Arkansas Administrative Code
Agency 126 - PUBLIC SERVICE COMMISSION
Division 01 - Pipeline Safety Section
Rule 126.01.14-001 - Arkansas Gas Pipeline Code: Revised 9-25-2014

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 - 23-15-216). 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:

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 for violations of the Arkansas Gas Pipeline Code not to 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.

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.

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 Arkansas Public Service Commission or any person 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:

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 from a public or municipal utility meter to consumers who may or may not be metered; and the gas is not consumed solely by the owner/operator.

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'.

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.

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:

System means all pipeline facilities used by a particular operator in the transportation of gas, including, but not limited to line pipe, valves and other appurtenances connected to line pipe, compressor units, fabricated assemblies associated with compressor units, metering (including customers' meters) and delivery stations, and fabricated assemblies in metering and delivery stations.

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.

Each operator shall file with Pipeline Safety, Public Service Commission, a plan for operation, inspection and maintenance of each pipeline facility which he owns or operates. In addition, each change to this plan must be filed with Pipeline Safety 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.

Materials for pipe and components must be:

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.

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:

The longitudinal joint factor to be used in the design formula in § 192.105 is determined in accordance with the following table:

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:

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:

Click here to view image

Click here to view image

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).

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 overpressuring.

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.

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.

Copper pipe may not be threaded, except that copper pipe used for joining screw fittings or valves may be threaded if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe listed in Table C1 of ASME/ANSI B16.5.

No person may carry out the inspection of joints in plastic pipes required by §§ 192.273(c) and 192.285(b) unless that person has been qualified by appropriate training or experience in evaluating the acceptability of plastic pipe joints made under the applicable joining procedure.

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 part.

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.

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:

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:

This subpart prescribes minimum requirements for installing customer meters, service regulators, service lines, service line valves, and service line connections to mains.

Each steel service line to be operated at less than 100 p.s.i. (689 kPa) gage must be constructed of pipe designed for a minimum of 100 p.s.i. (689 kPa) gage.

Each copper service line installed within a building must be protected against external damage.

Each service line that is not placed in service upon completion of installation must comply with one of the following until the customer is supplied with gas:

This subpart prescribes minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion.

The corrosion control procedures required by § 192.605(b)(2), including those for design, installation, operation and maintenance of cathodic protection systems, must be carried out by, or under the direction of, a person qualified by experience and training in pipeline corrosion control methods.

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.

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.

This subpart prescribes minimum leak-test and strength-test requirements for pipelines.

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.

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:

Each operator shall establish procedures for analyzing accidents and failures, including the selection of samples of the failed facility or equipment for laboratory examination, where appropriate, for the purpose of determining the causes of the failure and minimizing the possibility of a recurrence.

Each tap made on a pipeline under pressure must be performed by a crew qualified to make hot taps.

This subpart prescribes minimum requirements for maintenance of pipeline facilities.

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-

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:

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:

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.

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.

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:

General. This subpart prescribes minimum requirements for an IM program for any gas distribution pipeline covered under this part, including liquefied petroleum gas systems. A gas distribution operator, other than a master meter operator or a small LPG operator, must follow the requirements in §§ 192.1005-192.1013 of this subpart. A master meter operator or small LPG operator of a gas distribution pipeline must follow the requirements in § 192.1015 of this subpart.

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.

API 5L-Steel Pipe, "API 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-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-Steel pipe, "Standard Specification for Electric-Fusion- Welded Pipe for Atmospheric and Lower Temperatures" (incorporated by reference, see § 192.7).

ASTM A672-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-Steel pipe "Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High Pressure Service at High Temperatures" (incorporated by reference, see § 192.7).

ASTM D2513-99-Thermoplastic pipe and tubing, "Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings" (incorporated by reference, see § 192.7).

ASTM D2517-Thermosetting plastic pipe and tubing, "Standard Specification Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (incorporated by reference, see § 192.7).

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:

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.

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.

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:

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 High Consequence Area

Click here to view image

Figure E.I.A

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.

m 3means 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 (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA 59A, 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 (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 (incorporated by reference, see § 193.2013) with the following exceptions:

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.

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 (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA 59A, 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 (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 (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA 59A, 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.

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 AGA "Purging Principles and Practice" 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 (incorporated by reference, see § 193.2013) requires. Such records, whether required by this part or NFPA 59A, must be kept for a period of not less than five years.

This subpart prescribes requirements for maintaining components at LNG plants.