49 C.F.R. Subpart L—Operations
Title 49 - Transportation
This subpart prescribes minimum requirements for the operation of pipeline facilities. (a) No person may operate a segment of pipeline unless it is operated in accordance with this subpart. (b) Each operator shall keep records necessary to administer the procedures established under §192.605. (c) The Administrator or the State Agency that has submitted a current certification under the pipeline safety laws, (49 U.S.C. 60101 et seq.) with respect to the pipeline facility governed by an operator's plans and procedures may, after notice and opportunity for hearing as provided in 49 CFR 190.237 or the relevant State procedures, require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety. [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–66, 56 FR 31090, July 9, 1991; Amdt. 192–71, 59 FR 6584, Feb. 11, 1994; Amdt. 192–75, 61 FR 18517, Apr. 26, 1996] (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. (b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. (1) Operating, maintaining, and repairing the pipeline in accordance with each of the requirements of this subpart and subpart M of this part. (2) Controlling corrosion in accordance with the operations and maintenance requirements of subpart I of this part. (3) Making construction records, maps, and operating history available to appropriate operating personnel. (4) Gathering of data needed for reporting incidents under Part 191 of this chapter in a timely and effective manner. (5) Starting up and shutting down any part of the pipeline in a manner designed to assure operation within the MAOP limits prescribed by this part, plus the build-up allowed for operation of pressure-limiting and control devices. (6) Maintaining compressor stations, including provisions for isolating units or sections of pipe and for purging before returning to service. (7) Starting, operating and shutting down gas compressor units. (8) Periodically reviewing the work done by operator personnel to determine the effectiveness, and adequacy of the procedures used in normal operation and maintenance and modifying the procedures when deficiencies are found. (9) Taking adequate precautions in excavated trenches to protect personnel from the hazards of unsafe accumulations of vapor or gas, and making available when needed at the excavation, emergency rescue equipment, including a breathing apparatus and, a rescue harness and line. (10) Systematic and routine testing and inspection of pipe-type or bottle-type holders including— (i) Provision for detecting external corrosion before the strength of the container has been impaired; (ii) Periodic sampling and testing of gas in storage to determine the dew point of vapors contained in the stored gas which, if condensed, might cause internal corrosion or interfere with the safe operation of the storage plant; and (iii) Periodic inspection and testing of pressure limiting equipment to determine that it is in safe operating condition and has adequate capacity. (11) Responding promptly to a report of a gas odor inside or near a building, unless the operator's emergency procedures under §192.615(a)(3) specifically apply to these reports. (c) Abnormal operation. For transmission lines, the manual required by paragraph (a) of this section must include procedures for the following to provide safety when operating design limits have been exceeded: (1) Responding to, investigating, and correcting the cause of: (i) Unintended closure of valves or shutdowns; (ii) Increase or decrease in pressure or flow rate outside normal operating limits; (iii) Loss of communications; (iv) Operation of any safety device; and (v) Any other foreseeable malfunction of a component, deviation from normal operation, or personnel error, which may result in a hazard to persons or property. (2) Checking variations from normal operation after abnormal operation has ended at sufficient critical locations in the system to determine continued integrity and safe operation. (3) Notifying responsible operator personnel when notice of an abnormal operation is received. (4) Periodically reviewing the response of operator personnel to determine the effectiveness of the procedures controlling abnormal operation and taking corrective action where deficiencies are found. (5) The requirements of this paragraph (c) do not apply to natural gas distribution operators that are operating transmission lines in connection with their distribution system. (d) Safety-related condition reports. The manual required by paragraph (a) of this section must include instructions enabling personnel who perform operation and maintenance activities to recognize conditions that potentially may be safety-related conditions that are subject to the reporting requirements of §191.23 of this subchapter. (e) Surveillance, emergency response, and accident investigation. The procedures required by §§192.613(a), 192.615, and 192.617 must be included in the manual required by paragraph (a) of this section. [Amdt. 192–71, 59 FR 6584, Feb. 11, 1994, as amended by Amdt. 192–71A, 60 FR 14381, Mar. 17, 1995; Amdt. 192–93, 68 FR 53901, Sept. 15, 2003]
Title 49: Transportation
PART 192—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS
Subpart L—Operations
§ 192.601 Scope.
§ 192.603 General provisions.
§ 192.605 Procedural manual for operations, maintenance, and emergencies.
§ 192.607 [Reserved]
§ 192.609 Change in class location: Required study.
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:
(a) The present class location for the segment involved.
(b) The design, construction, and testing procedures followed in the original construction, and a comparison of these procedures with those required for the present class location by the applicable provisions of this part.
(c) The physical condition of the segment to the extent it can be ascertained from available records;
(d) The operating and maintenance history of the segment;
(e) The maximum actual operating pressure and the corresponding operating hoop stress, taking pressure gradient into account, for the segment of pipeline involved; and
(f) The actual area affected by the population density increase, and physical barriers or other factors which may limit further expansion of the more densely populated area.
§ 192.611 Change in class location: Confirmation or revision of maximum allowable operating pressure.
(a) If the hoop stress corresponding to the established maximum allowable operating pressure of a segment of pipeline is not commensurate with the present class location, and the segment is in satisfactory physical condition, the maximum allowable operating pressure of that segment of pipeline must be confirmed or revised according to one of the following requirements:
(1) If the segment involved has been previously tested in place for a period of not less than 8 hours, the maximum allowable operating pressure is 0.8 times the test pressure in Class 2 locations, 0.667 times the test pressure in Class 3 locations, or 0.555 times the test pressure in Class 4 locations. The corresponding hoop stress may not exceed 72 percent of the SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or 50 percent of SMYS in Class 4 locations.
(2) The maximum allowable operating pressure of the segment involved must be reduced so that the corresponding hoop stress is not more than that allowed by this part for new segments of pipelines in the existing class location.
(3) The segment involved must be tested in accordance with the applicable requirements of subpart J of this part, and its maximum allowable operating pressure must then be established according to the following criteria:
(i) The maximum allowable operating pressure after the requalification test is 0.8 times the test pressure for Class 2 locations, 0.667 times the test pressure for Class 3 locations, and 0.555 times the test pressure for Class 4 locations.
(ii) The corresponding hoop stress may not exceed 72 percent of the SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or 50 percent of SMYS in Class 4 locations.
(b) The maximum allowable operating pressure confirmed or revised in accordance with this section, may not exceed the maximum allowable operating pressure established before the confirmation or revision.
(c) Confirmation or revision of the maximum allowable operating pressure of a segment of pipeline in accordance with this section does not preclude the application of §§192.553 and 192.555.
(d) Confirmation or revision of the maximum allowable operating pressure that is required as a result of a study under §192.609 must be completed within 24 months of the change in class location. Pressure reduction under paragraph (a) (1) or (2) of this section within the 24-month period does not preclude establishing a maximum allowable operating pressure under paragraph (a)(3) of this section at a later date.
[Amdt. 192–63A, 54 FR 24174, June 6, 1989 as amended by Amdt. 192–78, 61 FR 28785, June 6, 1996; Amdt. 192–94, 69 FR 32895, June 14, 2004]
§ 192.612 Underwater inspection and reburial of pipelines in the Gulf of Mexico and its inlets.
(a) Each operator shall prepare and follow a procedure to identify its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water that are at risk of being an exposed underwater pipeline or a hazard to navigation. The procedures must be in effect August 10, 2005.
(b) Each operator shall conduct appropriate periodic underwater inspections of its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water based on the identified risk.
(c) If an operator discovers that its pipeline is an exposed underwater pipeline or poses a hazard to navigation, the operator shall—
(1) Promptly, but not later than 24 hours after discovery, notify the National Response Center, telephone: 1–800–424–8802, of the location and, if available, the geographic coordinates of that pipeline.
(2) Promptly, but not later than 7 days after discovery, mark the location of the pipeline in accordance with 33 CFR part 64 at the ends of the pipeline segment and at intervals of not over 500 yards (457 meters) long, except that a pipeline segment less than 200 yards (183 meters) long need only be marked at the center; and
(3) Within 6 months after discovery, or not later than November 1 of the following year if the 6 month period is later than November 1 of the year of discovery, bury the pipeline so that the top of the pipe is 36 inches (914 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) for normal excavation or 18 inches (457 millimeters) for rock excavation.
(i) An operator may employ engineered alternatives to burial that meet or exceed the level of protection provided by burial.
(ii) If an operator cannot obtain required state or Federal permits in time to comply with this section, it must notify OPS; specify whether the required permit is State or Federal; and, justify the delay.
[Amdt. 192–98, 69 FR 48406, Aug. 10, 2004]
§ 192.613 Continuing surveillance.
(a) Each operator shall have a procedure for continuing surveillance of its facilities to determine and take appropriate action concerning changes in class location, failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and other unusual operating and maintenance conditions.
(b) If a segment of pipeline is determined to be in unsatisfactory condition but no immediate hazard exists, the operator shall initiate a program to recondition or phase out the segment involved, or, if the segment cannot be reconditioned or phased out, reduce the maximum allowable operating pressure in accordance with §192.619 (a) and (b).
§ 192.614 Damage prevention program.
(a) Except as provided in paragraphs (d) and (e) of this section, each operator of a buried pipeline must carry out, in accordance with this section, a written program to prevent damage to that pipeline from excavation activities. For the purposes of this section, the term “excavation activities” includes excavation, blasting, boring, tunneling, backfilling, the removal of aboveground structures by either explosive or mechanical means, and other earthmoving operations.
(b) An operator may comply with any of the requirements of paragraph (c) of this section through participation in a public service program, such as a one-call system, but such participation does not relieve the operator of responsibility for compliance with this section. However, an operator must perform the duties of paragraph (c)(3) of this section through participation in a one-call system, if that one-call system is a qualified one-call system. In areas that are covered by more than one qualified one-call system, an operator need only join one of the qualified one-call systems if there is a central telephone number for excavators to call for excavation activities, or if the one-call systems in those areas communicate with one another. An operator's pipeline system must be covered by a qualified one-call system where there is one in place. For the purpose of this section, a one-call system is considered a “qualified one-call system” if it meets the requirements of section (b)(1) or (b)(2) of this section.
(1) The state has adopted a one-call damage prevention program under §198.37 of this chapter; or
(2) The one-call system:
(i) Is operated in accordance with §198.39 of this chapter;
(ii) Provides a pipeline operator an opportunity similar to a voluntary participant to have a part in management responsibilities; and
(iii) Assesses a participating pipeline operator a fee that is proportionate to the costs of the one-call system's coverage of the operator's pipeline.
(c) The damage prevention program required by paragraph (a) of this section must, at a minimum:
(1) Include the identity, on a current basis, of persons who normally engage in excavation activities in the area in which the pipeline is located.
(2) Provides for notification of the public in the vicinity of the pipeline and actual notification of the persons identified in paragraph (c)(1) of this section of the following as often as needed to make them aware of the damage prevention program:
(i) The program's existence and purpose; and
(ii) How to learn the location of underground pipelines before excavation activities are begun.
(3) Provide a means of receiving and recording notification of planned excavation activities.
(4) If the operator has buried pipelines in the area of excavation activity, provide for actual notification of persons who give notice of their intent to excavate of the type of temporary marking to be provided and how to identify the markings.
(5) Provide for temporary marking of buried pipelines in the area of excavation activity before, as far as practical, the activity begins.
(6) Provide as follows for inspection of pipelines that an operator has reason to believe could be damaged by excavation activities:
(i) The inspection must be done as frequently as necessary during and after the activities to verify the integrity of the pipeline; and
(ii) In the case of blasting, any inspection must include leakage surveys.
(d) A damage prevention program under this section is not required for the following pipelines:
(1) Pipelines located offshore.
(2) Pipelines, other than those located offshore, in Class 1 or 2 locations until September 20, 1995.
(3) Pipelines to which access is physically controlled by the operator.
(e) Pipelines operated by persons other than municipalities (including operators of master meters) whose primary activity does not include the transportation of gas need not comply with the following:
(1) The requirement of paragraph (a) of this section that the damage prevention program be written; and
(2) The requirements of paragraphs (c)(1) and (c)(2) of this section.
[Amdt. 192–40, 47 FR 13824, Apr. 1, 1982, as amended by Amdt. 192–57, 52 FR 32800, Aug. 31, 1987; Amdt. 192–73, 60 FR 14650, Mar. 20, 1995; Amdt. 192–78, 61 FR 28785, June 6, 1996; Amdt.192–82, 62 FR 61699, Nov. 19, 1997; Amdt. 192–84, 63 FR 38758, July 20, 1998]
§ 192.615 Emergency plans.
(a) Each operator shall establish written procedures to minimize the hazard resulting from a gas pipeline emergency. At a minimum, the procedures must provide for the following:
(1) Receiving, identifying, and classifying notices of events which require immediate response by the operator.
(2) Establishing and maintaining adequate means of communication with appropriate fire, police, and other public officials.
(3) Prompt and effective response to a notice of each type of emergency, including the following:
(i) Gas detected inside or near a building.
(ii) Fire located near or directly involving a pipeline facility.
(iii) Explosion occurring near or directly involving a pipeline facility.
(iv) Natural disaster.
(4) The availability of personnel, equipment, tools, and materials, as needed at the scene of an emergency.
(5) Actions directed toward protecting people first and then property.
(6) Emergency shutdown and pressure reduction in any section of the operator's pipeline system necessary to minimize hazards to life or property.
(7) Making safe any actual or potential hazard to life or property.
(8) Notifying appropriate fire, police, and other public officials of gas pipeline emergencies and coordinating with them both planned responses and actual responses during an emergency.
(9) Safely restoring any service outage.
(10) Beginning action under §192.617, if applicable, as soon after the end of the emergency as possible.
(b) Each operator shall:
(1) Furnish its supervisors who are responsible for emergency action a copy of that portion of the latest edition of the emergency procedures established under paragraph (a) of this section as necessary for compliance with those procedures.
(2) Train the appropriate operating personnel to assure that they are knowledgeable of the emergency procedures and verify that the training is effective.
(3) Review employee activities to determine whether the procedures were effectively followed in each emergency.
(c) Each operator shall establish and maintain liaison with appropriate fire, police, and other public officials to:
(1) Learn the responsibility and resources of each government organization that may respond to a gas pipeline emergency;
(2) Acquaint the officials with the operator's ability in responding to a gas pipeline emergency;
(3) Identify the types of gas pipeline emergencies of which the operator notifies the officials; and
(4) Plan how the operator and officials can engage in mutual assistance to minimize hazards to life or property.
[Amdt. 192–24, 41 FR 13587, Mar. 31, 1976, as amended by Amdt. 192–71, 59 FR 6585, Feb. 11, 1994]
§ 192.616 Public awareness.
(a) Each pipeline operator must develop and implement a written continuing public education program that follows the guidance provided in the American Petroleum Institute's (API) Recommended Practice (RP) 1162 (IBR, see §192.7).
(b) The operator's program must follow the general program recommendations of API RP 1162 and assess the unique attributes and characteristics of the operator's pipeline and facilities.
(c) The operator must follow the general program recommendations, including baseline and supplemental requirements of API RP 1162, unless the operator provides justification in its program or procedural manual as to why compliance with all or certain provisions of the recommended practice is not practicable and not necessary for safety.
(d) The operator's program must specifically include provisions to educate the public, appropriate government organizations, and persons engaged in excavation related activities on:
(1) Use of a one-call notification system prior to excavation and other damage prevention activities;
(2) Possible hazards associated with unintended releases from a gas pipeline facility;
(3) Physical indications that such a release may have occurred;
(4) Steps that should be taken for public safety in the event of a gas pipeline release; and
(5) Procedures for reporting such an event.
(e) The program must include activities to advise affected municipalities, school districts, businesses, and residents of pipeline facility locations.
(f) The program and the media used must be as comprehensive as necessary to reach all areas in which the operator transports gas.
(g) The program must be conducted in English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator's area.
(h) Operators in existence on June 20, 2005, must have completed their written programs no later than June 20, 2006. As an exception, operators of small propane distribution systems having less than 25 customers and master meter operators having less than 25 customers must have completed development and documentation of their programs no later than June 20, 2007. Upon request, operators must submit their completed programs to PHMSA or, in the case of an intrastate pipeline facility operator, the appropriate State agency.
(i) The operator's program documentation and evaluation results must be available for periodic review by appropriate regulatory agencies.
[Amdt. 192–100, 70 FR 28842, May 19, 2005; 70 FR 35041, June 16, 2005]
§ 192.617 Investigation of failures.
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.
§ 192.619 Maximum allowable operating pressure: Steel or plastic pipelines.
(a) Except as provided in paragraph (c) of this section, no person may operate a segment of steel or plastic pipeline at a pressure that exceeds the lowest of the following:
(1) The design pressure of the weakest element in the segment, determined in accordance with subparts C and D of this part. However, for steel pipe in pipelines being converted under §192.14 or uprated under subpart K of this part, if any variable necessary to determine the design pressure under the design formula (§192.105) is unknown, one of the following pressures is to be used as design pressure:
(i) Eighty percent of the first test pressure that produces yield under section N5 of Appendix N of ASME B31.8 (incorporated by reference, see §192.7), reduced by the appropriate factor in paragraph (a)(2)(ii) of this section; or
(ii) If the pipe is 12
(2) The pressure obtained by dividing the pressure to which the segment was tested after construction as follows:
(i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5.
(ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, the test pressure is divided by a factor determined in accordance with the following table:
------------------------------------------------------------------------ Factors \1\, segment_ ----------------------------------- Installed Installed Converted Class location before after under (Nov. 12, (Nov. 11, § 1970) 1970) 192.14------------------------------------------------------------------------1................................... 1.1 1.1 1.252................................... 1.25 1.25 1.253................................... 1.4 1.5 1.54................................... 1.4 1.5 1.5------------------------------------------------------------------------\1\ For offshore segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe riser, the factor is 1.5.
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(3) The highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column. This pressure restriction applies unless the segment was tested according to the requirements in paragraph (a)(2) of this section after the applicable date in the third column or the segment was uprated according to the requirements in subpart K of this part: |
------------------------------------------------------------------------ Pipeline segment Pressure date Test date------------------------------------------------------------------------_Onshore gathering line that March 15, 2006, or 5 years preceding first became subject to this date line becomes applicable date part (other than § subject to this in second column. 192.612) after April 13, 2006. part, whichever is later._Onshore transmission line that was a gathering line not subject to this part before March 15, 2006.Offshore gathering lines........ July 1, 1976...... July 1, 1971.All other pipelines............. July 1, 1970...... July 1, 1965.------------------------------------------------------------------------
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(4) The pressure determined by the operator to be the maximum safe pressure after considering the history of the segment, particularly known corrosion and the actual operating pressure. (b) No person may operate a segment to which paragraph (a)(4) of this section is applicable, unless over-pressure protective devices are installed on the segment in a manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with §192.195. (c) The requirements on pressure restrictions in this section do not apply in the following instance. An operator may operate a segment of pipeline found to be in satisfactory condition, considering its operating and maintenance history, at the highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column of the table in paragraph (a)(3) of this section. An operator must still comply with §192.611. [35 FR 13257, Aug. 19, 1970] Editorial Note: For § 192.621 Maximum allowable operating pressure: High-pressure distribution systems.(a) No person may operate a segment of a high pressure distribution system at a pressure that exceeds the lowest of the following pressures, as applicable: (1) The design pressure of the weakest element in the segment, determined in accordance with subparts C and D of this part. (2) 60 p.s.i. (414 kPa) gage, for a segment of a distribution system otherwise designed to operate at over 60 p.s.i. (414 kPa) gage, unless the service lines in the segment are equipped with service regulators or other pressure limiting devices in series that meet the requirements of §192.197(c). (3) 25 p.s.i. (172 kPa) gage in segments of cast iron pipe in which there are unreinforced bell and spigot joints. (4) The pressure limits to which a joint could be subjected without the possibility of its parting. (5) The pressure determined by the operator to be the maximum safe pressure after considering the history of the segment, particularly known corrosion and the actual operating pressures. (b) No person may operate a segment of pipeline to which paragraph (a)(5) of this section applies, unless overpressure protective devices are installed on the segment in a manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with §192.195. [35 FR 13257, Aug. 19, 1970, as amended by Amdt 192–85, 63 FR 37504, July 13, 1998] § 192.623 Maximum and minimum allowable operating pressure; Low-pressure distribution systems.(a) No person may operate a low-pressure distribution system at a pressure high enough to make unsafe the operation of any connected and properly adjusted low-pressure gas burning equipment. (b) No person may operate a low pressure distribution system at a pressure lower than the minimum pressure at which the safe and continuing operation of any connected and properly adjusted low-pressure gas burning equipment can be assured. § 192.625 Odorization of gas.(a) A combustible gas in a distribution line must contain a natural odorant or be odorized so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell. (b) After December 31, 1976, a combustible gas in a transmission line in a Class 3 or Class 4 location must comply with the requirements of paragraph (a) of this section unless: (1) At least 50 percent of the length of the line downstream from that location is in a Class 1 or Class 2 location; (2) The line transports gas to any of the following facilities which received gas without an odorant from that line before May 5, 1975; (i) An underground storage field; (ii) A gas processing plant; (iii) A gas dehydration plant; or (iv) An industrial plant using gas in a process where the presence of an odorant: (A) Makes the end product unfit for the purpose for which it is intended; (B) Reduces the activity of a catalyst; or (C) Reduces the percentage completion of a chemical reaction; (3) In the case of a lateral line which transports gas to a distribution center, at least 50 percent of the length of that line is in a Class 1 or Class 2 location; or (4) The combustible gas is hydrogen intended for use as a feedstock in a manufacturing process. (c) In the concentrations in which it is used, the odorant in combustible gases must comply with the following: (1) The odorant may not be deleterious to persons, materials, or pipe. (2) The products of combustion from the odorant may not be toxic when breathed nor may they be corrosive or harmful to those materials to which the products of combustion will be exposed. (d) The odorant may not be soluble in water to an extent greater than 2.5 parts to 100 parts by weight. (e) Equipment for odorization must introduce the odorant without wide variations in the level of odorant. (f) To assure the proper concentration of odorant in accordance with this section, each operator must conduct periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectable. Operators of master meter systems may comply with this requirement by— (1) Receiving written verification from their gas source that the gas has the proper concentration of odorant; and (2) Conducting periodic “sniff” tests at the extremities of the system to confirm that the gas contains odorant. [35 FR 13257, Aug. 19, 1970] Editorial Note: For § 192.627 Tapping pipelines under pressure.Each tap made on a pipeline under pressure must be performed by a crew qualified to make hot taps. § 192.629 Purging of pipelines.(a) When a pipeline is being purged of air by use of gas, the gas must be released into one end of the line in a moderately rapid and continuous flow. If gas cannot be supplied in sufficient quantity to prevent the formation of a hazardous mixture of gas and air, a slug of inert gas must be released into the line before the gas. (b) When a pipeline is being purged of gas by use of air, the air must be released into one end of the line in a moderately rapid and continuous flow. If air cannot be supplied in sufficient quantity to prevent the formation of a hazardous mixture of gas and air, a slug of inert gas must be released into the line before the air. Browse Previous | Browse Next |
