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NM PSB Sample Manual 2/1/2017 By: Ilerma 1
MASTER METER OPERATORS OPERATION AND MAINTNANCE PLAN
DISCLAIMER - This disclaimer must not be removed from this publication
THIS PUBLICATION is provided as a public service to Master Meter Operators (Operator) in New Mexico and SHALL NOT BE SOLD IN PART, OR IN WHOLE.
The contents contained in this Operation and Maintenance Plan (Plan) are based on sound engineering principles developed by the Public Regulation Commission, Pipeline Safety Bureau and must be applied by the use of sound and competent judgment. The Plan should not restrict the operator from using other methods of complying with Federal and State Standards. In addition, the Operator is cautioned that the Plan material may not be adequate under all conditions encountered. Following the Plan does not ensure that an Operator is automatically in compliance with the requirements of Parts 191 and 192 and NMAC 18.60.2. This document supersedes the previous "Guidelines for Implementing an Operation & Maintenance Manual," published prior to December 2016. This Plan May be Used As A GUIDANCE TEMPLATE ONLY And Must Be Adapted For Each Operator’s Pipeline Facility. The regulations at 49 CFR Parts 191, 192 and NMAC 18.60.2 must be consulted on any issue concerning minimum safety requirements for each pipeline facility and for the transportation of gas. Errors may have been made in transcribing this written Plan and should be reported to the Pipeline Safety Bureau.
Owner or Managing Company Name:
Records Location:
Address:
City/State/Zip:
Telephone:
Unit Name:
Address:
City/State/Zip:
Telephone:
Issued Date: Revised Date:
NM PSB Sample Manual 2/1/2017 By: Ilerma 2
Revised Date:
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GENERAL STATEMENT This manual may consist of multiple binders with relevant sections and must be kept at appropriate locations where operation and maintenance activities are conducted. Appropriate sections of other documents referenced, instead of being incorporated, must be present at the location for which they apply. Procedures for this facility may vary in length and complexity depending on the pipeline size, locale, policies, and types of equipment in use and the amount of material included in its entirety, including manufacturers’ instructions, where appropriate. We must establish and maintain an ongoing training program that will provide operating and maintenance personnel with a basic understanding of each element of this procedural manual for operations, maintenance, and emergencies appropriate to the job assignment. Personnel who perform covered tasks and or persons having responsibilities associated with the gas pipeline facility must receive training and be evaluated prior to performing those tasks or conducting managerial tasks. The training shall include requirements for new or replacement construction activities; personnel must be able to understand and recognize differences between State of New Mexico Construction Industries Division (CID) Uniform Plumbing Code (UPC) and Uniform Mechanical Code (UMC) code and Federal Regulations 49 CFR Parts 191 & 192. Regarding Contractors: Insure contractor personnel are Operator Qualified PRIOR to performance of covered tasks. All covered tasks performed by contractor personnel must be reviewed and approved during performance to insure these procedures are followed. This may be accomplished by periodically inspecting, reviewing, or observing work being performed. Contractors are required to report to the manager or designee at the beginning and end of each day and are not allowed to perform covered tasks without prior approval.
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TABLE OF CONTENTS Page GENERAL STATEMENT ....................................................................................................................................... 3 SCOPE.............................................................................................................................................................. 7 OBJECTIVE........................................................................................................................................................ 7 SYSTEM DESCRIPTION .......................................................................................................................... 8 49 CFR PART 191 .................................................................................................................................. 9
191.5 NOTIFICATION OF INCIDENT .................................................................................................. 9 191.7 REPORT SUBMISSION REQUIREMENTS .................................................................................. 9 191.9 INCIDENT REPORT ................................................................................................................. 10 191.11 Distribution system: Annual report ..................................................................................... 10
49 CFR PARTS 192 ................................................................................................................................ 11 192.3 DEFINITIONS ......................................................................................................................... 11 192.13(b) What regulations Apply ..................................................................................................... 13 192.13(c) Maintain, Modify and Follow .............................................................................................. 13 192.16 CUSTOMER NOTIFICATION ................................................................................................ 14
SELECTION AND QUALIFICATION OF PIPE AND COMPONENTS FOR USE IN PIPELINE ............................... 14 192.53 MATERIALS ....................................................................................................................... 14 192.63 Marking of Materials ........................................................................................................... 14
MINIMUM REQUIREMENTS FOR THE DESIGN OF PIPE ........................................................................... 14 192.105 DESIGN FORMULA FOR STEEL PIPE .................................................................................... 14 192.121 DESIGN OF PLASTIC PIPE.................................................................................................... 15 192.123 DESIGN LIMITATIONS FOR PLASTIC PIPE ............................................................................ 16 192.145 VALVES ............................................................................................................................ 15 192.161 SUPPORTS AND ANCHORS ................................................................................................. 16 192.191 DESIGN PRESSURE OF PLASTIC FITTINGS............................................................................. 16 192.197 CONTROL OF PRESSURE..................................................................................................... 16
MINIMUM REQUIREMENTS FOR CONSTRUCTING OF MAINS ................................................................ 17 192.319 INSTALLATION OF PIPE IN A DITCH .................................................................................... 17 192.321 INSTALLATION OF PLASTIC PIPE ......................................................................................... 17 192.325 UNDERGROUND CLEARANCE ............................................................................................. 17 192.327 COVER .............................................................................................................................. 18
MINIMUM REQUIREMENTS FOR INSTALLING CUSTOMER METERS, SERVICE REGULATORS, SERVICE LINES, VALVES, AND SERVICE LINE CONNECTIONS TO MAINS ........................................................................... 18
192.355 METERS AND REGULATORS ................................................................................................ 18 192.363 SERVICE VALVE REQUIREMENTS ......................................................................................... 18 192.365 LOCATION OF VALVES ........................................................................................................ 19 192.381 EXCESS FLOW VALVE .......................................................................................................... 19
REQUIREMENTS FOR OPERATIONS, MAINTENANCE, AND EMERGENCIES PROCEDURES ........................... 19 192.605 MANUAL .......................................................................................................................... 19 192.605(a) MANUAL REVIEW ......................................................................................................... 20 192.605(b3) AVAILABILITY OF CONSTRUCTION RECORDS, MAPS, AND OPERATING HISTORY ........... 20 192.605(B)(4) Gathering of data needed for reporting incidents ...................................................... 20 192.605(b)(8) REVIEW OF PERSONNEL WORK ................................................................................. 21 192.605(b)(9) EXCAVATED TRENCHES ............................................................................................. 21 192.605(B)(11) Responding Promptly To A Report Of A Gas Odor .................................................... 22
MINIMUM REQUIREMENTS FOR WELDING STEEL MATERIALS IN PIPELINES ........................................... 22 GENERAL WELDING CONTRACT REQUIREMENTS ................................................................................... 22
192.225 WELDING PROCEDURES .................................................................................................... 22 192.227 QUALIFICATION OF WELDERS ............................................................................................ 23
MINIMUM REQUIREMENTS FOR JOINING MATERIALS IN PIPELINES, OTHER THAN BY WELDING ........... 23 192.273 General ............................................................................................................................ 24
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192.281 Joining Solvent Cement/Heat Fusion ............................................................................... 24 192.283 QUALIFYING JOINING PROCEDURES .................................................................................. 25 192.285 Qualifications ................................................................................................................................ 25 192.287 Inspection of Joints ........................................................................................................... 25
CORROSION ..........................................................................................................................................
192.453 GENERAL REQUIREMENTS ................................................................................................ 26 192.455 BURIED PIPELINES .............................................................................................................. 26 192.459 EXAMINATION OF BURIED PIPELINE ................................................................................................ 27 FIELD REPORT .............................................................................................................................................. 27 192.461 PROTECTIVE COATING ................................................................................................................... 27 192.463 External Corrosion Control: Cathodic Protection ............................................................................. 28 192.465 CORROSION CONTROL MONITORING ............................................................................................. 28 REMEDIAL ACTION TO CORRECT DEFICIENCIES FOUND BY MONITORING ...................................................... 29 192.465(b) RECTIFIER INSPECTION ............................................................................................................... 29 192.467 ELECTRICAL ISOLATION .................................................................................................................. 29 192.469 TEST STATIONS ............................................................................................................................. 30 192.471 TEST LEADS .................................................................................................................................... 31 192.475 INTERNAL CORROSION CONTROL .................................................................................................. 31 192.479 ATMOSPHERIC CORROSION CONTROL ......................................................................................... 32 192.481 ATMOSPHERIC MONITORING ........................................................................................................ 32 192.483 REMEDIAL MEASURES ................................................................................................................... 32 192.487 REMEDIAL MEASURES GENERAL/LOCALIZED CORROSION ............................................................... 32 192.491 CORROSION RECORDS .................................................................................................................... 33
Minimum Leak-Test And Strength-Test Requirements For The Pipelines .............................................................. 33 192.503 General requirements .................................................................................................................... 33 192.509 STEEL MAIN TEST REQUIREMENTS .......................................................................................................... 34 192.511 STEEL SERVICE TEST REQUIREMENTS ........................................................................................................ 35 192.513 TEST REQUIREMENTS PLASTIC ....................................................................................................................................................................... 35 192.517 TEST RECORDS .............................................................................................................................. 35
Minimum Requirements For (Uprating) For Pipelines .................................................................................... 36 Minimum Requirements For The Operation Of Pipeline Facilities .............................................................................. 36
192.603 GENERAL RECORD PROVISIONS ............................................................................................................... 36 192.613 CONTINUING SURVEILLANCE ......................................................................................................... 36 192.614 (C) (6) DAMAGE PREVENTION .................................................................................................................... 36 18.60.2.8 C (6) NMAC .................................................................................................................................. 37
EMERGENCY PROCEDURES ................................................................................................................................ 37 EMERGENCY PLAN 192.615(a) ..................................................................................................................... 37
RECEIVING AND HANDLING EMERGENCY CALLS .................................................................................... 38 Emergency situations .................................................................................................................................. 39 Gas leaks inside .......................................................................................................................................... 39 Strong odor or high concentration of gas (flammable range) ......................................................................... 39 Gas leaks outside ........................................................................................................................................ 39 Broken Gas Line .......................................................................................................................................... 40 Explosion or Fire involving gas lines or located near the gas lines .................................................................. 40 Natural Disaster .......................................................................................................................................... 40 NMAC 18.60.2.8 (C) (6) ................................................................................................................................ 40 192.615(a) (4) EMERGENCY NOTIFICATION LIST, (MANAGER AND/OR MAINTNANCE PERSONNEL) ................. 40 192.615(a) (5).............................................................................................................................................. 41 192.615(a) (6).............................................................................................................................................. 41 192.615(a) (7).............................................................................................................................................. 41 192.615(a) (9) .............................................................................................................................................. 41
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192.615(b) (1) & (2) ..................................................................................................................................... 41 192.616(j) Public Awareness ...................................................................................................................... 41 192.617 Investigation of Failures ............................................................................................................... 42 Investigation Procedures ............................................................................................................................ 42 Data Collection ........................................................................................................................................... 42 Specimens .................................................................................................................................................. 42 192.619 Maximum Allowable Operating Pressure ...................................................................................... 43 192.625(a) ODORIZATION OF GAS ................................................................................................................ 44 192.625(f) Odorization of Gas .................................................................................................................... 44 192.627 Tapping Pipelines Under Pressure .................................................................................................. 44 192.629 Purging Of Pipelines ...................................................................................................................... 44 Use of Venting Stacks .................................................................................................................................. 45 Requirements For Maintenance .......................................................................................................... 45 192.703 General......................................................................................................................................... 45 192.723 Leakage Survey ............................................................................................................................. 45 If a Leak is Found ........................................................................................................................................ 46 192.725 TEST REQUIREMENTS FOR REINSTATING SERVICE LINE .................................................................... 46 192.727 ABANDONMENT OR DEACTIVATION OF FACILITIES........................................................................... 46 192.739 Pressure Limiting And Regulating Stations: Inspection And Testing ................................................. 47 192.747 VALVE MAINTENANCE .................................................................................................................... 47 192.751 PREVENTION OF ACCIDENTAL IGNITION .......................................................................................... 48 18 NMAC 60.2.12 CLASSIFICATION & REPAIR OF LEAKS ................................................................................. 49 PRIORITY OF REPAIRS .................................................................................................................................. 49 192.801 Operator Qualification ................................................................................................................... 50
SCOPE These procedures are in accordance with the applicable rules and regulations of 49 CFR Parts 191 & 192 and; In accordance with the applicable rules and regulations of the New Mexico Public Regulation Commission, Pipeline Safety Bureau, adopted pursuant to the Pipeline Safety Act [70-3-10 to 70-3-20 NMSA 1978, 1995. NMAC 18.60.2.8 ADOPTION OF PORTIONS OF THE CODE OF FEDERAL REGULATIONS: A. Adoption by reference. Except for the variances set forth in Subsection B of this section, the commission adopts the following portions of the code of federal regulations, as such may be amended from time to time, pertaining to gas facilities, and concerning the health, safety, and welfare of persons and property in New Mexico, as part of this rule: SEE NMAC 18.60.2 for entire Statue.
OBJECTIVE The purpose of this document is to outline the procedures for operations and maintenance (O&M Plan) necessary for the safe operation of the gas distribution pipeline system and for handling gas emergencies. The effectiveness of these procedures will depend on the training and knowledge of the appropriate personnel. Communication and liaison established with public assistance agencies is necessary in creating awareness of mutual assistance in a gas emergency.
SYSTEM DISCRIPTION Constructed in
The Maximum Allowable Operating Pressure (MAOP) is psig.
The Actual Operating Pressure (AOP) is psig.
Number of Services:
Total Length of Services:
Number of Isolation Valves:
Gas Supplier:
Mains Service Lines Type of Pipe Size Length Size Estimated Average Length Bare Steel Coated Steel Plastic (PVC) Plastic (PE) TOTAL
49 CFR PART 191
This section addresses requirements for reporting incidents to the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the New Mexico Pipeline Safety Bureau. 191.5 - NMAC 18.60.2.8 NOTIFICATION OF INCIDENT In accordance with Section 191.5 of 49 CFR Part 191, we will notify the New Mexico Public Regulation Commission (NMPRC), Pipeline Safety Bureau (PSB), of any natural gas incident* occurring on the pipeline system, and the National Response Center, Washington, D.C. as follows: *Notice to NMPRC PSB - At the earliest practicable moment following discovery, notice shall be given the National Response Center and to the NMPRC PSB for any Incident (described herein) as follows:
(1) An event that involves a release of gas from a pipeline, or of liquefied petroleum gas and that results in one or more of the following consequences: i. A death, or personal injury necessitating in-patient hospitalization;
ii. Estimated property damage of ($5,000 or more to NMPRC, Pipeline Safety Bureau) and of ($50,000 or more to National Response Center (NRC)) , including loss to the operator and others, or both, but excluding cost of gas lost;
iii. Unintentional estimated gas loss of three million cubic feet or more; (2) Activation of an emergency shutdown system for reasons other than an actual emergency does
not constitute an incident. (3) An event that is significant in the judgment of the operator, even though it did not meet the
criteria of paragraphs (1) or (2) of this definition. Giving notice at the earliest practicable moment means: Telephonic notice must be given within two hours following discovery* of the incident, for this reason the person who would ordinarily give notice is unable to do so, then notice must be given within one hour after the area has been rendered safe. *“DISCOVERY” - Means learning of an incident where a leak on the facilities is a possible contributing factor. It does not mean that we may delay giving notice until the precise location, cause, and existence of the leak is determined. This is because such a delay could result in destruction of evidence which would hinder investigation by the NMPRC PSB. Telephonic notice must include the following information:
(a) Geographic location of the incident; (b) The time of the incident; (c) The fatalities and personal injuries, if any; and (d) All other significant facts known that are relevant to the cause of the leak or extent of damage.
Telephonic notification to the NMPRC PSB as described above shall be given to one of the staff members in the Pipeline Safety Bureau at: EMERGENCY/INCIDENT PHONE (505) 490-2375. Federal National Response Center (NRC)- The Department of Transportation, National Response Center, will be notified by telephone at (800) 424-8802 or electronically at http://www.nrc.uscg.mil within two hours. 191.7 REPORT SUBMISSION REQUIREMENTS.
Reports required by 191.5 must be submitted electronically to the Pipeline and Hazardous Materials Safety Administration at http://portal.phmsa.dot.gov/pipeline unless an alternative reporting method is authorized. Alternative Reporting Method: If electronic reporting imposes an undue burden and hardship, a written request for an alternative reporting method may be submitted to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, PHP-20, 1200 New Jersey Avenue, SE, Washington DC 20590. The request must describe the undue burden and hardship. PHMSA will review the request and may authorize, in writing, an alternative reporting method. An authorization will state the period for which it is valid, which may be indefinite. PHMSA can be contacted at 202-366-8075, or electronically to [email protected] or make arrangements for submitting a report that is due after a request for alternative reporting is submitted but before an authorization or denial is received. 191.9 INCIDENT REPORT: We are not required to submit an incident report as required by 191.9; however, we must still report the incident as required by 191.5. This section addresses requirements for reporting of annual reports to the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the New Mexico Pipeline Safety Bureau (PSB). 191.11 DISTRIBUTION SYSTEM: ANNUAL REPORT. The annual report requirement in this section applies if we have 100 or more customers from a single source. We must file an annual report on DOT Form PHMSA F 7100.1-1if we have 100 or more customers in our pipeline system. The report must be submitted electronically to [email protected] each year, not later than March 15, for the preceding calendar year. A onetime issuance of an Operator Identification Number (OPID) is requirement for reporting. An OPID is assigned to an operator for the pipeline or pipeline system for which the operator has primary responsibility. To obtain an OPID, complete an OPID Assignment Request DOT Form PHMSA F 1000.1 through the National Registry of Pipeline, in accordance with § 191.7. Click on website below to obtain A OPID form. http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/OpID_Assignment_Form_PHMSA_F1000_1_rev5_2015.pdf We must submit each report required by this part electronically to the Pipeline and Hazardous Materials Safety Administration at http://portal.phmsa.dot.gov/pipeline unless an alternative reporting method is authorized in accordance with paragraph 191.7(d). Form Filling Instructions: http://www.windot.com/docs/federal/forms/Gas_Dist_Annual_Instructions_7100_1-1.pdf FORM: http://www.windot.com/docs/federal/forms/Gas_Distr_Annual_Form_F_7100_1-1.pdf
49 CFR PARTS 192
192.3 DEFINITIONS: Abandoned means permanently removed from service. Active corrosion means continuing corrosion that, unless controlled, could result in a condition that is detrimental to public safety. Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate. Anode means the electrode in a corrosion cell where oxidation or corrosion occurs. In a pipeline-related cathodic protection (CP) system, the anode is designed as the sacrificial material installed to purposely corrode and protect the pipeline or other underground structure(s). Anodeless Riser means a plastic pipe sheathed inside a protective steel metallic casing. The steel-cased plastic pipe protrudes from the soil and is part of the service line carrying gas to the customer regulator or and meter. Barhole means a small diameter hole in the ground made by a plunger bar or probe. These holes are made along the route of a gas pipeline to check the subsurface soil for an indication of gas accumulations due to leaks. Cathodic protection (CP) A technique to control the corrosion of a metal surface by making the structure work as the cathode of an electrochemical cell. Distribution Line means a pipeline other than a gathering or transmission line. Electrical survey means a series of closely spaced pipe-to-soil readings over pipelines which are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline.
Excess flow valve (EFV) means a device that is installed in a service line to automatically shut off the gas flow through the line when the flow exceeds a predetermined limit. Flame ionization means a device used to detect flammable gas concentrations. Sample vapors are drawn in and subjected to a high-temperature filament where the gases are ionized to indicate the concentration of combustible gases. Fusion means a process of joining plastic pipe segments by melting the plastic polymers at the two ends with heat to an extent where they will molecularly bond when pressed together. Gas means natural gas, flammable gas, or gas which is toxic or corrosive. High pressure distribution system means a distribution system in which the gas pressure in the main is higher than the pressure provided to the customer. Leak Classification means a method of classifying leaks according to their size, hazard to persons or property and required remedial actions to reduce the hazard. Leakage Survey means a systematic inspection of a pipeline for the purpose of finding leaks on a gas piping system. Leakage surveys must be conducted by the use of an electronic leak detection instrument. Leak test means a quality control check of the structural integrity of a pipeline performed by filling the line with air, gas, inert gas or fluid, and applying a specified pressure for a prescribed period of time. Any ruptures or leaks revealed by the test must be properly repaired. Listed specification means a specification listed in 49 CFR Part 192 Section I of Appendix B of this part. Lock-Up means the point at which a regulator shuts off completely. Lock up is important so that, under no-flow conditions, the regulator does not seep gas downstream. Low-pressure distribution system means a distribution system in which the gas pressure in the main is substantially the same as the pressure provided to the customer. Main means a distribution line that serves as a common source of supply for more than one service line. Master Meter means: Master Meter System means a pipeline system for distributing gas within, but not limited to, a definable area, such as a mobile home park, housing project, or apartment complex, where the operator purchases metered gas from an outside source for resale through a gas distribution pipeline system. The gas distribution pipeline system supplies the ultimate consumer who either purchases the gas directly through a meter or by other means, such as by rents. Maximum actual operating pressure (AOP) means the maximum pressure that occurs during normal operations over a period of 1 year. Maximum allowable operating pressure (MAOP) means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this part. NMPRC means New Mexico Public Regulation Commission Odorization means the process of adding an odor to natural gas. Since natural gas is odorless, odorant is added to the gas so that people can smell escaping or leaking gas and report to the operator or gas
companies for further investigation
Operator means a person who engages in the transportation of gas.
Our means: The Operator
Petroleum gas means propane, propylene, butane, (normal butane or isobutanes), and butylene (including isomers), or mixtures composed predominantly of these gases, having a vapor pressure not exceeding 1434 kPa 208 psi (1434 kPa) gage at 100F (38C).
Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative thereof.
PHMSA means the Pipeline and Hazardous Materials Safety Administration of the United States Department of Transportation.
Pipe means any pipe or tubing used in the transportation of gas, including pipe-type holders.
Pipeline means all parts of those physical facilities through which gas moves in transportation, including pipe, valves, and other appurtenance attached to pipe, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.
PSB means Pipeline Safety Bureau
Service line means a distribution line that transports gas from a common source of supply to an individual customer, to two adjacent or adjoining residential or small commercial customers, or to multiple residential or small commercial customers served through a meter header or manifold. A service line ends at the outlet of the customer meter or at the connection to a customer's piping, whichever is further downstream, or at the connection to customer piping if there is no meter.
Service regulator means the device on a service line that controls the pressure of gas delivered from a higher pressure to the pressure provided to the customer. A service regulator may serve one customer or multiple customers through a meter header or manifold.
SMYS means specified minimum yield strength is:
(a) For steel pipe manufactured in accordance with a listed specification, the yield strength specified as a minimum in that specification; or
(b) For steel pipe manufactured in accordance with an unknown or unlisted specification, the yield strength determined in accordance with §192.107(b)
State means State of New Mexico.
Transportation of gas means the distribution of gas by pipeline.
Valve means a mechanical device used to control the flow of gas.
We means: The Operator
Welder means a person who performs manual or semi-automatic welding.
192.13(b): What regulations Apply We may not operate a segment of pipeline that is replaced, relocated, or otherwise changed after November 12, 1970, unless that replacement, relocation, or change is made in accordance with the requirements in 49 CFR Part 192.
192.13(c) Maintain, Modify and Follow The procedures for operation & maintenance contained herein will be followed as stated in accordance with the established schedule herein, and modified as needed.
192.16 CUSTOMER NOTIFICATION We must notify each customer, once in writing, within 90 days after the customer first receives gas; however, we may continuously post a general notice in a prominent location frequented by our customers. The Notice provide in Attachment 1A must include the following requirements: (1) We do not maintain the customer's buried piping; (2) If the customer's buried piping is not maintained, it may be subject to the potential hazards of corrosion and leakage; (3) Buried gas piping must be:
• Periodically inspected for leaks; • Periodically inspected for corrosion if the piping is metallic; and • Repaired if any unsafe condition is discovered;
(4) When excavating near buried gas piping, the piping should be located in advance, and the excavation done by hand; and (5) Plumbing contractors can assist in locating, inspecting, and repairing the customer's buried piping.
SELECTION AND QUALIFICATION OF PIPE AND COMPONENTS FOR USE IN PIPELINE 192.53 MATERIALS Personnel shall ensure that all pipe and components materials used for new or replacement construction must meet the prescribed standards, or portions thereof, incorporated by reference in 192.7 and must be:
1) Able to maintain the structural integrity of the pipeline under temperature and other environmental conditions that may be anticipated;
2) Chemically compatible with any gas that they transport and with any other material in the pipeline with which they are in contact; and
3) Qualified in accordance with the applicable required standards in 192.7. 192.63 Marking of Materials All pipe, fittings and valves used in the pipeline facility shall be marked to indicate the following:
1) Size; 2) Material; 3) Manufacturer; 4) Pressure Rating; 5) Temperature Rating; 6) Type (As appropriate/applicable); 7) Grade (As appropriate/applicable); and 8) Model (As appropriate/applicable)
Polyethylene (PE) plastic pipe and fittings must be marked in accordance with ASTM D 2513. Materials used for replacements or new construction activities must be recorded and specifications must be available for inspection during NMPRC, PSB inspections.
MINIMUM REQUIREMENTS FOR THE DESIGN OF PIPE 192.105 DESIGN FORMULA FOR STEEL PIPE
Personnel must ensure steel pipe is designed so it does not affect the integrity of the pipeline or that it does not alter the maximum allowable operating pressure (MAOP). The design pressure for steel pipe shall be determined in accordance with the following formula:
• P = (2 St/D) x F x E x T • P = Design pressure in pounds per square inch (kPa) gage; • S = yield strength in pounds per square inch (kPa) determined in accordance with §192.107; • D = Nominal outside diameter of the pipe in inches (millimeters); • t = Nominal wall thickness of the pipe in inches (millimeters). If this is unknown, it is determined in
accordance with §192.109; • F = Design factor determined in accordance with §192.111; • E = Longitudinal joint factor determined in accordance with §192.113; and • T = temperature derating factor determined in accordance with §192.115.
192.121 DESIGN OF PLASTIC PIPE Subject to the limitations of §192.123, the design pressure for plastic pipe is determined by either of the following formulas:
or Where: P = Design pressure, gauge, psig (kPa). S = For thermoplastic pipe, the Hydrostatic Design Basis (HDB) is determined in accordance with the listed specification at a temperature equal to 73°F (23°C), 100°F (38°C), 120°F (49°C), or 140°F (60°C). In the absence of an HDB established at the specified temperature, the HDB of a higher temperature may be used in determining a design pressure rating at the specified temperature by arithmetic interpolation using the procedure in Part D.2 of PPI TR-3/2008, HDB/PDB/SDB/MRS Policies (incorporated by reference, see §192.7). For reinforced thermosetting plastic pipe, 11,000 psig (75,842 kPa). [Note: Arithmetic interpolation is not allowed for PA-11 pipe.] t = Specified wall thickness, inches (mm). D = Specified outside diameter, inches (mm). SDR = Standard dimension ratio, the ratio of the average specified outside diameter to the minimum specified wall thickness, corresponding to a value from a common numbering system that was derived from the American National Standards Institute preferred number series 10. DF = 0.32 or = 0.40 for PA-11 pipe produced after January 23, 2009 with a nominal pipe size (IPS or CTS) 4-inch or less, and a SDR of 11 or greater (i.e. thicker pipe wall). 192.123 DESIGN LIMITATIONS FOR PLASTIC PIPE (a) The design pressure may not exceed a gauge pressure of 100 psig for plastic pipe used in our distribution systems. The wall thickness for thermoplastic pipe may not be less than 0.062 inches. 192.145 VALVES All valves to be used on our pipeline facility must meet the minimum requirements of ANSI/API Spec 6D (incorporated by reference, see §192.7)
P=2S-( t )(DF) D - t
P= 28 (DF) (SDR - 1)
Each valve on a main installed for operating or emergency purposes must comply with the following:
1) The valve must be placed in a readily accessible location so as to facilitate its operation in an emergency.
2) The operating stem or mechanism must be readily accessible. 3) If the valve is installed in a buried box or enclosure, the box or enclosure must be installed so as to
avoid transmitting external loads to the main. A valve may not be used under operating conditions that exceed the applicable pressure- temperature ratings contained in those requirements. Valves used for replacements or new construction activities must be recorded and specifications must be available for inspection during NMPRC, PSB inspections.
192.161 SUPPORTS AND ANCHORS (a) Each pipeline and its associated equipment i.e., meters & regulators etc. must have enough anchors or supports to:
1) Prevent undue strain on connected equipment; 2) Resist longitudinal forces caused by a bend or offset in the pipe; and, 3) Prevent or damp out excessive vibration.
(b) Each exposed pipeline must have enough supports or anchors to protect the exposed pipe joints from the maximum end force caused by internal pressure and any additional forces caused by temperature expansion or contraction or by the weight of the pipe and its contents. (c) Each support or anchor on an exposed pipeline must be made of durable, noncombustible material and must be designed and installed as follows:
1) Free expansion and contraction of the pipeline between supports or anchors may not be restricted. 2) Provision must be made for the service conditions involved. 3) Movement of the pipeline may not cause disengagement of the support equipment.
192.191 DESIGN PRESSURE OF PLASTIC FITTINGS Thermoplastic fittings for plastic pipe must conform to ASTM D2513-99 for plastic materials other than Polyethylene or ASTM D2513-09a for polyethylene plastic materials.
192.197 CONTROL OF PRESSURE (a) A service regulator having the following characteristics must be used and 1 thru 7 must apply so that no other pressure limiting device is required
1) A regulator capable of reducing line pressure to pressures recommended for household appliances; 4 ounces.
2) A single port valve with proper orifice for the maximum gas pressure at the regulator inlet. 3) A valve seat made of resilient material designed to withstand abrasion of the gas, impurities in gas,
cutting by the valve, and to resist permanent deformation when it is pressed against the valve port. 4) Pipe connections to the regulator not exceeding 2 inches (51 millimeters) in diameter. 5) A regulator that, under normal operating conditions, is able to regulate the downstream pressure within
the necessary limits of accuracy and to limit the build-up of pressure under no-flow conditions to prevent a pressure that would cause the unsafe operation of any connected and properly adjusted gas utilization equipment.
6) In the event of failure the regulator must have enough relieve cabacity so that pressure delivered does
not exceed the recommended pressure of household appliances. 7) A self-contained service regulator with no external static or control lines.
MINIMUM REQUIREMENTS FOR CONSTRUCTING OF MAINS Each length of pipe and each component must be visually inspected at the site of installation to ensure that it has not sustained any visually determinable damage that could impair its serviceability. Must be constructed in accordance with comprehensive written specifications or standards and must be inspected to ensure that it is constructed consistent with 49 CFR. Each imperfection or damage that impairs the serviceability of a length of pipeline of steel pipe or plastic pipe must be repaired or removed. 192.319 INSTALLATION OF PIPE IN A DITCH Each line installed in a ditch must be backfilled in a manner that:
1) Provides firm support under the pipe; and 2) Prevents damage to the pipe and pipe coating from equipment or from the backfill material. 3) When long sections of pipe that have been welded alongside the ditch are lowered in, or where excessive
depths are encountered, care must be taken to avoid jerking the pipe or imposing any strains that might kink or put a permanent bend in the pipe. Where these conditions are encountered, the use of slack loops must be used.
4) The condition of the ditch bottom must be inspected just before the pipe is lowered in. 5) The surface of the coated pipe must be inspected as the pipe is lowered into the ditch. Coating
lacerations indicate that the pipe may have been damaged after the coating was applied. 6) The fit of the pipe to the ditch must be inspected before backfilling. 7) Backfilling must be performed in a manner to provide firm support under the pipe. If there are large rocks
in the material to be used as backfill, care shall be used to prevent damage to the coating. This may be accomplished by the use of rock shield material or by making an initial fill with enough rock-free material to prevent damage
192.321 INSTALLATION OF PLASTIC PIPE a) Plastic pipe must be installed below ground level. b) Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe
while it is underground. c) Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not
prohibited. d) Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion
damage, either by use of coated copper wire or by other means. e) Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the
plastic. The leading end of the plastic must be closed before insertion. 192.325 UNDERGROUND CLEARANCE
a) Each main must be installed with enough clearance (12 inches) from any other underground structure to allow proper maintenance and to protect against damage that might result from proximity to other structures.
b) In addition to meeting the requirements of paragraphs (a) of this section, each plastic main must be installed with sufficient clearance, or must be insulated, from any source of heat so as to prevent the heat from impairing the serviceability of the pipe.
c) When installing new mains or replacing existing mains, the proximity and condition of existing conduits, ducts, sewer lines, and similar structures, including abandoned structures, must be considered since they have the potential to provide a path for the migration of leaking gas.
192.327 COVER Each buried main must be installed with at least 24 inches of cover. Additional cover must be provided where the potential for damage by outside forces is greater than normal. Consideration must be given to the following:
1) Drainage ditch crossings. Consideration may also be given to alternates, such as casing or a protective concrete or steel slab.
2) Other utility crossings. The new gas facilities should be installed under the existing facilities, unless adequate cover can be provided or casing, bridging, or other protection is used.
3) Locations where erosion due to wind, water, or vehicular activity may affect the grade. 4) Locations where frost, drought, and heat might affect the pipeline.
MINIMUM REQUIREMENTS FOR INSTALLING CUSTOMER METERS, SERVICE REGULATORS, SERVICE LINES, VALVES, AND SERVICE LINE CONNECTIONS TO MAINS.
192.355 METERS AND REGULATORS
1) Pressure regulators and gas meters must be located where they can properly vent to the atmosphere;
2) Away from any opening into a building, minimum 3 feet; 3) The regulator vent shall be protected from rain or insect penetration; 4) In good mechanical condition; 5) Adequate from the standpoint of capacity and reliability of operation; 6) Set to control or relieve at the correct pressure consistent with the pressure limits of §192.201(a); 7) Pressure tested and adjusted to 4 ounces or 7 inches water column; 8) Test for Lock-up; and 9) Properly installed and protected from dirt, liquids, or other conditions that might prevent proper
operation.
192.363 SERVICE VALVE REQUIREMENTS A valve incorporated in the SUPPLIER’S meter assembly that allows the meter to be bypassed, may not be used as our service valve and cannot be identified as an Isolation/Designated Valve. (a) Each service line must have a service-line valve that meets the applicable requirements of this part and must be:
1) Able to maintain the structural integrity of the pipeline under temperature and other environmental conditions that may be anticipated; the valve must have a maximum service pressure rating for temperature that equals or exceeds the maximum service temperature;
2) Each valve must be able to meet the anticipated operating conditions; and 3) Each valve must be qualified in accordance with the applicable requirements of 192.363.
The Valve must also meet the following:
1) A soft seat valve must not be used if its ability to control the flow of gas could be adversely
affected by exposure to anticipated heat such as a fire, and shall not be installed adjacent to a structure. Note: a soft seat is a core made from plastic or other soft material that will melt if exposed to excessive heat.
2) Each valve installed aboveground or in an area where the blowing of gas would be hazardous, must be designed and constructed to minimize the possibility of the removal of the core of the valve with other than specialized tools;
3) Indicate size, material, manufacturer, pressure rating, and temperature rating, and as appropriate, type, grade, and model.
192.365 LOCATION OF VALVES When installing a shut-off valve, we must consider the access to and operability of the valve under all reasonably anticipated conditions including areas prone to damage from vehicle traffic or water dripping from roofs or flooding conditions. The valve must be easily accessible during normal or emergency conditions and shall be located outside the building.
192.381 EXCESS FLOW VALVE Excess flow valves (EFV), which are safety devices installed on natural gas distribution pipelines to reduce the risk of accidents, are currently required for new or replaced gas service lines servicing single-family residences (SFR), as that phrase is defined in 49 CFR 192.383(a). This rule, effective April 14, 2017, expands this requirement to include new or replaced branched service lines servicing SFRs, multifamily residences, and small commercial entities consuming gas volumes not exceeding 1,000 Standard Cubic Feet per Hour (SCFH). This rule requires operators to notify customers of their right to request installation of an EFV on service lines that are not being newly installed or replaced. PHMSA has left the question of who bears the cost of installing EFVs on service lines not being newly installed or replaced to the operator. Excess flow valves must be installed on single or multifamily residences residence service lines that operate continuously throughout the year at a pressure not less than 10 p.s.i. gage and must be manufactured and tested by the manufacturer according to an industry specification, or the manufacturer's written specification, to ensure that each valve will:
1) Function properly up to the maximum operating pressure at which the valve is rated; 2) Function properly at all temperatures reasonably expected in the operating environment of the
service line; 3) At 10 p.s.i. (69 kPa) gage, close at, or not more than 50 percent above, the rated closure flow rate
specified by the manufacturer.
REQUIREMENTS FOR OPERATIONS, MAINTENANCE, AND EMERGENCIES PROCEDURES: 192.605 MANUAL This manual of written procedures must be followed for Operation & Maintenance and Emergency response
activities. It is required that managers, supervisors, maintenance, and contractor personnel become familiar with the gas system and related procedures as described in this document, and to know the location of the buried gas pipelines as depicted on system maps. Employees will receive initial training on all existing procedures and on any revisions made to these procedures thereafter. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. Records of annual reviews and of employee training will be prepared and retained on file. 192.605(a) MANUAL REVIEW This manual must be reviewed and updated each calendar year but at intervals not exceeding 15 months. The review must demonstrate that all procedures were reviewed or only those parts that may be relevant at the time; however, a different part must be reviewed until the entire manual has been reviewed. It must ensure that the current facilities and any deficiencies in the manual are addressed. The Qualification (OQ) processes and procedures must be reviewed since changes to the manual may affect the OQ program. More serious deficiencies possibly identified following an incident or accident shall require immediate correction. A written record of the reviews must be maintained and shall include:
1) Date of review; 2) Signature of Individuals present; 3) Section(s) reviewed; 4) Results of that review; and 5) Supervisor/Manager signature.
192.605(b3) AVAILABILITY OF CONSTRUCTION RECORDS, MAPS, AND OPERATING HISTORY The construction records, maps, and operating history shall be made available to operating personnel, especially managers/supervisors or those called on to safely operate pipeline facilities or respond to emergencies, or both. The types of records and data that must be made available are as follows:
1) Maps showing location of pipe, valves, and other system components; 2) Maximum allowable operating pressures; 3) Actual Operating Pressure; 4) Inventories of pipe and equipment; 5) Maintenance history; 6) Operating history; 7) Emergency shutdown systems drawings; 8) Emergency Assistance contact information; 9) Isolation drawings; 10) Purging information; 11) Leak history; and 12) Cathodic protection history.
192.605(B)(4) Gathering of data needed for reporting incidents Whenever there is an accident involving the release of gas from a pipeline, it must be determined as soon as possible if there are any injuries requiring hospitalization, deaths, or property damage of $5,000.00 or more, including the cost of gas lost. On-site observations will be made and persons at the scene and witnesses will be interviewed to determine if there are any injuries or deaths and to obtain relevant information. If injuries resulted from the accident, determine if injured persons were hospitalized.
An estimate of property damage will be made using cost obtained from insurance adjuster, property owner, tenants, fire department, or consultant. Information on failed pipe or components will be obtained from the pipe/equipment supplier or a professional consultant. Gathering Data Needed For Reporting Incidents - Means (sources) by which information is to be obtained for telephonic reporting such as: A. Person(s) reporting an incident to you, and available witnesses; B. Time reported; C. Time dispatched, and arrival time; D. Remedial action taken; E. Fire or explosion; F. Death or injuries; G. Employee(s) who have knowledge of the facilities involved in the incident. H. Internal records, maps, etc, that describe the facilities and maintenance history. I. On-site inspection, preliminary findings. J. Fire/Police determinations. K. Determination of any outside activity prior to the incident such as excavation that could be a contributing
factor. A record of information obtained for reporting incidents will be prepared and retained. 192.605(b)(8) REVIEW OF PERSONNEL WORK
Each calendar year we must review personnel performance to determine if normal operating and maintenance procedures found in this manual are effective and adequate. Review must determine if deficiencies exist in the procedures. If applicable, modification of procedures should be accomplished as soon as possible. Documentation should be maintained for all procedure modifications and retraining of personnel must occur.
Each calendar year we must conduct random routine unannounced inspections. These inspections are to verify that personnel (employees and contractors) are following procedures while performance covered tasks. These inspections shall focus on specific areas of the operation, and are not considered a replacement for the annual procedures periodic review of the procedural manual. Information on the focus of the unannounced inspection, including appropriate procedures from the O&M manual, and the specific information to be obtained during the inspection shall be provided to the reviewer.
192.605(b)(9) EXCAVATED TRENCHES This procedure applies to excavation three (3) feet or greater. Personnel working in or near a trench must be aware of the potential for an oxygen-deficient environment and of potential dangers from accumulations of gas or vapor, particularly those associated with liquid petroleum gases. When determining the likelihood of gas or vapors presenting such a hazard to personnel, personnel will consider the depth and configuration of the trench, pipeline pressure, type of piping material, condition, and configuration of the pipeline facilities. Although natural gas is lighter than air and non-toxic, some natural gas pipelines contain constituents such as hydrogen sulfide, heavier-than-air hydrocarbons, and hydrocarbon liquids that may present a hazard to personnel working in or near the trench. The Escaping gas may present an added hazard because of the displacement of oxygen. An atmosphere containing less than 19.5% oxygen must be considered oxygen-deficient for respiration. When it is necessary for personnel to enter an excavated trench
where hazards could reasonably be expected, personnel must take the following actions, as appropriate: 1) Confirm that atmospheric monitoring devices, rescue equipment, and breathing apparatus are in
working order prior to each use, a rope and harness must be used; 2) Check the atmosphere in the excavated trench; 3) Establishing a means of exiting the trench, rope and harness must be used; 4) Review the rescue plan; 5) Placing a safety observer outside the trench to monitor the atmosphere inside the trench and to be
available to assist in use of rescue equipment, operation of a fire extinguisher, or otherwise assist in a rescue;
6) Minimize sources of ignition in and around the trench, such as: SEE 192.751 Prevention of accidental Ignition.
7) Take actions to reduce the accumulation of gas or vapors, such as: i. Isolating the gas facility by closing valves, squeezing off, bagging off, or using stoppers;
ii. Reducing pressure in the facility; and iii. Ventilating the work area.
8) The use of flame-retardant clothing, respiratory protection, or a rescue harness and line, as appropriate. Employees will be trained in the proper use of this equipment and instructed not to enter a trench without a second person as backup. All possible ignition sources will be eliminated and fire extinguisher kept on site at all times. 192.605(B)(11) RESPONDING PROMPTLY TO A REPORT OF A GAS ODOR INSIDE OR NEAR A BUILDING SEE 192.615
THIS SECTION PRESCRIBES MINIMUM REQUIREMENTS FOR WELDING STEEL MATERIALS IN PIPELINES
GENERAL WELDING CONTRACT REQUIREMENTS All welding will be contracted as needed. Welding contractors must provide welding procedures and qualified welders. Procedures and qualifications must be approved by us prior to performing welding activities.
The contractor must be operating under an OQ Program which we have verified as being compatible with our own, including the recognition of and reaction to AOCs identified in our plan. The contractor may participate in an OQ consortium approved by us.
Welding must meet the minimum requirements under 192.221. Welding activities on our pipeline facility by contractors, sub-contractors, or temporary help, etc., must be performed by a qualified welder in accordance with welding procedures qualified under section 5, of API 1104 current Edition.
It is our responsibility to ensure that every individual, who performs welding on our pipeline facility, is qualified as required by 192.227.
192.225 WELDING PROCEDURES (a) Welding must be performed by a qualified welder in accordance with welding procedures qualified under Section 5 of API 1104 current Edition. The quality of the test welds used to qualify welding procedures shall be determined by destructive testing in accordance with the applicable welding standard(s).
(b) Each welding procedure must be recorded in detail, including the results of the procedure qualifying tests. This record must be retained and followed whenever the procedure is used. Procedure qualifying test is: Coupon Test Report to qualify THE PROCEDURE, not the welder. 192.227 QUALIFICATION OF WELDERS (a) Except as provided in paragraph (b) of this section, each welder must be qualified in accordance with section 6 of API 1104 Current Edition or Section IX of the ASME Boiler and Pressure Vessel Code. However, a welder qualified under an earlier edition than listed in § 192.7 of this part may weld but may not re-qualify under that earlier edition. (b) A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in section I of *Appendix C within 49 CFR Part 192. Each welder who is to make a welded service line connection to a main must also first perform an acceptable test weld under 49 CFR Part 192 **Section II of Appendix C, as a requirement of the qualifying tests. *Section I of Appendix C: The test is made on pipe 12 inches (305 millimeters) or less in diameter. The test weld must be made with the pipe in a horizontal fixed position so that the test weld includes at least one section of overhead position welding. The beveling, root opening, and other details must conform to the specifications of the procedure under which the welder is being qualified. Upon completion, the test weld is cut into four coupons and subjected to a root bend test. If, as a result of this test, two or more of the four coupons develop a crack in the weld material, or between the weld material and base metal, that is more than 1/8-inch (3.2 millimeters) long in any direction, the weld is unacceptable. Cracks that occur on the corner of the specimen during testing are not considered. A welder who successfully passes a butt-weld qualification test under this section shall be qualified to weld on all pipe diameters less than or equal to 12 inches.
**Section II of Appendix C: A service line connection fitting is welded to a pipe section with the same diameter as a typical main. The weld is made in the same position as it is made in the field. The weld is unacceptable if it shows a serious undercutting or if it has rolled edges. The weld is tested by attempting to break the fitting off the run pipe. The weld is unacceptable if it breaks and shows incomplete fusion, overlap, or poor penetration at the junction of the fitting and run pipe.
THIS SECTION PRESCRIBES MINIMUM REQUIREMENTS FOR JOINING MATERIALS IN PIPELINES, OTHER THAN BY WELDING. Please note that requirements for operation and maintenance of plastic pipelines are specified in 49 CFR 192. These requirements are enforced by the Department of Transportation, Office of Pipeline Safety, for those operations under its regulatory authority. Although operations may or may not be covered are addressed below and are herein as a procedure and therefore subject to 192.605. Work shall not be performed on plastic pipe when a combustible mixture of gas and air may exist until the static charges have been dissipated. In all cases, all sources of ignition must be removed as follows:
1. The use of a grounded wet tape conductor which are wound around or lay in contact with the entire section of the exposed piping.
2. If gas is already present, the pipe should be wet with a very diluted water solution of dishwasher-type detergent starting from the ground end. The tape should then be applied immediately and left in place.
3. The tape should be kept wet by occasional applications of water. Where ambient temperatures below 0 degrees C. (32 degrees F.) are encountered, glycol may be added to the water to maintain tape flexibility.
The tape should be grounded with a metal pin driven into the ground. 4. Do not vent gas using an ungrounded plastic pipe or tubing. Even with grounded metal piping, venting gas
with high scale or dust content could generate a charge in the gas itself and could result in an arc from the dusty gas cloud back to the pipe and ignition. When venting, it should be done at a down-wind location remote from personnel or flammable material.
5. Ground the tools, such as saws, etc., that come in direct contact with the pipe. 6. In all cases, appropriate safety equipment such as flame-resistant clothing appropriately treated to avoid
static buildup and respiratory protection equipment should be used.
192.273 General Each joint must be made in accordance with written procedures that have been proven by test or experience to produce strong gas-tight joints. We may chose to follow manufacturer’s recommended procedures. Plastic pipe will be installed in a manner that ensures protection against damage to the pipe during installation. Soil will be free of rock or debris that could damage the pipe. All new or replacement plastic pipe must:
• The pipeline must be designed and installed so that each joint will sustain the longitudinal pullout or thrust forces caused by contraction or expansion of the piping or by anticipated external or internal loading;
• Each joint must be made in accordance with written procedures that have been proved by test or experience to produce strong gas-tight joints;
• Each joint must be inspected to insure compliance with this subpart; • Have tracer wire installed adjacent to the piping for locating purposes; • Tracer wire may not be wrapped around the pipe and must not contact the pipe, must be resistant to
corrosion damage, either by use of coated copper wire or by other means; and • Continuous gas pipeline warning tape shall be placed 12 inches above piping.
192.281 Joining Solvent Cement/Heat Fusion To achieve sound joints in plastic piping requires skillful application of qualified procedures and the use of proper materials and equipment in good condition. Joints must be made by personnel who are qualified in the written procedures required for the type of joint involved. We will follow recommended manufacturers written procedures to produce strong gas-tight joints. All personnel and contractors will be qualified to these procedures. ADDITIONAL EACH: Plastic pipe joints that are joined by solvent cement or heat fusion may not be disturbed until they have properly set. Plastic pipe may not be joined by a threaded joint or miter joint. Each solvent cement joint on plastic pipe must comply with the following:
1. The mating surfaces of the joint must be clean, dry, and free of material which might be detrimental to the joint;
2. The solvent cement must conform to ASTM D2513-99, (incorporated by reference, see § 192.7); and 3. The joint may not be heated to accelerate the setting of the cement.
Each heat-fusion joint on plastic pipe must comply with the following:
1. Butt heat-fusion joint must be joined by a device that holds the heater element square to the ends of the piping, compresses the heated ends together, and holds the pipe in proper alignment while the plastic hardens;
2. A socket heat-fusion joint must be joined by a device that heats the mating surfaces of the joint uniformly and simultaneously to essentially the same temperature;
3. An electrofusion joint must be joined utilizing the equipment and techniques of the fittings manufacturer or equipment and techniques shown, by testing joints to the requirements of §192.283(a)(1)(iii), to be at least equivalent to those of the fittings manufacturer;
4. Heat may not be applied with a torch or other open flame; and 5. Pipe must be blocked to eliminate stress at joint.
Each compression type mechanical joint on plastic pipe must comply with the following:
1. The gasket material in the coupling must be compatible with the plastic; 2. A rigid internal tubular stiffener, other than a split tubular stiffener, must be used in conjunction with
the coupling; and 3. Where joint is metallic, cathodic protection must be applied.
192.283 QUALIFYING JOINING PROCEDURES Joining of plastic pipe will be performed using pipe manufacturer's written procedures or other approved and qualified joining procedures. This procedures must be kept on file and also where joining is conducted. A copy of each written procedure being used for joining plastic pipe must be available to the persons making and inspecting joints. 192.285 Qualifications All employees or contractors must not make a plastic pipe joint unless that person has been trained and qualified under the applicable joining procedure. Persons qualifying to make joints in plastic piping shall be observed and certified by a qualified joiner while demonstrating their ability to make satisfactory joints using the correct procedure. Records or qualification cards or both, which show the extent of the individual's qualifications, shall be maintained for the qualification interval. Additionally, training information can be obtained by downloading from the PPI website at http://www.plasticpipe.org 192.287 Inspection of Joints Inspection of joints in plastic pipes required by 192.273(c) and 192.285(b) must be carried out by a person who has been qualified by appropriate training or experience in evaluating the acceptability of plastic pipe joints made under the applicable joining procedure. Record of training will be kept on file.
CORROSION
This Section Prescribes Minimum Requirements For The Protection Of Steel Pipelines From External, Internal, And Atmosphere Corrosion.
192.453 GENERAL REQUIREMENTS
These corrosion control procedures shall be carried out by, or under the direction of, competent persons who, by reason of knowledge of the physical sciences and the principles of engineering and mathematics, acquired by education and related practical experience, are qualified to engage in the practice of corrosion control on buried steel piping systems. Such person(s) may be registered professional engineers or persons recognized as corrosion specialists or cathodic protection specialists by OQ or NACE. It must provide for the:
1. Design; 2. Installation; 3. Operation; and 4. Maintenance.
Design must consider the following:
1. Recognition of hazardous conditions prevailing at the proposed installation site(s) and the selection and specification of materials and installation practices that ensures safe installation and operation.
2. Specification of materials and installation practices to conform to the latest editions of applicable codes, National Electrical Manufacturers Association (NEMA)(7) standards, National Electrical Code (NEC),(8), and NACE standards.
3. Selection and specification of materials and installation practices that ensure dependable and economical operation throughout the intended operating life.
4. Selection of locations for proposed installations to minimize currents or earth potential gradients, which can cause detrimental effects on foreign buried metallic structures.
5. Cooperative investigations to determine mutually satisfactory solution(s) of interference problems. 6. Special consideration should be given to the presence of sulfides, bacteria, disbonded coatings,
thermal insulating coatings, elevated temperatures, shielding, acid environments, and dissimilar metals.
7. Excessive levels of cathodic protection that can cause external coating disbondment and possible damage to high-strength steels as a result of hydrogen evolution should be avoided.
8. When amphoteric metals are involved, care should be taken so that high-pH conditions that could cause cathodic corrosion of the metal are not established.
Installation, Operation & Maintenance must follow the recommended NACE Standard RPO 169-2002.
Personnel responsible must have knowledge of and practical experience in the following:
1. Pipeline coatings; 2. Cathodic protection (CP) systems (galvanic and impressed current); 3. Stray current interference; 4. Electrical isolation; 5. Survey methods and evaluation techniques; and 6. Instruments used.
192.455 BURIED PIPELINES All steel pipes that are installed will be externally coated, and cathodically protected within one year of
installation.
192.459 EXAMINATION OF BURIED PIPELINE If deteriorated or disbonded coating or external corrosion is found, we must continue to investigate circumferentially and longitudinally until corrosion or damaged or disbonded coating requiring remedial action are no longer encountered. Whenever any portion of a buried pipeline is exposed, the exposed portion will be examined for evidence of external corrosion. If external corrosion is found, we must investigate circumferentially (around) and longitudinally (all along) beyond the exposed portion. Visually examine, (indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion. A record shall be kept and maintained on the condition of the pipe and/or coating that was examined. Repair of any coating damage caused or found during an inspection. FIELD REPORT A field work report must be completed describing the condition of the coating or exposed pipe surface in qualitative terms. General criteria for rating the existing conditions should be established system-wide to provide for consistency in field reporting and analysis.
The report should include the following. (a) An evaluation of the coating condition. (b) An evaluation of the pipe condition. (c) The extent of the initial investigation. (d) The extent of any additional investigation conducted, if remedial action is required.
192.461 PROTECTIVE COATING This procedure requires the use of a material designed for application to prevent corrosion of buried metallic structures, including pipelines and:
1. Materials with metallic properties are not allowed. 2. External protective coating which is an electrically insulating type must also have low moisture
absorption and high electrical resistance. 3. If electrical testing is used known as "jeeping" the voltage utilized for the electrical testing must be
in accordance with the manufacturer's recommendations or applicable industry standards. The voltage may vary with coating thickness and type; such as over girth welds, fittings, or coating repairs.
4. Coating material damaged or improperly installed must be repaired. 5. Each external protective coating must be protected from damage resulting from adverse ditch
conditions or damage from supporting blocks, protect the coating from damage as it is being lifted, installed into the ditch, and backfilled.
6. If coated pipe is installed by boring, driving, or other similar method, precautions must be taken to minimize damage to the coating during installation.
7. The surface preparation and application must be consistent with manufacturer's recommendations and applicable industry standards.
Coating must:
1. Be applied on a properly prepared surface, must be clean and be free of any dirt; 2. Have sufficient adhesion to the metal surface to effectively resist underfilm migration of moisture;
3. Be sufficiently ductile to resist cracking; 4. Have sufficient strength to resist damage due to handling and soil stress; and 5. Have properties compatible with any supplemental cathodic protection.
192.463 External Corrosion Control: Cathodic Protection Cathodic protection system must provide a level of cathodic protection that complies with either:
1. A negative (cathodic) voltage of at least 0.85 volt, with reference to a saturated copper-copper sulfate half cell. Determination of this voltage must be made with the protective current applied; and in accordance with: a) Voltage (IR) drops other than those across the structure electrolyte boundary must be
considered for valid interpretation of the voltage measurement. b) Negative (cathodic) voltage must be measured between the structure surface and a saturated
copper-copper sulfate half cell contacting the electrolyte. c) Reading is permitted at anode connection to verify condition of anode; however, reading
must be taken away from installed anodes except where reading is required for isolated risers.
2. A minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage
shift must be determined in accordance with: a. The polarization voltage shift must be determined by interrupting the protective current
and measuring the polarization decay. When the current is initially interrupted, an immediate voltage shift occurs. The voltage reading after the immediate shift must be used as the base reading from which to measure polarization decay.
b. Negative (cathodic) voltage must be measured between the structure surface and a saturated copper-copper sulfate half cell contacting the electrolyte.
c. Reading is permitted at anode connection to verify condition of anode; however, reading must be taken away from installed anodes except where reading is required for isolated risers.
Note: Switching criterion options is not allowed to meet compliance; it must be justified by performing a required analyses.
192.465 CORROSION CONTROL MONITORING We must develop an effective program to monitor cathodically protected pipe. Piping under cathodic protection must be monitored by electrical measurement (pipe-to-soil readings) each calendar year with intervals not exceeding 15 months. We must have documentation to prove that we are monitoring short, less than 100 feet, separately protected isolated sections of piping, services, short sections of coated steel pipeline, and anodes installed according to § 192.483 (c) and §192.457 (b) on a 10 percent annual basis. At least 10 percent of these protected structures, distributed over the entire system, must be surveyed each calendar year, with a different 10 percent checked each subsequent year, so that the entire system is tested in each 10-year period. These methods shall include inspection of bonds, diodes, isolation devices, test leads, casings, and any interference currents. (Note: Short, less than 100' ft. sections of pipe which are interconnected by cable, tracer wire, or other means, and are protected by a common current source or distributed anodes, are not considered to be isolated and must be monitored as a cathodic protection system on a annual basis.)
REMEDIAL ACTION TO CORRECT DEFICIENCIES FOUND BY MONITORING: 1. Remedial action is required whenever it is determined that the CP or other installed corrosion control
methods are not operating effectively. 2. The specific remedial action to be taken depends on the type of corrosion control method installed and the
problem encountered. In certain situations, the deficiency can be corrected by modifying existing corrosion control methods.
3. We must take prompt remedial action to correct deficiencies indicated by monitoring. Remedial action should correct the deficiency before the next monitoring cycle required by §192.465. Example: If it is discovered that pipe coating has deteriorated and that the existing corrosion control system is unable to achieve the desired CP level. We will initiate and document action taken to achieve the acceptable CP level before the next monitoring cycle. Remedial action might include the following.
i) Installing additional CP, ii) Recoating the pipe to meet the requirements of §192.461, iii) Conduction survey to determine if system is shorted to other structure(s), iv) Adjusting the rectifier.
4. If remedial action cannot be completed prior to the next scheduled monitoring cycle, we must document the
actions taken to correct the deficiency and the expected timeframe for completion; however this action must be justified and may result in a violation. Therefore, we must conduct surveys in a timely manner to eliminate this possibility.
Prompt Remedial Action shall be taken and documented within 30 days, i.e., preparing a work order. Remedial Action, to correct the deficiency shall be before the next monitoring cycle, unless justified by item 4 above. These time frames shall be adjusted to give consideration to the population density and environmental concerns of the area that could potentially be affected by released gas and where deficiencies could result in an immediate hazard to the public.
192.465(b) RECTIFIER INSPECTION If a rectifier or other impressed current power source is used it must be inspected six times each calendar year, but with intervals not exceeding 2 1/2 months, to insure that it is operating. Monitoring shall include both a visual inspection and electrical testing. The visual inspection shall include looking for physical damage of the installation/cabinet/components, evidence of overheating, and signs of insect/rodent nests, along with recording the specifics of the rectifier unit and meter readings/tap settings. Testing must include taking manual measurements of the rectifier output voltage and current to verify meter accuracy and structure-to-electrolyte potentials. Test the circuit breaker, transformer, rectifier stack, meters, fuses, choke, capacitors, and lightning arrestors separately. Keep an eye out for loose connections, signs of arcing, strange odors, and test to verify the integrity of the structure and groundbed lead wires. A Record of electrical reading shall be made.
192.467 ELECTRICAL ISOLATION (a) Each buried pipeline must be electrically isolated from other underground metallic structures,
unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit.
Insulating devices may consist of insulating flange assemblies, unions or couplings, or fabricated insulating
joints. These devices shall be properly rated for temperature, pressure, and dielectric strength. Typical locations where electrical insulating devices must be considered include the following:
• At supporting pipe poles and where electrical contact would preclude effective cathodic protection (CP). It may be necessary to electrically isolate the piping from such a structure, or the piping and structure from adjacent underground piping;
• At metallic curb boxes and valve enclosures. These should be designed, fabricated and installed in such a manner that electrical isolation from the piping system will be maintained;
• Points at which facilities change ownership, such as meter stations;
• Where a pipe enters a building through a metallic wall sleeve and where it is intended to maintain electrical isolation between the sleeve and the pipe. To accomplish this, insulating spacers should be used; and
• At the separation of underground pipe and aboveground piping.
(b) Each steel gas service riser (except anodeless risers) must have dielectric fittings installed for electrical isolation of the underground piping. Each cathodically protected service riser will be visually checked to ensure that no metallic object is in contact with the steel pipe or with the dielectric (insulating) union, and that no wire, chain or other device of any type is tied to the riser that can short out the cathodic protection system. Where insulating type casing spacers is used, one should be installed as close as practical to each end of the casing. Vent connections, when required, should be installed prior to the insertion of the carrier pipe to preclude the possibility of damage to the carrier pipe. The required annual monitoring of CP systems and the evaluation of such test data is generally sufficient to ensure that electrical isolation is adequate on cathodically protected piping. However, specific electrical tests on insulating devices must be made where deemed necessary to ensure the adequacy of electrical isolation and to pinpoint operational problems on CP systems. The test must indicate a substantial CP reading difference between the pipe and the insulating devise or casing. All CP readings that are substantially close must be investigated, repaired, or prompt remedial action must be taken, and remediation must occur before the next CP cycle. 192.469 TEST STATIONS A test station is the location designated by us, on a pipeline or facility, where cathodic protection readings are taken. Test stations for potential, current, or resistance measurements must be provided at sufficient locations to facilitate cathodic protection testing. Such locations shall include, but not be limited to, the following:
• Pipe casing installations, • Gas risers, • Metallic structure crossings, • Isolating joints, • Valve stations, • Regulator stations, • Galvanic anode installations, • Road crossings, • Stray-current areas, and
• Rectifier installations.
192.471 TEST LEADS Each test lead wire must be connected to the pipeline so as to remain mechanically secure and electrically conductive. We must inspect these test leads whenever CP readings are taken.
1) Connect test lead to the pipeline: • The preferred connection is Thermit Welding (CAD). Attachment of electrical leads directly
to steel pipe by the Thermit welding process using copper oxide and aluminum powder. The Thermit welding charge must be limited to a 15-gram cartridge.
• Metallic hose clamps may be used provided they are mechanically secure, electrically conductive and secured to restrict unauthorized removal.
2) Test lead wire must be attached to the pipeline so as to minimize stress concentration on the pipe; and
3) Each stripped test lead wire and stripped metallic area at point of connection to the pipeline must be coated with an electrical insulating material compatible with the pipe coating and the insulation on the wire.
192.475 INTERNAL CORROSION CONTROL Whenever any pipe is cut out, it will be examined for internal corrosion and the conditions found will be documented. If internal corrosion is found: 1) The adjacent pipe must be investigated to determine the extent of internal corrosion by visually
inspecting access ports or cut outs; 2) If corrosion is found on the inside surface of the adjacent pipeline then remaining wall strength
calculations shall be performed and the line segment derated, replaced or repaired according to the extent of internal corrosion found. See 192.487 for remedial measures.
192.479 ATMOSPHERIC CORROSION CONTROL A pipeline exposed to the atmosphere is a pipeline that is not buried in an electrolyte such as soil. Atmospheric Corrosion is an area of metal loss due to general corrosion, localized corrosion pitting, or peeling scale on the steel surface that has damaged the pipe. Surface oxide is corrosion and if allowed to continue may affect the safe operation of the pipeline at some point in the future. Oxidation (or "light surface oxide") can be defined as the slow rusting of pipe which is not yet considered to be atmospheric corrosion because there is no evidence of metal loss at this time. Coating material is unsuitable for the prevention of atmospheric corrosion. Coating materials of non-conductive paints, coatings, or jackets which will isolate the metal from the atmosphere and are suitable for the contaminants in the atmosphere must be used to protect against atmospheric corrosion. Soil-to-air interfaces (where the pipe first leaves the soil and is exposed to the atmosphere) are areas critical because of the transient conditions and must be protected from atmospheric corrosion. Protection must be accomplished by ensuring that the pipe is coated and painted several inches above and below these interfaces.
1. We must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, Coating material must be suitable for the prevention of atmospheric corrosion., SEE 192.461;
2. Except portions of pipelines in soil-to-air interfaces, we need not protect from atmospheric corrosion any pipeline for which we can demonstrate by test, investigation, or experience appropriate to the environment of the pipeline, that corrosion will: a) Only be a light surface oxide; or b) Not affect the safe operation of the pipeline before the next scheduled inspection. If found,
we will take remedial measures and clean and either coat or jacket the areas of atmospheric corrosion with a material suitable for the prevention of atmospheric corrosion.
192.481 ATMOSPHERIC MONITORING Particular attention shall be given to corrosion at soil-to-air interfaces, under thermal insulation, under dis-bonded coatings, and at pipe supports. At least once every 3 years not to exceed 39 months, we will check for atmospheric corrosion. The presence of atmospheric corrosion can be detected best by visual inspection. During inspections attention must be given particularly to pipe at soil-to-air interfaces (boundary line between soil and pipe), under thermal (jacketed) insulation, under disbonded coatings, at pipe supports, clamps, rest plates, and sleeved openings. This may require ladders, scaffolds, hoists, or other suitable means of permitting access to the structure being inspected. Evidence of atmospheric corrosion on meters and regulators may also be determined by inspection by employees such as persons who conduct continuing surveillance. If atmospheric corrosion is found, the condition will be corrected by cleaning the affected area and painting it with exterior paint that is made to protect metal from atmospheric corrosion or coated with an approved tape. If serious/extensive atmospheric corrosion is found, the condition will be evaluated and a determination made whether replacement is necessary.
192.483 REMEDIAL MEASURES
a) Each segment of metallic pipe that replaces pipe removed from a buried pipeline because of external corrosion must have a properly prepared surface and must be provided with an external protective coating that meets the requirements of Sec. 192.461.
b) Each segment of metallic pipe that replaces pipe removed from a buried pipeline or repaired because of external corrosion must be cathodically protected immediately.
192.487 REMEDIAL MEASURES GENERAL/LOCALIZED CORROSION General Corrosion is: Corrosion pitting so closely grouped as to affect the overall strength of the pipe. Localized Corrosion is: The selective removal of metal by corrosion at small areas or zones on a metal surface in contact with a corrosive environment. Each segment of generally corroded pipe with a remaining wall thickness less than that required for the MAOP of the pipeline, or a remaining wall thickness less than 30 percent of the nominal wall thickness, must be replaced. Corroded pipe may be repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. Reliable engineering tests and analyses must demonstrate compliance with a performance standard. We may conduct our own tests and analyses; or,
we may choose to accept testing and analyses done by manufacturers, trade associations, or consultants. The engineering tests and analyses must include the following items, as needed, to achieve satisfactory precision:
(1) Concise and orderly procedures for conducting tests and analyses; (2) Listing of equipment needed; (3) Descriptions of test specimens; (4) Required calculations; (5) Knowledge and experience relating to the subject area; (6) Data evaluation and statistical analysis; (7) Assessment of test results to verify an analytical model; and (8) Application of scientific principles.
Localized corrosion pitting: Pipe with localized corrosion pitting to a degree where leakage might result, must be replaced or repaired. 192.491 CORROSION RECORDS
Records must ensure that they are Reliable, Traceable, Verifiable, and Complete and must provide the following:
1. Who; 2. What; 3. Where; 4. When; and 5. Why
We must maintain records or maps to show the location of:
1) Cathodically protected piping; 2) Cathodic protection facilities; 3) Galvanic anodes; 4) Neighboring structures bonded to the cathodic protection system; 5) Showing a stated number of anodes, installed in a stated manner or spacing; and 6) Need not show specific distances to each buried anode.
Each record or map must be retained for as long as the pipeline remains in service.
We must maintain a record of each test, survey, or inspection required by 49 CFR in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist. These records must be retained for at least 5 years, except that records related to 192.465(a) and (e) and 192.475(b) must be retained for as long as the pipeline remains in service.
This Section Prescribes Minimum Leak-Test And Strength-Test Requirements For The Pipelines. TEST REQUIREMENTS
Records must ensure that they are Reliable, Traceable, Verifiable, and Complete
192.503 General requirements The test procedures requirements in the section must include the following:
1. The method and equipment used-
a. Equipment must be calibrated or verified; b. The preferred method is a chart; and c. If a gauge is used it must be at a pressure range that will easily indicate any leaks.
2. The test medium must be gas, air, liquid or inert gas; 3. Maximum test pressure; 3. The duration of the test; 4. The volumetric content of the piping and its location; and 5. The reason for the pressure test; such as,
(i) New construction; (ii) Pipe replacement; (iii) Class location changes; (iv) Uprating; (v) Integrity assessment; or (vi) Other as deemed appropriate.
(6. Records must indicate: 1) Who; 2) What; 3) When; 4) Where; and 5) Why.
A. We shall not operate a new segment of pipeline, or return to service a segment of pipeline that has been relocated or replaced, until:
1. It has been tested in accordance with 192.619 to substantiate the Maximum Allowable Operating Pressure (MAOP); and2. Each potentially hazardous leak has been located and eliminated.
B. We must test with liquid, air, natural gas, or inert gas that is:
1. Compatible with the material of which the pipeline is constructed; Relatively free of sedimentary materials; and, Except for natural gas, nonflammable.
If a component other than pipe is the only item being replaced or added to a pipeline, a strength test after installation is not required, if the manufacturer of the component certifies that:
1. The component was tested to at least the pressure required for the pipeline to which it is being added; 2. The component was manufactured under a quality control system that ensures that each item
manufactured is at least equal in strength to a prototype and that the prototype was tested to at least the pressure required for the pipeline to which it is being added; or
3. The component carries a pressure rating established through applicable ASME/ANSI, Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS) specifications, or by unit strength calculations as described in 192.143.
192.509 STEEL MAIN TEST REQUIREMENTS Steel mains shall be tested in accordance with 192.619 to substantiate the Maximum Allowable Operating Pressure (MAOP). Each segment of a steel pipeline that is to be operated below 100 psi must be leak tested in accordance with the following: The test procedure used must ensure discovery of all potentially hazardous leaks in the segment being tested:
1. We must test each main that is to be operated at less than 1 psi gage to at least 10 psi gage; and
2. Each main to be operated at or above 1 psig must be tested to at least 90 psi gage.
192.511 STEEL SERVICE TEST REQUIREMENTS Steel service lines shall be tested in accordance with 192.619 to substantiate the Maximum Allowable Operating Pressure (MAOP). a. We must test each segment of a steel service line in accordance with this section before being placed
in service. If feasible, the service-line connection to the main must be included in the test; if not feasible, it must be given a leakage test at the maximum operating pressure when placed in service.
1. Each segment of a Steel service line intended to be operated at a pressure of at least 1 p.s.i.
gage but not more than 40 p.s.i. gage must be given a leak test at a pressure of not less than 50 p.s.i. gage; and
2. Each segment of a Steel service line intended to be operated at pressures of more than 40p.s.i.
gage must be tested to at least 90 p.s.i. gage.
192.513 TEST REQUIREMENTS PLASTIC a. We must test each segment of a plastic pipeline in accordance with this section. b. The test procedure must ensure discovery of all potentially hazardous leaks in the segment being
tested. 1. The test pressure must be at least 150 percent of the maximum operating pressure or 50 p.s.i.
gage, whichever is greater. However, the maximum test pressure may not be more than three times the pressure determined by 192.121.
2. During the test, the temperature of thermoplastic material may not be more than 100 F, or the temperature at which the material's long-term hydrostatic strength has been determined under the listed specification, whichever is greater.
Repairs by replacement shall be made with material and methods approved for gas piping. All repairs will be performed by qualified personnel. On any new or maintenance repair work, components such as regulators, connectors, and valves, shall be examined to ensure that they are of listed or approved specifications and pressure ratings for compliance with the current regulation. 192.517 TEST RECORDS (a) We must retain for the useful life of the pipeline, a record of each test performed. The record must contain at least the following information:
1. Unit name, the name of the employee responsible for making the test, and if applicable the name of any test company used;
2. Test medium used; 3. Test pressure; 4. Test duration; 5. Pressure recording charts, or other record of pressure readings ; 6. Recording chart or pressure gage calibration dates; 7. Leaks and failures noted and their disposition.
(b) We must maintain a record of each test required for at least 5 years.
This Section Prescribes Minimum Requirements For (Uprating) For Pipelines.
The Maximum Allowable Operating Pressure (MAOP) established is currently adequate for our pipeline system. Should there be a need to increase our MAOP we must meet the requirement of 192.553 and 192.557 by establishing written procedures prior to uprate.
This Subpart Prescribes Minimum Requirements For The Operation Of Pipeline Facilities. 192.603
We may use any recordkeeping method that produces accurate, written and authentic records. Electronic records may be kept.
Records must ensure that they are Reliable, Traceable, Verifiable, and Complete Part 191 and Part 192 include requirements for reports, inspections, tests, written procedures, records, and similar actions on our part. Each regulation section must clearly and precisely state such requirements and the actions to be taken. The data constituting these records must be retained in a medium that has a life expectancy at least equal to the specified retention period prescribed in 49 CFR Parts 191 & 192. Records are required by New Mexico Public Regulation Commission (state) and/or the Pipeline Hazardous Materials Safety Administration (PHMSA) federal regulatory agency, pursuant to Federal and State law we must permit access to or the coping of pertinent records. These records shall be kept where Operation & Maintenance pipeline activities are conducted and must be comprehensive and in an orderly manner for employees or contractors use and must be available during State and/or Federal Inspections. 192.603 GENERAL RECORD PROVISIONS Records will be kept on file in sufficient detail to demonstrate compliance with all functions covered by procedures. Pipeline system mapping will be part of the records and the mapping will be kept up to date. Records must ensure that they are Reliable, Traceable, Verifiable, and Complete. 192.613 CONTINUING SURVEILLANCE
Surveillance must be continuous; however, in no case less than quarterly (4 times each calendar year) to identify any pipeline facilities experiencing abnormal or unusual operating and maintenance conditions. This will be accomplished by visual inspection of the facility as follows:
1. Effects of exposure or movement of pipeline facilities; 2. Potential for, or evidence of, tampering, vandalism, or damage; 3. Effects of encroachments on pipeline facilities; 4. Potential for gas migration through air intakes into buildings from meters, regulators or risers; 5. Specific circumstances relating to patrolling and leakage; 6. Potential for, or evidence of, soil or water accumulation in vaults or pits; 7. Potential for, or evidence of, excavation activity; 8. Inadequate support and backfill; and 9. Tree root or rock impingement.
192.614 (C) (6) DAMAGE PREVENTION
We will provide for inspection of pipelines where we have reason to believe they could be damaged by excavation. An inspection must be done as frequently as necessary during and after the activities to verify the integrity of the pipeline. In the case of blasting, all inspections must include leakage surveys. We will provide for temporary marking of buried pipelines in the area of excavation activity before the activity begins. Markings will follow the New Mexico Excavation Law. (a) Each notification will be evaluated to determine the need for, and the extent of, the inspection. Where required, the inspection may include periodic or full-time surveillance and may include leak surveys during and after construction. We must maintaining field contact with the excavator during the excavation activities to avoid potential problems and to promptly resolve any problems that may arise. The following factors must be considered in determining the need for, and extent of, inspections.
1. Type and duration of the excavation activity involved; 2. Proximity to the pipeline facilities; 3. Type of excavating equipment involved; 4. Importance of the facilities; 5. Type of area in which the excavation activity is being performed; 6. Potential for a serious incident should damage occur; 7. Past experience of the excavator; 8. Potential for damage occurring which may not be easily recognized by the excavator, such as
improper support during excavation and backfill or trenchless installations (e.g., boring); 9. Potential for facility markings to become obscured;
10. Verifying the location of the facilities by hand digging test holes., if necessary; 11. Maintaining minimum clearances of powered equipment from facilities; and 12. Preserving location markings.
18.60.2.8 C (6) NMAC In addition to Leak procedures in this manual, employees who respond to gas leaks caused by excavation must consider the possibility of multiple leaks and must check for gas accumulation in nearby buildings, and, if necessary, to take steps to promptly stop the flow of gas, such as:
1. Check the atmosphere of adjacent buildings using the appropriate instrument; 2. Evacuate all persons from the premises if there is any doubt about their safety; and 3. Ventilate the facilities, as required and verify explosive limits.
This procedure applies to both employee and contractor personnel who are responsible for emergency response to pipeline leaks or incidents.
EMERGENCY PROCEDURES
The Priority Will Be To Take Action Necessary To Protect People First And Then Property.
EMERGENCY PLAN 192.615(a)
The purpose of this emergency plan is to establish written procedures to minimize the hazard resulting from gas leaks or a gas pipeline emergency.
Receiving, identifying, and classifying notices of events which require immediate response. A map or blueprint of the system will be made available to maintenance personnel and they will be instructed to familiarize themselves with the locations of the valves that may be used in an emergency. EMERGENCY SITUATIONS - In case of a major leak, broken gas line, fire, or explosion, and upon learning of the incident personnel are instructed to call: Fire Department: Gas Supplier:
Police: Other:
Ambulance:
Maintenance personnel will follow the procedures for prompt and effective response to each of the following type of emergencies. More specific actions in emergency response may be needed and should be implemented as deemed appropriate, including procedures for the use of equipment under various situations.
RECEIVING AND HANDLING EMERGENCY CALLS To ensure prompt and adequate handling of all calls, reports, or indications concerning emergencies whether they are from customers, the public, operator employees, contractors, or other sources. The following must be included:
1. Arrangements for receiving notification of an emergency at any hour of the day, see 192.615(a)(4) below for list of available personnel.
2. When an answering service is used, answering service personnel shall be trained and have updated emergency call-out lists of operator personnel for emergency response.
Employees who receive calls must document the following details: 1. Name; 2. Address/Location of leak or odor; 3. Telephone number; 4. Reason for call; 5. Location of the odor (inside or outside); 6. Strength of odor? 7. Length of time odor has been present? 8. Was anyone working on indoor gas piping or appliances? 9. Is there any construction in the area? 10. Can you hear evidence of escaping gas? 11. What type of building or facility is involved? If the answers to these or other questions indicate a potentially hazardous situation, providing additional instructions to the caller, such as the following:
a. Do not create a source of ignition by operating switches, electrical appliances, or portable telephones.
b. Evacuate the area and wait for operator personnel to arrive. c. Call back from a safe location to provide additional information for response personnel.
Confirm that the caller understands the instructions and repeat instructions as necessary. If gas leakage or other hazard is determined to be significant, contact the local emergency response agency. Call 911 where appropriate, informing them of the emergency situation and providing pertinent information. Emergency situations: Emergency situations that require immediate response include the following:
1. Gas ignition or explosion. 2. A hissing noise is present or there is any indication of a broken or open-ended pipe. 3. Report of a pulled service or damaged facility. 4. Gas odor throughout the premise or building.
Arrangements made for establishing and maintaining adequate public and operator communications must be made. These arrangements must include means of communication with appropriate fire, police, and other public officials. Prompt and effective response to a notice of each type of emergency, including the following: I. Gas leaks inside Call regarding Faint odor or low (non-flammable) concentration of gas.
a) Make effort to determine source of leak on gas appliances; b) Caution building occupants; and c) Ventilate building; open windows, etc.
II. Strong odor or high concentration of gas (flammable range)
a) Evacuate building; call supervisor for assistance; b) Eliminate ignition sources; turn off gas meter; c) Evacuate home or building; d) Alert additional personnel with emergency equipment; and e) Make an effort to determine source of leak.
If a strong odor of gas is detected inside the home instruct customers: DO NOT turn on or off any electrical switches;
DO NOT use matches, lighters, or any gas or electrical appliances;
DO NOT use any telephones including cell phones;
Get neighbors assistance to report the emergency; and
LEAVE the home immediately until further notice. Do Not turn anything on or off and Do Not open or
close anything on your way out.
III. Gas leaks outside
(a) Faint odor or low concentration of gas at house or building foundation. (b) (c) Make an effort to determine source of leak using pinpointing technique. (d) (e) Strong odor or high concentration of gas shown on CGI at house foundation.
1. Evacuate building, turn off gas meter (Follow the Do Not above); 2. Alert additional personnel with emergency equipment; 3. Notify supervisor and fire department; 4. Turn off the gas meter; and
5. Barricade and keep people away from the area. IV. Broken Gas Line:
1. Alert additional personnel with emergency equipment; 2. Notify supervisor, gas supplier and fire department; 3. Alert and caution all residents; and 4. Barricade and guard the area.
V. Explosion or Fire involving gas lines or located near the gas lines:
1. Turn off the gas meter; 2. Alert additional personnel with emergency equipment; 3. Notify the Gas Company and fire department; 4. Alert and caution all residents; and 5. Barricade and guard the area
VI. Natural Disaster: The appropriate procedures listed above will be followed for natural disasters that cause gas leakage, fire or explosion.
NMAC 18.60.2.8 (C) (6) References in 49 CFR 192.605(b), 192.615(a) (7) to "procedures for making safe any actual or potential hazard to life or property" shall include specific procedures for emergency response to excavation damage near buildings that adequately address the possibility of multiple leaks and gas migration into nearby buildings. 192.615(a) (4) EMERGENCY NOTIFICATION LIST, (MANAGER AND/OR MAINTNANCE PERSONNEL)
CONTACT PERSON
DAY TELEPHONE
NIGHT TELEPHONE
Persons, Emergency Units And Sources Available For Assistance In An Emergency :
CONTACT PERSON
DAY TELEPHONE
NIGHT TELEPHONE NUMBER
Maintenance Personnel Will Be Instructed On The Use And Location Of The Following Emergency Equipment:
1. ___________ 2. ___________
3. ___________ 4. ___________ 5. ___________
192.615(a) (5) The priority will be to take action necessary to protect people first and then property.
192.615(a) (6) Personnel must become familiar with the pipeline system map to ensure location of emergency isolation valves that will be used as necessary to shutdown or reduce pressure to a section of the system where fire or explosion is involved to minimize hazards to life and property. 192.615(a) (7) All hazards or potential hazards to life or property will be made safe by following 192.615(a) items I through VI above.
192.615(a) (9) Shutdown & Outage Procedure: When the gas system or part is shutdown. Personnel will take the appropriate action as necessary to have gas service resumed as quickly as possible. Upon shutdown and interruption of service, all gas outlets at the meters or connection to customers piping, which are affected by the interruption must be closed, tagged, and customers notified. The piping system will be thoroughly examined to isolate the problem area. Leak detection survey will be conducted to determine the location and cause of leakage. List of available assistance will be followed if outside sources are necessary to make repairs or to resume service as quickly as possible. As soon as possible after the emergency, action will be taken to investigate the cause of any accident or failure according to §192.617.
192.615(b) (1) & (2) A copy of the latest edition of the emergency plan will be provided to supervisors responsible for emergency action. Training will be provided to operating personnel on the requirements of the emergency plan and the effectiveness of the training will be documented. After each emergency, employees’ activities will be reviewed to determine if the procedures were effectively followed. 192.616(j) Public Awareness We will provide our customers a public awareness message twice annually that includes:
1. A description of the purpose and reliability of the pipeline; 2. An overview of the hazards of the pipeline and prevention measures used; 3. Information about damage prevention; 4. How to recognize and respond to a leak; and
5. How to get additional information. Form 003 Must be used to provide Public Awareness messages. The information will be provided directly to customers twice annually or posted where tenants/customers frequent the location. 192.617 Investigation Of Failures In the event of a failure, an investigation will be conducted to determine the cause and minimizing the possibility of a recurrence. We must conduct a failure investigation and subsequent analysis to determine the root cause(s) of the failure. The investigation may be as simple as assembling an internal review group or as complex as conducting a full-scale failure investigation with laboratory analysis of a failed component. The general process for performing root-cause analysis is as follows:
1. Assemble a review team, this may require subject matter expert (SME) i.e., contractor(s); 2. Define the problem and gather data and documentation; 3. Identify factors that contributed to the problem (i.e., causal factors); 4. Find the root cause for each causal factor, such as people, equipment, material, process, or outside
influence; 5. Develop and assign recommendations; 6. Distribute recommendations and review procedures; and 7. Implement the recommendations.
Investigation Procedures:
1. Secure site and preserve unmolested, in place, any failed pipe or components; 2. Document any observations, photographs, conditions, and information from any witnesses at the scene; 3. Cooperate and assist in the investigation conducted by State and Federal pipeline safety inspectors; 4. Upon removal from the site, maintain chain of custody of any pipe or components that may have
contributed to the cause of the incident; and 5. Retain professional investigation agents and test laboratory if necessary.
Data Collection: When a detailed analysis is to be made, a person at the scene of the incident shall be designated to coordinate the investigation. That person's responsibilities should include the following:
1. Acting as a coordinator for all field investigative personnel; 2. Maintaining a log of the personnel, equipment, and witnesses; 3. Recording in chronological order the events as they took place; 4. Ensuring that photographs are taken of the incident and surrounding areas; 5. Ensuring the notification of all appropriate governmental authorities; and 6. Ensuring the preservation of evidence.
Specimens Selecting, collecting, preserving, labeling, and handling of specimens:
1. Avoid changing the granular structure in the areas of investigatory interest (e.g., avoid heat effects from cutting and outside forces due to tools and equipment).
2. Care shall be taken to ensure proper sampling and handling of soil specimens where corrosion may be involved.
3. Control the cutting, cleaning, lifting, identifying, and shipping of pipe specimens to preserve on the pipe surface, and on any tear surface or fracture face, including making cuts far enough from the failure to
avoid damaging critical areas of the specimen. 4. The number of specimens needed to be collected at the failure site may vary depending on the type and
number of tests anticipated. A series of independent or destructive tests may require multiple specimens. If there is a need to confirm the pipe material specifications, then additional pipe specimens must be obtained near the failure, but in an area of the piping where the physical properties and characteristics are unaffected by the failure itself.
192.619 Maximum Allowable Operating Pressure We must not operate a segment of steel or plastic pipeline at a pressure that exceeds a maximum allowable operating pressure determined under paragraph (c) of this section, or the lowest of the following: (1) The design pressure of the weakest element in the segment, determined in accordance with subparts C and D of 49 CFR Part 192. If any variable necessary to determine the design pressure under the design formula (§192.105) is unknown, one of the following pressures is to be used as design pressure: (i) Eighty percent of the first test pressure that produces yield under section N5 of Appendix N of ASME B31.8 (incorporated by reference, see §192.7), reduced by the appropriate factor in paragraph (a)(2)(ii) of this section; or (2) The pressure obtained by dividing the pressure to which the segment was tested after construction as follows: (i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5. (3) The highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column. This pressure restriction applies unless the segment was tested according to the requirements in paragraph (a)(2) of this section after the applicable date in the third column or the segment was uprated according to the requirements in subpart K of this part:
Pipeline segment
Pressure date Test date
March 15, 2006, or date line becomes subject to this part, whichever is later.
5 years preceding applicable date in second column.
All other pipelines.
July 1, 1970 July 1, 1965
(b) We must not operate a segment unless overpressure protective devices are installed on the segment in a
manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with §192.195.
(c) The requirements on pressure restrictions in this section do not apply in the following instance.
We may operate a segment of pipeline found to be in satisfactory condition, considering its operating and maintenance history, at the highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column of the table in paragraph (a)(3) of this section. We must still comply with §192.611. The history must be 5 consecutive years and our records must show that during those 5 years the pipeline system was maintained as required by 49 CFR Part 192.
192.625(a) ODORIZATION OF GAS The combustible gas in the distribution system must contain a natural odorant or be odorized so that
at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell.
192.625(a) A combustible gas in a distribution line must contain a natural odorant or be odorized so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell.
192.625(f) Odorization of Gas To assure the proper concentration of odorant we must conduct periodic sniff test samplings and annually receive written verification from our gas source that the gas has the proper concentration of odorant. Sampling sites must be selected to ensure that all gas within the piping system contains the required odorant concentration. The number of sites selected depends upon the size and configuration of the system and locations suspected of low odorant level within the system. Low indication of odor shall be reported to our gas supplier immediately. The testing must be performed semi-annually to ensure that the gas intensity is acceptable. Sniff tests are qualitative tests that must be performed by individuals with a normal sense of smell. Such tests must be conducted by releasing small amounts of gas for a short duration in a controlled manner to determine whether odorant is detectable.
1. We will retain records of sniff testing and records received from gas suppliers. 2. Records of sniff testing shall include the name of the person conducting the test, the date and
location of the test, and whether odorant was detected.
192.627 Tapping Pipelines Under Pressure
Any pipeline taps made under pressure will be done by qualified contractor personnel. Self-tapping tees will be used for service lines. Qualification must be available and supported by appropriate records or equivalent documents. It is acceptable to use the procedures as provided by the hot tap equipment manufacturer, as long as an associated reference is in the Procedural Manual and records. During the tapping we must address the following:
1. Verify pressure; 2. Inspect pipe for external corrosion; 3. Verify proper tap / seam / joint relationships; and 4. Verify tapping equipment and materials are correct for intended pressure service.
192.629 Purging Of Pipelines
1. When a pipeline is being purged of air by use of gas, the gas must be released into one end of the line in a moderately rapid and continuous flow. If gas cannot be supplied in sufficient quantity to prevent formation of a hazardous mixture of gas and air, a slug of inert gas must be released into the line before the gas.
2. When a pipeline is being purged of gas by use of air, the air must be released into one end of the line in a moderately rapid and continuous flow. If air cannot be supplied in sufficient quantity to
prevent formation of a hazardous mixture of gas and air, a slug of inert gas must be released into the line before the air.
3. The gas must not be purged into a confined space or area where there is an ignition source. Personnel shall ensure there is adequate ventilation and control the purging rate.
4. Personnel must monitor the discharge point of the purge with a combustible gas indicator and stopp the purge as soon as gas is detected. Purging stack must be used for all purging.
Use of Venting Stacks:
1. Purge stack(s) shall be of a size that will permit the free escape of purging and must be extended an adequate height above the ground and above personnel to prevent possible ignition from ground sources.
2. Service risers may be used as the stack as long as the purge through the riser can be completed safely as in No. 1 above;
3. When purging plastic pipe, a grounded steel stack or riser shall be used to eliminate static electricity on the inside of the plastic pipe that could be generated during the purging;
4. Ensure the stack is fabricated with a plastic to steel transition fitting and that the steel has been properly grounded;
5. Make sure the discharge is directed away from any buildings or potential ignition hazards 6. Personal Protective Equipment (PPE) must be worn; 7. Flame cutting may not be used; 8. Cutting tool and the pipe must be grounded separately; 9. A dry chemical fire extinguisher must be available during the purge and ready for immediate
use.
This Part Prescribes Requirements For Maintenance
192.703 General Any time a pipeline is found to be damaged or deteriorated to the extent that its serviceability is impaired or leakage constituting a hazard is evident, immediate temporary measures must be employed to protect the public and property. If it is not feasible to make a permanent repair at the time of discovery, permanent repairs must be made as soon as feasible. Each segment of pipeline that becomes unsafe must be replaced, repaired, or removed from service. Hazardous leaks must be repaired immediately. Leak classification are defined in part 18 NMAC 60.2.12 CLASSIFICATION & REPAIR OF LEAKS of this manual.
192.723 Leakage Survey An electronic gas detector type leak survey will be conducted on an established schedule as follows:
1 . As frequently as necessary, but at least once every 5 calendar years at intervals not exceeding 63
months; 2. The need for more frequent leak surveys will be determined by the system conditions and leak
survey results; and 3. Consideration shall be given to increased frequency for leak surveys based on the particular
circumstances and conditions;
If a Leak Is Found:
BARHOLE, MIGRATION, AND PERIMETER SURVEYS The migration of gas must be determined by establishing the outer boundaries of the indications. This will define the area in which the leak will normally be located. These tests must be made with a CGI without expending excessive effort providing sample points.
1. Turn on the CGI and purge the instrument with air and properly set it to zero. 2. Set the CGI on the Lower Explosive Limit scale (LEL) 3. Begin the investigation at the location identified by the report originator smelling the gas; if gas is
detected, perform a migration barhole survey by testing in a circular pattern (or any geometric pattern necessary) to determine the extent of the gas migration;
4. Test at intervals of 12 feet or less around the complete area; 5. Prior to bar holing, the location of the service must be known; 6. Make barholes at a depth of 18 inches or less for services and 24 inches for mains and place these
barholes as close as possible to the services or mains; 7. Survey by testing in a circular pattern until the CGI zeros out; and 8. Check all available substructures in the area of migration.
Pipelines to be surveyed will be located/traced and marked before each leakage surveys. Accurate up to date maps may be used to ensure the leak survey is conducted over the gas lines. The supervisor/manager will ensure proper technique in the use of each type of leak detection equipment and in the method of conducting leak surveys. Accurate and complete records will be kept of all lines surveyed, leaks detected and their classification. All leak detecting instruments will be calibrated before each use and records kept.
192.725 TEST REQUIREMENTS FOR REINSTATING SERVICE LINES
1. Each disconnected service line must be tested in the same manner as a new service line, before being reinstated.
2. Each service line temporarily disconnected from the main must be tested from the point of disconnection to the service line valve in the same manner as a new service line, before reconnecting. However, if provisions are made to maintain continuous service, such as by installation of a bypass, any part of the original service line used to maintain continuous service need not be tested Plastic service repair:
I. Squeeze off service upstream of damage/leak; II. Purge line at riser;
III. Cut of damage; IV. Install fitting, prepare to pressure test; V. Pressure test line up to the riser shut off valve;
VI. Install pretested pipe; VII. Remove squeeze off tool; and
VIII. Soap upstream and downstream fusion joints. The repair (point of disconnection) must be soap tested.
192.727 ABANDONMENT OR DEACTIVATION OF FACILITIES
Each pipeline abandoned in place must be disconnected from all sources and supplies of gas; purged of gas; and sealed at the ends. Abandonment must not be completed until it has been determined that the volume of natural gas contained within the abandoned section poses no potential hazard. Sealing Methods of sealing pipeline or main openings include, as applicable, the following:
1. Using normal end closures, such as welded or screwed caps, screwed plugs, blind flanges, and mechanical joint caps and plugs;
2. Welding steel plate to pipe ends; 3. Filling ends with a suitable plug material; or 4. Pinching the ends closed.
Whenever service to a customer is discontinued, one of the following must be complied with:
1. The valve that is closed to prevent the flow of gas to the customer must be provided with a locking device or other means designed to prevent the opening of the valve by persons other than those authorized;
2. A mechanical device or fitting that will prevent the flow of gas must be installed in the service line or in the meter assembly; or
3. The customer's piping must be physically disconnected from the gas supply and the open pipe ends sealed.
192.739 Pressure Limiting And Regulating Stations: Inspection And Testing.
Each pressure limiting station, relief device (except rupture discs), and Pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is-
1. In good mechanical condition as follows: a) Perform pressure test; b) Insure that regulators “Locks Up” by stopping gas flow downstream; and c) Inspect mechanical moving parts as necessary.
2. Adequate from the standpoint of capacity and reliability of operation for the service in which it is employed.
a) We must design regulators for capacity for the load they are serving. 3. Properly installed and protected from dirt, liquids, or other conditions that might prevent proper
operation.
192.747 VALVE MAINTENANCE (a) Any distribution main valves designated as key valves (emergency valves) will be checked for leaks, lubricated, and partially operated on an established schedule each calendar year at intervals not exceeding fifteen (15) months. (b) We will take prompt remedial action to correct any valve found inoperable, or designate an alternative valve if available.
INOPERABLE VALVES
One of The Following Actions Will be Performed If A Valve Is Found Inoperable.
(a) Repair the valve to make it operable.
(b) Designate another valve or valves to substitute for the inoperable valve that will provide a similar level of effectiveness for isolating the desired area.
Update the Following:
(1) Updating records for emergency shutdown and future maintenance requirements.
(2) Informing employees of the change to the isolation or emergency shutdown plan.
(c) Replace the valve.
192.751 PREVENTION OF ACCIDENTAL IGNITION
1. Smoking and open flames: Smoking and open flames is prohibited in the following locations.
• In structures or areas containing gas facilities where possible leakage or presence of gas constitutes a hazard of fire or explosion.
• In the open when accidental ignition of gas-air mixture might cause personal injury or property damage.
2. Accidental electric arcing:
To prevent accidental ignition by electric arcing, the following must be considered.
• Flashlights, portable floodlights, extension cords, and any other electrically powered tool or equipment shall be of a type approved for use in hazardous atmospheres. Care must be taken to ensure that electrical connections and disconnections are not made, and are prevented from occurring, in hazardous atmospheres.
• Internal combustion engines that power trucks, cars, compressors, pumps, generators, and other equipment must not be operated in suspected or known hazardous atmospheres.
• Bonding to provide electrical continuity shall be considered installed around all cuts separating metallic pipes that may have natural gas present. This bond shall be installed prior to cutting and maintained until all reconnections are completed or a gas free environment exists. Bond cables must be installed in a manner to ensure that they do not become detached during construction and that they provide minimal electrical resistance between pipe sections.
3. Static electricity on plastic pipe:
A static electric charge can build up on both the inside and outside of plastic pipe due to the dielectric properties of plastic. Discharging of the static electricity going to ground can cause an arc that will cause ignition if a flammable gas-air mixture is present. Arc preventing safety precautions are necessary.
The following shall be performed:
(a) Leaking or escaping gas shall be eliminated by closing valves or excavating and squeezing-off in a separate excavation at a safe distance from the escaping gas.
(b) If escaping gas cannot be effectively controlled or eliminated and it is necessary to work in an area of escaping gas, safety provisions must be considered such as dissipating or preventing the accumulation of a static electrical charge, venting the gas from the trench, and grounding those tools used in the area. Additionally, flame-resistant clothing treated to prevent static buildup and respiratory equipment shall be used.
Acceptable methods of dissipating or preventing the accumulation of static electricity include wetting the exposed area with an electrically conductive liquid (e.g., soapy water with glycol added when ambient temperatures are below freezing) and using an anti-static polyethylene (PE) film or wet non-synthetic cloth wound around or laid in contact with the entire section of exposed pipe and grounded with a brass pin driven
into the ground. Commercially available electrostatic discharge systems may be considered as a means of eliminating static electricity from both the inside and outside of PE pipe.
(c) A plastic pipe vent or blowdown stack must not be used due to the possibility that venting gas with a high scale or dust content could generate an internal static electrical charge that could ignite the escaping gas. Metal vent stacks must be grounded before placement in the escaping gas stream. Venting shall be done downwind at a safe distance from personnel and flammable material.
(d) To reduce potential sources of ignition, all tools, including squeeze-off tools, used in gaseous atmospheres should be grounded or the non-sparking type.
Fire extinguishers:
If escaping gas in the area of the work is possible, a fire extinguisher must be available upwind and adjacent to the area. It shall be fully charged and inspection must be current.
Verification of the presence of gas:
Gas or electric welding or cutting may not be performed on pipe or on pipe components that contain a combustible mixture of gas and air in the area of work.
Prior to welding, cutting, or performing other work on isolated sections of gas piping, a check shall be made with a gas detector for the presence of a combustible gas mixture inside the pipe. Work must not begin until safe conditions are indicated. If the work takes place over an extended period of time, the line shall be periodically monitored to ensure that a combustible gas mixture does not accumulate.
Posting Warning Signs:
(a) Posting warning signs.
(b) Directing motor vehicles and pedestrians away from the area by the following.
(1) Law enforcement.
(2) Traffic flaggers.
(3) Signs (e.g., detour, road closed).
(4) Barricades.
NMAC 18.60.2.12 CLASSIFICATION & REPAIR OF LEAKS All leaks upon discovery must be classified into one of the following three general categories: Hazardous Leak, Grade I or C: A leak which due to its location and/or magnitude constitutes an immediate hazard to persons or property. Potentially Hazardous Leak, Grade II or B: A leak that does not constitute an immediate hazard, but may become hazardous if not repaired within a reasonable time period. Non-Hazardous Leak, Grade III or A: A leak which does not constitute a hazard and shows no indication of becoming hazardous before routine scheduled repair could be accomplished.
PRIORITY OF REPAIRS
(Note: All leaks found shall be repaired promptly.) GRADE 1: Grade 1 leaks shall be repaired, eliminated or reclassified before leaving the site. You must remain on the
----
scene until you are relieved by an authorized person or a person qualified to make the repair or until the associated hazard has been eliminated. While on the scene, you must caution the public as needed and evacuate the area if required. GRADE 2: Grade 2 leaks shall be repaired within six months, but no later than seven months from the date the leak was reported. Grade 2 leaks shall be re-evaluated at least once every six months until repaired. GRADE 3: Grade 3 leaks shall be re-evaluated during the next scheduled leak survey or within fifteen months of the day reported, whichever occurs first until the leak is repaired. Re-evaluation is required each calendar year, not to exceed fifteen months, until the leak is repaired. 192.801 Operator Qualification: 1 GENERAL: Our Operator Qualification Program shall meet all of the requirements of 192.805. All covered tasks performed on our pipeline shall only be performed by Qualified Personnel unless an individual is directed and observed by an individual that is qualified. 2 CONTRACTORS
a) In implementing this Operations & Maintenance Plan and OQ Program, We must ensure that any contractor individual who performs covered tasks on our behalf needs to be qualified unless the individual will be directed and observed by an individual that is qualified;
b) We must include provisions in our written program to address the use of contractor(s) employee(s) performing covered tasks; and
We must ensure that qualifications are established and maintained. We may accept contractor(s) OQ Programs provided the program is reviewed by us to ensure it is consistent with our program.
RECORDKEEPING FORMS Use of these forms must comply with 49 CFR Part 192 and with our O&M Procedures. Review completed forms to insure the following is answered: WHO – person who performed covered task; and manager/supervisor
who reviewed; WHAT-- what was performed, the form may answer this part; WHEN—date and time; WHERE—location of activity i.e., address or description; and WHY – why was it required i.e., gas leak, routine maintenance, the form
may answer this part. Regarding Contractors: Contractor personnel must be Operator Qualified PRIOR to performance of covered tasks. All covered tasks performed by contractor personnel must be reviewed during performance to insure procedures are followed, and approved prior to contractor leaving premises. This may be accomplished by periodically inspecting, reviewing, or observing work being performed. Contractors are required to report at end of task performance or at end of each day. Contractors are not allowed to perform covered tasks without prior approval and without checking in with manager or designee.
FORMS
1 External or Internal Main or Service Inspection
Use Form 1
2 Gas Leak and Repair Report Use Form 2
3 Gas Inspection and Leakage Repair Use Form 3
4 Continuing Surveillance Use Form 4
5 Regulator Stations Inspection Report
Use Form 5
6 Valve Location Form Use Form 6
7 Sniff Tests & Letter Use Form 7
8 Telephone Report of Customer Leak Use Form 8
9 Atmospheric Corrosion Inspection Use Form 9
10 Pipeline Pressure Test Report Use Form 10
11 Procedural Manual Review Use Form 11
12 Leakage Survey (5 years not to exceed 63 Months)
Use Form 12
13 CGI Barhole Leakage Survey Use Form 13
14 Procedural Manual Review Use Form 14
15 Customer Buried Gas Pipeline Notice Use Form 15
16 Public Awareness Notice Use Form 16
17 Cathodic Protection Test Report Use Form 17
18 Rectifier Test Report Use Form 18
19 Use Form 19
20 Use Form 20
21 Use Form 21
22 Use Form 22
REPORT OF MAIN AND SERVICE LINE INSECTION (WHEN EXPOSED) Form 1
OPERATOR: _______________________________________Unit__________________________________________
This form is to be completed each time distribution main or service line is uncovered for inspection or any other reason, such as making service connections, main extensions, replacements, etc.
DATE:
1. Location:
2. Name of Inspector:
3. Designation of Line: Main Service
4. Age of Pipe: Years Line Size: Inches
5. Maximum Operating Pressure:
6. Pipe Specification:
7. Cathodic Protection Reading:
8. Coating: Type
9. External Condition: Smooth Pitted Depth of Pits
10. Internal Condition: Smooth Pitted Depth of Pits
11. Other Structures in the Area Endangering Pipeline:
12. Condition of Right-of-Way:
13. Corrective Measures Taken if Needed:
14. Anodes Installed: How many? Size Location
15. Soil: Kind: Sand ( ) Clay ( ) Loam ( ) Cinders ( ) Refuse ( )
16. Packing: Loose ( ) Medium ( ) Hard ( )
17. Moisture Content: Dry ( ) Damp ( ) Wet ( )
Inspected by: __________________________ Date: ________________________ Reviewed by: _____________________________ Date: ________________________
GAS LEAK AND REPAIR REPORT Form 2 Operator ________________________________________ Unit ________________________________________ Date: ____________ Time: ____________ Location (Address) ________________________________________________________ Reported by: ___________________________________ Description of Leak: _______________________________ Grade: 1 _____ 2 _____ 3 _____ INVESTIGATION: Investigation Date: _____________________ Leak Found? Yes _____ No_____ Investigated by: __________________________________ Time __________________ CGI used? Yes _____ No _____ Grade: 1_____ 2 _____ 3 _____ Location of Leak: _________________________________________________ Cause of Leak: ___________________________________________________ Condition Made Safe: Date: ________________________ Time: ______________________ Repair Report: Length of Pipe Exposed ________________feet. Leak at: Threads ________ Fitting: ______ Weld (Type) ________________ Valve _______ Other ___________ Pipe: Size ______” Steel _____ Plastic _____ Other ______ Depth _______ Coating : Wrapped _____ Scotch Coated _____ Condition: Good _____ Fair _____ Poor _____ Soil: Sand ____ Clay ____ Loam ____ Other (describe) _______________________ Moisture: Dry ____ Damp ____ Wet ____ Repair Made: _________________________________________________________________________ Anodes Installed: Amount _______ Weight ___________lbs. Depth Installed ______________ Repairs by: _________________________________________ Date: ______________________________ Reviewed by: ________________________________________ Date: ______________________________
GAS INSPECTION AND LEAKAGE REPAIR Form 3 OPERATOR: __________________________________________________________ Grade of Leak_____________
LEAK ADDRESS:
LEA
K DATA
Detected By Collecting Probable Source C.G.I. Test
Mobile Flame Pack In Building Mainline Gas Percent (%) Flame Pack Near Building Service Line L.E.L. Visual/Vegetation In Manhole Service Tap P.P.M. Combustible Meter In Soil Valve Negative Odor In Air Meter Set Bar Hole Other Tee
Pressure Surface Leak Cause
Low Lawn Corrosion Intermediate Soil Outside Force High Paved Construction Defect
Other Material Failure
Component
Explanation
Part of System
Pipe Type
Size
Year Installed
Pipe Main Steel Valve Service Plastic (PE) Fitting Meter/Regulator Set Plastic (PVC) Regulator Other
Reported by: Date Reported: __________________________ Repaired by: ________________________________ Date Repaired:________________________________
Reviewed By:_______________________________________Date Reviewed______________________________________
SKETCH SHOWING LEAKS LOCATED
Pipe Condition: Good: Fair: _____ Poor: ______
Coating Condition: Good: Fair:______
Poor: ____
CONTINUING SURVEILLANCE Form 4
OPERATOR:
Period Covered: Began Ended
Areas Covered:
Map References:
Leakage Indications Discovered (describe locations and indications, such as a condition of vegetation):
Describe any unusual conditions:
Other Factors noted which could affect present or future safety or operations of the gas system:
Follow-up (repairs, maintenance or test resulting from this inspection):
Comments:
Name of Technician: ___________________________________________ Supervisor Reviewed by:
Date Reviewed: ___________________________
REGULATOR INSPECTION REPORT Form 5
Operator: ____________________________________Unit_____________________________
Location:
Regulator Information
Make:____________________ Type: Size:__________Orfice Size: _____
Pressure Rating: Inlet: Outlet:
M.A.O.P. of System to which it is Connected: ____________ A.O.P. ______________
Operating Pressure: Inlet:_________ Outlet: Lockup OK?: Yes_____ NO_______
Pressure: ________ Setting: ________ Was the Regulator Stroked (to fully open)? Yes No
General Condition of area:
Atmospheric Corrosion: Yes No
Support Piping Rigid: Yes No
Guards: Yes No N/A _________
Area Clean of Weeds and Grass: Yes No
Corrections Made:
Remarks:
Inspected by: ______________________________ Date: __________________ Reviewed by: _______________________________________ Date: _______________________
VALVE INSPECTION REPORT Form 6 OPERATOR: ________________________________________Unit_______________________
**********
Valve Number Location Date Inspected Inspected By
**********
Valve Number Location Date Inspected Inspected By
**********
Valve Number Location Date Inspected Inspected By
Repairs Required: Yes____ No_____ Valve(s) Repaired:__________________________ Repairs Made: Yes____ No____ Lubrication Required Yes___ No____ Lubricated: Yes____ No____ N/A_____ Valve Box Clean of Debris: Yes_____ No: ______ Cleaned: Yes _____ No: _____ N/A _____ Alternate Valve Designated: Yes ________ No: _________ Not Required: Yes _____ No ______ Remarks: ____________________________________________________________ Inspected by:__________________________________ Date:_________________ Reviewed by:__________________________________ Date:_________________
ODORANT “SNIFF” TEST Form 7
Operator: ______________________________ Unit_____________________________ Location: Date: Odor Level: Nil
Barely Detectable Readily Detectable Strong
Remarks:
Observed By:
Location: Date: Odor Level: Nil
Barely Detectable Readily Detectable Strong
Remarks:
Observed By:
Location: Date: Odor Level: Nil
Barely Detectable Readily Detectable Strong
Remarks: Observed By:
Written verification from gas source: Yes_________ No________ Date:_____________________ Performed by:_____________________________________ Date:____________________________
Reviewed by:_______________________________________ Date:_____________________________
TELEPHONIC REPORT OF CUSTOMER LEAK Form 8
OPERATOR: __________________________________ Unit___________________________ Customer Leak Information
Time Call Received:________a.m./p.m. Date: ______________
Name of Caller: Caller’s Phone Number:
Name of Customer if not Caller:
Address of Leak:
Nature of Complaint: Odor ( ) Blowing Gas ( ) Dead Vegetation ( ) Other (describe):
Is the gas odor or sound inside the residence? Yes No If so, where is it located? (At the water heater, at the heating system, at the stove, in the hall, in the kitchen, etc.):
Is the gas odor or sound outside the residence? Yes No If so, where is it located? (at the meter, near the street, at the house, in the ditch, at the pool, at the gas grill, etc.):
How long have you been smelling or hearing the gas? Will someone be home for us to check the leak? Yes No
Leak Response Information Time Dispatched Investigator: am/p.m. Date: Name of Investigator: __________________________ Time of Investigator Arrival at Scene of Leak: a.m./p.m. Action Taken:
Time of Investigator Completion at Scene of Leak: a.m./p.m. Additional Follow-up (if needed): Yes No If so, what type of follow-up:
Additional Remarks:
Signature of Investigator: _________________________________ Date:____________________ Signature of Supervisor: _________________________________Date:____________________
ATMOSPHERIC CORROSION INSPECTION Form 9 OPERATOR: ______________________________ Unit_____________________________ Location:
This form is to be completed when above ground piping is inspected for corrosion from
atmospheric conditions or corrosive conditions that cannot be controlled by cathodic protection. Inspect all exposed piping every three years for atmospheric corrosion per §§192.479, 192.481 and 192.491.
Designation of Line: Distribution ( ) Service ( ) Line Size:
Area of Corrosion: Pipe ( ) Meter Set ( ) Fitting ( ) Regulator ( ) Soil-to-Air Interface ( ) Other (describe):
Corrective Measures Taken: Painted: Coated:
Other (describe): Type of Paint or Coating Used:
If General Painting of Exposed Piping is Undertaken, List Addresses Below:
Inspected By: ________________________ Date: __________________ Reviewed By:_________________________________________Date:______________________
PRESSURE TEST REPORT Form 10
OPERATOR _____________________________________ Unit___________________________
Testing By: ________________________________ Date: ______________ Time: ________________
This form must be completed for each section of newly installed or replaced section of main or service line.
Test Data
Type of Pipe: ___________ Size of Pipe: inches Length of Line:
Location of Line:
Tested with: Nitrogen ( ) Air ( ) Natural Gas ( ) Water & Air ( )
Other (describe):
Date of Test:_______________________Type of Recorder: Gauge ( ) Chart: ( )
Recorder Calibration Date:________________
Time Started: a.m./p.m. Time Ended: a.m./p.m.
Test Pressure Start: psig
Test Pressure Stop: psig
Line Loss: Yes No Amount Loss: mcf MAOP__________________AOP_______________________
Reason for Line Loss:
Corrective Measures Taken:
Remarks:
Company Representative: Date:
Reviewed by:___________________________________ Date:
PROCEDURAL MANUAL ANNUAL REVIEW Form 11
Operator: ______________________________ Unit:___________________________ The manual of written procedures for conducting operations and maintenance activities and for emergency response must be reviewed and updated at intervals not exceeding 15 months, but at least one each calendar year. The manual must be kept at locations where operations and maintenance activities are conducted. Date Reviewed:_______________ Reviewed: All Yes____ No_____ Section Reviewed:________________________________________________ Revision Required: Yes_______ No:_________ Revised: Yes _____ No:________ Date Revised ________________________ Reviewed by: Print Clearly Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Name:______________________________Signature_______________________________ Manager/Supervisor Signature:_______________________________________Date:_______________
LEAKAGE SURVEY Form 12
OPERATOR__________________________________ UNIT _____________________________ A leakage survey with leak detector equipment must be conducted at least once every 5 calendar years at intervals not exceeding 63 months. Surveys Must Include 100% Of Regulated Pipeline Facilities (Underground & Aboveground) DATE(s) of Survey: ________________________ Amount of Pipe Leak Surveyed____________________________________ Map Used: Yes: ( ) No: ( ) Pipeline Located: Yes: ( ) No: ( ) Approximate wind speed: ____________________ Instrument Used:__________________________ Calibration Date:____________________________ Leaks Found: Yes: ( ) No: ( ) Location of Leak i.e., (address):________________________________________________________ Leak Aboveground: Yes: ( ) No: ( ) Underground Yes: ( ) No: ( ) Leak at Main: Yes: ( ) No: ( ) Leak at Service: Yes: ( ) No: ( ) Grade: 1: ( ) 2: ( ) 3: ( ) Prompt Remedial Action (when Required) Date:_____________________ Action Taken:_________________________________________________________________________ Was CGI Instrument Required: Yes: ( ) No: ( ) If yes use CGI FORM 13 Surveyed By: __________________________________ Date: _______________________ Reviewed by: __________________________________Date: _______________________
LEAKAGE MIGRATION REPORT Form 13 OPERATOR:__________________________ UNIT: ________________________________
Draw Leak Migration Pattern in Box Below.
Begin the investigation at the location identified by the Flame Ionization leak detector. Perform a migration barhole survey by testing in a circular pattern or any geometric pattern to determine the extent of the gas migration. Continue probing until instrument ZERO’S (0) out. Include footages between Barholes and LEL% or/and Gas% Readings for each barhole. Identify all structures and provide footage from leak. Drawing must show all barholes including Zero (0) readings, Date: Investigated____________________________ Time Investigated: ____________________ Instrument Used:__________________________ Calibration Date:____________________________ Leaks Found: Yes: ( ) No: ( ) Location of Leak i.e., (address):________________________________________________________ Main: Yes: ( ) No: ( ) Service: Yes: ( ) No: ( ) Grade: 1: ( ) 2: ( ) 3: ( ) Prompt Remedial Action (when Required) Date:_____________________ Action Taken:_________________________________________________________________________ Investigated By: __________________________________ Date: _______________________ Reviewed by: __________________________________Date: _______________________
REVIEW OF PERSONNEL WORK Form 14 OPERATOR: ______________________________________ UNIT: ____________________________ Make a copy of procedure of task to be reviewed, insure procedure is followed. Person Observed: ____________________________________ Date: _____________________________________ Time: _________________________________ Task reviewed: ____________________________________________________________ Current Qualification Verified: Yes: ( ) No: ( ) Was task performed as required and were procedures followed: Yes: ( ) No: ( ) Able to Recognizing and react to Abnormal Operating Conditions (AOC) Yes: ( ) No: ( ) If NO was person removed from performing covered task: Yes: ( ) No: ( ) Was Person re-trained and re-evaluated: Yes: ( ) No: ( ) Comment: _____________________________________________________________________________________ _____________________________________________________________________________________ _____________________________________________________________________________________ Procedure Deficiencies: Yes ( ) No: ( ) If YES action taken:__________________________________________________________________ ____________________________________________________________________________________ Reviewer Name: ______________________________ Sign: __________________________________ Manager/Supervisor Review ___________________________Date: ____________________________
CUSTOMER NOTICE OF BURIED GAS PIPELINES Form 15
Operatoe______________________________________________ Unit _______________________________
We are required to notify you that we do not maintain your buried piping beyond our gas meter or regulator. “Maintain" means monitor for corrosion if your buried piping is metallic or survey for leaks. The buried gas piping from the meter/regulator to your home/building is customer-owned piping and is not maintained by us. You are responsible for any unsafe condition or repairs. If the customer's buried piping is not maintained, it may be subject to the potential hazards of corrosion and leakage. Buried gas piping should be:
1. Periodically inspected for leaks; 2. Periodically inspected for corrosion if the piping is metallic; and 3. Repaired if any unsafe condition is discovered. 4. When excavating near buried gas piping, the piping should be located in advance,
and the excavation done by hand. 5. Plumbing contractors or heating contractors can assist in locating, inspecting, and
repairing the customer's buried piping.
We or the local gas distribution company can provide you with information on plumbers and contractors that can assist in performing the inspections described above, making leak repairs, and in locating the buried gas lines prior to the start of any planned excavation.
PUBLIC AWARENESS MESSAGE Form 16
PURPOSE AND RELIABILITY OF THE PIPELINE
The purpose of the gas pipeline is to provide our customers with gas for their use. The pipeline is operated and maintained to protect its integrity. The line is protected to prevent corrosion, leak surveyed, patrolled, monitored, and operated and maintained as required by federal and state laws under 49 CFR Part 192.
GAS PROPERTIES
Natural gas normally is non-toxic, tasteless, colorless and odorless. For your safety, an acrid chemical, is added to the natural gas so that you will recognize it immediately, should there ever be a leak. This chemical makes natural gas smell like sulphur, or rotten eggs.
HOW TO RECOGNIZE AND RESPOND TO A LEAK
Possible indicators of a gas leak might include the following: 1. An odor of gas in a building. OR An odor of gas outside; 2. An odor of gas where excavation work is in progress or has recently been completed; 3. A hissing, roaring, or blowing sound; 4. Blowing or uncontrolled burning of gas; 5. Water bubbling or being blown in the air from water bodies or wet areas; 6. A fire in or near a gas appliance or piping; 7. Unusual dead vegetation where surrounding is normal
If you smell natural gas Leave the building immediately, taking everyone with you. Do not re-enter building for any reason. Do Not: DO: 1. Use phone, computer, appliances, 1. From an outside location call the gas company at Or garage door opener ____________24 hours a day, 7 days a week. 2. touch electrical outlets, switches or door bells Hearing & speech Impaired: Dial 711 3. Smoke or light matches or other open flames 2. From an outside location call other 4. Position or operate vehicles or powered equipment emergency contact persons 5. Do not open windows or doors
EMERGENCY CALL LIST FIRE DEPARTMENT CALL 911 GAS SUPPY COMPANY________________________________ OPERATOR CONTACT: DAY _________________ NIGHT: _______________________
DAMAGE PREVENTION No person or company shall begin any excavation on our properties before notifying our o f f i c e . When notified of an excavation, we must locate our natural gas lines as New Mexico Excavation Law requires. All marks for gas lines will be yellow in color. Location requests will be documented. This form if posted for compliance in a tenant commonly visited area such office, laundry room, and/or mail box area need not be distributed twice annually. If posted we must visit those areas to insure notice has not been remove.
CATHODIC PROTECTION TEST REPORT FORM 17 Operator/Unit___________________________________YEAR TESTED: _______________________________ Tested by: _____________________________________________ Date: _________________________ Test Location: -.85 Volt: 100 MV ON Reading: 100 MV OFF Reading: DECAY: ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ ___________ ________ _______________ _______________ _________ REVIEWED BY: _______________________________ DATE: ___________________________
RECTIFIER INSPECTION REPORT Form 18 Operator _________________________________________ Unit____________________________ RECTIFIER No. ______________________
Serial No. ______________ Intervals: 6 times per year not to exceed 2 ½ months DATE: SUPPLY OUTPUT: OUTPUT: RECTIFER VOLTAGE: VOLTAGE: AMPS CONDITION
INSPECTED BY: ______________________________ DATE: _________________________ REVIEWED BY: _______________________________ DATE: _________________________