DOT Pipeline Compliance News - March 2011 Issue

March 2011 Issue

In This Issue

Texas Issues Final Rule for Mandatory Gas Distribution Facility Replacements

The Railroad Commission of Texas has published new final rules for mandatory steel service line replacements. 16 TAC 8.209 Distribution Facilities Replacements prescribes the minimum requirements by which all gas distribution operators in Texas will develop and implement a risk-based program for the removal or replacement of steel service lines. Gas distribution operators affected by this rule must:

By August 1, 2011 develop and submit to the Railroad Commission their written program intended to comply with the requirements of the new final rule.
Develop a risk analysis program which ranks and prioritizes the highest risk facilities. Elements required to be included in the risk analysis are pipe location, composition of the piping system, corrosion history, environmental factors and any other conditions that would increase the potential or consequences of a leak.
Conduct a leak rate analysis for those steel service line segments that pose the greatest risk.
Complete the removal or replacement of steel service lines that pose the greatest risk within the following timelines:
- By June 30, 2013 for all steel segments with a leak rate of 7.5% or greater (i.e. Priority 1 segment)
- 10% of all steel service line segments each year with leak rates between 5% and 7.5% (i.e. Priority 2 segment)
- Replace (not repair) any service line that experience a leak within a segment with a leak rate less than 5% (i.e. Priority 3 segment)
Replace a minimum of 5% annually of the pipeline segments or facilities that pose the greatest risk.
Provide notice to the Railroad Commission with the schedule of replacements as well as any revisions to its program and replacement work plans.

For more information on how RCP can assist, or to obtain a copy of the preamble and final rule, contact Jessica Roger.

RCP’s Web-Based Compliance Management Systems

CP’s Compliance Management System (CMS) is an invaluable tool for managing all aspects of regulatory workflow. Some examples of how our clients are using the CMS include:

O&M Scheduling and Data Acquisition;
Cathodic Protection Inspection and Data Management;
One-Call Screening and Ticket Management;
Repair / Replacement Programs;
Operator Qualification Administration and Workflow Integration;
Leak Life Cycle Management;
Environmental, Health and Safety Compliance;
Audit Action Item Tracking; and
Customer Data Management.

DIMP Integration

For gas distribution operators looking for a powerful tool to implement DIMP, the RCP CMS integrates O&M data captured from field personnel along with inherent system attributes to provide real-time risk analysis, performance reporting, as well as track additional and accelerated actions taken to mitigate risks.

Key Features

GIS integrated workflow management
Custom tailored e-mail notifications and reporting
Runs on any web-enabled device, no software to download
Powerful reporting and custom query functionality
Multiple security and user privilege settings
Document storage and control (ex. procedures, maps, images, and completion documentation)
Automatic recurrence setting for routine tasks (example: leak surveys, CP surveys, etc.)
Create work orders for unscheduled / unplanned activities (ex. release reporting)

To request a demonstration or to request more information, please contact Jessica Roger.

Advisory Bulletin (ADB-11-02) Dangers of Abnormal Snow & Ice Build-Up on Gas Distribution Systems

The Department of Transportation/Pipeline Hazardous Materials Safety Administration (PHMSA) recently published advisory bulletin ADB-11-02 to advise owners and operators of petroleum gas and natural gas facilities of the need to take the appropriate steps to prevent damage to pipeline facilities from accumulated snow or ice. Past events on natural gas distribution system facilities appear to have been related to either the stress of snow and ice or the malfunction of pressure control equipment due to ice blockage of pressure control equipment vents. PHMSA is advising operators of petroleum gas and natural gas pipeline facilities, regardless of whether those facilities are regulated by PHMSA or state agencies, to consider the following steps to address the safety risks from accumulated snow and ice on pipeline facilities:

Notify customers and other entities of the need for caution associated with excessive accumulation and removal of snow and ice. Notice should include the need to clear snow and ice from exhaust and combustion air vents for gas appliances to: (a) Prevent accumulation of carbon monoxide in buildings; or (b) Prevent operational problems for the combustion equipment.
Pay attention to snow and ice related situations that may cause operational problems for pressure control and other equipment.
Monitor the accumulation of moisture in equipment and snow or ice blocking regulator or relief valve vents which could prevent regulators and relief valves from functioning properly.
The piping on service regulator sets is susceptible to damage that could result in failure if caution is not exercised in cleaning snow from around the equipment. Where possible, use a broom instead of a shovel to clear snow off regulators, meters, associated piping, propane tanks, tubing, gauges or other propane system appurtenances.
Remind the public to contact the gas company or designated emergency response officials if there is an odor of gas present or if gas appliances are not functioning properly. Also, remind the public that they should leave their residence immediately if they detect a gas or propane odor and report the odor to their gas company, propane operator or designated emergency response officials.

For a copy of ADB-11-02, contact Jessica Roger.

PHMSA Updates Gas Distribution Integrity Management FAQ’s

On February 9, 2011, PHMSA published several updates to the pipeline integrity FAQ’s for gas distribution pipelines. The revised FAQ’s are listed below.

A.7 Does the operator report the number of EFVs installed per year or the total number of EFVs installed on an operator’s system on the Annual Report form? Does the number include EFVs installed on services other than single-family residences?
Operators are to report the total number of EFVs installed in the system on service lines serving single-family residences and the estimated number of EFVs in their system at the end of the year. Both metrics are reported on the Annual Report form in Part E – Excess Flow Valve (EFV) Data. Operators may, but are not required, include EFVs installed on branched services serving single-family residences in the total. PHMSA revised the Annual Report form for the 2010 calendar year to accommodate this information.

C.4.b.2 Must each of the 8 threats be considered for every pipeline type?
Yes, an operator’s DIMP plan must consider each of the 8 threats for the pipeline system. The eight threats categories are corrosion, natural forces, excavation damage, other outside force damage, material or welds, equipment failure, incorrect operations, and other concerns that could threaten the integrity of its pipeline. Some threats may not be relevant to all pipe types or all operators’ circumstances. Some threats may apply but are not obvious. For example, corrosion is not a threat to plastic facilities but could be a threat to tracer wires, transition fittings, or to short pieces of metal main or services in a plastic system. Material or weld failures could apply to plastic (the brittle failure issue and potential for faulty fusion joints, for instance). Excavation damage occurs regardless of the pipe material.

C.4.g.1 When must operators start collecting and maintaining records with data needed for performance measures?
Reportable performance measures are to be submitted via the Gas Distribution Annual Report for Calendar Year 2010 which covers activities from January 1, 2010 thru December 31, 2010. The 2010 calendar year Annual Report is due by March 15, 2011.

C.4.g.2 When are performance measures due on Annual Reports?
The reportable performance measures are to be submitted via the 2010 Gas Distribution Annual Report form which is due by March 15, 2011. An operator also must report this information to the state pipeline safety authority if a state exercises jurisdiction over the operator’s pipeline.

Mar. 15, 2011 – Operators use proposed revised Gas Distribution Annual Report form, PHMSA F 7100.1-1 (12-05). It contains fields for reportable performance measures for the 2010 calendar year. Mechanical fitting failures are not to be reported for calendar year 2010.

Mar. 15, 2012 – Annual Report for calendar year 2011 must contain the required data for reportable performance measures from January 1, 2011 thru December 31, 2011.

C.5.4 Since there is a new form for mechanical fitting failures, do these failures still need to be reported under Part C of the Annual Report?
Yes, in addition to the new reporting requirements for hazardous mechanical fitting failures on the new Gas Distribution Mechanical Fitting Failure Form (PHMSA F–7100.1–2), both the number of total leaks and the number of hazardous leaks eliminated or repaired during the year due to mechanical fittings are still reported in “Part C – Total Leaks and Hazardous Leaks Eliminated/Repaired During Year.”

PHMSA created the new Mechanical Fitting Failure Report form [PHMSA F 7100.1-2] to address the new annual reporting requirement established by DIMP for hazardous leaks on mechanical fittings. Mechanical fitting failure reporting is due March 2012 for CY2011, Operators may submit data periodically throughout the year (preferred) or in one submission prior to March of the year following the failure. The online system for the new Mechanical Fitting Failure Report form [PHMSA F 7100.1-2] is now in operation.

NOTE:
Online submission via PHMSA Portal is required unless an alternative reporting method is granted by PHMSA. More information is available at PHMSA’s, Office of Pipeline Safety website, Pipeline Safety Community, and click the “ Online Data Entry” hyperlink listed in the first column.

PHMSA Updates Hazardous Liquid Integrity Management FAQ’s

On February 8, 2011, PHMSA published several updates to the pipeline integrity FAQ’s for hazardous liquid pipelines. The revised FAQ’s are listed below.

7.4 What is an ‘immediate repair condition’?

An immediate repair condition is a detected anomaly involving:

Metal loss greater than 80% of nominal wall regardless of dimensions.
Predicted burst pressure less than the maximum operating pressure at the location of the anomaly. (Where burst pressure has been calculated from the remaining strength of the pipe using a suitable metal loss strength calculation, e.g., ASME/ANSI B31G).
Dents on the top of the pipeline (above 4 and 8 o’clock position) with any indicated metal loss, cracking, or a stress riser.
Dents on top of the pipeline with a depth greater than 6 percent of nominal pipe diameter.
Significant anomaly that in the judgment of the person evaluating the assessment results requires immediate action.

Repairs must be made as soon as practicable. An operator must reduce pressure (to a level calculated using the formula in section 451.6.2.2 (b) of ASME/ANSI B31.4 as applicable (see FAQ 7.15)) as soon as safety allows and operate at or below that pressure until a repair can be made.

7.15 The rule requires that an operator temporarily reduce pressure if an immediate repair condition is discovered (195.452(h)(4)(i)). With respect to this requirement:

a. Can the temporary reduction in operating pressure be based upon previous maximum operating pressures?

No. A reduction in operating pressure is intended to provide an additional safety margin until the defect can be remediated. To assure that additional margin is provided, the pressure reduction must be based upon pressures that the pipe has actually experienced, with the defect present (i.e., pressures for which safety has been demonstrated). These may be well below the “maximum operating pressure” for the pipe.

The rule requires that the pressure reduction must be calculated using the method in section 451.6.2.2 (b) of ANSI/ASME B31.4 if that method is applicable and the information needed is available. If that method cannot be used, the operator is responsible for determining an appropriate basis for assuring additional safety through a reduction in pressure. A reduction of 20 percent below the highest operating pressure actually experienced at the location of the defect within the two months preceding the inspection may provide the necessary additional safety margin.

b. Can the temporary reduction in operating pressure be based on calculations other than those defined in section 451.6.2.2 (b) of ASME/ANSI B31.4?

The method described in section 451.6.2.2 (b) of ASME/ANSI B31.4 is required by the rule and must be used for all circumstances for which it is appropriate (e.g., corrosion). There are anomalies defined by the rule as immediate repair conditions for which the method of section 451.6.2.2 (b) is not applicable (e.g., dents). These are addressed in c. below. PHMSA Pipeline Safety is considering a change to the rule to recognize that section 451.6.2.2 (b) is not applicable to all immediate repair conditions, and may also allow alternative methods for calculating the required reduction in pressure. Until the rule is changed, however, the specified method must be used in all instances in which it applies.

c. Is section 451.6.2.2 (b) of ASME/ANSI B31.4 applicable for calculating the temporary pressure reduction required for top-side dents with metal loss (195.452(h)(4)(i)(C)) and dents greater than 6% of the pipe diameter (195.452(h)(4)(i)(D))?

No. The calculation in Section 451.6.2.2 (b) of ASME/ANSI B31.4 is applicable to determining the remaining strength of pipe with corrosion defects or grind repairs (i.e., loss of wall thickness). Pressure must be reduced for other types of immediate repair conditions, but operators must develop appropriate engineering justification for the amount of pressure reduction. A reduction in operating pressure is intended to provide an additional safety margin until the defect can be remediated. To assure that additional margin is provided, the pressure reduction must be based upon pressures that the pipe has actually experienced, with the defect present (i.e., pressures for which safety has been demonstrated). These may be well below the “maximum operating pressure” for the pipe.

A reduction of 20 percent below the highest operating pressure actually experienced at the location of the defect within the two months preceding the inspection may provide the necessary additional safety margin.

7.20 Is a 20 percent reduction in pressure an adequate interim measure for immediate repair conditions?

A reduction of 20 percent below the highest operating pressure actually experienced at the location of the defect within the period immediately preceding the inspection (e.g., two months) may provide the necessary additional safety margin. Operators should evaluate each situation to determine if additional reduction, or line shutdown, is needed. Operators must use Section 451.6.2.2 (b) of ASME/ANSI B31.4 to calculate the required pressure reduction for all situations in which it applies (as required by 452(h)(4)(i)). See FAQs 7.15 and 7.22 for more information.

7.22 Section 195.452(h)(4)(i) requires that I temporarily reduce pressure in response to an immediate repair condition. The same paragraph also requires that I must calculate the reduction using the formula in section 451.6.2.2 (b) of ASME/ANSI B31.4. If using that formula results in a calculated safe pressure that is higher than my original operating pressure, must I still reduce pressure? To what?

Yes. A pressure reduction is required to provide additional safety margin until an immediate repair condition can be addressed. PHMSA Pipeline Safety expects that situations in which the calculated safe pressure using the formula in section 451.6.2.2 (b) of ASME/ANSI B31.4 is higher than the original operating pressure will be rare. Nevertheless, if the calculated pressure is greater than the existing operating pressure, pressure must still be reduced to provide the necessary margin. Operators should determine the amount of such reduction based on their particular circumstances.

Operators should also note that the specified formula only applies to metal loss anomalies (i.e., corrosion). It does not apply to immediate repair conditions that do not involve metal loss, nor does it apply to dents with metal loss. For those circumstances, operators must determine an acceptable method for calculating an acceptable reduced operating pressure. A reduction of 20 percent below the highest operating pressure actually experienced at the location of the defect within the two months preceding the inspection may provide the necessary additional safety margin.

NTSB Hearing on San Bruno

The National Transportation Safety Board (NTSB) held a 3-day public hearing to gather additional factual information for the ongoing investigation into the natural gas pipeline rupture and explosion that occurred on September 9, 2010, in San Bruno, California. The goal of the hearing was for the Safety Board to learn more about the issues identified in the San Bruno pipeline rupture accident. The Board invited expert witnesses to provide sworn testimony. Additionally, several organizations were granted “party status” to the hearing so that they could question the witnesses directly. The witnesses and parties represented a range of government and industry communities and other officials who provide oversight.

Parties to the public hearing:

Pacific Gas & Electric
California Public Utilities Commission
Pipeline and Hazardous Materials Safety Administration
City of San Bruno
International Brotherhood of Electrical Workers Local 1245

The hearing agenda can be viewed here.

The hearings were webcast and archives are expected to remain available for the next three months. Click here to view the hearing archives.

MAOP Analysis Services

RCP has developed the most comprehensive MAOP analysis model on the market. Using this model, RCP has successfully conducted MAOP analysis for dozens of complex onshore/offshore gathering, transmission, and distribution pipeline systems. The analysis can be performed as a service with the results delivered on a system-by system basis as well as detailed individual record MAOP reports that indicate the regulatory code citation or letter of interpretation that is driving the calculated MAOP value. The MAOP model can also be purchased and configured to run by your personnel using your in-house data sets. For more information, visit www.rcp.com/serv_maop.asp or contact Jessica Roger.

PHMSA Notice of Extension for Comments on Collection of Info for Periodic Underwater Inspections

Docket No. PHMSA–2010–0355

The Federal pipeline safety regulations (49 CFR parts 190–199) require operators to conduct appropriate underwater inspections in the Gulf of Mexico. If an operator finds that its pipeline is exposed on the seabed floor or constitutes a hazard to navigation, the operator must contact the National Response Center by telephone within 24 hours of discovery to report the location of the exposed pipeline.

The Department of Transportation/Pipeline Hazardous Materials Safety Administration (PHMSA) issued a second notice to operators of underwater pipeline facilities (allowing an additional 30 days) to submit comments to the OMB regarding the need for the proposed collection of information for the proper performance of the functions of the agency, including:

whether the information will have practical utility;
the accuracy of the agency’s estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
ways to enhance the quality, utility, and clarity of the information to be collected; and
ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques

Send comments regarding the burden estimate, including suggestions for reducing the burden, to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attn: Desk Officer for DOT/ PHMSA, 725 17th Street, NW, Washington, DC 20503.

Comments are due on or before March 16, 2011.

TPSSC and THLPSSC Meetings

March 24 -25, Arlington, VA

The Technical Pipeline Safety Standards Committee (TPSSC) and the Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC) will meet on Thursday, March 24, 2011 from 9:00 a.m. to 4:00 p.m. and the TPSSC will meet on Friday, March 25, from 9 a.m. to 12:00 p.m. EST. The committees will meet in a joint session on Thursday, March 24 to discuss a proposed rulemaking to expedite the program implementation deadlines for certain control room management requirements.

Location: Crystal City Marriott at Reagan National Airport, 1999 Jefferson Davis Highway, Arlington, VA. For reservations, call 703-413-5500 or you may contact Marriott reservations 1-800-228-9290. The meeting room will be posted at the hotel. A block of rooms is being reserved for Advisory Committee Members only; others may be allowed in the block on a space available basis. Click here for Maps and Directions.

Attendees, click here to register in advance. On-site registration will be available starting at noon on Wednesday at 11:30 a.m. The meeting will not be web cast. Presentations will be available on the meeting website within 30 days following the meeting.

For further information, contact: Cheryl Whetsel by phone at (202) 366-4431 or by e-mail.

Control Room Management Services

RCP is able to provide pipeline operators with fully compliant, customized Control Room Management Programs that take advantage of any existing processes that are currently in place and develop new processes that are tailored to your organization’s ability to successfully implement.

RCP also has the expertise to conduct readiness assessments as well as compliance analysis of your existing Control Room Management programs. This independent analysis will take into consideration what others within the industry are doing as a benchmark as well as what the final regulations require.

For more information on how RCP can help with your Control Room Management Program, contact Jessica Roger.

API Pipeline Conference April 12 – 13

The 62nd annual API Pipeline Conference is being held April 12th and 13th at the Hyatt Regency Hill Country in San Antonio, Texas. The API Pipeline Environmental and Safety Awards will be presented during the luncheon on Wednesday, April 13th. For the Conference program, advance registration, and hotel information click here.

For award program and application information, please go to this API website and scroll down to “API Environmental and Safety Award Program.”

RCP will be there. How about you?

Gas Industry Conferences at a Glance

SGA Spring Gas Conference & Expo
March 15 – 17 at the Charlotte Convention Center in Charlotte, NC
A technical conference for natural gas operators. On March 16th, RCP’s Director of Communications, Amber Pappas, will be discussing Effectiveness Evaluations and their impact on Public Awareness Programs.

AGA Ops Conference & Biennial Exhibit
May 24 -27 at the Gaylord Opryland in Nashville, TN
The annual AGA Operations Conference is the natural gas industry’s premier gathering of natural gas utility and transmission company operations management from across North America and the world for the sharing of technical knowledge, ideas and practices to promote the safe, reliable, and cost-effective delivery of natural gas to the end-user.

RCP will have exhibits at both conferences and hope to see you there!

DOT Pipeline Compliance Workshop – May 10-12, 2011

Join us May 10 – 12 in Houston at our new office and dedicated training facility for an informative, lively, and interactive workshop on DOT Pipeline Compliance and OPA Planning for DOT Pipelines. This workshop has been attended by hundreds of pipeline personnel, with excellent feedback. The workshop provides an overview of the DOT pipeline regulations, and is appropriate for people who are new to pipeline regulations, who could use a refresher, or anyone who needs to know the latest information in these areas.

PROGRAM SCHEDULE:

Day 1 (May 10): Gas Pipeline Regulations (49CFR192)
The workshop will include an introduction to DOT/OPS pipeline compliance; State and Federal program variations; roles and responsibilities; design, construction, operations, maintenance, and emergency response requirements; how to monitor rulemaking activity and stay current with your compliance program; operator qualification, public awareness; with a specific emphasis on the gas integrity management regulations. Each attendee will receive general training materials which include the applicable DOT 49 CFR 192 regulations for gas pipelines (cd-rom), inspection checklists, and speaker’s PowerPoint presentation handouts.

Day 2 (May 11): Special Topics
Back by popular demand! RCP is conducting a special workshop day to discuss topics that many of our clients have expressed an interest in. The workshop topics will include: Control Room Management, Public Awareness Program Effectiveness Evaluations, and Revised Reporting Requirements.

Day 3 (May 12): Liquid Pipeline Regulations (49CFR195)
The workshop will include an introduction to DOT/OPS pipeline compliance; State and Federal program variations, roles and responsibilities; design, construction, operations, maintenance, and emergency response requirements; spill response planning requirements; how to monitor rulemaking activity and stay current with your compliance program; operator qualification and public awareness. Each attendee will receive general training materials which include the applicable DOT 49 CFR 195 regulations for hazardous liquid pipelines (cd-rom), inspection checklists, and speaker’s PowerPoint presentation handouts.

To register, or for additional information, click here.

CGA Excavation Safety Conference & Expo March 8 -10

The CGA Excavation Safety Conference & Expo will take place on March 8 – 10, 2011 in Orlando, Florida. Excavation safety and the protection of buried infrastructure is the shared responsibility of all stakeholder groups. This Conference brings together stakeholders from throughout the industry to share ideas, learn from the experts and gather information on industry trends and technologies. RCP’s Director of Communications, Amber Pappas, will attend this conference and speak on Wednesday, March 9th at 3:00 PM about using GPS for damage prevention purposes.

National Safe Digging Month

April 2011 will once again be National Safe Digging Month (NSDM), the time of year when all Common Ground Alliance (CGA) stakeholders come together to communicate how important it is that professionals and homeowners alike call 811 and follow the safe digging process to help prevent injuries, property damage and inconvenient outages.

To assist damage prevention stakeholders in the promoting NSDM, the CGA has created a full suite of tools. For more information on how you can participate, see the call811 website.

RCP Continues to Add More Firepower to its Staff

David White, who recently retired from BP Pipelines (North America) as a Regulatory Compliance Coordinator, has joined RCP as a Senior Advisor. Dave brings a wealth of pipeline industry knowledge and regulatory expertise, particularly in Control Room Management and Chemical Facility Anti-Terrorism Standards (CFATS). We are looking forward to his valuable contributions to RCP and our clients.

Bill Byrd signature
W. R. (Bill) Byrd, PE
President
RCP Inc.

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