126.05.21 Ark. Code R. 001
PREFACE
ARKANSAS GAS PIPELINE CODE
On August 12, 1968, the United States Congress passed Public Law 90-481, better known as the Natural Gas Pipeline Safety Act of 1968. This Act authorizes the Secretary of Transportation to administer this law, and to develop standards and regulate the enforcement of such standards for the design, installation, inspection, testing, construction, extension, operation, replacement and maintenance of pipeline facilities. Enacted on July 5, 1994, Public Law 103-272 revised, codified, and enacted the provisions of the Act without substantive change as Chapter 601 of Title 49, United States Code. Title 49 U.S.C. 60105 authorizes a state to regulate these minimum standards under a certification to the Secretary of Transportation that provides certain provisions are met by the state.
On March 15, 1971, the Arkansas General Assembly enacted Act 285 of 1971, the Arkansas Natural Gas Pipeline Safety Act of 1971, codified as Ark. Code Ann. § 23-15-201et seq. Act 285 authorized the Arkansas Public Service Commission to administer a state program pertaining to the design, installation, inspection, testing, construction, extension, operation, replacement, and maintenance of pipeline facilities used to transport natural gas. The Pipeline Safety Office was established and tasked with the responsibility of developing and implementing this program. Act 285 is far-reaching and affects directly or indirectly persons who distribute or use natural gas.
As long as natural gas flows through a closed controlled system, it remains an efficient, inexpensive and safe servant. However, when it escapes from its pipes, gas can turn on man violently and quickly. In passing the Arkansas Natural Gas Pipeline Safety Act of 1971, the Arkansas General Assembly intended to provide laws and standards which assured that these systems would continue to be operated in a safe manner and thereby reduce the possibility of gas escaping from its closed system. The objective of the pipeline safety program within Arkansas is to keep the gas confined to a closed, controlled system. This is best accomplished by requiring gas companies, operators of gas systems, and all persons who install natural gas pipelines to install and maintain them using only authorized materials and procedures and to comply with standards designed to ensure continuing quality of operation and maintenance.
The procedures and standards adopted by the Arkansas Public Service Commission, as authorized by Act 285, are known as the Arkansas Gas Pipeline Code. Compliance with the Code is mandatory under state law and non-compliance by any person engaging in the transportation of gas or who owns or operates pipeline facilities is punishable by a civil penalty not to exceed $200,000 per violation for each day the violation continues, except that the maximum civil penalty may not exceed $2,000,000 for any related series of violations. The law also provides authority for the Commission to file suit to restrain violations of the Code, including the restraint of transportation of gas or the operation of a pipeline facility.
The Arkansas Gas Pipeline Code is comprised of Parts 190, Enforcement Procedures; 191, Annual and Incident Reports; 192, Minimum Safety Standards; 193, Liquefied Natural Gas Facilities; and 199, Drug and Alcohol Testing. The paragraphs in Parts 191, 192, 193, and 199 correspond to the paragraph numbers of Parts 191, 192, 193, and 199 of Title 49, Code of Federal Regulations, Pipeline Safety Regulations.
ADMINISTRATIVE HISTORY
of the
ARKANSAS GAS PIPELINE CODE
Docket | Effective Date | Order No. | Subject Matter of Docket/Order |
U-2424(72-024-U) | 01/02/73 | -- | Adoption of Arkansas Gas Pipeline Code. |
U-2683(75-082-U) | 01/30/76 | -- | General Revisions to Code. |
U-2794(76-109-U) | 02/24/77 | -- | General Revisions to Code. |
U-2908(77-008-U) | 02/03/78 | -- | General Revisions to Code. |
U-2999(78-055-U) | 02/15/79 | -- | General revision to Code with emphasis on corrosion requirements. |
U-3083(80-007-U) | 03/18/80 | 2 | Adds requirements for qualifying persons and procedures for the joining of plastic pipe. |
81-040-U | 03/11/81 | 3 | Amends requirements concerning plastic pipe joining and external corrosion control monitoring. |
82-059-R | 04/16/82 | 6 | Adds Part 190 - Pipeline Safety Enforcement Procedures, and updates industry standards publications. |
83-015-R | 03/07/83 | 2 | Adds requirements for a Damage Prevention Program, and provides flexibility in scheduling inspections and tests. |
84-034-R | 07/06/84 | 4 | General Code revisions. |
85-086-R | 08/21/85 | 3 | Revised Part 191 - Transportation of Natural and Other Gas by Pipeline: Annual Reports and Incident Reports. Also revised the Code format. Complete republication by Order No. 4. |
86-169-R | 12/15/86 | 3 | Revised definition of operator. Amends provision regarding plastic pipe, welder qualification, preheating, stress relieving, nondestructive testing, bends and elbows. |
88-005-R | 07/14/88 | 4 | Revised Part 190 to provide for waivers, extensions, response to accident recommendations, and re-numbered paragraphs. Part 192 amended for Class locations, MAOP, testing repairs, odorization testing, damage prevention, &R/V calculation. |
89-034-R | 08/02/89 | 3 | Part 191 amended to include Safety-Related Condition Reports. Part 192 amended for deletion of outdated |
08/22/89 | 5 | references, adding requirements for safety-related conditions to be included in O &M plans, testing requirements for tie-in joints. Added Part 199 - Drug Testing. Establishes an employee drug testing program required of operators subject to Part 192. | |
90-015-R | 03/23/90 | 3 | General revisions with emphasis on updating of Standards & Specifications; class location vs. MAOP; cast/ductile iron, &copper pipe; Part 199 - changes caused by deletion of "Rehabilitation Committee" &its definition; changes in Drug tests required. |
91-056-R | 06/06/91 | 3 | Care when using tracer wire with plastic pipe, and lubrication requirements for valves. |
92-036-R | 05/12/92 | 3 | Parts 192 and 199 changed to reflect requirement of operators to amend plans and procedures as necessary for safety. Preface and Part 190 changed to reflect increase in civil penalties. |
93-020-R | 04/26/93 | 3 | Parts 191 and 192 changed to include certain gathering lines containing 100 ppm or more of hydrogen sulfide. Part 192 further changed by correcting certain discrepancies not previously discovered. Code format revised and complete republication of the Arkansas Gas Pipeline Code. |
94-025-R | 09/12/94 | 4 | Update of referenced Standards & Specifications; addition of requirement for gas detection in certain compressor station buildings; clarification of leakage survey requirements. Part 199 changes to record keeping, and a new requirement for an annual report on the anti-drug program. |
95-116-R | 04/27/95 | 3 | Definitions section and Parts 190 and 192 changed to reflect the requirement that certain new and replacement pipelines be designed and constructed to accommodate instrumented internal inspection devices. Part 190 changed to clarify the language in the issuance and handling of show cause orders. Part 192 changed to require meters which have been installed indoors to be in a ventilated place and not less than 3 feet from any source of ignition or source of heat which might damage the meter, to require detailed procedures in O&M manuals, that operators review and update their O&M manuals each year, and that operators prepare and follow procedures to safeguard personnel from unsafe accumulations of vapors or gas in excavated trenches. Part 199 reformatted to add Subpart B, Alcohol Misuse Prevention Program. Preface changed to include new title of Part 199. Complete republication of the Arkansas Gas Pipeline Code. |
96-181-R | 08/20/96 | 3 | Preface and Part 190 changed to reflect increased civil penalties. Part 192 changed to include notification requirement for customer-owned service lines, to extend existing excavation damage prevention requirements for gas pipelines in urban areas to gas pipelines in rural areas, and to require, with limited exceptions, line markers for transmission lines in urban areas. Part 199 changed to allow for the possibility of a reduced random drug testing rate, and to require reporting of information concerning missed tests. Complete republication of the Arkansas Gas Pipeline Code. |
97-034-R | 04/03/97 | 3 | Preface changed to explain the codification of the Natural Gas Pipeline Safety Act. Definition of "petroleum gas" added and definition of "transmission line" revised in the Definitions section. Numerous minor changes to Parts 191 and 192. Addition of performance standards for excess flow valves to Part 192. Appendices A and B to Part 192 updated. Minor revisions to Part 199. Complete republication of the Arkansas Gas Pipeline Code. |
99-130-R | 08/02/99 | 3 | All Parts changed to include metric equivalents for English measures. Part 192 changed to require that Excess Flow Valves ("EFO") close at 50% or less of the manufacturer's rated closure flow rate while operating at 10 pounds per square inch gauge (p.s.i.g.); removed the requirement to prevent installation of EFO's beneath hard surfaces; require operators to notify customers of the option to install EFO's before the installation or replacement of service lines; require that all operators must participate in a qualified one-call system; added transmission or distribution of gas containing H2S to reflect the exact language in Arkansas Code Annotated 23-15-203(3); removed atmospheric corrosion requirements for offshore facilities. Appendix A revised to incorporate certain versions of The American Society for Testing and Materials Standards by reference. Part 199 revised to clarify terms; added requirements for a Substance Abuse Professional ("SAP"). Complete republication of the Arkansas Gas Pipeline Code. |
00-312-R | 12/11/00 | 4 | Part 190.15 revised to include falsification of paperwork as probable violation. Part 192.17 revised to allow the use of a certified letter for notification of probable violation. New Subpart N - Operator Qualification added. Minor changes to Subpart I and M. Complete republication of the Arkansas Gas Pipeline Code. |
04-088-R | 08/26/04 | 3 | Adopted Federal Office of Pipeline Safety Amendments 192-86A, 192-89, 192-89A, 192-93, 19295, 199-19 and 199-21. |
06-123-R | 12/07/06 | 3 | Adopted Federal Pipeline and Hazardous Material Safety Administration Amendments 192-94, 192-95 C, 192-96, 192-97, 192-98, 192-99, 192-100, 192-101, 192-102, 192-103, 199-20, 49 CFR Part 193 in its entirety, Amendment 193-19, Nomenclature Change amendment regarding the change of the Research and Special Programs Administration into the Pipeline and Hazardous Materials Safety Administration, Act 1048 of the 82nd General Assembly of the Arkansas Legislature, and Act 153 of the 83rd General Assembly of the Arkansas Legislature. Complete republication of the Arkansas Gas Pipeline Code. |
08-167-R | 05/04/9 | 3 | Adopted Federal Pipeline and Hazardous Material Safety Administration amendment 192-103A, update of regulatory references to technical standards, amendment regarding design and construction standards to reduce internal corrosion in gas transmission pipelines, 192-104 Integrity Management Program modifications and clarifications, amendment regarding applicability of public awareness regulations to certain gas distribution operators, and amendment regarding administrative procedures, address updates, and technical amendments. Complete republication of the Arkansas Gas Pipeline Code. |
11-166-R | 06/08/12 | 5 | Adopted Federal Pipeline and Hazardous Material Safety Administration (PHMSA) amendments 107, 108, 109, 110, 111, 112, 114 and 115 to Part 192. Adopted PHMSA amendments 22 and 23 to Part 193. Adopted PHMSA amendment 21 to Part 191. Complete republication of the Arkansas Gas Pipeline Code. |
13-027-R | 10/16/13 | 3 | Editorial changes, adopted Private Line definition, added 192.27 Status of Leaks requirement, and added 192.724 Hazardous Facilities requirement. |
14-029-R | 09/25/14 | 5 | Adopted Federal Pipeline and Hazardous Material Safety Administration (PHMSA) amendments to incorporate higher civil penalties and minor redesignation changes. Also incorporated changes from Act 1343 of 2013 from the Arkansas General Assembly. Complete republication of the Arkansas Gas Pipeline Code. |
16-093-R | 05/19/17 | 4 | Adopted 2015 Federal Pipeline and Hazardous Material Safety Administration (PHMSA) amendments 191-23, 192-119, 192-120, 193-25, and 199-26 (80 FR 168, 12762, and 46847-01); and made technical corrections. Complete republication of the Arkansas Gas Pipeline Code. |
19-069-R | XX/XX/XX | 4 | Adoption of 2016 and 2017 Federal Pipeline and Hazardous Material Safety Administration (PHMSA) amendments 190-19 and 192-121, (81 FR 72739 and 82 FR 7972, and made technical corrections. Complete republication of the Arkansas Gas Pipeline Code. |
DEFINITIONS
DEFINITIONS OF WORDS/PHRASES USED IN THE ARKANSAS GAS PIPELINE CODE
Except as otherwise provided in this Code:
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 of the Pipeline and Hazardous Materials Safety Administration or any person to whom authority in the matter concerned has been delegated by the U.S. Secretary of Transportation.
Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safety-related parameters.
Business District means a location where gas mains are utilized to serve customers that are predominately commercial in nature, and where the street and/or sidewalk paving generally extends from the centerline of a thoroughfare to the established building line on either side.
Change to a segment of pipeline means a physical change in the pipeline or significant changes in operating pressure.
Commission means, unless the context otherwise requires, the Arkansas Public Service Commission or any person or entity to whom the Commission has delegated authority in the matter concerned.
Confirmed Discovery means when it can be reasonably determined, based on information available to the operator at the time a reportable event has occurred, even if only based on a preliminary evaluation.
Control Room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility.
Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a SCADA system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility.
Customer Meter means the meter that measures the transfer of gas from an operator to a consumer.
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.
Gas means natural, manufactured, liquefied natural, flammable gas or gas which is toxic or corrosive.
Gathering Line means a pipeline that transports gas from a current production facility to a transmission line or main.
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.
Incident means any of the following events:
Key Valves means shut off valves in a distribution system or transmission line which may be necessary to isolate segments of a system or line for emergency purposes.
Line Section means a continuous run of transmission line between adjacent compressor stations, between a compressor station and storage facilities, between a compressor station and a block valve, or between adjacent block valves.
Listed Specification means a specification listed in Section I of Appendix B to Part 192.
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 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 the payment of rent.
Maximum Actual Operating Pressure means the maximum pressure that occurs during normal operations over a period of one year.
Maximum Allowable Operating Pressure (MAOP) means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this code.
Mobile Home Park means two or more mobile homes located on a contiguous tract of land.
Municipality means a city, county or any other political subdivision of the State of Arkansas.
Manual service line shut-off valve means a curb valve or other manually operated valve located near the service line that is safely accessible to operator personnel or other personnel authorized by the operator to manually shut off gas flow to the service line, if needed.
Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters.
Operator means a person who:
Person means an individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof.
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 208 p.s.i.g. (1434 kPa) gage at 100&°F (38°C).
Petroleum Refinery means an industrial or manufacturing facility or plant primarily engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants or other products through the processing of petroleum crude oil that is subject to:
Pipe means any pipe or tubing used in the transportation of gas, including pipe-type holders.
Pipeline or Pipeline System means all parts of those physical facilities through which gas moves in transportation, including, but not limited to, pipe, valves and other appurtenances attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.
Pipeline Environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activity, and other known conditions that could affect the probability of active corrosion.
Pipeline Facilities includes without limitation, new and existing pipe, pipe rights-of-way, and any equipment, facility or building used in the transportation of gas or the treatment of gas during the course of transportation of gas.
Pipeline Safety Office or PSO means the Pipeline Safety Office within the Arkansas Public Service Commission that administers the Arkansas Natural Gas Pipeline Safety Act of 1971, Arkansas Code § 23-15-201et seq., the Arkansas Gas Pipeline Code, and related laws, rules, and regulations.
Production Facilities includes without limitation, piping or equipment used in the production, extraction, recovery, lifting, stabilization, separation or treatment of natural gas or associated storage or measurement from the wellhead to a meter where the gas is transferred to a custodian other than the well operator for gathering or transport, commonly known as a "custodial transfer meter".
Production Process means the extraction of gas from the geological source of supply to the surface of the earth, thence through the lines and equipment used to treat, compress and measure the gas between the wellhead and the meter where it is either sold or delivered to a custodian other than the well operator for gathering and transport to a place of sale, sometimes called "custodial transfer meter."
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, and is:
Supervisory Control and Data Acquisition (SCADA) System means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility.
Test Failure means a break or rupture that occurs during strength proof testing of transmission or gathering lines that are of such magnitude as to require repair before continuation of the test.
Transmission Line means a pipeline, other than a gathering line, that:
NOTE: A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas.
Transportation of Gas means the gathering, transmission or distribution of gas by pipeline or the storage of gas in or affecting interstate, intrastate, or foreign commerce.
This part prescribes procedures utilized by the Arkansas Public Service Commission (Commission) in carrying out its responsibilities regarding pipeline safety under the Arkansas Natural Gas Pipeline Safety Act of 1971 (Act 285 of 1971, as amended; Ark. Code Ann. § 23-15-201 et seq.). Any conflict between the Commission's Rules and Regulations and the Arkansas Statutes shall be resolved in favor of the statutes.
Each show cause order issued under this part shall be served in accordance with the current provisions of the Commission's Rules of Practice and Procedure and Ark. Code Ann. § 23-2-405.
The issuance of subpoenas and payment of witness fees shall be in accordance with the current provisions of the Commission's Rules of Practice and Procedure and Ark. Code Ann. § 23-2-402 and § 23-2-414.
In those instances when the actions necessary to correct documented deficiencies will exceed the time limit given in the notice of probable violation, an operator may request an extension of time in order to effect compliance. Each request must detail the reason(s) why compliance cannot be accomplished by the original suspense date, and the date the operator believes the necessary compliance actions can be completed. If the Commission finds the request to be reasonable a new suspense date may be established.
If unusual difficulty results from implementing a safety standard in Part 192 or Part 193, application may be made to the Commission for exemption from a particular standard. The application for exemption shall be accompanied by a thorough justification for requested actions.
The Commission may issue a show cause order notifying the owner or operator of a probable violation and advising the person to correct it or be subject to enforcement action. The severity of the probable violation shall be the determining factor in the type of notice issued by the Commission. A show cause order shall be served as provided in § 190.3.
An operator has 20 calendar days from the date of receipt of a show cause order to respond. The operator may:
Failure of the operator to respond in a timely manner to a show cause order under either subsection (a) or (b) of this section shall constitute a waiver of the operator's right to contest the allegations. The Commission may then act on the basis of the case file compiled by the Staff.
The Case File compiled by the Staff after the issuance of a show cause order shall contain the following information:
The Commission shall issue a final order at the conclusion of any proceedings initiated by a show cause order. The final order shall include:
Subsequent to a final order, the operator may request a rehearing pursuant to Ark. Code Ann. § 23-2-422, and the Commission's Rules of Practice and Procedure.
The Commission may assess civil penalties prescribed by Ark. Code Ann. § 23-15-211 for violations of the Arkansas Gas Pipeline Code which as of July 1, 2016, shall not exceed two hundred thousand dollars ($200,000) for each violation for each day that the violation persists, except that the maximum civil penalty shall not exceed two million dollars ($2,000,000) for any related series of violations. Before assessing a civil penalty, the Commission shall follow the procedures established by §§ 190.19 and 190.25.
Any civil penalty not promptly paid to the Commission shall be recovered with interest thereon from the date of the order in a civil action brought by the Commission under Ark. Code Ann. §§ 23-15-211 - 23-15212.
The Commission may restrain violations of the Arkansas Natural Gas Pipeline Safety Act of 1971, as amended, by seeking injunctive relief pursuant to Arkansas Code Ann. § 23-15-212.
ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION REPORTS
This part prescribes requirements for the reporting of incidents, safety-related conditions, and annual pipeline summary data, and applies to all persons engaged in the transportation of gas. Leaks/ignition which were intentionally caused by the operator are not reportable. This part does not apply to leaks and test failures that occur in the gathering of gas through a pipeline that operates at less than 0 p.s.i.g. (0 kPa), and through a pipeline that is not a regulated onshore gathering line (as determined in § 192.8 of this subchapter); however it shall apply to the gathering, transmission or distribution of gas containing 100 or more parts-per-million of hydrogen sulfide from the custodial transfer meter through any pipeline, rural or non-rural, to and through any pipeline facility that removes hydrogen sulfide except that portion of such a pipeline or pipeline facility that is located within the fenced boundary of a petroleum refinery. For those lines that are jurisdictional solely on the basis of their hydrogen sulfide content, the reports required by this part shall be submitted to the PSO and not to the U.S. Department of Transportation.
Incidents reportable under this subsection (a) include incidents occurring on all pipelines up to the outlet side of the customer's meter and must be reported at the earliest practicable moment unless there is evidence that the leak probably did not occur on pipelines used by the operator in the transportation of gas, in which case, notice may be delayed until determination is made.
Each mechanical fitting failure, as required by § 192.1009, must be submitted on a Mechanical Fitting Failure Report Form PHMSA F-7100.1-2. An operator must submit a mechanical fitting failure report for each mechanical fitting failure that occurs within a calendar year not later than March 15 of the following year (for example, all mechanical failure reports for calendar year 2011 must be submitted no later than March 15, 2012). Alternatively, an operator may elect to submit its reports throughout the year. In addition, an operator must also report this information to the State pipeline safety authority if a State has obtained regulatory authority over the operator's pipeline.
Each operator, primarily engaged in gas distribution, who also operates gas transmission or gathering pipelines shall submit separate reports for these pipelines as required by §§ 191.15 and 191.17. Each operator, primarily engaged in gas transmission or gathering, who also operates gas distribution pipelines shall submit separate reports for these pipelines as required by §§ 191.9 and 191.11.
This section displays the control number assigned by the Office of Management and Budget (OMB) to the information collection requirements in this part. The Paperwork Reduction Act requires agencies to display a current control number assigned by the Director of OMB for each agency information collection requirement.
OMB CONTROL NUMBER 2137-0522
Section of 49 CFR part 191 where identified | Form No. |
191.5 | Telephonic. |
191.9 | PHMSA 7100.1, PHMSA 7100. 3. |
191.11 | PHMSA 7100.1-1, PHMSA 7100.3-1. |
191.15 | PHMSA 7100.2. |
191.17 | PHMSA 7100.2-1. |
191.22 | PHMSA 1000.1. |
As used in this part:
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 of the Pipeline and Hazardous Materials Safety Administration or any person to whom authority in the matter concerned has been delegated by the U.S. Secretary of Transportation.
Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safety-related parameters.
Business District means a location where gas mains are utilized to serve customers that are predominately commercial in nature and where the street and/or sidewalk paving generally extends from the centerline of a thoroughfare to the established building line on either side.
Change to a segment of pipeline means a physical change in the pipeline or significant changes in operating pressure.
Commission means, unless the context otherwise requires, the Arkansas Public Service Commission or any person or entity to whom the Commission has delegated authority in the matter concerned.
Control Room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility.
Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a SCADA system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility.
Customer Meter means the meter that measures the transfer of gas from an operator to a consumer.
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.
Gas means natural, manufactured, liquefied natural, flammable gas or gas which is toxic or corrosive.
Gathering Line means a pipeline that transports gas from a current production facility to a transmission line or main.
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.
Key Valves means shut off valves in a distribution system or transmission line which may be necessary to isolate segments of a system or line for emergency purposes.
Line Section means a continuous run of transmission line between adjacent compressor stations, between a compressor station and storage facilities, between a compressor station and a block valve, or between adjacent block valves.
Listed Specification means a specification listed in Section I of Appendix B to Part 192.
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 System means a pipeline system for distribution 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 rents.
Maximum Actual Operating Pressure means the maximum pressure that occurs during normal operations over a period of one year.
Maximum Allowable Operating Pressure (MAOP) means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this code.
Mobile Home Park means two or more mobile homes located on a contiguous tract of land.
Municipality means a city, county or any other political subdivision of the State of Arkansas.
Operator means a person who:
Person means an individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof.
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 208 p.s.i.g. (1434 kPa) gage at 100°F (38°C).
Petroleum Refinery means an industrial or manufacturing facility or plant primarily engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants or other products through the processing of petroleum crude oil that is subject to:
Pipe means any pipe or tubing used in the transportation of gas, including pipe-type holders.
Pipeline or Pipeline System means all parts of those physical facilities through which gas moves in transportation, including, but not limited to, pipe, valves and other appurtenances attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.
Pipeline Environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activity, and other known conditions that could affect the probability of active corrosion.
Pipeline Facilities includes without limitation, new and existing pipe, pipe rights-of-way, and any equipment, facility or building used in the transportation of gas or the treatment of gas during the course of transportation of gas.
Private Line System means a natural gas pipeline or pipeline system that is not a master meter system; is not owned by, nor the responsibility of a public or municipal utility; is used to transport gas that is not consumed solely by the owner/operator from a public or municipal utility meter to consumers who may or may not be metered.
Production Facilities includes without limitation, piping or equipment used in the production, extraction, recovery, lifting, stabilization, separation or treatment of natural gas or associated storage or measurement from the wellhead to a meter where the gas is transferred to a custodian other than the well operator for gathering or transport, commonly known as a "custodial transfer meter."
Production Process means the extraction of gas from the geological source of supply to the surface of the earth, thence through the lines and equipment used to treat, compress and measure the gas between the wellhead and the meter where it is either sold or delivered to a custodian other than the well operator for gathering and transport to a place of sale, sometimes called "custodial transfer meter."
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 specific minimum yield strength, and is:
Supervisory Control and Data Acquisition (SCADA) System means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility.
Test Failure means a break or rupture that occurs during strength proof testing of transmission or gathering lines that are of such magnitude as to require repair before continuation of the test.
Transmission Line means a pipeline, other than a gathering line, that:
NOTE: A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas.
Transportation of Gas means the gathering, transmission or distribution of gas by pipeline or the storage of gas in or affecting interstate, intrastate, or foreign commerce.
Welder means a person who performs manual or semi-automatic welding.
Welding operator means a person who operates machine or automatic welding equipment.
Type | Feature | Area | Safety buffer |
A.. | -Metallic and the MAOP produces a hoop stress of 20 percent or more of SMYS. If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in subpart C of this part. -Non-metallic and the MAOP is more than 125 p.s.i.g. (862kPa). | Class 2, 3, or 4 location (see § 192.5).. | None |
B.. | -Metallic and the MAOP produces a hoop stress of less than 20 percent of SMYS. If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in subpart C of this part. -Non-metallic and the MAOP is 125 p.s.i.g. (862 k Pa) or less. | Area 1. Class 3 or 4 location Area 2. An area within a Class 2 location the operator determines by using any of the following three methods: (a) A class 2 location .. (b) An area extending 150 feet (45.7m) on each side of the centerline of any continuous 1 mile (1.6km) of pipeline and including more than 10 but fewer than 46 dwellings. (c) An area extending 150 feet (45.7m) on each side of the centerline of any continuous 1000 feet (305 m) of pipeline and including 5 or more dwellings. | If the gathering line is in Area 2(b) or 2(c), the additional lengths of line extend upstream and downstream from the area to a point where the line is at least 150 feet (45.7m) from the nearest dwelling in the area. However, if a cluster of dwellings in Area 2(b) or 2(c) qualifies a line as Type B, the type B classification ends 150 feet (45.7m) from the nearest dwelling in the cluster. |
Requirement | Compliance deadline |
Control corrosion according to Subpart I requirements for transmission lines. | April 15, 2009. |
Carry out a damage prevention program under § 192.614. | October 15, 2007. |
Establish MAOP under § 192.619. | October 15, 2007. |
Install and maintain line markers under § 192.707. | April 15, 2008. |
Establish a public education program under § 192.616. | April 15, 2008. |
Other provisions of this part as required by paragraph (c) of this section for Type A lines. | April 15, 2009. |
Pipeline | Date |
Offshore gathering line | July 31, 1977. |
Regulated onshore gathering line to which this part did not apply until April 14, 2006. | March 15, 2007. |
All other pipelines .. | March 12, 1971. |
Pipeline | Date |
Offshore gathering line | July 31, 1977. |
Regulated onshore gathering line to which this part did not apply until April 14, 2006. | March 15, 2007. |
All other pipelines .. | November 12, 1970. |
Includes means "including but not limited to."
May means "is permitted to" or "is authorized to."
May not means "is not permitted to" or "is not authorized to."
Shall is used in the mandatory and imperative sense.
Each operator shall file with the Pipeline Safety Office of the Arkansas Public Service Commission (PSO) a plan for operation, inspection, and maintenance of each pipeline facility which the operator owns or operates. In addition, each change to this plan must be filed with the PSO within 20 days after the change is made. Once filed, this plan becomes a part of these standards as though incorporated and must be followed by the operator.
This subpart prescribes minimum requirements for the selection and qualification of pipe and components for use in pipelines.
This subpart prescribes the minimum requirements for the design of pipe.
Pipe must be designed with sufficient wall thickness, or must be installed with adequate protection, to withstand anticipated external pressures and loads that will be imposed on the pipe after installation.
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. Additional wall thickness required for concurrent external loads in accordance with § 192.103 may not be included in computing design pressure.
F = Design factor determined in accordance with § 192.111.
E = Longitudinal joint factor determined in accordance with § 192.113.
T = Temperature derating factor determined in accordance with § 192.115.
Class Location | Design Factor (F) |
1......................... | 0.72 |
2......................... | 0.60 |
3......................... | 0.50 |
4......................... | 0.40 |
For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure (MAOP) calculated under § 192.620, a segment must meet the following additional design requirements. Records for alternative MAOP must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:
To address this design issue: | The pipeline segment must meet these additional requirements: |
(a) General standards for steel pipe | (1) The plate, skelp, or coil used for the pipe must be microalloyed, fine grain, fully killed, continuously cast steel with calcium treatment. (2) The carbon equivalents of the steel used for pipe must not exceed 0.25 percent by weight, as calculated by the Ito-Bessyo formula (Pcm formula) or 0.43 percent by weight, as calculated by the International Institute of Welding (IIW) formula. (3) The ratio of the specified outside diameter of the pipe to the specified wall thickness must be less than 100. The wall thickness or other mitigative measures must prevent denting and ovality anomalies during construction, strength testing and anticipated operational stresses. (4) The pipe must be manufactured using API Spec 5L, product specification level 2 (incorporated by reference, see § 192.7) for maximum operating pressures and minimum and maximum operating temperatures and other requirements under this section. |
(b) Fracture control | (1) The toughness properties for pipe must address the potential for initiation, propagation and arrest of fractures in accordance with: (i) API Spec 5L (incorporated by reference, see § 192.7); (ii) American Society of Mechanical Engineers (ASME) B31.8 (incorporated by reference, see § 192.7); and (iii) Any correction factors needed to address pipe grades, pressures, temperatures, or gas compositions not expressly addressed in API Spec 5L, product specification level 2 or ASME B31.8 (incorporated by reference, see § 192.7). (2) Fracture control must: (i) Ensure resistance to fracture initiation while addressing the full range of operating temperatures, pressures, gas compositions, pipe grade and operating stress levels, including maximum pressure and minimum temperatures for shut-in conditions that the pipeline is expected to experience. If these parameters change during operation of the pipeline such that they are outside the bounds of what was considered in the design evaluation, the evaluation must be reviewed and updated to assure continued resistance to fracture initiation over the operating life of the pipeline; (ii) Address adjustments to toughness of pipe for each grade used and the decompression behavior of the gas at operating parameters; (iii) Ensure at least 99 percent probability of fracture arrest within eight pipe lengths with a probability of not less than 90 percent within five pipe lengths; and (iv) Include fracture toughness testing that is equivalent to that described in supplementary requirements SR5A, SR5B, and SR6 of API Specification 5L (incorporated by reference, see § 192.7) and ensures ductile fracture and arrest with the following exceptions: (A) The results of the Charpy impact test prescribed in SR5A must indicate at least 80 percent minimum shear area for any single test on each heat of steel; and (B) The results of the drop weight test prescribed in SR6 must indicate 80 percent average shear area with a minimum single test result of 60 percent shear area for any steel test samples. The test results must ensure a ductile fracture and arrest. (3) If it is not physically possible to achieve the pipeline toughness properties of paragraphs (b)(1) and (2) of this section, additional design features, such as mechanical or composite crack arrestors and/or heavier walled pipe of proper design and spacing, must be used to ensure fracture arrest as described in paragraph (b)(2)(iii) of this section. |
(c)Plate/coil quality control | (1) There must be an internal quality management program at all mills involved in producing steel, plate, coil, skelp, and/or rolling pipe to be operated at alternative MAOP. These programs must be structured to eliminate or detect defects and inclusions affecting pipe quality. (2) A mill inspection program or internal quality management program must include (i) and either (ii) or (iii): (i) An ultrasonic test of the ends and at least 35 percent of the surface of the plate/coil or pipe to identify imperfections that impair serviceability such as laminations, cracks, and inclusions. At least 95 percent of the lengths of pipe manufactured must be tested. For all pipelines designed after December 22, 2008, the test must be done in accordance with ASTM A578/A578M Level B, or API Spec 5L Paragraph 7.8.10 (incorporated by reference, see § 192.7) or equivalent method, and either (ii) A macro etch test or other equivalent method to identify inclusions that may form centerline segregation during the continuous casting process. Use of sulfur prints is not an equivalent method. The test must be carried out on the first or second slab of each sequence graded with an acceptance criteria of one or two on the Mannesmann scale or equivalent; or (iii) A quality assurance monitoring program implemented by the operator that includes audits of: (a) all steelmaking and casting facilities, (b) quality control plans and manufacturing procedure specifications,(c) equipment maintenance and records of conformance, (d) applicable casting superheat and speeds, and (e) centerline segregation monitoring records to ensure mitigation of centerline segregation during the continuous casting process. |
(d) Seam quality control | (1) There must be a quality assurance program for pipe seam welds to assure tensile strength provided in the API Spec 5L (incorporated by reference, see § 192.7) for appropriate grades. (2) There must be a hardness test, using Vickers (Hv10) hardness test method or equivalent test method, to assure a maximum hardness of 280 Vickers of the following: (i) A cross section of the weld seam of one pipe from each heat plus one pipe from each welding line per day; and (ii) For each sample cross section, a minimum of 13 readings (three for each heat affected zone, three in the weld metal, and two in each section of the pipe base metal). (3) All of the seams must be ultrasonically tested after cold expansion and mill hydrostatic testing. |
(e) Mill hydrostatic test | (1) All pipe to be used in a new pipeline segment installed after October 1, 2015, must be hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. (2) Pipe in operation prior to December 22, 2008, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 90 percent SMYS for 10 seconds. (3) Pipe in operation on or after December 22, 2008, but before October 1, 2015, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. The test pressure may include a combination of internal test pressure and the allowance for end loading stresses imposed by the pipe mill hydrostatic testing equipment as allowed by ''ANSI/API Spec 5L'' (incorporated by reference, see § 192.7). |
(f) Coating | (1) The pipe must be protected against external corrosion by a non-shielding coating. (2) Coating on pipe used for trenchless installation must be non-shielding and resist abrasions and other damage possible during installation. (3) A quality assurance inspection and testing program for the coating must cover the surface quality of the bare pipe, surface cleanliness and chlorides, blast cleaning, application temperature control, adhesion, cathodic disbondment, moisture permeation, bending, coating thickness, holiday detection, and repair. |
(g) Fittings and flanges | (1) There must be certification records of flanges, factory induction bends and factory weld ells. Certification must address material properties such as chemistry, minimum yield strength and minimum wall thickness to meet design conditions. (2) If the carbon equivalents of flanges, bends and ells are greater than 0.42 percent by weight, the qualified welding procedures must include a pre-heat procedure. (3) Valves, flanges and fittings must be rated based upon the required specification rating class for the alternative MAOP. |
(h) Compressor stations | (1) A compressor station must be designed to limit the temperature of the nearest downstream segment operating at alternative MAOP to a maximum of 120 degrees Fahrenheit (49 degrees Celsius) or the higher temperature allowed in paragraph (h)(2) of this section unless a long-term coating integrity monitoring program is implemented in accordance with paragraph (h)(3) of this section. (2) If research, testing and field monitoring tests demonstrate that the coating type being used will withstand a higher temperature in long-term operations, the compressor station may be designed to limit downstream piping to that higher temperature. Test results and acceptance criteria addressing coating adhesion, cathodic disbondment, and coating condition must be provided to each PHMSA pipeline safety regional office where the pipeline is in service at least 60 days prior to operating above 120 degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State. (3) Pipeline segments operating at alternative MAOP may operate at temperatures above 120 degrees Fahrenheit (49 degrees Celsius) if the operator implements a longterm coating integrity monitoring program. The monitoring program must include examinations using direct current voltage gradient (DCVG) alternating current voltage gradient (ACVG), or an equivalent method of monitoring coating integrity. An operator must specify the periodicity at which these examinations occur and criteria for repairing identified indications. An operator must submit its long-term coating integrity monitoring program to each PHMSA pipeline safety regional office in which the pipeline is located for review before the pipeline segments may be operated at temperatures in excess of 120 degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State. |
The longitudinal joint factor to be used in the design formula in § 192.105 is determined in accordance with the following table:
Longitudinal Specification | Pipe Class | Joint Factor (E) |
ASTM A53/A53M .................... | Seamless................................................................................... | 1.00 |
Electric resistance welded ......................................................... | 1.00 | |
Furnace butt welded .................................................................. | 0.60 | |
ASTM A106 ............................ | Seamless................................................................................... | 1.00 |
ASTM A333/A333M ................ | Seamless................................................................................... | 1.00 |
Electric resistance welded ........................................................ | 1.00 | |
ASTM A381 ............................. | Double submerged arc welded .................................................. | 1.00 |
ASTM A671 ............................ | Electric fusion welded ............................................................... | 1.00 |
ASTM A672 ............................ | Electric fusion welded ................................................................ | 1.00 |
ASTM A691 ............................. | Electric fusion welded ............................................................... | 1.00 |
API Spec 5L ............................. | Seamless................................................................................... | 1.00 |
Electric resistance welded ......................................................... | 1.00 | |
Electric flash welded .................................................................. | 1.00 | |
Submerged arc welded .............................................................. | 1.00 | |
Furnace butt welded .................................................................. | 0.60 | |
Other ....................................... | Pipe over 4 inches (102 millimeters) .......................................... | 0.80 |
Other ....................................... | Pipe 4 inches (102 millimeters) or less ...................................... | 0.60 |
If the type of longitudinal joint cannot be determined, the joint factor to be used must not exceed that designated for "Other."
The temperature derating factor to be used in the design formula in § 192.105 is determined as follows:
Gas Temperature in Degrees Fahrenheit (Celsius) | Temperature Derating Factor (T) |
250°F (121°C) or less........................................................ | 1.000 |
300°F (149°C) ................................................................... | 0.967 |
350°F (177°C) ................................................................... | 0.933 |
400°F (204°C) ................................................................... | 0.900 |
450°F (232°C) ................................................................... | 0.867 |
For intermediate gas temperatures, the derating factor is determined by interpolation.
Subject to the limitations of § 192.123, the design pressure for plastic pipe is determined by either of the following formulas:
Where:
P = Design pressure, gauge, psig (kPa).
S = For thermoplastic pipe, the 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.
D F = 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 or 11 or greater (i.e. thicker pipe wall).
Nominal size in inches | Minimum wall thickness inches |
(millimeters) | (millimeters) |
2 (51) .............................................. | 0.060 (1.52) |
3 (76) .............................................. | 0.060 (1.52) |
4 (102) ............................................. | 0.070 (1.78) |
6 (152) ............................................. | 0.100 (2.54) |
Standard Size, inch (millimeter) | Nominal O.D., inch (millimeter) | Wall Thickness, inch (millimeter) | |
Nominal | Tolerance | ||
1/2 (13) | .625 (16) | .040 (1.06) | .0035 (.0889) |
5/8 (16) | .750 (19) | .042 (1.07) | .0035 (.0889) |
3/4 (19) | .875 (22) | .045 (1.14) | .004 (.102) |
1 (25) | 1.125 (29) | .050 (1.27) | .004 (.102) |
1 1/4 (32) | 1.375 (35) | .055 (1.40) | .0045 (.1143) |
1 1/2 (38) | 1.625 (41) | .060 (1.52) | .0045 (.1143) |
This subpart prescribes minimum requirements for the design and installation of pipeline components and facilities. In addition, it prescribes requirements relating to protection against accidental over pressuring.
Notwithstanding any requirement of this subpart which incorporates by reference an edition of a document listed in § 192.7 or Appendix B of this part, a metallic component manufactured in accordance with any other edition of that document is qualified for use under this part if-
Each welded branch connection made to pipe in the form of a single connection, or in a header or manifold as a series of connections, must be designed to ensure that the strength of the pipeline system is not reduced, taking into account the stresses in the remaining pipe wall due to the opening in the pipe or header, the shear stresses produced by the pressure acting on the area of the branch opening and any external loadings due to thermal movement, weight, and vibration.
Each extruded outlet must be suitable for anticipated service conditions and must be at least equal to the design strength of the pipe and other fittings in the pipeline to which it is attached.
Each pipeline must be designed with enough flexibility to prevent thermal expansion or contraction from causing excessive stresses in the pipe or components, excessive bending or unusual loads at joints, or undesirable forces or moments at points of connection to equipment, or at anchorage or guide points.
Each compressor station building must be ventilated to ensure that employees are not endangered by the accumulation of gas in rooms, sumps, attics, pits, or other enclosed places.
C = (3D x P x F)/1000) in inches; (C = (3D x P x F)/6,895) in millimeters
In which:
C = Minimum clearance between pipe containers or bottles in inches (millimeters).
D = Outside diameter of pipe containers or bottles in inches (millimeters)
P = Maximum allowable operating pressure, psi (kPa) gauge.
F = Design factor as set forth in § 192.111 of this part.
Maximum Allowable Operating Pressure | Minimum Clearance Feet (meters) |
Less than 1,000 p.s.i. (7 MPa) gage | 25 (7.6) |
1,000 p.s.i. (7 MPa) or more | 100 (31) |
Each vault must be located in an accessible location and, so far as practical, away from:
Each underground vault or closed top pit containing either a pressure regulating or reducing station, or a pressure limiting or relieving station, must be sealed, vented, or ventilated, as follows:
Each valve installed in plastic pipe must be designed so as to protect the plastic material against excessive torsional or shearing loads when the valve or shutoff is operated, and from any other secondary stresses that might be exerted through the valve or its enclosure.
Except for rupture discs, each pressure relief or pressure limiting device must:
The welding operation must be protected from weather conditions that would impair the quality of the completed weld.
Before beginning any welding, the welding surfaces must be clean and free of any material that may be detrimental to the weld, and the pipe or component must be aligned to provide the most favorable condition for depositing the root bead. This alignment must be preserved while the root bead is being deposited.
This subpart prescribes minimum requirements for constructing transmission lines and mains.
Each transmission line or main must be inspected to ensure that it is constructed in accordance with this subpart. An operator must not use operator personnel to perform a required inspection if the operator personnel performed the construction task requiring inspection. Nothing in this section prohibits the operator from inspecting construction tasks with operator personnel who are involved in other construction tasks.
Each length of pipe and each other 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.
For the purpose of this section a "dent" is a depression that produces a gross disturbance in the curvature of the pipe wall without reducing the pipe-wall thickness. The depth of a dent is measured as the gap between the lowest point of the dent and a prolongation of the original contour of the pipe.
Each imperfection or damage that would impair the serviceability of plastic pipe must be repaired or removed.
Each casing used on a transmission line or main under a railroad or highway must comply with the following:
Location | Normal Soil Inches (Millimeters) | Consolidated Rock Inches (Millimeters) |
Class 1 locations | 30 (762) | 18 (457) |
Class 2,3, and 4 locations | 36 (914) | 24 (610) |
Drainage ditches of public roads and railroad crossings | 36 (914) | 24 (610) |
For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure calculated under § 192.620, a segment must meet the following additional construction requirements. Records must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:
To address this construction issue: | The pipeline segment must meet this additional construction requirement: |
(a) Quality assurance (b) Girth welds (c) Depth of cover (d) Initial strength testing (e) Interference currents | (1) The construction of the pipeline segment must be done under a quality assurance plan addressing pipe inspection, hauling and stringing, field bending, welding, non-destructive examination of girth welds, applying and testing field applied coating, lowering of the pipeline into the ditch, padding and backfilling, and hydrostatic testing. (2) The quality assurance plan for applying and testing field applied coating to girth welds must be: (i) Equivalent to that required under § 192.112(f)(3) for pipe; and (ii) Performed by an individual with the knowledge, skills, and ability to assure effective coating application. (1) All girth welds on a new pipeline segment must be non-destructively examined in accordance with § 192.243(b) and (c). (1) Notwithstanding any lesser depth of cover otherwise allowed in § 192.327, there must be at least 36 inches (914 millimeters) of cover or equivalent means to protect the pipeline from outside force damage. (2) In areas where deep tilling or other activities could threaten the pipeline, the top of the pipeline must be installed at least one foot below the deepest expected penetration of the soil. (1) The pipeline segment must not have experienced failures indicative of systemic material defects during strength testing, including initial hydrostatic testing. A root cause analysis, including metallurgical examination of the failed pipe, must be performed for any failure experienced to verify that it is not indicative of a systemic concern. The results of this root cause analysis must be reported to each PHMSA pipeline safety regional office where the pipe is in service at least 60 days prior to operating at the alternative MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State. (1) For a new pipeline segment, the construction must address the impacts of induced alternating current from parallel electric transmission lines and other known sources of potential interference with corrosion control. |
This subpart prescribes minimum requirements for installing customer meters, service regulators, service lines, service line valves, and service line connections to mains.
Branched service line means a gas service line that begins at the existing service line or is installed concurrently with the primary service line but serves a separate residence.
Replaced service line means a gas service line where the fitting that connects the service line to the main is replaced or the piping connected to this fitting is replaced.
Service line serving single-family residence means a gas service line that begins at the fitting that connects the service line to the main and serves only one single family residence (SFR).
Manual service line shut-off valve means a curb valve or other manually operated valve located near the service line that is safely accessible to operator personnel or other personnel authorized by the operator to manually shut off gas flow to the service line, if needed.
This subpart prescribes minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion.
Whenever an operator has knowledge that any portion of a buried pipeline is exposed, the exposed portion, if bare or the coating is deteriorated, must be examined for evidence of external corrosion. If external corrosion requiring remedial action under §§ 192.483 through 192.489 is found, the operator shall investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion.
Each pipeline under cathodic protection required by this subpart must have sufficient test stations or other contact points for electrical measurement to determine the adequacy of cathodic protection.
If corrosive gas is being transported, coupons or other suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion must be checked two times each calendar year, but with intervals not exceeding 7 1/2 months.
If the pipeline is located..... | Then the frequency of inspections is: |
Onshore | At least once every 3 calendar years, but with intervals not exceeding 39 months. |
Offshore | At least once each calendar year, but with intervals not exceeding 15 months. |
Each operator that uses direct assessment as defined in § 192.903 on an onshore transmission line made primarily of steel or iron to evaluate the effects of a threat in the first column must carry out the direct assessment according to the standard listed in the second column. These standards do not apply to methods associated with direct assessment, such as close interval surveys, voltage gradient surveys, or examination of exposed pipelines, when used separately from the direct assessment process.
Threat | Standard1 |
External corrosion | § 192.9252 |
Internal corrosion in pipelines that transport dry gas | § 192.927 |
Stress corrosion cracking | § 192.929 |
1For lines not subject to subpart O of this part, the terms "covered segment" and "covered pipeline segment" in §§ 192.925, 192.927, and 192.929 refer to the pipeline segment on which direct assessment is performed.
2In § 192.925(b), the provision regarding detection of coating damage applies only to pipelines subject to subpart O of this part.
This subpart prescribes minimum leak-test and strength-test requirements for pipelines.
Class location | Maximum hoop stress allowed as percentage of SMYS | |
Natural Gas | Air or inert gas | |
1........ | 80 | 80 |
2........ | 30 | 75 |
3........ | 9/18/2023A0 | 50 |
4........ | 30 | 40 |
Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated at a hoop stress less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage must be tested in accordance with the following:
Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated below 100 p.s.i.g. must be leak tested in accordance with the following:
This subpart prescribes minimum requirements for increasing maximum allowable operating pressures (uprating) for pipelines.
Pipe Size Inches (millimeters) | ALLOWANCE Inches (millimeters) Cast Iron Pipe | ||
Cast Iron Pipe | Ductile iron pipe | ||
Pit Cast Pipe | Centrifugally Cast Pipe | ||
3-8 (76-203) | 0.075(1.91) | 0.065(1.65) | 0.065(1.65) |
10-12 (254 to 305) | 0.08(2.03) | 0.07(1.78) | 0.07(1.78) |
14-24 (356 to 610) | 0.08(2.03) | 0.08(2.03) | 0.075(1.91) |
30-42 (762 to 1067) | 0.09(2.29) | 0.09(2.29) | 0.075(1.91) |
48 (1219) | 0.09(2.29) | 0.09(2.29) | 0.08(2.03) |
54-60 (1372 to 1524) | 0.09(2.29) | ------------ | ------------ |
This subpart prescribes minimum requirements for the operation of pipeline facilities.
Whenever an increase in population density indicates a change in class location for a segment of an existing steel pipeline operating at hoop stress that is more than 40 percent of SMYS, or indicates that the hoop stress corresponding to the established maximum allowable operating pressure for a segment of existing pipeline is not commensurate with the present class location, the operator shall immediately make a study to determine:
Class location | Factors Segment- | ||
Installed before (Nov.12, 1970) | Installed after (Nov. 11, 1970) | Converted under § 192.14 | |
1........ | 1.1 | 1.1 | 1.25 |
2........ | 1.25 | 1.25 | 1.25 |
3......... | 1.4 | 1.5 | 1.5 |
4......... | 1.4 | 1.5 | 1.5 |
Pipeline segment | Pressure date | Test date |
-Onshore gathering line that first became subject to this part (other than § 192.612) after April 13, 2006. -Onshore transmission line that was a gathering line not subject to this part before March 15, 2006. Offshore gathering lines.... All other pipelines..... | March 15, 2006, or date line becomes subject to this part, whichever is later. July 1, 1976 July 1, 1970 | 5 years preceding applicable date in second column. July 1, 1971 July 1, 1965 |
Class Location | Alternative Design Factor (F) |
1 | 0.80 |
2 | 0.67 |
3 | 0.56 |
Class Location | Alternative Test Factor |
1 | 1.25 |
2 | 1.50 1 |
3 | 1.50 |
1 For Class 2 alternative maximum allowable operating pressure segments installed prior to December 22, 2008, the alternative test factor is 1.25.
To address increased risk of a maximum allowable operating pressure based on higher stress levels in the following areas: | Take the following additional step: |
(1) Identifying and evaluating threats. | Develop a threat matrix consistent with § 192.917 to do the following: (i) Identify and compare the increased risk of operating the pipeline at the increased stress level under this section with conventional operation; and (ii) Describe and implement procedures used to mitigate the risk. |
(2) Notifying the public. | (i) Recalculate the potential impact circle as defined in § 192.903 to reflect use of the alternative maximum operating pressure calculated under paragraph (a) of this section and pipeline operating conditions; and (ii) In implementing the public education program required under § 192.616, perform the following: (A) Include persons occupying property within 220 yards of the centerline and within the potential impact circle within the targeted audience; and (B) Include information about the integrity management activities performed under this section within the message provided to the audience. |
(3) Responding to an emergency in an area defined as a high consequence are in § 192.903. | (i) Ensure that the identification of high consequence areas reflects the larger potential impact circle recalculated under paragraph (d)(2)(i) of this section. (ii) If personnel response time to mainline valves on either side of the high consequence area exceeds one hour (under normal driving conditions and speed limits) from the time the event is identified in the control room, provide remote valve control through a supervisory control and data acquisition (SCADA) system, other leak detection system, or an alternate method of control. (iii) Remote valve control must include the ability to close and monitor the valve position (open or closed), and monitor pressure upstream and downstream. (iv) A line break valve control system using differential pressure, rate of pressure drop or other widely-accepted method is an acceptable alternative to remove valve control. |
(4) Protecting the rightof-way. | (i) Patrol the right-of-way at intervals not exceeding 45 days, but at least 12 times each calendar year, to inspect for excavation activities, ground movement, wash outs, leakage, or other activities or conditions affecting the safety operation of the pipeline. (ii) Develop and implement a plan to monitor for and mitigate occurrences of unstable soil and ground movement. (iii) If observed conditions indicate the possible loss of cover, perform a depth of cover study and replace cover as necessary to restore the depth of cover or apply alternative means to provide protection equivalent to the originally-required depth of cover. (iv) Use line-of-sight line markers satisfying the requirements of § 192.707(d) except in agricultural areas, large water crossings or swamp, steep terrain, or where prohibited by Federal Energy Regulatory Commission orders, permits, or local law. (v) Review the damage prevention program under § 192.614(a) in light of national consensus practices, to ensure the program provides adequate protection of the right-of-way. Identify the standards or practices considered in the review, and meet or exceed those standards or practices by incorporating appropriate changes into the program. (vi) Develop and implement a right-of-way management plan to protect the pipeline segment from damage due to excavation activities. |
(5) Controlling internal corrosion. | (i) Develop and implement a program to monitor for and mitigate the presence of, deleterious gas stream constituents. (ii) At points where gas with potentially deleterious contaminants enters the pipeline, use filter separators or separators and gas quality monitoring equipment. (iii) Use gas quality monitoring equipment that includes a moisture analyzer, chromatograph, and periodic hydrogen sulfide sampling. (iv) Use cleaning pigs and sample accumulated liquids. Use inhibitors when corrosive gas or liquids are present. (v) Address deleterious gas stream constituents as follows: (A) Limit carbon dioxide to 3 percent by volume; (B) Allow no free water and otherwise limit water to seven pounds per million cubic feet of gas; and (C) Limit hydrogen sulfide to 1.0 grain per hundred cubic feet (16 ppm) of gas, where the hydrogen sulfide is greater than 0.5 grain per hundred cubic feet (8 ppm) of gas, implement a pigging and inhibitor injection program to address deleterious gas stream constituents, including follow-up sampling and quality testing of liquids at receipt points. (vi) Review the program at least quarterly based on the gas stream experience and implement adjustments to monitor for, and mitigate the presence of, deleterious gas stream constituents. |
(6) Controlling interference that can impact external corrosion. | (i) Prior to operating an existing pipeline segment at an alternate maximum allowable operating pressure calculated under this section, or within six months after placing a new pipeline segment in service at an alternate maximum allowable operating pressure calculated under this section, address any interference currents on the pipeline section. (ii) To address interference currents, perform the following: (A) Conduct an interference survey to detect the presence and level of any electrical current that could impact external corrosion where interference is suspected; (B) Analyze the results of the survey; and (C) Take any remedial action needed within 6 months after completing the survey to protect the pipeline segment from deleterious current. |
(7) Confirming external corrosion control through indirect assessment. | (i) Within six months after placing the cathodic protection of a new pipeline segment in operation, or within six months after certifying a segment under § 192.620(c)(1) of an existing pipeline segment under this section, assess the adequacy of the cathodic protection through an indirect method such as close-interval survey, and the integrity of the coating using direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG). (ii) Remediate any construction damaged coating with a voltage drop classified as moderate or severe (IR drop greater than 35% for DCVG or 50 dBµv for ACVG) under section 4 of NACE RP-0502-2002 (incorporated by reference, see § 192.7). (iii) Within six months after completing the baseline internal inspection required under paragraph (d)(9) of this section, integrate the results of the indirect assessment required under paragraph (d)(7)(i) of this section with the results of the baseline internal inspection and take any needed remedial actions. (iv) For all pipeline segments in high consequence areas, perform periodic assessments as follows: (A) Conduct periodic close interval surveys with current interrupted to confirm voltage drops in association with periodic assessments under subpart O of this part. (B) Locate pipe-to-soil test stations at half-mile intervals within each high consequence area ensuring at least one station is within each high consequence area, if practicable. (C) Integrate the results with those of the baseline and periodic assessments for integrity done under paragraphs (d)(9) and (d)(10) of this section. |
(8) Controlling external corrosion through cathodic protection. | (i) If an annual test station reading indicates cathodic protection below the level of protection required in subpart I of this part, complete remedial action within six months of the failed reading or notify each PHMSA pipeline safety regional office where the pipeline is in service demonstrating that the integrity of the pipeline is not compromised if the repair takes longer than 6 months. An operator must also notify the State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State; and (ii) After remedial action to address a failed reading, confirm restoration of adequate corrosion control by a close interval survey on either side of the affected test station to the next test station unless the reason for the failed reading is determined to be a rectifier connection or power input problem that can be remediated and otherwise verified. (iii) If the pipeline segment has been in operation, the cathodic protection system on the pipeline segment must have been operational within 12 months of the completion of construction. |
(9) Conducting a baseline assessment of integrity. | (i) Except as provided in paragraph (d)(9)(iii) of this section, for a new pipeline segment operating at the new alternative maximum allowable operating pressure, perform a baseline internal inspection of the entire pipeline segment as follows: (A) Assess using a geometry tool after the initial hydrostatic test and backfill and within six months after placing the new pipeline segment in service; and (B) Assess using a high resolution magnetic flux tool within three years after placing the new pipeline segment in service at the alternative maximum allowable operating pressure. (ii) Except as provided in paragraph (d)(9)(iii) of this section, for an existing pipeline segment, perform a baseline internal assessment using a geometry tool and a high resolution magnetic flux tool before, but within two years prior to, raising pressure to the alternative maximum allowable operating pressure as allowed under this section. (iii) If headers, mainline valve by-passes, compressor station piping, meter station piping, or other short portion of a pipeline segment operating at alternative maximum allowable operating pressure cannot accommodate a geometry tool and a high resolution magnetic flux tool, use direct assessment (per § 192.925, § 192.927 and/or § 192.929) or pressure testing (per subpart J of this part) to assess that portion. |
(10) Conducting periodic assessments of integrity. | (i) Determine a frequency for subsequent periodic integrity assessments as if all the alternative maximum allowable operating pressure pipeline segments were covered by subpart O of this part; and (ii) Conduct periodic internal inspections using a high resolution magnetic flux tool on the frequency determined under paragraph (d)(10)(i) of this section, or (iii) Use direct assessment (per § 192.925, § 192.927 and/or § 192.929) or pressure testing (per subpart J of this part) for periodic assessment of a portion of a segment to the extent permitted for a baseline assessment under paragraph (d)(9)(iii) of this section. |
(11) Making repairs. | (i) Perform the following when evaluating an anomaly: (A) Use the most conservative calculation for determining remaining strength or an alternative validated calculation based on pipe diameter, wall thickness, grade, operating pressure, operating stress level, and operating temperature: and (B) Take into account the tolerance of the tools used in the inspection. (ii) Repair a defect immediately if any of the following apply: (A) The defect is a dent discovered during the baseline assessment for integrity under paragraph (d)(9) of this section and the defect meets the criteria for immediate repair in §192.309(b) (B) The defect meets the criteria for immediate repair in § 192.933(d). (C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure. (D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under paragraph (a) of this section and the failure pressure is less than 1.4 times the alternative maximum allowable operating pressure. (iii) If paragraph (d)(11)(ii) of this section does not require immediate repair, repair a defect within one year if any of the following apply: (A) The defect meets the criteria for repair within one year in § 192.933(d). (B) The alternative maximum allowable operating pressure was based on a design factor of 0.80 under paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure. (C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under paragraph (a) of this section and the failure pressure is less than 1.50 times the alternative maximum allowable operating pressure. (D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under paragraph (a) of this section and the failure pressure is less than or equal to 1.80 times the alternative maximum allowable operating pressure. (iv) Evaluate any defect not required to be repaired under paragraph (d)(11)(ii) or (iii) of this section to determine its growth rate, set the maximum interval for repair or reinspection, and repair or re-inspect within that interval. |
Operators must comply with the team training requirements under this paragraph by no later than January 23, 2018.
This subpart prescribes minimum requirements for maintenance of pipeline facilities.
Maximum interval between patrols | ||
Class location of line | At highway and railroad crossings | At all other places |
1, 2....... | 7 1/2 months, but at least twice each .calendar year. | 15 months, but at least once each calendar year. |
3........ | 4 1/2 months, but at least four times each calendar year. | 7 1/2 months, but at least twice each calendar year. |
4........ | 4 1/2 months, but at least four times each calendar year. | 4 1/2 months, but at least four times each calendar year. |
Leakage surveys of a transmission line must be conducted at intervals not exceeding 15 months, but at least once each calendar year. However, in the case of a transmission line which transports gas in conformity with § 192.625 without an odor or odorant, leakage surveys using leak detector equipment must be conducted:
Each operator shall maintain the following records for transmission lines for the periods specified:
Each weld that is unacceptable under § 192.241(c) must be repaired as follows:
Each permanent field repair of a leak on a transmission line must be made by-
NOTE: Test duration must be of sufficient length to detect leakage, and the following should be considered:
Volume under test and the time for the test medium to become temperature stabilized.
If the MAOP produces a hoop stress that is: | Then the pressure limit is: |
Greater than 72 percent of SMYS | MAOP plus 4 percent |
Unknown as a precentage of SMYS | A pressure that will prevent unsafe operation of the pipeline considering its operating and maintenance history and MAOP |
Each operator shall take steps to minimize the danger of accidental ignition of gas in any structure or area where the presence of gas constitutes a hazard of fire or explosion, including the following:
When an operator has knowledge that the support for a segment of a buried cast iron pipeline is disturbed:
Abnormal operating condition means a condition identified by the operator that may indicate a malfunction of a component or deviation from normal operations that may:
Evaluation means a process, established and documented by the operator, to determine an individual's ability to perform a covered task by any of the following:
Qualified means that an individual has been evaluated and can:
Each operator shall have and follow a written qualification program. The program shall include provisions to:
Each operator shall maintain records that demonstrate compliance with this subpart.
This subpart prescribes minimum requirements for an integrity management program on any gas transmission pipeline covered under this part. For gas transmission pipelines constructed of plastic, only the requirements in §§ 192.917, 192.921, 192.935 and 192.937 apply.
The following definitions apply to this subpart.
Assessment is the use of testing techniques as allowed in this subpart to ascertain the condition of a covered pipeline segment.
Confirmatory direct assessment is an integrity assessment method using more focused application of the principles and techniques of direct assessment to identify internal and external corrosion in a covered transmission pipeline segment.
Covered segment or covered pipeline segment means a segment of gas transmission pipeline located in a high consequence area. The terms gas and transmission line are defined in § 192.3.
Direct assessment is an integrity assessment method that utilizes a process to evaluate certain threats (i.e., external corrosion, internal corrosion and stress corrosion cracking) to a covered pipeline segment's integrity. The process includes the gathering and integration of risk factor data, indirect examination or analysis to identify areas of suspected corrosion, direct examination of the pipeline in these areas, and post assessment evaluation.
High consequence area means an area established by one of the methods described in paragraphs (1) or (2) as follows:
Identified site means each of the following areas:
Potential impact circle is a circle of radius equal to the potential impact radius (PIR).
Potential impact radius (PIR) means the radius of a circle within which the potential failure of a pipeline could have significant impact on people or property. PIR is determined by the formula r = 0.69 * (square root of (p*d2)), where 'r' is the radius of a circular area in feet surrounding the point of failure, 'p' is the maximum allowable operating pressure (MAOP) in the pipeline segment in pounds per square inch and 'd' is the nominal diameter of the pipeline in inches.
Note: 0.69 is the factor for natural gas. This number will vary for other gases depending upon their heat of combustion. An operator transporting gas other than natural gas must use section 3.2 of ASME/ANSI B31.8S (incorporated by reference, see § 192.7) to calculate the impact radius formula.
Remediation is a repair or mitigation activity an operator takes on a covered segment to limit or reduce the probability of an undesired event occurring or the expected consequences from the event.
An operator's initial integrity management program begins with a framework (see § 192.907) and evolves into a more detailed and comprehensive integrity management program, as information is gained and incorporated into the program. An operator must make continual improvements to its program. The initial program framework and subsequent program must, at minimum, contain the following elements. (When indicated, refer to ASME/ANSI B31.8S (incorporated by reference, see § 192.7) for more detailed information on the listed element.)
An operator must include each of the following elements in its written baseline assessment plan:
An operator using the confirmatory direct assessment (CDA) method as allowed in § 192.937 must have a plan that meets the requirements of this section and of § 192.925 (ECDA) and § 192.927 (ICDA).
An operator must comply with the following requirements in establishing the reassessment interval for the operator's covered pipeline segments.
Maximum Reassessment Interval | |||
Assessment Method | Pipeline operating at or above 50% SMYS | Pipeline operating at or above 30% SMYS, up to 50% SMYS | Pipeline operating below 30% SMYS |
Internal Inspection Tool, Pressure Test or Direct Assessment | 10 years(*) | 15 years(*) | 20 years(**) |
Confirmatory Direct Assessment | 7 years | 7 years | 7 years |
Low stress Reassessment | Not applicable | Not applicable | 7 years + ongoing actions specified in § 192.941 |
(*) A Confirmatory direct assessment as described in § 192.931 must be conducted by year 7 in a 10-year interval and years 7 and 14 of a 15-year interval.
(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the interval.
An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At minimum, an operator must maintain the following records for review during an inspection.
An operator must provide any notification required by this subpart by -
An operator must file any report required by this subpart to the Information Resources Manager through the online reporting system provided by PHMSA for electronic reporting in accordance with § 191.7 of this Code.
The following definitions apply to this subpart:
Excavation Damage means any impact that results in the need to repair or replace an underground facility due to a weakening, or the partial or complete destruction, of the facility, including, but not limited to, the protective coating, lateral support, cathodic protection or the housing for the line device or facility.
Hazardous Leak means a leak that represents an existing or probably hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous.
Integrity Management Plan or IM Plan means a written explanation of the mechanisms or procedures the operator will use to implement its integrity management program and to ensure compliance with this subpart.
Integrity Management Program or IM Program means an overall approach by an operator to ensure the integrity of its gas distribution system.
Mechanical fitting means a mechanical device used to connect sections of pipe. The term "Mechanical fitting" applies only to:
Small LPG Operator means an operator of a liquefied petroleum gas (LPG) distribution pipeline that serves fewer than 100 customers from a single source.
No later than August 2, 2011 a gas distribution operator must develop and implement an integrity management program that includes a written integrity management plan as specified in § 192.1007.
A written integrity management plan must contain procedures for developing and implementing the following elements:
An operator must maintain records demonstrating compliance with the requirements of this subpart for at least 10 years. The records must include copies of superseded integrity management plans developed under this subpart.
APPENDIX A TO PART 192 - RESERVED
APPENDIX B TO PART 192 - QUALIFICATION OF PIPE
I.Listed Pipe Specifications
ANSI/API Specification 5L-Steel Pipe, "Specification for Line Pipe" (incorporated by reference, see § 192.7).
ASTM A53/A53M-Steel Pipe, "Standard Specification for Pipe, Steel Black and Hot-Dipped, Zinc-Coated, Welded and Seamless" (incorporated by reference, see § 192.7).
ASTM A106/A106M-Steel Pipe, "Standard Specification for Seamless Carbon Steel Pipe for High Temperature Service" (incorporated by reference, see § 192.7).
ASTM A333/A333M-Steel Pipe, "Standard Specification for Seamless and Welded Steel Pipe for Low Temperature Service" (incorporated by reference, see § 192.7).
ASTM A381-Steel pipe, "Standard Specification for Metal-Arc-Welded Steel Pipe for Use with High-Pressure Transmission Systems" (incorporated by reference, see § 192.7).
ASTM A671/A671M-Steel pipe, "Standard Specification for Electric-Fusion- Welded Pipe for Atmospheric and Lower Temperatures" (incorporated by reference, see § 192.7).
ASTM A672/A672M-Steel pipe, "Standard Specification for Electric-Fusion- Welded Steel Pipe for High-Pressure Service at Moderate Temperatures" (incorporated by reference, see § 192.7).
ASTM A691/A691M-Steel pipe "Standard Specification for Carbon and Alloy Steel Pipe, ElectricFusion-Welded for High Pressure Service at High Temperatures" (incorporated by reference, see § 192. 7).
ASTM D2513-99, "Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings" (incorporated by reference, see § 192.7).
ASTM D2513-09a-Polyethylene thermoplastic pipe and tubing, "Standard Specification for Polyethylene (PE) gas Pressure Pipe, Tubing, and Fittings", (incorporated by reference, see § 192.7).
ASTM D2517-Thermosetting plastic pipe and tubing, "Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (incorporated by reference, see § 192.7).
II. Steel Pipe of Unknown or Unlisted Specification
A. Bending Properties. For pipe 2 inches (51 millimeters) or less in diameter, a length of pipe must be cold bent through at least 90 degrees around a cylindrical mandrel that has a diameter 12 times the diameter of the pipe, without developing cracks at any portion and without opening the longitudinal weld. For pipe more than 2 inches (51 millimeters) in diameter, the pipe must meet the requirements of the flattening tests set forth in ASTM A53/A53M (incorporated by reference, see § 192.7) except that the number of tests must be at least equal to the minimum required in paragraph II-D of this appendix to determine yield strength.
B. Weldability. A girth weld must be made in the pipe by a welder who is qualified under subpart E of this part. The weld must be made under the most severe conditions under which welding will be allowed in the field and by means of the same procedure that will be used in the field. On pipe more than 4 inches (102 millimeters) in diameter, at least one test weld must be made for each 100 lengths of pipe. On pipe 4 inches (102 millimeters) or less in diameter, at least one test weld must be made for each 400 lengths of pipe. The weld must be tested in accordance with API Standard 1104 (incorporated by reference, see § 192.7). If the requirements of API Standard 1104 cannot be met, weldability may be established by making chemical tests for carbon and manganese, and proceeding in accordance with section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference, see § 192.7). The same number of chemical tests must be made as are required for testing a girth weld.
C. Inspection. The pipe must be clean enough to permit adequate inspection. It must be visually inspected to ensure that it is reasonably round and straight and there are no defects which might impair the strength or tightness of the pipe.
D. Tensile properties. If the tensile properties of the pipe are not known, the minimum yield strength may be taken as 24,000 p.s.i. (165 MPa) or less, or the tensile properties may be established by performing tensile test as set forth in API Specification 5L (incorporated by reference, see § 192.7). All test specimens shall be selected at random and the following number of tests must be performed.
Number of Tensile Tests - All Sizes
10 lengths or less | 1 set of tests for each length. |
11 to 100 lengths | 1 set of tests for each 5 lengths, but not less than 10 tests. |
Over 100 lengths | 1 set of tests for each 10 lengths, but not less than 20 tests. |
If the yield-tensile ratio, based on the properties determined by those tests, exceeds 0.85, the pipe may be used only as provided in § 192.55 (c).
III. Steel Pipe Manufactured Before November 12, 1970, to Earlier Editions of Listed Specifications
Steel pipe manufactured before November 12, 1970, in accordance with a specification of which a later edition is listed in Section I of this appendix, is qualified for use under this part if the following requirements are met:
A. Inspection. The pipe must be clean enough to permit adequate inspection. It must be visually inspected to ensure that it is reasonably round and straight and that there are no defects which might impair the strength or tightness of the pipe.
B. Similarity of specification requirements. The edition of the listed specification under which the pipe was manufactured must have substantially the same requirements with respect to the following properties as a later edition of that specification listed in Section I of this appendix:
(1) Physical (mechanical) properties of pipe, including yield and tensile strength, elongation, and yield to tensile ratio, and testing requirements to verify those properties.
(2) Chemical properties of pipe and testing requirements to verify those properties.
C. Inspection or test of welded pipe. On pipe with welded seams, one of the following requirements must be met:
(1) The edition of the listed specification to which the pipe was manufactured must have substantially the same requirements with respect to nondestructive inspection of welded seams and the standards for acceptance or rejection and repair as a later edition of the specification listed in Section I of this appendix.
(2) The pipe must be tested in accordance with Subpart J of this part to at least 1.25 times the maximum allowable operating pressure if it is to be installed in a Class 1 location and to at least 1.5 times the maximum allowable operating pressure if it is to be installed in a Class 2, 3 or 4 location. Notwithstanding any shorter time period permitted under Subpart J of this part, the test pressure must be maintained for at least 8 hours.
APPENDIX C TO PART 192 - QUALIFICATION OF WELDERS FOR LOW STRESS LEVEL PIPE
I. Basic Test
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.
II. Additional Tests for Welders of Service Line Connections to Mains
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.
III. Periodic Tests for Welders of Small Service Lines
Two samples of the welder's work, each about 8 inches (203 millimeters) long with the weld located approximately in the center, are cut from steel service line and tested as follows:
(1) One sample is centered in a guided bend testing machine and bent to the contour of the die for a distance of 2 inches (51 millimeters) on each side of the weld. If the sample shows any breaks or cracks after removal from the bending machine, it is unacceptable.
(2) The ends of the second sample are flattened and the entire joint subjected to a tensile strength test. If failure occurs adjacent to or in the weld metal, the weld is unacceptable. If a tensile strength testing machine is not available, this sample must also pass the bending test prescribed in Subparagraph (1) of this paragraph.
APPENDIX D TO PART 192 - CRITERIA FOR CATHODIC PROTECTION AND DETERMINATION OF MEASUREMENTS
I. Criteria for Cathodic Protection
A. Steel, cast iron, and ductile iron structures
(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 Sections II and IV of this appendix.
(2) A negative (cathodic) voltage shift of at least 300 millivolts. Determination of this voltage shift must be made with the protective current applied, and in accordance with Sections II and IV of this appendix. This criterion of voltage shift applies to structures not in contact with metal of different anodic potentials.
(3) A minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with Sections III and IV of this appendix.
(4) A voltage at least as negative (cathodic) as that originally established at the beginning of the Tafel segment of the E-log-I curve. This voltage must be measured in accordance with Section IV of this appendix.
(5) A net protective current from the electrolyte into the structure surface as measured by an earth current technique applied at predetermined current discharge (anodic) points of the structure.
B. Aluminum structures
(1) Except as provided in Subparagraphs (3) and (4) of this paragraph, a minimum negative (cathodic) voltage shift of 150 millivolts, produced by the application of protective current. The voltage shift must be determined in accordance with Sections II and IV of this appendix.
(2) Except as provided in Subparagraphs (3) and (4) of this paragraph, a minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with Sections III and IV of this appendix.
(3) Notwithstanding the alternative minimum criteria in Subparagraphs (1) and (2) of this paragraph, aluminum, if cathodically protected at voltages in excess of 1.20 volts as measured with reference to a copper-copper sulfate half cell, in accordance with Section IV of this appendix, and compensated for the voltage (IR) drops other than those across the structure-electrolyte boundary, may suffer corrosion resulting from the buildup of alkali on the metal surface. A voltage in excess of 1.20 volts may not be used unless previous test results indicate no appreciable corrosion will occur in the particular environment.
(4) Since aluminum may suffer from corrosion under high pH conditions, and since application of cathodic protection tends to increase the pH at the metal surface, careful investigation or testing must be made before applying cathodic protection to stop pitting attack on aluminum structures in environments with a natural pH in excess of 8.
C. Copper structures
A minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with Sections III and IV of this appendix.
D. Metals of different anodic potentials
A negative (cathodic) voltage, measured in accordance with Section IV of this appendix, equal to that required for the most anodic metal in the system must be maintained. If amphoteric structures are involved that could be damaged by high alkalinity covered by Subparagraphs (3) and (4) of paragraph B of this section, they must be electrically isolated with insulating flanges, or the equivalent.
II. Interpretation of Voltage Measurement
Voltage (IR) drops other than those across the structure-electrolyte boundary must be considered for valid interpretation of the voltage measurement in paragraphs A(1) and (2) and paragraph B(1) of Section I of this appendix.
III. Determination of Polarization Voltage Shift
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 in paragraphs A(3), B(2), and C of Section I of this appendix.
IV. Reference Half Cells
A. Except as provided in paragraphs B and C of this section, negative (cathodic) voltage must be measured between the structure surface and a saturated copper-copper sulfate half cell contacting the electrolyte.
B. Other standard reference half cells may be substituted for the saturated copper-copper sulfate half cell. Two commonly used reference half cells are listed below along with their voltage equivalent to -0.85 volt as referred to a saturated copper- copper sulfate half cell:
(1) Saturated KCl calomel half cell: -0.78 volt.
(2) Silver-silver chloride half cell used in sea water: -0.80 volt.
C. In addition to the standard reference half cells, an alternate metallic material or structure may be used in place of the saturated copper sulfate half cell if its potential stability is assured and if its voltage equivalent referred to a saturated copper-copper sulfate half cell is established.
APPENDIX E TO PART 192 - GUIDANCE ON DETERMINING HIGH CONSEQUENCE AREAS AND ON CARRYING OUT REQUIREMENTS IN THE INTEGRITY MANAGEMENT RULE
I. Guidance on Determining a High Consequence Area
To determine which segments of an operator's transmission pipeline system are covered for purposes of the integrity management program requirements, an operator must identify the high consequence areas. An operator must use method (1) or (2) from the definition in § 192.903 to identify a high consequence area. An operator may apply one method to its entire pipeline system, or an operator may apply one method to individual portions of the pipeline system. (Refer to figure E.I.A for a diagram of a high consequence area).
Determining a High Consequence Area
II. Guidance on Assessment Methods and Additional Preventive and Mitigative
Measures for Transmission Pipelines
(a) Table E.II.1 gives guidance to help an operator implement requirements on additional preventive and mitigative measures for addressing time dependent and independent threats for a transmission pipeline operating below 30% SMYS not in an HCA (i.e. outside of potential impact circle) but located within a Class 3 or Class 4 Location.
(b) Table E.II.2 gives guidance to help an operator implement requirements on assessment methods for addressing time dependent and independent threats for a transmission pipeline in an HCA.
(c) Table E.II.3 gives guidance on preventative & mitigative measures addressing time dependent and independent threats for transmission pipelines that operate below 30% SMYS, in HCAs.
Table E.II.1
Preventive and Mitigative Measures for Transmission Pipelines Operating Below 30% SMYS not in an HCA but in a Class 3 or Class 4 Location
(Column 1) Threat | Existing 192 Requirements | (Column 4) Additional(to 192 requirements) Preventive and Mitigative Measures | |
(Column 2) Primary | (Column 3) Secondary | ||
External Corrosion | 455-(Gen. Post 1971), 457-(Gen. Pre-1971) 459-(Examination), 461-(Ext. coating) 463-(CP), 465-(Monitoring) 467-(Elect isolation), (469-Test stations) 471-(Test leads), 473-(Interference) 479-(Atmospheric), 481-(Atmospheric) 485-(Remedial), 705-(Patrol) 706-(Leak survey), 711 -(Repair - gen.) 717-(Repair - perm.) | 603-(Gen Oper'n) 613-(Surveillance) | For Cathodically Protected Transmission Pipeline: * Perform semi-annual leak surveys. For Unprotected Transmission Pipelines or for Cathodically Protected Pipe where Electrical Surveys are Impractical: * Perform quarterly leak surveys |
Internal Corrosion | 475-(Gen IC), 477-(IC monitoring) 485-(Remedial), 705-(Patrol) 706-(Leak survey), 711-(Repair - gen.) 717-(Repair - perm.) | 53(a)-(Materials) 603-(Gen Oper'n) 613-(Surveillance) | * Perform semi-annual leak surveys. |
3rd Party Damage | 103-(Gen. Design), 111-(Design factor) 317-(Hazard prot), 327-(Cover) 614-(Dam. Prevent), 616-(Public education) 705-(Patrol), 707-(Line markers) 711 (Repair - gen.), 717-(Repair - perm.) | 615-(Emerg. Plan) | * Participation in state one-call system, * Use of qualified operator employees and contractors to perform marking and locating of buried structures and in direct supervision of excavation work, AND * Either monitoring of excavations near operator's transmission pipelines, or bi-monthly patrol of transmission pipelines in class 3 and 4 locations. Any indications of unreported construction activity would require a follow up investigation to determine if mechanical damage occurred. |
Table E.II.2
Assessment Requirements for Transmission Pipelines in HCAs (Re-assessment intervals are maximum allowed)
Re-Assessment Requirements (see Note 3) | ||||||
At or above 50% SMYS | At or above 30% SMYS up to 50% SMYS | Below 30% SMYS | ||||
Baseline Assessment Method (see Note 3) | Max Re-Assessment Interval | Assessment Method | Max Re-Assessment Interval | Assessment Method | Max Re-Assessment Interval | Assessment Method |
Pressure Testing | 7 | CDA | 7 | CDA | Ongoing | Preventative &Mitigative (P&M) Measures (see Table E.II.3), (see Note 2) |
10 | Pressure Test or ILI or DA | |||||
Repeat inspection cycle every 10 years | 15(see Note 1) | Pressure Test or ILI or DA (see Note 1) | ||||
Repeat inspection cycle every 15 years | Pressure Test or ILI or DA | |||||
20 | ||||||
Repeat inspection cycle every 20 years | ||||||
In-Line Inspection | 7 | CDA | 7 | CDA | Ongoing | Preventative &Mitigative (P&M) Measures (see Table E.II.3), (see Note 2) |
10 | ILI or DA or Pressure Test | |||||
Repeat inspection cycle every 10 years | 15 (see Note 1) | ILI or DA or Pressure Test (see Note 1) | ||||
Repeat inspection cycle every 15 years | 20 | ILI or DA or Pressure Test | ||||
Repeat inspection cycle every 20 years | ||||||
Direct Assessment | 7 | CDA | 7 | CDA | Ongoing | Preventative &Mitigative (P&M) Measures (see Table E.II.3), (see Note 2) |
10 | DA or ILI or Pressure Test | |||||
Repeat inspection cycle every 10 years | 15(see Note 1) | DA or ILI or Pressure Test (see Note 1) | ||||
Repeat inspection cycle every 15 years | 20 | DA or ILI or Pressure Test | ||||
Repeat inspection cycle every 20 years | ||||||
Note 1: Operator may choose to utilize CDA at year 14, then utilize ILI, Pressure Test, or DA at year 15 as allowed under ASME B31.8S
Note 2: Operator may choose to utilize CDA at year 7 and 14 in lieu of P & M
Note 3: Operator may utilize "other technology that an operator demonstrates can provide an equivalent understanding of the condition of line pipe"
Table E.II.3
Preventative & Mitigative Measures addressing Time Dependent and Independent Threats for Transmission Pipelines that Operate Below 30% SMYS, in HCAs
Threat | Existing 192 Requirements | Additional (to 192 requirements) Preventive & Mitigative Measures | |
Primary | Secondary | ||
External Corrosion | 455 - (Gen. Post 1971) 457 - (Gen. pre-1971) 459 - (Examination) 461 - (Ext. coating) 463 - (CP) 465 - (Monitoring) 467 - (Elect isolation) | 603 - (Gen Oper) 613 - (Surveil) | For Cathodically protected Trmn. Pipelines * Perform an electrical survey (i.e. indirect examination tool/method) at least every 7 years. Results are to be utilized as part of an overall evaluation of the CP system and corrosion threat for the covered segment. Evaluation shall include consideration of leak repair and ispection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. |
External Corrosion | 469 - (Test stations) 471 - (Test leads) 473 - (Interference) 479 - (Atmospheric) 481 - (Atmospheric) 485 - (Remedial) 705 - (Patrol) 706 - (Leak survey) 711 - (repair - gen.) 717 - (Repair perm.) | For Unprotected Trmn. Pipelines or for Cathodically protected Pipe where Electrical Surveys are Impracticable * Conduct quarterly leak surveys AND * Every 1 1/2 years, determine areas of active corrosion by evaluation of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. | |
Internal Corrosion | 475 - (Gen IC) 477 - (IC monitoring) 485 - (Remedial) 705 - (Patrol) 706 - (Leak survey) 711 - (repair - gen.) 717 - (Repair perm.) | 53 (a) - (Materials) 603 - (Gen Oper) 613 - (Surveil) | * Obtain and review gas analysis data each calendar year for corrosive agents from transmission pipelines in HCAs, * Periodic testing of fluid removed from pipelines. Specifically, once each calendar year from each storage field that may affect transmission pipelines in HCAs, AND * At least every 7 years, integrate data obtained with applicable internal corrosion leak records, incident reports, safety related condition reports, repair records, patrol records, exposed pipe reports, and test records. |
3rd Party Damage | 103 - (Gen. Design) 111 - (Design factor) 317 - (Hazard prot) 327 (cover) 614 - (Dam. Prevent) 616 - (Public educat) 705 - (Patrol) 707 - (Line markers) 711 - (repair - gen.) 717 - (Repair-perm.) | 615 - (Emerg Plan) | * Participation in state one-call system, * Use of qualified operator employees and contractors to perform makring and locating of buried structures and in direct supervison of excavation work, AND * Either monitoring of excavations near operator's transmission pipelines, or bi-monthly patrol of transmission pipelines in HCAs or class 3 or 4 locations. Any indications of unreported construction activity would require a follow up investigation to determine if mechanical damage occurred. |
As used in this part:
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Ambient vaporizer means a vaporizer which derives heat from naturally occurring heat sources, such as the atmosphere, sea water, surface waters, or geothermal waters.
Cargo transfer system means a component, or system of components functioning as a unit, used exclusively for transferring hazardous fluids in bulk between a tank car, tank truck, or marine vessel and a storage tank.
Component means any part, or system of parts functioning as a unit, including, but not limited to, piping, processing equipment, containers, control devices, impounding systems, lighting, security devices, fire control equipment, and communication equipment, whose integrity or reliability is necessary to maintain safety in controlling, processing, or containing a hazardous fluid.
Container means a component other than piping that contains a hazardous fluid.
Control system means a component, or system of components functioning as a unit, including control valves and sensing, warning, relief, shutdown, and other control devices, which is activated either manually or automatically to establish or maintain the performance of another component.
Controllable emergency means an emergency where reasonable and prudent action can prevent harm to people or property.
Design pressure means the pressure used in the design of components for the purpose of determining the minimum permissible thickness or physical characteristics of its various parts. When applicable, static head shall be included in the design pressure to determine the thickness of any specific part.
Determine means make an appropriate investigation using scientific methods, reach a decision based on sound engineering judgment, and be able to demonstrate the basis of the decision.
Dike means the perimeter of an impounding space forming a barrier to prevent liquid from flowing in an unintended direction.
Emergency means a deviation from normal operation, a structural failure, or severe environmental conditions that probably would cause harm to people or property.
Exclusion zone means an area surrounding an LNG facility in which an operator or government agency legally controls all activities in accordance with § 193.2057 and § 193.2059 for as long as the facility is in operation.
Fail-safe means a design feature which will maintain or result in a safe condition in the event of malfunction or failure of a power supply, component, or control device.
g means the standard acceleration of gravity of 9.806 meters per second2 (32.17 feet per second2).
Gas, except when designated as inert, means natural gas, other flammable gas, or gas which is toxic or corrosive.
Hazardous fluid means gas or hazardous liquid.
Hazardous liquid means LNG or a liquid that is flammable or toxic.
Heated vaporizer means a vaporizer which derives heat from other than naturally occurring heat sources.
Impounding space means a volume of space formed by dikes and floors which is designed to confine a spill of hazardous liquid.
Impounding system includes an impounding space, including dikes and floors for conducting the flow of spilled hazardous liquids to an impounding space.
Liquefied natural gas or LNG means natural gas or synthetic gas having methane (CH4) as its major constituent which has been changed to a liquid.
LNG facility means a pipeline facility that is used for liquefying natural gas or synthetic gas or transferring, storing, or vaporizing liquefied natural gas.
LNG plant means an LNG facility or system of LNG facilities functioning as a unit.
m3 means a volumetric unit which is one cubic meter, 6.2898 barrels, 35.3147 ft.3, or 264.1720 U.S. gallons, each volume being considered as equal to the other.
Maximum allowable working pressure means the maximum gage pressure permissible at the top of the equipment, containers or pressure vessels while operating at design temperature.
Normal operation means functioning within ranges of pressure, temperature, flow, or other operating criteria required by this part.
Operator means a person who owns or operates an LNG facility.
Person means any individual, firm, joint venture, partnership, corporation, association, state, municipality, cooperative association, or joint stock association and includes any trustee, receiver, assignee, or personal representative thereof.
Pipeline facility means new and existing piping, rights-of-way, and any equipment, facility, or building used in the transportation of gas or in the treatment of gas during the course of transportation.
Piping means pipe, tubing, hoses, fittings, valves, pumps, connections, safety devices or related components for containing the flow of hazardous fluids.
Storage tank means a container for storing a hazardous fluid.
Transfer piping means a system of permanent and temporary piping used for transferring hazardous fluids between any of the following: Liquefaction process facilities, storage tanks, vaporizers, compressors, cargo transfer systems, and facilities other than pipeline facilities.
Transfer system includes transfer piping and cargo transfer system.
Vaporization means an addition of thermal energy changing a liquid to a vapor or gaseous state.
Vaporizer means a heat transfer facility designed to introduce thermal energy in a controlled manner for changing a liquid to a vapor or gaseous state.
Waterfront LNG plant means an LNG plant with docks, wharves, piers, or other structures in, on, or immediately adjacent to the navigable waters of the United States or Puerto Rico and any shore area immediately adjacent to those waters to which vessels may be secured and at which LNG cargo operations may be conducted.
Incidents, safety-related conditions, and annual pipeline summary data for LNG plants or facilities must be reported in accordance with the requirements of Part 191 of this subchapter.
Each LNG facility designed, constructed, replaced, relocated or significantly altered after March 31, 2000 must be provided with siting requirements in accordance with the requirements of this part and of NFPA-59A-2001 (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA-59A-2001, this part prevails.
Each LNG container and LNG transfer system must have a thermal exclusion zone in accordance with section 2.2.3.2 of NFPA-59A-2001 (incorporated by reference, see § 193.2013) with the following exceptions:
Each LNG container and LNG transfer system must have a dispersion exclusion zone in accordance with sections 2.2.3.3 and 2.2.3.4 of NFPA-59A-2001 (incorporated by reference, see § 193.2013) with the following exceptions:
Materials
Each operator shall keep a record of all materials for components, buildings, foundations, and support systems, as necessary to verify that material properties meet the requirements of this part. These records must be maintained for the life of the item concerned.
Design of Components and Buildings
Impoundment Design and Capacity
An outer wall of a component served by an impounding system may not be used as a dike unless the outer wall is constructed of concrete.
A covered impounding system is prohibited except for concrete wall designed tanks where the concrete wall is an outer wall serving as a dike.
Each impounding system serving an LNG storage tank must have a minimum volumetric liquid impoundment capacity of:
LNG Storage Tanks
A flammable nonmetallic membrane liner may not be used as an inner container in a storage tank.
Each LNG facility constructed after March 31, 2000 must comply with requirements of this part and of NFPA-59A-2001 (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA-59A-2001, this part prevails.
No person may place in service any component until it passes all applicable inspections and tests prescribed by this subpart and NFPA-59A-2001 (incorporated by reference, see § 193.2013).
After March 31, 2000, each new, replaced, relocated or significantly altered vaporization equipment, liquefaction equipment, and control systems must be designed, fabricated, and installed in accordance with requirements of this part and of NFPA-59A-2001 (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA-59A-2001, this part prevails.
VAPORIZATION EQUIPMENT
Each LNG plant must have a control center from which operations and warning devices are monitored as required by this part. A control center must have the following capabilities and characteristics:
This subpart prescribes requirements for the operation of LNG facilities
Each operator shall follow one or more manuals of written procedures to provide safety in normal operation and in responding to an abnormal operation that would affect safety. The procedures must include provisions for:
Each component in operation or building in which a hazard to persons or property could exist must be monitored to detect fire or any malfunction or flammable fluid that could cause a hazardous condition. Monitoring must be accomplished by watching or listening from an attended control center for warning alarms, such as gas, temperature, pressure, vacuum, and flow alarms, or by conducting an inspection or test at intervals specified in the operating procedures.
The procedures must provide for the following:
When necessary for safety, components that could accumulate significant amounts of combustible mixtures must be purged in accordance with a procedure which meets the provisions of the Purging Principles and Practices (incorporated by reference, see § 193.2013) after being taken out of service and before being returned to service.
Each operator shall maintain a record of results of each inspection, test and investigation required by this subpart. For each LNG facility that is designed and constructed after March 31, 2000 the operator shall also maintain related inspection, testing, and investigation records that NFPA-59A-2001 (incorporated by reference, see § 193.2013) requires. Such records, whether required by this part or NFPA-59A-2001, must be kept for a period of not less than five years.
This subpart prescribes requirements for maintaining components at LNG plants.
Each support system or foundation of each component must be inspected for any detrimental change that could impair support.
Each auxiliary power source must be tested monthly to check its operational capability and tested annually for capacity. The capacity test must take into account the power needed to start up and simultaneously operate equipment that would have to be served by that power source in an emergency.
Hoses used in LNG or flammable refrigerant transfer systems must be:
Each LNG storage tank must be inspected or tested to verify that each of the following conditions does not impair the structural integrity or safety of the tank:
Each exposed component that is subject to atmospheric corrosive attack must be protected from atmospheric corrosion by:
Each component that is subject to internal corrosive attack must be protected from internal corrosion by:
Corrosion protection provided as required by this subpart must be periodically monitored to give early recognition of ineffective corrosion protection, including the following, as applicable:
Prompt corrective or remedial action must be taken whenever an operator learns by inspection or otherwise that atmospheric, external, or internal corrosion is not controlled as required by this subpart.
This subpart prescribes requirements for personnel qualifications and training.
For the design and fabrication of components, each operator shall use-
Personnel having security duties must be qualified to perform their assigned duties by successful completion of the training required under § 193.2715.
Each operator shall follow a written plan to verify that personnel assigned operating, maintenance, security, or fire protection duties at the LNG plant do not have any physical condition that would impair performance of their assigned duties. The plan must be designed to detect both readily observable disorders, such as physical handicaps or injury, and conditions requiring professional examination for discovery.
Each operator must provide and maintain fire protection at LNG plants according to sections 9.1 through 9.7 and section 9.9 of NFPA-59A-2001 (incorporated by reference, see § 193.2013). However, LNG plants existing on March 31, 2000, need not comply with provisions on emergency shutdown systems, water delivery systems, detection systems, and personnel qualification and training until September 12, 2005.
This subpart prescribes requirements for security at LNG plants. However, the requirements do not apply to existing LNG plants that do not contain LNG.
Each operator shall prepare and follow one or more manuals of written procedures to provide security for each LNG plant. The procedures must be available at the plant in accordance with § 193.2017 and include at least:
The protective enclosure may be one or more separate enclosures surrounding a single facility or multiple facilities.
A means must be provided for:
Where security warning systems are not provided for security monitoring under § 193.2913, the area around the facilities listed under § 193.2905(a) and each protective enclosure must be illuminated with a minimum in service lighting intensity of not less than 2.2 lux (0.2 ftc) between sunset and sunrise.
Each protective enclosure and the area around each facility listed in § 193.2905(a) must be monitored for the presence of unauthorized persons. Monitoring must be by visual observation in accordance with the schedule in the security procedures under § 193.2903(a) or by security warning systems that continuously transmit data to an attended location. At an LNG plant with less than 40,000 m3 (250,000 bbl) of storage capacity, only the protective enclosure must be monitored.
An alternative source of power that meets the requirements of § 193.2445 must be provided for security lighting and security monitoring and warning systems required under §§ 193.2911 and 193.2913.
As used in this part-
Accident means an incident reportable under Part 191 involving gas pipeline facilities or LNG facilities.
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Covered employee, employee, or individual to be tested means a person who performs a covered function, including persons employed by operators, contractors engaged by operators, and persons employed by such contractors.
Covered function means an operations, maintenance, or emergency-response function regulated by part 192, 193, or 195 of this chapter that is performed on a pipeline or on an LNG facility.
DOT Procedures means the Procedures for Transportation Workplace Drug and Alcohol Testing Programs published by the Office of the Secretary of Transportation in part 40 of this title.
Fail a drug test means that the confirmation test result shows positive evidence of the presence under DOT Procedures of a prohibited drug in an employee's system.
Operator means a person who owns or operates pipeline facilities subject to Part 192 or Part 193 of this Code.
Pass a drug test means that initial testing or confirmation testing under DOT Procedures does not show evidence of the presence of a prohibited drug in a person's system.
Performs a covered function includes actually performing, ready to perform, or immediately available to perform a covered function.
Positive rate for random drug testing means the number of verified positive results for random drug tests conducted under this part plus the number of refusals of random drug tests required by this part, divided by the total number of random drug tests results (i.e., positives, negatives, and refusals) under this part.
Prohibited drug means any of the following substances specified in Schedule I or Schedule II of the Controlled Substances Act (21 U.S.C. 812) : marijuana, cocaine, opiates, amphetamines, and phencyclidine (PCP).
Refuse to submit, refuse, or refuse to take means behavior consistent with DOT Procedures concerning refusal to take a drug test or refusal to take an alcohol test.
State agency means an agency of any of the several states, the District of Columbia, or Puerto Rico that participates under the pipeline safety laws (49 U.S.C. 60101et seq.).
The anti-drug and alcohol programs required by this part must be conducted according to the requirements of this part and DOT Procedures. Terms and concepts used in this part have the same meaning as in DOT Procedures. Violations of DOT Procedures with respect to anti-drug and alcohol programs required by this part are violations of this part.
The purpose of this subpart is to establish programs designed to help prevent accidents and injuries resulting from the use of prohibited drugs by employees who perform covered functions for operators of certain pipeline facilities subject to part 192, 193, or 195 of this chapter.
Each operator shall conduct the following drug tests for the presence of a prohibited drug:
With respect to those employees who are contractors or employed by a contractor, an operator may provide by contract that the drug testing, education, and training required by this subpart be carried out by the contractor provided:
The purpose of this subpart is to establish programs designed to help prevent accidents and injuries resulting from the misuse of alcohol by employees who perform covered functions for operators of certain pipeline facilities subject to part 192 of this code.
Each operator must maintain and follow a written alcohol misuse plan that conforms to the requirements of this part and DOT Procedures concerning alcohol testing programs. The plan shall contain methods and procedures for compliance with all the requirements of this subpart, including required testing, record keeping, reporting, education and training elements.
Before performing an alcohol test under this subpart, each operator shall notify a covered employee that the alcohol test is required by this subpart. No operator shall falsely represent that a test is administered under this subpart.
Each operator shall prohibit a covered employee from reporting for duty or remaining on duty requiring the performance of covered functions while having an alcohol concentration of 0.04 or greater. No operator having actual knowledge that a covered employee has an alcohol concentration of 0.04 or greater shall permit the employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee from using alcohol while performing covered functions. No operator having actual knowledge that a covered employee is using alcohol while performing covered functions shall permit the employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee from using alcohol within four hours prior to performing covered functions, or, if an employee is called to duty to respond to an emergency, within the time period after the employee has been notified to report for duty. No operator having actual knowledge that a covered employee has used alcohol within four hours prior to performing covered functions or within the time period after the employee has been notified to report for duty shall permit that covered employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee who has actual knowledge of an accident in which his or her performance of covered functions has not been discounted by the operator as a contributing factor to the accident from using alcohol for eight hours following the accident, unless he or she has been given a post-accident test under § 199.225(a), or the operator has determined that the employee's performance could not have contributed to the accident.
Each operator shall require a covered employee to submit to a post-accident alcohol test required under § 199.225(a), a reasonable suspicion alcohol test required under § 199.225(b), or a follow-up alcohol test required under § 199.225(d). No operator shall permit an employee who refuses to submit to such a test to perform or continue to perform covered functions.
Each operator shall conduct the following types of alcohol tests for the presence of alcohol:
Except as provided in §§ 199.239 through 199.243, no operator shall permit any covered employee to perform covered functions if the employee has engaged in conduct prohibited by §§ 199.215 through 199.223 or an alcohol misuse rule of another DOT agency.
No operator shall permit a covered employee who has engaged in conduct prohibited by §§ 199.215 through 199.223 to perform covered functions unless the employee has met the requirements of § 199.243.
Each operator shall ensure that persons designated to determine whether reasonable suspicion exists to require a covered employee to undergo alcohol testing under § 199.225(b) receive at least 60 minutes of training on the physical, behavioral, speech, and performance indicators of probable alcohol misuse.
126.05.21 Ark. Code R. 001