Mo. Code Regs. Ann. tit. 20, § 4240-40.030
PURPOSE: This rule prescribes minimum safety standards regarding the design, fabrication, installation, construction, metering, corrosion control, testing, uprating, operation, maintenance, leak detection, repair, replacement, and integrity management of pipelines used for the transportation of natural and other gas.
PUBLISHER’S NOTE: The secretary of state has determined that the publication of the entire text of the material which is incorporated by reference as a portion of this rule would be unduly cumbersome or expensive. This material as incorporated by reference in this rule shall be maintained by the agency at its headquarters and shall be made available to the public for inspection and copying at no more than the actual cost of reproduction. This note applies only to the reference material. The entire text of the rule is printed here.
AGENCY NOTE: This rule is similar to the Minimum Federal Safety Standards contained in 49 CFR part 192, Code of Federal Regulations. Parallel citations to Part 192 are provided for gas operator convenience and to promote public safety. Appendix E, contained in this rule, is a Table of Contents for 20 CSR 4240-40.030.
(1) General.
(A) What Is the Scope of this Rule? (192.1)
requirements for pipeline facilities and the transportation of gas in Missouri and under the jurisdiction of the commission. A table of contents is provided in Appendix E, which is included herein (at the end of this rule).
2. This rule does not apply to—
A. The gathering of gas—
at less than zero (0) pounds per square inch gauge (psig) (0 kPa); or
regulated onshore gathering line (as determined in (1)(E)); or
only petroleum gas or petroleum gas/air mixtures to—
if no portion of the system is located in a public place; or
tem is located entirely on the customer’s premises (no matter if a portion of the system is located in a public place).
(B) Definitions. (192.3) as used in this rule—
removed from service;
corrosion that, unless controlled, could result in a condition that is detrimental to public safety;
of the Pipeline and Hazardous Materials Safety Administration of the United States Department of Transportation to whom authority in the matters of pipeline safety have been delegated by the Secretary of the United States Department of Transportation, or his or her delegate;
means of indicating to the controller that equipment or processes are outside operatordefined, safety-related parameters;
regularly or periodically occupied by people;
Public Service Commission;
center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility;
ual who remotely monitors and controls the safety-related operations of a pipeline facility via a supervisory control and data acquisition (SCADA) system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility;
measures the transfer of gas from an operator to a consumer;
means the pipeline safety program manager at the address contained in 20 CSR 4240- 40.020(5)(E) for correspondence;
other than a gathering or transmission line;
closely spaced pipe-to-soil readings over pipelines which are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline, except that other indirect examination tools/methods can be used for an electrical survey included in the federal regulations in 49 CFR part 192, subpart O and appendix E (incorporated by reference in section (16));
(ECA) means a documented analytical procedure based on fracture mechanics principles, relevant material properties (mechanical and fracture resistance properties), operating history, operational environment, in-service degradation, possible failure mechanisms, initial and final defect sizes, and usage of future operating and maintenance procedures to determine the maximum tolerable sizes for imperfections based upon the pipeline segment maximum allowable operating pressure;
that has a maximum allowable operating pressure (MAOP) greater than 100 psi (689 kPa) gauge that produces hoop stresses less than twenty percent (20%) of specified minimum yield strength (SMYS);
inspection performed after a repair procedure has been completed in order to determine the effectiveness of the repair and to ensure that all hazardous leaks in the area are corrected;
gas piping downstream from the outlet of the customer meter or operator-owned pipeline, whichever is farther downstream;
gas, manufactured gas, or gas which is toxic or corrosive;
transports gas from a current production facility to a transmission line or main;
means a distribution system in which the gas pressure in the main is higher than an equiv- 20 CSR 4240-40
alent to fourteen inches (14") water column;
pipe wall acting circumferentially in a plane perpendicular to the longitudinal axis of the pipe produced by the pressure in the pipe;
cation listed in subsection I. of Appendix B, which is included herein (at the end of this rule);
means a distribution system in which the gas pressure in the main is less than or equal to an equivalent of fourteen inches (14") water column;
serves as a common source of supply for more than one (1) service line;
means the maximum pressure that occurs during normal operations over a period of one (1) year;
sure (MAOP) means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this rule;
means—
“potential impact circle” as defined in 49 CFR 192.903 (incorporated by reference in section (16)), containing either—
intended for human occupancy; or
face (including shoulders) of a designated “interstate,” “other freeway or expressway,” as well as any “other principal arterial” roadway with four (4) or more lanes, as defined in the Federal Highway Administration’s Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1 (see: https://www.fhwa.dot.gov/planning/ processes/statewide/related/highway_functional_clas sifications/fcauab.pdf), and that does not meet the definition of “high consequence area” in 49 CFR 192.903 (incorporated by reference in section (16)); and
quence area extends axially along the length of the pipeline from the outermost edge of the first potential impact circle containing either five (5) or more buildings intended for human occupancy; or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with four (4) or more lanes, to the outermost edge of the last contiguous potential impact circle that contains either five (5) or more buildings intended for human occupancy, or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or AND INSURANCE
expressway, as well as any other principal arterial roadway with four (4) or more lanes;
or town;
engages in the transportation of gas;
joint venture, partnership, corporation, association, county, state, municipality, political subdivision, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative of them;
propylene, butane (normal butane or isobutanes), and butylene (including isomers), or mixtures composed predominantly of these gases, having a vapor pressure not exceeding 208 psi (1434 kPa) gauge at 100°F (38°C);
Hazardous Materials Safety Administration of the United States Department of Transportation;
in the transportation of gas, including pipetype holders;
physical facilities through which gas moves in transportation, including pipe, valves, and other appurtenances attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies;
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;
existing pipelines, 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;
reading when testing in a bar hole or opening without induced ventilation;
line that transports gas from a common source of supply to an individual customer, to two (2) 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;
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 (1) customer or multiple customers through a meter header or manifold;
yield strength is—
accordance with a listed specification, the yield strength specified as a minimum in that specification; or
accordance with an unknown or unlisted specification, the yield strength determined in accordance with paragraph (3)(D)2. (192.107[b]);
sition (SCADA) system means a computerbased 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;
taken on a combustible gas indicator unit after adequately venting the test hole or opening;
other than a gathering line, that—
line or storage facility to a distribution center, storage facility, or large volume customer that is not downstream from a distribution center (A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas.);
percent (20%) or more of SMYS; or
field;
gathering, transmission, or distribution of gas by pipeline or the storage of gas, in or affecting intrastate, interstate, or foreign commerce;
way large enough for a man to enter;
face structure that a man can enter;
used when pulling polyethylene pipe, typically through methods such as horizontal directional drilling, to ensure that damage will not occur to the pipeline by exceeding the maximum tensile stresses allowed;
forms manual or semi-automatic welding;
who operates machine or automatic welding equipment; and
line that transports gas from the service line to the customer’s building. If multiple buildings are being served, building means the building nearest to the connection to the service line. For purposes of this definition, if aboveground fuel line piping at the meter location is located within five feet (5') of a building being served by that meter, it will be considered to the customer’s building and no yard line exists. At meter locations where aboveground fuel line piping is located greater than five feet (5') from the building(s) being served, the underground fuel line from the meter to the entrance into the nearest building served by that meter will be considered the yard line and any other lines are not considered yard lines.
(C) Class Locations. (192.5)
locations for the purpose of this rule. The following criteria apply to classifications under this section:
that extends two hundred twenty (220) yards (200 meters) on either side of the centerline of any continuous one- (1-) mile (1.6 kilometers) length of pipeline; and
multiple dwelling unit building is counted as a separate building intended for human occupancy.
(1)(C)3., pipeline locations are classified as follows:
location unit that has ten (10) or fewer buildings intended for human occupancy;
location unit that has more than ten (10) but fewer than forty-six (46) buildings intended for human occupancy;
C. A Class 3 location is—
forty-six (46) or more buildings intended for human occupancy; or
within one hundred (100) yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by twenty (20) or more persons on at least five (5) days a week for ten (10) weeks in any twelve- (12-) month period (The days and weeks need not be consecutive); and
location unit where buildings with four (4) or more stories aboveground are prevalent.
and 4 may be adjusted as follows:
dred twenty (220) yards (200 meters) from the nearest building with four (4) or more stories aboveground; and
ed for human occupancy requires a Class 2 or 3 location, the class location ends two hundred twenty (220) yards (200 meters) from the nearest building in the cluster.
document the current class location of each gas transmission pipeline segment and that demonstrate how the operator determined each current class location in accordance with this subsection.
(D) Incorporation By Reference of the Federal Regulation at 49 CFR 192.7. (192.7)
Regulations (CFR) dated October 1, 2019, and the subsequent amendment 192-125 (published in Federal Register on October 1, 2019, page 84 FR 52180), the federal regulation at 49 CFR 192.7 is incorporated by reference and made a part of this rule. This rule does not incorporate any subsequent amendments to 49 CFR 192.7.
the Federal Register are published by the Office of the Federal Register, National Archives and Records Administration, 8601 Adelphi Road, College Park, MD 20740- 6001. The October 1, 2019 version of 49 CFR part 192 is available at https://www.govinfo.gov/#citation. The Federal Register publication on page 84 FR 52180 is available at https://www.govinfo.gov/content/pkg/FR- 2019-10-01/pdf/2019-20306.pdf.
vides a listing of the documents that are incorporated by reference partly or wholly in 49 CFR part 192, which is the federal counterpart and foundation for this rule. All incorporated materials are available for inspection from several sources, including the following sources:
Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590. For more information, contact 202-366-4046 or go to the PHMSA website at www.phmsa.dot.gov/pipeline/regs;
Records Administration (NARA). For information on the availability of this material at NARA, go to the NARA website at www.archives.gov/federal-register/cfr/ibrlocations.html or call 202–741–6030 or 866- 272-6272; and
by reference can also be purchased or are otherwise made available from the respective standards-developing organizations listed in 49 CFR 192.7.
lished in Federal Register on June 14, 2004, page 69 FR 32886) moved the listing of incorporated documents to 49 CFR 192.7 from 49 CFR part 192−Appendix A, which is now “Reserved.” This listing of documents was in Appendix A to this rule prior to the 2008 amendment of this rule. As of the 2008 amendment, Appendix A to this rule is also “Reserved” and included herein.
(E) Gathering Lines. (192.8 and 192.9)
Regulations (CFR) dated October 1, 2019, and the subsequent amendment 192-125 (published in Federal Register on October 1, 2019, page 84 FR 52180), the federal regulations at 49 CFR 192.8 and 192.9 are incorporated by reference and made a part of this rule. This rule does not incorporate any subsequent amendments to 49 CFR 192.8 and 192.9.
published by the Office of the Federal Register, National Archives and Records Administration, 8601 Adelphi Road, College Park, MD 20740-6001. The October 1, 2019 version of 49 CFR part 192 is available at https://www.govinfo.gov/#citation. The Federal Register publication on page 84 FR 52180 is available at https://www.govinfo.gov/content/pkg/FR- 2019-10-01/pdf/2019-20306.pdf.
192.9 provide the requirements for gathering lines. The requirements for offshore lines are not applicable to Missouri.
(F) Petroleum Gas Systems. (192.11)
gas by pipeline to a natural gas distribution system must meet the requirements of this rule and of NFPA 58 and NFPA 59 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
rule that transports only petroleum gas or petroleum gas/air mixtures must meet the requirements of this rule and of NFPA 58 and NFPA 59 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
rule and NFPA 58 and NFPA 59 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), NFPA 58 and NFPA 59 prevail.
(G) What General Requirements Apply to Pipelines Regulated under this Rule? (192.13)
pipeline listed in the first column that is readied for service after the date in the second column, unless— 20 CSR 4240-40
installed, constructed, initially inspected, and initially tested in accordance with this rule; or
under this rule in accordance with subsection (1)(H). (192.14)
Pipeline Date Regulated onshore gathering line to which 49 CFR 192.8 and 192.9 did not apply until April 14, 2006 (see (1)(E)) March 15, 2007 All other pipelines March 12, 1971
pipeline listed in the first column that is replaced, relocated, or otherwise changed after the date in the second column, unless that replacement, relocation, or change has been made according to the requirements in this rule.
Pipeline Date Regulated onshore gathering line to which 49 CFR 192.8 and 192.9 did not apply until April 14, 2006 (see (1)(E)) March 15, 2007 All other pipelines November 12, 1970
as appropriate, and follow the plans, procedures, and programs that it is required to establish under this rule.
(17) apply regardless of installation date. The requirements within other sections of this rule apply regardless of the installation date only when specifically stated as such.
(H) Conversion to Service Subject to this Rule. (192.14)
(1)(H)4., a steel pipeline previously used in service not subject to this rule qualifies for use under this rule if the operator prepares and follows a written procedure to carry out the following requirements:
tion, and maintenance history of the pipeline must be reviewed and, where sufficient historical records are not available, appropriate tests must be performed to determine if the pipeline is in a satisfactory condition for safe operation;
aboveground segments of the pipeline, and appropriately selected underground segments must be visually inspected for physical defects and operating conditions which reasonably could be expected to impair the strength or tightness of the pipeline;
ditions must be corrected in accordance with AND INSURANCE
this rule; and
accordance with section (10) to substantiate the maximum allowable operating pressure permitted by section (12).
of the pipeline a record of investigations, tests, repairs, replacements, and alterations made under the requirements of paragraph (1)(H)1.
from service not previously covered by this rule must notify PHMSA and designated commission personnel sixty (60) days before the conversion occurs as required by 20 CSR 4240-40.020(11).
steel pipe may not be converted to service subject to this rule.
cathodically protected must be replaced under subsection (15)(C).
cathodically protected may not be converted to a pipeline as defined in subsection (1)(B), such as a service line or main.
cathodically protected may not be converted to a service line.
cathodically protected may not be converted to a main in Class 3 and Class 4 locations.
(I) Rules of Regulatory Construction. (192.15)
1. As used in this rule—
limited to;
authorized to;
or is not authorized to; and
imperative sense.
2. In this rule—
include the plural;
the singular; and
gender include the feminine.
(J) Filing of Required Plans, Procedures, and Programs.
nated commission personnel all plans, procedures, and programs required by this rule (to include welding and joining procedures, construction standards, control room management procedures, corrosion control procedures, damage prevention program, distribution integrity management plan, emergency procedures, public education program, operator qualification program, replacement programs, transmission integrity management program, and procedural manual for operations, maintenance, and emergencies). In addition, each change must be submitted to designated commission personnel within twenty (20) days after the change is made.
ty jurisdiction of the Missouri Public Service Commission must establish and submit welding procedures, joining procedures, and construction specifications and standards to designated commission personnel before construction activities begin. All other plans, procedures and programs required by rules 20 CSR 4240-40.020, 20 CSR 4240-40.030, and 20 CSR 4240-40.080 must be established and submitted to designated commission personnel before the system is put into operation.
testing in accordance with 20 CSR 4240- 40.080 must be submitted to designated commission personnel.
(K) Customer Notification Required by Section 192.16 of 49 CFR part 192. (192.16)
ator of a service line who does not maintain the customer’s buried piping up to entry of the first building downstream, or, if the customer’s buried piping does not enter a building, up to the principal gas utilization equipment or the first fence (or wall) that surrounds that equipment. For the purpose of this subsection, “customer’s buried piping” does not include branch lines that serve yard lanterns, pool heaters, or other types of secondary equipment. Also, “maintain” means monitor for corrosion according to subsection (9)(I) if the customer’s buried piping is metallic, survey for leaks according to subsection (13)(M), and if an unsafe condition is found, take action according to paragraph (12)(S)3.
tomer once in writing of the following information:
the customer’s buried piping;
not maintained, it may be subject to the potential hazards of corrosion and leakage;
C. Buried gas piping should be—
leaks;
corrosion if the piping is metallic; and
dition is discovered;
piping, the piping should be located in advance, and the excavation done by hand; and
plumbing contractors, and heating contractors can assist in locating, inspecting, and repairing the customer’s buried piping.
tomer not later than August 14, 1996, or ninety (90) days after the customer first receives gas at a particular location, whichever is later. However, operators of master meter systems may continuously post a general notice in a prominent location frequented by customers.
ing records available for inspection by designated commission personnel:
use; and
sent to customers within the previous three (3) years.
(M) How to Notify PHMSA and Designated Commission Personnel. (192.18)
cation required by this rule by—
tronic mail to InformationResourcesManager@dot.gov; or
ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22–321, 1200 New Jersey Ave. SE, Washington, DC 20590.
nated commission personnel by electronic mail to PipelineSafetyProgramManager@psc.mo.gov or by mail to Pipeline Safety Program Manager, Missouri Public Service Commission, PO Box 360, Jefferson City, MO 65102.
notification is made pursuant to (10)(K)2., (12)(E)5.D. and E., (12)(U)3.B.(III) and 3.F., (12)(V)2.C., (13)(DD)3.G., (13)(EE)4.C.(IV) and 5.B.(I)(e), 49 CFR 192.921(a)(7) (incorporated by reference in section (16)), or 49 CFR 192.937(c)(7) (incorporated by reference in section (16)) to use a different integrity assessment method, analytical method, sampling approach, or technique (i.e., ‘‘other technology’’) that differs from that prescribed in those requirements, the operator must notify PHMSA at least ninety (90) days in advance of using the “other technology.” An operator may proceed to use the “other technology” ninety-one (91) days after submittal of the notification unless it receives a letter from the Associate Administrator for Pipeline Safety informing the operator that PHMSA objects to the proposed use of “other technology” or that PHMSA requires additional time to conduct its review.
(2) Materials.
(B) General. (192.53) Materials for pipe and components must be—
integrity of the pipeline under temperature and other environmental conditions that may be anticipated;
that they transport and with any other material in the pipeline with which they are in contact;
applicable requirements of this section; and
for the underground construction of pipelines, except that other previously qualified materials may be used for—
structed of the same material; and
nances attached to the pipe.
with approval of the commission.
(C) Steel Pipe. (192.55)
under this rule if—
with a listed specification;
B. It meets the requirements of—
this rule; or
November 12, 1970, either subsection II or III of Appendix B to this rule; or
graph (2)(C)3. or 4.
under this rule if—
with a listed specification and it meets the requirements of paragraph II-C of Appendix B to this rule;
B. It meets the requirements of—
this rule; or
November 12, 1970, either subsection II or III of Appendix B to this rule;
of the same or higher pressure and meets the requirements of paragraph II-C of Appendix B to this rule; or
graph (2)(C)3.
at a pressure resulting in a hoop stress of less than six thousand (6000) pounds per square inch (psi) (41 MPa) where no close coiling or close bending is to be done, if visual examination indicates that the pipe is in good condition and that it is free of split seams and other defects that would cause leakage. If it is to be welded, steel pipe that has not been manufactured to a listed specification must also pass the weldability tests prescribed in paragraph II-B of Appendix B to this rule.
ly used may be used as replacement pipe in a segment of pipeline if it has been manufactured prior to November 12, 1970, in accordance with the same specification as the pipe used in constructing that segment of pipeline.
expanded must comply with the mandatory provisions of API Specification 5L (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
(D) Plastic Pipe. (192.59)
use under this rule if—
with a listed specification;
which contact may be anticipated; and
under this rule if—
with a listed specification;
which contact may be anticipated;
vice;
tolerances of the specification to which it was manufactured; and
(2)(D)1.A. and 2.A., where pipe of a diameter included in a listed specification is impractical to use, pipe of a diameter between the sizes included in a listed specification may be used if it—
teria required of pipe included in that listed specification; and
pounds which meet the criteria for material required of pipe included in that listed specification.
allowed in plastic pipe produced after March 20 CSR 4240-40
6, 2015 used under this rule.
(E) Marking of Materials. (192.63)
(2)(E)4. and (2)(E)5., each valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which it was manufactured.
are subject to stress from internal pressure may not be field die stamped.
ing, the die must have blunt or rounded edges that will minimize stress concentrations.
items manufactured before November 12, 1970, that meet all of the following:
manufacturer, and model; and
pressure, temperature, and other appropriate criteria for the use of items are readily available.
also meet the following requirements:
scribed in the listed specification and the requirements of subparagraph (2)(E)5.B. must be repeated at intervals not exceeding two (2) feet;
ufactured after December 31, 2019 must be marked in accordance with the listed specification; and
pipelines prescribed in the listed specification and subparagraph (2)(E)5.B. must be legible until the time of installation.
(F) Transportation of Pipe. (192.65)
at a hoop stress of twenty percent (20%) or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of seventy to one (70:1) or more that is transported by railroad unless the transportation is performed in accordance with API RP 5L1 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
operated at a hoop stress of twenty percent (20%) or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of seventy to one (70:1) or more that is transported by ship or barge on both inland and marine waterways unless the transportation is performed in accordance with API RP 5LW (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
a hoop stress of twenty percent (20%) or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness AND INSURANCE
ratio of seventy to one (70:1) or more that is transported by truck unless the transportation is performed in accordance with API RP 5LT (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
(G) Records: Material Properties. (192.67)
installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records that document the physical characteristics of the pipeline, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition of materials for pipe in accordance with subsections (2)(B) and (2)(C) (192.53 and 192.55). Records must include tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed.
installed on or before July 1, 2020, if operators have records that document tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition in accordance with subsections (2)(B) and (2)(C) (192.53 and 192.55), operators must retain such records for the life of the pipeline.
ments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of subsection (12)(U) (192.624) according to the terms of that subsection.
(3) Pipe Design.
(C) Design Formula for Steel Pipe. (192.105)
determined in accordance with the following formula: P = (2 St/D) × F × E × T where— P = Design pressure in pounds per square inch (kPa) gauge; S = Yield strength in pounds per square inch (kPa) determined in accordance with subsection (3)(D); (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 subsection (3)(E) (192.109). Additional wall thickness required for concurrent external loads in accordance with subsection (3)(B) (192.103) may not be included in computing design pressure; F = Design factor determined in accordance with subsection (3)(F) (192.111); E = Longitudinal joint factor determined in accordance with subsection (3)(G) (192.113); and T = Temperature derating factor determined in accordance with subsection (3)(H) (192.115).
cold expansion to meet the SMYS is subsequently heated, other than by welding or stress relieving as a part of welding, the design pressure is limited to seventy-five percent (75%) of the pressure determined under paragraph (3)(C)1. if the temperature of the pipe exceeds 900 °F (482 °C) at any time or is held above 600 °F (316 °C) for more than one (1) hour.
(D) Yield Strength (S) for Steel Pipe. (192.107)
accordance with a specification listed in subsection I of Appendix B, the yield strength to be used in the design formula in subsection (3)(C) (192.105) is the SMYS stated in the listed specification, if that value is known.
accordance with a specification not listed in subsection I of Appendix B or whose specification or tensile properties are unknown, the yield strength to be used in the design formula in subsection (3)(C) (192.105) is one (1) of the following:
accordance with paragraph II-D of Appendix B, the lower of the following:
average yield strength determined by the tensile tests; or
mined by the tensile tests; or
provided in subparagraph (3)(D)2.A., twenty-four thousand (24,000) psi (165 MPa).
(E) Nominal Wall Thickness (t) for Steel Pipe. (192.109)
pipe is not known, it is determined by measuring the thickness of each piece of pipe at quarter points on one end.
grade, size, and thickness and there are more than ten (10) lengths, only ten percent (10%) of the individual lengths, but not less than ten (10) lengths, need to be measured. The thickness of the lengths that are not measured must be verified by applying a gauge set to the minimum thickness found by the measurement. The nominal wall thickness to be used in the design formula in subsection (3)(C) (192.105) is the next wall thickness found in commercial specifications that is below the average of all the measurements taken. However, the nominal wall thickness used may not be more than one and fourteen hundredths (1.14) times the smallest measurement taken on pipe less than twenty inches (20") (508 millimeters) in outside diameter, nor more than one and eleven hundredths (1.11) times the smallest measurement taken on pipe twenty inches (20") (508 millimeters) or more in outside diameter.
(F) Design Factor (F) for Steel Pipe. (192.111)
graphs (3)(F)2.–4., the design factor to be used in the design formula in subsection (3)(C) (192.105) is determined in accordance with the following table:
Class Location Design Factor (F) 1 0.72 2 0.60 3 0.50 4 0.40
be used in the design formula in subsection (3)(C) (192.105) for steel pipe in Class 1 locations that—
unimproved public road without a casing;
a parallel encroachment on, the right-of-way of either a hard surfaced road, a highway, a public street, or a railroad;
trian, railroad, or pipeline bridge; or
(including separators, mainline valve assemblies, cross-connections and river crossing headers) or is used within five (5) pipe diameters in any direction from the last fitting of a fabricated assembly, other than a transition piece or an elbow used in place of a pipe bend which is not associated with a fabricated assembly.
of 0.50 or less must be used in the design formula in subsection (3)(C) (192.105) for uncased steel pipe that crosses the right-ofway of a hard surfaced road, a highway, a public street, or a railroad.
design factor of 0.50 or less must be used in the design formula in subsection (3)(C) (192.105) for—
regulating station or measuring station; and
on a platform located in inland navigable waters.
Longitudinal Joint Factor Specification Pipe Class (E)
ASTM A 53/A53M Seamless 1.00 Electric resistance welded 1.00 Furnace butt welded 0.60 ASTM A 106 Seamless 1.00 ASTM A 333/A 333M Seamless 1.00 Electric resistance welded 1.00 ASTM A 381 Double submerged arc welded 1.00 ASTM A 671 Electric fusion welded 1.00 ASTM A 672 Electric fusion welded 1.00 ASTM A 691 Electric fusion welded 1.00 API 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. AND INSURANCE
Gas Temperature Temperature in Degrees Derating Fahrenheit Factor (T) (Celsius) 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.
(I) Design of Plastic Pipe. (192.121)
plastic pipe are determined in accordance with either of the following formulas: t P = 2 S × DF (D–t) 2 S P = × DF (SDR–1) where P = Design pressure, psi (kPa) gauge; S= For thermoplastic pipe, the hydrostatic design base (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 in 49 CFR 192.7 and adopted in subsection (1)(D)); t = Specified wall thickness, inches (millimeters); D = Specified outside diameter, inches (millimeters); and SDR = Standard dimension ratio, the ratio of the average specified outside diameter to the minimum specified wall thickness, corresponding to a value from a common numbering system that was derived from the American National Standards Institute preferred number series 10. DF = Design Factor, a maximum of 0.32 unless otherwise specified for a particular material in this subsection.
Pipe and Components.
exceed a gauge pressure of 100 psi (689 kPa) gauge for plastic pipe.
operating temperatures of the pipe will be:
°F (-40 °C) if all pipe and pipeline components whose operating temperature will be below -20 °F (-29 °C) have a temperature rating by the manufacturer consistent with that operating temperature; or
the HDB used in the design formula under this subsection is determined.
tic pipe may not be less than 0.062 inches (1.57 millimeters).
HDB in accordance with PPI TR–4/2012 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ments.
192.121(c)(1) is not adopted in this rule. (This federal regulation permits higher design pressures for certain types of PE pipe.)
January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
exceed 100 psig;
is PE2708 or PE4710;
(IPS or CTS) of 12 inches or less; and
outside diameter is not less than that listed in the following table:
(cid:51)(cid:40)(cid:3)(cid:51)(cid:76)(cid:83)(cid:72)(cid:29)(cid:3)(cid:48)(cid:76)(cid:81)(cid:76)(cid:80)(cid:88)(cid:80)(cid:3)(cid:58)(cid:68)(cid:79)(cid:79)(cid:3)(cid:55)(cid:75)(cid:76)(cid:70)(cid:78)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
(cid:51)(cid:76)(cid:83)(cid:72)(cid:3)(cid:54)(cid:76)(cid:93)(cid:72)(cid:3) (cid:48)(cid:76)(cid:81)(cid:76)(cid:80)(cid:88)(cid:80)(cid:3)(cid:90)(cid:68)(cid:79)(cid:79)(cid:3) (cid:11)(cid:76)(cid:81)(cid:70)(cid:75)(cid:72)(cid:86)(cid:12)(cid:3) (cid:87)(cid:75)(cid:76)(cid:70)(cid:78)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:11)(cid:76)(cid:81)(cid:70)(cid:75)(cid:72)(cid:86)(cid:12)(cid:3) (cid:242)(cid:3)(cid:5)(cid:3)(cid:38)(cid:55)(cid:54)(cid:3) (cid:244)(cid:3)(cid:5)(cid:3)(cid:38)(cid:55)(cid:54)(cid:3) (cid:242)(cid:3)(cid:5)(cid:3)(cid:44)(cid:51)(cid:54)(cid:3) (cid:244)(cid:3)(cid:5)(cid:3)(cid:44)(cid:51)(cid:54)(cid:3) (cid:20)(cid:3)(cid:5)(cid:3)(cid:38)(cid:55)(cid:54)(cid:3) (cid:20)(cid:3)(cid:5)(cid:3)(cid:44)(cid:51)(cid:54)(cid:3) (cid:20)(cid:3)(cid:243)(cid:3)(cid:5)(cid:3)(cid:44)(cid:51)(cid:54)(cid:3) (cid:20)(cid:3)(cid:242)(cid:3)(cid:5)(cid:3)(cid:44)(cid:51)(cid:54)(cid:3) (cid:21)(cid:3)(cid:5)(cid:3) (cid:22)(cid:3)(cid:5)(cid:3) (cid:23)(cid:3)(cid:5)(cid:3) (cid:25)(cid:3)(cid:5)(cid:3) (cid:27)(cid:3)(cid:5)(cid:3) (cid:20)(cid:19)(cid:3)(cid:5)(cid:3) (cid:20)(cid:21)(cid:3)(cid:5)(cid:3) (cid:3)
192.121(d) through (f) are not adopted in this rule. (Those federal regulations address design requirements for types of plastic pipe other than PE pipe.) (cid:54)(cid:39)(cid:53)(cid:3)(cid:57)(cid:68)(cid:79)(cid:88)(cid:72)(cid:86)(cid:3) (cid:38)(cid:82)(cid:85)(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3) (cid:54)(cid:39)(cid:53)(cid:3)(cid:11)(cid:89)(cid:68)(cid:79)(cid:88)(cid:72)(cid:86)(cid:12)(cid:3) (cid:19)(cid:17)(cid:19)(cid:28)(cid:19)(cid:3) (cid:19)(cid:17)(cid:19)(cid:28)(cid:19)(cid:3) (cid:19)(cid:17)(cid:19)(cid:28)(cid:19)(cid:3) (cid:19)(cid:17)(cid:19)(cid:28)(cid:24)(cid:3) (cid:19)(cid:17)(cid:20)(cid:20)(cid:28)(cid:3) (cid:19)(cid:17)(cid:20)(cid:20)(cid:28)(cid:3) (cid:19)(cid:17)(cid:20)(cid:24)(cid:20)(cid:3) (cid:19)(cid:17)(cid:20)(cid:26)(cid:22)(cid:3) (cid:19)(cid:17)(cid:21)(cid:20)(cid:25)(cid:3) (cid:19)(cid:17)(cid:21)(cid:24)(cid:28)(cid:3) (cid:19)(cid:17)(cid:21)(cid:25)(cid:24)(cid:3) (cid:19)(cid:17)(cid:22)(cid:20)(cid:24)(cid:3) (cid:19)(cid:17)(cid:23)(cid:20)(cid:20)(cid:3) (cid:19)(cid:17)(cid:24)(cid:20)(cid:21)(cid:3) (cid:19)(cid:17)(cid:25)(cid:19)(cid:26)(cid:3)
(K) Design of Copper Pipe for Repairs. (192.125)
a minimum wall thickness of 0.065 inches (1.65 millimeters) and must be hard drawn.
must have a minimum wall thickness not less than that indicated in the following table:
Standard Nominal Wall (inch) Size (inch) O.D. (inch) Thickness (millimeter) (millimeter) (millimeters) 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)
vices lines may not be used at pressures in excess of 100 psi (689 kPa) gauge.
internal corrosion resistant lining may not be used to carry gas that has an average hydrogen sulfide content of more than 0.3 grains/100 ft3 (6.9/m3) under standard conditions. Standard conditions refers to 60 °F and 14.7 psia (38 °C and one atmosphere) of gas.
(M) Records: Pipe design. (192.127)
installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records documenting that the pipe is designed to withstand anticipated external pressures and loads in accordance with subsection (3)(B) (192.103) and documenting that the determination of design pressure for
(cid:26)(cid:3) the pipe is made in accordance with subsec- (cid:28)(cid:17)(cid:26)(cid:3) (cid:28)(cid:17)(cid:22)(cid:3) tion (3)(C) (192.105). (cid:20)(cid:20)(cid:3)
(cid:20)(cid:20)(cid:3) installed on or before July 1, 2020, if opera- (cid:20)(cid:20)(cid:3) tors have records documenting pipe design (cid:20)(cid:20)(cid:3) and the determination of design pressure in (cid:20)(cid:20)(cid:3) accordance with subsections (3)(B) and (cid:20)(cid:20)(cid:3) (3)(C) (192.103 and 192.105), operators (cid:20)(cid:22)(cid:17)(cid:24)(cid:3) must retain such records for the life of the (cid:20)(cid:26)(cid:3) (cid:21)(cid:20)(cid:3) pipeline. (cid:21)(cid:20)(cid:3)
(cid:21)(cid:20)(cid:3) ments installed on or before July 1, 2020, if (cid:21)(cid:20)(cid:3) an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of subsection (12)(U) (192.624) according to the terms of that subsection.
(B) General Requirements. (192.143)
able to withstand operating pressures and other anticipated loadings without impairment of its serviceability with unit stresses equivalent to those allowed for comparable material in pipe in the same location and kind of service. However, if design based upon unit stresses is impractical for a particular component, design may be based upon a pressure rating established by the manufacturer by pressure testing that component or a prototype of the component.
components and facilities must meet applicable requirements for corrosion control found in section (9).
plastic pipeline component installed after April 22, 2019, must be able to withstand operating pressures and other anticipated loads in accordance with a listed specification.
(C) Qualifying Metallic Components. (192.144) Notwithstanding any requirement of this section which incorporates by reference an edition of a document listed in 49 CFR 192.7 (see (1)(D)) or Appendix B, a metallic component manufactured in accordance with any other edition of that document is qualified for use under this rule if—
inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component; and
which the component was manufactured has equal or more stringent requirements for the following as an edition of that document currently or previously listed in 49 CFR 192.7 (see (1)(D)) or Appendix B:
(D) Valves. (192.145)
valves, each valve must meet the minimum requirements of ANSI/API Specification 6D (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), or to a national or international standard that provides an equivalent performance level. A valve may not be used under operating conditions that exceed the applicable pressure-temperature ratings contained in those requirements.
comply with the following:
service pressure rating for temperatures that equal or exceed the maximum service temperature; and
the manufacturing, as follows:
position, the shell must be tested with no leakage to a pressure at least one and one-half (1.5) times the maximum service rating;
must be tested to a pressure not less than one and one-half (1.5) times the maximum service pressure rating. Except for swing check valves, test pressure during the seat test must be applied successively on each side of the closed valve with the opposite side open. No visible leakage is permitted; and
completed, the valve must be operated through its full travel to demonstrate freedom from interference.
anticipated operating conditions.
cover, and/or end flange) components made of ductile iron may be used at pressures exceeding eighty percent (80%) of the pressure ratings for comparable steel valves at their listed temperature. However, a valve having shell components made of ductile iron may be used at pressures up to eighty percent (80%) of the pressure ratings for comparable steel valves at their listed temperature, if —
pressure does not exceed 1,000 psi (7 MPa) gauge; and
iron component in the fabrication of the valve shells or their assembly.
cover, and/or end flange) components made of cast iron, malleable iron, or ductile iron may be used in the gas pipe components of compressor stations.
valves installed after April 22, 2019, must meet the minimum requirements of a listed specification. A valve may not be used under operating conditions that exceed the applicable pressure and temperature ratings contained in the listed specification.
(E) Flanges and Flange Accessories. (192.147)
(other than cast iron) must meet the minimum requirements of ASME/ANSI B16.5 and MSS SP–44 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), or the equivalent.
withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service.
iron pipe must conform in dimensions, drilling, face, and gasket design to ASME/ANSI B16.1 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) and be cast integrally with the pipe, valve, or fitting.
(F) Standard Fittings. (192.149)
threaded fittings may not be less than specified for the pressures and temperatures in the applicable standards referenced in this rule or their equivalent.
have pressure and temperature ratings based on stresses for pipe of the same or equivalent material. The actual bursting strength of the fitting must at least equal the computed bursting strength of pipe of the designated material and wall thickness, as determined by a prototype that was tested to at least the pressure required for the pipeline to which it is being added.
22, 2019, must meet a listed specification.
(G) Tapping. (192.151)
a hot tap must be designed for at least the operating pressure of the pipeline.
the extent of full-thread engagement and the need for the use of outside-sealing service connections, tapping saddles, or other fixtures must be determined by service conditions.
iron or ductile iron pipe, the diameter of the tapped hole may not be more than twenty-five percent (25%) of the nominal diameter of the pipe unless the pipe is reinforced, except that—
replacement service, if they are free of cracks and have good threads; and
(32 millimeters) tap may be made in a fourinch (4") (102 millimeters) cast iron or ductile iron pipe, without reinforcement.
soil, and service conditions may create unusual external stresses on cast iron pipe, unreinforced taps may be used only on sixinch (6") (152 millimeters) or larger pipe.
(H) Components Fabricated by Welding. (192.153)
assemblies of standard pipe and fittings AND INSURANCE
joined by circumferential welds, the design pressure of each component fabricated by welding, whose strength cannot be determined, must be established in accordance with paragraph UG-101 of the ASME Boiler and Pressure Vessel Code (Section VIII, Division 1) (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
and longitudinal seams must be designated, constructed, and tested in accordance with section 1 of the ASME Boiler and Pressure Vessel Code (Section VIII, Division 1 or 2) (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), except for the following:
ing fittings;
tested under a specification listed in Appendix B to this rule;
rings or collars; and
facturer certifies have been tested to at least twice the maximum pressure to which they will be subjected under the anticipated operating conditions.
peel swages may not be used on pipelines that are to operate at a hoop stress of twenty percent (20%) or more of the SMYS of the pipe.
accordance with the ASME Boiler and Pressure Vessel Code (Section VIII, Division 1 or 2) (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), flat closures and fish tails may not be used on pipe that either operates at 100 psi (689 kPa) gauge or more, or is more than three inches (3") (76 millimeters) nominal diameter.
sure established in accordance with paragraph (4)(H)1. or 2. and subject to the strength testing requirements of paragraph (10)(C)2. must be tested to at least one and one-half (1.5) times the MAOP.
(L) Supports and Anchors. (192.161)
equipment must have enough anchors or supports to—
equipment;
by a bend or offset in the pipe; and
vibration.
enough supports or anchors to protect the exposed pipe joints from the maximum end force caused by internal pressure and any additional forces caused by temperature expansion or contraction or by the weight of the pipe and its contents.
exposed pipeline must be made of durable, noncombustible material and must be designed and installed as follows:
the pipeline between supports or anchors may not be restricted;
service conditions involved; and
cause disengagement of the support equipment.
operated at a stress level of fifty percent (50%) or more of SMYS must comply with the following:
welded directly to the pipe;
member that completely encircles the pipe; and
to a pipe, the weld must be continuous and cover the entire circumference.
connected to a relatively unyielding line or other fixed object must have enough flexibility to provide for possible movement or it must have an anchor that will limit the movement of the pipeline.
being connected to new branches must have a firm foundation for both the header and the branch to prevent detrimental lateral and vertical movement.
(M) Compressor Stations—Design and Construction. (192.163)
Except for a compressor building on a platform located in inland navigable waters, each main compressor building of a compressor station must be located on property under the control of the operator. It must be far enough away from adjacent property not under control of the operator to minimize the possibility of fire being communicated to the compressor building from structures on adjacent property. There must be enough open space around the main compressor building to allow the free movement of firefighting equipment.
on a compressor station site must be made of noncombustible materials if it contains either—
millimeters) in diameter that is carrying gas under pressure; or
gas utilization equipment used for domestic purposes.
compressor building must have at least two (2) separated and unobstructed exits located so as to provide a convenient possibility of escape and an unobstructed passage to a place of safety. Each door latch on an exit must be of a type which can be readily opened from the inside without a key. Each swinging door located in an exterior wall must be mounted to swing outward.
compressor station must have at least two (2) gates located so as to provide a convenient opportunity for escape to a place of safety or have other facilities affording a similarly convenient exit from the area. Each gate located within two hundred feet (200') (61 meters) of any compressor plant building must open outward and, when occupied, must be openable from the inside without a key.
ment and wiring installed in compressor stations must conform to NFPA-70 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), so far as that code is applicable.
(N) Compressor Stations—Liquid Removal. (192.165)
liquefy under the anticipated pressure and temperature conditions, the compressor must be protected against the introduction of liquids in quantities that could cause damage.
entrained liquids at a compressor station must—
of removing these liquids;
ried into the compressors, have either automatic liquid removal facilities, an automatic compressor shutdown device, or a high liquid level alarm; and
with section VIII of the ASME Boiler and Pressure Vessel Code (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) and the additional requirements of paragraph (4)(H)5., except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4 or less.
(O) Compressor Stations—Emergency Shutdown. (192.167)
sor stations of one thousand (1,000) horsepower (746 kilowatts) or less, each compressor station must have an emergency shutdown system that meets the following:
the station and blowdown the station piping;
blowdown piping at a location where the gas will not create a hazard;
down of gas compressing equipment, gas fires, and electrical facilities in the vicinity of gas headers and in the compressor building, except that—
emergency lighting required to assist station personnel in evacuating the compressor building and the area in the vicinity of the gas headers must remain energized; and
protect equipment from damage may remain energized; and
two (2) locations, each of which is—
tion;
is fenced or near emergency exits if not fenced; and
feet (500') (153 meters) from the limits of the station.
directly to a distribution system with no other adequate source of gas available, the emergency shutdown system must be designed so that it will not function at the wrong time and cause an unintended outage on the distribution system.
gable waters, the emergency shutdown system must be designed and installed to actuate automatically by each of the following events:
pressor station—
the maximum allowable operating pressure plus fifteen percent (15%); or
occurs on the platform; and
in a building—
occurs in the building; or
in air reaches fifty percent (50%) or more of the lower explosive limit in a building which has a source of ignition. For the purpose of part (4)(O)3.B.(II), an electrical facility which conforms to Class 1, Group D of the National Electrical Code is not a source of ignition.
(P) Compressor Stations—Pressure Limiting Devices. (192.169)
pressure relief or other suitable protective devices of sufficient capacity and sensitivity to ensure that the maximum allowable operating pressure of the station piping and equipment is not exceeded by more than ten percent (10%).
the pressure relief valves of a compressor station must extend to a location where the gas may be discharged without hazard.
(Q) Compressor Stations—Additional Safety Equipment. (192.171)
adequate fire protection facilities. If fire pumps are a part of these facilities, their operation may not be affected by the emergency shutdown system.
other than an electrical induction or synchronous motor must have an automatic device to shut down the unit before the speed of either the prime mover or the driven unit exceeds a maximum safe speed.
sor station must have a shutdown or alarm device that operates in the event of inadequate cooling or lubrication of the unit.
that operates with pressure gas injection must be equipped so that stoppage of the engine automatically shuts off the fuel and vents the engine distribution manifold.
compressor station must have vent slots or holes in the baffles of each compartment to prevent gas from being trapped in the muffler.
(192.173) 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.
(S) Pipe-Type and Bottle-Type Holders. (192.175)
must be designed so as to prevent the accumulation of liquids in the holder, in connecting pipe or in auxiliary equipment that might cause corrosion or interfere with the safe operation of the holder.
must have a minimum clearance from other holders in accordance with the following formula: C = (3D × P × F)/1000 (in inches) (C=(3D×P×F) / 6,895) (in millimeters) where 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; and F =Design factor as set forth in subsection (3)(F) (192.111).
(T) Additional Provisions for Bottle-Type Holders. (192.177)
1. Each bottle-type holder must be—
rounded by fencing that prevents access by unauthorized persons and with minimum clearance from the fence as follows:
Minimum Maximum Allowable Clearance Operating Pressure feet (meters) Less than 1000 psi (7 MPa) gauge 25 (7.6) 1000 psi (7 MPa) gauge or more 100 (31)
set forth in subsection (3)(F) (192.111); and
accordance with subsection (7)(N). (192.327)
from steel that is not weldable under field conditions must comply with the following:
alloy steel must meet the chemical and tensile requirements for the various grades of steel in ASTM A372/A372M (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D));
steel may not exceed 0.85;
the holder after it has been heat-treated or stress-relieved, except that copper wires may AND INSURANCE
be attached to the small diameter portion of the bottle end closure for cathodic protection if a localized Thermit welding process is used;
hydrostatic test at a pressure that produces a hoop stress at least equal to eighty-five percent (85%) of the SMYS; and
components must be leak tested after installation as required by section (10).
(U) Transmission Line Valves. (192.179)
tionalizing block valves spaced as follows, unless in a particular case the administrator finds that alternative spacing would provide an equivalent level of safety:
Class 4 location must be within two and onehalf (2 1/2) miles (4 kilometers) of a valve;
Class 3 location must be within four (4) miles (6.4 kilometers ) of a valve;
Class 2 location must be within seven and one-half (7 1/2) miles (12 kilometers) of a valve; and
Class 1 location must be within ten (10) miles (16 kilometers) of a valve.
transmission line must comply with the following:
to open or close the valve must be readily accessible and protected from tampering and damage; and
prevent settling of the valve or movement of the pipe to which it is attached.
between main line valves must have a blowdown valve with enough capacity to allow the transmission line to be blown down as rapidly as practicable. Each blowdown discharge must be located so the gas can be blown to the atmosphere without hazard and, if the transmission line is adjacent to an overhead electric line, so that the gas is directed away from the electrical conductors.
(V) Distribution Line Valves. (192.181)
tem must have valves spaced so as to reduce the time to shut down a section of main in an emergency. The valve spacing is determined by the operating pressure, the size of the mains and the local physical conditions, but it must at least provide zones of isolation sized so that the operator could relight the lost customer services within a period of eight (8) hours after restoration of system pressure.
flow or pressure of gas in a distribution system must have a valve installed on the inlet piping and on the outlet piping at a sufficient distance from the regulator station to permit the operation of the valve during an emergency that might preclude access to the station. An outlet valve on regulator stations will not be required on single-feed distribution systems when the outlet piping size is less than or equal to two inches (2") in nominal diameter.
operating or emergency purposes must comply with the following:
readily accessible location so as to facilitate its operation in an emergency;
must be readily accessible; and
box or enclosure, the box or enclosure must be installed so as to avoid transmitting external loads to the main.
(W) Vaults—Structural Design Requirements. (192.183)
valves, pressure relieving, pressure limiting, or pressure regulating stations must be able to meet the loads which may be imposed upon it and to protect installed equipment.
so that all of the equipment required in the vault or pit can be properly installed, operated, and maintained.
ulator vault or pit must be steel for sizes ten inches (10") (254 millimeters), and less, except that control and gauge piping may be copper. Where pipe extends through the vault or pit structure, provision must be made to prevent the passage of gases or liquids through the opening and to avert strains in the pipe.
(X) Vaults—Accessibility. (192.185) Each vault must be located in an accessible location and, so far as practical, away from—
traffic is heavy or dense;
basins or places where the access cover will be in the course of surface waters; and
ities.
(Y) Vaults—Sealing, Venting, and Ventilation. (192.187) 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:
two hundred (200) cubic feet (5.7 cubic meters)—
with two (2) ducts, each having at least the ventilating effect of a pipe four inches (4") (102 millimeters) in diameter;
minimize the formation of combustible atmosphere in the vault or pit; and
above grade to disperse any gas-air mixtures that might be discharged;
than seventy-five (75) cubic feet (2.1 cubic meters) but less than two hundred (200) cubic feet (5.7 cubic meters)—
opening must have a tight fitting cover without open holes through which an explosive mixture might be ignited, and there must be a means for testing the internal atmosphere before removing the cover;
must be a means of preventing external sources of ignition from reaching the vault atmosphere; or
paragraph (4)(Y)1. or 3. applies; and
(4)(Y)2. is ventilated by openings in the covers or gratings and the ratio of the internal volume, in cubic feet, to the effective ventilating area of the cover or grating, in square feet, is less than twenty to one (20:1), no additional ventilation is required.
(Z) Vaults—Drainage and Waterproofing. (192.189)
minimize the entrance of water.
be connected by means of a drain connection to any other underground structure.
must conform to the applicable requirements of Class 1, Group D, of the National Electrical Code, NFPA-70 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
(AA) Risers Installed After January 22, 2019. (192.204)
safe performance under anticipated external and internal loads acting on the assembly.
must be designed and tested in accordance with ASTM F1973–13 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
stations to plastic mains must be rigid and designed to provide adequate support and resist lateral movement. Anodeless risers used in accordance with this paragraph must have a rigid riser casing.
(CC) Protection Against Accidental Overpressuring. (192.195)
vided in subsection (4)(DD) (192.197), each pipeline that is connected to a gas source so that the maximum allowable operating pressure could be exceeded, as the result of pressure control failure or of some other type of failure, must have pressure relieving or pressure limiting devices that meet the requirements of subsections (4)(EE) and (FF). (192.199 and 192.201)
tions systems. Each distribution system that is supplied from a source of gas that is at a higher pressure than the maximum allowable operating pressure for the system must—
capable of meeting the pressure, load and other service conditions that will be experienced in normal operation of the system, and that could be activated in the event of failure of some portion of the system; and
dental overpressuring.
(DD) Control of the Pressure of Gas Delivered from Transmission Lines and High- Pressure Distribution Systems to Service Equipment. (192.197) If the maximum allowable operating pressure of the system exceeds fourteen inches (14") water column, one (1) of the following methods must be used to regulate and limit, to the maximum safe value, the pressure of gas delivered to the customer:
over-pressure protection device set to limit, to a maximum safe value, the pressure of the gas delivered to the customer and another regulator located upstream from the service regulator. The upstream regulator may not be set to maintain a pressure higher than sixty (60) psi (414 kPa) gauge. A device must be installed between the upstream regulator and the service regulator to limit the pressure on the inlet of the service regulator to sixty (60) psi (414 kPa) gauge or less in case the upstream regulator fails to function properly. This device may be either a relief valve or an automatic shutoff that shuts and remains closed until manually reset, if the pressure on the inlet of the service regulator exceeds the set pressure (sixty (60) psi (414 kPa) gauge or less);
regulator set to limit, to a maximum safe value, the pressure of the gas delivered to the customer. A device or method that indicates the failure of the service regulator must also be provided. The service regulator must be monitored at intervals not exceeding fifteen (15) months, but at least once each calendar year for detection of a failure;
vented to the outside atmosphere, with the relief valve set to open so that the pressure of gas going to the customer does not exceed a maximum safe value. The relief valve may either be built into the service regulator or it may be a separate unit installed downstream from the service regulator. This combination may be used alone only in those cases where the inlet pressure on the service regulator does not exceed the manufacturer’s safe working pressure rating of the service regulator, and may not be used where the inlet pressure on the service regulator exceeds sixty (60) psi (414 kPa) gauge. For higher inlet pressure, the methods in paragraph (4)(DD)1. or 2. must be used; or
shutoff device that closes upon a rise in pressure downstream from the regulator and remains closed until manually reset.
(EE) Requirements for Design of Pressure Relief and Limiting Devices. (192.199) Except for rupture discs, each pressure relief or pressure limiting device must—
the operation of the device will not be impaired by corrosion;
designed not to stick in a position that will make the device inoperative;
can be readily operated to determine if the valve is free, can be tested to determine the pressure at which it will operate and can be tested for leakage when in the closed position;
bustible material;
let ports designed to prevent accumulation of water, ice, or snow, located where gas can be discharged into the atmosphere without undue hazard;
size of the openings, pipe and fittings located between the system to be protected and the pressure relieving device, and the size of the vent line, are adequate to prevent hammering of the valve and to prevent impairment of relief capacity;
station to protect a pipeline system from overpressuring, be designed and installed to 20 CSR 4240-40
prevent any single incident, for instance, an explosion in a vault or damage by a vehicle, from affecting the operation of both the overpressure protective device and the district regulator;
system under protection from its source of pressure, be designed to prevent unauthorized access to or operation of the following stop valves regardless of installation date:
sure relief valve or pressure limiting device inoperative;
lator or relief devices; and
that, if operated, would cause the regulator or overpressure protection device to be inoperative;
quate overpressure protection is provided for all town border stations and district regulator stations regardless of installation date;
for overpressure protection, be designed and installed to include an internal or separate device or method that indicates a failure of the operating regulator regardless of installation date. The operating regulator must be monitored at least monthly for regulator stations for detection of a failure; and
ing monitors are used for overpressure protection, be designed and installed to include an internal or separate device or method that indicates a failure of each regulator regardless of installation date. Each regulator must be monitored at least monthly for regulator stations for detection of a failure. When the operator chooses to use a pressure gauge as the separate device to comply with paragraph (4)(EE)10. or 11., the pressure gauge must have the capability to record the high pressure, such as a recording chart or “tattle-tale” needle (a standard sight gauge is not adequate for this purpose).
(FF) Required Capacity of Pressure Relieving and Limiting Stations. (192.201)
sure limiting station or group of those stations installed to protect a pipeline must have enough capacity, and must be set to operate, to ensure the following:
tem, the pressure may not cause the unsafe operation of any connected and properly adjusted gas utilization equipment; and
sure distribution system—
ating pressure is sixty (60) psi (414 kPa) gauge or more, the pressure may not exceed AND INSURANCE
the maximum allowable operating pressure plus ten percent (10%) or the pressure that produces a hoop stress of seventy-five percent (75%) of SMYS, whichever is lower;
operating pressure is twelve (12) psi (83 kPa) gauge or more, but less than sixty (60) psi (414 kPa) gauge, the pressure may not exceed the maximum allowable operating pressure plus six (6) psi (41 kPa) gauge; or
operating pressure is less than twelve (12) psi (83 kPa) gauge, the pressure may not exceed the maximum allowable operating pressure plus fifty percent (50%).
ulating or compressor station feeds into a pipeline, relief valves or other protective devices must be installed at each station to ensure that the complete failure of the largest capacity regulator or compressor, or any single run of lesser capacity regulators or compressors in that station, will not impose pressures on any part of the pipeline or distribution system in excess of those for which it was designed, or against which it was protected, whichever is lower.
ing devices must be installed at or near each regulator station in a low-pressure distribution system, with a capacity to limit the maximum pressure in the main to a pressure that will not exceed the safe operating pressure for any connected and properly adjusted gas utilization equipment.
(GG) Instrument, Control, and Sampling Pipe and Components. (192.203)
to the design of instrument, control, and sampling pipe and components. It does not apply to permanently closed systems, such as fluidfilled temperature-responsive devices.
employed for pipe and components must be designed to meet the particular conditions of service and the following:
attaching boss, fitting, or adapter must be made of suitable material, be able to withstand the maximum service pressure and temperature of the pipe or equipment to which it is attached, and be designed to satisfactorily withstand all stresses without failure by fatigue;
isolated from sources of pressure by other valving, a shutoff valve must be installed in each takeoff line as near as practicable to the point of takeoff. Blowdown valves must be installed where necessary;
be used for metal temperatures greater than four hundred degrees Fahrenheit (400 °F) (204 °C);
tain liquids must be protected by heating or other means from damage due to freezing;
uids may accumulate must have drains or drips;
clogging from solids or deposits must have suitable connections for cleaning;
nents, and supports must provide safety under anticipated operating stresses;
pipe, and between pipe and valves or fittings, must be made in a manner suitable for the anticipated pressure and temperature condition. Slip-type expansion joints may not be used. Expansion must be allowed for by providing flexibility within the system itself; and
from anticipated causes of damage and must be designed and installed to prevent damage to any one (1) control line from making both the regulator and the overpressure protective device inoperative.
(HH) Passage of Internal Inspection Devices. (192.150)
(4)(HH)2. and (4)(HH)3., each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line must be designed and constructed to accommodate the passage of instrumented internal inspection devices in accordance with NACE SP0102, section 7 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
2. This subsection does not apply to—
sor stations, meter stations, or regulator stations;
facilities, other than a continuous run of transmission line between a compressor station and storage facilities;
mented internal inspection device is not commercially available;
conjunction with a distribution system which are installed in Class 4 locations; and
190.9, the administrator finds in a particular case would be impracticable to design and construct to accommodate the passage of instrumented internal inspection devices.
cies, construction time constraints, or other unforeseen construction problems need not construct a new or replacement segment of a transmission line to meet paragraph (4)(HH)1., if the operator determines and documents why an impracticability prohibits compliance with paragraph (4)(HH)1. Within thirty (30) days of discovering the emergency or construction problem, the operator must petition, under 49 CFR 190.9, for approval that design and construction to accommodate passage of instrumented internal inspection devices would be impracticable. If the petition is denied, within one (1) year after the date of the notice of the denial, the operator must modify that segment to allow passage of instrumented internal inspection devices.
(II) Records: Pipeline Components. (192.205)
installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records documenting the manufacturing standard and pressure rating to which each valve was manufactured and tested in accordance with this section. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of forty-two thousand (42,000) psi (X42) or greater and with nominal diameters of greater than two inches (2") must have records documenting the manufacturing specification in effect at the time of manufacture, including yield strength, ultimate tensile strength, and chemical composition of materials.
installed on or before July 1, 2020, if operators have records documenting the manufacturing standard and pressure rating for valves, flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of forty-two thousand (42,000) psi (X42) or greater and with nominal diameters of greater than two inches (2"), operators must retain such records for the life of the pipeline.
ments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of subsection (12)(U) (192.624) according to the terms of that subsection.
(5) Welding of Steel in Pipelines.
(A) Scope. (192.221)
requirements for welding steel materials in pipelines.
ing that occurs during the manufacture of steel pipe or steel pipeline components.
(B) General.
accordance with established written welding procedures that have been qualified under subsection (5)(C) (192.225) to produce sound, ductile welds.
welders who are qualified under subsections (5)(D) and (E) (192.227 and 192.229) for the welding procedure to be used.
(C) Welding Procedures. (192.225)
qualified welder or welding operator in accordance with welding procedures qualified under section 5, section 12, Appendix A, or Appendix B of API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) or section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) to produce welds meeting the requirements of section (5) of this rule. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the referenced welding standard(s).
recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used.
(D) Qualification of Welders and Welding Operators. (192.227)
(5)(D)2., each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A, or Appendix B of API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) or section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). However, a welder or welding operator qualified under an earlier edition of a standard listed in 49 CFR 192.7 (see subsection (1)(D)) may weld but may not requalify under that earlier edition.
welding on pipe to be operated at a pressure that produces a hoop stress of less than twenty percent (20%) of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in subsection I. of Appendix C, which is included herein (at the end of this rule). Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under subsection II. of Appendix C as a requirement of the qualifying test.
after July 1, 2021, records demonstrating each individual welder qualification at the time of construction in accordance with this section must be retained for a minimum of five (5) years following construction.
(E) Limitations on Welders and Welding Operators. (192.229)
qualification is based on nondestructive testing may weld compressor station pipe and components.
weld with a particular welding process unless, within the preceding six (6) calendar months, the welder or welding operator was engaged in welding with that process.
fied under paragraph (5)(D)1. (192.227[a])—
ated at a pressure that produces a hoop stress of twenty percent (20%) or more of SMYS unless within the preceding six (6) calendar months the welder or welding operator has had one (1) weld tested and found acceptable under section 6, section 9, section 12, or Appendix A of API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). Alternatively, welders or welding operators may maintain an ongoing qualification status by performing welds tested and found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals not exceeding seven and one-half (7 1/2) months. A welder or welding operator qualified under an earlier edition of a standard listed in 49 CFR 192.7 (see subsection (1)(D)) may weld, but may not requalify under that earlier edition; and
ated at a pressure that produces a hoop stress of less than twenty percent (20%) of SMYS unless the welder or welding operator is tested in accordance with subparagraph (5)(E)3.A. or requalifies under subparagraph (5)(E)4.A. or B.
fied under paragraph (5)(D)2. may not weld unless—
calendar months, but at least once each calendar year, the welder or welding operator has requalified under paragraph (5)(D)2.; or
one-half (7 1/2) calendar months, but at least twice each calendar year, the welder or welding operator has had—
ed, and found acceptable in accordance with the qualifying test; or
on service lines two inches (2") (51 millimeters) or smaller in diameter, two (2) sample welds tested and found acceptable in accordance with the test in subsection III. of Appendix C to this rule.
The welding operation must be protected from weather conditions that would impair the quality of the completed weld.
(G) Miter Joints. (192.233)
ated at a pressure that produces a hoop stress of thirty percent (30%) or more of SMYS may not deflect the pipe more than three degrees (3°).
ated at a pressure that produces a hoop stress of less than thirty percent (30%), but more than ten percent (10%), of SMYS may not deflect the pipe more than twelve and onehalf degrees (12 1/2°) and must be a distance equal to one (1) pipe diameter or more away from any other miter joint, as measured from the crotch of each joint.
ated at a pressure that produces a hoop stress of ten percent (10%) or less of SMYS may not deflect the pipe more than ninety degrees (90°).
(I) Inspection and Test of Welds. (192.241)
conducted by an individual qualified by appropriate training and experience to ensure that—
accordance with the welding procedure; and
graph (5)(I)3.
ed at a pressure that produces a hoop stress of twenty percent (20%) or more of SMYS must be nondestructively tested in accordance with subsection (5)(J), except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if—
of less than six inches (6") (152 millimeters); or
pressure that produces a hoop stress of less than forty percent (40%) of SMYS and the welds are so limited in number that nondestructive testing is impractical.
nondestructively tested or visually inspected is determined according to the standards in section 9 or Appendix A of API Standard 1104 (incorporated by reference in 49 CFR AND INSURANCE
192.7 and adopted in subsection (1)(D)). Appendix A of API Standard 1104 may not be used to accept cracks.
(J) Nondestructive Testing. (192.243)
be performed by any process, other than trepanning, that will clearly indicate the defects that may affect the integrity of the weld.
be performed—
dures; and
and qualified in the established procedures and with the equipment employed in testing.
the proper interpretation of each nondestructive test of a weld to ensure the acceptability of the weld under paragraph (5)(I)3. (192.241[c]).
required under paragraph (5)(I)2. (192.241[b]), the following percentages of each day’s field butt welds, selected at random by the operator, must be nondestructively tested over their entire circumference:
percent (10%);
percent (15%);
crossings of major or navigable rivers and within railroad or public highway rights-ofway, including tunnels, bridges, and overhead road crossings, one hundred percent (100%) unless impracticable, in which case at least ninety percent (90%). Nondestructive testing must be impracticable for each girth weld not tested; and
ins of replacement sections, one hundred percent (100%).
ator whose work is isolated from the principal welding activity, a sample of each welder or welding operator’s work for each day must be nondestructively tested, when that testing is required under paragraph (5)(I)2. (192.241[b]).
required under paragraph (5)(I)2. (192.241[b]), each operator must retain, for the life of the pipeline, a record showing, by milepost, engineering station, or by geographic feature, the number of girth welds made, the number nondestructively tested, the number rejected and the disposition of the rejects.
(K) Repair or Removal of Defects. (192.245)
paragraph (5)(I)3. (192.241[c]) must be removed or repaired. A weld must be removed if it has a crack that is more than eight percent (8%) of the weld length.
the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely affect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability.
a previously repaired area must be in accordance with written weld repair procedures that have been qualified under subsection (5)(C) (192.225). Repair procedures must provide that the minimum mechanical properties specified for the welding procedure used to make the original weld are met upon completion of the final weld repair.
(6) Joining of Materials Other Than by Welding.
(A) Scope. (192.271)
requirements for joining materials in pipelines, other than by welding.
during the manufacture of pipe or pipeline components.
(B) General. (192.273)
installed so that each joint will sustain the longitudinal pullout or thrust forces caused by contraction or expansion of the piping or by anticipated external or internal loading.
dance with written procedures that have been proved by test or experience to produce strong gastight joints.
ensure compliance with this section.
(C) Cast Iron Pipe. (192.275)
cast iron pipe must be sealed with mechanical leak clamps.
pipe must have a gasket made of a resilient material as the sealing medium. Each gasket must be suitably confined and retained under compression by a separate gland or follower ring.
threaded joints.
brazing.
(D) Ductile Iron Pipe. (192.277)
by threaded joints.
by brazing.
(F) Plastic Pipe (192.281)
joined by solvent cement, adhesive, or heat fusion may not be disturbed until it has properly set. Plastic pipe may not be joined by a threaded joint or miter joint.
cement joint on plastic pipe must comply with the following:
must be clean, dry, and free of material which might be detrimental to the joint;
to ASTM D 2564-12 for PVC (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)); and
cooled to accelerate the setting of the cement.
joint on a PE pipe or component, except for electrofusion joints, must comply with ASTM F2620-12 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) and the following:
joined by a device that holds the heater element square to the ends of the pipe or component, compresses the heated ends together, and holds the pipe in proper alignment in accordance with the appropriate procedure qualified under subsection (6)(G);
joined by a device that heats the mating surfaces of the pipe or component uniformly and simultaneously to establish the same temperature. The device used must be the same device specified in the operator’s joining procedure for socket fusion;
made using the equipment and techniques prescribed by the fitting manufacturer or using equipment and techniques shown, by testing joints to the requirements of part (6)(G)1.A.(III), to be equivalent or better than the requirements of the fitting manufacturer; and
torch or other open flame.
type mechanical joint on plastic pipe must comply with the following:
pling must be compatible with the plastic;
other than a split tubular stiffener, must be used in conjunction with the coupling;
a listed specification based upon the applicable material; and
installed after April 22, 2019, must be Category 1 as defined by a listed specification for the applicable material, providing a seal plus resistance to a force on the pipe joint equal to or greater than that which will cause no less than 25% elongation of pipe, or the pipe fails outside the joint area if tested in accordance with the applicable standard.
(G) Plastic Pipe—Qualifying Joining Procedures. (192.283)
adhesive joints. Before any written procedure established under paragraph (6)(B)2. is used for making plastic pipe joints by a heat fusion, solvent cement, or adhesive method, the procedure must be qualified by subjecting specimen joints made according to the procedure to the following tests, as applicable:
A. The test requirements of—
pipe, based on the pipe material, the Sustained Pressure Test or the Minimum Hydrostatic Burst Test per the listed specification requirements. Additionally, for electrofusion joints, based on the pipe material, the Tensile Strength Test or the Joint Integrity Test per the listed specification;
tings for polyethylene pipe and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM F1055-98(2006) (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D));
pipe connections, subject a specimen joint made from pipe sections joined at right angles according to the procedure to a force on the lateral pipe until failure occurs in the specimen. If failure initiates outside the joint area, the procedure qualifies for use; and
lateral pipe connections, perform testing in accordance with a listed specification. If the test specimen elongates no less than twentyfive percent (25%) or failure initiates outside the joint area, the procedure qualifies for use.
procedure established under paragraph (6)(B)2. is used for making mechanical plastic pipe joints, the procedure must be qualified in accordance with a listed specification based upon the pipe material.
being used for joining plastic pipe must be available to the persons making and inspecting joints.
(H) Plastic Pipe—Qualifying Persons to Make Joints. (192.285)
joint unless that person has been qualified under the applicable joining procedure by—
in the use of the procedure; and
sections joined according to the procedure that passes the inspection and test set forth in paragraph (6)(H)2.
2. The specimen joint must be—
assembly or joining and found to have the same appearance as a joint or photographs of a joint that is acceptable under the procedure; and
cement, or adhesive joint—
test methods listed under paragraph (6)(G)1. (192.283[a]), or for polyethylene heat fusion joints (except for electrofusion joints) visually inspected and tested in accordance with ASTM F2620-12 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) applicable to the type of joint and material being tested;
tion and found not to contain flaws that would cause failure; or
gitudinal straps, each of which is—
not to contain voids or discontinuities on the cut surfaces of the joint area; and
torque, or impact and, if failure occurs, it must not initiate in the joint area.
an applicable procedure once each calendar year at intervals not exceeding fifteen (15) months, or after any production joint is found unacceptable by testing under subsection (10)(G). (192.513)
method to determine that each person making joints in plastic pipelines in the operator’s system is qualified in accordance with this subsection.
July 1, 2021, records demonstrating each person’s plastic pipe joining qualifications at the time of construction in accordance with this section must be retained for a minimum of five (5) years following construction.
(7) General Construction Requirements for Transmission Lines and Mains.
(E) Repair of Steel Pipe. (192.309)
impairs the serviceability of a length of steel pipe must be repaired or removed. If a repair is made by grinding, the remaining wall thickness must at least be equal to either—
by the tolerances in the specification to which the pipe was manufactured; or
required for the design pressure of the pipeline.
removed from steel pipe to be operated at a pressure that produces a hoop stress of twenty percent (20%) or more of SMYS, unless the dent is repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe:
centrator such as a scratch, gouge, groove, or arc burn;
weld or a circumferential weld; and
that produces a hoop stress of forty percent (40%) or more of SMYS, a dent that has a depth of—
(1/4") (6.4 millimeters) in pipe twelve and three-quarters inches (12 3/4") (324 millimeters) or less in outer diameter; or
the nominal pipe diameter in pipe over twelve and three-quarters inches (12 3/4") (324 millimeters) in outer diameter. For the purpose of this subsection, 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 AND INSURANCE
between the lowest point of the dent and a prolongation of the original contour of the pipe.
operated at a pressure that produces a hoop stress of forty percent (40%) or more of SMYS must be repaired or removed. If a repair is made by grinding, the arc burn must be completely removed and the remaining wall thickness must be at least equal to either—
required by the tolerances in the specification to which the pipe was manufactured; or
required for the design pressure of the pipeline.
may not be repaired by insert patching or by pounding out.
that is removed from a length of pipe must be removed by cutting out the damaged portion as a cylinder.
(G) Bends and Elbows. (192.313)
than a wrinkle bend made in accordance with subsection (7)(H) (192.315), must comply with the following:
viceability of the pipe;
contour and be free from buckling, cracks, or any other mechanical damage; and
weld, the longitudinal weld must be as near as practicable to the neutral axis of the bend unless—
nal bending mandrel; or
(305 millimeters) or less in outside diameter or has a diameter-to-wall thickness ratio less than seventy (70).
pipe which is located where the stress during bending causes a permanent deformation in the pipe must be nondestructively tested either before or after the bending process.
transverse segments of these elbows may not be used for changes in direction on steel pipe that is two inches (2") (51 millimeters) or more in diameter unless the arc length, as measured along the crotch, is at least one inch (1") (25 millimeters).
pipe with a bend radius that is less than the minimum bend radius specified by the manufacturer for the diameter of the pipe being installed.
(H) Wrinkle Bends in Steel Pipe. (192.315)
steel pipe to be operated at a pressure that produces a hoop stress of thirty percent (30%), or more, of SMYS.
comply with the following:
kinks;
the bend, the wrinkles must be a distance of at least one (1) pipe diameter;
millimeters) or larger in diameter, the bend may not have a deflection of more than one and one-half degrees (1 1/2°) for each wrinkle; and
weld, the longitudinal seam must be as near as practicable to the neutral axis of the bend.
(I) Protection From Hazards. (192.317)
steps to protect each transmission line or main from washouts, floods, unstable soil, landslides, or other hazards that may cause the pipeline to move or to sustain abnormal loads.
or main, not located in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades.
each platform located in inland navigable waters must be protected from accidental damage by vessels.
(J) Installation of Pipe in a Ditch. (192.319)
mission line that is to be operated at a pressure producing a hoop stress of twenty percent (20%) or more of SMYS must be installed so that the pipe fits the ditch so as to minimize stresses and protect the pipe coating from damage.
or main is backfilled, it must be backfilled in a manner that—
pipe; and
pipe coating from equipment or from the backfill material.
(K) Installation of Plastic Pipe. (192.321)
ground level except as provided by paragraphs (7)(K)7., (7)(K)8., and (7)(K)9.
or any other below grade enclosure must be completely encased in gastight metal pipe and fittings that are adequately protected from corrosion.
minimize shear or tensile stresses.
wall thickness in accordance with (3)(I).
have an electrically conductive wire or other means of locating the pipe while it is underground. Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means.
must be inserted into the casing pipe in a manner that will protect the plastic. Plastic pipe that is being encased must be protected from damage at all entrance and all exit points of the casing. The leading end of the plastic must be closed before insertion.
porarily installed above-ground level under the following conditions:
demonstrate that the cumulative aboveground exposure of the pipe does not exceed the manufacturer’s recommended maximum period of exposure or two (2) years, whichever is less;
damage by external forces is unlikely or is otherwise protected against such damage; and
sure to ultraviolet light and high and low temperatures.
bridges provided that it is—
mechanical damage, such as installation in a metallic casing;
tion; and
temperature limits specified in subsection (3)(I).
ground level provided they comply with the following:
plastic main is protected against deterioration and external damage;
port external loads; and
stations must meet the design requirements of (4)(AA).
(L) Casing. (192.323) Each casing used on a transmission line or main under a railroad or highway must comply with the following:
stand the superimposed loads;
ing the casing, the ends must be sealed;
sealed and the sealing is strong enough to retain the maximum allowable operating pressure of the pipe, the casing must be designed to hold this pressure at a stress level of not more than seventy-two percent (72%) of SMYS; and
vents must be protected from the weather to prevent water from entering the casing.
(M) Underground Clearance. (192.325)
installed with at least twelve inches (12") (305 millimeters) of clearance from any other underground structure not associated with the transmission line. If this clearance cannot be attained, the transmission line must be protected from damage that might result from the proximity of the other structure.
enough clearance from any other underground structure to allow proper maintenance and to protect against damage that might result from proximity to other structures.
ments of paragraph (7)(M)1. or 2., each plastic transmission line or main must be installed with sufficient clearance, or must be insulated, from any source of heat so as to prevent the heat from impairing the serviceability of the pipe.
must be installed with a minimum clearance from any other holder as prescribed in paragraph (4)(S)2. (192.175[b])
(N) Cover. (192.327)
(7)(N)3. and 5., each buried transmission line must be installed with a minimum cover as follows: Normal Consolidated Soil Rock Location 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)
(7)(N)3. and 4., each buried main must be installed with at least twenty-four inches (24") (610 millimeters) of cover.
vents the installation of a transmission line or main with the minimum cover, the transmission line or main may be installed with less cover if it is provided with additional protection to withstand anticipated external loads.
than twenty-four inches (24") (610 millimeters) of cover if the law of the state or municipality—
less than twenty-four inches (24") (610 millimeters);
a common trench with other utility lines; and
of damage to the pipe by external forces.
(7)(N)3., all pipe installed in a navigable river, stream, or harbor must be installed with a minimum cover of forty-eight inches (48") (1219 millimeters) in soil or twentyfour inches (24") (610 millimeters) in consolidated rock between the top of the pipe and the underwater natural bottom (as determined by recognized and generally accepted practices).
(P) Installation of Plastic Pipelines by Trenchless Excavation. (192.329) Plastic pipelines installed by trenchless excavation must comply with the following:
steps to provide sufficient clearance for installation and maintenance activities from other underground utilities and/or structures at the time of installation; and
and components that are pulled through the ground must use a weak link, as defined in subsection (1)(B), to ensure the pipeline will not be damaged by any excessive forces during the pulling process.
(8) Customer Meters, Service Regulators, and Service Lines.
(B) Service Lines and Yard Lines.
dential/small commercial yard line replacements made after December 15, 1989, must be installed, owned, operated, and maintained by the operator regardless of meter location. Installations of customer-owned service lines and residential/small commercial yard lines, as defined in (1)(B) (192.3), will not be permitted. If the customer meter is not located within five feet (5') of the building wall, the service line to the customer’s nearest building shall be installed, owned, operated, and maintained by the operator. Installation and maintenance may be performed by representatives approved by the operator and the operator must assure that the work performed by approved representatives is in compliance with the requirements of this rule.
cial/industrial customers may be installed or replaced, owned, and maintained, except for leak surveys, by the customer, provided the new yard line is cathodically protected, coated steel, or polyethylene pipe and the operator’s installation standards are met.
(C) Customer Meters and Regulators— Location. (192.353)
whether inside or outside of a building, must be installed in a readily accessible location and be protected from corrosion and other damage, including, if installed outside a building, vehicular damage that may be anticipated. However, the upstream regulator in a series may be buried.
in a building must be located as near as practical to the point of service line entrance.
must be located in a ventilated place and not less than three feet (3') (914 millimeters) from any source of ignition or any source of heat which might damage the meter.
tor in a series must be located outside the building, unless it is located in a separate metering or regulating building.
(D) Customer Meters and Regulators— Protection From Damage. (192.355)
sure. If the customer’s equipment might create either a vacuum or a back pressure, a device must be installed to protect the system.
vents. Service regulator vents and relief vents must terminate outdoors and the outdoor terminal must—
from the vent can escape freely into the atmosphere and away from any opening into the AND INSURANCE
building; and
by submergence in areas where flooding may occur.
houses a customer meter or regulator at a place where vehicular traffic is anticipated must be able to support that traffic.
(E) Customer Meters and Regulators— Installation. (192.357)
be installed so as to minimize anticipated stresses upon the connecting piping and the meter.
used, the wall thickness remaining after the threads are cut must meet the minimum wall thickness requirements of this rule.
easily damaged material may not be used in the installation of meters or regulators.
must be vented to the atmosphere outside the building.
(F) Customer Meter Installations— Operating Pressure. (192.359)
that is more than sixty-seven percent (67%) of the manufacturer’s shell test pressure.
tured after November 12, 1970, must have been tested to a minimum of ten (10) psi (69 kPa) gauge.
meter may not be used at a pressure that is more than fifty percent (50%) of the pressure used to test the meter after rebuilding or repairing.
(G) Service Lines—Installation. (192.361)
be installed with at least twelve inches (12") (305 millimeters) of cover in private property and at least eighteen inches (18") (457 millimeters) of cover in streets and roads, except a plastic service line that is not inserted in a metallic casing must be installed with at least eighteen inches (18") (457 millimeters) of cover in all locations. However, where an underground structure prevents installation at those depths, the service line must be able to withstand any anticipated external load.
line must be properly supported on undisturbed or well-compacted soil, and material used for backfill must be free of materials that could damage the pipe or its coating.
sate in the gas might cause interruption in the gas supply to the customer, the service line must be graded so as to drain into the main or into drips at the low points in the service line.
external loading. Each service line must be installed so as to minimize anticipated piping strain and external loading.
ings. Each underground service line installed below grade through the outer foundation wall of a building must—
be protected against corrosion;
be protected from shearing action and backfill settlement; and
prevent leakage into the building.
buildings. Where an underground service line is installed under a building—
conduit;
must extend, if the service line supplies the building it underlies, into a normally usable and accessible part of the building; and
the service line must be sealed to prevent gas leakage into the building and, if the conduit is sealed at both ends, a vent line from the annular space must extend to a point where gas would not be a hazard, and extend above grade, terminating in a rain and insect resistant fitting.
Each underground nonmetallic service line that is not encased must have a means of locating the pipe that complies with paragraph (7)(K)5.
(H) Service Lines—Valve Requirements. (192.363)
line valve that meets the applicable requirements of sections (2) and (4) of this rule. A valve incorporated in a meter bar, that allows the meter to be bypassed, may not be used as a service line valve.
be used if its ability to control the flow of gas could be adversely affected by exposure to anticipated heat.
pressure service line, installed aboveground or in an area where the blowing of gas would be hazardous, must be designed and constructed to minimize the possibility of the removal of the core of the valve with other than specialized tools.
(I) Service Lines—Location of Valves. (192.365)
service line valve must be installed upstream of the regulator or, if there is no regulator, upstream of the meter.
must have a shut-off valve in a readily accessible location that is outside of the building.
ground service line valve must be located in a covered durable curb box or standpipe that allows ready operation of the valve and is supported independently of the service lines.
(J) Service Lines—General Requirements for Connections to Main Piping. (192.367)
tion to a main must be located at the top of the main or, if that is not practical, at the side of the main, unless a suitable protective device is installed to minimize the possibility of dust and moisture being carried from the main into the service line.
main. Each compression-type service line to main connection must—
tively sustain the longitudinal pullout or thrust forces caused by contraction or expansion of the piping, or by anticipated external or internal loading;
the service line to the main connection fitting, have gaskets that are compatible with the kind of gas in the system; and
plastic, be a Category 1 connection as defined by a listed specification for the applicable material, providing a seal plus resistance to a force on the pipe joint equal to or greater than that which will cause no less than 25% elongation of pipe, or the pipe fails outside the joint area if tested in accordance with the applicable standard.
(K) Service Lines—Connections to Cast Iron or Ductile Iron Mains. (192.369)
iron or ductile iron main must be connected by a mechanical clamp, by drilling and tapping the main, or by another method meeting the requirements of subsection (6)(B). (192.273)
requirements of paragraphs (4)(G)2. and 3. (192.151[b] and [c]) must also be met.
(M) Service Lines—Plastic. (192.375)
building must be installed below ground level, except that—
with paragraph (7)(K)7.; and
and outside the building, if—
the plastic service line is protected against deterioration and external damage;
used to support external loads; and
vice line meets the design requirements of (4)(AA).
installed inside a building.
grade vault or pit must be completely encased in gastight metal pipe and fittings that are adequately protected from corrosion.
minimize shear or tensile stresses.
encased must have a minimum wall thickness of 0.090 inches (0.090"), except that pipe with an outside diameter of 0.875 inches (0.875") or less may have a minimum wall thickness of 0.062 inches (0.062").
must be inserted into the casing pipe in a manner that will protect the plastic. The leading end of the plastic must be closed before insertion.
lation of plastic service lines by trenchless excavation, see subsection (8)(R). (192.376)
(N) New Service Lines Not in Use. (192.379) Each service line that is not placed in service upon completion of installation must comply with one (1) of the following until the customer is supplied with gas:
flow of gas to the customer must be provided with a locking device or other means designed to prevent the opening of the valve by persons other than those authorized by the operator;
will prevent the flow of gas must be installed in the service line or in the meter assembly; or
ically disconnected from the gas supply and the open pipe ends sealed.
(O) Service Lines—Excess Flow Valve Performance Standards. (192.381)
vice lines that operate continuously throughout the year at a pressure not less than ten (10) psi (69 kPa) must be manufactured and tested by the manufacturer according to an industry specification, or the manufacturer’s written specification, to ensure that each valve will—
mum operating pressure at which the valve is rated;
tures reasonably expected in the operating environment of the service line;
C. At ten (10) psi (69 kPa) gauge:
percent (50%) above, the rated closure flow rate specified by the manufacturer; and
flow—
designed to allow pressure to equalize across the valve, to no more than five percent (5%) of the manufacturer’s specified closure flow rate, up to a maximum of twenty (20) cubic feet per hour (0.57 cubic meters per hours); or
designed to prevent equalization of pressure across the valve, to no more than 0.4 cubic feet per hour (0.01 cubic meters per hour); and
than the manufacturer’s minimum specified operating pressure and the flow rate is below the manufacturer’s minimum specified closure flow rate.
applicable requirements of sections (2) and (4).
identify the presence of an excess flow valve in the service line.
flow valve as near as practical to the fitting connecting the service line to its source of gas supply.
excess flow valve on a service line where the operator has prior experience with contaminants in the gas stream, where these contaminants could be expected to cause the excess flow valve to malfunction or where the excess flow valve would interfere with necessary operation and maintenance activities on the service line, such as blowing liquids from the service line.
(P) Excess Flow Valve Installation. (192.383)
1. Definitions for subsection (8)(P).
service line that begins at the existing service line or is installed concurrently with the primary service line but serves a separate residence.
service line where the fitting that connects the service line to the main is replaced or the piping connected to this fitting is replaced.
residence means a gas service line that begins at the fitting that connects the service line to the main and serves only one (1) single-family residence. 20 CSR 4240-40
valve (EFV) installation must comply with the performance standards in subsection (8)(O). After April 14, 2017, each operator must install an EFV on any new or replaced service line serving the following types of services before the line is activated:
single family residence;
family residence installed concurrently with the primary single family residence service line (i.e., a single EFV may be installed to protect both service lines);
family residence installed off a previously installed single family residence service line that does not contain an EFV;
known customer loads not exceeding one thousand standard cubic feet per hour (1,000 SCFH) per service, at time of service installation, based on installed meter capacity; and
tomer served by a single service line with a known customer load not exceeding one thousand standard cubic feet per hour (1,000 SCFH), at the time of meter installation, based on installed meter capacity.
installation requirement. An operator need not install an excess flow valve if one (1) or more of the following conditions are present:
at a pressure of ten (10) psi gauge or greater throughout the year;
with contaminants in the gas stream that could interfere with the EFV’s operation or cause loss of service to a residence;
essary operation or maintenance activities, such as blowing liquids from the line; or
standards in subsection (8)(O) is not commercially available to the operator.
Existing service line customers who desire an EFV on service lines not exceeding one thousand standard cubic feet per hour (1,000 SCFH) and who do not qualify for one (1) of the exceptions in paragraph (8)(P)3. may request an EFV to be installed on their service lines. If an eligible service line customer requests an EFV installation, an operator must install the EFV at a mutually agreeable date. The operator’s rate-setter determines how and to whom the costs of the requested EFVs are distributed.
concerning EFV installation. Operators must notify customers of their right to request an AND INSURANCE
EFV in the following manner:
(8)(P)5.E., each operator must provide written or electronic notification to customers of their right to request the installation of an EFV. Electronic notification can include emails, website postings, and e-billing notices;
explanation for the service line customer of the potential safety benefits that may be derived from installing an EFV. The explanation must include information that an EFV is designed to shut off the flow of natural gas automatically if the service line breaks;
description of EFV installation and replacement costs. The notice must alert the customer that the costs for maintaining and replacing an EFV may later be incurred, and what those costs will be to the extent known;
if a service line customer requests installation of an EFV and the load does not exceed one thousand standard cubic feet per hour (1,000 SCFH) and the conditions of paragraph (8)(P)3. are not present, the operator must install an EFV at a mutually agreeable date; and
may continuously post a general notification in a prominent location frequented by customers.
cation. An operator must make a copy of the notice or notices currently in use available during inspections conducted by designated commission personnel.
master meter systems, each operator must report the EFV measures detailed in the annual report required by 20 CSR 4240- 40.020(7)(A).
(Q) Manual Service Line Shut-Off Valve Installation (192.385)
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.
tor must install either a manual service line shut-off valve or, if possible, based on sound engineering analysis and availability, an EFV for any new or replaced service line with installed meter capacity exceeding 1,000 SCFH.
Manual service line shut-off valves for any new or replaced service line must be installed in such a way as to allow accessibility during emergencies. Manual service shut-off valves installed under this subsection are subject to regular scheduled maintenance, as documented by the operator and consistent with the valve manufacturer’s specification.
(R) Installation of Plastic Service Lines by Trenchless Excavation. (192.376) Plastic service lines installed by trenchless excavation must comply with the following:
steps to provide sufficient clearance for installation and maintenance activities from other underground utilities and structures at the time of installation; and
and components that are pulled through the ground must use a weak link, as defined in subsection (1)(B), to ensure the pipeline will not be damaged by any excessive forces during the pulling process.
(9) Requirements for Corrosion Control.
(B) How Does this Section Apply to Converted Pipelines and Regulated Onshore Gathering Lines? (192.452)
the date the pipeline was installed or any earlier deadlines for compliance, each pipeline which qualifies for use under this rule in accordance with subsection (1)(H) must have a cathodic protection system designed to protect the pipeline in its entirety in accordance with subsection (9)(H) within one (1) year after the pipeline is readied for service.
For any regulated onshore gathering line to which 49 CFR 192.8 and 192.9 did not apply until April 14, 2006, and for any gathering line that becomes a regulated onshore gathering line under subsection (1)(E) because of a change in class location or increase in dwelling density:
specifically applicable to pipelines installed before August 1, 1971, apply to the gathering line regardless of the date the pipeline was actually installed; and
specifically applicable to pipelines installed after July 31, 1971, apply only if the pipeline substantially meets those requirements.
(D) External Corrosion Control—Buried or Submerged Pipelines Installed After July 31, 1971. (192.455)
(9)(D)2., 5., and 6., each buried or submerged pipeline installed after July 31, 1971, must be protected against external corrosion, including the following:
coating meeting the requirements of subsection (9)(G) (192.461); and
system designed to protect the pipeline in accordance with this section, installed and placed in operation within one (1) year after completion of construction.
paragraph (9)(D)1., if the operator can demonstrate by tests, investigation, or experience that—
environment does not exist; or
operating period of service not to exceed five (5) years beyond installation, corrosion during the five- (5-) year period of service of the pipeline will not be detrimental to public safety.
paragraph (9)(D)2., if a pipeline is externally coated, it must be cathodically protected in accordance with subparagraph (9)(D)1.B.
buried or submerged pipeline if that aluminum is exposed to an environment with a natural pH in excess of eight (8), unless tests or experience indicate its suitability in the particular environment involved.
electrically isolated, metal alloy fittings in plastic pipelines, if—
operator can show by test, investigation, or experience in the area of application that adequate corrosion control is provided by the alloy composition; and
leaking caused by localized corrosion pitting.
tings installed after April 22, 2019, that do not meet the requirements of paragraph (9)(D)5. must be cathodically protected, and must be maintained in accordance with the operator’s integrity management plan.
(E) External Corrosion Control—Buried or Submerged Pipelines Installed Before August 1, 1971. (192.457)
sion line and each buried or submerged feeder line or main in excess of one hundred feet (100') installed before August 1, 1971, that has an effective external coating must be cathodically protected along the entire area that is effectively coated, in accordance with this section unless definitely scheduled in a replacement program in subsection (15)(E). For the purposes of this section, a pipeline does not have an effective external coating if its cathodic protection current requirements are substantially the same as if it were bare. The operator shall make tests to determine the cathodic protection current requirements.
each of the following buried or submerged pipelines installed before August 1, 1971, must be cathodically protected in accordance with this section in areas in which active corrosion is found:
mission lines;
mains not in excess of one hundred feet (100');
lines or mains; and
except that steel service lines must be replaced as required by subsection (15)(C).
(G) External Corrosion Control—Protective Coating. (192.461)
applied for the purpose of external corrosion control must—
surface;
metal surface to effectively resist underfilm migration of moisture;
cracking;
damage due to handling and soil stress; and
any supplemental cathodic protection.
also have low moisture absorption and high electrical resistance.
be inspected just prior to lowering the pipe into the ditch and backfilling, and any damage detrimental to effective corrosion control must be repaired.
be protected from damage resulting from adverse ditch conditions or damage from supporting blocks.
driving, or other similar method, precautions must be taken to minimize damage to the coating during installation.
(H) External Corrosion Control—Cathodic Protection. (192.463)
required by this section must provide a level of cathodic protection that complies with one (1) or more of the applicable criteria contained in Appendix D, which is included herein (at the end of this rule).
buried or submerged pipeline containing a metal of different anodic potential—
electrically isolated from the remainder of the pipeline and cathodically protected; or
pipeline must be cathodically protected at a cathodic potential that meets the requirements of Appendix D for amphoteric metals.
must be controlled so as not to damage the protective coating or the pipe.
(I) External Corrosion Control— Monitoring. (192.465)
protection must be tested at least once each calendar year, but with intervals not exceeding fifteen (15) months, to determine whether the cathodic protection meets the requirements of subsection (9)(H). (192.463) However, if tests at those intervals are impractical for separately protected short sections of mains or transmission lines, not in excess of one hundred feet (100') (thirty meters (30 m)), or separately protected service lines, these pipelines may be surveyed on a sampling basis. At least twenty percent (20%) of these protected structures, distributed over the entire system, must be surveyed each calendar year, with a different twenty percent (20%) checked each subsequent year, so that the entire system is tested in each five- 20 CSR 4240-40
(5-) year period. Each short section of metallic pipe less than one hundred feet (100') (thirty meters (30 m)) in length installed and cathodically protected in accordance with paragraph (9)(R)2. (192.483[b]), each segment of pipe cathodically protected in accordance with paragraph (9)(R)3. (192.483[c]) and each electrically isolated metallic fitting not meeting the requirements of paragraph (9)(D)5. (192.455[f]) must be monitored at a minimum rate of ten percent (10%) each calendar year, with a different ten percent (10%) checked each subsequent year, so that the entire system is tested every ten (10) years.
other impressed current power source must be inspected six (6) times each calendar year but with intervals not exceeding two and onehalf (2 1/2) months to ensure that it is operating.
diode, and each interference bond whose failure would jeopardize structure protection must be electrically checked for proper performance six (6) times each calendar year, but with intervals not exceeding two and onehalf (2 1/2) months. Each other interference bond must be checked at least once each calendar year, but with intervals not exceeding fifteen (15) months.
remedial action to correct any deficiencies indicated by the monitoring set forth in paragraphs (9)(I)1.–3. Corrective measures must be completed within six (6) months unless otherwise approved by designated commission personnel.
by paragraphs (9)(D)2. and (9)(E)2., each operator must, not less than every three (3) years at intervals not exceeding thirty-nine (39) months, reevaluate its unprotected pipelines and cathodically protect them in accordance with section (9) in areas in which active corrosion is found. Unprotected steel service lines are subject to replacement pursuant to subsection (15)(C). The operator must determine the areas of active corrosion by electrical survey. However, on distribution lines and where an electrical survey is impractical on transmission lines, areas of active corrosion may be determined by other means that include review and analysis of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, the pipeline environment, and by instrument leak detection surveys (see subsections (13)(D) and (13)(M)). When the operator conducts electrical surveys, the operator must demonstrate that the surveys effectively identify areas of active corrosion. AND INSURANCE
(J) External Corrosion Control—Electrical Isolation. (192.467)
must be electrically isolated from other underground metallic structures, unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit.
must be installed where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control.
ed in a ferrous pipe, each pipeline must be electrically isolated from metallic casings that are a part of the underground system. However, if isolation is not achieved because it is impractical, other measures must be taken to minimize corrosion of the pipeline inside the casing.
made to assure that electrical isolation is adequate.
installed in an area where a combustible atmosphere is anticipated unless precautions are taken to prevent arcing.
proximity to electrical transmission tower footings, ground cables or counterpoise, or in other areas where fault currents or unusual risk of lightning may be anticipated, it must be provided with protection against damage due to fault currents or lightning, and protective measures must also be taken at insulating devices.
(L) External Corrosion Control—Test Leads. (192.471)
to the pipeline so as to remain mechanically secure and electrically conductive.
to the pipeline so as to minimize stress concentration on the pipe.
metallic area at point of connection to the pipeline must be coated with an electrical insulating material compatible with the pipe coating and the insulation on the wire.
(M) External Corrosion Control—Interference Currents. (192.473)
is subjected to stray currents shall have in effect a continuing program to minimize the detrimental effects of these currents.
protection system or galvanic anode system must be designed and installed so as to minimize any adverse effects on existing adjacent underground metallic structures.
(N) Internal Corrosion Control—General and Monitoring. (192.475 and 192.477)
by pipeline, unless the corrosive effect of the gas on the pipeline has been investigated and steps have been taken to minimize internal corrosion.
pipeline for any reason, the internal surface must be inspected for evidence of corrosion. If internal corrosion is found—
gated to determine the extent of internal corrosion;
extent required by the applicable paragraphs of subsections (9)(S), (T) or (U) (192.485, 192.487, or 192.489); and
the internal corrosion.
of hydrogen sulfide per one hundred (100) cubic feet (5.8 milligrams/m3) at standard conditions (four (4) parts per million) may not be stored in pipe-type or bottle-type holders.
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 (2) times each calendar year, but with intervals not exceeding seven and one-half (7 1/2) months.
(O) Internal Corrosion Control—Design and Construction of Transmission Line. (192.476)
provided in paragraph (9)(O)2., each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line must have features incorporated into its design and construction to reduce the risk of internal corrosion. At a minimum, unless it is impracticable or unnecessary to do so, each new transmission line or replacement of line pipe, valve, fitting, or other line component in a transmission line must—
that liquids will collect in the line;
tures whenever the configuration would allow liquids to collect; and
ing internal corrosion at locations with significant potential for internal corrosion.
design and construction requirements of paragraph (9)(O)1. do not apply to pipeline installed or line pipe, valve, fitting, or other line component replaced before May 23, 2007.
When an operator changes the configuration of a transmission line, the operator must evaluate the impact of the change on internal corrosion risk to the downstream portion of an existing transmission line and provide for removal of liquids and monitoring of internal corrosion as appropriate.
records demonstrating compliance with this subsection. Provided the records show why incorporating design features addressing (9)(O)1.A., (9)(O)1.B., or (9)(O)1.C. is impracticable or unnecessary, an operator may fulfill this requirement through written procedures supported by as-built drawings or other construction records.
(P) Atmospheric Corrosion Control— General. (192.479)
1971. Each aboveground pipeline or portion of a pipeline installed after July 31, 1971, that is exposed to the atmosphere must be cleaned and coated with a material suitable for the prevention of atmospheric corrosion. An operator need not comply with this paragraph for an inside pipeline, if the operator can demonstrate by test, investigation or experience appropriate to the inside environment of the pipeline that corrosion will—
metal before the next scheduled inspection.
1971. Each aboveground pipeline or portion of a pipeline installed before August 1, 1971, that is exposed to the atmosphere must be cleaned and coated with a material suitable for the prevention of atmospheric corrosion. This applies to all portions of pipelines in soil-to-air interfaces. For portions of pipelines that are not in soil-to-air interfaces, the operator need not protect from atmospheric corrosion any pipeline for which the operator demonstrates by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will—
pipeline before the next scheduled inspection.
and subsection (9)(Q), atmospheric corrosion means corrosion that has resulted in pitting of the base metal.
(Q) Atmospheric Corrosion Control— Monitoring. (192.481)
pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion at least once every three (3) calendar years, but with intervals not exceeding thirty-nine (39) months. (Atmospheric corrosion is defined in paragraph (9)(P)3.)
give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, at deck penetrations, and in spans over water.
during an inspection, the operator must provide protection against the corrosion as required by subsection (9)(P) within twelve (12) months unless otherwise approved by designated commission personnel.
(R) Remedial Measures—General. (192.483)
replaces pipe removed from a buried or submerged pipeline because of external corrosion must have a properly prepared surface and must be provided with an external protective coating that meets the requirements of subsection (9)(G). (192.461)
replaces pipe removed from a buried or submerged pipeline because of external corrosion must be cathodically protected and monitored in accordance with this section.
pipe, each segment of buried or submerged pipe that is required to be repaired because of external corrosion must be cathodically protected and monitored in accordance with this section.
(S) Remedial Measures—Transmission Lines. (192.485)
transmission line with general corrosion and with a remaining wall thickness less than that required for the maximum allowable operating pressure of the pipeline must be replaced or the operating pressure reduced commensurate with the strength of the pipe based on actual remaining wall thickness. However, corroded pipe may be repaired by a method that reliable engineering test and analysis show can permanently restore the serviceability of the pipe. Corrosion pitting so closely grouped as to affect the overall strength of the pipe is considered general corrosion for the purpose of this paragraph.
segment of transmission line pipe with localized corrosion pitting to a degree where leakage might result must be replaced or repaired, or the operating pressure must be reduced commensurate with the strength of the pipe, based on the actual remaining wall thickness in the pits.
(9)(S)2., the strength of pipe based on actual remaining wall thickness may be determined by the procedure in ASME/ANSI B31G (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) or the procedure in PRCI PR-3-805 (R-STRENG) (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). Both procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations prescribed in the procedures.
(T) Remedial Measures—Distribution Lines Other Than Cast Iron or Ductile Iron Lines. (192.487)
iron or ductile iron pipe, each segment of generally corroded distribution line pipe with a remaining wall thickness less than that required for the maximum allowable operating pressure of the pipeline, or a remaining wall thickness less than thirty percent (30%) of the nominal wall thickness, must be replaced. However, corroded pipe may be repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. Corrosion pitting so closely grouped as to affect the overall strength of the pipe is considered general corrosion for the purpose of this paragraph.
for cast iron or ductile iron pipe, each segment of distribution line pipe with localized corrosion pitting to a degree where leakage might result must be replaced or repaired.
(U) Remedial Measures—Cast Iron and Ductile Iron Pipelines. (192.489)
of cast iron or ductile iron pipe on which general graphitization is found to a degree where a fracture or any leakage might result must be replaced.
ment of cast iron or ductile iron pipe on which localized graphitization is found to a degree where any leakage might result must be replaced or repaired, or sealed by internal sealing methods adequate to prevent or arrest any leakage.
(V) Corrosion Control Records. (192.491)
or maps to show the location of cathodically protected piping, cathodic protection facilities, galvanic anodes, and neighboring structures bonded to the cathodic protection system. Records or maps showing a stated number of anodes, installed in a stated manner or spacing, need not show specific distances to each buried anode. Each operator shall develop 20 CSR 4240-40
and maintain maps showing, at a minimum: the location of cathodically protected mains (except for short sections less than one hundred feet (100') in length); feeder lines; and transmission lines; and all cathodic protection facilities such as rectifiers, test points (except for service riser locations that are not used each year), electrical isolating devices that separate protection zones, and interference bonds.
graph (9)(V)1. must be retained for as long as the pipeline remains in service.
of each test, survey, inspection, and remedial action required by this section in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist. These records must be retained for at least five (5) years, except that records related to paragraphs (9)(I)1., (9)(I)4., (9)(I)5., and (9)(N)2. must be retained for as long as the pipeline remains in service.
Threat Standard¹ (see section (16)) External corrosion 49 CFR 192.925² Internal corrosion in pipelines that transport dry gas 49 CFR 192.927 Stress corrosion cracking 49 CFR 192.929
1For lines not subject to 49 CFR part 192, subpart O, the terms “covered segment” and “covered pipeline segment” in 49 CFR 192.925, 192.927, and 192.929 refer to the pipeline segment on which direct assessment is performed. 2In 49 CFR 192.925[b], the provision regarding detection of coating damage applies only to pipelines subject to 49 CFR part 192, subpart O. (X) In-line Inspection of Pipelines. (192.493) When conducting in-line inspections of pipelines required by this rule, an operator must comply with API STD 1163, ANSI/ASNT ILI–PQ, and NACE SP0102 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). Assessments may be conducted using tethered AND INSURANCE
or remotely controlled tools, not explicitly discussed in NACE SP0102, provided they comply with those sections of NACE SP0102 that are applicable.
(10) Test Requirements.
(B) General Requirements. (192.503)
ment of pipeline, or return to service a segment of pipeline that has been relocated or replaced, until—
with this section and subsection (12)(M) (192.619) to substantiate the maximum allowable operating pressure; and
has been located and eliminated.
natural gas, or inert gas that is—
which the pipeline is constructed;
materials; and
flammable.
(10)(C)1. (192.505[a]), if air, natural gas, or inert gas is used as the test medium, the following maximum hoop stress limitations apply:
Maximum Hoop Stress Class Allowed as Location Percentage of SMYS Natural Air or Gas Inert Gas 1 80 80 2 30 75 3 30 50 4 30 40
segment of pipeline is excepted from the specific test requirements of this section, but it must be leak tested at not less than its operating pressure.
only item being replaced or added to a pipeline, a strength test after installation is not required, if the manufacturer of the component certifies that—
least the pressure required for the pipeline to which it is being added;
under a quality control system that ensures that each item manufactured is at least equal in strength to a prototype and that the prototype was tested to at least the pressure required for the pipeline to which it is being added; or
rating established through applicable ASME/ANSI specifications, Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS) specifications, or by unit strength calculations as described in subsection (4)(B).
(C) Strength Test Requirements for Steel Pipeline to Operate at a Hoop Stress of Thirty Percent (30%) or More of SMYS. (192.505)
ment of a steel pipeline that is to operate at a hoop stress of thirty percent (30%) or more of SMYS must be strength tested in accordance with this subsection to substantiate the proposed maximum allowable operating pressure. In addition, in a Class 1 or Class 2 location, if there is a building intended for human occupancy within three hundred feet (300') (91 meters) of a pipeline, a hydrostatic test must be conducted to a test pressure of at least one hundred twenty-five percent (125%) of maximum operating pressure on that segment of the pipeline within three hundred feet (300') (91 meters) of such a building, but in no event may the test section be less than six hundred feet (600') (183 meters) unless the length of the newly installed or relocated pipe is less than six hundred feet (600') (183 meters). However, if the buildings are evacuated while the hoop stress exceeds fifty percent (50%) of SMYS, air or inert gas may be used as the test medium.
compressor station, regulator station, and measuring station must be tested to at least Class 3 location test requirements.
(10)(C)4., the strength test must be conducted by maintaining the pressure at or above the test pressure for at least eight (8) hours.
of pipe, for which a post-installation test is impractical, a pre-installation strength test must be conducted by maintaining the pressure at or above the test pressure for at least four (4) hours.
(D) Test Requirements for Pipelines to Operate at a Hoop Stress Less Than Thirty Percent (30%) of SMYS and at or Above One Hundred (100) psi (689 kPa) Gauge. (192.507) Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated at a hoop stress less than thirty percent (30%) of SMYS and at or above one hundred (100) psi (689 kPa) gauge must be tested in accordance with subparagraph (12)(M)1.B. and the following:
procedure that will ensure discovery of all potentially hazardous leaks in the segment being tested;
be stressed to twenty percent (20%) or more of SMYS and natural gas, inert gas, or air is the test medium—
sure between one hundred (100) psi (689 kPa) gauge and the pressure required to produce a hoop stress of twenty percent (20%) of SMYS; or
for leaks while the hoop stress is held at approximately twenty percent (20%) of SMYS;
or above the test pressure for at least one (1) hour.
(E) Test Requirements for Pipelines to Operate Below One Hundred (100) psi (689 kPa) Gauge. (192.509) Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated below one hundred (100) psi (689 kPa) gauge must be leak tested in accordance with the following:
discovery of all potentially hazardous leaks in the segment being tested; and
less than one (1) psi (6.9 kPa) gauge must be tested to at least ten (10) psi (69 kPa) gauge, each main to be operated at or above one (1) psi (6.9 kPa) gauge through ninety (90) psi (621 kPa) gauge must be tested to at least ninety (90) psi (621 kPa) gauge, and each main that is to be operated between ninety (90) psi (621 kPa) gauge and one hundred (100) psi (689 kPa) gauge must be tested to at least one hundred (100) psi (689 kPa) gauge.
(F) Test Requirements for Service Lines. (192.511)
than plastic) must be leak tested in accordance with this subsection before being placed in service. If feasible, the service line connection to the main must be included in the test; if not feasible, it must be given a leakage test at the operating pressure when placed in service.
than plastic) intended to be operated at a pressure of at least one (1) psi (6.9 kPa) gauge but not more than forty (40) psi (276 kPa) gauge must be given a leak test at a pressure of not less than fifty (50) psi (345 kPa) gauge.
than plastic) intended to be operated at pressures of more than forty (40) psi (276 kPa) gauge through ninety (90) psi (621 kPa) gauge must be tested to at least ninety (90) psi (621 kPa) gauge; if the service line is to be operated between ninety (90) psi (621 kPa) gauge and one hundred (100) psi (689 kPa) gauge, it must be tested to at least one hundred (100) psi (689 kPa) gauge; and if the service line may be operated at one hundred (100) psi (689 kPa) gauge; or more, it must, at a minimum, be tested using the appropriate factor in subparagraph (12)(M)1.B. of this rule, except that each segment of the steel service line stressed to twenty percent (20%) or more of SMYS must be tested in accordance with subsection (10)(D).
(G) Test Requirements for Plastic Pipelines. (192.513)
must be tested in accordance with this subsection.
covery of all potentially hazardous leaks in the segment being tested.
hundred fifty percent (150%) of the maximum allowable operating pressure or fifty (50) psi (345 kPa) gauge, whichever is greater. However, the maximum test pressure may not be more than two and one half (2.5) times the pressure determined under subsection (3)(I), at a temperature not less than the pipe temperature during the test.
thermoplastic material may not be more than 100 °F (38 °C), or the temperature at which the material’s long-term hydrostatic strength has been determined under the listed specification, whichever is greater.
(H) Environmental Protection and Safety Requirements. (192.515)
each operator shall ensure that every reasonable precaution is taken to protect its employees and the general public during the testing. Whenever the hoop stress of the segment of the pipeline being tested will exceed fifty percent (50%) of SMYS, the operator shall take all practicable steps to keep persons not working on the testing operation outside of the testing area until the pressure is reduced to or below the proposed maximum allowable operating pressure.
medium is disposed of in a manner that will minimize damage to the environment.
(I) Records. (192.517)
each operator shall make and retain for the useful life of the pipeline, a record of each test performed under subsections (10)(C)– (E), (G), and (K). (192.505, 192.506, 192.507, 192.509, and 192.513) Where applicable to the test performed, the record must contain at least the following information, except as noted in subparagraph (10)(I)1.B.:
the operator’s employee responsible for making the test, and the name of any test company used;
performed pursuant to subsections (10)(E) and (G);
record of pressure readings;
nificant for the particular test;
disposition;
ed.
make and retain for the useful life of the pipeline, a record of each test performed under subsections (10)(F) and (G) (192.511 and 192.513). Where applicable to the test performed, the record must contain the test pressure, leaks, and failures noted and their disposition and the date.
(J) Test Requirements for Customer- Owned Fuel Lines.
cally turns on the flow of gas to new fuel line installations—
tested for leakage to at least the delivery pressure;
accessible customer gas piping, interior and exterior, and all connected equipment shall be conducted to determine that the requirements of any applicable industry codes, standards or procedures adopted by the operator to assure safe service are met; and
ble local (city, county, etc.) codes must be met.
material must not be more than one hundred degrees Fahrenheit (100 °F) during the test.
performed in accordance with this subsection shall be maintained by the operator for a period of not less than two (2) years.
(K) Transmission Lines: Spike Hydrostatic Pressure Test. (192.506)
segment of steel transmission pipeline that is operated at a hoop stress level of thirty percent (30%) or more of SMYS is spike tested under this rule, the spike hydrostatic pressure test must be conducted in accordance with this subsection.
medium.
as specified in subparagraph (12)(M)1.B. (192.619(a)(2)).
maintaining a pressure at or above the baseline test pressure for at least eight (8) hours as specified in subsection (10)(C) (192.505).
the baseline pressure and within the first two (2) hours of the eight- (8-) hour test interval, the hydrostatic pressure must be raised (spiked) to a minimum of the lesser of 1.5 times MAOP or one-hundred percent (100%) SMYS. This spike hydrostatic pressure test must be held for at least fifteen (15) minutes after the spike test pressure stabilizes.
cal evaluation process. Operators may use “other technology” or another process supported by a documented engineering analysis for establishing a spike hydrostatic pressure test or equivalent. Operators must notify PHMSA ninety (90) days in advance of the assessment or reassessment requirements of this chapter. The notification must be made in accordance with subsection (1)(M) (192.18) and must include the following information:
technologies to be used for all tests, examinations, and assessments;
duct tests, examinations, assessments, perform evaluations, analyze defects, and remediate defects discovered;
inal design, maintenance and operating history, anomaly or flaw characterization;
tance criteria;
ment findings;
monitoring and acceptance procedures, if used;
growth analysis and pipeline segment life analysis for the time interval for additional assessments, as required; and
dures and assessments by a qualified technical subject matter expert.
(11) Uprating.
(B) General Requirements. (192.553)
requirements of this section require that an increase in operating pressure be made in increments, the pressure must be increased gradually, at a rate that can be controlled and in accordance with the following: AND INSURANCE
increase, the pressure must be held constant while the entire segment of the pipeline that is affected is checked for leaks. When a combustible gas is being used for uprating, all buried piping must be checked with a leak detection instrument after each incremental increase; and
repaired before a further pressure increase is made, except that a leak determined not to be potentially hazardous need not be repaired, if it is monitored during the pressure increase and it does not become potentially hazardous.
segment of pipeline shall retain for the life of the segment a record of each investigation required by this section, of all work performed, and of each pressure test conducted, in connection with the uprating.
uprates a segment of pipeline shall establish a written procedure that will ensure compliance with each applicable requirement of this section.
allowable operating pressure. Except as provided in (11)(C)3., a new maximum allowable operating pressure established under this section may not exceed the maximum that would be allowed under subsections (12)(M) and (12)(N) for a new segment of pipeline constructed of the same materials in the same location. However, when uprating a steel pipeline, if any variable necessary to determine the design pressure under the design formula in subsection (3)(C) is unknown, the MAOP may be increased as provided in subparagraph (12)(M)1.A.
allowable operating pressure. Subsections (12)(M) and (N) (192.619 and 192.621) must be reviewed when establishing a new MAOP. The pressure to which the pipeline is raised during the uprating procedure is the test pressure that must be divided by the appropriate factors in subparagraph (12)(M)1.B. (192.619[a][2]) except that pressure tests conducted on steel and plastic pipelines after July 1, 1965 are applicable.
(C) Uprating to a Pressure That Will Produce a Hoop Stress of Thirty Percent (30%) or More of SMYS in Steel Pipelines. (192.555)
section have been met, no person may subject any segment of a steel pipeline to an operating pressure that will produce a hoop stress of thirty percent (30%) or more of SMYS and that is above the established maximum allowable operating pressure.
above the previously established maximum allowable operating pressure the operator shall—
maintenance history and previous testing of the segment of pipeline and determine whether the proposed increase is safe and consistent with the requirements of this rule; and
alterations in the segment of pipeline that are necessary for safe operation at the increased pressure.
(11)(C)2., an operator may increase the maximum allowable operating pressure of a segment of pipeline constructed before September 12, 1970, to the highest pressure that is permitted under subsection (12)(M) (192.619), using as test pressure the highest pressure to which the segment of pipeline was previously subjected (either in a strength test or in actual operation).
(11)(C)2., an operator that does not qualify under paragraph (11)(C)3. may increase the previously established maximum allowable operating pressure if at least one (1) of the following requirements is met:
cessfully tested in accordance with the requirements of this rule for a new line of the same material in the same location; or
operating pressure may be established for a segment of pipeline in a Class 1 location if the line has not previously been tested, and if—
accordance with the requirements of this rule;
pressure does not exceed eighty percent (80%) of that allowed for a new line of the same design in the same location; and
the new maximum allowable operating pressure is consistent with the condition of the segment of pipeline and the design requirements of this rule.
ed in accordance with paragraph (11)(C)3. or subparagraph (11)(C)4.B., the increase in pressure must be made in increments that are equal to—
before the uprating; or
total pressure increase, whichever produces the fewer number of increments.
(D) Uprating—Steel Pipelines to a Pressure That Will Produce a Hoop Stress Less Than Thirty Percent (30%) of SMYS— Plastic, Cast Iron, and Ductile Iron Pipelines. (192.557)
section have been met, no person may subject—
operating pressure that will produce a hoop stress less than thirty percent (30%) of SMYS and that is above the previously established maximum allowable operating pressure; or
pipeline segment to an operating pressure that is above the previously established maximum allowable operating pressure.
above the previously established maximum allowable operating pressure, the operator shall—
maintenance history of the segment of pipeline;
ment survey (if it has been more than one (1) year since the last survey conducted with a leak detection instrument) and repair any leaks that are found, except that a leak determined not to be potentially hazardous need not be repaired, if it is monitored during the pressure increase and it does not become potentially hazardous;
or alterations in the segment of pipeline that are necessary for safe operation at the increased pressure;
and dead ends in pipe joined by compression couplings or bell and spigot joints to prevent failure of the pipe joint, if the offset, bend, or dead end is exposed in an excavation;
which the pressure is to be increased from any adjacent segment that will continue to be operated at a lower pressure; and
lines, or both, is to be higher than the pressure delivered to the customer, install a service regulator on each service line and test each regulator to determine that it is functioning. Pressure may be increased as necessary to test each regulator, after a regulator has been installed on each pipeline subject to the increased pressure.
(11)(D)2., the increase in maximum allowable operating pressure must be made in accordance with paragraph (11)(B)5. The pressure must be increased in increments that are equal to ten (10) psi (69 kPa) gauge or twenty-five percent (25%) of the total pressure increase, whichever produces the fewer number of increments. Whenever the requirements of subparagraph (11)(D)2.F. apply, there must be at least two (2) approximately equal incremental increases.
pipeline facilities are not complete enough to determine stresses produced by internal pressure, trench loading, rolling loads, beam stresses, and other bending loads, in evaluating the level of safety of the pipeline when operating at the proposed increased pressure, the following procedures must be followed:
original laying conditions cannot be ascertained, the operator shall assume that cast iron pipe was supported on blocks with tamped backfill and that ductile iron pipe was laid without blocks with tamped backfill;
depth is known, the operator shall measure the actual cover in at least three (3) places where the cover is most likely to be greatest and shall use the greatest cover measured;
thickness is known, the operator shall determine the wall thickness by cutting and measuring coupons from at least three (3) separate pipe lengths. The coupons must be cut from pipe lengths in areas where the cover depth is most likely to be the greatest. The average of all measurements taken must be increased by the allowance indicated in the following table:
Allowance inches (millimeters) Cast Iron Pipe
Pipe Size Pit Cast Centrifugally Ductile inches Pipe Cast Pipe Iron Pipe (millimeters) 3 to 8 0.075 0.065 0.065 (76 to 203) (1.91) (1.65) (1.65) 10 to 12 0.08 0.07 0.07 (254 to 305) (2.03) (1.78) (1.78) 14 to 24 0.08 0.08 0.075 (356 to 610) (2.03) (2.03) (1.91) 30 to 42 0.09 0.09 0.075 (762 to 1067) (2.29) (2.29) (1.91)
48 0.09 0.09 0.08 (1219) (2.29) (2.29) (2.03) 54 to 60 0.09 — — (1372 to (2.29) — — 1524)
manufacturing process is known, the operator shall assume that the pipe is pit cast pipe with a bursting tensile strength of eleven thousand (11,000) psi (76 MPa) and a modulus of rupture of thirty-one thousand (31,000) psi (214 MPa).
(12) Operations.
(B) General Provisions. (192.603)
pipeline unless it is operated in accordance with this section.
essary to administer the procedures established under subsection (12)(C). (192.605)
ensuring that all work completed on its pipelines by its consultants and contractors complies with this rule.
may require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety. In the event of a dispute between designated commission personnel and the operator with respect to the appropriateness of a required amendment, the operator may file with the commission a request for a hearing before the commission, or the designated commission personnel may request that a complaint be filed against the operator by the general counsel of the commission.
(C) Procedural Manual for Operations, Maintenance, and Emergencies. (192.605)
and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines that are not exempt under subparagraph (12)(C)3.E., the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding fifteen (15) months, but at least once each calendar year. This manual must be prepared before initial operations of a pipeline system commence and appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted.
The manual required by paragraph (12)(C)1. must include procedures for the following, if applicable, to provide safety during maintenance and normal operations:
repairing the pipeline in accordance with each of the requirements of this section and sections (13) and (14);
dance with the operations and maintenance requirements of section (9);
maps, and operating history available to appropriate operating personnel;
reporting incidents under 20 CSR 4240- 40.020 in a timely and effective manner;
part of a pipeline in a manner designed to assure operation within the MAOP limits prescribed by this rule, plus the build-up allowed for operation of pressure limiting and control devices;
including provisions for isolating units or sections of pipe and for purging before returning to service;
down gas compressor units;
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;
that operating pressures are appropriate for the class location;
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;
ing and inspecting pipe-type or bottle-type holders including:
corrosion before the strength of the container has been impaired;
of gas in storage to determine the dew point of vapors contained in the stored gas that, if condensed, might cause internal corrosion or interfere with the safe operation of the storage plant; and
of pressure limiting equipment to determine that it is in a safe operating condition and has adequate capacity;
routine activities including, but not limited to, meter reading and cathodic protection work, for the purpose of detecting potential leaks by observing vegetation and odors. Potential leak indications must be recorded and responded to in accordance with section (14);
tomer-owned gas piping and equipment in accordance with subsection (12)(S);
of a gas odor inside or near a building, unless the operator’s emergency procedures under subparagraph (12)(J)1.C. specifically apply to these reports; and
trol room management procedures required by subsection (12)(T).
sion lines the manual required by paragraph (12)(C)1. must include procedures for the following to provide safety when operating design limits have been exceeded:
correcting the cause of—
shutdowns;
sure or flow rate outside normal operating limits;
device; and
tion of a component, deviation from normal operation, or personnel error which could cause a hazard to persons or property;
operation after abnormal operation has ended at sufficient critical locations in the system to determine continued integrity and safe operation;
personnel when notice of an abnormal operation is received;
response of operator personnel to determine the effectiveness of the procedures controlling abnormal operation and taking corrective action where deficiencies are found; and
(12)(C)3. do not apply to natural gas distribution operations that are operating transmission lines in connection with their distribution system.
al required by paragraph (12)(C)1. 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 commission’s reporting requirements.
and accident investigation. The procedures required by paragraph (12)(H)1. and subsections (12)(J) and (L) (192.613[a], 192.615 and 192.617) must be included in the manual required by paragraph (12)(C)1.
(D) Qualification of Pipeline Personnel.
1. Scope. (192.801)
minimum requirements for operator qualification of individuals performing covered tasks on a pipeline facility. This subsection applies to all individuals who perform covered tasks, regardless of whether they are employed by the operator, a contractor, a subcontractor, or any other entity performing covered tasks on behalf of the operator.
a covered task is an activity, identified by the operator, that—
ity;
or emergency-response task;
of this rule; and
integrity of the pipeline.
2. Definitions. (192.803)
means a condition identified by the operator that may indicate a malfunction of a component or deviation from normal operations that may:
design limits;
sons, property, or the environment; or
response.
process consisting of training and examination, established and documented by the operator, to determine an individual’s ability to perform a covered task and to demonstrate that an individual possesses the knowledge and skills under paragraph (12)(D)4. After initial evaluation for paragraph (12)(D)4., subsequent evaluations for paragraph (12)(D)4. can consist of examination only. The examination portion of this process may be conducted by one (1) or more of the following:
could involve observation supplemented by appropriate queries. Observations can be made during:
has been evaluated and can:
and
mal operating conditions.
Each operator shall have and follow a written qualification program. The program shall include provisions to:
ensure that individuals performing covered tasks have the necessary knowledge and skills to perform the tasks in a manner that ensures the safe operation of pipeline facilities;
individuals performing covered tasks are qualified and have the necessary knowledge and skills to perform the tasks in a manner that ensures the safe operation of pipeline facilities;
qualified pursuant to this subsection to perform a covered task if directed and observed by an individual that is qualified;
ator has reason to believe that the individual’s performance of a covered task contributed to an incident meeting the Missouri reporting requirements in 20 CSR 4240-40.020(4)(A);
tor has reason to believe that the individual is no longer qualified to perform a covered task;
changes to rules and procedures, that affect covered tasks to individuals performing those covered tasks and their supervisors, and incorporate those changes in subsequent evaluations;
ered task at which evaluation of the individual’s qualifications is needed, with a maximum interval of thirty-nine (39) months;
of the knowledge and skills under paragraph (12)(D)4. at intervals not to exceed thirtynine (39) months;
J. Ensure that covered tasks are—
uals; or
ified individuals; and
designated commission personnel as required by subsection (1)(J).
applies must possess the knowledge and skills necessary to—
rule that relate to the covered tasks they perform;
procedural manual for operations, maintenance, and emergencies established under subsection (12)(C) (192.605) that relate to the covered tasks they perform;
that relate to the covered task they perform in accordance with manufacturer’s instructions;
ards of the gas transported, including flammability range, odorant characteristics, and corrosive properties;
sources;
to cause emergencies, including equipment or facility malfunctions or failure and gas leaks, predict potential consequences of these conditions, and take appropriate corrective action;
accidental release of gas and to minimize the potential for fire or explosion; and
ing procedures and equipment, fire suits, and breathing apparatus by utilizing, where feasible, a simulated pipeline emergency condition.
the training and annual review requirements regarding the operator’s emergency procedures in subparagraph (12)(J)2.B., in addition to the qualification program required in paragraph (12)(D)3.
tion to the supervisors or designated persons who will determine when an evaluation is necessary under subparagraph (12)(D)3.F.
ately knowledgeable individuals to provide training and to perform evaluations. Where hands-on examinations and observations are used, the evaluator should possess the required knowledge to ascertain an individual’s ability to perform covered tasks and react to abnormal operating conditions that might occur while performing those tasks.
operator shall maintain records that demonstrate compliance with this subsection.
A. Qualification records shall include:
individual(s);
tasks the individual is qualified to perform;
tion; and
current qualification shall be maintained while the individual is performing the covered task. Records of prior qualification and records of individuals no longer performing covered tasks shall be retained for a period of five (5) years.
9. General. (192.809)
ification program by April 27, 2001. The program must be available for review by designated commission personnel.
ification of individuals performing covered tasks by October 28, 2002.
vation of on-the-job performance may not be used as the sole method of evaluation.
(E) Verification of Pipeline Material Properties and Attributes: Steel Transmission Pipelines. (192.607)
this rule, operators of steel transmission pipelines must document and verify material properties and attributes in accordance with this subsection.
and attributes. Records established under this subsection documenting physical pipeline characteristics and attributes, including diameter, wall thickness, seam type, and grade (e.g., yield strength, ultimate tensile strength, or pressure rating for valves and flanges, etc.), must be maintained for the life of the pipeline and be traceable, verifiable, and complete. Charpy v-notch toughness values established under this subsection needed to meet the requirements of the ECA method at subparagraph (12)(U)3.C. (192.624(c)(3)) or the fracture mechanics requirements at subsection (13)(EE) (192.712) must be maintained for the life of the pipeline.
attributes. If an operator does not have traceable, verifiable, and complete records required by paragraph (12)(E)2., the operator must develop and implement procedures for conducting nondestructive or destructive tests, examinations, and assessments in order to verify the material properties of aboveground line pipe and components, and of buried line pipe and components when excavations occur at the following opportunities: Anomaly direct examinations, in situ evaluations, repairs, remediations, maintenance, and excavations that are associated with replacements or relocations of pipeline segments that are removed from service. The procedures must also provide for the following:
test location, material properties for minimum yield strength and ultimate tensile strength must be determined at a minimum of five (5) places in at least two (2) circumferential quadrants of the pipe for a minimum total of ten (10) test readings at each pipe cylinder location;
location, a set of material properties tests for minimum yield strength and ultimate tensile strength must be conducted on each test pipe cylinder removed from each location, in accordance with API Specification 5L;
ments must be appropriate for verifying the necessary material properties and attributes;
documented, the procedures must include accepted industry methods for verifying pipe material toughness; and
and attributes for non-line pipe components must comply with paragraph (12)(E)6.
tive methods. Procedures developed in accordance with paragraph (12)(E)3. for verification of material properties and attributes using nondestructive methods must—
and techniques that have been validated by a subject matter expert based on comparison with destructive test results on material of comparable grade and vintage;
surement inaccuracy and uncertainty using reliable engineering tests and analyses; and
properly calibrated for comparable test materials prior to usage.
To verify material properties and attributes for a population of multiple, comparable segments of pipe without traceable, verifiable, and complete records, an operator may use a sampling program in accordance with the following requirements:
populations of similar segments of pipe for each combination of the following material properties and attributes: Nominal wall thicknesses, grade, manufacturing process, pipe manufacturing dates, and construction dates. If the dates between the manufacture or construction of the pipeline segments exceeds two (2) years, those segments cannot be considered as the same vintage for the purpose of defining a population under this section. The total population mileage is the cumulative mileage of pipeline segments in the population. The pipeline segments need not be continuous;
according to subparagraph (12)(E)5.A., the operator must determine material properties at all excavations that expose the pipe associated with anomaly direct examinations, in situ evaluations, repairs, remediations, or maintenance, except for pipeline segments exposed during excavation activities pursuant to subsection (12)(I) (192.614), until completion of the lesser of the following:
rounded up to the nearest whole number; or
vations if the population is more than onehundred-fifty (150) miles;
excavation according to the requirements of paragraph (12)(E)3. may be counted as one (1) sample under the sampling requirements of this paragraph (12)(E)5.;
with properties that are not consistent with available information or existing expectations or assumed properties used for operations and maintenance in the past, the operator must establish an expanded sampling program. The expanded sampling program must use valid statistical bases designed to achieve at least a ninety-five percent (95%) confidence level that material properties used in the operation and maintenance of the pipeline are valid. The approach must address how the sampling plan will be expanded to address findings that reveal material properties that are not consistent with all available information or existing expectations or assumed material properties used for pipeline operations and maintenance in the past. Operators must notify PHMSA in advance of using an expanded sampling approach in accordance with subsection (1)(M) (192.18); and
statistical sampling approach that differs from the requirements specified in subparagraph (12)(E)5.B. The alternative sampling program must use valid statistical bases designed to achieve at least a ninety-five percent (95%) confidence level that material AND INSURANCE
properties used in the operation and maintenance of the pipeline are valid. The approach must address how the sampling plan will be expanded to address findings that reveal material properties that are not consistent with all available information or existing expectations or assumed material properties used for pipeline operations and maintenance in the past. Operators must notify PHMSA in advance of using an alternative sampling approach in accordance with subsection (1)(M) (192.18).
components other than line pipe, an operator must develop and implement procedures in accordance with paragraph (12)(E)3. for establishing and documenting the ANSI rating or pressure rating (in accordance with ASME/ANSI B16.5 (incorporated by reference in 49 CFR 192.7 and adopted in (1)(D))).
for the chemical and mechanical properties of components in compressor stations, meter stations, regulator stations, separators, river crossing headers, mainline valve assemblies, valve operator piping, or cross-connections with isolation valves from the mainline pipeline.
is required for non-line pipe components, including valves, flanges, fittings, fabricated assemblies, and other pressure retaining components and appurtenances that are—
nominal outside diameter;
thousand (42,000) psi (Grade X–42) or greater; or
are directly installed on the pipeline and cannot be isolated from mainline pipeline pressures.
al properties of non-line pipe components must be based on the documented manufacturing specification for the components. If specifications are not known, usage of manufacturer’s stamped, marked, or tagged material pressure ratings and material type may be used to establish pressure rating. Operators must document the method used to determine the pressure rating and the findings of that determination.
determined from the destructive or nondestructive tests required by this subsection (12)(E) cannot be used to raise the grade or specification of the material, unless the original grade or specification is unknown and MAOP is based on an assumed yield strength of twenty-four thousand (24,000) psi in accordance with subparagraph (3)(D)2.B. (192.107(b)(2)).
(F) Change in Class Location—Required Study. (192.609) Whenever an increase in population density indicates a change in class locations for a segment of an existing steel pipeline operating at a hoop stress that is more than forty percent (40%) 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—
ment involved;
procedures followed in the original construction and a comparison for these procedures with those required for the present class location by the applicable provisions of this rule;
to the extent it can be ascertained from available records;
ry of the segment;
sure and the corresponding operating hoop stress, taking pressure gradient into account, for the segment of pipeline involved; and
lation density increase and physical barriers or other factors which may limit further expansion of the more densely populated area.
(G) Change in Class Location— Confirmation or Revision of Maximum Allowable Operating Pressure. (192.611) 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 (1) of the following three (3) paragraphs:
viously tested in place for a period of not less than eight (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 seventy-two percent (72%) of SMYS of the pipe in Class 1 and 2 locations, sixty percent (60%) of SMYS in Class 3 locations or fifty percent (50%) of SMYS in Class 4 locations;
pressure of the segment involved must be reduced so that the corresponding hoop stress is not more than that allowed by this rule for new segments of pipelines in the existing class location; or
must be tested in accordance with the applicable requirements of section (10), and its maximum allowable operating pressure must then be established according to the following criteria:
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; and
not exceed seventy-two percent (72%) of the SMYS of the pipe in Class 1 and 2 locations, sixty percent (60%) of SMYS in Class 3 locations or fifty percent (50%) of the SMYS in Class 4 locations.
pressure confirmed or revised in accordance with this subsection may not exceed the maximum allowable operating pressure established before the confirmation or revision.
imum allowable operating pressure of a segment of pipeline in accordance with this subsection does not preclude the application of subsections (11)(B) and (C). (192.553 and 192.555)
imum allowable operating pressure that is required as a result of a study under subsection (12)(F) must be completed within twenty-four (24) months of the change in class location. Pressure reduction under paragraph (12)(G)1. or 2. within the twenty-four- (24-) month period does not preclude establishing a maximum allowable operating pressure under paragraph (12)(G)3., at a later date.
(H) Continuing Surveillance. (192.613)
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.
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 paragraphs (12)(M)1. and 2. (192.619[a] and [b])
(I) Damage Prevention Program. (192.614)
graphs (12)(I)6. and 7., each operator of a buried pipeline shall carry out in accordance with this subsection a written program to prevent damage to that pipeline by excavation activities. For the purpose of this subsection, excavation activities include excavation, blasting, boring, tunneling, backfilling, the removal of aboveground structures by either explosive or mechanical means, and other earthmoving operations. Particular attention should be given to excavation activities in close proximity to cast iron mains with remedial actions taken as required by subsection (13)(Z). (192.755).
duties specified in paragraph (12)(I)3. 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 subsection. However, an operator must perform the duties of subparagraph (12)(I)3.D. through participation in the qualified one-call system for Missouri. An operator’s pipeline system must be covered by the qualified one-call system for Missouri.
required by paragraph (12)(I)1. must, at a minimum—
basis, of persons who normally engage in excavation activities in the area in which the pipeline is located. A listing of persons involved in excavation activities shall be maintained and updated at least once each calendar year with intervals not exceeding fifteen (15) months. If an operator chooses to participate in an excavator education program of a one-call notification center, as provided for in subparagraphs (12)(I)3.B. and C., then such updated listing shall be provided to the one-call notification center prior to December 1 of each calendar year. This list should at least include, but not be limited to, the following:
struction companies, engineering firms, etc.—Identification of these should at least include a search of the phone book yellow pages, checking with the area and/or state office of the Associated General Contractors, and checking with the operating engineers local union hall(s);
tricts; and
general notification of the public in the vicinity of the pipeline. Provide for actual notification of the persons identified in subparagraph (12)(I)3.A., at least once each calendar year at intervals not exceeding fifteen (15) months by registered or certified mail, or notification through participation in an excavator education program of a one-call notification center meeting the requirements of subparagraph (12)(I)3.C. Mailings to excavators shall include a copy of the applicable sections of Chapter 319, RSMo, or a summary of the provisions of Chapter 319, RSMo, approved by designated commission personnel, concerning underground facility safety and damage prevention pertaining to excavators. The operator’s public notifications and excavator notifications shall include information concerning the existence and purpose of the operator’s damage prevention program, as well as information on how to learn the location of underground pipelines before excavation activities are begun;
tor’s compliance with the excavator notification requirements of subparagraph (12)(I)3.B., a one-call system’s excavator education program must—
hensive listing of excavators who use the onecall notification center and who are identified by the operators pursuant to the requirements of subparagraph (12)(I)3.A.;
educational mailings to the excavators named on the comprehensive listing maintained pursuant to part (12)(I)3.C.(I), by first class mail; and
following in at least one (1) of the semiannual mailings specified in part (12)(I)3.C.(II): Chapter 319, RSMo or a summary of the provisions of Chapter 319, RSMo, approved by designated commission personnel, concerning underground facility safety and damage prevention which pertain to excavators; an explanation of the types of temporary markings normally used to identify the approximate location of underground facilities; and a description of the availability and proper use of the one-call system’s notification center;
recording notification of planned excavation activities;
subparagraphs (12)(I)3.B.–D. as follows:
recent annual notifications sent to excavators identified in subparagraph (12)(I)3.A., or the four (4) most recent semiannual notifications sent in accordance with subparagraph (12)(I)3.C., must be retained; 20 CSR 4240-40
in subparagraph (12)(I)3.D. shall be retained for at least two (2) years. At a minimum, these records should include the date and the time the request was received, the actions taken pursuant to the request, and the date the response actions were taken; and
required by Chapter 319, RSMo, to be maintained by the notification center shall be available to the operator for at least five (5) years;
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;
buried pipelines in the area of excavation activity before, as far as practical, the activity begins; and
of pipelines that an operator has reason to believe could be damaged by excavation activities:
frequently as necessary during and after the activities to verify the integrity of the pipeline; and
inspection must include leakage surveys.
paragraph (12)(I)3.D. should be evaluated to determine the need for and the extent of inspections. The following factors should be considered in determining the need for and extent of those inspections:
vation activity involved;
facilities;
involved;
facilities;
vation activity is being performed;
should damage occur;
with the operator; and
ring which may not be easily recognized by the excavator.
attention, during and after excavation activities, to the possibility of joint leaks and breaks due to settlement when excavation activities occur near cast iron and threadedcoupled steel.
this subsection is not required for the following pipelines:
ically controlled by the operator; and
petroleum gas system subject to subsection (1)(F) (192.11) or part of a distribution system operated by a person in connection with that person’s leasing of real property or by a condominium or cooperative association.
than municipalities (including operators of master meters) whose primary activity does not include the transportation of gas need not comply with the following:
(12)(I)1. that the damage prevention program be written; and
(12)(I)3.A., (12)(I)3.B., and (12)(I)3.C.
(J) Emergency Plans. (192.615)
procedures to minimize the hazard resulting from a gas pipeline emergency. At a minimum, the procedures must provide for the following:
fying notices of events which require immediate response by the operator;
quate means of communication with appropriate fire, police, and other public officials;
tively to a notice of each type of emergency, including the following:
building;
involving a pipeline facility;
directly involving a pipeline facility; and
equipment, tools, and materials, as needed at the scene of an emergency;
tecting people first and then property;
and pressure reduction in any section of the operator’s pipeline system necessary to minimize hazards to life or property;
tial hazard to life or property;
and other public officials of gas pipeline emergencies and coordinating with them both planned responses and actual responses during an emergency;
(12)(L) (192.617), if applicable, as soon after the end of the emergency as possible; and
controller during an emergency in accordance with subsection (12)(T).
2. Each operator shall—
responsible for emergency action a copy of that portion of the latest edition of the emergency procedures established under paragraph (12)(J)1. as necessary for compliance with those procedures;
personnel and conduct an annual review to assure that they are knowledgeable of the emergency procedures and verify that the training is effective; and
determine whether the procedures were effectively followed in each emergency.
maintain liaison with appropriate fire, police, and other public officials to—
resources of each government organization that may respond to a gas pipeline emergency;
operator’s ability in responding to a gas pipeline emergency;
emergencies of which the operator notifies the officials; and
can engage in mutual assistance to minimize hazards to life or property.
(K) Public Awareness. (192.616)
meter system covered under paragraph (12)(K)10., 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 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). In addition, the program must provide for notification of the intended groups on the following schedule:
tions and persons engaged in excavation related activities must be notified at least annually;
semiannually; and
semiannually by mailings or hand-delivered messages and at least nine (9) times a calendar year by billing messages.
the general program recommendations of API RP 1162 and assess the unique attributes and characteristics of the operator’s pipeline and facilities.
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.
cally include provisions to educate the public, appropriate government organizations, and persons engaged in excavation related activities on:
tem prior to excavation and other damage prevention activities;
unintended releases from a gas pipeline facility;
release may have occurred;
lic safety in the event of a gas pipeline release; and
event.
to advise affected municipalities, school districts, businesses, and residents of pipeline facility locations.
must be as comprehensive as necessary to reach all areas in which the operator transports gas.
English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator’s area.
2005, must have completed their written programs no later than June 20, 2006. The operator of a master meter covered under paragraph (12)(K)10. must complete development of its written procedure by June 13, 2008. Operators must submit their completed programs and any program changes to designated commission personnel as required by subsection (1)(J).
tion and evaluation results must be available for periodic review by designated commission personnel.
a primary activity, the operator of a master meter is not required to develop a public awareness program as prescribed in paragraphs (12)(K)1.–7. Instead the operator must develop and implement a written procedure to provide its customers public awareness messages twice annually. If the master meter is located on property the operator does not control, the operator must provide similar messages twice annually to persons controlling the property. The public awareness message must include:
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.
(M) Maximum Allowable Operating Pressure−Steel or Plastic Pipelines. (192.619 and 192.620)
(12)(M)3., 4., and 6., no person may operate a segment of steel or plastic pipeline at a pressure that exceeds the lowest of the following:
element in the segment, determined in accor-
and adopted in subsection (1)(D)), reduced by the appropriate factor in part (12)(M)1.B.(II); or
quarter inches (12 3/4") (three hundred twenty-four (324) mm) or less in outside diameter and is not tested to yield under this paragraph, two hundred (200) psi (one thousand three hundred seventy-nine (1379) kPa) gauge;
the highest pressure to which the segment was tested after construction or uprated as follows:
the test pressure is divided by a factor of 1.5; and 20 CSR 4240-40
hundred (100) psi (six hundred eighty-nine (689) kPa) gauge or more, the test pressure is divided by a factor determined in accordance with the following table:
4 1.4 1.5 1.5 1.5
1For segments installed, uprated, or converted after July 31, 1977 that are located on a platform in inland navigable waters, including a pipe riser, the factor is 1.5.
sure to which the segment was subjected during the five (5) years preceding the applicable date in the second column. This pressure restriction applies unless the segment was tested in accordance with subparagraph (12)(M)1.B. after the applicable date in the third column or the segment was uprated in accordance with section (11);
All other pipelines. July 1, 1970 July 1, 1965
| dance with sections (3) and (4). However, for | |||||
|---|---|---|---|---|---|
| steel pipe in pipelines being converted under | Pipeline Segment | Pressure Date | Test date | ||
| subsection (1)(H) or uprated under section | Onshore gathering line that first | March 15, 2006, or | Five (5) years preceding | ||
| (11), if any variable necessary to determine | became subject to 49 CFR 192.8 | date | line | becomes | applicable date in second |
| the design pressure under the design formula | |||||
| and 192.9 after April 13, 2006 | subject to this rule, | column. | |||
| in subsection (3)(C) is unknown, one (1) of | |||||
| (see subsection (1)(E)). | whichever is later. | ||||
| the following pressures is to be used as design | |||||
| pressure: | Onshore transmission line that | March 15, 2006 | March 15, 2001 | ||
| (I) Eighty percent (80%) of the first | was a gathering line not subject | ||||
| test pressure that produces yield under sec- | to 49 CFR 192.8 and 192.9 | ||||
| tion N5 of Appendix N of ASME B31.8 | before March 15, 2006 (see | ||||
| (incorporated by reference in 49 CFR 192.7 | subsection (1)(E)). |
| A. A description of the purpose and | |||||
|---|---|---|---|---|---|
| reliability of the pipeline; | |||||
| Factors1, segment - | |||||
| B. An overview of the hazards of the | |||||
| pipeline and prevention measures used; | Installed | Converted | |||
| C. Information about damage preven- | Installed after Nov. 11, | on or after | under | ||
| tion; | Class | Installed before Nov. | 1970 and before July | July 1, | subsection |
| D. How to recognize and respond to a | |||||
| Location | 12, 1970 | 1, 2020 | 2020 | (1)(H) (192.14) | |
| leak; and | |||||
| E. How to get additional information. | 1 | 1.1 | 1.1 | 1.25 | 1.25 |
| (L) Investigation of Failures. (192.617) | 2 | 1.25 | 1.25 | 1.25 | 1.25 |
| Each operator shall establish procedures for | 3 | 1.4 | 1.5 | 1.5 | 1.5 |
AND INSURANCE
operator to be the maximum safe pressure after considering and accounting for records of material properties, including material properties verified in accordance with subsection (12)(E), if applicable, and the history of the pipeline segment, including known corrosion and the actual operating pressure.
pipeline to which this subsection applies unless overpressure protective devices are installed for the segment in a manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with subsection (4)(CC). (192.195)
tions in this subsection 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 five (5) years preceding the applicable date in the second column of the table in subparagraph (12)(M)1.C. An operator must still comply with subsection (12)(G).
pressure that results in a hoop stress greater than seventy-two percent (72%) of SMYS.
paragraphs (12)(M)1. through 4., operators of steel transmission pipelines that meet the criteria specified in paragraph (12)(U)1. must establish and document the maximum allowable operating pressure in accordance with subsection (12)(U).
pipelines must make and retain records necessary to establish and document the MAOP of each pipeline segment in accordance with paragraphs (12)(M)1. through 5. as follows:
as of July 1, 2020 must retain any existing records establishing MAOP for the life of the pipeline;
as of July 1, 2020 that do not have records establishing MAOP and are required to reconfirm MAOP in accordance with subsection (12)(U), must retain the records reconfirming MAOP for the life of the pipeline; and
operation after July 1, 2020 must make and retain records establishing MAOP for the life of the pipeline.
ating pressure for certain steel pipelines. (192.620) The federal regulations at 49 CFR 192.620 are not adopted in this rule.
(N) Maximum Allowable Operating Pressure—High-Pressure Distribution Systems. (192.621)
a high pressure distribution system at a pressure that exceeds the lowest of the following pressures, as applicable:
element in the segment, determined in accordance with sections (3) and (4);
a segment of a distribution system otherwise designated to operate at over sixty (60) psi (414 kPa) gauge, unless the service lines in the segment are equipped with service regulators or other pressure limiting devices in series that meet the requirements of subsection (4)(DD) (192.197[c]);
gauge in segments of cast iron pipe in which there are unreinforced bell and spigot joints;
joint could be subjected without the possibility of its parting; and
operator to be the maximum safe pressure after considering the history of the segment, particularly known corrosion and the actual operating pressures.
pipeline to which this subsection applies, unless overpressure protective devices are installed for the segment in a manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with subsection (4)(CC). (192.195)
(O) Maximum and Minimum Allowable Operating Pressure—Low-Pressure Distribution Systems. (192.623)
sure distribution system at a pressure greater than—
unsafe the operation of any connected and properly adjusted low-pressure gas utilization equipment; or
(14") water column.
sure distribution system at a pressure lower than—
the safe and continuing operation of any connected and properly adjusted low-pressure gas utilization equipment can be assured; or
water column.
(P) Odorization of Gas. (192.625)
line or distribution line must contain a natural odorant or be odorized so that at a concentration in air of one-fifth (1/5) of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell. However, for transmission lines in operation before May 28, 1995, the section of transmission line between the supplier’s delivery point and the odorizer need not meet the requirements of this paragraph.
1995, a combustible gas in a transmission line must comply with the requirements of paragraph (12)(P)1., and the odorizer must be located as close as practical to the delivery point from the supplier.
used, the odorant in combustible gases must comply with the following:
ous to persons, materials, or pipe; and
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.
water to an extent greater than two and onehalf (2 1/2) parts to one hundred (100) parts by weight.
introduce the odorant without wide variations in the level of odorant.
odorant in accordance with this subsection, each operator must conduct, at least monthly, odor intensity tests with an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectable. At individually odorized service lines, the odor intensity shall be checked at least once each calendar year at intervals not to exceed fifteen (15) months. Operators of master meter systems may comply with this paragraph by—
from their gas source that the gas has the proper concentration of odorant; and
at the extremities of the system to confirm that the gas contains odorant.
periodically to assure adequate odorant is available. Odorant injection rates can be a useful monitoring tool for some systems. Each operator should consider when and where to use odorant injection rates.
(R) Purging of Pipelines. (192.629)
by use of gas, the gas must be released into one (1) 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.
gas by use of air, the air must be released into one (1) 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.
(S) Providing Service to Customers.
turns on the flow of gas to a customer (see requirements in subsection (10)(J) for new fuel line installations)—
tested for leakage to at least the delivery pressure; and
accessible customer gas piping, interior and exterior, and all connected equipment shall be conducted to determine that the requirements of any applicable industry codes, standards, or procedures adopted by the operator to assure safe service are met. This visual inspection need not be met for emergency outages or curtailments. In the event a large commercial or industrial customer denies an operator access to the customer’s premises, the operator does not need to comply with the above requirement if the operator obtains a signed statement from the customer stating that the customer will be responsible for inspecting its exposed, accessible gas piping, and all connected equipment, to determine that the piping and equipment meets any applicable codes, standards, or procedures adopted by the operator to assure safe service. In the event the customer denies an operator access to its premises and refuses to sign a statement as described above, the operator may file with the commission an application for waiver of compliance with this provision.
customer or a customer relocated from a different operating district, the operator must provide the customer with the following as soon as possible, but within seven (7) calendar days, unless the operator can demonstrate that the information would be the same:
operator in the event of an emergency or to report a gas odor;
contact the operator when excavation work is to be performed; and
tomer’s responsibility for maintaining his/her gas piping and utilization equipment. In addition, the operator should determine if a customer notification is applicable per subsection (1)(K).
to any customer whose fuel lines or gas utilization equipment are determined to be unsafe. The operator, however, may continue providing service to the customer if the unsafe conditions are removed or effectively eliminated.
performed in accordance with this subsection shall be maintained by the operator for a period of not less than two (2) years.
(T) Control Room Management. (192.631)
1. General.
operator of a pipeline facility with a controller working in a control room who monitors and controls all or part of a pipeline facility through a SCADA system. Each operator must have and follow written control room management procedures that implement the requirements of this subsection, except as follows. For each control room where an operator’s activities are limited to either or both of distribution with less than two hundred fifty thousand (250,000) services or transmission without a compressor station, the operator must have and follow written procedures that implement only paragraphs (12)(T)4. (regarding fatigue), (12)(T)9. (regarding compliance validation), and (12)(T)10. (regarding compliance and deviations).
subsection must be integrated, as appropriate, with operating and emergency procedures required by subsections (12)(C) and (12)(J). An operator must develop the procedures no later than August 1, 2011, and must implement the procedures according to the following schedule. The procedures required by paragraph (12)(T)2.; subparagraphs (12)(T)3.E. and (12)(T)4.B. and C.; and paragraphs (12)(T)6. and (12)(T)7. must be implemented no later than October 1, 2011. The procedures required by subparagraphs (12)(T)3.A.–D. and (12)(T)4.A. and D.; and paragraph (12)(T)5. must be implemented no later than August 1, 2012. The training procedures required by paragraph (12)(T)8. must be implemented no later than August 1, 2012, except that any training required by another paragraph or subparagraph of this subsection must be implemented no later than the deadline for that paragraph or subparagraph.
ator must define the roles and responsibilities of a controller during normal, abnormal, and emergency operating conditions. To provide for a controller’s prompt and appropriate response to operating conditions, an operator must define each of the following:
responsibility to make decisions and take actions during normal operations;
mal operating condition is detected, even if the controller is not the first to detect the condition, including the controller’s responsibility to take specific actions and to communicate with others;
gency, even if the controller is not the first to detect the emergency, including the controller’s responsibility to take specific actions and to communicate with others;
shift-changes and any hand-over of responsibility between controllers; and
qualifications of others with the authority to direct or supersede the specific technical actions of a controller.
operator must provide its controllers with the information, tools, processes, and procedures necessary for the controllers to carry out the roles and responsibilities the operator has defined by performing each of the following:
11.1, and 11.3 of API RP 1165 (incorporated by reference in 49 CFR 192.7 and adopted in (1)(D)) whenever a SCADA system is added, expanded, or replaced, unless the operator demonstrates that certain provisions of sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 are not practical for the SCADA system used;
tion between SCADA displays and related field equipment when field equipment is added or moved and when other changes that affect pipeline safety are made to field equipment or SCADA displays;
nication plan to provide adequate means for manual operation of the pipeline safely, at least once each calendar year, but at intervals not to exceed fifteen (15) months;
at least once each calendar year, but at intervals not to exceed fifteen (15) months; and
dures for when a different controller assumes responsibility, including the content of information to be exchanged.
must implement the following methods to reduce the risk associated with controller fatigue that could inhibit a controller’s ability to carry out the roles and responsibilities the operator has defined:
ule rotations that provide controllers off-duty time sufficient to achieve eight (8) hours of continuous sleep; AND INSURANCE
sors in fatigue mitigation strategies and how off-duty activities contribute to fatigue;
to recognize the effects of fatigue; and
controller hours-of-service, which may provide for an emergency deviation from the maximum limit if necessary for the safe operation of a pipeline facility.
using a SCADA system must have a written alarm management plan to provide for effective controller response to alarms. An operator’s plan must include provisions to:
alarm operations using a process that ensures alarms are accurate and support safe pipeline operations;
month points affecting safety that have been taken off scan in the SCADA host, have had alarms inhibited, generated false alarms, or that have had forced or manual values for periods of time exceeding that required for associated maintenance or operating activities;
alarm set-point values and alarm descriptions at least once each calendar year, but at intervals not to exceed fifteen (15) months;
plan required by this paragraph at least once each calendar year, but at intervals not exceeding fifteen (15) months, to determine the effectiveness of the plan;
general activity being directed to and required of each controller at least once each calendar year, but at intervals not to exceed fifteen (15) months, that will assure controllers have sufficient time to analyze and react to incoming alarms; and
through the implementation of subparagraphs (12)(T)5.A.–E.
must assure that changes that could affect control room operations are coordinated with the control room personnel by performing each of the following:
control room representatives, operator’s management, and associated field personnel when planning and implementing physical changes to pipeline equipment or configuration;
tact the control room when emergency conditions exist and when making field changes that affect control room operations; and
management participation in planning prior to implementation of significant pipeline hydraulic or configuration changes.
must assure that lessons learned from its operating experience are incorporated, as appropriate, into its control room management procedures by performing each of the following:
be reported pursuant to 20 CSR 4240-40.020 to determine if control room actions contributed to the event and, if so, correct, where necessary, deficiencies related to—
device;
and
and
operator’s experience in the training program required by this subsection.
lish a controller training program and review the training program content to identify potential improvements at least once each calendar year, but at intervals not to exceed fifteen (15) months. An operator’s program must provide for training each controller to carry out the roles and responsibilities defined by the operator. In addition, the training program must include the following elements:
conditions likely to occur simultaneously or in sequence;
non-computerized (tabletop) method for training controllers to recognize abnormal operating conditions;
responsibilities for communication under the operator’s emergency response procedures;
troller a working knowledge of the pipeline system, especially during the development of abnormal operating conditions;
are periodically, but infrequently used, providing an opportunity for controllers to review relevant procedures in advance of their application; and
exercises that include both controllers and other individuals, defined by the operator, who would reasonably be expected to operationally collaborate with controllers (control room personnel) during normal, abnormal, or emergency situations. Operators must comply with the team training requirements under this paragraph by no later than January 23, 2018.
must submit their procedures to designated commission personnel per subsection (1)(J).
operator must maintain for review during inspection—
ance with the requirements of this subsection; and
any deviation from the procedures required by this subsection was necessary for the safe operation of a pipeline facility.
(U) Maximum Allowable Operating Pressure Reconfirmation: Steel Transmission Pipelines. (192.624)
transmission pipeline segments must reconfirm the maximum allowable operating pressure (MAOP) of all pipeline segments in accordance with the requirements of this section if either of the following conditions are met:
MAOP in accordance with subparagraph (12)(M)1.B., including records required by paragraph (10)(I)1., are not traceable, verifiable, and complete and the pipeline is located in one (1) of the following locations:
defined in 49 CFR 192.903 (incorporated by reference in section (16)); or
tion.
was established in accordance with paragraph (12)(M)3., the pipeline segment’s MAOP is greater than or equal to thirty percent (30%) of the specified minimum yield strength, and the pipeline segment is located in one ( 1 ) of the following areas:
defined in 49 CFR 192.903 (incorporated by reference in section (16));
tion; or
area” as defined in subsection (1)(B), if the pipeline segment can accommodate inspection by means of instrumented inline inspection tools.
Operators of a pipeline subject to this subsection must develop and document procedures for completing all actions required by this section by July 1, 2021. These procedures must include a process for reconfirming MAOP for any pipelines that meet a condition of paragraph (12)(U)1., and for performing a spike test or material verification in accordance with subsections (10)(K) and (12)(E), if applicable. All actions required by this subsection must be completed according to the following schedule:
actions required by this subsection on at least fifty percent (50%) of the pipeline mileage by July 3, 2028;
actions required by this subsection on onehundred percent (100%) of the pipeline mileage by July 2, 2035 or as soon as practicable, but not to exceed four (4) years after the pipeline segment first meets a condition of paragraph (12)(U)1. (e.g., due to a location becoming a high consequence area), whichever is later; and
constraints limit an operator from meeting the deadlines in this subsection, the operator may petition for an extension of the completion deadlines by up to one (1) year, upon submittal of a notification in accordance with subsection (1)(M) (192.18). The notification must include an up-to-date plan for completing all actions in accordance with this subsection, the reason for the requested extension, current status, proposed completion date, outstanding remediation activities, and any needed temporary measures needed to mitigate the impact on safety.
sure determination. Operators of a pipeline segment meeting a condition in paragraph (12)(U)1. must reconfirm its MAOP using one of the following methods:
a pressure test and verify material properties records in accordance with subsection (12)(E) and the following requirements:
sure test in accordance with section (10). The MAOP must be equal to the test pressure divided by the greater of either 1.25 or the applicable class location factor in (12)(M)1.B.(II);
Determine if the following material properties records are documented in traceable, verifiable, and complete records: diameter, wall thickness, seam type, and grade (minimum yield strength, ultimate tensile strength); and
tion. If any of the records required by (12)(U)3.A.(II) are not documented in traceable, verifiable, and complete records, the operator must obtain the missing records in accordance with subsection (12)(E). An operator must test the pipe materials cut out from the test manifold sites at the time the pressure test is conducted. If there is a failure during the pressure test, the operator must test any removed pipe from the pressure test failure in accordance with subsection (12)(E);
Reduce pressure, as necessary, and limit MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the five (5) years preceding October 1, 2019, divided by the greater of 1.25 or the applicable class location factor in (12)(M)1.B.(II). The highest actual sustained pressure must have been reached for a minimum cumulative duration of eight (8) hours during a continuous thirty- (30-) day period. The value used as the highest actual sustained operating pressure must account for differences between upstream and downstream pressure on the pipeline by use of either the lowest maximum pressure value for the entire pipeline segment or using the operating pressure gradient along the entire pipeline segment (i.e., the location-specific operating pressure at each location).
had a class location change in accordance with subsection (12)(G), and records documenting diameter, wall thickness, seam type, grade (minimum yield strength and ultimate tensile strength), and pressure tests are not documented in traceable, verifiable, and complete records, the operator must reduce the pipeline segment MAOP as follows:
a class location changed from Class 1 to Class 2, from Class 2 to Class 3, or from Class 3 to Class 4, reduce the pipeline MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the five (5) years preceding October 1, 2019, divided by 1.39 for Class 1 to Class 2, 1.67 for Class 2 to Class 3, and 2.00 for Class 3 to Class 4; and
a class location changed from Class 1 to Class 3, reduce the pipeline MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the five (5) years preceding October 1, 2019, divided by 2.00.
segment in accordance with section (11) is allowed if the MAOP is established using Method 2.
Method 2, but desires to use a less conservative pressure reduction factor or longer lookback period, the operator must notify PHMSA in accordance with subsection (1)(M) (192.18) no later than seven (7) calendar days after establishing the reduced MAOP. The notification must include the following details:
tional constraints, special circumstances, or other factors that preclude, or make it impractical, to use the pressure reduction fac- 20 CSR 4240-40
tor specified in subparagraph (12)(U)3.B.;
eling for failure stress pressures and cyclic fatigue crack growth analysis that complies with subsection (13)(EE);
MAOP by another method allowed by this subsection is impractical;
MAOP determined by the operator is safe based on analysis of the condition of the pipeline segment, including material properties records, material properties verified in accordance with subsection (12)(E), and the history of the pipeline segment, particularly known corrosion and leakage, and the actual operating pressure, and additional compensatory preventive and mitigative measures taken or planned; and
ing at the requested MAOP, long-term remediation measures and justification of this operating time interval, including fracture mechanics modeling for failure stress pressures and cyclic fatigue growth analysis and other validated forms of engineering analysis that have been reviewed and confirmed by subject matter experts;
Assessment (ECA). Conduct an ECA in accordance with subsection (12)(V);
Replace the pipeline segment in accordance with this rule;
Pipeline Segments with Small Potential Impact Radius. Pipelines with a potential impact radius (PIR) less than or equal to onehundred-fifty (150) feet may establish the MAOP as follows:
than the highest actual operating pressure sustained by the pipeline during five (5) years preceding October 1, 2019, divided by 1.1. The highest actual sustained pressure must have been reached for a minimum cumulative duration of eight (8) hours during one continuous thirty- (30-) day period. The reduced MAOP must account for differences between discharge and upstream pressure on the pipeline by use of either the lowest value for the entire pipeline segment or the operating pressure gradient (i.e., the location specific operating pressure at each location);
with paragraphs (13)(C)1. and 3. and conduct instrumented leakage surveys in accordance with subsection (13)(D) at intervals not to exceed those in the following table 1: AND INSURANCE
Table 1
Class locations Patrols
(B) Class 3 and Class 4 3 months, but at least six times each calendar year
ing of the pipeline segment in accordance with section (11) is allowed; or
Operators may use an alternative technical evaluation process that provides a documented engineering analysis for establishing MAOP. If an operator elects to use alternative technology, the operator must notify PHMSA in advance in accordance with subsection (1)(M) (192.18). The notification must include descriptions of the following details:
to be used for tests, examinations, and assessments; the method for establishing material properties; and analytical techniques with similar analysis from prior tool runs done to ensure the results are consistent with the required corresponding hydrostatic test pressure for the pipeline segment being evaluated;
conduct tests, examinations, assessments and evaluations, analyze defects and flaws, and remediate defects discovered;
ing original design, maintenance and operating history, anomaly or flaw characterization;
acceptance criteria, including anomaly detection confidence level, probability of detection, and uncertainty of the predicted failure pressure quantified as a fraction of specified minimum yield strength;
tains cracking or may be susceptible to cracking or crack-like defects found through or identified by assessments, leaks, failures, manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with subsection (13)(EE);
dures;
used to justify and establish the MAOP; and (VIII) Documentation of the operator’s processes and procedures used to implement the use of the alternative technology, including any records generated through its use.
records of investigations, tests, analyses, Leakage surveys 3½ months, but at least four times each calendar year 3 months, but at least six times each calendar year
assessments, repairs, replacements, alterations, and other actions taken in accordance with the requirements of this subsection for the life of the pipeline.
(V) Engineering Critical Assessment for Maximum Allowable Operating Pressure Reconfirmation: Steel Transmission Pipelines. (192.632) When an operator conducts an MAOP reconfirmation in accordance with subparagraph (12)(U)3.C. “Method 3” using an ECA to establish the material strength and MAOP of the pipeline segment, the ECA must comply with the requirements of this section. The ECA must assess: threats; loadings, and operational circumstances relevant to those threats, including along the pipeline right-of way; outcomes of the threat assessment; relevant mechanical and fracture properties; inservice degradation or failure processes; and initial and final defect size relevance. The ECA must quantify the interacting effects of threats on any defect in the pipeline.
1. ECA Analysis.
perform an ECA analysis in accordance with paragraph (12)(V)1. are as follows: Diameter, wall thickness, seam type, grade (minimum yield strength and ultimate tensile strength), and Charpy v-notch toughness values based upon the lowest operational temperatures, if applicable. If any material properties required to perform an ECA for any pipeline segment in accordance with paragraph (12)(V)1. are not documented in traceable, verifiable, and complete records, an operator must use conservative assumptions and include the pipeline segment in its program to verify the undocumented information in accordance with subsection (12)(E). The ECA must integrate, analyze, and account for the material properties, the results of all tests, direct examinations, destructive tests, and assessments performed in accordance with subsection (12)(V), along with other pertinent information related to pipeline integrity, including close interval surveys, coating surveys, interference surveys required by section (9), cause analyses of prior incidents, prior pressure test leaks and failures, other leaks, pipe inspections, and prior integrity assessments, including those required by subsections (12)(L) and (13)(DD) and section (16).
mine the predicted failure pressure for the defect being assessed using procedures that implement the appropriate failure criteria and justification as follows:
cracks or crack-like defects remaining in the pipe, or that could remain in the pipe, to determine the predicted failure pressure of each defect in accordance with subsection (13)(EE);
metal loss defects not associated with a dent, including corrosion, gouges, scrapes, or other metal loss defects that could remain in the pipe, to determine the predicted failure pressure. ASME/ANSI B31G (incorporated by reference in 49 CFR 192.7 and adopted in (1)(D)) or R–STRENG (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) must be used for corrosion defects. Both procedures and their analysis apply to corroded regions that do not penetrate the pipe wall over eighty percent (80%) of the wall thickness and are subject to the limitations prescribed in the equations’ procedures. The ECA must use conservative assumptions for metal loss dimensions (length, width, and depth);
ed failure pressure for gouges, scrapes, selective seam weld corrosion, crack-related defects, or any defect within a dent, appropriate failure criteria and justification of the criteria must be used and documented; and
yield and ultimate tensile strength is not known or not documented by traceable, verifiable, and complete records, then the operator must assume thirty thousand (30,000) psi or determine the material properties using subsection (12)(E).
tion of defects to conservatively determine the most limiting predicted failure pressure. Examples include, but are not limited to, cracks in or near locations with corrosion metal loss, dents with gouges or other metal loss, or cracks in or near dents or other deformation damage. The ECA must document all evaluations and any assumptions used in the ECA process.
the lowest predicted failure pressure for any known or postulated defect, or interacting defects, remaining in the pipe divided by the greater of 1.25 or the applicable factor listed in part (12)(M)1.B.(II).
remaining in the pipe. An operator must utilize previous pressure tests or develop and implement an assessment program to determine the size of defects remaining in the pipe to be analyzed in accordance with paragraph (12)(V)1.
pressure test that complied with section (10) to determine the defects remaining in the pipe if records for a pressure test meeting the requirements of section (10) exist for the pipeline segment. The operator must calculate the largest defect that could have survived the pressure test. The operator must predict how much the defects have grown since the date of the pressure test in accordance with subsection (13)(EE). The ECA must analyze the predicted size of the largest defect that could have survived the pressure test that could remain in the pipe at the time the ECA is performed. The operator must calculate the remaining life of the most severe defects that could have survived the pressure test and establish a reassessment interval in accordance with the methodology in subsection (13)(EE).
inspection program in accordance with paragraph (12)(V)3.
ogy” if it is validated by a subject matter expert to produce an equivalent understanding of the condition of the pipe equal to or greater than pressure testing or an inline inspection program. If an operator elects to use “other technology” in the ECA, it must notify PHMSA in advance of using the “other technology” in accordance with subsection (1)(M) (192.18). The “other technology” notification must have—
or technologies to be used for all tests, examinations, and assessments, including characterization of defect size used in the crack assessments (length, depth, and volumetric); and
conduct tests, examinations, assessments and evaluations, analyze defects, and remediate defects discovered.
tion (ILI) program to determine the defects remaining in the pipe for the ECA analysis must be performed using tools that can detect wall loss, deformation from dents, wrinkle bends, ovalities, expansion, seam defects, including cracking and selective seam weld corrosion, longitudinal, circumferential and girth weld cracks, hard spot cracking, and stress corrosion cracking.
might be susceptible to hard spots based on assessment, leak, failure, manufacturing vintage history, or other information, then the ILI program must include a tool that can detect hard spots.
federal incident, as defined in 20 CSR 4240- 40.020(2)(D), attributed to a girth weld failure since its most recent pressure test, then the ILI program must include a tool that can detect girth weld defects unless the ECA analysis performed in accordance with this section includes an engineering evaluation program to analyze and account for the susceptibility of girth weld failure due to lateral stresses.
formed in accordance with subsection (9)(X).
or equivalent methodologies to validate the performance of the ILI tools in identifying and sizing actionable manufacturing and construction related anomalies. Enough data points must be used to validate tool performance at the same or better statistical confidence level provided in the tool specifications. The operator must have a process for identifying defects outside the tool performance specifications and following up with the ILI vendor to conduct additional in-field examinations, reanalyze ILI data, or both.
assessment results must meet the requirements of subsections (13)(H) and (13)(DD) and section (16), and must conservatively account for the accuracy and reliability of ILI, in-the-ditch examination methods and tools, and any other assessment and examination results used to determine the actual sizes of cracks, metal loss, deformation, and other defect dimensions by applying the most conservative limit of the tool tolerance specification. ILI and in-the-ditch examination tools and procedures for crack assessments (length and depth) must have performance and evaluation standards confirmed for accuracy through confirmation tests for the defect types and pipe material vintage being evaluated. Inaccuracies must be accounted for in the procedures for evaluations and fracture mechanics models for predicted failure pressure determinations.
ments must be remediated in accordance with applicable criteria in subsection (13)(H) and 49 CFR 192.933 (incorporated by reference in section (16)).
segment contains cracking or may be susceptible to cracking or crack-like defects found through or identified by assessments, leaks, failures, manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with subsection (13)(EE).
records of investigations, tests, analyses, assessments, repairs, replacements, alterations, and other actions taken in accordance with the requirements of this subsection for the life of the pipeline.
(13) Maintenance.
(B) General. (192.703)
pipeline unless it is maintained in accordance with this section.
becomes unsafe must be replaced, repaired, or removed from service.
and repaired in accordance with section (14).
(C) Transmission Lines—Patrolling. (192.705)
gram to observe surface conditions on and adjacent to the transmission line right-of-way for indications of leaks, construction activity, and other factors affecting safety and operation.
mined by the size of the line, the operating pressures, the class location, terrain, weather, and other relevant factors, but intervals between patrols may not be longer than prescribed in the following table:
Maximum Interval Between Patrols
Class At Highway At All Location and Railroad Other of Line Crossing Locations Locations 1, 2 7 1/2 months; but at 15 months; but at least least twice each once each calendar year calendar year 3 4 1/2 months; but at 7 1/2 months; but at least four times each least twice each calencalendar year dar year 4 4 1/2 months; but at 4 1/2 months; but at least four times each least four times each calendar year calendar year
ing, driving, flying, or other appropriate means of traversing the right-of-way.
(D) Transmission Lines—Leakage Surveys. (192.706)
transmission line must be conducted—
not exceeding seven and one-half (7 1/2) months but at least twice each calendar year;
not exceeding four and one-half (4 1/2) months but at least four (4) times each calendar year; and AND INSURANCE
not exceeding fifteen (15) months but at least once each calendar year.
buried fuel lines connected to a transmission line must be leak surveyed in accordance with subsection (13)(M).
(E) Line Markers for Mains and Transmission Lines. (192.707)
in paragraph (13)(E)2., a line marker must be placed and maintained as close as practical over each buried main and transmission line—
or railroad. Some crossings may require markers to be placed on both sides due to visibility limitations or crossing widths; and
location of the transmission line or main to reduce the possibility of damage or interference.
markers are not required for the following buried pipelines—
located at crossings of or under waterways and other bodies of water;
located in Class 3 or Class 4 locations where placement of a marker is impractical; or
Class 3 or Class 4 locations where a damage prevention program is in effect under (12)(I).
must be placed and maintained along each section of a main and transmission line that is located aboveground.
be written legibly on a background of sharply contrasting color on each line marker:
or “Danger,” followed by the words “Gas (or name of gas transported) Pipeline” all of which, except for markers in heavily developed urban areas, must be in letters at least one inch (1") (25 millimeters) high with onequarter inch (1/4") (6.4 millimeters) stroke; and
phone number (including area code) where the operator can be reached at all times.
(F) Record Keeping. (192.709)
shall keep records covering each leak discovered, repair made, line break, leakage survey, line patrol, and inspection for as long as the segment of transmission line involved remains in service. (192.709)
lines, each operator shall maintain—
leak report for not less than six (6) years;
investigation and classification for not less than six (6) years. These records shall at least contain sufficient information to determine if proper assignment of the leak class was made, the promptness of actions taken, the address of the leak and the frequency of reevaluation and/or reclassification;
repair for the life of the facility involved, except no record is required for repairs of aboveground Class 4 leaks. These records shall at least contain sufficient information to determine the promptness of actions taken, address of the leak, pipe condition at the leak site, leak classification at the time of repair, and other such information necessary for proper completion of DOT annual Distribution and Transmission Line report forms (PHMSA F 7100.1-1 and PHMSA F 7100.2-1); and
veys and line patrols conducted over each segment of pipeline for not less than six (6) years. These records shall at least contain sufficient information to determine the frequency, scope, and results of the leakage survey or line patrol.
each operator shall maintain records of notifications and leakage surveys required by subsection (13)(M) for not less than six (6) years.
(G) Transmission Lines—General Requirements for Repair Procedures. (192.711)
must take immediate temporary measures to protect the public whenever—
that impairs its serviceability is found in a segment of steel transmission line operating at or above forty percent (40%) of the SMYS; and
nent repair at the time of discovery.
make permanent repairs on its pipeline system according to the following:
The operator must make permanent repairs as soon as feasible; and
When an operator discovers a condition on a pipeline covered under section (16)—Pipeline Integrity Management for Transmission Lines (Subpart O), the operator must remediate the condition as prescribed by 49 CFR 192.933(d) (this federal regulation is incorporated by reference and adopted in section (16)).
subparagraph (13)(J)2.C. (192.717[b][3]), no operator may use a welded patch as a means of repair.
(H) Transmission Lines—Permanent Field Repair of Imperfections and Damages. (192.713)
pairs the serviceability of pipe in a steel transmission line operating at or above forty percent (40%) of SMYS must be—
replacing a cylindrical piece of pipe; or
engineering tests and analyses show can permanently restore the serviceability of the pipe.
level during repair operations.
(I) Transmission Lines—Permanent Field Repair of Welds. (192.715) Each weld that is unacceptable under paragraph (5)(I)3. (192.241[c]) must be repaired as follows:
transmission line out of service, the weld must be repaired in accordance with the applicable requirements of subsection (5)(K) (192.245);
dance with subsection (5)(K) (192.245) while the segment of transmission line is in service if—
reduced so that it does not produce a stress that is more than twenty percent (20%) of the SMYS of the pipe; and
be limited so that at least one-eighth inch (1/8") (3.2 millimeters) thickness in the pipe weld remains; and
repaired in accordance with paragraph (13)(I)1. or 2. must be repaired by installing a full encirclement welded split sleeve of appropriate design.
(J) Transmission Lines—Permanent Field Repair of Leaks. (192.717). Each permanent field repair of a leak on a transmission line must be made by—
replacing a cylindrical piece of pipe; or
following methods:
split sleeve of appropriate design, unless the transmission line is joined by mechanical couplings and operates at less than forty percent (40%) of SMYS;
install a properly designed bolt-on-leak clamp;
and on pipe of not more than forty thousand (40,000) psi (276 MPa) SMYS, fillet weld over the pitted area a steel plate patch with rounded corners, of the same or greater thickness than the pipe, and not more than one-half (1/2) of the diameter of the pipe in size;
pipeline in inland navigable waters, mechanically apply a full encirclement split sleeve of appropriate design; or
neering tests and analyses show can permanently restore the serviceability of the pipe.
(K) Transmission Lines—Testing of Repairs. (192.719)
ment of transmission line is repaired by cutting out the damaged portion of the pipe as a cylinder, the replacement pipe must be tested to the pressure required for a new line installed in the same location. This test may be made on the pipe before it is installed.
Each repair made by welding in accordance with subsections (13)(H), (I), and (J) (192.713, 192.715, and 192.717) must be examined in accordance with subsection (5)(I). (192.241)
(L) Distribution Systems—Patrolling. (192.721)
must be determined by the severity of the conditions which could cause failure or leakage and the consequent hazards to public safety.
where anticipated physical movement or external loading could cause failure or leakage must be patrolled—
not exceeding four and one-half (4 1/2) months but at least four (4) times each calendar year; and
vals not exceeding seven and one-half (7 1/2) months, but at least twice each calendar year.
intervals not exceeding fifteen (15) months but at least once each calendar year.
(M) Distribution Systems—Leakage Surveys. (192.723)
system shall conduct periodic instrument leakage surveys in accordance with this subsection.
control program must be determined by the nature of the operations and the local conditions but it must meet the following minimum requirements:
vey must be conducted in business districts, including tests of the atmosphere in gas, electric, telephone, sewer, and water system manholes, at cracks in pavement and sidewalks, and at other locations providing an opportunity for finding gas leaks, at intervals not exceeding fifteen (15) months but at least once each calendar year;
graph (13)(M)2.C., instrument leak detection surveys must be conducted outside of business districts as frequently as necessary, but at intervals not exceeding—
once each calendar year, for unprotected steel pipelines and unprotected steel yard lines;
least once each third calendar year, for all other pipelines and yard lines; and
at least once each third calendar year, for buried fuel lines operating above low pressure, except for buried fuel lines to large commercial/industrial customers that are notified in accordance with paragraph (13)(M)3. Instrument leak detection surveys of buried fuel lines may be conducted around a portion of the perimeter of the building. This perimeter-type survey shall be conducted along the side of the building nearest the meter location (or the fuel line entrances in the case of multiple buildings) and along the closest adjacent side; and
that are required to be leak surveyed under subparagraph (13)(M)2.B., but are located within high security areas such as prisons, notifications to the customer as described in paragraph (13)(M)3. may be conducted instead of a leak survey.
mercial/industrial customers with buried fuel lines operating above low pressure at one (1) or more buildings, that are not leak surveyed in accordance with part (13)(M)2.B.(III), that maintenance is the customer’s responsibility and leak surveys should be conducted. Notification must be provided once each third calendar year, at intervals not exceeding thirty-nine (39) months.
surveys and notifications are contained in subsection (13)(F).
(N) Test Requirements for Reinstating Service Lines and Fuel Lines. (192.725)
(13)(N)2. and 4., each disconnected service line must be tested in the same manner as a new service line and the associated fuel line must meet the requirements of subsection (12)(S) before being reinstated.
line temporarily disconnected from the transmission line or main for any reason must be tested from the point of disconnection to the service line valve in the same manner as a new service line. However, if provisions are made to maintain continuous service, such as by installation of a bypass, any part of the original service line used to maintain continuous service need not be tested. If continuous service is not maintained, the requirements in subsection (12)(S) must be met for the associated fuel line.
line to which service has been discontinued shall have service resumed in accordance with subsection (12)(S). Each fuel line restored after a system outage shall have service resumed in accordance with subparagraph (12)(S)1.A. and the procedures required under subparagraph (12)(J)1.I. (192.615[a][9])
nected from the transmission line or main due to third party damage must be tested from the point of disconnection to the main in the same manner as a new service line, or it may be surveyed from the point of disconnection to the main using a leak detection instrument.
(O) Abandonment or Deactivation of Facilities. (192.727)
ment or deactivation of pipelines in accordance with the requirements of this subsection.
must be disconnected from all sources and supplies of gas, purged of gas, and sealed at the ends. However, the pipeline need not be purged when the volume of gas is so small that there is no potential hazard.
pipeline that is not being maintained under this rule must be disconnected from all sources and supplies of gas, purged of gas, and sealed at the ends. However, the pipeline need not be purged when the volume of gas is so small that there is no potential hazard.
discontinued, one (1) of the following must be complied with:
the flow of gas to the customer must be provided with a locking device or other means designed to prevent the opening of the valve by persons other than those authorized by the operator;
will prevent the flow of gas must be installed in the service line or in the meter assembly; or
physically disconnected from the gas supply AND INSURANCE
and the open pipe ends sealed.
shall ensure that a combustible mixture is not present after purging.
with a suitable compacted material.
that crosses over, under, or through a commercially navigable waterway, the last operator of that facility must file a report upon abandonment of that facility. The addresses (mail and email) and phone numbers given in this paragraph are from 49 CFR 192.727(g) as published on October 1, 2009. Please consult the current edition of 49 CFR part 192 for any updates to these addresses and phone numbers.
data on pipeline facilities abandoned after October 10, 2000, is to the National Pipeline Mapping System (NPMS) in accordance with the NPMS “Standards for Pipeline and Liquefied Natural Gas Operator Submissions.” To obtain a copy of the NPMS Standards, please refer to the NPMS homepage at www.npms.phmsa.dot.gov or contact the NPMS National Repository at (703) 317- 3073. A digital data format is preferred, but hard copy submissions are acceptable if they comply with the NPMS Standards. In addition to the NPMS-required attributes, operators must submit the date of abandonment, diameter, method of abandonment, and certification that, to the best of the operator’s knowledge, all of the reasonably available information requested was provided and, to the best of the operator’s knowledge, the abandonment was completed in accordance with applicable laws. Refer to the NPMS Standards for details in preparing your data for submission. The NPMS Standards also include details of how to submit data. Alternatively, operators may submit reports by mail, fax, or email to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue SE, Washington, DC 20590- 0001; fax (202) 366-4566; email, InformationResourcesManager@phmsa.dot.g ov. The information in the report must contain all reasonably available information related to the facility, including information in the possession of a third party. The report must contain the location, size, date, method of abandonment, and a certification that the facility has been abandoned in accordance with all applicable laws.
(P) Compressor Stations—Inspection and Testing of Relief Devices. (192.731)
sure relieving device in a compressor station must be inspected and tested in accordance with subsections (13)(R) and (T) (192.739 and 192.743), and must be operated periodically to determine that it opens at the correct set pressure.
ment found must be promptly repaired or replaced.
must be inspected and tested at intervals not exceeding fifteen (15) months but at least once each calendar year to determine that it functions properly.
(Q) Compressor Stations—Storage of Combustible Materials and Gas Detection. (192.735 and 192.736)
in quantities beyond those required for everyday use, or other than those normally used in compressor buildings, must be stored a safe distance from the compressor building.
tanks must be protected in accordance with NFPA-30 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
each compressor building in a compressor station must have a fixed gas detection and alarm system, unless the building is—
percent (50%) of its upright side area is permanently open; or
compressor station of one thousand (1,000) horsepower (746 kW) or less.
is necessary for maintenance under paragraph (13)(Q)5., each gas detection and alarm system required by this subsection must—
pressor building for a concentration of gas in air of not more than twenty-five percent (25%) of the lower explosive limit; and
detected, warn persons about to enter the building and persons inside the building of the danger.
required by this subsection must be maintained to function properly. The maintenance must include performance tests.
(R) Pressure Limiting and Regulating Stations—Inspection and Testing. (192.739)
device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding fifteen (15) months but at least once each calendar year to inspections and tests to determine that it is—
capacity and reliability of operation for the service in which it is employed;
(13)(R)2., set to control or relieve at the correct pressures that will prevent downstream pressures from exceeding the allowable pressures under subsections (4)(FF) and (12)(M)–(O);
from dirt, liquids, and other conditions that might prevent proper operation;
rized operation of valves in accordance with paragraph (4)(EE)8.;
functions in accordance with paragraphs (4)(EE)10. and 11. in a manner that is adequate from the standpoint of reliability of operation; and
sure protection in accordance with paragraph (4)(EE)9.
determined under paragraph (12)(M)3., if the MAOP is sixty (60) psi (four hundred fourteen (414) kPa) gauge or more, the control or relief pressure limit is as follows:
stress that is greater than seventy-two percent (72%) of SMYS, then the pressure limit is MAOP plus four percent (4%); or
stress that is unknown as a percentage of SMYS, then the pressure limit is a pressure that will prevent unsafe operation of the pipeline considering its operating and maintenance history and MAOP.
connected to production, gathering, or transmission pipelines, requirements for inspecting and testing devices and equipment are provided in subsection (13)(BB).
(S) Pressure Limiting and Regulating Stations—Telemetering or Recording Gauges. (192.741)
more than one (1) district pressure regulating station and/or furnishing service to more than one thousand (1000) customers must be equipped with graphic telemetering, recording pressure gauges, or another device (other than pressure gauges unless they are continuously monitored) to indicate the gas pressure in the district.
single district pressure regulating station, the operator shall determine the necessity of installing telemetering or recording gauges in the district, taking into consideration the number of customers supplied, the operating pressures, the capacity of the installation and other operating conditions.
high or low pressure, the regulator and the auxiliary equipment must be inspected and the necessary measures employed to correct any unsatisfactory operating conditions.
data shall be identified, dated, and kept on file for a minimum of two (2) years.
(T) Pressure Limiting and Regulating Stations—Capacity of Relief Devices. (192.743)
limiting stations and pressure regulating stations must have sufficient capacity to protect the facilities to which they are connected. Except as provided in paragraph (13)(R)2., these devices must have sufficient capacity to limit the pressure on the facilities to which they are connected to the desired maximum pressure which does not exceed the pressure allowed by subsection (4)(FF). This capacity must be determined at intervals not exceeding fifteen (15) months, but at least once each calendar year, by testing the devices in place or by review and calculations.
determine if a relief device has sufficient capacity, the calculated capacity must be compared with the rated or experimentally determined relieving capacity of the device for the conditions under which it operates. After the initial calculations, subsequent calculations need not be made if the annual review documents that parameters have not changed to cause the rated or experimentally determined relieving capacity to be insufficient.
capacity, a new or additional device must be installed to provide the capacity required by paragraph (13)(T)1.
(U) Valve Maintenance—Transmission Lines. (192.745)
might be required during any emergency must be inspected and partially operated at intervals not exceeding fifteen (15) months but at least once each calendar year.
remedial action to correct any valve found inoperable, unless the operator designates an alternative valve.
(V) Valve Maintenance—Distribution Systems. (192.747)
necessary for the safe operation of a distribution system, must be checked for accessibility and serviced at intervals not exceeding fifteen (15) months but at least once each calendar year.
valves, the use of which may be necessary for the safe operation of a distribution system, shall be inspected at intervals not exceeding fifteen (15) months but at least once each calendar year. At a minimum, the valves that are metallic must be partially operated during alternating calendar years.
tion of a distribution system include, but are not limited to, those which provide:
lation of the system or any portion of it;
tion, preferably from a remote location;
the operator could relight the lost customer services within a period of eight (8) hours after restoration of system pressure; or
ties where historical records indicate conditions of greater than normal pipeline failure risk.
remedial action to correct any valve found inoperable, unless the operator designates an alternative valve.
(W) Vault Maintenance. (192.749)
ing and pressure limiting equipment, and having a volumetric internal content of two hundred (200) cubic feet (5.66 cubic meters) or more must be inspected at intervals not exceeding fifteen (15) months but at least once each calendar year to determine that it is in good physical condition and adequately ventilated.
ment in the vault must be inspected for leaks and any leaks found must be repaired.
be inspected to determine that it is functioning properly.
assure that it does not present a hazard to public safety.
(X) Prevention of Accidental Ignition. (192.751) 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:
being vented into open air, each potential source of ignition must be removed from the area and a fire extinguisher must be provided;
may not be performed on pipe or on pipe components that contain a combustible mixture of gas and air in the area of work; and 20 CSR 4240-40
appropriate.
(Y) Caulked Bell and Spigot Joints. (192.753)
ot joint that is subject to pressures of more than twenty-five (25) psi (172 kPa) gauge must be sealed with—
B. A material or device which—
of the joint;
chemically or mechanically, or both, with the bell and spigot metal surfaces or adjacent pipe metal surfaces; and
that meets the strength, environmental, and chemical compatibility requirements of paragraphs (2)(B)1. and 2. and subsection (4)(B). (192.53[a] and [b] and 192.143)
joint that is subject to pressures of twentyfive (25) psi (172 kPa) gauge or less and is exposed for any reason must be sealed by a means other than caulking.
(Z) Protecting or Replacing Disturbed Cast Iron Pipelines. (192.755) When an operator has knowledge that the support for a segment of a buried cast iron pipeline is disturbed or that an excavation or erosion is nearby, the operator shall determine if more than half the pipe diameter lies within the area of affected soil. For the purposes of this subsection, “area of affected soil” refers to the area above a line drawn from the bottom of the excavation or erosion, at the side nearest the main, at a forty-five degree (45°) angle from the horizontal (a lesser angle should be used for sandy or loose soils, or a greater angle may be used for certain consolidated soils if the angle can be substantiated by the operator). If more than half the pipe diameter lies within the area of affected soil, the following measures/precautions must be taken—
protected, as necessary, against damage during the disturbance by—
tion equipment, trains, trucks, buses, or blasting;
could remove or undermine pipe support;
the pipeline; or
which may subject that segment of the pipeline to bending stress;
diameter, then as soon as feasible, this segment of cast iron pipeline, which shall include a minimum of ten feet (10') beyond AND INSURANCE
the area of affected soil, must be replaced, except as noted in paragraph (13)(Z)4.;
nominal diameter, then as soon as feasible, appropriate steps must be taken to provide permanent protection for the disturbed segment from damage that might result from external loads, including compliance with applicable requirements of subsection (7)(J) (192.319) and paragraph (7)(I)1. (192.317[a]); and
would not necessarily be required if—
removed for a length less than ten (10) times the nominal pipe diameter not to exceed six feet (6');
lies within the area of affected soil for a length less than ten (10) times the nominal pipe diameter not to exceed six feet (6');
operator in the course of routine maintenance, such as leak repairs to the main or service line installation, where the exposed portion of the main does not exceed six feet (6'), and the backfill supporting the pipe is replaced and compacted by the operator; or
was adequately installed to protect the cast iron pipeline during excavation and backfilling.
(BB) Pressure Regulating, Limiting, and Overpressure Protection—Individual Service Lines Directly Connected to Production, Gathering, or Transmission Pipelines. (192.740)
provided in paragraph (13)(BB)3., to any service line directly connected to a production, gathering, or transmission pipeline that is not operated as part of a distribution system.
device, relief device (except rupture discs), automatic shutoff device, and associated equipment must be inspected and tested at least once every three (3) calendar years, not exceeding thirty-nine (39) months, to determine that it is:
capacity and reliability of operation for the service in which it is employed;
rect pressure consistent with the pressure limits of paragraph (4)(DD)2.; and to limit the pressure on the inlet of the service regulator to sixty (60) psi (414 kPa) gauge or less in case the upstream regulator fails to function properly; and
from dirt, liquids, or other conditions that might prevent proper operation.
equipment installed on service lines that only serve engines that power irrigation pumps.
(DD) Transmission Lines: Assessments Outside of High Consequence Areas. (192.710)
to steel transmission pipelines segments with a maximum allowable operating pressure of greater than or equal to thirty percent (30%) of the specified minimum yield strength and are located in—
defined in subsection (1)(B), if the pipeline segment can accommodate inspection by means of an instrumented inline inspection tool (i.e., “smart pig”); and
a pipeline segment located in a “high consequence area” as defined in 49 CFR 192.903 (incorporated in section (16)).
2. General.
must perform initial assessments in accordance with this section based on a risk-based prioritization schedule and complete initial assessment for all applicable pipeline segments no later than July 3, 2034, or as soon as practicable but not to exceed ten (10) years after the pipeline segment first meets the conditions of paragraph (13)(DD)1. (e.g., due to a change in class location or the area becomes a moderate consequence area), whichever is later.
tor must perform periodic reassessments at least once every ten (10) years, with intervals not to exceed one-hundred twenty-six (126) months, or a shorter reassessment interval based upon the type of anomaly, operational, material, and environmental conditions found on the pipeline segment, or as necessary to ensure public safety.
may use a prior assessment conducted before July 1, 2020 as an initial assessment for the pipeline segment, if the assessment met the section (16) requirements for in-line inspection at the time of the assessment. If an operator uses this prior assessment as its initial assessment, the operator must reassess the pipeline segment according to the reassessment interval specified in subparagraph (13)(DD)2.B. calculated from the date of the prior assessment.
assessment conducted in accordance with the requirements of paragraph (12)(U)3. for establishing MAOP may be used as an initial assessment or reassessment under this subsection.
assessments and the reassessments required by paragraph (13)(DD)2. must be capable of identifying anomalies and defects associated with each of the threats to which the pipeline segment is susceptible and must be performed using one (1) or more of the following methods:
inspection tool or tools capable of detecting those threats to which the pipeline is susceptible, such as corrosion, deformation and mechanical damage (e.g., dents, gouges, and grooves), material cracking and crack-like defects (e.g., stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with subsection (9)(X);
ducted in accordance with section (10). The use of section (10) pressure testing is appropriate for threats such as internal corrosion, external corrosion, and other environmentally assisted corrosion mechanisms; manufacturing and related defect threats, including defective pipe and pipe seams; and stress corrosion cracking, selective seam weld corrosion, dents, and other forms of mechanical damage;
spike hydrostatic pressure test conducted in accordance with subsection (10)(K). A spike hydrostatic pressure test is appropriate for time-dependent threats such as stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects;
and in situ direct examination by means of visual examination, direct measurement, and recorded non-destructive examination results and data needed to assess all applicable threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), Inverse Wave Field Extrapolation (IWEX), radiography, and magnetic particle inspection (MPI);
Guided Wave Ultrasonic Testing (GWUT) as described in Appendix F to 49 CFR part 192 (incorporated in section (16));
ment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in 49 CFR 192.923 and with the applicable requirements specified in 49 CFR 192.925, 192.927, and 192.929 (incorporated in section (16)); or
nology” that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using the “other technology” in accordance with subsection (1)(M) (192.18).
lyze and account for the data obtained from an assessment performed under paragraph (13)(DD)3. to determine if a condition could adversely affect the safe operation of the pipeline using personnel qualified by knowledge, training, and experience. In addition, when analyzing inline inspection data, an operator must account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies.
a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than one hundred eighty (180) days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that one hundred eighty (180) days is impracticable.
ply with the requirements in subsections (9)(S), (13)(G), and (13)(H), where applicable, if a condition that could adversely affect the safe operation of a pipeline is discovered.
must analyze and account for all available relevant information about a pipeline in complying with the requirements in paragraphs (13)(DD)1. through 6.
(EE) Analysis of Predicted Failure Pressure. (192.712)
this rule, operators of steel transmission pipelines must analyze anomalies or defects to determine the predicted failure pressure at the location of the anomaly or defect, and the remaining life of the pipeline segment at the location of the anomaly or defect, in accordance with this subsection.
ing corrosion metal loss under this section, an operator must use a suitable remaining strength calculation method including, ASME/ANSI B31G (incorporated by reference in 49 CFR 192.7 and adopted in (1)(D)); R–STRENG (incorporated by reference in 49 CFR 192.7 and adopted in (1)(D)); or an alternative equivalent method of remaining strength calculation that will provide an equally conservative result.
4. Cracks and crack-like defects.
lyzing cracks and crack-like defects under this subsection, an operator must determine predicted failure pressure, failure stress pressure, and crack growth using a technically proven fracture mechanics model appropriate to the failure mode (ductile, brittle, or both), material properties (pipe and weld properties), and boundary condition used (pressure test, ILI, or other).
remaining life. If the pipeline segment is susceptible to cyclic fatigue or other loading conditions that could lead to fatigue crack growth, fatigue analysis must be performed using an applicable fatigue crack growth law (for example, Paris Law) or other technically appropriate engineering methodology. For other degradation processes that can cause crack growth, appropriate engineering analy- 20 CSR 4240-40
sis must be used. The above methodologies must be validated by a subject matter expert to determine conservative predictions of flaw growth and remaining life at the maximum allowable operating pressure. The operator must calculate the remaining life of the pipeline by determining the amount of time required for the crack to grow to a size that would fail at maximum allowable operating pressure.
would fail at MAOP, and the material toughness is not documented in traceable, verifiable, and complete records, the same Charpy v-notch toughness value established in subparagraph (13)(EE)5.B. must be used.
be determined using a fracture mechanics model appropriate to the failure mode (ductile, brittle, or both) and boundary condition used (pressure test, ILI, or other).
the remaining life of the pipeline before fifty percent (50%) of the remaining life calculated by this analysis has expired. The operator must determine and document if further pressure tests or use of other assessment methods are required at that time. The operator must continue to re-evaluate the remaining life of the pipeline before fifty percent (50%) of the remaining life calculated in the most recent evaluation has expired.
ing. For cases in which the operator does not have in-line inspection crack anomaly data and is analyzing potential crack defects that could have survived a pressure test, the operator must calculate the largest potential crack defect sizes using the methods in subparagraph (13)(EE)4.A. If pipe material toughness is not documented in traceable, verifiable, and complete records, the operator must use one (1) of the following for Charpy vnotch toughness values based upon minimum operational temperature and equivalent to a full-size specimen value:
ues from comparable pipe with known properties of the same vintage and from the same steel and pipe manufacturer;
toughness value to determine the toughness based upon the material properties verification process specified in subsection (12)(E);
v-notch upper-shelf toughness level of one hundred twenty (120) foot-pounds; or
an operator demonstrates can provide conservative Charpy v-notch toughness values of the crack-related conditions of the pipeline segment. Operators using an assumed Charpy AND INSURANCE
v-notch toughness value must notify PHMSA in accordance with subsection (1)(M) (192.18).
predicted or assumed anomalies or defects in accordance with this subsection, an operator must use data as follows.
lyze and account for uncertainties in reported assessment results (including tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying tool performance) in identifying and characterizing the type and dimensions of anomalies or defects used in the analyses, unless the defect dimensions have been verified using in situ direct measurements.
dance with this subsection must utilize pipe and material properties that are documented in traceable, verifiable, and complete records. If documented data required for any analysis is not available, an operator must obtain the undocumented data through subsection (12)(E). Until documented material properties are available, the operator shall use conservative assumptions as follows:
must use one of the following for material toughness:
values from comparable pipe with known properties of the same vintage and from the same steel and pipe manufacturer;
notch toughness value to determine the toughness based upon the ongoing material properties verification process specified in subsection (12)(E);
not have a history of reportable incidents caused by cracking or crack-like defects, maximum Charpy v-notch toughness values of 13.0 foot-pounds for body cracks and 4.0 foot-pounds for cold weld, lack of fusion, and selective seam weld corrosion defects;
history of reportable incidents caused by cracking or crack-like defects, maximum Charpy v-notch toughness values of 5.0 footpounds for body cracks and 1.0 foot-pound for cold weld, lack of fusion, and selective seam weld corrosion; or
an operator demonstrates can provide conservative Charpy v-notch toughness values of crack-related conditions of the pipeline segment. Operators using an assumed Charpy vnotch toughness value must notify PHMSA in advance in accordance with subsection (1)(M) (192.18) and include in the notification the bases for demonstrating that the Charpy v-notch toughness values proposed are appropriate and conservative for use in analysis of crack-related conditions;
must assume one of the following for material strength:
or
strength that is the basis for the current maximum allowable operating pressure; and
data. Until pipe wall thickness, diameter, or other data are determined and documented in accordance with subsection (12)(E), the operator must use values upon which the current MAOP is based.
dance with this subsection must be reviewed and confirmed by a subject matter expert.
the life of the pipeline records of the investigations, analyses, and other actions taken in accordance with the requirements of this subsection. Records must document justifications, deviations, and determinations made for the following, as applicable:
the analysis;
mation evaluated, including any multiple inline inspection tool runs;
and evaluation accuracy specifications and tolerances used in technical and operational results;
failure, the equivalent number of annual pressure cycles, and the pressure cycle counting method;
dicted failure pressure from the required fatigue life models and fracture mechanics evaluation methods;
and/or predicted failure pressure calculations;
safety factors;
ified technical subject matter experts; and
management personnel.
(14) Gas Leaks.
(B) Investigation and Classification Procedures.
tion or any leak or odor call from the general public, police, fire, or other authorities or notification of damage to facilities by contractors or other outside sources shall require immediate investigation and classification.
odor notice shall include the use of gas detection equipment upon initial entry into the structure and during investigations within the structure. When investigating an outside leak or odor notice, special attention must be given to those situations where conditions could impair the venting of natural gas to the atmosphere or impair the ability of gas detection equipment to properly detect the presence of gas, such as excessive ground moisture, rain, snow, frozen soil, or wind.
shall be conducted using gas detection equipment. Sampling of the subsurface atmosphere shall be done at sufficient intervals and locations to assure safety to persons and property in the immediate and adjacent area.
leak classifications shall be substantiated by the use of gas detection equipment.
be conducted immediately after the repair of each Class 1 or Class 2 leak, and continued as necessary, to determine the effectiveness of the repair and to assure all hazardous leaks in the affected area are corrected.
on a customer’s premises for any type of customer gas service order or call, including all premises odor calls, tests of the subsurface atmosphere must be made using gas detection equipment, except as noted below. At least one test must be made at a location where the buried service line or yard line is near the structure; for copper service lines, at least one (1) additional test must be made at the customer’s property line, approximately one hundred feet (100') from the structure, or at the service tap at the main, whichever is closest to the structure. In lieu of conducting the tests of the subsurface atmosphere, the operator may conduct a leak survey of this pipe with gas detection equipment capable of detecting gas concentrations of three hundred (300) parts per million, gas-in-air. These tests are not required for collections, discontinuance of service for nonpayment, meter readings, read-ins/read-outs, line locations, atmospheric corrosion protection work or general painting, when relighting after emergency outages or curtailments, when lighting customer pilot lights, cathodic protection work, or if leak tests have been conducted at the location within the previous fifteen (15) months.
(C) Leak Classifications. The leak classifications in this subsection apply to pipelines, and do not apply to fuel lines. The definitions for “pipeline,” “fuel line,” “reading,” “sustained reading,” “building,” “tunnel,” and “vault or manhole” are included in subsection (1)(B). The definition for “reading” is the highest sustained reading when testing in a bar hole or opening without induced ventilation. Thus, the leak classification examples involving a gas reading do not apply to outside pipelines located aboveground. Even though the leak classifications do not apply to fuel lines, an operator must respond immediately to each notice of an inside leak or odor as required in paragraphs (12)(J)1., (14)(B)1., and (14)(B)2. In addition, the requirements in paragraph (12)(S)3. apply to fuel lines that are determined to be unsafe.
to its location and/or magnitude, constitutes an immediate hazard to a building and/or the general public. A Class 1 leak requires immediate corrective action. Examples of Class 1 leaks are: a gas fire, flash, or explosion; broken gas facilities such as contractor damage, main failures or blowing gas in a populated area; an indication of gas present in a building emanating from operator-owned facilities; a gas reading equal to or above the lower explosive limit in a tunnel, sanitary sewer, or confined area; gas entering a building or in imminent danger of doing so; and any leak which, in the judgment of the supervisor at the scene, is regarded as immediately hazardous to the public and/or property. When venting at or near the leak is the immediate corrective action taken for Class 1 leaks where gas is detected entering a building, the leak may be reclassified to a Class 2 leak if the gas is no longer entering the building, nor is in imminent danger of doing so. However, the leak shall be rechecked daily and repaired within fifteen (15) days. Leaks of this nature, if not repaired within five (5) days, may need to be reported as a safety-related condition, as required in 20 CSR 4240-40.020(12) and (13). (191.23 and 191.25)
constitute an immediate hazard to a building or to the general public, but is of a nature requiring action as soon as possible. The leak of this classification must be rechecked every fifteen (15) days, until repaired, to determine that no immediate hazard exists. A Class 2 leak may be properly reclassified to a lower leak classification within fifteen (15) days after the initial investigation. Class 2 leaks due to readings in sanitary sewers, tunnels, or confined areas must be repaired or properly reclassified within fifteen (15) days after the initial investigation. All other Class 2 leaks must be eliminated within forty-five (45) days after the initial investigation, unless it is definitely included and scheduled in a rehabilitation or replacement program to be completed within a period of one (1) year, in which case the leak must be rechecked every fifteen (15) days to determine that no immediate hazard exists. Examples of Class 2 leaks are: a leak from a transmission line discernible twentyfive feet (25') or more from the line and within one hundred feet (100’) of a building; any reading outside a building at the foundation or within five feet (5') of the foundation; any reading greater than fifty percent (50%) gas-in-air located five to fifteen feet (5'–15') from a building; any reading below the lower explosive limit in a tunnel, sanitary sewer, or confined area; any reading equal to or above the lower explosive limit in a vault, catch basin, or manhole other than a sanitary sewer; or any leak, other than a Class 1 leak, which in the judgment of the supervisor at the scene, is regarded as requiring Class 2 leak priority.
constitute a hazard to property or to the general public but is of a nature requiring routine action. These leaks must be repaired within five (5) years and be rechecked twice per calendar year, not to exceed six and one-half (6 1/2) months, until repaired or the facility is replaced. Examples of Class 3 leaks are: any reading of fifty percent (50%) or less gas-inair located between five and fifteen feet (5'– 15') from a building; any reading located between fifteen and fifty feet (15'–50') from a building, except those defined in Class 4; a 20 CSR 4240-40
reading less than the lower explosive limit in a vault, catch basin, or manhole other than a sanitary sewer; or any leak, other than a Class 1 or Class 2 which, in the judgment of the supervisor at the scene, is regarded as requiring Class 3 priority.
leak which is completely nonhazardous. No further action is necessary.
(15) Replacement Programs.
(C) Replacement Program—Unprotected Steel Service Lines and Yard Lines. At a minimum, each investor-owned, municipal, or master meter operator shall establish instrument leak detection survey and replacement programs for unprotected operator-owned and customer-owned steel service lines and yard lines. The operator may choose from the following options, unless otherwise ordered by the commission:
detection surveys on all unprotected steel service lines and yard lines and implement a replacement program where all unprotected steel service lines and yard lines will be replaced by May 1, 1994;
detection surveys on all unprotected steel service lines and unprotected steel yard lines. The operator shall compile a historical summary listing the cumulative number of unprotected steel service lines and yard lines installed, replaced, or repaired due to underground leakage and with active underground leaks in a defined area. Based on the results of the summary, the operator shall initiate replacement, to be completed within eighteen (18) months, of all unprotected steel service lines and yard lines in a defined area once twenty-five percent (25%) or more meet the previously mentioned repair, replacement, and leakage conditions. At a minimum, ten percent (10%) of the customer-owned unprotected steel service lines in the system as of December 15, 1989, must be replaced annually. Beginning with calendar year 1994, a minimum of five percent (5%) of the unprotected steel yard lines, and operator-owned and installed unprotected steel service lines in the system as of December 15, 1989, must be replaced annually; and
detection surveys on all unprotected steel service lines and unprotected steel yard lines and implement a replacement program. The program must prioritize replacements based on the greatest potential for hazards. At a minimum, ten percent (10%) of the customerowned unprotected steel service lines in the system as of December 15, 1989, must be replaced annually. Beginning with calendar year 1994, a minimum of five percent (5%) of the unprotected steel yard lines, and operator-owned and installed unprotected steel service lines in the system as of December 15, 1989, must be replaced annually.
(D) Replacement Program—Cast Iron.
mission lines, feeder lines, or mains shall develop a replacement program to be submitted with an explanation to the commission by May 1, 1990, for commission review and approval. This systematic replacement program shall be prioritized to identify and eliminate pipelines in those areas that present the greatest potential for hazard in an expedited manner. These high priority replacement areas would include, but not be limited to:
located beneath pavement which is continuous to building walls;
located near concentrations of the general public such as Class 4 locations, business districts and schools;
blasting or construction activities have occurred in close proximity to cast iron pipelines;
have had sections replaced as a result of requirements in subsection (13)(Z) (192.755);
lie in areas of planned future development projects, such as city, county, or state highway construction/relocations, urban renewal, etc.; and
exhibit a history of leakage or graphitization.
program and schedule shall also be established for cast iron pipelines not identified by the operator as being high priority.
lines shall replace them by December 31, 1991.
(E) Replacement/Cathodic Protection Program—Unprotected Steel Transmission Lines, Feeder Lines, and Mains. Operators who have unprotected steel transmission lines, feeder lines, or mains shall develop a program to be submitted with an explanation to the commission by May 1, 1990, for commission review and approval. This program shall be prioritized to identify and cathodically protect or replace pipelines in those areas that present the greatest potential for hazard in an expedited manner. These high priority areas should include, but not be limited to:
pipelines located beneath pavement which is continuous to building walls;
lines near concentrations of the general public such as Class 4 locations, business districts, and schools;
blasting, or construction activities have occurred in close proximity to unprotected steel pipelines;
that lie in areas of planned future development projects, such as city, county, or state highway construction/relocations, urban renewal, etc.;
that exhibit a history of leakage or corrosion; and
subject to stray current.
(16) Pipeline Integrity Management for Transmission Lines.
(F) For the purposes of this section, the following substitutions should be made for certain references in the federal pipeline safety regulations that are incorporated by reference in subsection (16)(A).
ence to “part 192” should refer to “20 CSR 4240-40.030” instead.
192.937(c)(2), the references to “subpart J of this part” should refer to “20 CSR 4240- 40.030(10)” instead.
erence to “an incident under part 191” should refer to “a federal incident under 20 CSR 4240-40.020” instead.
ence to “section 192.705” should refer to “20 CSR 4240-40.030(13)(C)” instead.
erence to “section 192.706” should refer to “20 CSR 4240-40.030(13)(D)” instead.
to “section 191.17 of this subchapter” should refer to “20 CSR 4240-40.020(10)” instead.
to “a State authority with which OPS has an interstate agent agreement, and a State or local pipeline safety authority that regulates a covered pipeline segment within that State” should refer to “designated commission personnel” instead.
“section 191.7 of this subchapter” should refer to “20 CSR 4240-40.020(5)(A)” instead.
(17) Gas Distribution Pipeline Integrity Management (IM).
(A) What Definitions Apply to this Section? (192.1001) The following definitions apply to this section.
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.
as defined in paragraph (14)(C)1.
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 section.
program means an overall approach by an operator to ensure the integrity of its gas distribution system.
cal device used to connect sections of pipe. The term ‘‘Mechanical fitting’’ applies only to—
(B) What Do the Regulations in this Section Cover? (192.1003)
graph (17)(B)2., this section prescribes minimum requirements for an IM program for any gas distribution pipeline covered under this rule, including liquefied petroleum gas systems. A gas distribution operator, other than a master meter operator, must follow the requirements in subsections (17)(C)–(G). A master meter operator must follow the requirements in subsection (17)(H).
apply to an individual service line directly connected to a transmission, gathering, or production pipeline.
(D) What Are the Required Elements of an Integrity Management Plan? (192.1007) A written integrity management plan must contain procedures for developing and implementing the following elements:
demonstrate an understanding of its gas distribution system developed from reasonably available information.
pipeline’s design and operations and the environmental factors that are necessary to assess the applicable threats and risks to its gas distribution pipeline.
from past design, operations, and maintenance.
needed and provide a plan for gaining that information over time through normal activities conducted on the pipeline (e.g., design, construction, operations, or maintenance activities).
by which the IM program will be reviewed periodically and refined and improved as needed.
tion of data on any new pipeline installed. The data must include, at a minimum, the location where the new pipeline is installed and the material of which it is constructed.
consider the following categories of threats to each gas distribution pipeline: corrosion, natural forces, excavation damage, other outside force damage, material or welds, equipment failure, incorrect operation, and other concerns that could threaten the integrity of its pipeline. An operator must consider reasonably available information to identify existing and potential threats. Sources of data may include, but are not limited to, incident and leak history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, and excavation damage experience.
must evaluate the risks associated with its distribution pipeline. In this evaluation, the operator must determine the relative importance of each threat and estimate and rank the risks posed to its pipeline. This evaluation must consider each applicable current and potential threat, the likelihood of failure associated with each threat, and the potential consequences of such a failure. An operator may subdivide its pipeline into regions with similar characteristics (e.g., contiguous areas within a distribution pipeline consisting of mains, services, and other appurtenances; areas with common materials or environmental factors), and for which similar actions likely would be effective in reducing risk.
address risks. Determine and implement measures designed to reduce the risks from failure of its gas distribution pipeline. These measures must include an effective leak management program (unless all leaks are repaired when found).
results, and evaluate effectiveness.
measures from an established baseline to evaluate the effectiveness of its IM program. An operator must consider the results of its performance monitoring in periodically reevaluating the threats and risks. These performance measures must include the following:
either eliminated or repaired as required by paragraph (14)(C)1. (or total number of leaks if all leaks are repaired when found), categorized by cause;
ages;
(receipt of information by the underground facility operator from the notification center);
eliminated or repaired, categorized by cause;
either eliminated or repaired as required by paragraph (14)(C)1. (or total number of leaks if all leaks are repaired when found), categorized by material; and
operator determines are needed to evaluate the effectiveness of the operator’s IM program in controlling each identified threat.
An operator must re-evaluate threats and risks on its entire pipeline and consider the relevance of threats in one (1) location to other areas. Each operator must determine the appropriate period for conducting complete program evaluations based on the complexity of its system and changes in factors affecting the risk of failure. An operator must conduct a complete program re-evaluation at least every five (5) years. The operator must consider the results of the performance monitoring in these evaluations.
basis, the four (4) measures listed in parts (17)(D)5.A.(I)–(IV), as part of the annual report required by 20 CSR 4240- 40.020(7)(A). An operator also must report the four (4) measures to designated commission personnel.
(E) What Must an Operator Report When a Mechanical Fitting Fails? (192.1009)
(17)(E)2., each operator of a distribution pipeline system must submit a report on each mechanical fitting failure, excluding any failure that results only in a nonhazardous leak. The report(s) must be submitted in accordance with 20 CSR 4240-40.020(7)(B) (191.12).
ing requirements in paragraph (17)(E)1. do not apply to master meter operators.
(192.1011) An operator must maintain records demonstrating compliance with the requirements of this section for at least ten (10) years. The records must include copies of superseded integrity management plans developed under this section.
(G) When May an Operator Deviate from Required Periodic Inspections Under this Rule? (192.1013)
the frequency of periodic inspections and tests required in this rule on the basis of the engineering analysis and risk assessment required by this section.
proposal to the secretary of the commission. The commission may accept the proposal on its own authority, with or without conditions and limitations as the commission deems appropriate, on a showing that the operator’s proposal, which includes the adjusted interval, will provide an equal or greater overall level of safety.
approved reduction in the frequency of a periodic inspection or test only where the operator has developed and implemented an integrity management program that provides an equal or improved overall level of safety despite the reduced frequency of periodic inspections.
(H) What Must a Master Meter Operator Do to Implement this Section? (192.1015)
2011, the operator of a master meter system must develop and implement an IM program that includes a written IM plan as specified in paragraph (17)(G)2. The IM program for these pipelines should reflect the relative simplicity of these types of pipelines.
agement plan must address, at a minimum, the following elements:
demonstrate knowledge of its pipeline, which, to the extent known, should include the approximate location and material of its pipeline. The operator must identify additional information needed and provide a plan for gaining knowledge over time through normal activities conducted on the pipeline (e.g., design, construction, operations, or maintenance activities);
consider, at minimum, the following categories of threats (existing and potential): corrosion, natural forces, excavation damage, other outside force damage, material or weld failure, equipment failure, and incorrect operation;
evaluate the risks to its pipeline and estimate the relative importance of each identified threat;
to mitigate risks. The operator must determine and implement measures designed to reduce the risks from failure of its pipeline;
results, and evaluate effectiveness. The operator must monitor, as a performance measure, the number of leaks eliminated or repaired on its pipeline and their causes; and
ment. The operator must determine the appropriate period for conducting IM program evaluations based on the complexity of its pipeline and changes in factors affecting the risk of failure. An operator must re-evaluate its entire program at least every five (5) years. The operator must consider the results of the performance monitoring in these evaluations.
for a period of at least ten (10) years, the following records:
with this subsection, including superseded IM plans;
tification; and
and material of all piping and appurtenances that are installed after the effective date of the operator’s IM program and, to the extent known, the location and material of all pipe and appurtenances that were existing on the effective date of the operator’s program.
Appendix A—20 CSR 4240-40.030 (Reserved)
Appendix B to 20 CSR 4240-40.030 Appendix B—Qualification of Pipe and Components
ASTM A53/A53M—Steel pipe, “Standard Specification for Pipe, Steel Black and Hot- Dipped, Zinc-Coated, Welded and Seamless” (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM A106/A106M—Steel pipe, “Standard Specification for Seamless Carbon Steel Pipe for High Temperature Service” (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM A333/A333M—Steel pipe, “Standard Specification for Seamless and Welded Steel Pipe for Low Temperature Service” (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM A381—Steel pipe, “Standard Specification for Metal-Arc-Welded Steel Pipe for Use with High-Pressure Transmission Systems” (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM A671/A671M—Steel pipe, “Standard Specification for Electric-Fusion-Welded Pipe for Atmospheric and Lower Temperatures” (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM A672/A672M—Steel pipe, “Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures” (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM A691/A691M—Steel pipe, “Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High- Pressure Service at High Temperatures” (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM D2513-12ae1, “Standard Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings” (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM F2817–10 ‘‘Standard Specification for Poly (Vinyl Chloride) (PVC) Gas Pressure Pipe and Fittings for Maintenance or Repair’’ (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). B. Other Listed Specifications for Components.
ASME B16.40–2008 ‘‘Manually Operated Thermoplastic Gas Shutoffs and Valves in Gas Distribution Systems’’ (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM D2513–12ae1 ‘‘Standard Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings’’ (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM F1055–98 (2006) ‘‘Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing’’ (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM F1924–12 ‘‘Standard Specification for Plastic Mechanical Fittings for Use on Outside Diameter Controlled Polyethylene Gas Distribution Pipe and Tubing’’ (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM F1948–12 ‘‘Standard Specification for Metallic Mechanical Fittings for Use on Outside Diameter Controlled Thermoplastic Gas Distribution Pipe and Tubing’’ (incorporated by reference, in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM F1973–13 ‘‘Standard Specification for Factory Assembled Anodeless Risers and Transition Fittings in Polyethylene (PE) and Polyamide 11 (PA 11) and Polyamide 12 (PA 12) Fuel Gas Distribution Systems’’ (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
ASTM F2817–10 ‘‘Standard Specification for Poly (Vinyl Chloride) (PVC) Gas Pressure Pipe and Fittings for Maintenance or Repair’’ (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).
II. Steel pipe of unknown or unlisted specification.
(400) lengths of pipe. The weld must be tested in accordance with API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). 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 in 49 CFR 192.7 and adopted in subsection (1)(D)). The same number of chemical tests must be made as are required for testing a girth weld.
D. Tensile properties. If the tensile properties of the pipe are not known, the minimum yield strength may be taken as twenty-four thousand (24,000) psi (165 MPa) or less, or the tensile properties may be established by performing tensile tests as set forth in API Specification 5L (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). 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 20 CSR 4240-40
in paragraph (2)(C)3. of 20 CSR 4240- 40.030. (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 rule if the following requirements are met:
Appendix C to 20 CSR 4240-40.030 Appendix C—Qualification of Welders for Low Stress Level Pipe
diameter. The test weld must be made with the pipe in a horizontal fixed position so that the test weld includes at least one (1) 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 (4) coupons and subjected to a root bend test. If, as a result of this test, two (2) or more of the four (4) coupons develop a crack in the weld material, or between the weld material and base metal, that is more than one-eighth inch (1/8") (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 twelve inches (12").
Appendix D to 20 CSR 4240-40.030 Appendix D—Criteria for Cathodic Protection and Determination of Measurements
I. Criteria for cathodic protection.
(100) millivolts. This polarization voltage shift must be determined in accordance with sections III. and IV. of this appendix. 3) 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. 4) 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 I.B.3) and 4) of this appendix, a minimum negative (cathodic) voltage shift of one hundred fifty (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 paragraphs I.B.3) and 4) of this appendix, a minimum negative (cathodic) polarization voltage shift of one hundred (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 paragraphs I.B.1) and 2) of this appendix, aluminum, if cathodically protected at voltages in excess of one and twotenths (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 alkalis on the metal surface. A voltage in excess of one and twotenths (1.20) volts may not be used unless previous test results indicate no appreciable corrosion will occur in the particular environment. 4) Because aluminum may suffer from corrosion under high pH conditions and because 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 eight (8).
negative (cathodic) polarization voltage shift of one hundred (100) millivolts. This polarization voltage shift must be determined in accordance with sections III. and IV. of this appendix.
tials. 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 paragraphs I.B.3) and 4) of this appendix, they must be electrically isolated with insulating flanges or the equivalent.
IV. Reference half cells.
Appendix E to 20 CSR 4240-40.030 Appendix E—Table of Contents—Safety Standards—Transportation of Gas by Pipeline.
20 CSR 4240-40.030(1) General
20 CSR 4240-40.030(2) Materials
20 CSR 4240-40.030(3) Pipe Design
20 CSR 4240-40.030(4) Design of Pipeline Components
Delivered From Transmission Lines and High-Pressure Distribution Systems to Service Equipment. (192.197)
20 CSR 4240-40.030(5) Welding of Steel in Pipelines
20 CSR 4240-40.030(6) Joining of Materials Other Than by Welding
20 CSR 4240-40.030(7) General Construction Requirements for Transmission Lines and Mains
20 CSR 4240-40.030(8) Customer Meters, Service Regulators, and Service Lines
20 CSR 4240-40.030(9) Requirements for Corrosion Control
20 CSR 4240-40.030(10) Test Requirements
20 CSR 4240-40.030(12) Operations
20 CSR 4240-40.030(13) Maintenance
20 CSR 4240-40.030(14) Gas Leaks
20 CSR 4240-40.030(15) Replacement Programs
20 CSR 4240-40.030(16) Pipeline Integrity Management for Transmission Lines
20 CSR 4240-40.030(17) Gas Distribution Pipeline Integrity Management (IM)
AUTHORITY: sections 386.250, 386.310, and 393.140, RSMo 2016.* This rule originally filed as 4 CSR 240-40.030. Original rule filed Feb. 23, 1968, effective March 14, 1968. Amended: Filed Dec. 28, 1970, effective Jan. 6, 1971. Amended: Filed Dec. 29, 1971, effective Jan. 7, 1972. Amended: Filed Feb. 16, 1973, effective Feb. 26, 1973. Amended: Filed Feb. 1, 1974, effective Feb. 11, 1974. Amended: Filed Dec. 19, 1975, effective Dec. 29, 1975. Emergency amendment filed Jan. 17, 1977, effective Jan. 27, 1977, expired May 27, 1977. Amended: Filed Jan. 17, 1977, effective June 1, 1977. Emergency amendment filed March 15, 1978, effective March 25, 1978, expired July 23, 1978. Amended: Filed 20 CSR 4240-40 March 15, 1978, effective July 13, 1978. Amended: Filed July 5, 1978, effective Oct. 12, 1978. Amended: Filed July 13, 1978, effective Oct. 12, 1978. Amended: Filed Jan. 12, 1979, effective April 12, 1979. Amended: Filed May 27, 1981, effective Nov. 15, 1981. Amended: Filed Dec. 28, 1981, effective July 15, 1982. Amended: Filed Jan. 25, 1983, effective June 16, 1983. Amended: Filed Jan. 17, 1984, effective June 15, 1984. Amended: Filed Nov. 16, 1984, effective April 15, 1985. Amended: Filed Jan. 22, 1986, effective July 18, 1986. Amended: Filed May 4, 1987, effective July 24, 1987. Amended: Filed Feb. 2, 1988, effective April 28, 1988. Rescinded and readopted: Filed May 17, 1989, effective Dec. 15, 1989. Amended: Filed Oct. 7, 1994, effective May 28, 1995. Amended: Filed April 9, 1998, effective Nov. 30, 1998. Amended: Filed Dec. 14, 2000, effective May 30, 2001. Amended: Filed Oct. 15, 2007, effective April 30, 2008. Amended: Filed Nov. 29, 2012, effective May 30, 2013. Amended: Filed Nov. 14, 2016, effective June 30, 2017. Amended: Filed June 4, 2018, effective Jan. 30, 2019. Amended: Filed Dec. 12, 2019, effective July 30, 2020. Amended: Filed June 29, 2021, effective Jan. 30, 2022. *Original authority: 386.250, RSMo 1939, amended 1963, 1967, 1977, 1980, 1987, 1988, 1991, 1993, 1995, 1996; 386.310, RSMo 1939, amended 1979, 1989, 1996; and 393.140, RSMo 1939, amended 1949, 1967. Fields v. Missouri Power & Light Company, 374 SW2d 17 (Mo. 1963). Violations of general law, municipal ordinances, rules of the Public Service Commission and the like are considered and held to be negligence per se. Here, violation of a rule of a private gas company filed with the P.S.C. cannot result in the creation of a cause of action in favor of another person separate and apart from an action based on common law negligence.