GTI developed a large database on
accelerated LTHS tests on PE pipe test specimens subjected to:
x Internal pressure only;
x Internal pressure combined with a simulated rock impingement load;
x Internal pressure combined with a simulated soil deflection/load;
x Internal pressure combined with a simulated pipe bending load/moment; or
x Internal pressure combined with a secondary stress induced by a pipe squeeze-off.
In accelerated LTHS tests, PE pipe specimens were subjected to the above–described loads
until they exhibited a failure manifested in the form of a leak. To accelerate the failure process,
the largest percentage of the accelerated LTHS tests was performed at a test temperature of 80°C
or 90°C. The time to failure in the LTHS tests was monitored and automatically recorded.
An examination was undertaken to determine the failure mode of all the test specimens that
failed/leaked in LTHS tests at elevated temperatures and under internal pressure combined with a
secondary stress. The examinations showed that all the pipe specimens in the LTHS tests
exhibited a SCG failure process.
Title: DTPH56-06-T-0004 Final Report Page 56
Stresses that Drive Crack Initiation and Growth through Pipe Walls
Because of the pipe cooling process, residual circumferential (hoop) and axial stresses
develop in the pipe wall. These stresses develop due to the differences in thermal strains
resulting from the contractions and expansions experienced by the various material layers
making-up the pipe wall. Several experimental investigations were conducted by GTI and other
researchers to measure the magnitudes and distribution of residual stresses created in the pipe
wall during manufacturing.
Experimental evaluations have shown that the residual circumferential stress component has
its maximum tensile magnitude at the pipe inner diameter (ID) surface. This residual hoop stress
component decreases continuously with increasing wall thickness and attains a minimum
compressive magnitude at the pipe outer diameter (OD) surface.
For Aldyl-A pipe materials, laboratory measurements showed that the magnitude of the
residual tensile hoop stress component on the ID is in the range of 200psi to 450psi and the
compressive hoop stress on the OD is in the range -850psi to -1000psi. Similarly, laboratory
measurements showed that the longitudinal residual axial stress component in Aldyl-A pipes has
a maximum tensile magnitude of about 350psi.
Figure 57 shows a plot of the experimentally measured magnitude and distribution of the
circumferential residual stress component as a function of distance or wall depth measured from
the ID of the pipe for a 2-inch SDR11 Aldyl-A pipe manufactured during 1973. The solid line
represents actual lab measurements and the dotted line represents theoretical predictions. The
presented data show that the circumferential residual stress component has a maximum tensile
magnitude of about 200psi at the pipe ID. This residual stress decreases and attains a zero
magnitude at a depth of about 0.7 of the wall thickness. This residual stress component decreases
continuously and attains a minimum compressive value of about -950psi at the pipe outer
surface.
Title: DTPH56-06-T-0004 Final Report Page 57
Figure 57. Circumferential Residual Stress Component as a Function of the Wall Depth
The residual circumferential stress component acts in combination with the hoop stress
induced by the internal pressure. The hoop stress induced by the internal pressure is defined by
the following equation.
2
)1( DRPS (1)
Where:
S = hoop stress
P = internal pressure
DR = dimension ratio
Title: DTPH56-06-T-0004 Final Report Page 58
Applying the equation to the 2-inch SDR 11 pipe from above at an internal pressure of about
60 psig; the circumferential tensile hoop stress component at the pipe ID that is equal to 300psi.2
From Figure 57, the tensile circumferential residual stress component at the pipe ID is equal to
about 200psi. Adding these two stress components gives a resultant circumferential tensile hoop
stress equal to +500psi acting on the inner pipe wall.
At the pipe OD, the resultant circumferential hoop stress is compressive equal to - 650psi
(+300psi due to internal pressure - 950psi due to the compressive residual hoop stress).
Therefore, the residual circumferential tensile stress component is significantly
effective in increasing the resultant stress that drives the initiation and growth of defects
and cracks on the inner pipe surface into axial slits through the pipe wall. On the outer
pipe surface, the residual compressive circumferential (hoop) stress component is very
effective in reducing the resultant stress and consequently retarding and inhibiting the
growth of defects, notches and cracks on the pipe OD.
Effects of Elevated Test Temperatures
The effects of elevated temperatures on the residual stresses were measured for several
Aldyl-A pipes. For the 2-inch SDR 11 Aldyl-A pipe that was installed in gas service in 1973 and
removed during 1983, Figure 57 shows a plot of the measured residual circumferential tensile
stress component as a function of different test temperatures (including 80 °C and 90 °C) and
several test periods (including 1, 10, and 100 hours). Figure 58 shows that after a test period of
about 100 hours at 80°C or higher test temperatures, the residual circumferential stress acting on
the pipe ID decreased by more than 50%.
Figure 58. Effect of Test Temperature and Time on Residual Hoop Stress Component
2 The internal pressure also causes a tensile axial stress of about 150psi to act on the pipe wall.
Title: DTPH56-06-T-0004 Final Report Page 59
Specimens of this pipe material were also subjected to long-term hydrostatic stress rupture
tests at 80°C and a test pressure of about 117psig; this pressure induced a tensile hoop stress of
about 580psi. The laboratory LTHS test results generated for this Aldyl-A pipe material that was
in field service for 10 years are reported in Table 12.
Table 12. Test Data for a 2 Inch Aldyl-A Pipe Manufactured In 1973 and Removed From Gas
Service in 1983.

Te
n
s
i
l
e

Y
i
e
l
d

S
t
r
e
n
g
t
h
,

p
s
i

Qu
i
c
k

B
u
r
s
t

P
r
e
s
s
u
r
e
,

p
s
i
g

Lo
n
g
-
T
e
r
m

Hy
d
r
o
s
t
a
t
i
c

St
r
e
s
s

R
u
p
t
u
r
e

T
e
s
t

Te
n
s
i
l
e

R
e
s
i
d
u
a
l

Ho
o
p

S
t
r
e
s
s

o
n

I
n
n
e
r

S
u
r
f
a
c
e
,

p
s
i

Co
m
p
r
e
s
s
i
v
e

R
e
s
i
d
u
a
l

Ho
o
p

S
t
r
e
s
s

o
n

O
u
t
e
r

s
u
r
f
a
c
e
,

p
s
i

De
n
s
i
t
y

Cr
y
s
t
a
l
l
i
n
i
t
y

Ho
o
p

S
t
r
e
s
s
,

p
s
i

Fa
i
l
u
r
e

Ti
m
e
,

h
o
u
r
s

As-Received Pipe 2275 668 580 399 338 -831 0.9526 0.7138
Lab. Annealed at
80°C for 100 hours 2490 98 -246 0,9548 0.7277
Lab. Annealed at
80°C for 1 hour 684 580 663
The data in Table 12 show that the tensile circumferential residual stress at the inner pipe
surface of the “As-Received” pipe was equal to about 338psi. The resultant tensile hoop stress on
the pipe ID was about 918psi (580psi due to pressure plus 338psi due to the residual hoop stress
component). For this as-received pipe, LTHS tests were performed at a temperature of about
40°C; at this temperature, the test failure time was about 399 hours.
After 100 hours at 80°C test temperature, the residual hoop stress component decreased to
98psi (a 70% decrease).
Another pipe sample of this lot was annealed at 80°C for only one hour prior to the LTHS
test; then, it was subjected to LTHS testing at 117psig pressure; the induced pipe hoop stress was
580psi. For the annealed pipe sample, the resultant tensile hoop stress was about 678psi (580psi
due to pressure + 98psi due to the residual hoop stress component). The annealed sample failed
in LTHS testing after about 663 hours; an increase in failure time of about 66% compared to the
LTHS failure time obtained at a test temperature of about 40°C.
The above test results show that long-term hydrostatic stress-rupture (LTHS) tests at
elevated temperatures of 80°C or 90°C, cause the resultant hoop stress acting on the inner pipe
Title: DTPH56-06-T-0004 Final Report Page 60
surface to be about 50% less than that acting on pipes at room or field service temperatures. This
lower circumferential resultant tensile stress results in greater LTHS test failure times.
Several additional experimental investigations at 80°C or higher temperatures have
demonstrated that the decrease in residual stresses leads to an increase in the LTHS test failure
time of PE pipes by more than 50%.
Even though elevated temperature testing accelerates the failure process in PE pipes it also
has the un-intended and undesirable effect of eliminating the contribution of the residual stresses
in driving the initiation and growth of defects, notches, and cracks.
At temperatures higher than about 50°C (120°F), elevated LTHS test temperatures
have substantial effects in reducing the residual stresses and the resultant hoop stress that
drives crack growth on the pipe ID by about 50%; this has the effect of increasing the
LTHS failure times by about 50%.
At temperatures lower than about 120°F, the effects of elevated LTHS temperatures on
the residual stresses and the resultant hoop stress are minimal; thus, at lower LTHS test
temperatures, the effect on the LTHS failure time may be neglected.
Title: DTPH56-06-T-0004 Final Report Page 61
Engineering Methods to Predict Life Expectancy
The results presented in the previous sections show that the majority of the short-term
laboratory tests that are typically implemented provide, at best, qualitative information on the
relative susceptibility of PE gas pipe materials to SCG field failures. Based on extensive
investigations it is concluded that the predicted remaining life expectancy is a key measure that
can be used to rank the susceptibility of PE gas pipe materials to SCG field failures.
Researchers have predicted PE pipe life expectancy using methods and analytical models
developed in principles of engineering fracture mechanics. To apply these models, measurements
of SCG or Crack Tip Opening Displacement (CTOD) rates are obtained for PE pipe materials
using accurate monitoring devices under well-controlled laboratory conditions.3 In some cases,
the SCG rates were determined experimentally by measuring the rate of the CTOD in a notched
“PENT” specimen.
In other cases, the SCG rates for PE pipe materials were determined through careful
experimental measurements of the CTOD in a notched PE pipe sector specimen subjected to a
three-point bending load. These rates were developed for PE LIFESPAN FORECASTING
software which was used to predict the life expectancy of PE gas pipe materials. The LIFESPAN
software implements methods of linear fracture mechanics combined with measurements of SCG
rates. Several investigations have shown excellent correlations between the life predictions made
using the LIFESPAN software and actual field failure times of PE gas pipes.
There are significant costs associated with measuring SCG or CTOD rates using either the
notched “PENT” test specimen or the notched pipe sector specimen. As a result, SCG or CTOD
rates are not available for many different PE gas pipe materials. Also, it is substantially less
costly and significantly quicker to apply materials science and engineering models to LTHS tests
data to predict the life expectancy of PE gas pipe materials.
One of two materials science models is typically implemented. The two materials
science/engineering models are the Bi-Directional Shift Functions (BDSF) and the three-
coefficient Rate Process Method (RPM). Both of these models are based on a fundamental law of
physics involving the “Second Law of Thermodynamics”. Both of these models have been used
and validated for PE gas pipes by several researchers. To apply these models, the failure times
are first obtained using the LTHS test performed in accordance ASTM D1598. The LTHS test is
conducted on PE pipe test specimens prepared from the “As-received” pipe material. Then, the
pipe life expectancy is predicted by applying either the BDSF or the RPM. Numerous
investigations have shown excellent correlations between the life predictions made using LTHS
test data combined with the BDSF or the RPM method and the actual field failure times of PE
gas pipes
Because of the above and the extensive LTHS database, it was decided that the predicted
remaining life expectancy made using the LTHS test data combined with either the BDSF or the
3 GTI published several reports that presented fracture mechanics models used to predict the SCG failure
time. These reports include the following publications: GRI-91/0360, GRI-92/0479, GRI-92/0480, GRI-
92/0481, GRI-93/0105, and GRI-93/0106.
Title: DTPH56-06-T-0004 Final Report Page 62
RPM model may be used to rank the relative susceptibility of different PE gas pipes to SCG field
failures.
Original Bi-Directional Shift Functions Model
The BDSF, denoted as F1 and F2, allow projections using laboratory test failure time (Timet)
generated at a laboratory test pressure (Pt) and at a specific test temperature (Tt) to predict the
specific pressure (Ps) and the specific failure time (Times) corresponding to any specific
temperature (Ts).
)(109.0
1 stTTeF (2)
)(0116.0
2 tsTTeF (3)
1FTimeTimets (4)
2F
PPt
s (5)
Where:
Pt = laboratory test pressure
Tt = laboratory test temperature
Timet = laboratory test failure time
Ts = specific temperature including field service temperature
Ps = predicted pressure (psig) corresponding to Ts
Times = predicted failure time corresponding to Ts
To implement the BDSF, the laboratory tests may be conducted at only one set of test
conditions. This condition involves testing pipe specimens at a test temperature and a test
pressure to be specified properly so that it can be projected to give the pressure (psig) PS
corresponding to the specified temperature TS.
Modified Bi-Directional Shift Functions Equations
The original BDSF is appropriate for projecting to temperatures >50°C. However, when
projecting to temperatures <50°C, these functions should be modified to compensate for the
effect of elevated LTHS test temperatures in reducing the stress driving crack initiation and
growth. This can be accomplished by introducing the Temperature Factor (TF) as follows:
)(2 TFF
PPt
s (6)
Where:
Pt = laboratory test pressure
Title: DTPH56-06-T-0004 Final Report Page 63
Ps = predicted pressure (psig) corresponding to Ts
TF = 2, for Ts <50°C; and
TF = 1, for Ts >50°C
Original Three-Coefficient Rate Process Method
The three-coefficient RPM is based on the Arrhenius equation describing thermally
activated processes; it may be expressed in terms of the following equation:
T
PCLogBATimeLog10
10  (7)
Where:
T= absolute temperature in Kelvin (°K=°C+273)
P = pressure
Time = average failure time corresponding to Tand P
The three coefficients A,B, and C are unknown constants that are, in general, functions
of the material properties, temperature, stresses or applied loads, and geometrical variables.
To apply the RPM, first it is necessary to determine the values of the three unknown
coefficients for the PE material when subjected to internal pressure and/or a specific secondary
stress. Hence, three sets of LTHS tests should be conducted on replicate sets of test specimens at
three distinct test conditions. The three distinct test conditions may involve the use of two
different test temperatures and two different test pressures.
The RPM allows one to predict the life expectancy for a broader range of pressures and
many different field temperatures. However, the BDSF allow one to make a life prediction
corresponding to only one specific field temperature.
In cases involving laboratory tests performed at less than three distinct test conditions, the
BDFS may be implemented to make predictions.
Modified Three-Coefficient Rate Process Method
The original RPM is appropriate for projecting to temperatures >50°C. However, when
projecting to temperatures <50°C, these functions should be modified to compensate for the
effect of elevated LTHS test temperatures in reducing the stress driving crack initiation and
growth. This can be accomplished by introducing the Temperature Factor (TF) as follows:
T
TFPCLog
T
BATimeLog )(10
10  (8)
Where:
T= absolute temperature in Kelvin (°K=°C+273)
Title: DTPH56-06-T-0004 Final Report Page 64
P = pressure
Time = average failure time corresponding to Tand P
TF = 2, for Ts <50°C; and
TF = 1, for Ts >50°C
Note: The researchers who developed the original BDSF and the RPM models may not have
intended the use of the models for predictions at temperatures lower than LTHS test temperatures
by more than 30°C or 40°C.
Sample Set on the Predicted Remaining Life Expectancy
GTI database includes information on many different PE gas pipe materials and sizes that
were manufactured from several PE resins and pipe extruders. These pipe materials were
installed in many different geographical regions throughout the U.S. These pipe materials were
subjected to different underground day-to-day and seasonal temperatures. Also, these pipes
materials were installed in different soils with varying topographies and under several different
installation conditions.
Because of the above, for any predictions made on the remaining life expectancy and the
pipe pressures to be applicable and accurate for a specific pipeline they should be made based on
the temperature, soil topography, field installation conditions and operations that correspond to
those specific to where the pipe is installed.
Again it should emphasized, that the predictions on the remaining life expectancy of PE
pipes presented in this section represent only one sample set of predictions for an assumed
specific average annual underground temperature. Also, the presented sample set of life
predictions presented in this section assume a specific set of external loads due to the field
secondary stresses induced by impinging rock loads, squeeze-offs, pipe bending, or earth/soil
loads.
Therefore the remaining life expectancy predictions presented in this section do not
necessarily apply to any geographic region or any pipeline operator system. Thus, the presented
predictions should NOT be considered a reference but only as a sample for an arbitrarily selected
set of assumed service conditions. The assumed set of conditions used is one from an
exceedingly large group of possible service conditions and geographic locations.
Table 13 presents predictions of the remaining life expectancy and pressure for several PE
gas pipe materials for an assumed average annual underground field temperature of 60°F. The
predictions are made for pipes subjected to internal pressure or internal pressure combined with a
secondary stress induced by an impinging rock load, a squeeze-off, a pipe bending moment, or a
soil/earth load. The selected magnitudes of the secondary stresses are based on a maximum
limiting value determined to be typical for that installation period.
The predictions are made using accelerated LTHS laboratory test data determined at test
temperatures of 80°C and 90°C. The RPM model and/or the BDSF model were implemented in
making the predictions presented in Table 13. The predictions are presented only for purposes of
discussion.

Title: DTPH56-06-T-0004 Final Report Page 65
Table 13. Predicted remaining life expectancy for PE gas pipe

Ma
t
e
r
i
a
l

Ye
a
r

M
a
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u
f
a
c
t
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e

Pi
p
e

D
i
a
m
e
t
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r
/
S
D
R

Predicted Remaining Life Expectancy, Years
Pi
p
e

P
r
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s
s
u
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e
,

p
s
i
g

Pi
p
e

P
r
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s
s
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On
l
y

Pi
p
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P
r
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s
s
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e

a
n
d

R
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c
k

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t
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Pi
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P
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s
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a
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Sq
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z
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-
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f
f

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a
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d
.

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x

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-
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x

O
D

Aldyl-A MD 1970 3”/11 60 psig 158 yr 42 yr 28 yr 79 yr 50 yr
Aldyl-A MD 1971 2”/11 60 psig 33 yr
Aldyl-A MD 1971 4”/11 60 psig 21 yr 15 yr
Aldyl-A MD 1972 2”/11 60 psig 28 yr 19 yr 16 yr 22 yr 24 yr
Aldyl-A MD 1973 2”/11 60 psig 58 yr 38 yr 47 yr 50 yr 55 yr
Aldyl-A MD 1974 2”/11 60 psig 49 yr 24 yr 32 yr 35 yr 43 yr
Aldyl-A MD 1974 2”/11 60 psig 51 yr 26 yr 19 yr 27 yr
Aldyl-A MD 1976 2”/11 60 psig 62 yr 18 yr 23 yr 42 yr 57 yr
Aldyl-A MD 1977 3”/11.5 60 psig 129 yr
Aldyl-A MD 1980 4”/11.5 60 psig 174 yr
Aldyl-A MD 1983 3”/11.5 60 psig 71 yr 31yr 36 yr 42 yr 57 yr
Aldyl-A MD 1984 4”/11.5 60 psig 353 yr
Aldyl-A MD 1984 3”/11.5 60 psig 249 yr
Aldyl-A MD 1985 3”/11.5 60 psig >500 yr
Aldyl-A MD 1986 2”/11 60 psig 76 yr 35 yr 28 yr 39 yr 52 yr
Aldyl-A MD 1986 3”/11.5 60 psig >500 yr
Aldyl-A MD 1986 4”/11.5 60 psig >500 yr
Aldyl-A MD 1988 4”/11.5 60 psig 220 yr
Aldyl-A MD1 1989 6”/11.5 53psig >300 yr
Aldyl-A MD2 1989 6”/11.5 53psig >300 yr
Aldyl-A MD3 1989 6”/11.5 53psig >300 yr
Aldyl-A MD 1990 2”/11 60 psig >500 yr >500
yr >500 yr >500 yr >500 yr
Aldyl-A MD 1990 4”/11.5 60 psig >500 yr
Aldyl-A MD4 1990 6”/11.5 53psig >300 yr
Aldyl-A MD 1991 4”/11.5 60 psig >500 yr >500 >500 yr >500 yr >500 yr
Title: DTPH56-06-T-0004 Final Report Page 66
yr
Aldyl-A MD 1991 3”/11.5 60 psig >500 yr
Aldyl-A MD 1993 2”/11 60 psig >500 yr
Aldyl-A MD 1993 3”/11.5 60 psig >500 yr
Plexco Yel. MD5 1994 6”/11.5 53psig
131 yr
(cap
fracture)

Plexco Yel. MD6 1994 6”/11.5 53psig >300 yr
Plexco Yel. MD5 1999 6”/11.5 50psig
176 yr
(cap
fracture)

Plexco Yel. MD1 1999 6”/11.5 53psig >300 yr
Driscoplex6500
MD6 2002 6”/11.5 53psig >300 yr
Driscoplex6500
MD6 2002 6”/11.5 53psig >300 yr

Note Superscript
1. Heat fusion saddle tee
2. Heat fusion saddle tee and butt fusion
3. Heat fusion saddle tee and electro-fusion socket couplings
4. Electro-fusion saddle tee
5. Heat-fusion saddle tee and socket coupling– Top of Cap fractured at thread
6. Electro-fusion saddle tee and socket coupling.
Table 13 lists a few PE pipe sections containing heat-fusion saddle tees and laterals. For two
of these, the top of the cap on the saddle tee fractured at the thread. The life expectancy for these
cases is reported.
Secondary Stress Effects
For a few PE pipe materials, Table 13 presents the forecasted pipe remaining life expectancy
for pipes subjected to an internal pressure combined with a secondary stress induced by a rock
impingement, a squeeze-off, a bending moment, or a soil load. It was found that for certain PE
pipe materials, rock impingement loads cause the greatest stress and hence lead to the shortest
predicted life expectancy. For other PE pipe materials, a squeeze-off causes the greatest stress
and hence may lead to the shortest life expectancy.
For an assumed annual average underground field temperature of 60°F, Figure 59 presents
graphical plots giving the predicted remaining life expectancy for an older Aldyl-A pipe
Title: DTPH56-06-T-0004 Final Report Page 67
subjected to internal pressure or internal pressure combined with either a rock impingement load,
a squeeze-off, a bending moment or a soil load. Figure 59 shows that impinging rocks and /or
pipe squeeze-offs may induce the greatest stress that drives crack initiation and growth and hence
a shorter life expectancy. In general, rock impingements and/or pipe squeeze-offs have more
severe effect on PE pipes than pipe bending or an excessive soil load due to compaction.
Figure 59. Predicted Remaining Life Expectancy of an Older Aldyl-A Pipe
Field Temperature Effects
It should be noted that the BDSFs and the RPM models are both based on exponential
relationships. These models and the generated laboratory test data show that the PE pipe failure
time or alternatively the remaining life expectancy, increase exponentially with decreasing
temperatures and decreasing pressures. Therefore, the lower is the underground field
temperature; the greater is the remaining pipe life expectancy.
Figure 60 presents graphical plots for the predicted life expectancy as a function of the
average annual underground field temperature for an older Aldyl-A pipe material subjected to
pressures of 40psig, 50psig, or 60psig. This figure clearly shows that the life expectancy of the
PE pipe increases exponentially with decreasing field temperature.
Title: DTPH56-06-T-0004 Final Report Page 68
Figure 60. Predicted Remaining Life Expectancy as a Function of Temperature
The predictions are presented to show that the pipe life expectancy is a key measure of
the susceptibility of PE gas pipe materials to SCG field failures and that these predictions
are applicable and accurate only when they consider the specific conditions for a specific
PE pipeline.

40
45
50
55
60
65
70
20 40 60 80 100 120 140 160 180 200
Av
e
r
a
g
e

F
i
e
l
d

Te
m
p
e
r
a
t
u
r
e

(
d
e
g
F
)
Time (years)
Predicted Pipe Remaining Life Expectancy VS
Average Annual Field Temperature for Pipe Service
Pressure of 40psig, 50psig, or 60psig
40 psig
50 psig
60 psig
Title: DTPH56-06-T-0004 Final Report Page 69
Slow Crack Growth Conclusion
The objective of the work task was to identify the susceptibility of plastic gas pipe materials
to brittle SCG field failures. To accomplish the objectives of this task, a thorough review of the
literature including GTI database on PE gas pipe materials was conducted.
Other than failures caused by excavation, the review indicated that the majority of the PE
gas pipe materials that fail under typical field conditions exhibit SCG fracture morphology.
Using optical and SEM- microscopic examinations, the SCG fracture process exhibited by
several different PE pipe samples was investigated and described.
Several laboratory tests and methods were evaluated to determine whether or not they can be
used to provide information on the susceptibility of PE gas pipe materials to SCG field failure.
These tests included the Tensile, Quick Burst Pressure, Melt Index, Density, Bend-Back, and
PENT.
The review showed that the short-term mechanical strength tests may not provide qualitative
or quantitative information on the relative susceptibility of PE gas pipe materials to SCG field
failures. The review indicated that the Density or Melt Index (or Melt Flow) may provide
qualitative information on the relative susceptibility of PE gas pipe materials to SCG field
failures.
Qualitative information on the susceptibility of different PE pipe materials to SCG field
failures may be obtained using optical and SEM microscopy.
The Bend–Back test can provide accurate qualitative information on the susceptibility of PE
gas pipe materials to early pre-mature brittle SCG failures. Visual examinations of specimens
subjected to the Bend-Back test identified several Aldyl-A MDPE pipes that have inferior Low-
Ductile Inner Wall (LDIW) materials which are highly susceptible to pre-mature early brittle
SCG field failures. It was found that several Aldyl-A MDPE pipe lots manufactured in 1971
have LDIW materials and are highly susceptible to pre-mature SCG field failure.
Data obtained using the notched PENT test were evaluated. For many Aldyl-A MDPE pipe
materials manufactured during the period 1970 to 1985, the PENT test failure times ranged
between 0.6 hours and 21.4 hours. However these Aldyl-A pipe materials continue to provide
good field service. Some of these materials have been in gas service for more than 35 years.
Correlations between the PENT failure times of older PE pipe materials and the field failure
times are currently inconclusive. However, PENT test data on newer materials suggest that the
PENT test may provide a useful quantitative relative reference on the susceptibility of PE gas
pipe materials to SCG field failures.
Extensive evaluations of various tests showed that the predicted remaining life expectancy is
a key quantitative measure that can be used to rank the susceptibility of PE gas pipe materials to
SCG field failures. To predict the life expectancy of a PE gas pipe material, researchers utilized
long-term laboratory test data combined with either of two materials science models, the BDSF
or the three-coefficient RPM.
Review of GTI database showed that numerous PE gas pipe materials were subjected to
LTHS tests. Accelerated LTHS test data were generated at several elevated test temperatures
including 80°C and 90°C and using several test pressures. Many LTHS tests were conducted on
PE pipes subjected to internal pressure or internal pressure combined with a secondary stress
Title: DTPH56-06-T-0004 Final Report Page 70
simulating a rock impingement load, a squeeze-off, a pipe bending moment, or a transverse earth
or soil load.
Annealing and LTHS laboratory tests showed that at temperatures higher than about 50°C
(120°F), the stress that drives crack initiation and growth on the pipe ID is reduced by about
50%; this has the effect of increasing the LTHS test failure times by about 50%. At temperatures
lower than about 50°C (120°F), the effects of elevated LTHS temperatures on the stress that
drives crack initiation and growth are negligible.
Hence, if the pipe life expectancy is predicted for temperatures less than about 50°C
(120°F), then one should compensate for the effects of elevated LTHS-test temperatures. This
compensation may be implemented through the use of a Temperature Factor, denoted as TF.
Laboratory test data showed that the Temperature Factor, TF, is equal to about two (2).
Therefore, to compensate for the effects of elevated LTHS-test temperatures in reducing the
stress driving the crack initiation and growth, the BDSF and the RPM models should be modified
through the implementation of a temperature factor TF. The modified BDSF and the RPM
models that incorporate a Temperature Factor are presented above.
For the modified BDSF and the RPM models, it is important to emphasize that:
TF =1, for predictions made at temperatures > 50°C (about 120°F): and
TF = 2, for predictions made at temperatures < 50°C (about 120°F).
The remaining life expectancy is predicted for several PE gas pipe materials assuming a
sample set of field and operational conditions. The presented predictions on the pipe remaining
life expectancy assume a specific set of secondary stresses induced by impinging rock loads,
squeeze-offs, pipe bending, or earth/soil loads. The assumed set of conditions is one from an
exceedingly large group of possible service conditions and geographic locations. The predictions
are made using accelerated LTHS laboratory test data determined at test temperatures of 80°C
and 90°C combined with the modified RPM model and/or the modified BDSF model
The test results and the predictions show that rock impingements and/or squeeze-offs, in
general, induce the greatest stress in PE pipes thus causing the greatest damage and resulting in
the shortest remaining life expectancy.
The models, laboratory test data, and predictions show that the remaining life expectancy of
PE pipe materials increases exponentially with decreasing field temperatures and decreasing
pressures. Therefore, the lower is the underground field temperature the greater is the remaining
pipe life expectancy.
The predicted life expectancy of a PE gas pipe provides one of the most reliable and
accurate quantitative measure of the relative the susceptibility of the PE pipe material to SCG
field failure. However, for these predictions to be applicable, accurate, and reliable, it is critically
important to take into account the actual field temperatures, soil topography, and installation
conditions that are specific to that pipeline and its geographic location.

Title: DTPH56-06-T-0004 Final Report Page 71
Root Cause Analysis of Field Failures
GTI received and documented 55 plastic pipe samples that were removed from service due
to leaks/failures. Eight samples underwent extensive laboratory testing to determine the root
cause of the leak failure. The remainder were photographed and visually examined. All have
been categorized on the basis of the most probable cause of failure: material, procedural, quality
control, or miscellaneous. The information obtained for the samples has been incorporated with
an additional database to provide insight to where defects occur and how they lead to in-service
failures. Of the samples received, failures occurred in:
x Elbows
x Fusion Joints
o Butt
o Socket
o Saddle
x Mechanical Fittings
x Pipe walls due to impingement, loading, and squeeze-offs
x Service Tee Threads
x Tapping Tee Caps
x Transition Fittings.
Failure Categories
Failures were divided into four categories: Material, Procedural, Quality Control, and
Miscellaneous. On some occasions, the failure category could not be determined due to a lack of
information. These have been placed in split categories after the four primary classifications.
Material Failures are those which can be attributed to the imposition of a mechanical load
that the polyethylene gas pipe or fitting is unable to sustain. This category includes slow crack
growth and rapid crack propagation failures. Slow crack growth failures in pipe have occurred
because of rock impingement, squeeze- off, insert renewal, bending, and earth settlement. Slow
crack growth at joints and in fittings have occurred in butt joints, socket joints and fittings,
saddle joints, and tapping tee caps, and because of internal pressure.
Procedural Failures are those failures that occurred as a result of improper field
operations. This category includes separation of joints because of improper heat-fusion joining
conditions in butt joints, socket joints and fittings, and saddle joints and tapping tees.
Quality Control Problems are attributable to defects in the extruded plastic pipe or fitting or
to resin-related problems which adversely affect the expected performance of the material. Often
these problems are detected prior to installation. They illustrate problems with pipe quality that
can occur during production. Quality control problems can be detected as improper dimensional
tolerances, visible or microscopically visible defects, or as melt irregularities.
Miscellaneous Problems are those that do not fall clearly into one of the foregoing
categories. (GRI-98/0202)
Title: DTPH56-06-T-0004 Final Report Page 72
Laboratory Field Failure Analysis Procedure
The laboratory analysis procedure used for this project is described for sample number
#602533. This specimen is identified as a 4” IPS SDR 11.5 DuPont Aldyl-A PE 2306
manufactured in 1984. It was removed from service in 2008 and submitted to GTI for analysis.
Upon receipt, the specimen was photographed and examined. The as received sample is shown in
Figure 61. Background and service information are summarized in Table 14.
Impingement – #602533
Figure 61. As Received Sample with Attached 4” X 2” Electrofusion Tapping Tee
Title: DTPH56-06-T-0004 Final Report Page 73
Table 14. Impingement Background
Pipe Information 602533
Diameter 4”
SDR 11.5
Resin PE 2306
Manufacturer DuPont
Design Pressure 60psig
Service Information
Operating Pressure 60 psig at 65°F / 45 psig at 0°F
Service Temperature 60°F
Comments NA
Timeline
Placed in Service August 1984
Installation Method Direct Lay
Removed from Service January 2008
Comments Tee was installed in 2004
Environmental
Soil Type Rocky, sandy and silty
Evidence of 3rd Party Damage Possibly
Visual Examination
The sample revealed an off-axis slit failure which grew in two directions from an
indentation in the outer wall. The specimen was cut in half to reveal an approximately 3” slit on
the inner wall. The outer and inner wall of the pipe can be seen in Figure 62 and Figure 63
respectively. The specimen was cut from each end to within about ¼” of the crack. It was then
force fractured using liquid nitrogen to reveal the fracture face as seen in Figure 64 and Figure
65.
Figure 62. Slit Failure Growing Away From Impingement Point
Title: DTPH56-06-T-0004 Final Report Page 74
Figure 63. View of the Slit from the Inner Wall
Figure 64. Pipe Was Force Fractured to Reveal the Fracture Faces
Title: DTPH56-06-T-0004 Final Report Page 75
Figure 65. Close Up View of the Fracture Faces
Using high powered optical microscopy, the fracture faces were examined. The photographs
taken with the stereo optical microscope were stitched together and are shown in Figure 66. The
initiation point is noted on the photograph and was found to be on the inner wall directly
opposite of the indentation on the outer wall. The crack left visible striations as it grew step-wise
from the initiation point on the inner wall to the outer wall. Two ductile rupture zones are also
visible.
Title: DTPH56-06-T-0004 Final Report Page 76
Figure 66. Microscopy
Fracture Origin, Inner Wall
Initiation
Ductile
Rupture
Title: DTPH56-06-T-0004 Final Report Page 77
In addition to visual inspections, the tests outlined in Table 15 were also performed. Density
and melt flow tests were used to determine if the material was within manufacturer specification
when it was extruded. Oxidation Induction Time (OIT) and Differential Scanning Calorimetry
(DSC) were used to determine the oxidation and the melting point/ heat of fusion of the pipe
material. Fourier Transform Infrared Spectroscopy (FT-IR) tests were run to check for material
degradation and contamination.
Table 15: Test Methods Used in Root-Cause Evaluation
Test Method Revision Title
Leak Test* GTI Internal Method
Density*GTI Internal Method for Density by Helium
Pycnometer
ASTM D1238 04 Standard Test Method for Melt Flow Rates of
Thermoplastics by Extrusion Plastometer
ASTM D3895 07 Standard Test Method for Oxidative-Induction Time by
Differential Scanning Calorimetry
ASTM D3418 03 Standard Test Method for Transition Temperatures of
Polymers By Differential Scanning Calorimetry
FT-IR* GTI Internal Method for Infrared Analysis
* GTI’s laboratory maintains A2LA accreditation to ISO/IEC 17025 for specific tests listed in
A2LA Certificate 2139-01 and meets the relevant quality system requirements of ISO
9000:2000. Test/calibration/inspection method(s) and results are not covered by our current
A2LA accreditation.
Density
The skeletal density of the pipe was determined to be 0.942g/cc using the helium
pycnometer. This is consistent with medium density polyethylene gas pipe material from the
time period sample #602533 was manufactured.
Melt Flow
Portions of the pipe sections were prepared and subjected to ASTM D1238 melt flow
testing.
Table 16: Melt Flow Measurements
Sample ID Trial # Rate (g/10min)
602533-001 1 1.458
602533-001 2 1.158
602533-001 3 1.151
Average 1.256±0.1752
These results were consistent with medium density polyethylene gas pipe material.
Title: DTPH56-06-T-0004 Final Report Page 78
Thermal Analysis
Specimens were prepared from the pipe section and subjected to ASTM D3418 differential
scanning calorimetry. The resulting thermograms (Figure 67) indicated a heat of fusion of
157J/g and no additional melting or exotherms were detected which would have suggested the
presence of contamination. In addition, ASTM D3895 was performed on the prepared specimen
and indicated an oxidative-induction time of 49.6 minutes as seen in Figure 68. This was
consistent with the age of the PE considering it has absorbed organic materials from the gas
supply over time. These organic compounds are relatively easily oxidized when compared to PE.
Figure 67. Differential Scanning Calorimetry
Title: DTPH56-06-T-0004 Final Report Page 79
Figure 68. Oxidative Induction Time
Infrared Analysis
A comprehensive analysis was performed to determine the condition of the pipe and to
detect the presence of any organic materials not associated with the pipe material using Fourier-
Transform - Infrared Spectroscopy. The results did not indicate the presence of foreign organic
materials in the outer (Figure 69), middle (Figure 70), or inner (Figure 71) pipe wall within the
detectability of the instrument. The 1650cm-1 to1750cm-1 region of the resulting spectra was
also examined. Absorbencies in this region are associated with polyethylene oxidative products
though none were detected for this sample. This suggested that the pipe was manufactured and
stored acceptably prior to installation.
Title: DTPH56-06-T-0004 Final Report Page 80
Figure 69. FT-IR Outer Wall
Figure 70. FT-IR Middle Wall
Title: DTPH56-06-T-0004 Final Report Page 81
Figure 71. FT-IR Inner Wall
Conclusions
Because the battery of tests suggests nothing was out of the ordinary with the pipe material,
it is quite unlikely that the pipe extrusion process contributed to the slow crack growth failure. It
was concluded that the highly localized stresses induced on the pipe wall by a foreign body, most
likely a rock, led to the initiation of a slit failure on the inner pipe wall. The crack grew stepwise
in two directions away from the initiation point with the final through wall fracture occurring in a
ductile manner. This sample is classified as a material SCG failure due to rock impingement.
Research Approach
Eight samples were evaluated using the procedure described above and have been placed at
the beginning of their respective section. Roughly 50 additional pipe samples were received from
field service for failure evaluation. As the budget could not support full analysis of this many
samples, only visual examinations were performed on the remainder. Photographs, background
data, and visual examination results are provided.
Title: DTPH56-06-T-0004 Final Report Page 82
Material Failures
Tap Tee – #678156
Figure 72. As Received Sample with Two Tees. Leak Occurred At Untapped Tee, Left
Figure 73. Untapped Tee with Circumferential Slit
Title: DTPH56-06-T-0004 Final Report Page 83
Table 17. Tap Tee Background
Pipe Information 678156
Diameter 2”
SDR 11
Resin PE 2306
Manufacturer DuPont
Design Pressure 60psig
Service Information
Operating Pressure 60 psig at 65°F / 30 psig at 0°F
Service Temperature 60°F
Comments NA
Timeline
Placed in Service August 1980
Installation Method Direct Lay
Removed from Service November 2007
Comments Leak at untapped tee
Environmental
Soil Type Rocky, sandy and silty
Evidence of 3rd Party Damage No
Visual Examination
The submitted pipe section was subjected to initial examination. The examination indicated
the presence of a slit immediately adjacent to one side of the tee with minimal bead and rollback
as shown in Figure 73. The section was leak tested to verify the leak location at the observed slit
as shown in Figure 74. The section was cut longitudinally to expose the inner surface (Figure
75) then further cut to expose both fracture surfaces (Figure 76). The fracture surfaces contained
debris on the surface consistent with soil. A spherical particle was observed and initially thought
to be imbedded in the pipe wall on the tee side of the fracture but closer inspection revealed the
absence of a companion dimple on the pipe side of the fracture. It was concluded that this
particle had deposited itself post fracture. The particle can be seen in Figure 79.
Title: DTPH56-06-T-0004 Final Report Page 84
Figure 74. Underwater Leak Test Revealing Leak Location
Figure 75. Sample Was Cut to Show Inner Pipe Wall
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Figure 76. Close Up of the Circumferential Slit on the Inner Wall
Figure 77. Length of Fracture Faces Identified with Red Marker
Title: DTPH56-06-T-0004 Final Report Page 86
Figure 78. Close up of the Fracture Face Away from the Tee
Figure 79. Close up of the Fracture Face towards the Tee with Area of Interest Identified
Title: DTPH56-06-T-0004 Final Report Page 87
The surfaces were examined with a stereo optical microscope and revealed that the SCG
fracture originated from the inner wall of the pipe and proceeded outward as shown in Figure 80.
Another area exhibited a secondary SCG fracture origin originating near the outer surface of the
pipe then proceeding inward, suggesting a change or compound loading of the area. The
secondary origin is identified in Figure 81.
Figure 80. Microscopy of the Fracture Face Away From the Tee
Figure 81. Microscopy of the Fracture Face towards the Tee
Area of Crack Origin
Area of Crack Origin
Secondary Origin
Title: DTPH56-06-T-0004 Final Report Page 88
Density
The skeletal density of the pipe was determined to be 0.939g/cc using the helium
pycnometer. This is consistent with medium density polyethylene gas pipe material from the
time period sample #678156 was manufactured.
Melt Flow
Sections of the pipe were prepared and subjected to ASTM D1238 melt flow testing.
Table 18: Melt Flow Measurements - Pipe
Sample ID Trial # Rate (g/10min)
678156-001 1 0.9200
678156-001 2 1.4360
678156-001 3 1.4060
Average 1.2540±0.2896
These results were consistent with medium density polyethylene gas pipe material.
Thermal Analysis
Specimens were prepared from the pipe section and subjected to ASTM D3418 differential
scanning calorimetry. The resulting thermograms indicated a heat of fusion of 182.8J/g and no
additional melting or exotherms were detected which would have suggested the presence of
contamination. The results are shown in Figure 82. In addition, ASTM D3895 was performed on
the prepared specimen to determine OIT. The test ran for 85 minutes but the material never
oxidized as shown in Figure 83. This was consistent with the age of the PE considering it has
absorbed organic materials from the gas supply over time. These organic compounds are
relatively easily oxidized when compared to PE.
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Figure 82. Differential Scanning Calorimetry
Figure 83. Oxidative Induction Time
Title: DTPH56-06-T-0004 Final Report Page 90
Infrared Analysis
A comprehensive analysis was performed to determine the condition of the pipe and to
detect the presence of any organic materials not associated with the pipe material using Fourier-
Transform - Infrared Spectroscopy. The results did not indicate the presence of foreign organic
materials in the outer (Figure 84), middle (Figure 85), or inner (Figure 86) pipe wall within the
detectability of the instrument. The 1650cm-1 to1750cm-1 region of the resulting spectra was
also examined. Absorbencies in this region are associated with polyethylene oxidative products.
Weak absorbencies were observed in this region that indicated minimal oxidation had occurred.
This suggested that the pipe was manufactured and stored acceptably prior to installation.
Figure 84. FT-IR Outer Wall
Title: DTPH56-06-T-0004 Final Report Page 91
Figure 85. FT-IR Middle Wall
Figure 86. FT-IR Inner Wall
Conclusions
Based on the tests performed, it was concluded that the submitted section failed due to the
stress concentration at the edge of the fusion tee. Typical loads associated with pipe
burial/settling and the relatively low resistance to crack propagation of older generation PE
material combined with the stress concentrator to lead to the observed SCG failure.
Title: DTPH56-06-T-0004 Final Report Page 92
Impingement - #00590
Figure 87. As Received Condition
Table 19. Impingement Background
Pipe Information 00590
Color Orange
Diameter 4”
SDR 11.5
Resin PE 2306
Manufacturer Driscopipe
Design Pressure -
Service Information
Operating Pressure -
Service Temperature 55°F
Comments -
Timeline
Placed in Service -
Installation Method -
Removed from Service September 2007
Comments -
Environmental
Soil Type -
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 93
Visual Examination
The sample contained a crack approximately 6.25” in length in the outer wall of the pipe
(Figure 88) and a dimple in the exterior surface of the pipe located approximately midway in the
crack length (Figure 89). Examination of the inner pipe wall confirmed that the crack had
traversed through the pipe wall as shown in Figure 90.
Figure 88. Crack on Outer Wall
Figure 89. Close Up, Dimple and Crack
Dimple
Title: DTPH56-06-T-0004 Final Report Page 94
Figure 90. Crack As Seen On Inner Wall
The pipe was the carefully cut so as to expose the fracture surface while minimizing
opposing fracture surface contact and associated smearing of the surface morphology during the
cutting operation. Once the fracture surfaces were exposed they were visually examined at
magnifications up to 160X. The origin of the fracture, visible in Figure 91 and Figure 92, was
found in the inner wall; located almost directly beneath the dimple in the outer wall. There was
no evidence of defects or foreign material in the pipe wall.
Figure 91. Fracture Origin
Fracture Origin
Crack Direction
Impingement Site
Title: DTPH56-06-T-0004 Final Report Page 95
Figure 92. Composite Photo, Fracture Surface - Outer Wall at Top
Density and Melt Flow
A portion of the pipe material was removed and subjected to melt flow analysis in
accordance with ASTM D1238. The results of this testing indicated that the pipe material had a
MFR of 0.16g/10min. Density testing was also performed using a helium pycnometer. This test
indicated that the material had a density of 0.942g/cc.
Conclusions
Based on the tests performed it was concluded that:
1) The fracture in the submitted pipe section resulted from rock impingement with the
crack propagating by SCG process,
2) There were no observed pre-existing defects in the pipe; and
3) The pipe was consistent with properly extruded PE 2306 material.
Title: DTPH56-06-T-0004 Final Report Page 96
Impingement - #04020731
Figure 93. Bottom Side of as Received Sample
Table 20. Slit Failure Background
Pipe Information 04020731
Color Tan
Diameter 2”
SDR -
Resin PE 2306
Manufacturer DuPont Aldyl A
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig
Timeline
Placed in Service February 1971
Installation Method Direct Burial; Bored
Removed from Service September 2007
Comments 40” depth of cover; Pipe laying on rock in ditch
Environmental
Soil Type Sand; Rock
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 97
Visual Examination
The failure report and background documentation provided with this sample indicated the
presence of a rock in the ditch at the failure location. The impingement point is expressed by a
green circle in Figure 94 below. Figure 95 shows the slit as seen on the inner wall. The location
of the slit on the inner wall corresponds to the outer wall location. The impingement of the rock
resulted in localized pipe loading/deformation leading to an axial slit wise crack. Most likely, it
initiated on the ID (under tensile load) and grew through the wall to the OD.
Figure 94. Axial Slit on Outer Wall
Figure 95. Axial Slit on Inner Pipe Wall
Title: DTPH56-06-T-0004 Final Report Page 98
External Loading - #26020806
Figure 96. As Received Sample
Table 21. External Loading Background
Pipe Information 26020806
Color Orange
Diameter 4”
SDR -
Resin PE 2306
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments
Pressure tested at 100 psig for 150 minutes; Pipe
was resting on a 4” steel main
Timeline
Placed in Service August 1976
Installation Method Direct Burial; Bored
Removed from Service January 2008
Comments 30” depth of cover
Environmental
Soil Type Sand
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 99
Visual Examination
According to background information provided by the submitting company, the pipe was
found resting on a 4-inch steel main. This resulted in a localized shell bending load and
deformation of the plastic pipe. An axial slit-wise crack was observed centered on the inner wall
at the load point. The slit on the inner wall was measured at approximately 4” long. The crack
exhibited full wall penetration resulting in a 1” slit on the outer wall.
Figure 97. Side and Bottom View of Sample
Title: DTPH56-06-T-0004 Final Report Page 100
Figure 98. Slit on Outer Wall
Figure 99. Slit on Inner Wall
Title: DTPH56-06-T-0004 Final Report Page 101
Tee Caps
Cap –#50020726
Figure 100. As Received Cap
Background data was not available for this sample.
Title: DTPH56-06-T-0004 Final Report Page 102
Visual Examination
The cap was transversely split in two. The topside of the cap contained an o-ring for sealing
the cap to the tee. This o-ring was free of nicks, had no embedded material and was also free of
cracking. The actual cap material adjacent to the o-ring was free of scratches and gouges
suggesting that the cap was tightened down without the top of the tee coming in contact with the
cap which would have suggested potential over-tightening of the cap during installation. Both the
top side (Figure 101) and bottom side (Figure 102) fracture surfaces were lightly covered with
dirt from the installation site with more dust on the open-side fracture surface. The cap threads
were free from distortion and damage as shown in Figure 103.
The top-side fracture surface was further examined using the stereo optical microscope with
magnification capabilities to 320X. The results of this examination failed to indicate a single
fracture origin. Instead it was determined that the fracture originated at the root of the last thread
(nearest the top of the cap) and radiated outward tangent to this thread root. The fracture surface
exhibited no indication of a torsional force component. White streaks were observed in the
fracture surface as seen in Figure 104.
Figure 101. Topside Fracture Surface

Title: DTPH56-06-T-0004 Final Report Page 103
Figure 102. Bottom Side Fracture Surface
Figure 103. Cap Threads
Title: DTPH56-06-T-0004 Final Report Page 104
Figure 104. Topside Fracture Surface
Infrared Analysis
A specimen was prepared from the cap and subjected to infrared analysis. The resulting
spectrum, shown in Figure 105, contained absorbencies consistent with a nylon (polyamide)
thermoplastic.
Figure 105. FT-IR Spectrum of the Cap Material
Banding
Thread Roo
Title: DTPH56-06-T-0004 Final Report Page 105
Differential Scanning Calorimetry
Since infrared analysis cannot conclusively determine the type of nylon, another specimen
was prepared and analyzed for melting temperature by DSC. The resulting thermogram, seen in
Figure 106, indicated a peak melt at 252°C. This was consistent with nylon 6,6 thermoplastic.
No other melts were present that would have indicated the presence of a contaminant material.
Figure 106. DSC Thermogram of the Cap Material
Thermogravimetric Analysis and Energy Dispersive X-ray
To further identify the cap material, a final specimen was prepared and analyzed using
Thermogravimetric Analysis (TGA) to determine the ash content. The resulting TGA plot
(Figure 107) indicated that the material had an ash content of 40%. Subsequent analysis by
Energy Dispersive X-ray (EDX) indicated that the ash contained significant amounts of silicon
(Si), aluminum (Al), oxygen (O). This suggested the presence of kaolin, a common filler
material. Titanium (Ti) was also present to a lesser extent and suggested the presence of
titanium dioxide, a common filler, pigment, and flattening agent used in plastics and coatings.
The EDX spectrum can be seen in Figure 108.
Title: DTPH56-06-T-0004 Final Report Page 106
Figure 107. TGA Plot
Figure 108. EDX Spectrum of the Cap Material Ash
Title: DTPH56-06-T-0004 Final Report Page 107
Conclusions
Based on the tests performed it was concluded that:
1) Nylon materials are known to be to generally tough materials. The subject cap was
manufactured from nylon, a 40% Kaolin filled (polyamide) 6,6. Nylon 6,6 the most
commonly used of this material family.
2) The cap failure initiated in the root of the thread nearest the top off the cap. This
area served to concentrate the tensile stress resulting from the mating of the cap to
the companion tee.
3) There were no indications of over tightening or improper processing of the cap.
4) The banding observed in the fracture surfaces was the result of a differential cooling
rate across the thickness of the part. This is common and was not a major
contributor to the cap failure.
5) The white material found on the fracture surfaces was later determined to be un
pigmented nylon 6,6 and was not a major contributor, if at all, to the cap failure.
Title: DTPH56-06-T-0004 Final Report Page 108
Cap - #20020447
Figure 109. As Received Cap
Table 22. Cap Background
Pipe Information 20020447
Color Black
Diameter 2” x ¾” Service Tee
SDR -
Resin -
Manufacturer Wayne
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 90 psig for 120 minutes
Timeline
Placed in Service November 1993
Installation Method -
Removed from Service April 2004
Comments 12” depth of cover
Environmental
Soil Type Loam
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 109
Visual Examination
This cap, manufactured by Wayne, exhibited a crack which extended approximately 230°
around the circumference. The crack appeared to have originated in the first thread. Gouges
indicative of the use of a wrench were apparent as seen to the left in Figure 109 though it is not
possible to determine whether these marks were created during installation, service, or removal.
Figure 110. Crack Seen Inside the Cap.
Title: DTPH56-06-T-0004 Final Report Page 110
Cap - #21020739
Figure 111. As Received Cap
Table 23. Cap Background
Pipe Information 21020739
Color Black
Diameter -
SDR -
Resin
Manufacturer Wayne
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 90 psig for 15 minutes
Timeline
Placed in Service December 1993
Installation Method -
Removed from Service November 2007
Comments 36” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 111
Visual Examination
This cap exhibited a crack which ran about 200° around the circumference. The crack on
this cap appears to have started at the first thread and also exhibited signs of wrench use.
Figure 112. Soil on Interior Surface
Title: DTPH56-06-T-0004 Final Report Page 112
Cap - #22020733
Figure 113. As Received Cap
Table 24. Cap Background
Pipe Information 22020733
Color Black
Diameter -
SDR -
Resin
Manufacturer Wayne
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 30 psig for 15 minutes
Timeline
Placed in Service January 1978
Installation Method -
Removed from Service October 2007
Comments 24” depth of cover
Environmental
Soil Type Gravel
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 113
Visual Examination
This cap exhibited a crack which extended approximately 215° around the circumference.
The crack appears to have originated in the first thread as indicated by the soil visible on the
interior of the cap shown in Figure 114.
Figure 114. Dirty Interior Surface
Title: DTPH56-06-T-0004 Final Report Page 114
Cap - #23020464
Figure 115. As Received Cap
Table 25.Cap Background
Pipe Information 23020464
Color Black
Diameter -
SDR -
Resin -
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service 1980
Installation Method -
Removed from Service June 2004
Comments 40” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 115
Visual Examination
This cap from an unknown manufacturer exhibited a crack which was visible around the
entire circumference. The crack appeared to have originated in the first thread. Gouges indicative
of the use of a wrench were apparent as seen in Figure 116.
Figure 116. Cracked Cap with Wrench Marks
Title: DTPH56-06-T-0004 Final Report Page 116
Cap - #24020499
Figure 117. As Received Cap
Table 26. Cap Background
Pipe Information 24020499
Color Black
Diameter -
SDR -
Resin -
Manufacturer Wayne (cap)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service November 1993
Installation Method -
Removed from Service December 2004
Comments 24” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 117
Visual Examination
This cap exhibited a crack which extended approximately 240° around the circumference.
The crack appeared to have originated in the same place as the previous caps. Gouges indicative
of the use of a wrench can be seen in Figure 118.
Figure 118. Yellow Tee Visible Through the Crack
Title: DTPH56-06-T-0004 Final Report Page 118
Caps - #25020718 and #49020718
Figure 119. As Received Service Tee with Broken Cap
Table 27. Cap Background
Pipe Information 25020718
Diameter 2”
SDR -
Resin -
Manufacturer Wayne
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service 1992 (main)
Installation Method -
Removed from Service 2007
Comments 24” depth of cover
Environmental
Soil Type Loam
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 119
Visual Examination
The received sample contained two service tees. The caps on each tee were completely
severed. As seen in Figure 121, the cracks originated at the first thread on one of the caps.
Figure 120. Fracture Surfaces of Cap
Figure 121. Fracture Surface of the Top of the Cap
Title: DTPH56-06-T-0004 Final Report Page 120
Cap - #31020649
Figure 122. As Received Cap
Table 28. Cap Background
Pipe Information 31020649
Color Tan
Diameter 2” (main) 1 – ¼” (service)
SDR -
Resin PE 2306
Manufacturer DuPont Aldyl A(pipe and tee)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig
Timeline
Placed in Service November 1970
Installation Method -
Removed from Service December 2006
Comments 36” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 121
Visual Examination
The cap was extensively damaged yet all of the external threads appeared to have remained
intact. The corresponding internal threads in the saddle tee were intact as well. The cap
exhibited multiple fracture planes with associated multiple fracture origins. Fifty 50% of the
upper portion of the cap was missing along with the o-ring. The general orientation of the major
fracture planes suggested that the cap may have been subjected to significant loading from
above.
Figure 123. Cap, Underside Left and Topside Right
Figure 124. Internal Threads of the Saddle Tee
Title: DTPH56-06-T-0004 Final Report Page 122
Thread Inserts
Service Tee Threads - #15020650
Figure 125. As Received Tee
Visual Examination
The sample was missing background data and companion cap upon submission. GTI was
unable to obtain either. The failure initiated at root of the second thread. The thread root acted as
a stress concentrator to the tensile forces produced by tightening the cap.
Title: DTPH56-06-T-0004 Final Report Page 123
Figure 126. Close-up View of Thread Insert
Title: DTPH56-06-T-0004 Final Report Page 124
Service Tee Threads - #29020510
Figure 127. As Received Tee
Table 29. Service Tee Threads Background
Pipe Information 29020510
Color Tan
Diameter 2”
SDR -
Resin PE 2306
Manufacturer Aldyl-A
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig
Timeline
Placed in Service May 1970
Installation Method Direct Burial
Removed from Service January 2005
Comments 36” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 125
Visual Examination
The threaded insert fractured about 300° at the second thread which remained attached to the
cap. The thread root acted as a stress concentrator to the tensile forces produced by tightening the
cap. The cap contained deposits consistent with an aged lubricant that was most likely applied to
the o-ring on a previous occasion. Lubricants can imbrittle certain types of plastic but without
identifying this particular insert material it cannot be stated with certainty.
Figure 128. Close up of Severed Insert
Figure 129. Cap with Insert Attached
Title: DTPH56-06-T-0004 Final Report Page 126
Socket Couplings
Socket Coupling - #30020542
Figure 130. As Received
Table 30. Coupling Background
Pipe Information 30020542
Color Black
Diameter 2”
SDR -
Resin -
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 360 minutes
Timeline
Placed in Service January 1972
Installation Method Direct Burial
Removed from Service May 2005
Comments 60” depth of cover
Environmental
Soil Type Sand
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 127
Visual Examination
The coupling exhibited complete separation in plane with the end of the orange pipe.
Preliminary examination of the fracture surface indicated the presence of torsional loading of the
coupling and adjacent pipe. Approximately 50% of the face of the failure exhibited features
similar to SCG. The crack appears to have initiated on the ID then grew towards the OD with
final ductile rupture at the OD surface. In Figure 132, the whitened area below the yellow line
shows the SCG features. The ductile rupture area is above the yellow line.
Figure 131. Severed Coupling
Figure 132. Fracture Face
Title: DTPH56-06-T-0004 Final Report Page 128
Socket Coupling - #35020485
Figure 133. As Received Service Tee with Socket Coupling
Table 31. Socket Coupling Background
Pipe Information 35020485
Color Orange
Diameter 1”
SDR -
Resin -
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 15 minutes
Timeline
Placed in Service October 1971
Installation Method -
Removed from Service October 2004
Comments 36” depth of cover
Environmental
Soil Type
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 129
Visual Examination
The socket coupling showed signs of overheating to the point of deformation. A 1 – ¾”
circumferential slit was observed on the underside of the socket. The slit appears to line up with
end of the service line pipe. The side view of the specimen in Figure 134 shows the service line
in parallel misalignment. The direction of the misalignment relative to the location of the crack
indicates that an excessive bending stress was applied.
Figure 134. Side View
Figure 135. Bottom View
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Figure 136. 1 - ¾” Circumferential Slit on Underside of Coupling
Title: DTPH56-06-T-0004 Final Report Page 131
Socket Coupling - #39020605
Figure 137. As Received Coupling
Table 32. Socket Coupling Background
Pipe Information 39020603
Color Orange
Diameter 2”
SDR 11
Resin PE 2306
Manufacturer Driscopipe 6500 (pipe) Unknown (coupling)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 4 hours
Timeline
Placed in Service 1982
Installation Method -
Removed from Service January 2006
Comments 40” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage Loading from excavation in area
Title: DTPH56-06-T-0004 Final Report Page 132
Visual Examination
As seen in Figure 137, the pipe was under a bending moment from installation conditions.
Because the bending made it impossible to observe the entire inside of the pipe, one end was cut
off. A slit failure in the circumferential direction was observed on the pipe wall as seen in Figure
138. The crack lined up with the edge of the coupling which is also where external leak location
was identified during pressure testing as identified by an arrow in Figure 139. The direction of
the misalignment relative to the location of the crack indicates that an excessive bending stress
was applied.
Figure 138. Crack in Pipe Wall on ID
Figure 139. Side View of Socket Fusion
Title: DTPH56-06-T-0004 Final Report Page 133
Socket Tees
Socket Tee - #19020414
Figure 140. As Received Socket Tee
Table 33. Socket Tee Background
Pipe Information 19020414
Color Orange
Diameter 4”
SDR -
Resin -
Manufacturer Unknown (pipe) Unknown (tee)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 120 minutes
Timeline
Placed in Service 1978
Installation Method -
Removed from Service March 2004
Comments 48” depth of cover
Environmental
Soil Type Rock
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 134
Visual Examination
A thru wall circumferential slit on the socket was observed. The 4” slit appeared to line up
with the end of the pipe. Also of note, the socket displayed some radial distortion. Interference
between the pipe and the socket could be responsible for elevating stresses at the pipe
edge/socket interface.
Figure 141. Circumferential Slit in Fitting
Title: DTPH56-06-T-0004 Final Report Page 135
Socket Tee - #33020602
Figure 142. As Received Socket Tee
Table 34. Socket Tee Background
Pipe Information 33020602
Color Orange
Diameter 3 Way Tee 2” in all directions
SDR 11.5
Resin PE 2306
Manufacturer Unknown (pipe) unknown (tee)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments
Pressure tested at 90 psig for 60 minutes ;
Interference fit slit
Timeline
Placed in Service September 1972
Installation Method Direct Burial
Removed from Service January 2006
Comments 30” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 136
Visual Examination
A 2” circumferential slit crack in the socket that grew completely through the socket wall
was observed. The slit was approximately lined up with the end of the pipe where stress was
most likely concentrated due to radial distortion also noted on this sample.
Figure 143. Circumferential Slit in Socket
Supplemental Inspection
This sample was shared with another PHMSA sponsored project “Nonmetallic Joint Quality
Assessment” (Project #217 Contract Number: DTPH56-07-T-000001). The objective of this
project is to develop non-destructive inspection techniques for heat fusion joints. Ultrasonic
measurements were used on this and other samples and provided information on flaws in the
interior of the pipe and fitting. The numbers visible on the sample mark locations where
measurements were made and recorded using ultrasonic sensor. The measurements showed the
crack direction from the OD to the ID angles into the body of the socket tee.
Title: DTPH56-06-T-0004 Final Report Page 137
Socket Tee - #34020623
Figure 144. As Received Socket Tee
Table 35. Socket Tee Background
Pipe Information 34020623
Color Orange
Diameter 2”
SDR -
Resin PE 3206
Manufacturer Driscopipe 6500 (pipe) Unknown (tee)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 90 psig for 4 hours
Timeline
Placed in Service August 1983
Installation Method Direct Burial; Bored
Removed from Service March 2006
Comments 48” depth of cover
Environmental
Soil Type Sand
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 138
Visual Examination
A crack was observed on the face of socket tee as seen in Figure 145. Looking into the
fitting, a ledge was observed, suggesting this is a molded part rather than an extruded pipe. A
circumferential crack extending 60o around the circumference and discoloring were also
observed. These three features are identified by arrows in Figure 146.
Figure 145. Crack on Socket Surface
Figure 146. Features on ID
Ledge Crack Discoloration
Title: DTPH56-06-T-0004 Final Report Page 139
Supplemental Inspection
This sample was also shared with PHMSA sponsored project “Nonmetallic Joint Quality
Assessment” (Project #217 Contract Number: DTPH56-07-T-000001). Black dots seen in Figure
147 show ultrasonic measurement locations. The measurements showed poor fusion quality at
the pipe/coupling interface for a distance of 0.3” in from the edge of the socket tee. This area is
marked by green arcs in Figure 147. Beyond this area, fusion quality improved dramatically
going towards the body of the tee. The location of the crack on the molded part/pipe was 0.3”
from the edge of the socket tee. The information suggests gas escaped out of the crack and
through the un-bonded area between the pipe and coupling.
Figure 147: Photograph of Tee Showing Location of Leak
Title: DTPH56-06-T-0004 Final Report Page 140
Procedural Failures
High Volume Tapping Tee - #00632
Figure 148. Close-up of Pipe Section with Tee as Seen in the Field.

Table 36. 4” x 2” HVTT Background
Pipe Information 00632
Diameter 4”
SDR 11.5
Resin PE 2406
Manufacturer Plexco
Design Pressure 60 psig
Service Information
Operating Pressure 20-35 psig
Service Temperature 55°F
Comments Pressure tested to 100 psig
Timeline
Placed in Service January 23, 1997
Installation Method Direct bury with stiffener sleeve
Removed from Service September 12, 2007
Comments Sleeve was installed prior to tee
Environmental
Soil Type In situ and sand shading
Evidence of 3rd Party Damage No
“Nose” of
the tee
Title: DTPH56-06-T-0004 Final Report Page 141
Visual Examination
Areas of uneven rollback or no rollback were discovered at the tee-pipe interface as shown
in the photos in Figure 149. A gap was noted on the inside of the tee between the tee and the pipe
outer wall as seen in Figure 150. This gap suggested an area of discontinuous fusion.
Figure 149. Left Side with No Bead Rollback and Right Side with Uneven Bead Rollback
Figure 150. Close-up of Gap between Pipe Surface and Fitting
Title: DTPH56-06-T-0004 Final Report Page 142
The specimen was capped, immersed in water, and pressurized to 15 psi to verify the
location of the leak. As seen in Figure 151, the leak was found on the backside of the tee at the
fusion interface.
Figure 151. Pressure Test to Identify Leak Location
After the initial leak test, the tee and companion pipe segment were sectioned and force
fractured with liquid nitrogen in order to expose the area of the detected leak. Once the tee was
separated from the pipe, a shifting of the print line was observed as seen in Figure 152.
Line drawings were overlaid on the photograph to illustrate the complexity of the surface
condition. The damage encircled by purple was caused by GTI scraping to obtain sample
material for differential scanning calorimetry. The area lined by red was observed as being shiny
and smooth as well as depressed relative to the surrounding areas. Coloring in the red area
matched the coloring of the scraped areas around the tee though more yellow. This suggested
heating in this area was minimal and a corresponding minimal fusion, if any, had occurred. The
area lined by grey indicated rough, raised areas. The surface was somewhat grey in color and
exhibited signs of some adhesion. The blue area was also depressed and matched the shape of the
edge of the tee’s saddle. The red, grey, and blue areas had matching surfaces on the underside of
the tee. The opposing face to the red area was smooth and the opposing face to the grey area was
relatively rough. The blue area’s mating face showed transfer of the print line. This transfer can
be seen in Figure 153. A close up examination of this area revealed the presence of fibers
imbedded in the surface. The fibers likely transferred from a material used in the pre-fusion
cleaning process.
Title: DTPH56-06-T-0004 Final Report Page 143
Figure 152. Pipe Segment Surface from Under the Tee on the Side Containing the Leak
Scraped by GTI
Shiny, smooth, depressed area
Rough, grey colored area
Depressed area
Title: DTPH56-06-T-0004 Final Report Page 144
Figure 153. Mating Surfaces of the Tee and Pipe
Scraped by GTI for
testing
Title: DTPH56-06-T-0004 Final Report Page 145
Density
The densities of the pipe and tee material were determined to be 0.9421g/cc and 0.9404g/cc
respectively. This was consistent with medium density polyethylene gas pipe material.
Melt Flow
Portions of the pipe and tee sections were prepared and subjected to ASTM D1238 melt
flow testing.
Table 37: Melt Flow Measurements - Pipe
Sample ID Trial # Rate (g/10min)
632-001a 1 0.1709
632-001a 2 0.1732
632-001a 3 0.1748
Average 0.173±0.002
Table 38: Melt Flow Measurements - Tee
Sample ID Trial # Rate (g/10min)
632-001b 1 0.1683
632-001b 2 0.1690
632-001b 3 0.1692
Average 0.1688±0.0005
These results were consistent with medium density polyethylene gas pipe material.
Thermal Analysis
Specimens were prepared from the pipe section by removing material from the pipe fusion
surface, middle of the pipe wall, and the inner pipe wall surface. These specimens were subjected
to ASTM D3418 differential scanning calorimetry. The resulting thermograms indicated
consistent levels of crystallinity for each of the specimens. No additional melting or exotherms
were detected which would have suggested the presence of contamination. In addition, ASTM
D3895 oxidative-induction time was performed on another set of prepared specimens. The
scraped surface prepared for the fusion exhibited a slightly lower induction time than the middle
and inner layers of the pipe. This was consistent with pipe that has been in the field. The OIT
and DSC thermograms are shown in Figure 154, Figure 155, and Figure 156.
Title: DTPH56-06-T-0004 Final Report Page 146
Figure 154. OIT and DSC – Outer Wall – Pipe
Figure 155. OIT and DSC – Middle Wall – Pipe
Title: DTPH56-06-T-0004 Final Report Page 147
Figure 156. OIT and DSC – Inner Wall – Pipe
Title: DTPH56-06-T-0004 Final Report Page 148
Infrared Analysis
A comprehensive analysis was performed to determine the condition of the pipe and tee
sections as well as detect the presence of any organic materials not associated with the pipe
material. The resulting spectra were analyzed and indicated no any foreign organic materials in
the outer diameter fusion area, middle, and inner diameter surfaces. The 1650cm-1 to1750cm-1
region of the resulting spectra were closely examined. Absorbencies in this region are associated
with PE oxidative products. No absorbencies were detected in this region. This suggested that
the pipe was manufactured and stored acceptably prior to installation. The FT-IR charts for the
outer, middle, and inner walls can be seen in Figure 157, Figure 158, and Figure 159,
respectively.
Acetone extractions of the good (adjacent to proper rollback on fusion bead) and poor
(adjacent to area with no fusion bead) fusion areas of the tee were performed to see if any
organic materials not associated with the tee material could be detected. No abnormal
absorbencies were detected in the resulting spectra shown in Figure 160 and Figure 161.
x
Figure 157. FT-IR - Outer Wall – Pipe
Title: DTPH56-06-T-0004 Final Report Page 149
Figure 158. FT-IR - Middle Wall – Pipe
Figure 159. FT-IR - Inner Wall – Pipe
Title: DTPH56-06-T-0004 Final Report Page 150
Figure 160. FT-IR – Good Fusion Area
Figure 161. FT-IR - Poor Fusion Area
Title: DTPH56-06-T-0004 Final Report Page 151
Conclusions
Based on the tests performed and the information provided it was concluded that:
1) The 4” pipe had a preexisting deflection when the fusion procedure was performed
preventing the entire face of the tee from fusing to the pipe wall. The pipe surface
was concave at the fusion interface which caused unequal application force across
the face where more force was realized on the left and right side of the tee than in the
midsection. The surfaces of the two parts indicated that the fusion was more
complete on the sides of the tee than in the center.
2) The large degree of movement of the pipe print line underneath indicated that the tee
had moved significantly during the fusion most likely due to insufficient clamping
and/or improper positioning. This was consistent with the observed poor, non-
existent rollback and the significantly large areas of little or no fusion that were
observed. Based on background information, difficult spatial circumstances may
have prevented the operator from properly using aligning equipment.
3) The offset position of the sleeve relative to the nose of the tee indicated that the fill
had settled. This offset applied downward stress to the nose thereby transferring
additional stress to the fusion. This additional stress contributed to the failure.
4) The material properties of the pipe material were consistent with normal medium
density PE material that was properly stored prior to installation and free of
contaminants. It was determined that the pipe material did not contribute to the
failure.
Title: DTPH56-06-T-0004 Final Report Page 152
Butt Fusions
Butt Fusion - #060204100
Figure 162. As Received Butt Fusion
Table 39. 2” Butt Fusion Background
Pipe Information 060204100
Color Orange
Diameter 2”
SDR 11
Resin PE 2306
Manufacturer Driscopipe
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service 1979
Installation Method -
Removed from Service December 2004
Comments 32” depth of cover
Environmental
Soil Type Loam
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 153
Visual Examination
The internal and external beads were symmetric and displayed a proper amount of rollover.
Examination of the fracture surfaces showed no indication of cold fusion or slow crack growth.
Instead, the surfaces were indicative of a dynamic brittle fracture over the majority of the face
with the final fracture location exhibiting ductile fibrils/tearing. These features are typical of an
overload failure.
Figure 163. Side View of Butt Fusion
Title: DTPH56-06-T-0004 Final Report Page 154
Figure 164. Fusion Faces
Figure 165. Inside Bead on One Side of Fusion
Title: DTPH56-06-T-0004 Final Report Page 155
Butt Fusion - #07020714
Figure 166. As Received Butt Fusion
Table 40. 4” Butt Fusion Background
Pipe Information 07020714
Color Orange
Diameter 4”
SDR 11.5
Resin PE 2306
Manufacturer Driscopipe 6500 20 May 83
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 90 psig for 2 hours
Timeline
Placed in Service 1983
Installation Method Direct Burial; Bored
Removed from Service March 2007
Comments 4’ depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 156
Visual Examination
As can be seen in Figure 166, the sample exhibited an axial misalignment resulting in the
appearance of mitered faces. The internal and external fusion beads did not exhibit complete
rollover, as seen in Figure 167.
Figure 167. Incomplete Bead Rollover
Title: DTPH56-06-T-0004 Final Report Page 157
Butt Fusion - #08020601
Figure 168. As Received Butt Fusion
Table 41. 3” Butt Fusion Background
Pipe Information 08020601
Color Orange
Diameter 3”
SDR 11.5
Resin PE
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service May 1975
Installation Method -
Removed from Service January 2006
Comments 34” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 158
Visual Examination
A 360° cold bond was observed on the mid-wall of both faces of the butt fusion. This
depressed area is outlined with arrows in Figure 169. The weak to non-existent interface bond
between the mid-walls was a result of improper heat/pressure/time variables in the joining
procedure. Fusion occurred only in the melt bead and resulted in approximately 30 years of
service before final separation.
Figure 169. Fusion Faces Showing Cold Fusion Area
Title: DTPH56-06-T-0004 Final Report Page 159
Butt Fusion - #09020552
Figure 170. As Received Butt Fusion
Table 42. 2” Butt Fusion Background
Pipe Information 09020552
Color Orange
Diameter 2”
SDR -
Resin PE 2306
Manufacturer Conind
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 90 psig for 120 minutes
Timeline
Placed in Service 1975
Installation Method -
Removed from Service September 2005
Comments -
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 160
Visual Examination
The overall workmanship of this fusion was poor. Relative to each other, the pipes displayed
parallel misalignment (Figure 170) as well as asymmetric beads (Figure 171). Individual beads
were not easily discernable. One was barely visible and neither showed proper rollover
suggesting inadequate heat/time/pressure during the fusion procedure.
Figure 171. Uneven Rollback
Figure 172. Side of Bead
Title: DTPH56-06-T-0004 Final Report Page 161
Butt Fusion - #10020477
Figure 173. As Received
Table 43. 4” Butt Fusion Background
Pipe Information 10020477
Color Orange
Diameter 4”
SDR 11.5
Resin -
Manufacturer Driscopipe 6500
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service 1985
Installation Method -
Removed from Service August 2004
Comments 36” depth of cover
Environmental
Soil Type Sand
Evidence of 3rd Party Damage No; Other excavation occurred
Title: DTPH56-06-T-0004 Final Report Page 162
Visual Examination
The external bead rollover appeared adequate based on the visual exam. The internal bead
did not appear to rollover completely. As seen in Figure 174, the mid-wall displayed a lack of
bond penetration of approximately 20-30% cold fusion around the entire circumference.
Figure 174. Area of Cold Fusion
Figure 175. Fusion Faces
Title: DTPH56-06-T-0004 Final Report Page 163
Butt Fusion - #11020511
Figure 176. As Received Butt Fusion
Table 44. 4” Butt Fusion Background
Pipe Information 11020541
Color Yellow
Diameter 4”
SDR 11.5
Resin PE 2406
Manufacturer Plexco
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 18 hours
Timeline
Placed in Service February 1994
Installation Method Direct Burial; Bored
Removed from Service May 2005
Comments 48” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 164
Visual Examination
Visually, this joint exemplified adequate bead size and rollover. A void was noticeable at the
leak location, as identified by the arrow in Figure 177. Looking down the interior of the pipe
revealed the presence of foreign matter (Figure 178). The foreign object, which resembled a
plant (Figure 179), was embedded in the fusion at the location of the leak location identified on
the external wall.
Figure 177. Leak Location at the Bead Weld
Figure 178. View down the Inside of the Pipe Section
Title: DTPH56-06-T-0004 Final Report Page 165
Figure 179. Close-up of the Inner Weld Bead
Title: DTPH56-06-T-0004 Final Report Page 166
Butt Fusion - #12020550
Figure 180. As Received
Table 45. 4” Butt Fusion Background
Pipe Information 12020550
Color Orange
Diameter 4”
SDR -
Resin PE 2306
Manufacturer _______TURE
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service -
Installation Method -
Removed from Service August 2005
Comments 48” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 167
Visual Examination
This fusion joint displayed axial misalignment of the pipe ends (Figure 180) and a visible
separation within the joint (Figure 181). Bead rollover was also inadequate and nonsymmetrical
as seen in Figure 182.
Figure 181. Weld Separation along ~3” Arc Length
Figure 182. Uneven Beads
Title: DTPH56-06-T-0004 Final Report Page 168
Butt Fusion - #13020706
Figure 183. As Received
Table 46. 4” Butt Fusion Background
Pipe Information 13020706
Color Orange / Yellow
Diameter 4”
SDR -
Resin PE
Manufacturer Plexco
Design Pressure 60psig
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 95 psig for 2 hours
Timeline
Placed in Service December 1989
Installation Method Bored
Removed from Service February 2007
Comments 44” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 169
Visual Examination
Cold fusion occurred over at least 50% of the fusion surface resulting in an inadequate bond.
The bead shows inconsistent rollover. Using Figure 184 as a reference, the beads within the
green box exhibited proper bead rollover. The beads within the black boxes did not roll over
completely. The discrepancy of the beads indicates a problem with heat/time/pressure during the
fusion process.
Figure 184. Fusion Faces
Title: DTPH56-06-T-0004 Final Report Page 170
Butt Fusion - #45020551
Figure 185. As Received 6” Butt Fusion
Table 47. Poly Valve Butt Fusion Background
Pipe Information 45020551
Color Yellow
Diameter 6”
SDR 11.5 (pipe); 11 (valve)
Resin PE 2406 (pipe and valve)
Manufacturer Uponor (pipe) ; Nordstrom (valve)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service 2000
Installation Method -
Removed from Service August 2005
Comments 60” depth of cover; Was exposed in 14’ hole when
dirt bank caved
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 171
Visual Examination
There does not appear to be any misalignment of the faces. Rollback looks even internally
and externally. The fusion faces appeared to have about 80% cold fusion, shown in red in Figure
186. The fused portion occurred about 180° around the ID and on about 120° (6-10 o’clock) of
the OD as seen on the valve side. The pipe surface has been grit blasted by gas flow.
Figure 186. Fusion Face, Valve
Title: DTPH56-06-T-0004 Final Report Page 172
Figure 187. Fusion Face, Pipe
Title: DTPH56-06-T-0004 Final Report Page 173
Multiple Fusion Joints - #40020413
Figure 188. As Received
Table 48. Multiple Fusion Joints Background
Pipe Information 40020413
Color Orange
Diameter 3” and 1 - ½”
SDR -
Resin -
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service -
Installation Method -
Removed from Service February 2004
Comments 8” depth of cover; System acquired from apartment
property
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 174
Visual Examination
This sample would require pressure testing to determine the leak location and sectioning to
determine the cause. The entire sample consisted of sloppy workmanship. Poor bead rollover,
parallel misalignment, and burn marks were all visible on the specimen.
Figure 189. Close Up View of Specimen
Title: DTPH56-06-T-0004 Final Report Page 175
Figure 190. Misalignment and Poor Bead Rollover at the Reducing Coupling
Figure 191. Back to Back Couplings
Title: DTPH56-06-T-0004 Final Report Page 176
Socket Couplings
Socket Coupling - #16020611
Figure 192. As Received
Table 49. Socket Fusion Coupling Background
Pipe Information 16020611
Color Orange
Diameter 1”
SDR 11
Resin PE 2306
Manufacturer Conind Mark II (pipe) Unknown (coupling)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service -
Installation Method -
Removed from Service February 2006
Comments 36” depth of cover
Environmental
Soil Type Loam
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 177
Visual Examination
The leak location was marked by the field crew during removal of the section. The marking
was approximately 1” around the circumference of the pipe as seen in Figure 193. The coupling
and pipe were in parallel misalignment to each other. Due to the nature of this sample, the root
cause cannot be determined without sectioning.
Figure 193. Leak Location
Title: DTPH56-06-T-0004 Final Report Page 178
Socket Coupling - #31020649
Figure 194. As Received
Table 50. Coupling Background
Pipe Information 31020649
Color Tan
Diameter 2” (main) 1 – ¼” (service)
SDR -
Resin PE 2306
Manufacturer DuPont Aldyl A(pipe and tee)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig
Timeline
Placed in Service November 1970
Installation Method -
Removed from Service December 2006
Comments 36” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 179
Visual Examination
The sample exhibited poor workmanship though no obvious sign exists for the coupling
leak. Ruler approximation of the “nose” of the tee relative to the edge of the coupling suggested
inappropriate stab depth of the coupling onto the tee. This interior surface showed minimal to no
rollback. The external surface where the leak location was noted showed little and inconsistent
rollback of the companion materials. Further examination by destructive methods could provide
better information.
Figure 195. End View of Pipe
Figure 196. Leak Location as Identified by Utility
Title: DTPH56-06-T-0004 Final Report Page 180
Socket Tees
Socket Tee - #36020713
Figure 197. As Received
Table 51. Socket Tee Background
Pipe Information 36020713
Color Orange
Diameter 1 – ¼” all ways
SDR -
Resin -
Manufacturer RAHN (Canada)
Design Pressure
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service -
Installation Method -
Removed from Service 2007
Comments -
Environmental
Soil Type -
Evidence of 3rd Party Damage -
Title: DTPH56-06-T-0004 Final Report Page 181
Visual Examination
Visually, the melting was improper but in order to determine the leak path and the root
cause, the sample would need to be sectioned.
Figure 198. Leak Location as Identified by Utility
Figure 199. End View on Leak Side
Title: DTPH56-06-T-0004 Final Report Page 182
Socket Tee - #47020565
Figure 200. As Received Socket Tee
Table 52. Socket Tee Background
Pipe Information 47020565
Color Orange
Diameter 4”
SDR 11.5 (pipe)
Resin PE 2306 TR 418 (pipe)
Manufacturer Extron (tee); Plexco (pipe)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 240 minutes
Timeline
Placed in Service May 1973
Installation Method Direct Burial; Bored
Removed from Service December 2005
Comments 48” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 183
Visual Examination
Radial distortion as seen in Figure 201 was observed in the sockets. Misalignment of the
pipes into the sockets was also apparent. This sample was submitted without any indication of
the leak location. A pressure test was performed and determined that gas leaked out of the joint
at the pipe/socket interface. As shown in Figure 202, the leak occurred over 3” of the
circumference in the fusion joint. A close up of this area is shown in Figure 203.
Figure 201. Radial Distortion
Title: DTPH56-06-T-0004 Final Report Page 184
Figure 202. Leak at Pipe/Socket Interface
Figure 203. Close up of Pipe/Socket Interface
Title: DTPH56-06-T-0004 Final Report Page 185
Squeeze-offs
Squeeze-Off - #02020717
Figure 204. Top and Side View of as Received Squeeze-off
Table 53. 4” Single Bar Squeeze-off Background
Pipe Information 02020717
Color Orange
Diameter 4”
SDR 11.5
Resin PE 2306
Manufacturer Conind Mark II 1-12-78 (Grating visible under UV)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 90 psig for 4 hours
Timeline
Placed in Service 1978
Installation Method -
Removed from Service March 2007
Comments 5’ depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 186
Visual Examination
The pipe was squeezed with a single bar squeeze off tool. Visual observations indicated the
pipe was significantly over squeezed above recommended values. The excessive squeeze
resulted in significant amounts of permanent deformation at the squeeze ears and apparent wall
thinning. Large voids, whitening, and cracks were present at the squeeze ears on the inner
surface of the pipe. These can be seen in Figure 205 and Figure 206. An axial slit at one ear was
apparent at the outer surface, as seen in Figure 204, indicating the crack initiated on the inner
surface and grew through the wall to the outer surface.
Figure 205. End View Showing Deformation
Figure 206. Slit as Viewed from Inner Wall
Wall Thinning
from Squeeze Bar
Title: DTPH56-06-T-0004 Final Report Page 187
Squeeze-off - #03020647
Figure 207. Top and Side View of as Received Sample
Table 54. 2” Squeeze-off Background
Pipe Information 03020647
Color Orange
Diameter 2”
SDR -
Resin PE 2306
Manufacturer Driscopipe 6500
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 170 minutes
Timeline
Placed in Service January 1979
Installation Method Direct Burial
Removed from Service November 2006
Comments 48” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 188
Visual Examination
The sample appears to have been squeezed three times within an 8” length of pipe using a
single bar squeeze tool. The deformations were about 3” and 4.5” center to center separation. It
is possible that the squeeze tool was not equipped with stops resulting in excessive plastic
deformation and yielding. Wall thinning, buckling, and dimpling were apparent on the outer wall
as seen in Figure 208. On the inner wall, a yielded region was observed in the axial direction
extending from one squeeze location to another.
Figure 208. Dimpling and Buckling
Figure 209. Two of Three Squeeze Points Visible on the Inner Wall
Title: DTPH56-06-T-0004 Final Report Page 189
Squeeze-off - #05020548
Figure 210. As Received Squeeze-off Sample
Table 55. Squeeze-off Background
Pipe Information 05020548
Color Orange
Diameter 2”
SDR 11
Resin -
Manufacturer Driscopipe
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 120 minutes
Timeline
Placed in Service June 1982
Installation Method Direct Burial
Removed from Service August 2005
Comments 32” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 190
Visual Examination
As with other samples, this pipe exhibited markings of a single bar squeeze off machine. In
the ear region, a square shaped deformation (Figure 211) implied the pipe was not centered in the
squeeze off machine. Observations of the inner wall show a large cavity (Figure 212) and an
axial slit under the square shaped deformation.
Figure 211. Top and Sides of Squeeze Location
Title: DTPH56-06-T-0004 Final Report Page 191
Figure 212. Cavity and Deformation on Inner Wall
Title: DTPH56-06-T-0004 Final Report Page 192
Tap Tees
Tap Tee - #28020502
Figure 213. As Received Tap Tee
Table 56. 1 – ¼” x 1” Tap Tee Background
Pipe Information 28020502
Color Orange
Diameter 1 – ¼” x 1”
SDR -
Resin -
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 50 psig for 15 minutes
Timeline
Placed in Service 1975
Installation Method -
Removed from Service January 2005
Comments 39” depth of cover
Environmental
Soil Type Sand
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 193
Visual Examination
This fusion exhibited a very asymmetric and poorly formed bead. The marked location of
the leak was at a location with a high stress concentration between the pad and the pipe. During
the visual examination no crack or void was seen so a leak test would need to be performed to
verify the leak path. The likely cause for failure is poor workmanship.
Figure 214. Underside of the Pipe and Saddle
Title: DTPH56-06-T-0004 Final Report Page 194
Figure 215. Side View of the Saddle
Figure 216. Leak Location
Title: DTPH56-06-T-0004 Final Report Page 195
Tap Tee - #42020711
Figure 217. As Received Tap Tee
Table 57. 2” x 3/4” Tap Tee Background
Pipe Information 42020711
Color Orange
Diameter 2”
SDR 11
Resin PE 2306
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service March 1976 (tee)
Installation Method -
Removed from Service April 2007
Comments -
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 196
Visual Examination
The sample had inadequate melt and roll over on the backside of the saddle tee where the
leak locations are marked. This sample would require sectioning for further comment.
Figure 218. Backside of Saddle Tee
Title: DTPH56-06-T-0004 Final Report Page 197
Figure 219. Close-up of Backside of Tee
Figure 220. Side of Tee
Title: DTPH56-06-T-0004 Final Report Page 198
Tap Tee - #43020555
Figure 221. As Received Tap Tee
Table 58. 2” x 3/4” Tap Tee Background
Pipe Information 43020555
Color Orange
Diameter 2” x ¾” IPS
SDR -
Resin PE 2306 (pipe)
Manufacturer Plexco (tee); Driscoplex (pipe)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service 1988
Installation Method -
Removed from Service October 2005
Comments 42” depth of cover
Environmental
Soil Type Loam
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 199
Visual Examination
Examination showed cold fusion over about 90% of the fusion area. The fusion face on the
pipe still had visible superficial scratches. These scratches would have been created during
fusion preparation, which points to a lack of heat and fusion during the joining process.
Figure 222. Saddle Face
Figure 223. Pipe Surface
Title: DTPH56-06-T-0004 Final Report Page 200
Tap Tee - #44020539
Figure 224. As Received Tap Tee
Table 59. 1 – ¼” x 1” Tap Tee Background
Pipe Information 44020539
Color Orange
Diameter 1 – ¼” x 1” (tee) 1 - ¼” (pipe)
SDR 10 (pipe)
Resin PE 2306 (tee) TR 418 (pipe)
Manufacturer Plexco (tee) Conind (pipe)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 10 psig for 10 minutes
Timeline
Placed in Service November 1978
Installation Method -
Removed from Service April 2005
Comments 36” depth of cover
Environmental
Soil Type Loam
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 201
Visual Examination
Because no bead was present, inadequate melting due to poor workmanship is suspected as
the primary reason for leaking.
Figure 225. Backside of Tee
Title: DTPH56-06-T-0004 Final Report Page 202
Tap Tee – Socket Fusion - #32020543
Figure 226. As Received Tap Tee
Table 60. 2” x ½” Tap Tee - Socket Fusion Background
Pipe Information 32020543
Color Orange
Diameter 2” IPS x ½” CTS
SDR -
Resin PE 2306
Manufacturer Plexco
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service June 1982
Installation Method -
Removed from Service July 2005
Comments 30” depth of cover; Tee on angle
Environmental
Soil Type Loam
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 203
Visual Examination
Background information provided with the sample included field notes indicating the tee
was on an angle. This likely caused undue stresses on the service pipe which lead to an
unrecoverable bending moment. Signs of ductile overload (Figure 228) and necking of the pipe
wall thickness were present.
Figure 227. Socket of Tee, Side View
Figure 228. Ductile Tearing
Title: DTPH56-06-T-0004 Final Report Page 204
Transition Fitting
Transition Fitting - #18020538
Figure 229. As Received
Table 61. Transition Fitting Background
Pipe Information 18020538
Color Green Coated Steel to Orange PE
Diameter 1 – ¼”
SDR 10
Resin TR 418
Manufacturer --
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig
Timeline
Placed in Service 1988
Installation Method -
Removed from Service April 2005
Comments 38” depth of cover; Improper padding
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 205
Visual Examination
The sample suffered excessive bending between the pipe and the stab fitting likely due to
improper support on the underside of the pipe based on the field report.
Figure 230. Side and Bottom View of Transition
Title: DTPH56-06-T-0004 Final Report Page 206
Quality Control Problems
3” Elbow - #675540
Figure 231. As Received Sample - 3” Elbow
Table 62. 3” Elbow Background
Pipe Information 675540
Diameter 3”
SDR 11.5
Resin PE 2306
Manufacturer DuPont
Design Pressure 60psig
Service Information
Operating Pressure 35 psig at 60°F / 10psig at 0°F
Service Temperature 60°F
Comments NA
Timeline
Placed in Service 1970
Installation Method Direct Lay
Removed from Service December 2007
Comments NA
Environmental
Soil Type Rocky, sandy and silty
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 207
Visual Examination
The submitted section was subjected to visual examination. The results of this examination
indicated the presence of a circumferential slit in the injection molded elbow. The section was
capped, pressurized, and subjected to leak testing using soap solution. Leaking occurred at the
slit as seen in Figure 232. Next, the section was cut longitudinally (Figure 233) to examine the
exposed inner surface. Radial distortion of the elbow and pipe were noted. A gap was detected
in the socket fusion area at the pipe/elbow interface as identified in Figure 234 and Figure 235.
The area was moderately flexed by hand and movement of the joint was observed and
photographed.
The section containing the leak path was cooled with liquid nitrogen and force fractured to
expose the associated surfaces as seen in Figure 237 through Figure 242. Examination of the
surface confirmed the earlier observed area of significantly poor fusion. At higher magnification
areas of banding (Figure 239) and ductile failure regions were observed as well as debris
deposited by the gas leak. Closer scrutiny indicated the presence of dark spots imbedded in the
fracture surfaces as seen in Figure 243 and Figure 244.
Figure 232. Leak Location As Identified By a Soap Solution
Title: DTPH56-06-T-0004 Final Report Page 208
Figure 233. Cut Sample to Expose Inner Wall
Figure 234. Portion of Elbow Containing Leak
Lack of
Fusion
Distortion of
Elbow and Pipe
Title: DTPH56-06-T-0004 Final Report Page 209
Figure 235. Inner Fusion Interface with Area of Observed Lack of Fusion
Figure 236. Fusion Interface
Lack of
Fusion
Pipe
Elbow
Elbow
Pipe Wall
Title: DTPH56-06-T-0004 Final Report Page 210
Figure 237. Force Fracture of the Sample, Showing Area of Observed Lack of Fusion
Figure 238. Fractured Sample with the Elbow Side, Top, and Pipe Side, Bottom.
Title: DTPH56-06-T-0004 Final Report Page 211
Figure 239. Close up of the Fracture Faces with the Elbow Side on the Right
Figure 240. Fracture Face on the Elbow Side. Ductile Failure Region
Fracture
undercut
Banding
Title: DTPH56-06-T-0004 Final Report Page 212
Figure 241. Close up of the Fracture Face on the Pipe Side
Figure 242. Fracture Face on the Pipe Side with an Area of Interest Identified
Title: DTPH56-06-T-0004 Final Report Page 213
Figure 243. Microscopy - Fracture Face of Elbow – Toward the Elbow Side
Figure 244. Microscopy – Fracture Face of Elbow – Toward the Pipe Side
Density
The skeletal density of the pipe was determined to be 0.940g/cc using the helium
pycnometer. This was consistent with medium density polyethylene gas pipe material from the
time period sample #675540 was manufactured.
The skeletal density of the elbow was determined to be 0.948g/cc using the helium
pycnometer. The density was a little higher than the pipe which is an attribute of the
manufacturing process as the part was molded rather than extruded. This was consistent with
medium density polyethylene material.
Title: DTPH56-06-T-0004 Final Report Page 214
Melt Flow
Portions of the pipe and elbow sections were prepared and subjected to ASTM D1238 melt
flow testing.
Table 63: Melt Flow Measurements - Pipe
Sample ID Trial # Rate (g/10min)
675540-001a 1 1.0722
675540-001a 2 0.9900
675540-001a 3 1.1172
Average 1.0598±0.0645
Table 64: Melt Flow Measurements - Elbow
Sample ID Trial # Rate (g/10min)
675540-001b 1 1.2980
675540-001b 2 1.1580
675540-001b 3 1.1600
Average 0.2053±0.0803
These results were consistent with medium density polyethylene gas pipe material.
Thermal Analysis- Pipe Wall
Specimens were prepared from the pipe section and subjected to ASTM D3418 differential
scanning calorimetry. The resulting thermograms indicated a heat of fusion of 160J/g as shown
in Figure 245. No additional melting or exotherms were detected which would have suggested
the presence of contamination. In addition, ASTM D3895 was performed on the prepared
specimen and indicated an oxidative-induction time of 42.8 minutes as seen in Figure 246. This
was consistent with the age of the PE considering it has absorbed organic materials from the gas
supply over time. Many of these organic compounds are relatively easily oxidized when
compared to PE.
Thermal Analysis - Elbow
Specimens were prepared from the elbow and subjected to ASTM D3418 differential
scanning calorimetry. The resulting thermograms indicated a heat of fusion of 190.5J/g as
shown in Figure 247. No additional melting or exotherms were detected which would have
suggested the presence of contamination. In addition, ASTM D3895 was performed on the
prepared specimen and indicated an oxidative-induction time of 40.37 minutes as shown in
Figure 248. This was consistent with the age of the PE considering it has absorbed organic
materials from the gas supply over time. Many of these organic compounds are relatively easily
oxidized when compared to PE.
Title: DTPH56-06-T-0004 Final Report Page 215
Figure 245. Differential Scanning Calorimetry – Pipe
Figure 246. Oxidative Induction Time – Pipe
Title: DTPH56-06-T-0004 Final Report Page 216
Figure 247. Differential Scanning Calorimetry - Elbow
Figure 248. Oxidative Induction Time - Elbow
Title: DTPH56-06-T-0004 Final Report Page 217
Infrared Analysis
A comprehensive infrared analysis was performed to determine the condition of the pipe and
elbow and to detect the presence of any organic materials not associated with the respective
material. The resulting spectra failed to indicate the presence of foreign organic materials in the
pipe wall or elbow within the detectability of the instrument. The 1650cm-1 to1750cm-1 region
of the resulting spectra was also examined. Absorbencies in this region are associated with
polyethylene oxidative products. Weak absorbencies were observed in this region that indicated
minimal oxidation had occurred and suggested that the pipe was manufactured and stored
acceptably prior to installation.
Figure 249. FT-IR Outer Wall – Pipe
Title: DTPH56-06-T-0004 Final Report Page 218

Figure 250. FT-IR Middle Wall – Pipe
Figure 251. FT-IR Inner Wall – Pipe
Title: DTPH56-06-T-0004 Final Report Page 219
Figure 252. FT-IR - Outer Wall - Elbow
Figure 253. FT-IR - Middle Wall - Elbow
Title: DTPH56-06-T-0004 Final Report Page 220
Figure 254. FT-IR - Inner Wall - Elbow
Conclusions
Based on the tests performed it was concluded that:
1) There was a significant area of poor fusion that contributed to the failure.
2) There were particles imbedded in the fracture surface of the elbow indicating that
this material entered during the molding of the part that contributed to the failure.
3) The elbow and companion pipe exhibited radial distortion which indicated
significant radial stress was present. This stress resulted from the interference fit
between the elbow and pipe causing expansion of the elbow and resulted in peak
stress concentration at the pipe edge/elbow interface. This elevated stress state aided
the formation and propagation of the fracture.
Title: DTPH56-06-T-0004 Final Report Page 221
¾” Valve – #642535
Figure 255. As Received Sample Shown Leaking from Under the Cap
Table 65. ¾” Valve Background
Pipe Information 642535
Diameter ¾”
SDR 11
Resin PE 2306
Manufacturer DuPont (05-80)
Design Pressure 60psig
Service Information
Operating Pressure 60 psig at 65°F / 45 psig at 0°F
Service Temperature 60°F
Comments NA
Timeline
Placed in Service September 1980
Installation Method Direct Lay
Removed from Service October 2007
Comments NA
Environmental
Soil Type Rocky, sandy and silty
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 222
Visual Examination
Soap solution testing showed the leak originating from the underside of the valve as seen in
Figure 255 and Figure 256. The entire valve was transversely sectioned and examined. The
results of this examination did not detect any damage to the core, seal, or housing. As shown in
Figure 257 and Figure 258. The examination focus was on the lower half of the valve. The
position of the valve core was indexed relative to the housing using a series of markings shown
in Figure 259. The valve was placed into a fixture and using appropriately sized tools, the core
was carefully displaced from the valve body as shown in Figure 260. There were two o-rings on
the core section. There was a noticeable loss of material observed on the bottom o-ring and a
piece of rubber was observed wedged between the upper o-ring and its companion groove. These
damaged areas can be seen in Figure 261, Figure 262, and, Figure 263. Upon removal the piece
of rubber was found to match well with the damaged area of the bottom o-ring as demonstrated
in Figure 264 and Figure 265. Lubricant was observed on all surfaces which is consistent with
the fact that the o-rings are typically lubricated prior to assembly.
Figure 256. Valve with Leak Pinpointed
Title: DTPH56-06-T-0004 Final Report Page 223
Figure 257. Valve Was Halved to Help Expose O-Ring
Figure 258. Close up of the Core and Seal
Title: DTPH56-06-T-0004 Final Report Page 224
Figure 259. Valve Core with Indexing Marks
Figure 260. Valve Core Removed from Housing
Title: DTPH56-06-T-0004 Final Report Page 225
Figure 261. Valve Core. Lower O-Ring Bottom
Figure 262. O-Ring Damage. Upper O-Ring, Foreground. Lower O-Ring, Background.
Title: DTPH56-06-T-0004 Final Report Page 226
Figure 263. Imbedded Fragment Between Upper O-Ring and Core Land.
Figure 264. O-Ring Fragment Removed from the Upper O-ring Land Area.
Title: DTPH56-06-T-0004 Final Report Page 227
Figure 265. Higher Magnification of Figure 264
Infrared Analysis and Hardness Testing
Portions of the upper and lower o-ring rings were removed, cleaned, and subjected to
infrared analysis. Both of the resulting spectra correlated well with absorbencies indicative of
nitrile rubber. See Figure 266 and Figure 267. Subsequent hardness testing indicated that the
material was 71-74 Shore A.
Figure 266. FT-IR - Lower O-Ring Nitrile Rubber
Title: DTPH56-06-T-0004 Final Report Page 228
Figure 267. FT-IR - Upper O-Ring Nitrile Rubber
Conclusions
Based on the tests performed it was concluded that:
1) The cause of the leak was damage to the lower o-ring during assembly, which
resulted in a section of rubber breaking off from the o-ring. In time, this rubber
section migrated to and wedged itself between the upper o-ring and its groove. Both
conditions reduced the sealing effectiveness of the o-rings.
2) Both o-rings were manufactured from nitrile rubber. Nitrile rubber is commonly
used in natural gas systems. Hardness testing indicated Shore hardness of up to 74A.
Typically as these materials age they become harder and their sealing effectiveness
decreases. When the o-rings were new, they were still able to seal despite the
observed damage. As the o-rings aged, they were no longer effective in maintaining
a good seal.
Title: DTPH56-06-T-0004 Final Report Page 229
Miscellaneous Problems
Charred Pipe – #01020436
Figure 268. As Received
Table 66. Charred ¾” Pipe Background
Pipe Information 010204336
Color Yellow
Diameter ¾”
SDR 11
Resin PE 2406
Manufacturer Driscoplex 6500
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service 2004
Installation Method Bored
Removed from Service February 2004
Comments 48” depth of cover
Environmental
Soil Type Loam
Evidence of 3rd Party Damage No; In close proximity to electric cables
Title: DTPH56-06-T-0004 Final Report Page 230
Visual Examination
This pipe section was exposed to excessive heating from a shorted electric cable. The pipe
was installed by boring and may have caused the damage to the electric cable insulation.
Figure 269. Up Close View of Damaged Pipe Section
Title: DTPH56-06-T-0004 Final Report Page 231
Tap Tee – #642909
Figure 270. As Received Sample of a Leaking Tee
Figure 271. Circumferential Slit on the Backside of the Tee
Title: DTPH56-06-T-0004 Final Report Page 232
Table 67. 1 - Tap Tee Background
Pipe Information 642909
Diameter 1 – ¼”
SDR 10
Resin PE 2306
Manufacturer DuPont (1-82)
Design Pressure 60psig
Service Information
Operating Pressure 60 psig at 65°F / 50 psig at 0°F
Service Temperature 60°F
Comments NA
Timeline
Placed in Service Main in 1982; Service in 1983
Installation Method Direct Lay
Removed from Service December 2007
Comments NA
Environmental
Soil Type Rocky, sandy and silty
Evidence of 3rd Party Damage Yes
Visual Examination
The results of this examination indicated that the pipe segment section was permanently
deformed 90 degrees from the saddle fused service tee. On the back side of the tee, away from
the service outlet, a fracture in the pipe was observed as seen in Figure 271. Also in this area
immediately adjacent to the fracture, the saddle fusion appeared to have minimal roll back on
this side of the tee. The opposite side of the tee exhibited a double bead and significantly more
material roll back than the side immediately adjacent to the observed fracture.
The pipe segment was cut longitudinally approximately 180 degrees from the service tee.
The area of interest was then carefully cut further aiding exposure of the fracture surfaces of the
observed crack as shown in Figure 272 through Figure 274. After opening the fracture, the
saddle fused service tee exhibited a large area of poor adhesion to the pipe as seen in Figure 275.
Visual examination (Figure 276 and Figure 277) and higher magnification examination (Figure
278 and Figure 279) using a stereo optical microscope indicated that the fracture surfaces were
white and exhibited characteristics consistent with ductile failure of the pipe wall.
Title: DTPH56-06-T-0004 Final Report Page 233
Figure 272. Pipe Was Cut Away to Reveal the Inner Pipe Wall
Figure 273. Damage on the Inner Wall
Title: DTPH56-06-T-0004 Final Report Page 234
Figure 274. Damage on the Inner Wall
Figure 275. Tee Separated from Pipe during Force Fracture
Title: DTPH56-06-T-0004 Final Report Page 235
Figure 276. Fracture Face on the Pipe No Longer Attached to the Tee
Figure 277. Opposing Fracture Face
Title: DTPH56-06-T-0004 Final Report Page 236
Figure 278. Fracture Face Microscopy on the Pipe No Longer Attached to the Tee
Figure 279. Opposing Fracture Face Microscopy
Title: DTPH56-06-T-0004 Final Report Page 237
Density
The skeletal density of the pipe was determined to be 0.939g/cc using the helium
pycnometer. This was consistent with medium density polyethylene gas pipe material from the
time period sample 642909 was manufactured.
Melt Flow
Sections of the pipe were prepared and subjected to ASTM D1238 melt flow testing.
Table 68: Melt Flow Measurements
Sample ID Trial # Rate (g/10min)
642909-001 1 1.0246
642909-001 2 1.1580
642909-001 3 1.1660
Average 1.1162±0.0794
These results were consistent with medium density polyethylene gas pipe material.
Thermal Analysis
Specimens were prepared from the pipe section and subjected to ASTM D3418 differential
scanning calorimetry. The resulting thermograms, seen in Figure 280, indicated a heat of fusion
of 171.2J/g and no additional melting or exotherms were detected which would have suggested
the presence of contamination. In addition, ASTM D3895 was performed on the prepared
specimen and indicated an oxidative-induction time of 51.7 minutes as shown in Figure 281.
This was consistent with the age of the PE considering it has absorbed organic materials from the
gas supply over time. These organic compounds are relatively easily oxidized when compared to
PE.
Title: DTPH56-06-T-0004 Final Report Page 238
Figure 280. Differential Scanning Calorimetry
Figure 281. Oxidative Induction Time
Title: DTPH56-06-T-0004 Final Report Page 239
Infrared Analysis
A comprehensive infrared analysis was performed to determine the condition of the pipe as
it detects the presence of any organic materials not associated with the pipe material. The results
did not indicate the presence of any foreign organic materials in the outer middle or inner pipe
wall within the detectability of the instrument. Weak absorbencies detected in the 1650cm-1
to1750cm-1 region of the spectra suggested minor oxidation of the pipe material had occurred.
Figure 282. FT-IR - Outer Wall
Title: DTPH56-06-T-0004 Final Report Page 240
Figure 283. FT-IR - Middle Wall
Figure 284. FT-IR - Inner Wall
Title: DTPH56-06-T-0004 Final Report Page 241
Conclusions
Based on the tests performed, it was concluded that:
1) The saddle fusion surface tee exhibited a large area that was not properly fused. A
good fusion would be stronger than the pipe wall itself and would result in tearing of
the pipe wall before separation of the fusion.
2) The pipe segment was significantly deformed. The deformation was consistent with
significantly high loads, possibly from digging equipment.
3) Examination of the fractured surfaces indicated ductile overload of the pipe wall
material. No smaller fracture characteristics were observed which would have
indicated a pre-existing crack prior to the ductile overload.
4) Excavation damage is the most likely the cause of failure.
Title: DTPH56-06-T-0004 Final Report Page 242
Electrofusion Tee – #642430
Figure 285. As Received Sample
Figure 286. Brittle Plastic Seepage from the Tee
Title: DTPH56-06-T-0004 Final Report Page 243
Table 69. 4” x 4” Electrofusion Tee Background
Pipe Information 642430
Diameter 4”
SDR 11.5
Resin PE 2306 or PE 2406
Manufacturer DuPont
Design Pressure 60psig
Service Information
Operating Pressure ~55 psig in summer / ~19 psig in winter
Service Temperature 60°F
Comments NA
Timeline
Placed in Service November 1984
Installation Method Direct Lay
Removed from Service October 2007
Comments Failed EF procedure
Environmental
Soil Type Rocky, sandy and silty
Evidence of 3rd Party Damage No
Visual Examination
The pipe segment containing the electrofused saddle tee (Figure 285) was subjected to visual
examination using the naked eye as well as high powered stereo optical microscopy. Results of
this examination indicated a solidified area of material between the saddle fusion tee and the pipe
that had seeped from the tee-pipe interface as seen in Figure 286.
Thermal Analysis
Specimens were prepared from the pipe section and companion electrofused tee as well as
the seepage material and subjected to ASTM D3895. The resulting thermograms indicated
oxidative induction times (OITs) of 27, 70, and 14 minutes for the pipe, tee, and seepage material
respectively. See Figure 287, Figure 288, and Figure 289. The OIT of 27 minutes for the pipe
material was considered on the low side of normal for an in service pipe. The OIT of 70 minutes
for the tee material was considered normal. The OIT of 14 minutes for the seepage material was
significantly low and suggested significant material degradation.
In addition, ASTM D3418 differential scanning calorimetry was performed on a set of
specimens. The resulting thermograms (Figure 290, Figure 291, and Figure 292) indicated heats
of fusion of 181J/g, 172 J/g, 232J/g for the pipe, tee, and seepage material respectively. No
additional melting or exotherms were detected which would have suggested the presence of
contamination. The significantly higher heat of fusion for the seepage material suggested
material densification as the result of degradation and/or relatively slow cooling rate of the
material.
Title: DTPH56-06-T-0004 Final Report Page 244
Figure 287. Oxidative Induction Time - Pipe
Figure 288. Oxidative Induction Time - Tee
Title: DTPH56-06-T-0004 Final Report Page 245
Figure 289. Oxidative Induction Time - Seepage Material
Figure 290. Differential Scanning Calorimetry – Pipe
Title: DTPH56-06-T-0004 Final Report Page 246
Figure 291. Differential Scanning Calorimetry – Tee
Figure 292. Differential Scanning Calorimetry – Seepage Material
Title: DTPH56-06-T-0004 Final Report Page 247
Infrared Analysis
A comprehensive infrared analysis was performed to determine the condition of the pipe,
tee, and seepage material and to detect the presence of any organic compounds not associated
with the respective materials. The results did not indicate the presence of any foreign organic
compounds in the material specimens. There were no detectable oxidation absorbencies in the
pipe or tee material as shown in Figure 293 and Figure 294, respectively. An absorbance was
detected at 1718cm-1of the seepage material spectrum characteristic of a ketone compound
consistent with oxidation products of polyethylene. The absorbance peak is noted in Figure 295.
The peak height was measured and compared against the 1460cm-1 peak of the spectrum. The
resulting quotient was 0.17 (carbonyl index, CI). Typical CI for non-aged samples is 0.01-0.05.
Figure 293. FT-IR Spectrum – Pipe Material
Title: DTPH56-06-T-0004 Final Report Page 248
Figure 294. FT-IR Spectrum – Tee Material
Figure 295. FT-IR Spectrum – Seepage Material: Note ketone absorbance
Title: DTPH56-06-T-0004 Final Report Page 249
Conclusions
Based on the tests performed, it was concluded that:
1) The electrofusion saddle generated enough heat to degrade the pipe and tee material
at the fusion interface. This degradation was detected by both DSC-OIT and FT-IR.
The degradation was severe enough to cause a significant localized melt viscosity
reduction or thinning of the material, facilitating the observed seepage. The effects of
this degradation on the fusion longevity could not be determined and would require a
more in depth study.
2) Some potential causes include equipment malfunction and/or electrofusion
programming error(s).
Title: DTPH56-06-T-0004 Final Report Page 250
Material / Quality
Compression Fitting - #17020701
Figure 296. As Received Fitting
Table 70. 1 – ¼” Amp Fitting Background
Pipe Information 17020701
Color Orange
Diameter 1 – ¼”
SDR -
Resin PE 2306
Manufacturer -
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 2 hours
Timeline
Placed in Service June 1977
Installation Method Direct Burial; Bored
Removed from Service January 2007
Comments 14” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 251
Visual Examination
The fitting exhibited a slit failure at the mold seam/knit line as shown up close in Figure
297. All surfaces of the fitting show crazing.
Figure 297. Slit at Knit Line
Title: DTPH56-06-T-0004 Final Report Page 252
Procedural / Material
Mechanical Fitting - #41020409
Figure 298. As Received Sample
Table 71. 1 – ¼” x 1” Fitting Background
Pipe Information 41020409
Color Yellow/White
Diameter 1 – ¼” x 1”
SDR -
Resin -
Manufacturer AMP
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments -
Timeline
Placed in Service -
Installation Method -
Removed from Service February 2004
Comments -
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 253
Visual Examination
The AMP fitting exhibited a partial pullout. The actual cause cannot be determined without
dissecting the fitting.
Figure 299. Close up View of AMP Fitting
Title: DTPH56-06-T-0004 Final Report Page 254
Tap Tee - #27020640
Figure 300. As Received Sample
Table 72. Tap Tee Background
Pipe Information 27020640
Color Orange
Diameter 2” (main) 1 – ¼” (service)
SDR 11
Resin PE 2306
Manufacturer Driscopipe 6500 (main) Plexco (tee)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 15 minutes
Timeline
Placed in Service July 1983
Installation Method -
Removed from Service October 2006
Comments 48” depth of cover
Environmental
Soil Type Clay
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 255
Visual Examination
A circumferential gap/crack was located between the ID of the socket and the OD of the
pipe. The area containing the crack had less rollback than the remaining socket surface. Root
cause determination would require sectioning of the fusion joint though poor workmanship is
probable.
Figure 301. Socket Joint
Figure 302. Area Identified as Leaking
Title: DTPH56-06-T-0004 Final Report Page 256
Bolt-on Tap Tee - #14020742
Figure 303. As Received Tee
Table 73. Bolt-on Tap Tee Background
Pipe Information 14020742
Color Orange
Diameter 2”
SDR 11
Resin PE 2306
Manufacturer Driscopipe (pipe) Amp (fitting)
Design Pressure -
Service Information
Operating Pressure 1-60 psig
Service Temperature 60°F
Comments Pressure tested at 100 psig for 15 minutes
Timeline
Placed in Service July 1979
Installation Method -
Removed from Service December 2007
Comments 24” depth of cover
Environmental
Soil Type Gravel
Evidence of 3rd Party Damage No
Title: DTPH56-06-T-0004 Final Report Page 257
Visual Examination
Leak markings were indicated on both sides of the fitting. The inner surface of the pipe did
not show signs of cracking which would suggest that the leak was caused by the service tee seal.
A definitive cause would require fitting disassembly.
Figure 304. Side View of Mechanical Tee
Title: DTPH56-06-T-0004 Final Report Page 258
Root Cause Failure Results
Fifty-five samples were analyzed over the course of the project. Of these, 22 were classified
as material failures, 24 as procedural failures/poor workmanship, 2 as quality control problems, 3
miscellaneous failures, and 4 were not classified. These results combined with a previous
database account for 104 samples of which, 45 were classified as material failures, 36 as
procedural failures, 12 as quality control problems, 7 miscellaneous failures, and 4 were not
classified. These results have been placed into the following tables: Table 74. Material Failures,
Table 75. Procedural Failures, Table 76. Quality Control Failures, Table 77. Miscellaneous
Failures, and Table 78. Other Failures.
Table 74. Material Failures
Specimen
Number
Description Material Pipe Size Nature of Failure
FͲ83025Bending/earth
settlement
PE2306 2”IPSSDR11 Circumferentialslit
FͲ84014ButtJointPE2306 2”IPSSDR11 Jointmisalignment
20020447Cap Ͳ 2”x¾”ServiceTee
Circumferentialcrack
withinthreads
21020739Cap Ͳ Ͳ
Circumferentialcrack
withinthreads
22020733Cap Ͳ Ͳ
Circumferentialcrack
withinthreads
23020464Cap Ͳ Ͳ
Circumferentialcrack
withinthreads
24020499Cap Ͳ Ͳ
Circumferentialcrack
withinthreads
25020718Cap Ͳ 2"
Circumferentialcrack
withinthreads
31020650Cap Ͳ 3x1Ͳ ¼”Tee
49020718Cap Ͳ Ͳ
Circumferentialcrack
withinthreads
50020726Cap Ͳ Ͳ
Circumferentialcrack
withinthreads
26020806ExternalLoadingPE2306 4" AxialSlit
00590ImpingementPE2306 4" AxialSlit
602533ImpingementPE2306 4" AxialSlit
04020731ImpingementPE2306 2" AxialSlit
FͲ82006InsertRenewalPE2306 1Ͳ3/8”OD,.090”wall AxialSlits
FͲ84005InternalPressurePE2306 ½”IPSSDR11 Axialruptureinpipewall
FͲ81001RockImpingementPE2306 2”IPSSDR11 AxialSlits
FͲ81002RockImpingementPE2306 2”IPSSDR11 AxialSlits
FͲ81003RockImpingementPE2306 2”IPSSDR11 AxialSlits
FͲ81004RockImpingementPE2306 2”IPSSDR11 AxialSlits
N/ARockImpingementPE2306 2”HDPE ThroughͲwallcrack
FͲ84009SaddleJointPE2306 2”IPSx½”Circumferentialcrack
throughpipe
FͲ84011SaddleJointPE2306 3”IPSx½” Axialcrackthroughpipe
FͲ85010SaddleJointPE2306 4”IPSSDR11 Circumferentialcrack
throughpipe
Title: DTPH56-06-T-0004 Final Report Page 259
FͲ86002SaddleJointPE2306 2”IPSSDR11 Inadequatefusion
FͲ86003SaddleJointHDPE 3”IPSSDR11 Circumferentialslitfailure
atedgeofsaddlefusion
15020650ServiceTeeThreadsPE23062x1Ͳ¼”Tee
Circumferentialcrack
withinthreads
29020510ServiceTeeThreads Ͳ2"
Circumferentialcrack
withinthreads
30020542SocketCoupling Ͳ2"
Circumferentialcrack
throughcoupling
35020485SocketCouplingPE2306 1"SocketFusion CircumferentialSlit
39020603SocketCouplingPE2306 2"SDR11 CircumferentialSlit
FͲ81011SocketJointPE2306 2”IPSSDR11 Circumferentialcrack
throughpipewall
FͲ84012SocketJointPE2306 ½”CTS Circumferentialcracks
throughpipe
FͲ84018SocketJointPE2306 2”IPSSDR11 Socketmisalignment
19020414SocketTeePE2306 4"3WayCircumferentialSlit
33020602SocketTeePE2306 2"SDR11.5 CircumferentialSlit
34020623SocketTeePE2306 2"CircumferentialSlit
FͲ81005SqueezeͲoffPE2306 2”IPSSDR11 AxialSlits
FͲ83019SqueezeͲoffPE2306 2”IPSSDR11 AxialSlits
FͲ83023SqueezeͲoffPE2306 3”IPSSDR11 AxialSlits
678156TapTeePE2306 2" CircumferentialSlit
FͲ84013TappingTeePE2306 6”SDR17w/tapping
tee
Axialstress
FͲ81006TappingTeeCapPE2306 N/A Circumferentialcrack
withinthreads
FͲ84003TeePE2306 2”IPSSDR112x2x2
Tee
Circumferentialcrack
throughfitting

Title: DTPH56-06-T-0004 Final Report Page 260
Table 75. Procedural Failures
Specimen
Number
Description Material Pipe Size Nature of Failures
07020714ButtFusionPE2306 4"SDR11.5 Misalignment
08020601ButtFusionPE2306 3"SDR11.5 Lackofbond
09020552ButtFusionPE2306 2" IrregularFusionBead
10020477ButtFusionPE2306 4"SDR11 Lackofbond
11020541ButtFusionPE2406 4"SDR11.5 Foreignbody
12020550ButtFusionPE2306 4" IrregularFusionBead
13020706ButtFusionPE2306 4" Lackofbond
45020551ButtFusionPE2406
6"SDR11.5(pipe)11
(valve)
Lackofbond
060204100ButtFusionPE2306 2" Overload
FͲ80004ButtjointPE2306 4“IPSSDR11Lackofbond
FͲ80005ButtjointPE3406 6“IPSLackofbond
FͲ85001ButtjointPE2306 3“IPSSDR11Inadequatefusion
FͲ89005ButtjointPE2406 2“IPSSDR11FailedduringplowͲin
N/AButtjointHDPE 8“SDR11HDPEInadequatefusion
FͲ84008EllfittingPE2306 2“IPSSDR11Lackofbondin90°Ell due
tomisalignment
00632HighVolume
TappingTee Ͳ4"x2"
Inadequatefusion
N/AImpactonaboltPE3408 1–¼”DR11HDPEThroughͲwallcrack
40020413
MultipleFusion
Joints Ͳ3”and1Ͳ½”Poorworkmanship
FͲ90013SaddlejointPE2306 2“IPSSDR11 Poorfusionpractice
16020611SocketCouplingPE2306 1"SDR11 Poorworkmanship
31020649SocketCouplingPE2306 2x1Ͳ ¼”Tee Poorworkmanship
FͲ84006SocketjointPE2306 4“IPSSDR11Lackofbondinfusionjoint
36020713SocketTee Ͳ1–¼”Poorworkmanship
47020565SocketTeePE2306,TR418 4"SDR11.5 Poorworkmanship
02020717SqueezeͲoffPE2306 4"SDR11.5 Oversqueezed
03020647SqueezeͲoffPE2306 2" Oversqueezed
05020548SqueezeͲoffPE2306 2"SDR11 Misalignedinmachine
28020502TapTee Ͳ1–¼”x1” Poorworkmanship
42020711TapTeePE2306 2x3/4”SDR11 Poorworkmanship
43020555TapTeePE2306 2”x¾”IPS Lackofbond
44020539TapTee
PE2306(tee)TR
418(pipe)
1–¼”x1”(tee)1Ͳ ¼”
SDR10(pipe)Poorworkmanship
32020543
TapTeeͲSocket
FusionPE23062”IPSx½”CTSOverload
FͲ86001TappingteePE2306 2x5/8“tappingteeInadequatejoint
N/ATappingteePE2306 1–¼”w/½”tapping
tee
Longitudinalcracks
18020538TransitionFittingTR418 1–¼”SDR11 BendingStress
FͲ90005TransitionfittingPE2306 4“IPSSDR11.5SCGdrivenby
misalignmentorexternal
bending
Title: DTPH56-06-T-0004 Final Report Page 261
Table 76. Quality Control Failures
Specimen
Number
Description Material Pipe Size Nature of Failures
642535¾”ValvePE2306 ¾”DamagedOͲring
6755403”ElbowPE2306 3" Circumferentialcrack
N/ACharredPEmass
insidepipe
3”MDPE Internalobstruction
FͲ82001Dimensional
tolerance
PE2306 4”IPSSDR11.5 OutͲofͲroundness
FͲ80008MeltirregularitiesPE3408 3”IPS SDR11 Irregularfusionbead
FͲ84001MicroscopicdefectsPE2306 5/8”CTS Pinholes
N/AMoldweldͲline
cracking
PE2306 6”IPSAldyltee Crackingthroughcrotch
FͲ87003Qualitycontrol:
manufacturing
defect
PE3406 2”IPSSDR11 Inclusionextending
throughpipewall
N/ASaddlejointPE3408 4”,6” Inadequatefusion
FͲ82004VisibledefectsPE2306 2”IPSSDR11 Thinspots
062994Ͳ1Weaklapdueto
polyamidefilm
PE3408 4”SDR11 Axialcrack
092394Ͳ1Weaklapdueto
polyamidefilm
PE3408 4”SDR11 Axialcrack

Table 77. Miscellaneous Failures
Specimen
Number
Description Material Pipe Size Nature of Failures
01020436CharredPipePE2406 ¾”Overheatingofmaterial
642909TapTeePE2306 1–¼”Lackofbond/Overload
642430ElectrofusionTeePE2306 4”x4”Overheatingofmaterial
FͲ90010MeltedpipePE2306 4”IPS Overheatedelectriclight
cablelayingonpipe
N/APipeatcompressor
station
PE3408 2” Axialcrack
N/APipeatcompressor
station
PE3408 2” Axialcrack
N/APlowedͲinpipePhilips6500 2”SDR11MDPE Circumferentialcrack
Table 78. Other Failures
Type of Failure Specimen
Number
Description Material Pipe Size Nature of Failures
Material/Quality17020701MechanicalCoupling PE2306 1–¼”SlitFailure
Procedural/Material41020409MechanicalFitting Ͳ 1–¼”x1”Pullout
Procedural/Material27020640TapTee PE2306 2x¼”TeeIrregularFusionBead
Procedural/Material14020742BoltͲonTapTee PE2306 2"SDR11 
Title: DTPH56-06-T-0004 Final Report Page 262
Table 79. All Failures
Type of
Failure
Specimen
Number Description Mat’l Pipe Size Nature of Failure
QualityControl642535¾”ValvePE2306¾”DamagedOͲring
QualityControl6755403”ElbowPE23063"Circumferentialcrack
MaterialFͲ83025Bending/earth
settlementPE23062”IPSSDR11Circumferentialslit
Procedural/
Material14020742BoltͲonTapTeePE23062"SDR11 
Procedural07020714ButtFusionPE23064"SDR11.5Misalignment
Procedural08020601ButtFusionPE23063"SDR11.5Lackofbond
Procedural09020552ButtFusionPE23062"IrregularFusionBead
Procedural10020477ButtFusionPE23064"SDR11Lackofbond
Procedural11020541ButtFusionPE24064"SDR11.5Foreignbody
Procedural12020550ButtFusionPE23064"IrregularFusionBead
Procedural13020706ButtFusionPE23064"Lackofbond
Procedural45020551ButtFusionPE24066"SDR11.5
(pipe)11(valve)Lackofbond
Procedural060204100ButtFusionPE23062"Overload
MaterialFͲ84014ButtJointPE23062”IPSSDR11Jointmisalignment
ProceduralFͲ80004ButtjointPE23064“IPSSDR11Lackofbond
ProceduralFͲ80005ButtjointPE34066“IPSLackofbond
ProceduralFͲ85001ButtjointPE23063“IPSSDR11Inadequatefusion
ProceduralFͲ89005ButtjointPE24062“IPSSDR11FailedduringplowͲin
ProceduralN/AButtjointHDPE8“SDR11HDPEInadequatefusion
Material20020447Cap Ͳ2”x¾”Service
Tee
Circumferentialcrack
withinthreads
Material21020739Cap Ͳ ͲCircumferentialcrack
withinthreads
Material22020733Cap Ͳ ͲCircumferentialcrack
withinthreads
Material23020464Cap Ͳ ͲCircumferentialcrack
withinthreads
Material24020499Cap Ͳ ͲCircumferentialcrack
withinthreads
Material25020718Cap Ͳ2"Circumferentialcrack
withinthreads
Material31020650Cap Ͳ3x1Ͳ¼”Tee
Material49020718Cap Ͳ ͲCircumferentialcrack
withinthreads
Material50020726Cap Ͳ ͲCircumferentialcrack
withinthreads
QualityControlN/ACharredPEmass
insidepipe 3”MDPEInternalobstruction
Miscellaneous01020436CharredPipePE2406¾”Overheatingofmaterial
QualityControlFͲ82001Dimensional
tolerancePE23064”IPSSDR11.5OutͲofͲroundness
Title: DTPH56-06-T-0004 Final Report Page 263
Miscellaneous642430Electrofusion
TeePE23064”x4”Overheatingofmaterial
ProceduralFͲ84008EllfittingPE23062“IPSSDR11Lackofbondin90°Elldue
tomisalignment
Material26020806ExternalLoadingPE23064"AxialSlit
Procedural00632HighVolume
TappingTeeͲ4"x2"Inadequatefusion
ProceduralN/AImpactonaboltPE34081–¼”DR11
HDPEThroughͲwallcrack
Material00590ImpingementPE23064"AxialSlit
Material602533ImpingementPE23064"AxialSlit
Material04020731ImpingementPE23062"AxialSlit
MaterialFͲ82006InsertRenewalPE23061Ͳ3/8”OD,.090”
wallAxialSlits
MaterialFͲ84005InternalPressurePE2306½”IPSSDR11Axialruptureinpipewall
Material/
Quality17020701Mechanical
CouplingPE23061–¼”SlitFailure
Procedural/Ma
terial41020409Mechanical
Fitting 1–¼”x1”Pullout
QualityControlFͲ80008Melt
irregularitiesPE34083”IPSSDR11Irregularfusionbead
MiscellaneousFͲ90010MeltedpipePE23064”IPSOverheatedelectriclight
cablelayingonpipe
QualityControlFͲ84001Microscopic
defectsPE23065/8”CTSPinholes
QualityControlN/AMoldweldͲline
crackingPE23066”IPSAldylteeCrackingthroughcrotch
Procedural40020413MultipleFusion
JointsͲ3”and1Ͳ½”Poorworkmanship
MiscellaneousN/A
Pipeat
compressor
station
PE34082”Axialcrack
MiscellaneousN/A
Pipeat
compressor
station
PE34082”Axialcrack
MiscellaneousN/APlowedͲinpipePhilips65002”SDR11MDPECircumferentialcrack
QualityControlFͲ87003
Qualitycontrol:
manufacturing
defect
PE34062”IPSSDR11Inclusionextending
throughpipewall
MaterialFͲ81001Rock
ImpingementPE23062”IPSSDR11AxialSlits
MaterialFͲ81002Rock
ImpingementPE23062”IPSSDR11AxialSlits
MaterialFͲ81003Rock
ImpingementPE23062”IPSSDR11AxialSlits
MaterialFͲ81004Rock
ImpingementPE23062”IPSSDR11AxialSlits
MaterialN/ARock
ImpingementPE23062”HDPEThroughͲwallcrack
MaterialFͲ84009SaddleJointPE23062”IPSx½”Circumferentialcrack
Title: DTPH56-06-T-0004 Final Report Page 264
throughpipe
MaterialFͲ84011SaddleJointPE23063”IPSx½”Axialcrackthroughpipe
MaterialFͲ85010SaddleJointPE23064”IPSSDR11Circumferentialcrack
throughpipe
MaterialFͲ86002SaddleJointPE23062”IPSSDR11Inadequatefusion
MaterialFͲ86003SaddleJointHDPE3”IPSSDR11Circumferentialslitfailure
atedgeofsaddlefusion
ProceduralFͲ90013SaddlejointPE23062“IPSSDR11Poorfusionpractice
QualityControlN/ASaddlejointPE34084”,6”Inadequatefusion
Material15020650ServiceTee
ThreadsPE23062x1Ͳ¼”TeeCircumferentialcrack
withinthreads
Material29020510ServiceTee
ThreadsͲ2"Circumferentialcrack
withinthreads
Material30020542SocketCoupling Ͳ2"Circumferentialcrack
throughcoupling
Material35020485SocketCouplingPE23061"SocketFusionCircumferentialSlit
Material39020603SocketCouplingPE23062"SDR11CircumferentialSlit
Procedural16020611SocketCouplingPE23061"SDR11Poorworkmanship
Procedural31020649SocketCouplingPE23062x1Ͳ¼”TeePoorworkmanship
MaterialFͲ81011SocketJointPE23062”IPSSDR11Circumferentialcrack
throughpipewall
MaterialFͲ84012SocketJointPE2306½”CTSCircumferentialcracks
throughpipe
MaterialFͲ84018SocketJointPE23062”IPSSDR11Socketmisalignment
ProceduralFͲ84006SocketjointPE23064“IPSSDR11Lackofbondinfusionjoint
Material19020414SocketTeePE23064"3WayCircumferentialSlit
Material33020602SocketTeePE23062"SDR11.5CircumferentialSlit
Material34020623SocketTeePE23062"CircumferentialSlit
Procedural36020713SocketTee Ͳ 1–¼”Poorworkmanship
Procedural47020565SocketTeePE2306,TR
4184"SDR11.5Poorworkmanship
MaterialFͲ81005SqueezeͲoffPE23062”IPSSDR11AxialSlits
MaterialFͲ83019SqueezeͲoffPE23062”IPSSDR11AxialSlits
MaterialFͲ83023SqueezeͲoffPE23063”IPSSDR11AxialSlits
Procedural02020717SqueezeͲoffPE23064"SDR11.5Oversqueezed
Procedural03020647SqueezeͲoffPE23062"Oversqueezed
Procedural05020548SqueezeͲoffPE23062"SDR11Misalignedinmachine
Material678156TapTeePE23062"CircumferentialSlit
Miscellaneous642909TapTeePE23061–¼”Lackofbond/Overload
Procedural28020502TapTee Ͳ 1–¼”x1”Poorworkmanship
Procedural42020711TapTeePE23062x3/4”SDR11Poorworkmanship
Procedural43020555TapTeePE23062”x¾”IPSLackofbond
Procedural44020539TapTee
PE2306
(tee)TR418
(pipe)
1–¼”x1”(tee)
1Ͳ¼”SDR10
(pipe)
Poorworkmanship
Title: DTPH56-06-T-0004 Final Report Page 265
Procedural/Ma
terial27020640TapTeePE23062x¼”TeeIrregularFusionBead
Procedural32020543TapTeeͲSocket
FusionPE23062”IPSx½”CTSOverload
MaterialFͲ84013TappingTeePE23066”SDR17w/
tappingteeAxialstress
ProceduralFͲ86001TappingteePE23062x5/8“tapping
teeInadequatejoint
ProceduralN/ATappingteePE23061–¼”w/½”
tappingteeLongitudinalcracks
MaterialFͲ81006TappingTeeCapPE2306N/ACircumferentialcrack
withinthreads
MaterialFͲ84003TeePE23062”IPSSDR11
2x2x2Tee
Circumferentialcrack
throughfitting
Procedural18020538TransitionFittingTR4181–¼”SDR11BendingStress
ProceduralFͲ90005TransitionfittingPE23064“IPSSDR11.5
SCGdrivenby
misalignmentorexternal
bending
QualityControlFͲ82004VisibledefectsPE23062”IPSSDR11Thinspots
QualityControl062994Ͳ1Weaklapdueto
polyamidefilmPE34084”SDR11Axialcrack
QualityControl092394Ͳ1Weaklapdueto
polyamidefilmPE34084”SDR11Axialcrack
Title: DTPH56-06-T-0004 Final Report Page 266
The samples received by GTI under this project were also incorporated with a previous
database of received field failures. They are included in Table 80. This group of failures shows
the largest number of defects occurred at joints, particularly at saddles, sockets, butt, and tee
joints.
Table 80. Received Failures
Failure Type Number
MaterialFailures 
Pipe 
RockImpingement9
SqueezeͲoff8
InsertRenewal1
Bending/Settlement3
InternalPressure1

Joints
EndCaps8
TappingTeeCaps9
TeesandElls21
Sockets74
Saddles118

FusionFailuresinJoints
ButtFusion29
SocketFusion7
SaddleFusion5

QualityControlProblems6

ThirdParty14

Other8

Total321
Title: DTPH56-06-T-0004 Final Report Page 267
Characterizing the Resistance of PE to RCP through S-4 Testing
It is estimated that about 30% of all the new PE pipe installations are 4-inch and larger in
size. Many gas distribution companies now routinely install PE pipes in 12- and 16-inch
diameter sizes. Also, many of the newer high-density (HD) PE pipelines including those
extruded from Bi-Modal materials are being subjected to pressures greater than 100psig.
RCP is a failure mode that is in complete contrast to SCG. RCP is characterized by a fast
moving large-scale crack that can travel at high speeds over long spans of a PE pipeline. These
types of failures are rare but reports of RCP field failure do exist. A PE gas system had a RCP
failure in which a pipe crack propagated 700 meters before arresting. Other less severe RCP
incidents have occurred in gas pipelines.(Vanspeybroeck, 2002) RCP failures may be very severe
events due to the large volumes of gas that can be quickly released. It is critical that the
phenomenon is well understood and pipelines are designed to minimize the susceptibility to RCP
failures.
Rapid Crack Propagation
A RCP failure mode consists of two phases. First, there is an initiation phase where a
critical crack is formed; this can be a pre-existing notch or generated under dynamic conditions
that involve loads impacting the pipe at high speeds.(Kanninen, O'Donoghue, Cardinal, Green,
Curr, & Williams, 1989) Investigations have shown that a pre-existing notch or crack is
considered critical if it extends about 90% through the pipe wall.(Krishnaswamy, Maxey, Leis,
& Mamoun, 1986) If the pipeline is free of any pre-existing critical defects or notches, then
crack initiation may be induced by a sharp-edged object, such as a blade, that impacts the pipe
line at a very high speed. In this case, the sharp-edged object or source impacting the pipe creates
a notch in the pipe and causes a large amount of elastic strain energy to be stored in the pipe
material and possibly released. Observations of numerous experiments have shown that a sharp-
edged object that impacts a PE pipe causes an RCP critical notch when the notch depth is in the
range of about 50 to 70% of the wall thickness and the notch axial length is about one pipe
diameter.
The second phase involves the release of the stored elastic energy to sustain crack
propagation. This phase is characterized by a steady state crack growth at speeds in excess of
200 m/s over a very long pipe span. To sustain RCP, the energy that drives the crack, denoted as
(J), needs to be greater than the Dynamic Toughness of the PE pipe material, denoted as (Jc).
Equation [9] mathematically expresses the necessary condition for the dynamic propagation of a
crack.(Leis, 1989)
CJJ!(9)
Where:
J = driving energy
JC = dynamic toughness
Title: DTPH56-06-T-0004 Final Report Page 268
If the driving energy (J) decreases or is less than Jc,the crack will stop propagating, i.e.
the crack will arrest. The energy or force that drives the growth of a dynamic RCP crack,
denoted as J, is given in equation [10].
2/3
2
5.2
125.11
DE
t
DDp
J
¸¹
ᬩ
§
 (10)
Where:
J = driving energy
P = pipe internal pressure
D = diameter
ED = dynamic modulus

The expression for J is developed using numerical modeling techniques and principles of
fracture mechanics. ED is a materials property that is dependent on temperature. The dynamic
toughness of a PE pipe material (ED) decreases substantially and rapidly with decreasing
temperatures. From equation [2], it should be noted that the RCP driving force is directly
proportional to the pressure raised to a power of 2.5, the pipe diameter, and SDR. The energy
that drives the growth of a dynamic RCP crack J is inversely related to the dynamic modulus.
Thus, the RCP driving force increases substantially with increasing pressure, SDR and pipe
diameter. The RCP driving force J is inversely proportional to the dynamic modulus.
Figure 305 depicts a schematic illustration of a RCP event in which the crack is traveling
axially along the pipe. Typically, a RCP crack propagates in a sinusoidal pattern along the axial
direction of the PE pipe. In some cases, the RCP crack bifurcates or rings around the pipe.(Leis,
1989)
Figure 305: Schematic of Growing RCP Crack. (Kanninen, Et Al., 1997)
Title: DTPH56-06-T-0004 Final Report Page 269
Equation [10] shows that a primary driving force for RCP is the internal pressure of the pipe.
However, an initiated and growing crack allows for gas to rapidly escape the pipe leading to a
pressure drop as shown in Figure 305. This sets a balance between how quickly the crack grows
(crack propagation) and how quickly the internal pressure escapes from the pipe (decompression
speed). The entire length of pipe in the field is pressurized; as the gas escapes through the crack
it is replaced from the gas contained in the remaining section of the pipe. If the crack speed and
decompression speed are matched, the pressure drop at the crack tip will remain static as there is
insufficient time for it to drop further. In this situation, the crack can propagate over very long
pipe spans. If the pipe decompression is sufficiently fast, the pressure driving the RCP crack will
quickly dissipate thus causing the driving force to be less than Jc, causing crack arrest.
From equation [10] some general relations that lead to a greater chance of RCP are clear:
x Increasing pressure substantially increases RCP susceptibility
x Increasing pipe diameter increases RCP susceptibility
x Increasing SDR increases RCP susceptibility
x Decreasing dynamic modulus increases RCP susceptibility
In summary,
x If J > Jc Then the RCP crack propagates.
x If J < Jc Then the crack arrest occurs.
Title: DTPH56-06-T-0004 Final Report Page 270
S-4 Background
Appropriate testing methodologies were developed to better understand the conditions that
lead to RCP and what prevents it. Tests of all types were considered but due to the pipe size
requirement in RCP, most testing methods focus on using full or longer-sized pipes for
experimentation. GTI conducted numerous RCP full-scale field tests on different types of PE
pipes materials and sizes. These full-scale field tests were performed on pipes having a length
greater than 50 feet. To correlate the results of the full-scale field tests with a small-scale bench-
top test, GTI conducted several tests using a modified version of the Charpy impact test.(Brown,
Lu, & Mamoun, 2000) However, these correlations were inconclusive.
Test Requirements
A test method to evaluate a plastic pipe’s resistance to RCP needs to fit a criteria (Wolters &
Ketel, 1983):
x A sharp crack needs to be initiated at a high speed (greater than decompression
speeds);
x Crack propagation and crack arrest need to be differentiated; and
x Sufficient gas pressure/supply to prevent too quick of a decompression of the pipe
test sample.
Along with these requirements, any test would need to produce consistent and reproducible
results that can be correlated to field conditions. This would help determine design and
operating factors that the plastic pipeline industry can implement and use. Currently, to
characterize the resistance of PE pipe materials to RCP, two tests are typically conducted. These
are the Full-Scale field RCP tests and the laboratory small-scale steady-state (S-4) test.
Full-Scale RCP Field Tests
Full scale RCP testing mimics the conditions conducive to a RCP event that may occur in an
installed PE gas pipe. In a full-scale field test, the length of the PE pipe test sample is typically in
the range of 70 to 100 feet. The test temperature and pressure of the pipe are controlled and
monitored throughout the test. A sharp crack is then initiated in a section of the pipe through
either a pre-notched slit or a fast moving blade. This crack then grows through the pipe
depending on the various test conditions. In many GTI full-scale field tests, the crack speed is
monitored and recorded using timing wires; this information was needed to develop small-scale
laboratory tests that could be accurately correlated with full-scale field tests.
Figure 306 is a photographic view of one of GTI full-scale tests that were conducted on a
100-ft long pipe sample. This view shows the possible catastrophic failure that can occur during
a RCP event and also illustrates the RCP sinusoidal crack that propagated axially along the pipe
length.
The full-scale RCP field tests involve substantial engineering design and planning costs.
This cost makes the full-scale test less than ideal for parametric evaluations of the RCP
phenomenon in plastic pipe materials.
Title: DTPH56-06-T-0004 Final Report Page 271
Figure 306: Full Scale RCP Testing Result (Kanninen Et Al., 1997)
S-4 Testing
Due to the difficulty and costs involved in conducting experiments on full-scale pipe
specimens, a small more compact version of the test was developed for laboratory evaluations:
the small-scale steady-state (S-4) test.
The small-scale steady-state (S-4) test is conducted on short lengths of PE pipes. In an S-4
test, the length of the pipe test sample is between seven (7) and nine (9) times the pipe diameter.
The pipe test sample is cooled to a uniform constant temperature, subjected to a constant internal
pressure, and then impacted at one end with a sharp blade to produce an axial crack in the PE
pipe test specimen. The S-4 test is performed in accordance with ISO 13477 test specification.
Title: DTPH56-06-T-0004 Final Report Page 272
The objective of the S-4 test is to experimentally determine either the:
x Critical pressure pc,S4 corresponding to a given constant temperature determined
from a series of initiation tests; or
x Critical temperature Tc,S4 corresponding to a constant pressure of 5 bars (1 bar =
14.7psig).
In the S-4 test, the pipe test sample is conditioned and cooled to a specified test temperature
determined from a series of initiation tests. Then, while the test specimen is at that temperature,
the pipe is pressurized and impacted with a sharp-edge blade. A rapidly running crack is
initiated in the pipe by the fast moving steel blade. The resultant crack can be measured,
characterized, and categorized as either propagation or arrest. A key feature of the S-4 test
apparatus is that internal baffles prevent rapid decompression of the sample. This feature allows
for testing of a small pipe sections and at lower pressures than required for full scale
testing.(Kanninen, Kuhlman, & Mamoun, Rupture-Prevention Design Procedure to Ensure PE
Gas Pipe System Performance, 1993) A systematic series of tests can be carried out by varying a
single condition at a time. This assists in performing extensive parametric evaluation of the
important variables effecting RCP.
Using the S-4 test methodology, the critical temperature or critical pressure can be
determined for any pipe material and size.
ISO Specification (ISO 13477)
ISO Specification 13477: Thermoplastics Pipes for the Conveyance of Fluids –
Determination of Resistance to Rapid Crack Propagation (RCP) – Small-Scale Steady-State Test
(S4 Test) describes in detail the physical dimensions of many components of an S-4 testing
apparatus. The details and specifications on sample preparation and testing conditions are
described in the ISO specification. The sections that follow briefly describe the testing
procedure contained within the ISO 13477 specification; for full details please reference the
specification directly.
The S-4 test procedure involves performing first the so-called initiation tests. The initiation
tests are then followed by conducting a series of the S-4 full-scale arrest and propagation tests to
determine either the critical pressure or the critical temperature for a PE pipe test material.
Initiation Tests
Before performing a full S-4 tests, initiation tests must be carried out. The initiation tests
are to verify whether or not a fast moving sharp crack can be generated by the striking blade in a
given pipe material and size. The test sections are cooled to 32 °F and struck with no internal
pressure applied. A successful initiation consists of a crack that is at least 0.7 pipe diameters in
length. In this way the energy needed to initiate the fast moving crack is determined for a given
PE pipe material. Figure 307 shows a successful crack initiation test, in which the crack reached
a length greater than 0.7 pipe diameters. If the initiation conditions are not met the blade speed
can be modified but must remain within 5 m/s of 15 m/s. If initiation is not induced at 32°F,
then the test temperature is reduced until the required crack initiation conditions are met.
Alternatively, an internal notch can be introduced to facilitate crack initiation.(ISO 13477)
Title: DTPH56-06-T-0004 Final Report Page 273
Figure 307: S-4 Crack Initiation Result
Critical Pressure Testing
In the standard S-4 procedure, the pipe test specimen is cooled to the required initiation
temperature. Then, the pipe specimen is pressurized with a compressible fluid, usually air. The
pipe is then struck with a sharp-edge blade to initiate a fast moving crack. To evaluate a pipe’s
critical pressure, a series of S-4 tests are performed while systematically varying the internal pipe
pressure. This test method is incorporated into the ISO 13477 specification with the condition
that the test temperature is held constant at a temperature of 32 °F. The crack that results is
considered “propagation” if its length exceeds 4.7 times the pipe diameters. If a crack is
initiated, by growing more than 0.7 pipe diameters and fails to propagate a length of 4.7 times
the pipe diameters then it is considered an “arrest.”(ISO 13477) After performing a series of S-4
tests at different pressures, the highest pressure at which crack arrest occurs is considered the
critical pressure for that specific pipe material and size.
Correlation of the S-4 Critical Pressure to the Full-Scale Field Test
Several full-scale RCP field tests and S-4 were conducted on different PE pipe materials
manufactured in Europe. On the basis of these tests, researchers developed an empirical
correlation between the S-4 critical pressure and the pressure that caused RCP failures in the full-
scale field tests. This correlation was developed by testing resins and pipe materials with
substantial compounding and manufacturing differences than United States produced PE pipe
materials. These differences may result in pipe materials having different RCP resistant
properties. Therefore this correlation may not be valid for US gas grade pipe materials and
Title: DTPH56-06-T-0004 Final Report Page 274
should serve as a guide. The empirically found correlation is given in Equation [11], (ISO
13477):
atmatmScFScpppp 4,,6.3 (11)
Where:
pc,FS = full scale critical pressure
pc,S4 = S-4 critical pressure
patm = atmospheric pressure
In this Equation, it should be noted that 1 patm = 1 Bar = 14.7psig.
Critical Temperature Testing
To determine the critical temperature of a PE pipe material using the S-4 test, a series of
tests are performed on a given PE pipe material of a specific size. The S-4 tests are conducted on
pipe test specimens subjected to a constant pressure of 5 bars or 72.5 psi. In this series of tests,
the pipe temperature is systematically varied until a temperature is determined above which
crack arrest occurs. The coldest/lowest test temperature that results in a crack arrest is designated
as the critical temperature. Above this temperature, no amount of pressure will sustain
RCP.(Leevers, Venizelos, & Morgan, 1993) In some pipe materials it may be impossible to
determine the critical temperature following the S-4 test procedure.(ISO 13477)
Title: DTPH56-06-T-0004 Final Report Page 275
GTI S-4 Test Apparatus
The requirements of an S-4 test apparatus are described in detail in ISO 13477:2008(E).
What follows is the description of GTI’s implementation of the ISO specification. Figure 308
depicts the major components of the S-4 test apparatus:
1. Pipe Assembly: Metal Shaft, Anvil, and Baffles
2. External Containment Cage and Frame
3. Striking Blade Assembly.
Figure 308: GTI’s S-4 Testing Apparatus
Shaft, Anvil, Baffles and Pipe Assembly
The pipe assembly consists of a metal shaft, baffles, an external containment cage, and end
caps. The shaft and end caps facilitate sealing the pipe air-tight and contain ports to allow for
pressurization and pressure monitoring, see Figure 309. A metal anvil is inserted on the metal
shaft preventing excessive pipe deformations; see
Figure 310, at the blade’s point of impact. The metal baffles are cylindrical disks that are
assembled on the pipe shaft and are equidistant apart by the insertion of metallic spacers. The
3. Striking Blade Assembly
1. Pipe Assembly
2. Cage and Frame
Title: DTPH56-06-T-0004 Final Report Page 276
baffles as shown in Figure 312 are evenly spaced and sized according to the ISO specification.
The baffles prevent quick decompression of the pressurized pipe sample after crack initiation.
The PE pipe test specimen is inserted over the anvil and the end-caps are tightly secured at
the pipe ends. The entire pipe assembly consisting of the anvil, the baffles and the PE pipe with
its end-caps can be removed from the test apparatus and placed into an environmental chamber
to allow for pipe conditioning at the required test temperature. The entire pipe assembly is
conditioned and cooled at the chosen temperature for a minimum of 24 hours before being
removed for S-4 testing. GTI monitors the pipe’s temperature with thermocouples and carries
out the testing within the time period allowed by the ISO specification.
Figure 309: End Cap Contains a Port to Fill/Monitor Pipe Specimen.
Title: DTPH56-06-T-0004 Final Report Page 277
Figure 310: Assembly Anvil Prevents Excessive Pipe Wall Deformation during Impact
Figure 311: Schematic of Pipe Assembly Used at GTI
Title: DTPH56-06-T-0004 Final Report Page 278
Figure 312: Baffles and Anvil That Are Contained Within the Pipe Specimen
External Containment Cage and Frame
The S-4 containment cage and frame are attached to the laboratory’s floor and provide a
stable base for the S-4 test. After cooling, the pipe assembly is quickly centered in the external
cage which has spacing that matches the internal baffle system as specified in the ISO standard.
The cage prevents excessive diametric deformations of the pipe as the crack propagates as shown
in Figure 313. The frame attached to the cage is movable to allow for the insertion of the pipe
assembly after which it is moved under the blade-impacting assembly. The exterior cage is then
closed around the pipe assembly and locked in place, as pictured in Figure 314. The overall
frame keeps the alignment between the pipe assembly and blade assembly.
Title: DTPH56-06-T-0004 Final Report Page 279
Figure 313: FET Analysis Showing the Extensive Deformation of a Pipe during RCP
Figure 314: External Cage
Title: DTPH56-06-T-0004 Final Report Page 280
Striking Blade Assembly
This section of the S-4 apparatus propels a steel blade into the pipe surface to initiate the fast
moving crack. The blade assembly is adjustable to different pipe diameters by moving it up and
down and changing the size of the blade. A large pressurized air cylinder controlled by a
solenoid valve provides the acceleration for the steel blade down the rectangular shaft pictured in
Figure 308. When it strikes the pipe assembly, the blade speed is near 15 m/s. GTI monitors the
blade’s speed at impact by timing the blade’s travel over a known distance. As the blade exits
the shaft it strikes the pipe above the anvil initiating a crack as pictured in Figure 315.
Figure 315: Blade Resting in the Crack It Initiated
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H
D
P
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r
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c
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m
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IS
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1
3
4
7
7

Ev
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Te
s
t

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.

CP

Sp
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c
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n

No
.

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s
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Te
m
p
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(
°
F
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1

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m
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8

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r
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m
p
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F
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11

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9
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12

4
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1
9
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7

3
1
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3

1
6
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9
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13

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6
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4

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9
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P
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14

4
6

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6

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9

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6
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8
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9
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P
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c
k

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p
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t
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g
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6
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P
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r
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c
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l

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D
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4
7
7

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.

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m
e
n

No
.

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t

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m
p
.
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F
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9
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Title: DTPH56-06-T-0004 Final Report Page 306
RCP Results, Correlations, and Conclusions
The S-4 critical temperature and pressure values were determined for various pipe materials
and sizes as shown in Table 91.
The critical pressure values corresponding to pipes subjected to full-scale field installations
were calculated using equation [11] from the ISO standard. These values are listed in Table 91.
Table 91: Summary of S-4 Test Results
Pipe Material
Nominal Pipe
Size
Diameter(in)/SDR
Critical Pressure
S-4 (psig)
Critical
Temperature
(°F(°C))
Correlated
Critical
Pressure** Full
Scale (psig)
Driscoplex 6500
PE2406/2708 6" IPS/SDR 11.0 15.5 65.5 (18.6) 94.0
Polypipe
PE3408/3608 6" IPS/SDR 11.0 17.0 50.8 (10.4)* 99.4
Yellowstripe
8300 PE100 6" IPS/SDR 11.0 27.6*** 36.9 (2.7) 137.6
Driscoplex 6500
PE2406/2708 8" IPS/SDR 11.0 11.5 79.6
Yellowstripe
8300 PE100 8" IPS/SDR 13.5 27.0 135.4
Driscoplex 6500
PE2406/2708
12" IPS/SDR
11.0 18.5 104.8
* Note: No arrest point was found
** Correlated pressure calculated using equation 11: pc,FS = 3.6(pc,S4+patm)-patm*** Critical pressure tests for 6” PE100 were carried out at a temperature of 23 °F
The S-4 Critical Pressure was determined for each of the 6 PE pipe materials. In addition,
the S-4 Critical Temperature was determined for the three 6-inch diameter pipe materials. To
determine the Critical Pressure or the Critical temperature, a series of S-4 tests were performed.
For critical pressure determination, the test pressures were systematically varied while
maintaining constant test temperature. For determining the critical temperature, the test
temperatures were systematically varied while maintaining constant test pressure, 5 bars. If field
conditions are well above a pipe’s critical temperature, then it is very unlikely that RCP would
occur. Assuming that the correlation is applicable and valid, the S-4 Critical Pressure was then
combined with the model to determine the full-scale pipe pressure that may lead to a potential
RCP field failure. The S-4 test results and correlations may be used to mitigate the potential for
a RCP failure in the field through selection of proper PE pipe materials and sizes or by
subjecting pipes to MAOP that would not exceed the field pressure calculated using the
empirical correlating model.
Title: DTPH56-06-T-0004 Final Report Page 307
Conclusion
The use of polyethylene (PE) piping has continuously increased. By 2006, the number of
miles of plastic mains increased to 619,000 miles. The number of plastic services grew to over
39.6 million. In order to continue the delivery of safe and reliable energy, it is important to
improve knowledge regarding the state of PE systems. The modes of failure and causes are well
documented for plastic materials in general. The most common mode of field failures has been
attributed to SCG. Many improvements have been made to make PE materials more resistant to
SCG but no matter the material improvements, PE, as well as other piping materials, remains
vulnerable to excavation damage. A review of the “Natural Gas Distribution Incident Data” from
1984 to 2006 showed that excavation damage especially by third parties was the number one
contributor to the cost of damages, injuries, and fatalities in both plastic and steel. Eliminating
excavation damage would cut the total number of reportable incidents by more than half.
Overall, the research performed as part of this report showed that there was very little data
available in the public domain in regard to failures associated with plastic piping systems. GTI
databases were evaluated to characterize SCG and identify susceptibility to premature SCG
failures. Laboratory tests were evaluated to determine whether or not they can be used to provide
information on SCG susceptibility. Additional data was generated through analysis of 55 field
failures. Resistance of PE materials to RCP was investigated through laboratory S-4 testing.
Critical pressure was determined for 6 pipe materials. Critical temperature was determined for 3
materials.
Title: DTPH56-06-T-0004 Final Report Page 308
Recommendations
Under the Root Cause Analysis Task, GTI received fifty-five samples for analysis. Of these,
nine were tapping tee caps. The prominent style of cap received contained the threads on the
inside of the cap. There were eight of these caps and all fractures appeared to have started at the
first thread root. Sample #50020726, which was examined in greater detail than the others, did
not exhibit signs of over-tightening which may indicate a potential issue with this style or
material. Consideration should be given to studying the remaining seven caps to determine if
there is a systemic issue.
There is a need to develop a reliable technology that can be used to accurately locate
underground plastic pipes. There is a critical need to develop a technology that can identify in
real-time the presence of a third-party excavation activity and then promptly alert the pipeline
operator.
Title: DTPH56-06-T-0004 Final Report Page 309
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Alberta, Canada: ASME, 2008.
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Polyethylene Fuel Pipes,” GRI-86/0211, 1986.
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National Transportation Safety Board, Special Investigation Report, “Brittle-like Cracking
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Models of Plastic Gas Piping,” GRI-82/0101.2, 1982.
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Popelar, C.H., V.H. Kenner, and S.F. Popelar, “The Determination of the Performance Life
of Heat Fusion Joints in Polyethylene Gas Pipe Materials,” GRI-91/0032, 1991.
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Prabhat, K., W.A. Maxey, L. Hulbert, and M. Mamoun. (1983). The Use of Charpy and
Robertson Tests in Predicting Rapid Crack Propagation in Polyethylene Pipes. Proceedings of
the 8th Plastics Fuel Gas Pipe Symposium, (pp. 128-132). New Orleans.
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Improved Design and Construction Practices to Account for Thermal Loads in Plastic Gas
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Polyethylene Gas Pipe Materials,” GRI-85/0045, 1985.
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and Fracture Behavior of Polyolefin Gas Piping,” GRI-80/0045, 1980.
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Vanspeybroeck, P. (2002). RCP, After 25 Years of Debates, Finally Mastered by Two ISO-
Tests.17th International Plastic Fuel Gas Pipe Symposium (pp. 47-55). San Francisco:
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for Study of Rapid Crack Propagation in PE Pipelines. Proceedings of the 8th Plastics Fuel Gas
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Testing for Polyethylene Piping Materials,” GRI-88/0221, 1988.
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1998.
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Pennsylvania, August 21, 2004.” PAB-06-01
“Pipeline Accident Report: Natural Gas Pipeline Explosion and Fire in South Riding,
Virginia, July 7, 1998.” PAB 01-01
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Cloud, Minnesota, December 11, 1998.” PAB 01-01
Title: DTPH56-06-T-0004 Final Report Page 313
List of Acronyms
Acronym Description
ABSAcrylonitrilebutadienestyrene
ASTMAmericanSocietyforTestingandMaterials
BDSFBiͲDirectionalShiftFunctions
CTODCrackTipOpeningDisplacement
DIMPDistributionIntegrityManagementPlan
DOTDepartmentofTransportation
DSCDifferentialScanningCalorimetry
EDDynamicModulus
FTͲIRFourierTransformInfraredSpectroscopy
GRIGasResearchInstitute
GTIGasTechnologyInstitute
HDBHydrostaticDesignBasis
HDPEHighDensityPolyethylene
HVTTHighVolumeTappingTee
IDInnerDiameter
ISOInternationalOrganizationforStandardization
LDIWLowDuctileInnerWall
LEFMLinearElasticFractureMechanics
LTHSLongTermHydrostaticStressͲRupture
MDPEMediumDensityPolyethylene
MIMeltIndex
NTSBNationalTransportationSafetyBoard
ODOuterDiameter
OITOxidativeInductionTime
PEPolyethylene
PENTPennsylvaniaNotchTest
PHMSAPipelineandHazardousMaterialsSafetyAdministration
PPIPlasticsPipeInstitute
PVCPolyvinylchloride
QBQuickBurst
RCPRapidCrackPropagation
RPMRateProcessMethod
SͲ4SmallScaleSteadyState
SCGSlowCrackGrowth
SDRStandardDimensionRatio
END OF REPORT

APPENDIX 12: 1982 LETTER FROM DUPONT TO ITS CUSTOMERS REGARDING LEAKS DUE TO
SLITS IN ALDYL "A" PIPE MADE BEFORE 1973

APPENDIX 13: NTSB SPECIAL INVESTIGATION REPORT

APPENDIX 14: PHMSA ADVISORY ADB -99-02
12212 Federal Register /Vol. 64, No. 47/Thursday, March 11, 1999/Notices
each natural gas distribution system
operator with Century pipe revise their
plastic pipe repair procedure(s) to
exclude pipe pinching for isolating
sections of Century pipe. Additionally,
RSPA recommends replacement of any
Century pipe segment that has a
significant leak history or which for any
reason is of suspect integrity.
Authority:49 U.S.C. Chapter 601; 49 CFR
1.53.
Issued in Washington, DC on March 5,
1999.
Richard B. Felder,
Associate Administrator for Pipeline Safety.
[FR Doc. 99–6013 Filed 3–10–99; 8:45 am]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
Research and Special Programs
Administration
Potential Failures Due to Brittle-Like
Cracking of Older Plastic Pipe in
Natural Gas Distribution Systems
AGENCY:Research and Special Programs
Administration (RSPA), DOT.
ACTION:Notice; issuance of advisory
bulletin on brittle-like failures of plastic
pipe to owners and operators of natural
gas distribution systems.
SUMMARY:RSPA is issuing this advisory
bulletin to owners and operators of
natural gas distribution systems to
inform them of the potential
vulnerability of older plastic gas
distribution pipe to brittle-like cracking.
The National Transportation Safety
Board (NTSB) recently issued a Special
Investigation Report (NTSB/SIR–98/01),
Brittle-like Cracking in Plastic Pipe for
Gas Service, that described how plastic
pipe installed in natural gas distribution
systems from the 1960s through the
early 1980s may be vulnerable to brittle-
like cracking resulting in gas leakage
and potential hazards to the public and
property. RSPA has also issued an
additional advisory bulletin (ADB–99–
01) reminding natural gas distribution
system operators of the potential poor
resistance to brittle-like cracking of
certain polyethylene pipe manufactured
by Century Utility Products, Inc.
ADDRESSES:This document can be
viewed on the Office of Pipeline Safety
(OPS) home page at: http://ops.dot.gov.
FOR FURTHER INFORMATION CONTACT:
Gopala K. Vinjamuri, (202) 366–4503, or
by email at
[e-mail].
SUPPLEMENTARY INFORMATION:
I. Background
The National Transportation Safety
Board (NTSB) recently issued a Special
Investigation Report (NTSB/SIR–98/01),
Brittle-like Cracking in Plastic Pipe for
Gas Service, that described how plastic
pipe installed in natural gas distribution
systems from the 1960s through the
early 1980s may be vulnerable to brittle-
like cracking resulting in gas leakage
and potential hazards to the public and
property. An NTSB survey of the
accident history of plastic pipe
suggested that the material may be
susceptible to premature brittle-like
cracking under conditions of local stress
intensification because of improper
joining or installation procedures.
Hundreds of thousands of miles of
plastic pipe have been installed, with a
significant amount installed prior to the
mid-1980s. NTSB believes any
vulnerability of this material to
premature failure could represent a
potentially serious hazard to public
safety.
The NTSB report addressed the
following safety issues:
The vulnerability of plastic pipe to
premature failures due to brittle-like
cracking;
The adequacy of available guidance
relating to the installation and
protection of plastic pipe connections to
steel mains; and
Performance monitoring of plastic
pipeline systems as a way of detecting
unacceptable performance in piping
systems.
Copies of this report may be obtained
by calling NTSB’s Public Inquiry Office
at 202–314–6551.
The phenomenon of brittle-like
cracking in plastic pipe as described in
the NTSB report and generally
understood within the plastic pipeline
industry relates to a part-through crack
initiation in the pipe wall followed by
stable crack growth at stress levels much
lower than the stress required for
yielding, resulting in a very tight slit-
like opening and gas leak. Although
significant cracking may occur at points
of stress concentration and near
improperly designed or installed
fittings, small brittle-like cracks may be
difficult to detect until a significant
amount of gas leaks out of the pipe, and
potentially migrates into an enclosed
space such as a basement. Premature
brittle-like cracking requires relatively
high localized stress intensification that
may be a result from geometrical
discontinuities, excessive bending,
improper fitting assemblies, and/or
dents and gouges. Because this failure
mode exhibits no evidence of gross
yielding at the failure location, the term
brittle-like cracking is used. This
phenomenon is different from brittle
fracture, in which the failure results in
fragmentation of the pipe.
The report suggests that the
combination of more durable plastic
pipe materials and more realistic
strength testing has improved the
reliability of estimates of the long-term
hydrostatic strength of modern plastic
pipe and fittings. The report also
documents that older polyethylene pipe,
manufactured from the 1960s through
the early 1980s, may fail at lower
stresses and after less time than was
originally projected. NTSB alleges that
past standards used to rate the long-term
strength of plastic pipe may have
overrated the strength and resistance to
brittle-like cracking of much of the
plastic pipe manufactured and used for
gas service from the 1960s through the
early 1980s.
In 1998, NTSB made several
recommendations to trade organizations
and to the Research and Special
Programs Administration (RSPA) on the
need for a better understanding of the
susceptibility of plastic pipe to brittle-
like cracking. NTSB recommended that
RSPA ‘‘[d]etermine the extent of the
susceptibility to premature brittle-like
cracking of older plastic piping (beyond
that marketed by Century Utilities
Products Inc.) that remains in use for
gas service nationwide.’’
II. Advisory Bulletin (ADB–99–02)
To:Owners and Operators of and
Natural Gas Distribution Pipeline
Systems
Subject:Potential susceptibility of
plastic pipe installed between the 1960
and the early 1980s to premature failure
due to brittle-like cracking.
Purpose:To inform natural gas
distribution pipeline operators of the
need to determine the extent of
susceptibility to brittle-like cracking of
plastic pipe installed between the years
1960 and early 1980s.
Advisory:A review of Office of
Pipeline Safety (OPS) reportable natural
gas pipeline incidents and the findings
of NTSB Special Investigation Report
(NTSB/SIR–98/01) indicates that certain
plastic pipe used in natural gas
distribution service may be susceptible
to brittle-like cracking. The standards
used to rate the long-term strength of
plastic pipe may have overrated the
strength and resistance to brittle-like
cracking of much of the plastic pipe
manufactured and used for gas service
from the 1960s through the early 1980s.
It is recommended that all owners and
operators of natural gas distribution
systems identify all pre-1982 plastic
pipe installations, analyze leak
12213Federal Register /Vol. 64, No. 47/Thursday, March 11, 1999/Notices
histories, and evaluate any conditions
that may impose high stresses on the
pipe. Appropriate remedial action,
including replacement, should be taken
to mitigate any risks to public safety.
Authority:49 U.S.C. Chapter 601; 49 CFR
1.53.
Issued in Washington, D.C. on March 3,
1999.
Richard B. Felder,
Associate Administrator for Pipeline Safety.
[FR Doc. 99–6051 Filed 3–10–99; 8:45 am]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
Surface Transportation Board
[STB Docket No. AB–437 (Sub–No. 1)]
Kansas Southwestern Railway,L.L.C.—Abandonment—In Sumner,
Harper, Barber, Reno and Kingman
Counties, KS
On February 19, 1999, the Kansas
Southwestern Railway, L.L.C. (KSW)
filed with the Surface Transportation
Board (Board) an application to
abandon: (1) a line of railroad known as
the Hardtner Branch, extending from
milepost 514, at Conway Springs, to
milepost 571.85, at Kiowa; and (2) a
portion of a line of railroad known as
the Stafford Branch, extending from
milepost 559.028, at Conway Springs, to
milepost 610.0, at Olcott, at total
distance of 108.8 miles, in Sumner,
Harper, Barber, Reno, and Kingman
Counties, KS. The line includes no
stations and traverses U.S. Postal
Service ZIP Codes 67031, 67106, 67118,
67014, 67622, 67068, 67121, 67004,
67049, 67003, 67061, and 67070.
The line does not contain federally
granted rights-of-way. Any
documentation in the KSW’s possession
will be made available promptly to
those requesting it. The applicant’s
entire case for abandonment (case-in-
chief) was filed with the application.
This line of railroad has appeared on
the applicant’s system diagram map or
has been included in its narrative in
category 1 since August 20, 1998.
The interest of railroad employees
will be protected by the conditions set
forth in Oregon Short Line R. Co.—
Abandonment—Goshen,360 I.C.C. 91
(1979).
Any interested person may file with
the Board written comments concerning
the proposed abandonment or protests
(including the protestant’s entire
opposition case) by April 5, 1999. All
interested persons should be aware that,
following any abandonment of rail
service and salvage of the line, the line
may be suitable for other public use,
including interim trail use. Any request
for a public use condition under 49
U.S.C. 10905 (49 CFR 1152.28) or for a
trail use condition under 16 U.S.C.
1247(d) (49 CFR 1152.29) must be filed
by April 5, 1999. Each trail use request
must be accompanied by a $150 filing
fee.See 49 CFR 1002.2(f)(27).
Applicant’s reply to any opposition
statements and its response to trail use
requests must be filed by April 20, 1999.
See 49 CFR 1152.26(a).
Persons opposing the proposed
abandonment that wish to participate
actively and fully in the process should
file a protest. Persons who may oppose
the abandonment but who do not wish
to participate fully in the process by
appearing at any oral hearings or by
submitting verified statements of
witnesses containing detailed evidence
should file comments. Persons seeking
information concerning the filing of
protests should refer to 49 CFR 1152.25.
Persons interested only in seeking
public use or trail use conditions should
also file comments.
In addition, a commenting party or
protestant may provide:
(i) An offer of financial assistance
(OFA) for continued rail service under
49 U.S.C. 10904 (due 120 days after the
application is filed or 10 days after the
application is granted by the Board,
whichever occurs sooner);
(ii) Recommended provisions for
protection of the interests of employees;
(iii) A request for a public use
condition under 49 U.S.C. 10905; and
(iv) A statement pertaining to
prospective use of the right-of-way for
interim trail use and rail banking under
16 U.S.C. 1247(d) and 49 CFR 1152.29.
All filings in response to this notice
must indicate the proceeding
designation STB Docket No. AB–437
(Sub-No. 1) and must be sent to: (1)
Surface Transportation Board, Office of
the Secretary, Case Control Unit, 1925 K
Street, N.W. Washington, DC 20423–
0001; and (2) Karl Morell, Ball Janik
LLP, Suite 225, 1455 F Street N.W.,
Washington, DC 20005. The original and
10 copies of all comments or protests
shall be filed with the Board with a
certificate of service. Except as
otherwise set forth in part 1152, every
document filed with the Board must be
served on all parties to the
abandonment proceeding. 49 CFR
1104.12(a).
The lines sought to be abandoned will
be available for subsidy or sale for
continued rail use, if the Board decides
to permit the abandonment in
accordance with applicable laws and
regulations (49 U.S.C. 10904 and 49 CFR
1152.27). Each OFA must be
accompanied by a $1,000 filing fee. See
49 CFR 1002.2(f)(25). No subsidy
arrangement approved under 49 U.S.C.
10904 shall remain in effect for more
than 1 year unless otherwise mutually
agreed by the parties (49 U.S.C.
10904(f)(4)(B)). Applicant will promptly
provide upon request to each interested
party an estimate of the subsidy and
minimum purchase price required to
keep the line in operation. The carrier’s
representative to whom inquiries may
be made concerning sale or subsidy
terms is set forth above.
Persons seeking further information
concerning abandonment procedures
may contact the Board’s Office of Public
Services at (202) 565–1592 or refer to
the full abandonment regulations at 49
CFR part 1152. Questions concerning
environmental issues may be directed to
the Board’s Section of Environmental
Analysis (SEA) at (202) 565–1545. [TDD
for the hearing impaired is available at
(202) 565–1695.]
An environmental assessment (EA) (or
environmental impact statement (EIS), if
necessary) prepared by SEA will be
served upon all parties of record and
upon any agencies or other persons who
commented during its preparation.
Other interested persons may contact
SEA to obtain a copy of the EA (or EIS).
EAs in abandonment proceedings
normally will be made available within
33 days of the filing of the application.
The deadline for submission of
comments on the EA will generally be
within 30 days of its service. The
comments received will be addressed in
the Board’s decision. A supplemental
EA or EIS may be issued where
appropriate.
Board decisions and notices are
available on our website at
‘‘WWW.STB.DOT.GOV.’’
Decided: March 3, 1999.
By the Board, David M. Konschnik,
Director, Office of Proceedings.
Vernon A. Williams,
Secretary.
[FR Doc. 99–5786 Filed 3–10–99; 8:45 am]
BILLING CODE 4915–00–P
DEPARTMENT OF THE TREASURY
Submission for OMB review; commentrequest
Agency Information CollectionActivities
March 4, 1999
The Department of Treasury has
submitted the following public
information collection requirement(s) to
OMB for review and clearance under the

APPENDIX 15: PHMSA ADVISORY ADB- 02-07
70806 Federal Register /Vol. 67, No. 228/Tuesday, November 26, 2002/Notices
For security reasons, attendees must
register in advance. To register, obtain
directions to the Vehicle Research and
Test Center, or request additional
information, contact Jan Cooper at
telephone [phone] extension
208. If Ms. Cooper is not available, you
may register by contacting Fred Seeberg
at telephone [phone] or Susan
Weiser at telephone [phone]
extension 209.
The handouts and other information
presented at the workshop will be
available for public inspection in the
DOT Docket in Washington, DC, within
two weeks after the meeting. Copies of
the materials will be available at ten
cents a page upon request to DOT
Docket, Room PL–401, 400 Seventh
Street, SW., Washington, DC 20590. The
DOT Docket is open to the public from
10 a.m. to 5 p.m. The material may also
be accessed electronically at http://
dms.dot.gov, at Docket No. NHTSA–
2001–9663.
The handouts and other information
presented at the workshop will also be
available on NHTSA’s Web site at URL
http://www-nrd.nhtsa.dot.gov/
departments/nrd-01/presentations/
presentations.html.
Should it be necessary to cancel the
meeting due to inclement weather or
any other emergencies, a decision to
cancel will be made as soon as possible
and posted immediately on NHTSA’s
Web site at URL http://
www.nhtsa.dot.gov/nhtsa.announce/
meetings/. If you do not have access to
the Web site, you may call for
information at the contacts listed below
and leave your telephone or telefax
number. You will be contacted only if
the meeting is postponed or canceled.
FOR FURTHER INFORMATION CONTACT:Jan
Cooper at telephone [phone]
extension 208. If Ms. Cooper is not
available, you may contact Fred Seeberg
at telephone [phone] or Susan
Weiser at telephone [phone]
extension 209.
Issued on: November 20, 2002.
Joseph N. Kanianthra,
Associate Administrator for Applied
Research.
[FR Doc. 02–30054 Filed 11–25–02; 8:45 am]
BILLING CODE 4910–59–P
DEPARTMENT OF TRANSPORTATION
Research and Special Programs
Administration
Notification of the Susceptibility To
Premature Brittle-Like Cracking of
Older Plastic Pipe
AGENCY:Research and Special Programs
Administration (RSPA), DOT.
ACTION:Notice; issuance of advisory
bulletin.
SUMMARY:RSPA is issuing this follow-
up advisory bulletin to owners and
operators of natural gas distribution
systems to inform them of the
susceptibility to premature brittle-like
cracking of older plastic pipe and the
voluntary efforts to collect and analyze
data on plastic pipe performance. A
Special Investigation Report issued by
the National Transportation Safety
Board (NTSB) described how plastic
pipe installed in natural gas distribution
systems from the 1960s through the
early 1980s may be vulnerable to brittle-
like cracking resulting in gas leakage
and potential hazards to the public and
property. On March 11, 1999, RSPA
issued two advisory bulletins on this
issue. The first bulletin reminded
natural gas distribution system
operators of the potential poor
resistance to brittle-like cracking of
certain polyethylene pipe manufactured
by Century Utility Products, Inc. The
second bulletin advised natural gas
distribution system operators of the
potential vulnerability of older plastic
pipe to brittle-like cracking.
ADDRESSES:This document can be
viewed on the Office of Pipeline Safety
(OPS) home page at: http://ops.dot.gov.
FOR FURTHER INFORMATION CONTACT:
Gopala K. Vinjamuri, (202) 366–4503, or
by e-mail at
[e-mail].
SUPPLEMENTARY INFORMATION:
I. Background
On April 23, 1998, NTSB issued a
Special Investigation Report (NTSB/
SIR–98/01), Brittle-like Cracking in
Plastic Pipe for Gas Service, that
describes how plastic pipe installed in
natural gas distribution systems from
the 1960s through the early 1980s may
be vulnerable to brittle-like cracking
resulting in gas leakage and potential
hazards to the public and property. An
NTSB survey of the accident history of
plastic pipe suggested that the material
may be susceptible to premature brittle-
like cracking under conditions of local
stress intensification because of
improper joining or installation
procedures. Hundreds of thousands of
miles of plastic pipe have been
installed, with a significant amount
installed prior to the early-1980s. NTSB
believes any vulnerability of this
material to premature cracking could
represent a potentially serious hazard to
public safety. Copies of this report may
be obtained by calling NTSB’s Public
Inquiry Office at 202–314–6551.
RSPA has already issued two advisory
bulletins on this issue. The first
advisory bulletin, ADB–99–01, which
was published in the Federal Register
on March 11, 1999 (47 FR 12211),
reminded natural gas distribution
system operators of the potential poor
resistance to brittle-like cracking of
certain polyethylene pipe manufactured
by Century Utility Products, Inc. The
second advisory bulletin, ADB–99–02,
also published in the Federal Register
on March 11, 1999 (47 FR 12212),
advised natural gas distribution system
operators of the potential brittle-like
cracking vulnerability of plastic pipe
installed between the 1960s and early
1980s.
The phenomenon of brittle-like
cracking in plastic pipe as described in
the NTSB report and generally
understood within the plastic pipeline
industry relates to a part-through crack
initiation in the pipe wall followed by
stable crack growth at stress levels much
lower than the stress required for
yielding, resulting in a very tight slit-
like openings and gas leaks. Although
significant cracking may occur at points
of stress concentration and near
improperly designed or installed
fittings, small brittle-like cracks may be
difficult to detect until a significant
amount of gas leaks out of the pipe, and
potentially migrates into an enclosed
space such as a basement. Premature
brittle-like cracking requires relatively
high localized stress intensification that
may be a result from geometrical
discontinuities, excessive bending,
improper installation of fittings, and
dents and gouges. Because this failure
mode exhibits no evidence of gross
yielding at the failure location, the term
brittle-like cracking is used. This
phenomenon is different from brittle
fracture, in which the pipe failure
causes fragmentation of the pipe.
The NTSB report suggests that the
combination of more durable plastic
pipe materials and more realistic
strength testing has improved the
reliability of estimates of the long-term
hydrostatic strength of modern plastic
pipe and fittings. The report also
documents that older polyethylene pipe,
manufactured from the 1960s through
the early 1980s, may fail at lower
stresses and after less time than was
originally projected. NTSB alleges that
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70807Federal Register /Vol. 67, No. 228/Tuesday, November 26, 2002/Notices
past standards used to rate the long-term
strength of plastic pipe may have
overrated the strength and resistance to
brittle-like cracking of much of the
plastic pipe manufactured and used for
gas service from the 1960s through the
early 1980s.
In 1998, NTSB made several
recommendations to trade organizations
and to RSPA on the need for a better
understanding of the susceptibility of
plastic pipe to brittle-like cracking. This
advisory bulletin responds to one of the
NTSB recommendations. It is that RSPA
‘‘[d]etermine the extent of the
susceptibility to premature brittle-like
cracking of older plastic piping (beyond
that marketed by Century Utilities
Products Inc.) that remains in use for
gas service nationwide. Inform gas
system operators of the findings and
require them to closely monitor the
performance of the older plastic piping
and to identify and replace, in a timely
manner, any of the piping that indicates
poor performance based on such
evaluation factors as installation,
operating, and environmental
conditions; piping failure
characteristics; and leak history.’’
In order to obtain the most complete
information on the extent of the
susceptibility to premature brittle-like
cracking of older plastic pipe, a meeting
was convened in May 1999 with all the
stakeholders to determine how
information on older plastic pipe could
be assembled. The meeting included
representatives of the American Gas
Association (AGA), the American Public
Gas Association (APGA), the Gas
Research Institute (GRI) (now the Gas
Technology Institute), the Midwest
Energy Association (MEA), and the
Plastic Pipe Institute (PPI).
As a result of the May 1999 meeting,
the Joint Government-Industry Plastic
Pipe Study Committee was formed to
address the recommendations of the
NTSB Special Investigation Report. The
committee held three separate meetings
to prepare a draft response to the NTSB
recommendations and a draft industry
notification of brittle-like cracking
problems, the subject of this advisory
bulletin. The committee membership
consisted of a representative from OPS,
a gas distribution operator from AGA,
and the Transportation Safety Institute.
Meetings were facilitated by General
Physics Corporation, Columbia, MD.
One of the committee findings was that
there is a lack of data available from the
industry to completely identify older
plastic pipe that is still in service and
may be susceptible to brittle-like
cracking.
This finding led to the formation of
the Plastic Pipe Database Committee
(PPDC) to develop a process for
gathering data on future plastic pipe
failures with involvement from the
states, which have assumed the
authority from OPS over gas distribution
systems, where most of the plastic pipe
is installed. The PPDC is comprised of
representatives from Federal and State
regulatory agencies and from the natural
gas and plastic pipe industries.
Members include AGA, APGA, PPI, the
National Association of Regulatory
Utility Commissioners (NARUC), the
National Association of Pipeline Safety
Representatives (NAPSR), and OPS.
The PPDC database is expected to
improve the knowledge base of gas
utility operators and regulators and is
intended to help reveal any failure
trends associated with older plastic
piping materials. The PPDC’s mission is
‘‘to develop and maintain a voluntary
data collection process that supports the
analysis of the frequency and causes of
in-service plastic piping material
failures.’’ It provides an opportunity for
government and industry to work
together to evaluate the extent of plastic
pipe performance problems and to
mitigate any risks to safety. The PPDC
started gathering data in January 2001
from OPS and State pipeline safety
agencies. For more information on the
PPDC, go to the AGA Web page (http:/
/www.aga.org), and enter ‘‘PPDC’’ in the
keyword search.
II. Advisory Bulletin (ADB–02–7)
To: Owners and Operators of Natural
Gas Distribution Pipeline Systems.
Subject: Notification of the
Susceptibility to Premature Brittle-like
Cracking of Older Plastic Pipe.
Advisory: In recent years, brittle-like
cracking has been observed in some
polyethylene pipes installed in gas
service through the early 1980s. This
brittle-like cracking (also known as slow
crack growth) can substantially reduce
the service life of polyethylene piping
systems.
The susceptibility of some
polyethylene pipes to brittle-like
cracking is dependent on the resin, pipe
processing, and service conditions. A
number of studies have been conducted
on older polyethylene pipe. These
studies have shown that some of these
older polyethylene pipes are more
susceptible to brittle-like cracking than
current materials. These older
polyethylene pipe materials include the
following:x Century Utility Products, Inc.
products. x Low-ductile inner wall ‘‘Aldyl A’’
piping manufactured by Dupont
Company before 1973.
x Polyethylene gas pipe designated
PE 3306. (As a result of poor
performance this designation was
removed from ASTM D–2513.)
The environmental, installation, and
service conditions under which the
piping is used are factors that could lead
to premature brittle-like cracking of
these older materials. These conditions
include, but are not limited to: x Inadequate support and backfill
during installation. x Rock impingement.x Shear/bending stresses due to
differential settlement resulting from
factors such as:
—Excavation in close proximity to
polyethylene piping
—Directional drilling in close proximity
to polyethylene piping
—Frost heave
x Bending stresses due to pipe
installations with bends exceeding
recommended practices. x Damaging squeeze-off practices.
Service temperatures and service
pressures also influence the service life
of polyethylene piping. Piping installed
in areas with higher ground
temperatures or operated under higher
operating pressures will have a shorter
life.
Gas system operators may experience
an increase in failure rates with a
susceptible material. A susceptible
material may have leak-free
performance for a number of years
before brittle-like cracks occur. An
increase in the occurrence of leaks will
typically be the first indication of a
brittle-like cracking problem. It is the
responsibility of each pipeline operator
to monitor the performance of their gas
system. RSPA issues the following
recommendations to aid operators in
identifying and managing brittle-like
cracking problems in polyethylene
piping involving taking appropriate
action, including replacement, to
mitigate any risks to public safety.
Because systems without known
susceptible materials may also
experience brittle-like cracking
problems, RSPA recommends that all
operators implement the following
practices for all polyethylene piping
systems:
1. Review system records to
determine if any known susceptible
materials have been installed in the
system. Both engineering and
purchasing records should be reviewed.
Based on the available records, identify
the location of the susceptible materials.
More frequent inspection and leak
surveys should be performed on systems
that have exhibited brittle-like cracking
failures of known susceptible materials.
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70808 Federal Register /Vol. 67, No. 228/Tuesday, November 26, 2002/Notices
1B&M received Board authorization to abandon
the above-described line pursuant to a decision in
Boston and Maine Corporation-Abandonment-in
Suffolk County, MA, STB Docket No. AB–32 (Sub-
No. 92) (STB served Dec. 21, 2001).
2Massport simultaneously filed a motion to
dismiss this proceeding, maintaining that the Board
should not exercise jurisdiction over this
transaction. The motion will be addressed by the
Board in a separate decision.
2. Establish a process to identify
brittle-like cracking failures.
Identification of failure types and site
installation conditions can yield
valuable information that can be used in
predicting the performance of the
system.
3. Use a consistent record format to
collect data on system failures. The
AGA Plastic Failure Report form
(Appendix F of the AGA Plastic Pipe
Manual) provides an example of a report
for the collection of failure data.
4. Collect failure samples of
polyethylene piping exhibiting brittle-
like cracking. Evidence of brittle-like
cracking may warrant laboratory testing.
Although every failure may not warrant
testing, collecting samples at the time of
failure would provide the opportunity
to conduct future testing should it be
deemed necessary.
5. Whenever possible record the print
line from any piping that has been
involved in a failure. The print line
information can be used to identify the
resin, manufacturer and year of
manufacture for plastic piping.
6. For systems where there is no
record of the piping material, consider
recording print line data when piping is
excavated for other reasons. Recording
the print line data can aid in
establishing the type and extent of
polyethylene piping used in the system.
(49 U.S.C. chapter 601; 49 CFR 1.53)
Issued in Washington, DC, on November
21, 2002.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 02–30055 Filed 11–25–02; 8:45 am]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
Surface Transportation Board
[STB Finance Docket No. 34276]
Massachusetts Port Authority-
Acquisition Exemption-Certain Assets
of Boston and Maine Corporation
The Massachusetts Port Authority
(Massport), a noncarrier, has filed a
notice of exemption under 49 CFR
1150.31 to acquire from the Boston and
Maine Corporation (B&M) certain
railroad rights-of-way and related
improvements, totaling approximately
1.45 miles, in Charlestown, Suffolk
County, MA. Massport proposes to
acquire B&M’s right, title and interest in
the rail line, known as the Mystic Wharf
Branch line, between milepost 0.00 and
milepost 1.45.1
Massport indicates that it does not
intend to conduct rail operations over
the line, but is acquiring it to preserve
the rail right-of-way and availability of
rail service to the Port. Massport further
indicates that it may develop an
adjacent haul road on the property at a
later date. According to Massport, B&M
will retain an exclusive permanent
easement on the line for rail operations,
and its affiliate Springfield Terminal
Railway Company will continue to be
responsible for providing rail operations
over the line. Massport will not obtain
the right or obligation to provide rail
freight service on the line. Massport
certifies that its projected revenues as a
result of this transaction will not result
in the creation of a Class II or Class I rail
carrier.
The parties reported that they
intended to consummate the transaction
on November 13, 2002.
If the notice contains false or
misleading information, the exemption
is void ab initio.2 Petitions to revoke the
exemption under 49 U.S.C. 10502(d)
may be filed at any time. The filing of
a petition to revoke will not
automatically stay the transaction.
An original and 10 copies of all
pleadings, referring to STB Finance
Docket No. 34276, must be filed with
the Surface Transportation Board, 1925
K Street, NW., Washington, DC 20423–
0001. In addition, a copy of each
pleading must be served on Keith G.
O’Brien, REA, CROSS &
AUCHINCLOSS, 1707 L Street NW.,
Suite 570, Washington, DC 20036.
Board decisions and notices are
available on our Web site at http://
www.stb.dot.gov.
Decided: November 19, 2002.
By the Board, David M. Konschnik,
Director, Office of Proceedings.
Vernon A. Williams,
Secretary.
[FR Doc. 02–29876 Filed 11–25–02; 8:45 am]
BILLING CODE 4915–00–P
DEPARTMENT OF THE TREASURY
Submission for OMB Review; Comment Request
November 15, 2002.
The Department of Treasury has
submitted the following public
information collection requirement(s) to
OMB for review and clearance under the
Paperwork Reduction Act of 1995,
Public Law 104–13. Copies of the
submission(s) may be obtained by
calling the Treasury Bureau Clearance
Officer listed. Comments regarding this
information collection should be
addressed to the OMB reviewer listed
and to the Treasury Department
Clearance Officer, Department of the
Treasury, Room 11000, 1750
Pennsylvania Avenue, NW.,
Washington, DC 20220.
DATES:Written comments should be
received on or before December 26, 2002
to be assured of consideration.
Financial Crimes Enforcement Network
(FinCEN)
OMB Number: 1506–0019.
Form Number: FinCEN Form 101.
Type of Review: Revision.
Title: Suspicious Activity Report by
the Securities and Futures Industry.
Description: Treasury is requiring
certain securities broker-dealers to file
suspicious activity Reports.
Respondents: Business or other for-
profit.
Estimated Number of Respondents/
Recordkeepers: 8,300.
Estimated Burden Hours Per
Respondent/Recordkeeper: 4 hours, 40
minutes.
Estimated recordkeeping/filing per
response: 4 hours.
Estimated record (SAR) completion
time: 40 minutes.
Frequency of Response: On occasion.
Estimated Total Reporting/
Recordkeeping Burden: 9,334 hours.
Clearance Officer: Lois K. Holland
(202) 622–1563, Departmental Offices,
Room 11000, 1750 Pennsylvania
Avenue, NW., Washington, DC 20220.
OMB Reviewer: Joseph F. Lackey, Jr.
(202) 395–7316, Office of Management
and Budget, Room 10235, New
Executive Office Building, Washington,
DC 20503.
Mary A. Able,
Departmental Reports, Management Officer.
[FR Doc. 02–29990 Filed 11–25–02; 8:45 am]
BILLING CODE 4810–02–P
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APPENDIX 16: PHMSA ADVISORY ADB 07-01
51301 Federal Register/Vol. 72, No. 172/Thursday, September 6, 2007/Notices
safety procedures used for filling,
operating, and discharging MATs to
determine whether additional safety
procedures should be implemented. To
this end, we request that persons who
use such transportation systems to
provide us with information on the
effectiveness of the current DOT
regulations, consensus standards, and
industry best practices. We are also
interested in any other procedures
utilized to ensure that operations related
to the transportation of acetylene on
MATs are performed safely.
We would also like to work with
shippers, carriers, and facilities that
receive shipments of acetylene in MATs
to develop and implement a pilot
program to test the effectiveness of
current or alternative procedures or
methods designed to enhance the safety
of transportation operations involving
acetylene on MATs. As part of this
program, we will assist individual
companies or facilities to evaluate the
effectiveness of their current procedures
and to identify additional measures that
should be implemented. We welcome
suggestions concerning how such a
program should be structured and the
entities that should participate.
To ensure that our message reaches all
stakeholders affected by these risks, we
plan to communicate this advisory
through our public affairs notification
and outreach processes. For additional
visibility, we have made this advisory
available on the PHMSA homepage at
http://www.phmsa.dot.gov and the DOT
electronic docket site at http://
dms.dot.gov. In addition, if you are
aware of other companies that are
involved in the charging, operating, and
discharging MATs, please share this
advisory notice with them and, if
possible, identify them in your
correspondence with this agency. We
believe a collaborative effort involving
an integrated and cooperative approach
will help us to address safety risks,
reduce incidents, enhance safety, and
protect the public.
Issued in Washington, DC on August 30,
2007.
Theodore L. Willke,
Associate Administrator for Hazardous
Materials Safety.
[FR Doc. 07–4355 Filed 9–5–07; 8:45 am]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
[Docket No. PHMSA–2004–19856]
Pipeline Safety: Updated Notification
of the Susceptibility to Premature
Brittle-Like Cracking of Older Plastic
Pipe
AGENCY: Pipeline and Hazardous
Materials Safety Administration
(PHMSA); DOT.
ACTION: Notice; Issuance of Advisory
Bulletin.
SUMMARY: PHMSA is issuing this
updated advisory bulletin to owners and
operators of natural gas pipeline
distribution systems concerning the
susceptibility of older plastic pipe to
premature brittle-like cracking. PHMSA
previously issued three advisory
bulletins on this subject: Two on March
11, 1999 and one on November 26,
2002. This advisory bulletin expands on
the information provided in the three
prior bulletins by listing two additional
pipe materials with poor performance
histories relative to brittle-like cracking
and by updating pipeline owners and
operators on the ongoing voluntary
efforts to collect and analyze data on
plastic pipe performance. Owners and
operators of natural gas pipeline
distribution systems are encouraged to
review the three previous advisory
bulletins in their entirety.
FOR FURTHER INFORMATION CONTACT:
Richard Sanders at (405) 954–7214, or
by e-mail at [e-mail].
SUPPLEMENTARY INFORMATION:
I. National Transportation Safety Board
(NTSB) Investigation
On April 23, 1998, the National
Transportation Safety Board (NTSB)
issued its Special Investigation Report,
Brittle-Like Cracking in Plastic Pipe for
Gas Service, NTSB/SIR–98/01. The
report described the results of the
NTSB’s special investigation of
polyethylene gas service pipe, which
addressed three major safety issues: (1)
Vulnerability of plastic piping to
premature failures due to brittle-like
cracking; (2) adequacy of available
guidance relating to the installation and
protection of plastic piping connections
to steel mains; and, (3) effectiveness of
performance monitoring of plastic
pipeline systems to detect unacceptable
performance in piping systems.
(1) Vulnerability of plastic piping to
premature failures due to brittle-like
cracking: The NTSB found that failures
in polyethylene pipe in actual service
are frequently brittle-like, slit failures,
not ductile failures. It concluded the
number and similarity of plastic pipe
accident and non-accident failures
indicate past standards used to rate the
long-term strength of plastic pipe may
have overrated the strength and
resistance to brittle-like cracking for
much of the plastic pipe manufactured
and used for gas service from the 1960s
through the early 1980s. The NTSB also
concluded any potential public safety
hazards from these failures are likely to
be limited to locations where stress
intensification exists. The NTSB went
on to state that more durable modern
plastic piping materials and better
strength testing have made the strength
ratings of modern plastic piping more
reliable.
(2) Adequacy of available guidance
relating to the installation and
protection of plastic piping connections
to steel mains: The NTSB concluded
that gas pipeline operators had
insufficient notification of the brittle-
like failure potential for plastic pipe
manufactured and used for gas service
from the 1960s to the early 1980s. The
NTSB also concluded this may not have
allowed companies to implement
adequate surveillance and replacement
programs for older plastic piping. The
NTSB explained the Gas Research
Institute (GRI) developed a significant
amount of data on older plastic pipe but
the data was published in codified
terms making it insufficient for use by
pipeline system operators. The NTSB
recommended that manufacturers of
resin and pipe, industry trade groups
and the Federal government do more to
alert pipeline operators to the role
played by stress intensification from
external forces in the premature failure
of plastic pipe due to brittle-like
cracking.
(3) Effectiveness of performance
monitoring of plastic pipeline systems
as a way of detecting unacceptable
performance in piping systems: The
NTSB’s analysis noted that Federal
regulations require pipeline operators to
have an ongoing program to monitor the
performance of their pipeline systems.
However, the NTSB investigation
revealed some gas pipeline operators’
performance monitoring programs did
not effectively collect and analyze data
to determine the extent of possible
hazards associated with plastic pipeline
systems. The NTSB pointed out, ‘‘such
a program must be adequate to detect
trends as well as to identify localized
problem areas, and it must be able to
relate poor performance to specific
factors such as plastic piping brands,
dates of manufacture (or installation
dates), and failure conditions.’’
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51302 Federal Register/Vol. 72, No. 172/Thursday, September 6, 2007/Notices
Copies of this report may be obtained
by searching the NTSB Web site at
www.ntsb.gov.
II. Advisory Bulletins Previously Issued
by PHMSA
The NTSB made several
recommendations to PHMSA and to
trade organizations in its 1998 special
investigation report. In response,
PHMSA issued three advisory bulletins.
The first advisory bulletin, ADB–99–01,
Potential Failure Due to Brittle-Like
Cracking of Certain Polyethylene Plastic
Pipe Manufactured by Century Utility
Products Inc, was published in the
Federal Register (FR) on March 11, 1999
(64 FR 12211) to advise natural gas
pipeline distribution system operators
that brittle-like cracking may occur on
certain polyethylene pipe manufactured
by Century Utility Products, Inc.
The second advisory bulletin, ADB–
99–02, Potential Failures Due to Brittle-
Like Cracking of Older Plastic Pipe in
Natural Gas Distribution Systems, was
also published in the Federal Register
on March 11, 1999 (64 FR 12212) to
advise natural gas pipeline distribution
system operators of the potential for
brittle-like cracking of plastic pipes
installed between the 1960s and early
1980s.
The third advisory bulletin, ADB–02–
07, Notification of the Susceptibility To
Premature Brittle-Like Cracking of Older
Plastic Pipe, was published in the
Federal Register on November 26, 2002
(67 FR 70806) to reiterate to natural gas
pipeline distribution system operators
the susceptibility of older plastic pipe to
premature brittle-like cracking. The
older polyethylene pipe materials
specifically identified in ADB–02–07
included, but were not limited to: x Century Utility Products, Inc.
products; x Low-ductile inner wall ‘‘Aldyl A’’
piping manufactured by DuPont
Company before 1973; and x Polyethylene gas pipe designated
PE 3306.
This third advisory bulletin also listed
several environmental, installation and
service conditions in which plastic
piping is used that could lead to
premature brittle-like cracking failure.
PHMSA also described six
recommended practices for
polyethylene gas pipeline system
operators to aid them with identifying
and managing brittle-like cracking
problems.
III. Plastic Pipe Studies
Beginning January 25, 2001, the
American Gas Association (AGA) began
to collect data on in-service plastic
piping material failures with the
objective of identifying trends in the
performance of these materials. The
resulting leak survey data, collected
from 2001 to present, on the county’s
natural gas distribution systems
includes both actual failure information
and negative reports (reports of no
leads) submitted voluntarily by
participating pipeline operating
companies.
The AGA, PHMSA, and other
industry and state organizations
continue to collect and analyze the data.
Unfortunately, the data cannot be
correlated with the quantities of each
plastic pipe material that may be in
service across the United States.
Therefore, the data does not assess the
failure rates of individual plastic pipe
materials on a linear basis (i.e. per foot,
per mile, etc.). However, the failure data
reinforces what is historically known
about certain older plastic piping and
components. The data also indicates the
susceptibility of additional specific
materials to brittle-like cracking.
IV. Advisory Bulletin ADB–07–01
To: Owners and Operators of Natural
Gas Pipeline Distribution Systems.
Subject: Updated Notification of the
Susceptibility of Older Plastic Pipes to
Premature Brittle-Like Cracking.
Advisory: All owners and operators of
natural gas distribution systems who
have installed and operate plastic
piping are reminded of the phenomenon
of brittle-like cracking. Brittle-like
cracking refers to crack initiation in the
pipe wall not immediately resulting in
a full break followed by stable crack
growth at stress levels much lower than
the stress required for yielding. This
results in very tight, slit-like, openings
and gas leaks. Although significant
cracking may occur at points of stress
concentration and near improperly
designed or installed fittings, small
brittle-like cracks may be difficult to
detect until a significant amount of gas
leaks out of the pipe, and potentially
migrates into an enclosed space such as
a basement. Premature brittle-like
cracking requires relatively high
localized stress intensification that may
result from geometrical discontinuities,
excessive bending, improper installation
of fittings, dents and/or gouges. Because
this failure mode exhibits no evidence
of gross yielding at the failure location,
the term brittle-like cracking is used.
This phenomenon is different from
brittle fracture, in which the pipe failure
causes fragmentation of the pipe.
All owners and operators of natural
gas distribution systems are future
advised to review the three earlier
advisory bulletins on this issue. In
addition to being available in the
Federal Register, these advisory
bulletins are available in the docket, and
on PHMSA’s Web site at http://
phmsa.dot.gov/ under Pipeline Safety
Regulations.
In the first advisory bulletin, ADB–
99–01, published on March 11, 1999 (64
FR 12211), PHMSA advises natural gas
distribution system operators of the
potential for poor resistance to brittle-
like cracking of certain polyethylene
pipe manufactured by Century Utility
Products, Inc. In the second advisory
bulletin, ADB–99–02, published on
March 11, 1999 (64 FR 12212), PHMSA
advises natural gas distribution system
operators of the potential for brittle-like
cracking of plastic pipes installed
between the 1960s and early 1980s.
In the third advisory bulletin, ADB–
02–07, published on November 26, 2002
(67 FR 70806), PHMSA reiterates to
pipeline operators the susceptibility of
some older plastic pipe to premature
brittle-like cracking which could
substantially reduce the service life of
natural gas distribution systems and to
explain the mission of the Plastic Pipe
Database Committee (PPDC) ‘‘to develop
and maintain a voluntary data collection
process that supports the analysis of the
frequency and causes of in-service
plastic piping material failures.’’ The
advisory bulletin also lists several
environmental, installation and service
conditions under which plastic piping
is used which is used which could lead
to premature brittle-like cracking
failure. PHMSA also describes six
recommended practices for
polyethylene gas pipeline system
operators to aid them with identifying
and managing brittle-like cracking
problems.
Lastly, the susceptibility of some
polyethylene pipes to brittle-like
cracking is dependent on the resin, pipe
processing, and service conditions. As
noted in ADB–02–07, these older
polyethylene pipe materials include, but
are not limited to:
x Century Utility Products, Inc.
products;
x Low-ductile inner wall ‘‘Aldyl A’’
piping manufactured by DuPont
Company before 1973; and
x Polyethylene gas pipe designated
PE 3306.
The data now supports adding the
following pipe materials to this list:
x Delrin insert tap tees; and,
x Plexco service tee Celcon
(polyacetal) caps.
Authority: 49 U.S.C. chapter 601 and 49
CFR 1.53.
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51303 Federal Register/Vol. 72, No. 172/Thursday, September 6, 2007/Notices
Issued in Washington, DC, on August 28,
2007.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 07–4309 Filed 9–5–07; 8:45 am]
BILLING CODE 4910–60–M
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
[Docket No. PHMSA–2007–28993]
Pipeline Safety: Adequacy of Internal
Corrosion Regulations for Hazardous
Liquid Pipelines
AGENCY: Pipeline and Hazardous
Materials Safety Administration
(PHMSA), U.S. Department of
Transportation (DOT).
ACTION: Notice of availability of
materials; request for comments.
SUMMARY: This notice announces the
availability of materials, including a
briefing paper prepared for PHMSA’s
Technical Hazardous Liquid Pipeline
Safety Standards Committee (THLPSSC)
and data on risks posed by internal
corrosion on hazardous liquid pipelines.
PHMSA is preparing a report to
Congress on the adequacy of the internal
corrosion regulations for hazardous
liquid pipelines. Participants at a
meeting of the THLPSSC discussed
issues involved in examining the
adequacy of the regulations and
requested additional data. PHMSA
requests public comment on these
matters.
DATES: Submit comments by October 9,
2007.
ADDRESSES: Comments should reference
Docket No. PHMSA–2007–28993 and
may be submitted in the following ways: x E-Gov Web site: http://
www.regulations.gov. This Web site
allows the public to enter comments on
any Federal Register notice issued by
any agency. Follow the instructions for
submitting comments. x Fax: [phone].x Mail: Docket Management System:
U.S. Department of Transportation,
Docket Operations, M–30, Room W12–
140, 1200 New Jersey Avenue, SE.,
Washington, DC 20590–0001. x Hand Delivery: DOT Docket
Management System, West Building
Ground Floor, Room W12–140, 1200
New Jersey Avenue, SE., Washington,
DC 20590–0001 between 9 a.m. and 5
p.m., Monday through Friday, except
Federal holidays.
Instructions: Identify the docket
number, PHMSA–2007–28993, at the
beginning of your comments. If you
submit your comments by mail, submit
two copies. To receive confirmation that
PHMSA received your comments,
include a self-addressed stamped
postcard. Internet users may submit
comments at http://
www.regulations.gov.
Note: Comments are posted without
changes or edits to http://
www.regulations.gov, including any personal
information provided. There is a privacy
statement published on http://
www.regulations.gov.
FOR FURTHER INFORMATION CONTACT:
Barbara Betsock at (202) 366–4361, or by
e-mail at [e-mail].
SUPPLEMENTARY INFORMATION: The
Pipeline Inspection, Protection,
Enforcement, and Safety Act of 2006
directs PHMSA to review the internal
corrosion regulations in subpart H of 49
CFR part 195 to determine if they are
adequate to ensure adequate protection
of the public and environment and to
report to Congress on the results of the
review. As an initial step in the review,
PHMSA consulted the THLPSSC at its
meeting on July 24, 2007. The briefing
paper prepared for the committee
members contains preliminary data on
risk history as well as questions relating
to the internal corrosion regulations.
This briefing paper is posted on
PHMSA’s pipeline Web site (http://
ops.dot.gov) and has been placed in the
docket.
At the meeting, PHMSA officials
committed to gathering additional data
responding to questions posed by the
committee members. PHMSA has
updated the data and included data
responsive to the committee members.
This data is also posted on the pipeline
Web site and contained in the docket.
PHMSA requests comments on the
adequacy of the internal corrosion
regulations and answers to the questions
posed in the briefing paper. PHMSA
will use these comments in its review of
the internal corrosion regulations.
Authority: 49 U.S.C. 60102, 60115, 60117:
Sec. 22, Pub. L. 109–468, 120 Stat. 3499.
Issued in Washington, DC on August 27,
2007.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. E7–17538 Filed 9–5–07; 8:45 am]
BILLING CODE 4910–60–P
DEPARTMENT OF VETERANS
AFFAIRS
[OMB Control No. 2900–0675]
Proposed Information Collection
Activity: Proposed Collection;
Comment Request
AGENCY: Center for Veterans Enterprise,
Department of Veterans Affairs.
ACTION: Notice.
SUMMARY: The Center for Veterans
Enterprise (CVE), Department of
Veterans Affairs (VA), is announcing an
opportunity for public comment on the
proposed collection of certain
information by the agency. Under the
Paperwork Reduction Act (PRA) of
1995, Federal agencies are required to
publish notice in the Federal Register
concerning each proposed collection of
information, including each proposed
extension of a currently approved
collection, and allow 60 days for public
comment in response to the notice. This
notice solicits comments for information
needed to identify veteran-owned
businesses.
DATES: Written comments and
recommendations on the proposed
collection of information should be
received on or before November 5, 2007.
ADDRESSES: Submit written comments
on the collection of information through
http://www.Regulations.gov; or Gail
Wegner (00VE), Department of Veterans
Affairs, 810 Vermont Avenue, NW.,
Washington, DC 20420 or e-mail:
[e-mail]. Please refer to
‘‘OMB Control No. 2900–0675’’ in any
correspondence. During the comment
period, comments may be viewed online
through the Federal Docket Management
System (FDMS) at http://
www.Regulations.gov.
FOR FURTHER INFORMATION CONTACT: Gail
Wegner at (202) 303–3296 or FAX (202)
254–0238.
SUPPLEMENTARY INFORMATION: Under the
PRA of 1995 (Pub. L. 104–13; 44 U.S.C.
3501–3521), Federal agencies must
obtain approval from the Office of
Management and Budget (OMB) for each
collection of information they conduct
or sponsor. This request for comment is
being made pursuant to section
3506(c)(2)(A) of the PRA.
With respect to the following
collection of information, CVE invites
comments on: (1) Whether the proposed
collection of information is necessary
for the proper performance of CVE’s
functions, including whether the
information will have practical utility;
(2) the accuracy of CVE’s estimate of the
burden of the proposed collection of
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APPENDIX 17: US DOT CALL TO ACTION
1 | P a g e
U.S. Department of Transportation Call to Action
To Improve the Safety of the Nation’s Energy Pipeline System
Executive Summary
Today, more than 2.5 million miles of pipelines are responsible for delivering oil and gas to
communities and businesses across the United States. That's enough pipeline to circle the earth
approximately 100 times.
Currently, these liquid and gas pipelines are operated by approximately 3,000 companies and fall
under the safety regulations of the U.S. Department of Transportation’s Pipeline and Hazardous
Materials Safety Administration (PHMSA). PHMSA has engineers and inspectors around the country
who oversee the safety of these lines and ensure that companies comply with critical safety rules that
protect people and the environment from potential dangers. While PHMSA directly regulates most of
the hazardous liquid pipelines in the nation, states take over when it comes to intrastate natural gas
pipelines. Every state, except Hawaii and Alaska, is responsible for the inspection and enforcement of
state pipeline safety laws for the natural gas pipeline systems within their respective states. Some
states – about 20 percent - also regulate the hazardous liquid lines within state borders.
In the wake of several recent serious pipeline incidents, U.S. DOT/PHMSA is taking a hard look at the
safety of the nation’s pipeline system. Over the last three years, annual fatalities have risen from nine
in 2008, to 13 in 2009 to 22 in 2010. Like other aspects of America’s transportation infrastructure, the
pipeline system is aging and needs a comprehensive evaluation of its fitness for service. Investments
that are made now will ensure the safety of the American people and the integrity of the pipeline
infrastructure for future generations.
For these reasons, Secretary LaHood has issued “A Call To Action” for all pipeline stakeholders,
including the pipeline industry, the utility regulators, and our state and federal partners. Secretary
LaHood brought together PHMSA Administrator Quarterman and the senior DOT leadership to design
a strategy to achieve that goal. The action plan below is the result of those deliberations.
Background
Much of the nation’s pipeline infrastructure was installed many decades ago, and some century-old
infrastructure continues to transport energy supplies to residential and commercial customers,
particularly in the urban areas across our nation. Older pipeline facilities that are constructed of
obsolete materials (e.g., cast iron, copper, bare steel, and certain kinds of welded pipe) may have
degraded over time, and some have been exposed to additional threats, such as excavation damage.
On December 4, 2009, PHMSA issued the Distribution Integrity Management Final Rule, which
extends the pipeline integrity management principles that were established for hazardous liquid and
natural gas transmission pipelines, to the local natural gas distribution pipeline systems. This
regulation, which becomes effective in August of 2011, requires operators of local gas distribution
2 | P a g e
pipelines to evaluate the risks on their pipeline systems to determine their fitness for service and take
action to address those risks. For older gas distribution systems, the appropriate mitigation measures
could involve major pipe rehabilitation, repair, and replacement programs. At a minimum, these
measures are needed to requalify those systems as being fit for service. While these measures may
be costly, they are necessary to address the threat to human life, property, and the environment.
In addition to the many pipelines constructed with obsolete materials, there are also early vintage
steel pipelines in high consequence areas that may pose risks because of inferior materials, poor
construction practices, and lack of maintenance or inadequate risk assessments performed by
operators. The lack of basic information or incomplete records about these systems is also a
contributing factor. The U.S. DOT is seeking to make sure these risks are identified, the pipelines are
assessed accurately, and preventative steps are taken where they are needed.
Action Plan
The U.S. DOT and PHMSA have developed this action plan to accelerate rehabilitation, repair, and
replacement programs for high-risk pipeline infrastructure and to requalify that infrastructure as fit
for service. The Department will engage pipeline safety stakeholders in the process to systematically
address parts of the pipeline infrastructure that need attention, and ensure that Americans remain
confident in the safety of their families, their homes, and their communities. The strategy involves:
x A CALL TO ACTION – Secretary LaHood is issuing a “Call to Action” to engage state partners,
technical experts, and pipeline operators in identifying pipeline risks and repairing,
rehabilitating, and replacing the highest risk infrastructure. Secretary LaHood is also asking
Congress to expand PHMSA’s ability to oversee pipeline safety.
ƒSecretary LaHood and PHMSA Administrator Quarterman have met with the Federal
Energy Regulatory Commission (FERC), the National Association of Regulatory and
Utility Commissioners (NARUC), state public utility commissions, and industry
leaders to ask all parties to step up efforts to identify high-risk pipelines and ensure
that they are repaired or replaced.
ƒSecretary LaHood is asking Congress to increase the maximum civil penalties for
pipeline violations from $100,000 per day to $250,000 per day, and from $1 million
for a series of violations to $2.5 million for a series of violations. He is also asking
Congress to help close regulatory loopholes, strengthen risk management
requirements, add more inspectors, and improve data reporting to help identify
potential pipeline safety risks early. The Senate has passed its version of the
pipeline safety reauthorization legislation. The House of Representatives is currently
considering two versions of a similar bill that could be passed by end of the year.
ƒThe U.S. DOT and PHMSA convened a Pipeline Safety Forum in April 2011 that
engaged a working session around the actions that DOT/PHMSA, the state regulatory
agencies, and the pipeline industry can take to drive more aggressive actions to raise
3 | P a g e
the bar on pipeline safety. The U.S. DOT and PHMSA is preparing a report based on
ideas, opportunities and challenges presented at the Forum and action that will be
taken.
x AGGRESSIVE EFFORTS – The U.S. DOT and PHMSA are calling on pipeline operators and owners to
review their pipelines and quickly repair and replace sections in poor condition.
o PHMSA has asked technical associations and pipeline safety groups to provide best
practices and technologies for repair, rehabilitation and replacement programs, and
has asked industry groups for commitments to accelerate needed repairs.
o PHMSA will review all data received from pipeline operators to identify areas with
critical needs.
o PHMSA’s Distribution Integrity Management rule became effective in August,
requiring all operators of local gas distribution pipeline systems to evaluate the risks
on their pipeline systems and take action to address those risks.
x TRANSPARENCY - U.S. DOT and PHMSA will execute this plan in a transparent manner with
opportunity for public engagement, including a dedicated website for this initiative, and
regular reporting to the public.
o PHMSA has launched a public website (http://opsweb.phmsa.dot.gov/pipelineforum),
which describes the ongoing pipeline rehabilitation, replacement and repair
initiatives.
o All materials from the Pipeline Safety Forum will be publicly posted to the web,
followed by a Draft Report for Notice and Comment. Once public input has been
collected, PHMSA will publish a final Pipeline Safety Report to the Nation.
o PHMSA will be holding a national forum on emergency preparedness and response
to pipeline emergencies. The forum will take place December 9, 2011, and will
include the major stakeholders from the emergency response community, industry
and government to discuss how best to improve pipeline emergency preparedness
and response capabilities.
o A report from the forum will be prepared and published.
Revised 11/1/11
###

APPENDIX 18: 1983 LETTER FORM DUPONT REGARDING THE IMPROVED ALDYL "A" SERVICE
PUNCH TEE