Missouri Public Service Commission
Natural Gas Safety Interpretations, Positions,
and Regulatory Information
March 1998
Missouri Public Service Commission
Natural Gas Safety Interpretations, Positions, and Regulatory Information
TABLE OF CONTENTS
1987-1
1991-1
1992-1
1994-1
1994-2
1995-1
1995-2
1995-3
1995-4
1995-5
1995-6
1996-1
1996-2
1997-1
1998-1
Over-Pressure Protection of Take-Point Feeder Lines...... 1
Line Marker Telephone Numbers...... 1
Recommended Practices for Checking Combustible Gas
Indicators and Flame Ionization Equipment for Accuracy...... 1
Pressure Regulating Stations; Farm Taps...... 2
Natural Disaster Report Form...... 3
Leaks on Aboveground Pipelines or Fuel Lines...... 4
Transmission Line Definition...... 6
Master Meter Definition...... 6
Leak Response Time...... 8
Maximum Safe Value...... 9
Testing Criteria for Evaluating the Performance of
Service Regulators...... 9
Information on Municipal Natural Gas Operators Operating
Outside of City Limits...... 10
Staff Review of Federal Regulation: 49 CFR §192.16...... 11
Polyethylene (PE) Backfill...... 12
General Guidelines for Boring (Drilling, Moling, etc.) of
Polyethylene Pipe Near Sewer Lines...... 13
Figures, Tables, and Supplemental Information...... Appendix
Missouri Public Service Commission
Natural gas Safety Interpretations, Positions, and Regulatory Information
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1987-1) Over Pressure Protection of Take-Point Feeder Lines (Distributed March 20, 1987)
Pursuant to several field inspections, the Missouri Public Service Commission’s pipeline safety staff (Staff) became aware of a potential safety hazard regarding over-pressure protection of take-point feeder lines.
The Staff found that several distribution operators did not know what their supplier’s over-pressure protection equipment set point and/or capacities were, even though the supplier’s equipment provided the only protection for certain distribution take-point feeder lines. Following discussions with the U.S. DOT Office of Pipeline Safety Central Region office, the Staff arrived at the following enforcement positions concerning this matter.
1)The natural gas supplier is responsible for providing pressure regulation and over-pressure protection to the upper limit of the delivery contract. Verification of the proper capacities and operating set points of over-pressure protection equipment should be provided to you on an “annual” basis.
2)If the MAOP of the distribution operator’s facilities downstream of the delivery take-point are or become less than the contract’s upper pressure limit, then the distribution operator is responsible for the over-pressure protection equipment unless the supplier is willing to provide such as a part of the delivery contact.
3)The above code compliance requirements will be actively monitored by the Staff during pipeline safety inspections. Any compliance problems related to item #1 will be forwarded to the DOT OPS Central Region Office for appropriate action.
1991-1)Line Marker Telephone Numbers(Distributed December 23, 1991)
Please be advised that 4 CSR 240-40.030(13)(E)4.B. [192.707(d)(2)] requires each line marker to have the name of the operator and telephone number (including area code) where the operator can be reached at all times. The Staff recommends that the One-Call telephone number be used with the “Call Before You Dig” warning; however, the operator’s emergency telephone number is required to be on the line marker for the report of emergencies.
1992-1)Recommended Practices for Checking Combustible Gas Indicators (CGI’s) and Flame Ionization (FI) Equipment for Accuracy(Distributed December 31, 1992)
During 1992, the Gas Safety Staff identified what it believed to be a potential problem involving numerous operators regarding the use of natural gas detection equipment that is not being checked/verified for accuracy on a frequent basis. The Staff found that some operators checked their instruments for accuracy before each day’s use, others never checked their equipment, while still others conducted tests at frequencies that fell somewhere between these two. The Staff polled various manufacturers and/or persons who conduct leak surveys commercially to see if they had any general recommended practices for checking of gas detection equipment for accuracy. Their recommendations ranged from a maximum of before each days use, to a minimum of monthly. The following is a brief synopsis of these recommended practices:
Heath -Heath has no written procedures, however, they recommend that operators check their CGI’s for accuracy on the LEL and 100% scales at least weekly;
MSA -For liability purposes they recommend daily checks of the CGI’s for accuracy on the LEL and 100% gas scales. In the “real world” they recommend at least weekly checks;
Scott/Davis - Their written procedures suggest that the CGI’s be checked for accuracy on the LEL and 100% scales at least monthly;
Bacharach - For liability purposes they do not have any written procedures, however, they suggest a routine testing procedure be developed. They suggest starting out with daily checks for accuracy and work into a longer period of time such as weekly or monthly. The frequency would depend on the instruments and how accurate they remain. If accuracy checks are made less frequently than daily, the equipment should also be checked daily for registration;
Southern Cross-Their written procedures suggest that FI equipment be checked for accuracy on a daily basis using 50 ppm methane gas. The Southern Cross CGI manual contains no statement recommending the calibration of CGI’s.
In addition, the American Gas Association (AGA) Gas Piping Technology Committee (GPTC) has published a Guide for Gas Transmission and Distribution Piping Systems (Guide). The Guide contains information for the maintenance of natural gas detection equipment. The Guide recommends that various daily operational checks of the equipment be made and at least monthly calibration checks be conducted. Appendix 1992-1 contains a copy of the pertinent part of Appendix G-11 of the GPTC’s Guide.
To comply with the requirements of 4 CSR 240-40.030(14) - Gas Leaks, the Staff had previously recommended to several operators that their natural gas detection equipment be checked for accuracy at least monthly unless it is an instrument kept in storage and seldom used. If the instrument is seldom utilized (less than monthly usage) the instrument should be checked for accuracy before each use. Please be advised that Staff still considers a monthly time frame for checking natural gas detection equipment for accuracy to be the maximum and in the future will continue to use this criterion to evaluate the operator’s procedures for checking natural gas detection equipment.
1994-1)Pressure Regulating Stations; Farm Taps(Distributed January 13, 1994)
In 1987, the Staff mailed an all operators memorandum regarding “farm tap” regulator sets/stations. All farm tap regulator sets serving 10 or more customers were to be identified and reworked by the end of 1987 so that regulator station inspections could be conducted in 1988. Enforcement on all other farm tap regulator sets (<10 customers) and “similar installations found within distribution systems” was “held in abeyance” until further interpretation/clarification could be received from the U.S. DOT-Office of Pipeline Safety (OPS). Since 1987, the Staff has obtained clarification from OPS based upon the main and service line definitions. The OPS position, as expressed to the Staff and as contained in some interpretations, is that a regulator serving a downstream main is a pressure regulating station. The Staff believes this position is too stringent, because it includes every regulator serving two or more service lines, regardless of the downstream MAOP.
Please be advised of the following Staff position applied to all regulators, not just “farm taps”, to determine if the regulator is a pressure regulating station.
A regulator is considered a pressure regulating station if:
1.It serves a downstream main that serves as the common source of supply for three or more service lines or meter set locations ( a single riser pipe with multiple meters will be considered one meter set location); and
2.The pressure reduction is required for the lower MAOP of the downstream main.
The Staff considers a regulator serving downstream mains with the same or higher MAOP as the upstream piping to be a “convenience” regulator, and does not consider it to be pressure regulating station. However, a line marker is required if the regulator and associated piping (which is a main) are located aboveground. Enforcement action regarding regulators serving two service lines or meter set locations will be held in abeyance until a Federal rulemaking is completed to define branch service lines, for which several waivers have been granted. If you have a master meter operator, please be aware that the regulator at the master meter is normally a pressure regulating station (OPS has interpreted that a master meter regulator is a pressure regulating station because it serves a downstream main).
In 1994, the Staff instructed operators that if the above Staff position included regulator installations that they were not currently inspecting annually, as required for pressure regulating stations, to take the necessary steps in 1994 to identify and/or rework these installations so that annual inspections could begin in 1995. The need for reworking these regulators installations should have been minimized by utilizing the attached OPS interpretation (see Appendix 1994-1) for practicable inspections of service-type regulators. Another alternative would have been to add regulators and piping so that each regulator serves only one or two service lines, especially where the service lines branch near the regulator outlet.
Some operators may have had a large number of facilities effected by these Staff positions. If so, and the time period allowed was burdensome, operators were asked to identify the magnitude of the situation and contact the Staff.
1994-2)Natural Disaster Report Form(Distributed April 20, 1994)
Please find in Appendix 1994-2 the Missouri Public Service Commission Natural Disaster Report Form. This form is to be used during a natural disaster to provide information to the Commission Staff. The completed report form should be faxed to the Commission at 573/751-1847. Operators not having fax capabilities should provide the information by telephone to the Staff.
The Commission Staff will notify you when submission of the report form is required. However, if a natural disaster affects your system prior to receiving a request for the report, please submit the completed report to the Staff by fax or provide the information by telephone.
This report form may be reproduced or additional copies will be provided by the Commission upon your request. Please add this form to your emergency procedures.
1995-1)Leaks on Aboveground Pipelines or Fuel Lines(Distributed May 2, 1995)
Based upon numerous operator inquiries and discussions during Staff inspections, the Staff is aware that the application of the leak classification regulations to aboveground leaks is confusing and inconsistent. This is primarily caused by:
1.The word “underground” in paragraph (14)(B)3., while “aboveground” is not used in section (14),
2.most of the examples given in the regulations apply to underground leaks, and
3.the general perception that the leak rules only apply to underground leaks.
Operators also ask how they should handle leaks found on fuel lines. Based upon current regulations, the Staff has developed the following positions for these two issues.
Staff Positions:
A.Section (14), the section of the Missouri pipeline safety regulations entitled “Gas Leaks”, applies to any leak from a “pipeline” as defined in paragraph (1)(B)21. This would include any “pipeline” whether it is underground versus aboveground, or interior versus exterior. The termination of a “pipeline” is normally at the meter outlet per the definition of “service line”. Since “fuel lines” are not “pipelines”, section (14) does not apply (see Positions G & H regarding fuel line leaks).
Rationale - The scope of section (13) is stated in subsection (13)(A): “This section prescribes minimum requirements for maintenance of pipeline facilities.” Paragraphs (13)(B)1. & 3. state “no person may operate a segment of pipeline, unless it is maintained in accordance with this section” and “leaks must be investigated, classified, and repaired in accordance with section (14)”. While most of the examples given in the leak classifications listed under subsection (14)(C) involve underground leaks, several of the examples of Class 1 leaks could involve a leak from an aboveground pipeline (such as blowing natural gas or natural gas drawn into a building by an air intake near the meter set) - see Position B.
B.A leak from an aboveground “pipeline” is a Class 1 leak if it: ignites or results in a flash/explosion, is blowing from a broken natural gas facility, results in an indication of natural gas present in a building, enters a building or is in imminent danger of doing so, or constitutes an immediate hazard to a building and/or the public.
Rationale - The definition and examples of a Class 1 leak contained in paragraph (14)(C)1. The Class 1 leak example not listed above is “a natural gas reading equal to or above the Lower Explosive Limit in a tunnel, sanitary sewer, or confined area” - See Position C.
C.Where the examples given in the leak classifications involve a “reading”, the example does not apply to aboveground piping unless it is located in a confined area.
Rationale - “Reading” is defined by paragraph (1)(B)23. as the “highest sustained reading when testing in a bar hole or opening without induced ventilation”. This definition could only apply to aboveground piping located in a confined area (such as a box, pit, or vault).
Special note on Class 2 leak example - “Class 2 leak is a leak that does not constitute an immediate hazard to a building or to the general public, but is of a nature requiring action as soon as possible” and one example of a Class 2 leak is “any reading outside a building at the foundation or within 5 feet of the foundation”. The Staff has observed several operators (or their leak survey contractor) who have over-classified meter set thread leaks detected with an FI unit as a Class 2 leak, because it was within 5 feet of the building. Since there is no “reading” (as defined in the regulations) in a bar hole or opening, a small thread leak at an aboveground meter set is not required to be classified as a Class 2 leak - see Position E. However a large volume aboveground leak does require a Class 2 leak priority if it “does not constitute an immediate hazard ..., but is of a nature requiring action as soon as possible” - see Position D.
D.If a leak (see Position E regarding a “no leak”) from an aboveground “pipeline” does not meet the Class 1 leak definition and examples (see Position B), it should be classified as a Class 2, Class 3, or Class 4 leak based upon the definition of each in the first sentence of paragraphs (14) (C)2., 3., or 4.
“Class 2 Leak is a leak that does not constitute an immediate hazard to a building or to the general public, but is of a nature requiring action as soon as possible.”
“Class 3 Leak is a leak that does not constitute a hazard to property or to the general public, but is of a nature requiring routine actions.”
“Class 4 Leak is a confined or localized leak which is completely non-hazardous.”
Rationale - The definitions of leak classifications. The examples given for Class 2 and Class 3 leaks involve “readings”, so they normally do not apply as explained in Position C.
E.Slight leakage at a pipe thread or valve core on an outside meter set is usually a Class 4 leak at the most, and “no leak” in many cases. For example, a small leak on an outside meter set that slowly forms a bubble in soap solution may be considered a “no leak”.
Rationale - Class 4 leak definition in paragraph (14)(C)4.
F.Repairs are not required for Class 4 leaks or “no leaks”. Repairs should be considered, especially if an odor was reported by the customer. While other leak repair records must be retained for the life of the facility [paragraph (13)(F)2.C.], the Staff believes the operator should not be required to retain a record for the repair of an aboveground Class 4 leak or “no leak”.
Rationale - Repairs should help prevent the customer from becoming accustomed to smelling a natural gas odor and not reporting it. Reasons for not retaining the repair record include: the repair is not required, the repair involved tightening threads or greasing a valve, or the aboveground piping is visible.
G.Natural gas detected inside a building, a gas fire, a gas flash and a gas explosion are occurrences that could result due to leakage from either a pipeline or a fuel line. Each of these occurrences are listed as Class 1 leak examples, but only leakage from a pipeline can actually be a Class 1 leak. However, regardless of the leak source, each of these examples require immediate corrective action in accordance with the operator’s emergency plan.
Rationale - Emergency plan requirements in paragraph (12)(J)1.
H.As stated in Position A, leaks found on fuel lines are not subject to classification under section (14). As some operators have done, it is acceptable to create a similar classification system for fuel line leaks in the O&M plan, but this is not required. Some fuel line leaks require emergency plan action (Position G). Fuel line leaks that are not emergencies but are determined to be unsafe, must be dealt with according to paragraph (12)(S)3. Fuel line leaks that are determined to be safe should be dealt with according to the utility’s tariffs/municipality’s ordinances if they address this issue; otherwise the operators’s policy, procedure (preferable) or practice should be used.
1995-2)Transmission Line Definition(Distributed May 2, 1995)
Several Missouri operators have “transmission lines” (lines) that operate at or have an MAOP that is equal to or above 20% of the specified minimum yield strength (SMYS). The Staff has found that many of these lines have laterals, off of the transmission lines, that are of smaller diameter pipe. The Staff has also found that there are transmission lines that “telescope” down to smaller diameter pipe. With the smaller diameter, the line no longer is operating at, nor is the MAOP at or above 20% SMYS and therefore, several operators believed that the smaller diameter sections should not have to be treated or reported as transmission line. After several discussions with the MGUTC Executive Board, the Staff decided to base determination of a transmission line on the MAOP being equal to or above 20% SMYS. If the transmission line transitions to smaller pipe or if there are laterals off the line that are of smaller diameter, the Staff will not consider those lines as transmission lines, as long as the MAOP is not equal to or above 20% SMYS. Please evaluate all pipelines at the MAOP to make sure of the number of miles of transmission lines in your system, and note that the Staff believes that the MAOP of the line is the pressure that must be used to determine the SMYS.