Pipeline Safety: Public Meeting on Applying, Interpreting, and Evaluating Data From In-Line Inspection Devices, 35153-35155 [05-11866]

Download as PDF Federal Register / Vol. 70, No. 115 / Thursday, June 16, 2005 / Notices commenter also set forth a series of reasons why he believes generally that nonprofessional access fees for online investors should be eliminated, noting that he has enumerated these reasons in comment letters to the Commission in the past. The Commission notes that the continuance of fees for the data products included in NASD Rule 7030 is not the subject of the proposed rule change, although a different pricing structure for the fees charged to distributors for the Nasdaq Market Index, which is being moved from NASD Rule 7030 to Rule 7010, is being proposed. With respect to the commenter’s more general concerns about nonprofessional access fees for online investors, the Commission notes that it has recently solicited public comment as part of a comprehensive review it has undertaken regarding market data fees and revenues,13 and the commenter’s views will be taken into account in that review. IV. Conclusion It is therefore ordered, pursuant to section 19(b)(2) of the Act,14 that the proposed rule change (SR–NASD–2004– 185), as amended, is approved. For the Commission, by the Division of Market Regulation, pursuant to delegated authority.15 J. Lynn Taylor, Assistant Secretary. [FR Doc. 05–11927 Filed 6–15–05; 8:45 am] SSS Form 160, Request for Overseas Job Assignment SSS Form 163, Employment Verification Form SSS Form 164, Alternative Service Worker Travel Reimbursement Request SSS Form 166, Claim for Reimbursement for Emergency Medical Care Copies of the above identified forms can be obtained upon written request to the Selective Service System, Reports Clearance Officer, 1515 Wilson Boulevard, Arlington, Virginia, 22209– 2425. No changes have been made to the above identified forms. OMB clearance is limited to requesting a three-year extension of the current expiration dates. Written comments should be sent within 60 days after the publication of this notice, to: Selective Service System, Reports Clearance Officer, 1515 Wilson Boulevard, Arlington, Virginia, 22209– 2425. A copy of the comments should be sent to Office of Information and Regulatory Affairs, Attention: Desk Officer, Selective Service System, Office of Management and Budget, New Executive Office Building, Room 3235, Washington, DC 20435. Dated: June 1, 2005. William A. Chatfield, Director. [FR Doc. 05–11896 Filed 6–15–05; 8:45 am] BILLING CODE 8015–01–M BILLING CODE 8010–01–P DEPARTMENT OF TRANSPORTATION SELECTIVE SERVICE SYSTEM Forms Submitted to the Office of Management and Budget for Extension of Clearance The following forms have been sumbitted to the Office of Management and Budget (OMB) for extension of clearance in compliance with the Paperwork Reduction Act (44 U.S. Chapter 35): SSS Form No. and Title: SSS Form 152, Alternative Service Employment Agreement SSS Form 153, Employer Data Sheet SSS Form 156, Skills Questionnaire SSS Form 157, Alternative Service Job Data Form 13 See Securities Exchange Act Release No. 50700 (Nov. 18, 2004), 69 FR 71256 (Dec. 8, 2004). See also Securities Exchange Act Release No. 50699 (Nov. 18, 2004), 69 FR 71126 (Dec. 8, 2004). 14 15 U.S.C. 78s(b)(2). 15 17 CFR 200.30–3(a)(12). 15:42 Jun 15, 2005 Jkt 205001 [Docket No. PHMSA–03–14455] Pipeline Safety: Public Meeting on Applying, Interpreting, and Evaluating Data From In-Line Inspection Devices Selective Service System. ACTION: Notice. AGENCY: VerDate jul<14>2003 Pipeline and Hazardous Materials Safety Administration Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, DOT. ACTION: Notice; public meeting. AGENCY: SUMMARY: The Pipeline and Hazardous Materials Safety Administration’s Office of Pipeline Safety (OPS) is hosting a public meeting to discuss concerns it has with how operators are applying, interpreting, and evaluating data acquired from In-Line Inspection Devices (ILI), and OPS’s expectations about how operators should be effectively integrating this data with other information about the operator’s pipeline. The meeting will be held Thursday, August 11, 2005, in Houston, TX, and is open to all interested parties. PO 00000 Frm 00092 Fmt 4703 Sfmt 4703 35153 The public meeting will be held Thursday, August 11, 2005, from 8:30 a.m. to 4.30 p.m. ADDRESSES: The meeting will be held in Houston, TX. The meeting location has not been determined yet and will be made available on https://ops.dot.gov shortly. FOR FURTHER INFORMATION CONTACT: Joy Kadnar (PHMSA/OPS) at 202–366– 0568; joy.kadnar@dot.gov, regarding the subject matter of this notice. For information regarding meeting logistics, please contact Veronica Garrison at (202) 366–4996; veronica.garrison@dot.gov or Janice Morgan at (202) 366–2392; janice.morgan@dot.gov. SUPPLEMENTARY INFORMATION: Subsequent to information acquired from integrity management program inspections and problems discovered during accident investigations, OPS has become concerned with performance issues associated with in-line inspection devices and how the data from these devices is being integrated with other information on the pipeline system. So that OPS can share these concerns in a public forum, OPS invites public participation in a meeting to be held Thursday, August 11, 2005, to discuss the characterization—discrimination, interpretation, and evaluation—of data acquired from ILI devices. ILI technology has been used for approximately 20 years and has become the preferred method used by pipeline operators to ensure the integrity of their pipeline assets. However, as demonstrated by recent accidents on hazardous liquid and natural gas pipeline systems, some pipelines that were inspected by ILI devices continue to fail. OPS will share its findings from these accidents and from recent Integrity Management Program (IMP) inspections. OPS needs to determine if the problem resides in the technology or in the secondary and tertiary stages of the ILI data evaluation—data characterization, validation, and mitigation. Specifically, is the problem data analysis, peer review of technicians involved in data review, lack of common standards for data review, detection thresholds, data validation, or the understanding of each tool’s strengths and weaknesses? A secondary objective of this meeting is for OPS to understand how the government, pipeline operators, standards organizations, and ILI vendors can help improve pipeline assessment using ILI technology. At this public meeting, OPS will highlight effective practices and use this medium to share these practices with the public. DATES: E:\FR\FM\16JNN1.SGM 16JNN1 35154 Federal Register / Vol. 70, No. 115 / Thursday, June 16, 2005 / Notices The preliminary agenda for this meeting includes briefings on the following topics: • OPS’s Experiences on Data Extracted using ILI Devices. • OPS Case Studies. • Hazardous Liquid IMP Inspection Experiences. • Views of Pipeline Operators. • Perspective from ILI Vendors. • Focus of Independent ILI Data Analysts. • ILI Standards— —Personnel Qualification and Vendor Reports; —ILI Flaw Detection Criteria; —ILI Data Discrimination; —Field Evaluation of ILI Data— Statistical Sampling, Flaw Thresholds, and Tolerances; —Contractual Criteria for Defect Reports. • Next Steps. Background ILI is the preferred technology to assure pipeline integrity. The OPS IMP inspections have revealed that many operators elect to use ILI devices to inspect their ‘‘piggable’’ pipeline sections to evaluate the condition of the pipe wall. OPS also found that many pipeline operators now use highresolution and deformation ILI tools. OPS is concerned about the secondary and tertiary evaluations being performed after ILI data is acquired because of several accidents that have occurred throughout the U.S. in the recent past. According to OPS’s experience, failures have occurred on pipelines inspected by all types of ILI tools. The following are some examples of pipelines that failed relatively soon after the pipelines were inspected, the data was analyzed, and the findings were reported to the pipeline operators: • In 1999, a small hazardous liquid pipeline operator used a state-of-the-art tool and mischaracterized a ‘‘wrinkle with a crack’’ as a ‘‘T-piece.’’ A few months later the pipeline ruptured at the location of this wrinkle. Most appurtenances and fittings like a TPiece will be welded to the main pipe. However, there were no girth welds on either side of this mischaracterized Tpiece as is typical for a T-piece. • In 2003, a hazardous liquid pipeline that was inspected just about a year before, failed in service. OPS’s investigation revealed that general corrosion caused the failure. On analyzing the data, OPS gathered that the ILI tool detected some pitting and the maximum pit depth was reported to be less that 50% of remaining wall. However, from a metallurgical analysis of the pipe segment OPS discovered 27 VerDate jul<14>2003 15:42 Jun 15, 2005 Jkt 205001 corrosion pits varying from 18% wall loss to 95% wall loss. The pipe failed where the wall loss was 95%. • In February 2004, a natural gas pipeline operator launched a geometry pig but the tool missed a series of wrinkles. One of those wrinkles ruptured. During our post-incident investigation OPS discovered that other wrinkles in the pipe were called out as pipe wall thickness changes although there were no girth welds adjacent to the location where the wall thickness changed. • Another hazardous liquid pipeline that was inspected seven times with different tools in a span of 10 years ruptured in 2004. The rupture was determined to have been caused by general corrosion. The general corrosion was detected by an ILI tool launched before the most recent ILI run. • In October 2004, a hazardous liquid pipeline operator launched three tools— a geometry pig, a corrosion detection pig, and an axial flaw detection pig—in relative succession to conduct a baseline assessment and to comply with the IMP regulations. About six months after these tools were launched, the pipeline’s seam split. • In November 2003, incipient third party damage caused another hazardous liquid pipeline to rupture just eight months after it was pigged. Our investigation revealed several longitudinal scratches and gouges on the pipe surface that were undetected by the ILI device. From our IMP inspections, OPS has also learned that pipeline operators do not have a consistent, standardized process to evaluate and assess data extracted by ILI devices. For example, some pipeline operators provide guidance to ILI vendors, contract field inspection personnel, and company personnel on how to assess ILI data. Others rely entirely on the ILI vendor or may actively participate in data extraction, or may even conduct an independent peer review of the ILI data if they have in-house expertise. For corrosion anomalies, pipeline operators use different interaction criteria. Some pipeline operators want only the deepest pit reported on each pipe length. Others want all pit depths reported. One pipeline operator directed the ILI vendor to report all anomalies, especially those with signatures that are indecipherable. OPS believes this to be a good practice, although it is not universally applied. OPS believes that most of the pipeline failures that occurred on pipeline segments that were inspected with ILI tools could have been prevented with the correct application of technology. PO 00000 Frm 00093 Fmt 4703 Sfmt 4703 The failures that OPS investigated have revealed that the larger problem may be with the machine-man interface during the latter stages of data analyses. Specifically, should the repositories of flaw signatures that ILI vendors use be improved? Must there be more attention expended on the peer review of technicians? Is the sample size used to confirm electronic data adequate or must it be increased? Should the data extraction process be more stringently monitored? Pipeline operators use a variety of surveying, monitoring, and testing practices to assure the integrity of their assets. Different practices may be used independently, or as supplements to others to assess pipeline integrity. ILI is just one of many integrity assurance practices used by the pipeline industry. An ILI using a smart device is one method to interrogate the pipe wall to detect irregularities that could decrease the pressure containment strength of the pipe. An ILI device is a computerized, selfcontained device that is inserted into the pipeline. These ILI devices are propelled forward by the fluid flowing through the pipeline and record information of the pipe wall as they travel through the pipeline. An ILI tool can detect, measure, record, and display irregularities in the pipe wall. These irregularities may represent corrosion, cracks, laminations, geometric deformations (dents, gouges, ovality, wrinkles, ripples, buckles), and other defects. Specialized ‘‘smart pigs’’ rely on various technologies to detect and determine the existence and severity of features in the pipeline. Corrosion tools use a magnetic field or ultra-sound to detect and record changes in the wall thickness of the pipe (crack detection tools most commonly use ultrasound) generating a signal into the pipe wall, which, based on how the signal is reflected back, detects cracks. Geometry tools examine a number of characteristics using mechanical fingers or electromagnetic waves to measure deviations in a pipeline’s internal diameter or to show the position of dents in the pipe. OPS is concerned that some pipelines continue to fail after being inspected by ILI tools. OPS will discuss its concerns at this public forum and share its expectations on how operators integrate this data. During this public meeting, OPS will seek answers to the following questions: • What are operators’ experiences and expectations with the capabilities of ILI technology? E:\FR\FM\16JNN1.SGM 16JNN1 Federal Register / Vol. 70, No. 115 / Thursday, June 16, 2005 / Notices • Is there a gap in understanding ILI tool data submitted by vendors of this technology? • Do ILI technology vendors educate their clients about the limitations of the tool being recommended for the application? • What defect detection and report criteria are used? Is it developed jointly by the vendor and the pipeline operator? • How are tool defect identification tolerances applied in reported criteria? • Is there a formal detection, validation, and mitigation process used to evaluate defects? How is it communicated to the pipeline operator? • What process is used to arrive at the number of confirmatory digs to corroborate the data extracted by the ILI device? • Are the standards developed for ILI technology appropriate for the current state ILI deployment? Does the guidance meet the needs of the large or small pipeline operator who is the first-time user of such technology? OPS expects at this public meeting to inform on the following: • The technique and criteria used to report defects; • Information exchange between the ILI vendor and pipeline operator during the secondary and tertiary stages of flaw characterization; • The currency and adequacy of performance standards for vendors of assessment technologies; • Sufficiency and relevance of performance standards for ILI assessment technology; and • Stages in data discrimination: Detection, validation, and mitigation. Issued in Washington, DC, on June 10, 2005. Joy Kadnar, Director of Engineering and Emergency Support, Office of Pipeline Safety. [FR Doc. 05–11866 Filed 6–15–05; 8:45 am] BILLING CODE 4910–60–P DEPARTMENT OF TRANSPORTATION Surface Transportation Board [STB Docket No. AB–70 (Sub-No. 5X] Florida East Coast Railway, L.L.C.— Abandonment Exemption—in Brevard County, FL Florida East Coast Railway, L.L.C. (FEC) has filed a notice of exemption under 49 CFR 1152 Subpart F—Exempt Abandonments to abandon a 9.8-mile line of railroad known as the Titusville Branch, extending from milepost TB 0.0 in Titusville to milepost TB 9.8 in Aurantia, in Brevard County, FL. The VerDate jul<14>2003 15:42 Jun 15, 2005 Jkt 205001 35155 line traverses United States Postal Service Zip Codes 32754 and 32796. FEC has certified that: (1) No local traffic has moved over the line for at least 2 years; (2) there is no overhead traffic to be rerouted; (3) no formal complaint filed by a user of rail service on the line (or by a State or local government entity acting on behalf of such user) regarding cessation of service over the line, either is pending with the Board or with any U.S. District Court or has been decided in favor of complainant within the 2-year period; and (4) the requirements at 49 CFR 1105.7 (environmental reports), 49 CFR 1105.8 (historic reports), 49 CFR 1105.11 (transmittal letter), 49 CFR 1105.12 (newspaper publication), and 49 CFR 1152.50(d)(1) (notice to governmental agencies) have been met. As a condition to this exemption, any employee adversely affected by the abandonment shall be protected under Oregon Short Line R. Co.— Abandonment—Goshen, 360 I.C.C. 91 (1979). To address whether this condition adequately protects affected employees, a petition for partial revocation under 49 U.S.C. 10502(d) must be filed. Provided no formal expression of intent to file an offer of financial assistance (OFA) has been received, this exemption will be effective on July 16, 2005, unless stayed pending reconsideration. Petitions to stay that do not involve environmental issues,1 formal expressions of intent to file an OFA under 49 CFR 1152.27(c)(2),2 and trail use/rail banking requests under 49 CFR 1152.29 must be filed by June 27, 2005. Petitions to reopen or requests for public use conditions under 49 CFR 1152.28 must be filed by July 6, 2005, with the Surface Transportation Board, 1925 K Street, NW., Washington, DC 20423–0001. A copy of any petition filed with the Board should be sent to FEC’s representative: Marlene Hammock, Assistant Secretary, Florida East Coast Railway, L.C.C., One Malaga Street, St. Augustine, FL 32085–1048. If the verified notice contains false or misleading information, the exemption is void ab initio. FEC has filed an environmental and historic report which addresses the abandonment’s effects, if any, on the environment and historic resources. SEA will issue an environmental assessment (EA) by June 21, 2005. Interested persons may obtain a copy of the EA by writing to SEA (Room 500, Surface Transportation Board, Washington, DC 20423–0001) or by calling SEA, at (202) 565–1539. [Assistance for the hearing impaired is available through the Federal Information Relay Service (FIRS) at 1– 800–877–8339.] Comments on environmental and historic preservation matters must be filed within 15 days after the EA becomes available to the public. Environmental, historic preservation, public use, or trail use/rail banking conditions will be imposed, where appropriate, in a subsequent decision. Pursuant to the provisions of 49 CFR 1152.29(e)(2), FEC shall file a notice of consummation with the Board to signify that it has exercised the authority granted and fully abandoned the line. If consummation has not been effected by FEC’s filing of a notice of consummation by June 16, 2006, and there are no legal or regulatory barriers to consummation, the authority to abandon will automatically expire. Board decisions and notices are available on our Web site at https:// www.stb.dot.gov. 1 The Board will grant a stay if an informed decision on environmental issues (whether raised by a party or by the Board’s Section of Environmental Analysis (SEA) in its independent investigation) cannot be made before the exemption’s effective date. See Exemption of Outof-Service Rail Lines, 5 I.C.C. 2d 377 (1989). Any request for a stay should be filed as soon as possible so that the Board may take appropriate action before the exemption’s effective date. 2 Each OFA must be accompanied by the filing fee, which currently is set at $1,200. See 49 CFR 1002.2(f)(25). Office of Thrift Supervision PO 00000 Frm 00094 Fmt 4703 Sfmt 4703 Decided: June 6, 2005. By the Board, David M. Konschnik, Director, Office of Proceedings. Vernon A. Williams, Secretary. [FR Doc. 05–11640 Filed 6–15–05; 8:45 am] BILLING CODE 4915–01–P DEPARTMENT OF THE TREASURY Office of the Comptroller of the Currency FEDERAL RESERVE SYSTEM FEDERAL DEPOSIT INSURANCE CORPORATION DEPARTMENT OF THE TREASURY Agency Information Collection Activities; Submission for OMB Review; Comment Request Concerning the Interagency Bank Merger Act Application Office of the Comptroller of the Currency (OCC), Treasury; Board of Governors of the Federal Reserve AGENCIES: E:\FR\FM\16JNN1.SGM 16JNN1

Agencies

[Federal Register Volume 70, Number 115 (Thursday, June 16, 2005)]
[Notices]
[Pages 35153-35155]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-11866]


=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

[Docket No. PHMSA-03-14455]


Pipeline Safety: Public Meeting on Applying, Interpreting, and 
Evaluating Data From In-Line Inspection Devices

AGENCY: Office of Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, DOT.

ACTION: Notice; public meeting.

-----------------------------------------------------------------------

SUMMARY: The Pipeline and Hazardous Materials Safety Administration's 
Office of Pipeline Safety (OPS) is hosting a public meeting to discuss 
concerns it has with how operators are applying, interpreting, and 
evaluating data acquired from In-Line Inspection Devices (ILI), and 
OPS's expectations about how operators should be effectively 
integrating this data with other information about the operator's 
pipeline. The meeting will be held Thursday, August 11, 2005, in 
Houston, TX, and is open to all interested parties.

DATES: The public meeting will be held Thursday, August 11, 2005, from 
8:30 a.m. to 4.30 p.m.

ADDRESSES: The meeting will be held in Houston, TX. The meeting 
location has not been determined yet and will be made available on 
https://ops.dot.gov shortly.

FOR FURTHER INFORMATION CONTACT: Joy Kadnar (PHMSA/OPS) at 202-366-
0568; joy.kadnar@dot.gov, regarding the subject matter of this notice. 
For information regarding meeting logistics, please contact Veronica 
Garrison at (202) 366-4996; veronica.garrison@dot.gov or Janice Morgan 
at (202) 366-2392; janice.morgan@dot.gov.

SUPPLEMENTARY INFORMATION: Subsequent to information acquired from 
integrity management program inspections and problems discovered during 
accident investigations, OPS has become concerned with performance 
issues associated with in-line inspection devices and how the data from 
these devices is being integrated with other information on the 
pipeline system. So that OPS can share these concerns in a public 
forum, OPS invites public participation in a meeting to be held 
Thursday, August 11, 2005, to discuss the characterization--
discrimination, interpretation, and evaluation--of data acquired from 
ILI devices.
    ILI technology has been used for approximately 20 years and has 
become the preferred method used by pipeline operators to ensure the 
integrity of their pipeline assets. However, as demonstrated by recent 
accidents on hazardous liquid and natural gas pipeline systems, some 
pipelines that were inspected by ILI devices continue to fail.
    OPS will share its findings from these accidents and from recent 
Integrity Management Program (IMP) inspections. OPS needs to determine 
if the problem resides in the technology or in the secondary and 
tertiary stages of the ILI data evaluation--data characterization, 
validation, and mitigation. Specifically, is the problem data analysis, 
peer review of technicians involved in data review, lack of common 
standards for data review, detection thresholds, data validation, or 
the understanding of each tool's strengths and weaknesses? A secondary 
objective of this meeting is for OPS to understand how the government, 
pipeline operators, standards organizations, and ILI vendors can help 
improve pipeline assessment using ILI technology. At this public 
meeting, OPS will highlight effective practices and use this medium to 
share these practices with the public.

[[Page 35154]]

    The preliminary agenda for this meeting includes briefings on the 
following topics:
     OPS's Experiences on Data Extracted using ILI Devices.
     OPS Case Studies.
     Hazardous Liquid IMP Inspection Experiences.
     Views of Pipeline Operators.
     Perspective from ILI Vendors.
     Focus of Independent ILI Data Analysts.
     ILI Standards--

    --Personnel Qualification and Vendor Reports;
    --ILI Flaw Detection Criteria;
    --ILI Data Discrimination;
    --Field Evaluation of ILI Data--Statistical Sampling, Flaw 
Thresholds, and Tolerances;
    --Contractual Criteria for Defect Reports.
     Next Steps.

Background

    ILI is the preferred technology to assure pipeline integrity. The 
OPS IMP inspections have revealed that many operators elect to use ILI 
devices to inspect their ``piggable'' pipeline sections to evaluate the 
condition of the pipe wall. OPS also found that many pipeline operators 
now use high-resolution and deformation ILI tools.
    OPS is concerned about the secondary and tertiary evaluations being 
performed after ILI data is acquired because of several accidents that 
have occurred throughout the U.S. in the recent past. According to 
OPS's experience, failures have occurred on pipelines inspected by all 
types of ILI tools. The following are some examples of pipelines that 
failed relatively soon after the pipelines were inspected, the data was 
analyzed, and the findings were reported to the pipeline operators:
     In 1999, a small hazardous liquid pipeline operator used a 
state-of-the-art tool and mischaracterized a ``wrinkle with a crack'' 
as a ``T-piece.'' A few months later the pipeline ruptured at the 
location of this wrinkle. Most appurtenances and fittings like a T-
Piece will be welded to the main pipe. However, there were no girth 
welds on either side of this mischaracterized T-piece as is typical for 
a T-piece.
     In 2003, a hazardous liquid pipeline that was inspected 
just about a year before, failed in service. OPS's investigation 
revealed that general corrosion caused the failure. On analyzing the 
data, OPS gathered that the ILI tool detected some pitting and the 
maximum pit depth was reported to be less that 50% of remaining wall. 
However, from a metallurgical analysis of the pipe segment OPS 
discovered 27 corrosion pits varying from 18% wall loss to 95% wall 
loss. The pipe failed where the wall loss was 95%.
     In February 2004, a natural gas pipeline operator launched 
a geometry pig but the tool missed a series of wrinkles. One of those 
wrinkles ruptured. During our post-incident investigation OPS 
discovered that other wrinkles in the pipe were called out as pipe wall 
thickness changes although there were no girth welds adjacent to the 
location where the wall thickness changed.
     Another hazardous liquid pipeline that was inspected seven 
times with different tools in a span of 10 years ruptured in 2004. The 
rupture was determined to have been caused by general corrosion. The 
general corrosion was detected by an ILI tool launched before the most 
recent ILI run.
     In October 2004, a hazardous liquid pipeline operator 
launched three tools--a geometry pig, a corrosion detection pig, and an 
axial flaw detection pig--in relative succession to conduct a baseline 
assessment and to comply with the IMP regulations. About six months 
after these tools were launched, the pipeline's seam split.
     In November 2003, incipient third party damage caused 
another hazardous liquid pipeline to rupture just eight months after it 
was pigged. Our investigation revealed several longitudinal scratches 
and gouges on the pipe surface that were undetected by the ILI device.
    From our IMP inspections, OPS has also learned that pipeline 
operators do not have a consistent, standardized process to evaluate 
and assess data extracted by ILI devices. For example, some pipeline 
operators provide guidance to ILI vendors, contract field inspection 
personnel, and company personnel on how to assess ILI data. Others rely 
entirely on the ILI vendor or may actively participate in data 
extraction, or may even conduct an independent peer review of the ILI 
data if they have in-house expertise.
    For corrosion anomalies, pipeline operators use different 
interaction criteria. Some pipeline operators want only the deepest pit 
reported on each pipe length. Others want all pit depths reported. One 
pipeline operator directed the ILI vendor to report all anomalies, 
especially those with signatures that are indecipherable. OPS believes 
this to be a good practice, although it is not universally applied.
    OPS believes that most of the pipeline failures that occurred on 
pipeline segments that were inspected with ILI tools could have been 
prevented with the correct application of technology. The failures that 
OPS investigated have revealed that the larger problem may be with the 
machine-man interface during the latter stages of data analyses. 
Specifically, should the repositories of flaw signatures that ILI 
vendors use be improved? Must there be more attention expended on the 
peer review of technicians? Is the sample size used to confirm 
electronic data adequate or must it be increased? Should the data 
extraction process be more stringently monitored?
    Pipeline operators use a variety of surveying, monitoring, and 
testing practices to assure the integrity of their assets. Different 
practices may be used independently, or as supplements to others to 
assess pipeline integrity. ILI is just one of many integrity assurance 
practices used by the pipeline industry. An ILI using a smart device is 
one method to interrogate the pipe wall to detect irregularities that 
could decrease the pressure containment strength of the pipe.
    An ILI device is a computerized, self-contained device that is 
inserted into the pipeline. These ILI devices are propelled forward by 
the fluid flowing through the pipeline and record information of the 
pipe wall as they travel through the pipeline. An ILI tool can detect, 
measure, record, and display irregularities in the pipe wall. These 
irregularities may represent corrosion, cracks, laminations, geometric 
deformations (dents, gouges, ovality, wrinkles, ripples, buckles), and 
other defects.
    Specialized ``smart pigs'' rely on various technologies to detect 
and determine the existence and severity of features in the pipeline. 
Corrosion tools use a magnetic field or ultra-sound to detect and 
record changes in the wall thickness of the pipe (crack detection tools 
most commonly use ultrasound) generating a signal into the pipe wall, 
which, based on how the signal is reflected back, detects cracks. 
Geometry tools examine a number of characteristics using mechanical 
fingers or electromagnetic waves to measure deviations in a pipeline's 
internal diameter or to show the position of dents in the pipe.
    OPS is concerned that some pipelines continue to fail after being 
inspected by ILI tools. OPS will discuss its concerns at this public 
forum and share its expectations on how operators integrate this data. 
During this public meeting, OPS will seek answers to the following 
questions:
     What are operators' experiences and expectations with the 
capabilities of ILI technology?

[[Page 35155]]

     Is there a gap in understanding ILI tool data submitted by 
vendors of this technology?
     Do ILI technology vendors educate their clients about the 
limitations of the tool being recommended for the application?
     What defect detection and report criteria are used? Is it 
developed jointly by the vendor and the pipeline operator?
     How are tool defect identification tolerances applied in 
reported criteria?
     Is there a formal detection, validation, and mitigation 
process used to evaluate defects? How is it communicated to the 
pipeline operator?
     What process is used to arrive at the number of 
confirmatory digs to corroborate the data extracted by the ILI device?
     Are the standards developed for ILI technology appropriate 
for the current state ILI deployment? Does the guidance meet the needs 
of the large or small pipeline operator who is the first-time user of 
such technology?
    OPS expects at this public meeting to inform on the following:
     The technique and criteria used to report defects;
     Information exchange between the ILI vendor and pipeline 
operator during the secondary and tertiary stages of flaw 
characterization;
     The currency and adequacy of performance standards for 
vendors of assessment technologies;
     Sufficiency and relevance of performance standards for ILI 
assessment technology; and
     Stages in data discrimination: Detection, validation, and 
mitigation.

    Issued in Washington, DC, on June 10, 2005.
Joy Kadnar,
Director of Engineering and Emergency Support, Office of Pipeline 
Safety.
[FR Doc. 05-11866 Filed 6-15-05; 8:45 am]
BILLING CODE 4910-60-P