Current through Register Vol. 49, No. 9, September, 2024
ADMINISTRATIVE HISTORY OF THE ARKANSAS GAS PIPELINE
CODE
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Docket
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Date
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Order No.
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Subject Matter of Docket/Order
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U-2424
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01/02/73
|
--
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Adoption of Arkansas Gas Pipeline Code.
|
|
U-2683
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01/30/76
|
--
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General Revisions to Code.
|
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U-2794
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02/24/77
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--
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General Revisions to Code.
|
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U-2908
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02/03/78
|
--
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General Revisions to Code.
|
|
U-2999
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02/15/79
|
--
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General revision to Code with emphasis on corrosion
requirements.
|
|
U-3083
|
03/18/80
|
2
|
Adds requirements for qualifying persons and procedures
for the joining of plastic pipe.
|
|
81-040-U
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03/11/81
|
3
|
Amends requirements concerning plastic pipe joining and
external corrosion control monitoring.
|
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82-059-R
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04/16/82
|
6
|
Adds Part 190 - Pipeline Safety Enforcement Procedures,
and updates industry standards publications.
|
|
83-015-R
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03/07/83
|
2
|
Adds requirements for a Damage Prevention Program, and
provides flexibility in scheduling inspections and tests.
|
|
84-034-R
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07/06/84
|
4
|
General Code revisions.
|
|
85-086-R
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08/21/85
|
3
|
Revised Part 191 - Transportation of Natural and Other
Gas by Pipeline: Annual Reports and Incident Reports. Also revised the Code
format. Complete republication by Order No. 4.
|
|
86-169-R
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12/15/86
|
3
|
Revised definition of operator. Amends provision
regarding plastic pipe, welder qualification, preheating, stress relieving,
nondestructive testing, bends and elbows.
|
|
88-005-R
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07/14/88
|
4
|
Revised Part 190 to provide for waivers, extensions,
response to accident recommendations, and re-numbered paragraphs. Part 192
amended for Class locations, MAOP, testing repairs, odorization testing, damage
prevention, & R/V calculation.
|
|
89-034-R
|
08/02/89
|
3
|
Part 191 amended to include Safety-Related Condition
Reports. Part 192 amended for deletion of outdated references, adding
requirements for safety-related conditions to be included in O & M plans,
testing requirements for tie-in joints.
Added Part 199 - Drug Testing. Establishes an employee
drug testing program required of operators subject to Part 192.
|
|
90-015-R
|
03/23/90
|
3
|
General revisions with emphasis on updating of
Standards & Specifications; class location vs. MAOP; cast/ductile iron,
& copper pipe; Part 199 - changes caused by deletion of "Rehabilitation
Committee" & its definition; changes in Drug tests required.
|
|
91-056-R
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06/06/91
|
3
|
Care when using tracer wire with plastic pipe, and
lubrication requirements for valves.
|
|
92-036-R
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05/12/92
|
3
|
Parts 192 and 199 changed to reflect requirement of
operators to amend plans and procedures as necessary for safety. Preface and
Part 190 changed to reflect increase in civil penalties.
|
|
93-020-R
|
04/26/93
|
3
|
Parts 191 and 192 changed to include certain gathering
lines containing 100 ppm or more of hydrogen sulfide. Part 192 further changed
by correcting certain discrepancies not previously discovered. Code format
revised and complete republication of the Arkansas Gas Pipeline Code.
|
|
94-025-R
|
09/12/94
|
4
|
Update of referenced Standards & Specifications;
addition of requirement for gas detection in certain compressor station
buildings; clarification of leakage survey requirements. Part 199 changes to
record keeping, and a new requirement for an annual report on the anti-drug
program.
|
|
95-116-R
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04/27/95
|
3
|
Definitions section and Parts 190 and 192 changed to
reflect the requirement that certain new and replacement pipelines be designed
and constructed to accommodate instrumented internal inspection devices. Part
190 changed to clarify the language in the issuance and handling of show cause
orders. Part 192 changed to require meters which have been installed indoors to
be in a ventilated place and not less than 3 feet from any source of ignition
or source of heat which might damage the meter, to require detailed procedures
in O&M manuals, that operators review and update their O&M manuals each
year, and that operators prepare and follow procedures to safeguard personnel
from unsafe accumulations of vapors or gas in excavated trenches. Part 199
reformatted to add Subpart B, Alcohol Misuse Prevention Program. Preface
changed to include new title of Part 199. Complete republication of the
Arkansas Gas Pipeline Code. |
|
96-181-R
|
08/20/96
|
3
|
Preface and Part 190 changed to reflect increased
civil penalties. Part 192 changed to include notification requirement for
customer-owned service lines, to extend existing excavation damage prevention
requirements for gas pipelines in urban areas to gas pipelines in rural areas,
and to require, with limited exceptions, line markers for transmission lines in
urban areas. Part 199 changed to allow for the possibility of a reduced random
drug testing rate, and to require reporting of information concerning missed
tests. Complete republication of the Arkansas Gas Pipeline Code. |
|
97-034-R
|
04/03/97
|
3
|
Preface changed to explain the codification of the
Natural Gas Pipeline Safety Act. Definition of "petroleum gas" added and
definition of "transmission line" revised in the Definitions section. Numerous
minor changes to Parts 191 and 192. Addition of performance standards for
excess flow valves to Part 192. Appendices A and B to Part 192 updated. Minor
revisions to Part 199. Complete republication of the Arkansas Gas Pipeline
Code. |
|
99-130-R
|
08/02/99
|
3
|
All Parts changed to include metric equivalents for
English measures. Part 192 changed to require that Excess Flow Valves ("EFO")
close at 50% or less of the manufacturer's rated closure flow rate while
operating at 10 pounds per square inch gauge (p.s.i.g.); removed the
requirement to prevent installation of EFO's beneath hard surfaces; require
operators to notify customers of the option to install EFO's before the
installation or replacement of service lines; require that all operators must
participate in a qualified one-call system; added transmission or distribution
of gas containing H2S to reflect the exact language in
Arkansas Code Annotated
23-15-203(3);
removed atmospheric corrosion requirements for offshore facilities. Appendix A
revised to incorporate certain versions of The American Society for Testing and
Materials Standards by reference. Part 199 revised to clarify terms; added
requirements for a Substance Abuse Professional ("SAP"). Complete republication
of the Arkansas Gas Pipeline Code. |
|
00-312-R
|
12/11/00
|
4
|
Part 190.15 revised to include falsification of
paperwork as probable violation. Part 192.17 revised to allow the use of a
certified letter for notification of probable violation. New Subpart N -
Operator Qualification added. Minor changes to Subpart I and M. Complete
republication of the Arkansas Gas Pipeline Code. |
|
04-088-R
|
8/26/04
|
3
|
Adopted Federal Office of Pipeline Safety Amendments
192-86A, 192-89, 192-89A, 192-93, 192-95, 199-19 and 199-21. |
|
06-123-R
|
12/07/06
|
3
|
Adopted Federal Pipeline and Hazardous Material Safety
Administration Amendments 192-94, 192-95 C, 192-96, 192-97, 192-98, 192-99,
192-100, 192-101, 192-102, 192-103, 199-20, 49 CFR Part 193 in its entirety,
Amendment 193-19, Nomenclature Change amendment regarding the change of the
Research and Special Programs Administration into the Pipeline and Hazardous
Materials Safety Administration, Act 1048 of the
82nd General Assembly of the Arkansas Legislature,
and Act 153 of the 83rd General Assembly of the
Arkansas Legislature. Complete republication of the Arkansas Gas Pipeline
Code. |
|
08-167-R
|
5/04/09
|
3
|
Adopted Federal Pipeline and Hazardous Material Safety
Administration amendment 192-103A, update of regulatory references to technical
standards, amendment regarding design and construction standards to reduce
internal corrosion in gas transmission pipelines, 192-104 Integrity Management
Program modifications and clarifications, amendment regarding applicability of
public awareness regulations to certain gas distribution operators, and
amendment regarding administrative procedures, address updates, and technical
amendments. Complete republication of the Arkansas Gas Pipeline
Code. |
|
11-166-R
|
6/08/12
|
5
|
Adopted Federal Pipeline and Hazardous Material Safety
Administration (PHMSA) amendments 107, 108, 109, 110, 111, 112, 114 and 115 to
Part 192. Adopted PHMSA amendments 22 and 23 to Part 193. Adopted PHMSA
amendment 21 to Part 191. Complete republication of the Arkansas Gas Pipeline
Code. |
PREFACE
ARKANSAS GAS PIPELINE CODE
On August 12, 1968, the United States Congress passed Public
Law 90-481, better known as the Natural Gas Pipeline Safety Act of 1968. This
Act authorizes the Secretary of Transportation to administer this law, develop
standards and to regulate enforcement of such standards for the design,
installation, inspection, testing, construction, extension, operation,
replacement and maintenance of pipeline facilities. Enacted on July 5, 1994,
Public
Law 103-272 revised, codified, and enacted the
provisions of the Act without substantive change as Chapter 601 of Title 49,
United States Code. Title
49 U.S.C.
60105 authorizes a state to regulate these
minimum standards under certification to the Secretary of Transportation,
providing certain provisions are met by each state.
On March 15, 1971, the State Legislature of Arkansas enacted
Act 285 into law. This Act, known as the Arkansas Natural Gas Pipeline Safety
Act of 1971, authorized the Arkansas Public Service Commission to administer a
state program pertaining to the design, installation, inspection, testing,
construction, extension, operation, replacement and maintenance of pipeline
facilities used to transport natural gas. The Pipeline Safety Office was
established and tasked with the responsibility of developing and implementing
this program. Act 285 is far reaching and affects directly or indirectly
persons who distribute or use natural gas.
As long as natural gas flows through a closed controlled
system, it remains an efficient, inexpensive and safe servant. However, when it
escapes from its pipes, gas can turn on man violently and quickly. In passing
the Arkansas Natural Gas Pipeline Safety Act, the Arkansas Legislature intended
to provide laws and standards which assured that these systems would continue
to be operated in a safe manner and thereby reduce the possibility of gas
escaping from its closed system. The objective of the pipeline safety program
within Arkansas is to keep the gas confined to a closed, controlled system.
This is best accomplished by requiring gas companies, operators of gas systems
and all persons who install natural gas pipelines to install and maintain them,
using only authorized materials and procedures and to comply with standards
designed to ensure continuing quality of operation and maintenance.
These procedures and standards adopted by the Arkansas Public
Service Commission, as authorized by Act 285, are known as the Arkansas Gas
Pipeline Code. This Code is a mandatory requirement under state law and
non-compliance by any person(s) engaging in the transportation of gas or who
owns or operates pipeline facilities, is subject to a civil penalty, not to
exceed $100,000 for each violation for each day the violation continues, except
that the maximum civil penalty may not exceed $1,000,000 for any related series
of violations. The law also provides authority for the Commission to file suit
to restrain violations of the Code, including the restraint of transportation
of gas or the operation of a pipeline facility.
The Arkansas Gas Pipeline Code is comprised of Parts 190,
Enforcement Procedures; 191, Annual and Incident Reports; 192, Minimum Safety
Standards; 193, Liquefied Natural Gas Facilities; and 199, Drug and Alcohol
Testing. The paragraphs in Parts 191, 192, 193, and 199 correspond to the
paragraph numbers of Parts 191, 192, 193, and 199 of Title 49, Code of Federal
Regulations, Pipeline Safety Regulations.
DEFINITIONS
DEFINITIONS OF WORDS/PHRASES USED IN THE ARKANSAS GAS PIPELINE
CODE
Abandoned means permanently
removed from service.
Active Corrosion means continuing
corrosion that, unless controlled, could result in a condition that is
detrimental to public safety.
Administrator means the
Administrator of the Pipeline and Hazardous Materials Safety Administration or
any person to whom authority in the matter concerned has been delegated by the
U.S. Secretary of Transportation.
Alarm means an audible or visible
means of indicating to the controller that equipment or processes are outside
operator-defined, safety-related parameters.Business
District means a location where gas mains are utilized to serve
customers that are predominately commercial in nature, and where the street
and/or sidewalk paving generally extends from the centerline of a thoroughfare
to the established building line on either side.
Change to a segment of pipeline
means a physical change in the pipeline or significant changes in operating
pressure.
Commission means Arkansas Public
Service Commission or any person whom the Commission has delegated authority in
the matter concerned.
Control Room means an operations
center staffed by personnel charged with the responsibility for remotetly
monitoring and controlling a pipeline facility.
Controller means a qualified
individual who remotely monitors and controls the safety-related operations of
a pipeline facility via a SCADA system from a control room, and who has
operational authority and accountability for the remote operational functions
of the pipeline facility.
Customer Meter means the meter
that measures the transfer of gas from an operator to a consumer.
Distribution Line means a
pipeline other than a gathering or transmission line.
Electrical Survey means a series
of closely spaced pipe-to-soil readings over pipelines which are subsequently
analyzed to identify locations where a corrosive current is leaving the
pipeline.
Gas means natural, manufactured,
liquefied natural, flammable gas or gas which is toxic or corrosive.
Gathering Line means a pipeline
that transports gas from a current production facility to a transmission line
or main.
High Pressure Distribution System
means a distribution system in which the gas pressure in the main is higher
than the pressure provided to the customer.
Key Valves means shut off valves
in a distribution system or transmission line which may be necessary to isolate
segments of a system or line for emergency purposes.
Line Section means a continuous
run of transmission line between adjacent compressor stations, between a
compressor station and storage facilities, between a compressor station and a
block valve, or between adjacent block valves.
Listed Specification means a
specification listed in Section I of Appendix B to Part 192.
Low-Pressure Distribution System
means a distribution system in which the gas pressure in the main is
substantially the same as the pressure provided to the customer.
Main means a distribution line
that serves as a common source of supply for more than one service line.
Master Meter System means a
pipeline system for distributing gas within, but not limited to, a definable
area, such as a mobile home park, housing project, or apartment complex, where
the operator purchases metered gas from an outside source for resale through a
gas distribution pipeline system. The gas distribution pipeline system supplies
the ultimate consumer who either purchases the gas directly through a meter or
by other means, such as rents.
Maximum Actual Operating Pressure
means the maximum pressure that occurs during normal operations over a period
of one year.
Maximum Allowable Operating Pressure
(MAOP) means the maximum pressure at which a pipeline or
segment of a pipeline may be operated under this code.
Mobile Home Park means two or
more mobile homes located on a contiguous tract of land.
Municipality means a city, county
or any other political subdivision of the State of Arkansas.
Operator means a person
who:
(1) Engages in the transportation
of gas; or
(2) Operates a
distribution system within a mobile home park, public housing authority, or
multiple building complex. The system is not owned, nor the responsibility of a
public or municipal utility, and is used to transport gas from a master meter
or a public/municipal utility main to consumers who may or may not be metered.
Gas is not consumed solely by the owner/operator.
Person means an individual, firm,
joint venture, partnership, corporation, association, State, municipality,
cooperative association, or joint stock association, and includes any trustee,
receiver, assignee, or personal representative thereof.
Petroleum Gas means propane,
propylene, butane (normal butane or isobutanes), and butylene (including
isomers), or mixtures composed predominantly of these gases, having a vapor
pressure not exceeding 208 p.s.i.g. (1434 kPa) gage at 100°F
(38°C).
Petroleum Refinery means an
industrial or manufacturing facility or plant primarily engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants or
other products through the processing of petroleum crude oil that is subject
to:
(A) The federal Environmental
Protection Agency Standards of Performance for New Stationary Sources set forth
in Subpart GGG of 40 CFR part 60 or successor regulations;
(B) The federal
Environmental Protection Agency Chemical Accident Prevention
Provisions set forth in Subparts, A, B, D, E, F, G, and H of 40 CFR Part 68 or
successor regulations; and
(C) The federal Occupational Safety and
Health Administration Regulations governing process safety management of highly
hazardous chemicals set forth in
29 CFR
§
1910.119 or successor
regulations;
Pipe means any pipe or tubing
used in the transportation of gas, including pipe-type holders.
Pipeline or Pipeline System means
all parts of those physical facilities through which gas moves in
transportation, including, but not limited to, pipe, valves and other
appurtenances attached to pipe, compressor units, metering stations, regulator
stations, delivery stations, holders, and fabricated assemblies.
Pipeline Environment includes
soil resistivity (high or low), soil moisture (wet or dry), soil contaminants
that may promote corrosive activity, and other known conditions that could
affect the probability of active corrosion.
Pipeline Facilities includes
without limitation, new and existing pipe, pipe rights-of-way, and any
equipment, facility or building used in the transportation of gas or the
treatment of gas during the course of transportation of gas.
Production Facilities includes
without limitation, piping or equipment used in the production, extraction,
recovery, lifting, stabilization, separation or treatment of natural gas or
associated storage or measurement from the wellhead to a meter where the gas is
transferred to a custodian other than the well operator for gathering or
transport, commonly known as a 'custodial transfer meter'.
Production Process means the
extraction of gas from the geological source of supply to the surface of the
earth, thence through the lines and equipment used to treat, compress and
measure the gas between the wellhead and the meter where it is either sold or
delivered to a custodian other than the well operator for
gathering and transport to a place of sale, sometimes called 'custodial
transfer meter'.
Service Line means a distribution
line that transports gas from a common source of supply to an individual
customer, to two adjacent or adjoining residential or small commercial
customers, or to multiple residential or small commercial customers served
through a meter header or manifold. A service line ends at the outlet of the
customer meter or at the connection to a customer's piping, whichever is
further downstream, or at the connection to customer piping if there is no
meter.
Service Regulator means the
device on a service line that controls the pressure of gas delivered from a
higher pressure to the pressure provided to the customer. A service regulator
may serve one customer or multiple customers through a meter header or
manifold.
SMYS means specified minimum
yield strength, and is:
(1) For steel
pipe manufactured in accordance with a listed specification, the yield strength
specified as a minimum in that specification; or
(2) For steel pipe manufactured in accordance
with an unknown or unlisted specification, the yield strength determined in
accordance with § 192.107(b).
Supervisory Control and Data Acquisition (SCADA)
System means a computer-based system or systems used by a
controller in a control room that collects and displays information about a
pipeline facility and may have the ability to send commands back to the
pipeline facility.
System means all pipeline
facilities used by a particular operator in the transportation of gas,
including, but not limited to line pipe, valves and other appurtenances
connected to line pipe, compressor units, fabricated assemblies associated with
compressor units, metering (including customers' meters) and delivery stations,
and fabricated assemblies in metering and delivery stations.
Test Failure means a break or
rupture that occurs during strength proof testing of transmission or gathering
lines that are of such magnitude as to require repair before continuation of
the test.
Transmission Line means a
pipeline, other than a gathering line, that:
(1) Transports gas from a gathering line or
storage facility to a gas distribution center, storage facility, or large
volume customer that is not down-stream from a gas distribution
center;
(2) Operates at a hoop
stress of 20 percent or more SMYS;
(3) Or a pipeline that transports gas within
a storage field.
NOTE: A large volume customer may receive similar
volumes of gas as a distribution center, and includes factories, power plants,
and institutional users of gas.
Transportation of Gas means the
gathering, transmission or distribution of gas by pipeline or the storage of
gas in or affecting interstate, intrastate, or foreign commerce.
PART 190
-PIPELINE SAFETY ENFORCEMENT
PROCEDURES
SUBPART A
-GENERAL
§ 190.1
Purpose.
This part prescribes procedures utilized by the Arkansas Public
Service Commission (Commission) in carrying out its responsibilities regarding
pipeline safety under the Arkansas Natural Gas Pipeline Safety Act of 1971 (Act
285 of 1971, as amended; Ark. Code Ann. §
23-15-201 -
23-15-216).
Any conflict between the Commission's Rules and Regulations and the Arkansas
Statutes shall be resolved in favor of the statutes.
§ 190.3
Service.
Each show cause order issued under this part shall be served in
accordance with the current provisions of the Commission's Rules of Practice
and Procedure and Ark. Code Ann. §
23-2-405.
§ 190.5
Subpoenas,
Witness Fees.
The issuance of subpoenas and payment of witness fees shall be
in accordance with the current provisions of the Commission's Rules of Practice
and Procedure and Ark. Code Ann. §
23-2-402
and §
23-2-414.
§ 190.7
Extension of
Time.
In those instances when the actions necessary to correct
documented deficiencies will exceed the time limit given in the notice of
probable violation, an operator may request an extension of time in order to
effect compliance. Each request must detail the reason(s) why compliance cannot
be accomplished by the original suspense date, and the date the operator
believes the necessary compliance actions can be completed. If the Commission
finds the request to be reasonable a new suspense date may be
established.
§ 190.9
Petitions for Finding or Approval.
(a) In circumstances where a rule contained
in Part 192 or Part 193 authorizes the Administrator to make a finding or
approval, an operator may petition the Administrator for such a finding or
approval.
(b) Each petition must
refer to the rule authorizing the action sought and contain information or
arguments that justify the action. Unless otherwise specified, no public
proceeding is held on a petition before it is granted or denied. After a
petition is received, the Administrator or participating state agency notifies
the petitioner of the disposition of the petition or, if the request requires
more extensive consideration or additional information or comments are
requested and delay is expected, of the date by which action will be taken. For
operators seeking a finding or approval involving intrastate pipeline
transportation, petitions must be sent to: Pipeline Safety Office, Arkansas
Public Service Commission, P.O. Box 400, Little Rock, Arkansas
72203-0400.
(c) All petitions must
be received at least 90 days prior to the date by which the operator requests
the finding or approval to be made.
(d) The Administrator will make all findings
or approvals of petitions initiated under this section. The Pipeline Safety
Office (PSO), upon receiving petitions initiated under this paragraph, shall
provide the Administrator a written recommendation by certified mail, return
receipt requested as to the disposition of any petition received by the PSO.
Where the Administrator does not reverse or modify a recommendation made by the
PSO within 10 business days of its receipt, the recommended disposition shall
constitute the Administrator's decision on the petition.
§ 190.11
Waivers.
If unusual difficulty results from implementing a safety
standard in Part 192 or Part 193, application may be made to the Commission for
exemption from a particular standard. The application for exemption shall be
accompanied by a thorough justification for requested actions.
SUBPART B
-ENFORCEMENT
§ 190.15
Inspections, Production of Records, and Accident Investigations.
(a) The Commission may conduct inspections
and investigate accidents in accordance with Ark. Code Ann. §
23-15-207.
Operators are required to provide records requested by the Commission pursuant
to Ark. Code Ann. §
23-15-206(b)
for any inspection or accident investigation.
(b) If an inspection or accident
investigation indicates that a probable violation exists, or if an operator
falsifies records, or fails to provide any record(s) requested by the
Commission, a notice of probable violation will be sent to the operator. For
the purposes of this rule, a probable violation for failing to provide records
shall arise only from failure to provide records required by § 190.15 (a),
in the form in which they are maintained in the ordinary course of business.
Consistent with the requirements of Rule 3.05 and Section 13 of the
Commission's Rules of Practice and Procedure, the operator shall be allowed a
minimum of 15 days to respond after service of any such request for records.
For purposes of this rule, falsifying records shall mean "the original entry or
subsequent modification of any official record with the intent to mislead or
deceive a third party later examining the document."
(c) If an accident investigation results in
the PSO making recommendations in a formal accident investigation report, the
operator will make written response to those recommendations within the time
frame specified in the report.
§
190.17
Notice of Probable Violation.
(a) The Commission begins enforcement
proceedings by serving a notice of probable violation of the Arkansas Gas
Pipeline Code or any order issued thereunder. This notification shall advise
the operator that a written response is required and that failure to respond
may result in enforcement action in accordance with § 190.19.
(b) A notice of probable violation issued
under this section shall include:
(1)
Statement of the provisions of the laws, regulations or orders which the
respondent is alleged to have violated and a statement of the evidence upon
which the allegations are based;
(2) Notice of response options available to
the respondent.
(c) The
notice of probable violation shall normally be in the form of an inspection
report mailed to the person charged. However, the notice of probable violation
may be served in the form of a certified letter or show cause order.
(d) A notice of probable violation for
failure to produce or falsification of records may be served in the form of a
certified letter or show cause order. Falsification of records may also be
referred to the Inspector General of the U.S. Department of Transportation for
investigation and prosecution under applicable provisions of federal criminal
law.
§ 190.19
Show Cause Orders.
The Commission may issue a show cause order notifying the owner
or operator of a probable violation and advising the person to correct it or be
subject to enforcement action. The severity of the probable violation shall be
the determining factor in the type of notice issued by the Commission. A show
cause order shall be served as provided in § 190.3.
§ 190.21
Response Options.
An operator has 20 calendar days from the date of receipt of a
show cause order to respond. The operator may:
(a) Submit written response to the
allegations. The written response may contain one of the following:
(1) Evidence to rebut the allegations of the
show cause order; or
(2) Actions
taken to achieve compliance; or
(3)
A request for an extension of time to correct the alleged probable
violation(s).
(b)
Request a hearing.
(1) A request for a hearing
shall be in writing and shall conform to the Commission's Rules of Practice and
Procedure.
Failure of the operator to respond in a timely manner to a show
cause order under either subsection (a) or (b) of this section shall constitute
a waiver of the operator's right to contest the allegations. The Commission may
then act on the basis of the case file compiled by the Staff.
§ 190.23
Case File.
The Case File compiled by the Staff after the issuance of a
show cause order shall contain the following information:
(a) The inspection reports and any other
evidence of alleged violations;
(b)
A copy of the show cause order;
(c)
Any material submitted by the operator pursuant to § 190.21(a);
and
(d) The evaluation of the Staff
and their recommendations for final action.
§ 190.25
Final Order.
The Commission shall issue a final order at the conclusion of
any proceedings initiated by a show cause order. The final order shall
include:
(a) Findings of fact
addressing all material issues and conclusions of law;
(b) A statement of the amount of the civil
penalty, if any, and the procedures for the payment of the penalty;
and
(c) A statement of the
necessary actions to be taken by the operator and a schedule for completion of
those actions, if any are found to be necessary.
§ 190.27
Petitions for
Reconsideration.
Subsequent to a final order, the operator may request a
rehearing pursuant to Ark. Code Ann. §
23-2-422,
and the Commission's Rules of Practice and Procedure.
§ 190.29
Civil Penalties.
The Commission may assess civil penalties for violations of the
Arkansas Gas Pipeline Code not to exceed one hundred thousand dollars
($100,000) for each violation for each day that the violation persists, except
that the maximum civil penalty shall not exceed one million dollars
($1,000,000) for any related series of violations. Before assessing a civil
penalty, the Commission shall follow the procedures established by §§
190.19 and 190.25.
§
190.31
Payment of Civil Penalties.
Any civil penalty not promptly paid to the Commission shall be
recovered with interest thereon from the date of the order in a civil action
brought by the Commission.
SUBPART C
-SPECIFIC RELIEF
§ 190.41
Hazardous
Conditions.
(a) Whenever the
Commission finds a particular facility to be hazardous to life or property, it
shall be empowered to require the person operating such facility to take such
corrective measures necessary to remove such hazards.
(b) Where the operator contests the
corrective measures imposed by the Commission, the operator may request a
hearing which shall be made in writing and shall conform to the Commission's
Rules of Practice and Procedure. A request for a hearing under this paragraph
shall not act to stay the corrective measures initially required by the
Commission.
§
190.43
Injunctive Action.
The Commission may restrain violations of the Arkansas Natural
Gas Pipeline Safety Act of 1971, as amended, by seeking injunctive relief
pursuant to Arkansas Code Ann. §
23-15-212.
PART 191
-TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: ANNUAL REPORTS AND
INCIDENT REPORTS
§ 191.1
Scope.
This part prescribes requirements for the reporting of
incidents, safety-related conditions, and annual pipeline summary data, and
applies to all persons engaged in the transportation of gas. Leaks/ignition
which were intentionally caused by the operator are not reportable. This part
does not apply to leaks and test failures that occur in the gathering of gas
through a pipeline that operates at less than 0 p.s.i.g. (0 kPa), and through a
pipeline that is not a regulated onshore gathering line (as determined in
§ 192.8 of this subchapter); however it shall apply to the gathering,
transmission or distribution of gas containing 100 or more parts-per-million of
hydrogen sulfide from the custodial transfer meter through any pipeline, rural
or non-rural, to and through any pipeline facility that removes hydrogen
sulfide except that portion of such a pipeline or pipeline facility that is
located within the fenced boundary of a petroleum refinery. For those lines
that are jurisdictional solely on the basis of their hydrogen sulfide content,
the reports required by this part shall be submitted to the PSO and not to the
U.S. Department of Transportation.
§ 191.5
Telephonic Notice of
Certain Incidents.
(a) At the earliest
practicable moment following discovery, each operator shall give notice in
accordance with paragraph (b) of this section of any natural gas incident
involving a release of gas from a pipeline, or of liquefied natural gas,
liquefied petroleum gas, refrigerant gas, or gas from an LNG facility, and that
results in one or more of the following consequences:
(1) A death or personal injury requiring
in-patient hospitalization; or
(2)
Estimated property damage of $50,000 or more, including loss to the operator
and others, or both, but excluding cost of gas lost; or
(3) Unintentional estimated gas loss of three
million cubic feet or more;
(4) An
event that results in an emergency shutdown of an LNG facility. Activation of
an emergency shutdown system for reasons other than an actual emergency does
not constitute an incident.
(5) An
event that is significant, in the judgement of the operator, even though it did
not meet the criteria of subparagraphs (1), (2), (3) or (4).
Incidents reportable under Subparagraphs (1), (2), (3), (4) or
(5) above, include incidents occurring on all pipelines up to the outlet side
of the customer's meter and must be reported at the earliest practicable moment
unless there is evidence that the leak probably did not occur on pipelines used
by the operator in the transportation of gas, in which case, notice may be
delayed until determination is made.
(b) Each notice required by paragraph (a) of
this section must be made to the National Response Center either by telephone
to 800-424-8802 (in Washington, DC, 202-267-2675) or electronically at
http://www.nrc.uscg.mil and must
include the following information:
(1) Names
of operator and person making report and their telephone numbers.
(2) The location of the incident.
(3) The time of the incident.
(4) The number of fatalities and personal
injuries, if any.
(5) All other
significant facts that are known by the operator that are relevant to the cause
of the incident or extent of the damages.
(c) In addition to the telephonic notice
required in paragraph (b) of this section, notice will also be made by
telephone to (501) 682-5716 during normal business hours Monday through Friday.
Reports outside normal hours will be made to PSO personnel in accordance with
instructions issued by the PSO.
(d)
In addition to the requirements of paragraph (a) of this section, all gas
related incidents which result in personal injury requiring out-patient
treatment and/or property damage, including cost of lost gas, totaling $5,000
but less than $50,000, shall be telephonically reported to the Commission as
required by paragraph (c) above.
§ 191.7
Addressee for Written
Reports.
(a) Each written report
required by this part, with the exception of the "Safety-Related Condition
Report", will be made to Pipeline Safety Office, Arkansas Public Service
Commission, P. O. Box 400, Little Rock, Arkansas 72203-0400. These will be
submitted in duplicate.
(b) The
Safety-Related Condition Reports required by §§ 191.23 and 191.25
will be submitted directly to: Office of Pipeline Safety, Pipeline and
Hazardous Materials Safety Administration, U. S. Department of Transportation,
the Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE,
Washington, DC 20590-0001. A copy of these reports must be submitted
concurrently to the Pipeline Safety Office, Arkansas Public Service
Commission.
§ 191.9
Distribution System: Incident Report.
(a) Each operator of a distribution pipeline
system shall submit Department of Transportation Form PHMSA F7100.1 as soon as
practicable but not more than 20 days after detection of an incident required
to be reported under § 191.5(a) or (d).
(b) When additional relevant information is
obtained after the report is submitted under paragraph (a) of this section, the
operator shall make supplementary reports as deemed necessary with a clear
reference by date and subject to the original report.
(c) Master meter operators are not required
to submit an incident report as required by this section.
§ 191.11
Distribution System:
Annual Report.(a) Except as provided
in paragraph (b) of this section, each operator of a distribution system shall
submit an annual report for that system on Department of Transportation Form
PHMSA F7100.1-1. This report must be submitted for the preceding calendar year
no later than February 15 of each year.
(b) The annual report required by this
section need not be submitted with respect to:
(1) Petroleum gas systems which serve fewer
than 100 customers from a single source; or
(2) Master meter systems.
§ 191.12
Distribution Systems: Mechanical Fitting Failure Reports
Each mechanical fitting failure, as required by §
192.1009, must be submitted on a Mechanical Fitting Failure Report Form PHMSA
F-7100.1-2. An operator must submit a mechanical fitting failure report for
each mechanical fitting failure that occurs within a calendar year not later
than March 15 of the following year (for example, all mechanical failure
reports for calendar year 2011 must be submitted no later than March 15, 2012).
Alternatively, an operator may elect to submit its reports throughout the year.
In addition, an operator must also report this information to the State
pipeline safety authority if a State has obtained regulatory authority over the
operator's pipeline.
§
191.13
Distribution Systems Reporting Transmission
Pipelines: Transmission or Gathering Systems Reporting Distribution
Pipelines.
Each operator, primarily engaged in gas distribution, who also
operates gas transmission or gathering pipelines shall submit separate reports
for these pipelines as required by §§ 191.15 and 191.17. Each
operator, primarily engaged in gas transmission or gathering, who also operates
gas distribution pipelines shall submit separate reports for these pipelines as
required by §§ 191.9 and 191.11.
§ 191.15
Transmission Systems;
Gathering Systems; and Liquefied Natural Gas Facilities: Incident
Report.
(a)
Transmission or
Gathering. Each operator of a transmission system or a gathering
system subject to the jurisdiction of the Commission, shall submit Department
of Transportation Form PHMSA F7100.2 as soon as practicable but not more than
20 days after detection of an incident required to be reported under §
191.5(a) or (d).
(b)
LNG. Each operator of a liquefied natural gas plant or
facility must submit DOT Form PHMSA F 7100.3 as soon as practicable but not
more than 20 days after detection of an incident required to be reported under
§ 191.5 of this part.
(c)
Supplemental Report. When additional relevant information is
obtained after the report is submitted under paragraph (a) of this section, the
operator shall make supplementary reports as deemed necessary with a clear
reference by date and subject to the original report.
§ 191.17
Transmission Systems;
Gathering Systems; and Liquefied Natural Gas Facilities: Annual Report.
(a)
Transmission or
Gathering. Each operator of a transmission system or a gathering
system subject to the jurisdiction of the Commission shall submit an annual
report on Department of Transportation Form PHMSA F7100.2-1. This report must
be submitted for the preceding calendar year, not later than February 15 of
each year.
(b)
LNG. Each operator of a liquefied natural gas facility must
submit an annual report for that system on DOT Form PHSMA 7100.3-1. This report
must be submitted each year, not later than February 15, for the preceding
calendar year.
§
191.23
Reporting Safety-Related Conditions.
(a) Except as provided in paragraph (b) of
this section, each operator shall report in accordance with § 191.25 the
existence of any of the following safety-related conditions involving
facilities in service:
(1) In the case of a
pipeline (other than an LNG facility) that operates at a hoop stress of 20
percent or more of its specified minimum yield strength, general corrosion that
has reduced the wall thickness to less than that required for the maximum
allowable operating pressure, and localized corrosion pitting to a degree where
leakage might result.
(2)
Unintended movement or abnormal loading by environmental causes, such as an
earthquake, landslide, or flood, that impairs the serviceability of a pipeline
or the structural integrity or reliability of an LNG facility that contains,
controls or processes gas or LNG.
(3) Any crack or other material defect that
impairs the structural integrity or reliability of an LNG facility that
contains controls or processes gas or LNG.
(4) Any material defect or physical damage
that impairs the serviceability of a pipeline that operates at a hoop stress of
20 percent or more of its specified minimum yield strength.
(5) Any malfunction or operating error that
causes the pressure of a pipeline or LNG facility that contains or processes
gas or LNG to rise above its maximum allowable operating pressure (or working
pressure for LNG facilities) plus the build-up allowed for operation of
pressure limiting or control devices.
(6) A leak in a pipeline or LNG facility that
contains or processes gas or LNG that constitutes an emergency.
(7) Inner tank leakage, ineffective
insulation, or frost heave that impairs the structural integrity of an LNG
storage tank.
(8) Any
safety-related condition that could lead to an imminent hazard and causes
(either directly or indirectly by remedial action of the operator), for
purposes other than abandonment, a 20 percent or more reduction in operating
pressure or shutdown of operation of a pipeline or an LNG facility that
contains or processes gas or LNG.
(b) A report is not required for any
safety-related condition that:
(1) Exists on
a master meter system or a customer-owned service line;
(2) Is an incident or results in an incident
before the deadline for filing the safety-related condition report;
(3) Exists on a pipeline (other than an LNG
facility) that is more than 220 yards (200 meters) from any building intended
for human occupancy or outdoor place of assembly, except that reports are
required for conditions within the right-of-way of an active railroad, paved
road, street, or highway; or
(4) Is
corrected by repair or replacement in accordance with applicable safety
standards before the deadline for filing the safety-related condition report,
except that reports are required for conditions under paragraph (a)(1) of this
section other than localized corrosion pitting on an effectively coated and
cathodically protected pipeline.
§ 191.25
Filing Safety-Related
Condition Reports.(a) Each report of a
safety-related condition under § 191.23(a) must be filed (received by the
Associate Administrator, OPS) in writing within 5 working days (not including
Saturday, Sunday, or Federal holidays) after the day a representative of the
operator first determines that the condition exists, but not later than 10
working days after the day a representative of the operator discovers the
condition. Separate conditions may be described in a single report if they are
closely related. Reports may be transmitted by facsimile at (202)
366-7128.
(b) The report must be
headed "Safety-Related Condition Report" and provide the following information:
(1) Name and principal address of
operator.
(2) Date of
report.
(3) Name, job title, and
business telephone number of person submitting the report.
(4) Name, job title, and business telephone
number of person who determined that the condition exists.
(5) Date condition was discovered and date
condition was first determined to exist.
(6) Location of condition, with reference to
the State (and town, city, or county) or offshore site, and as appropriate,
nearest street address, offshore platform, survey station number, milepost,
landmark, or name of pipeline.
(7)
Description of the condition, including circumstances leading to its discovery,
any significant effects of the condition on safety, and the name of the
commodity transported or stored.
(8) The corrective action taken (including
reduction of pressure or shutdown) before the report is submitted and the
planned follow-up or future corrective action, including the anticipated
schedule for starting and concluding such action.
PART 192
-TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM SAFETY
STANDARDS
SUBPART A
-GENERAL§ 192.1
What
is the scope of this part?(a) Part 192
prescribes minimum safety requirements for pipeline facilities and the
transportation of gas within the State of Arkansas. Requirements of the
Arkansas Gas Pipeline Code shall take precedence over any other requirements
pertaining to construction, operation and maintenance of gas facilities under
the jurisdiction of the Arkansas Public Service Commission.
(b) This part does not apply to gathering of
gas through a pipeline that operates at less than 0 p.s.i.g. (0kPa), and
through a pipeline that is not a regulated onshore gathering line (as
determined in §192.8); however, it shall apply to the gathering,
transmission or distribution of gas containing 100 or more parts-per-million of
hydrogen sulfide from the custodial transfer meter through any pipeline, rural
or non-rural, to and through any pipeline facility that removes hydrogen
sulfide, except that portion of such a pipeline or pipeline facility that is
located within the fenced boundary of a petroleum refinery.
§ 192.3
Definitions
Abandoned means permanently
removed from service.
Active Corrosion means continuing corrosion that,
unless controlled, could result in a condition that is detrimental to public
safety.
Administrator means the
Administrator of the Pipeline and Hazardous Materials Safety Administration or
any person to whom authority in the matter concerned has been delegated by the
U.S. Secretary of Transportation.
Alarm means an audible or visible
means of indicating to the controller that equipment or processes are outside
operator-defined, safety-related parameters.
Business District means a
location where gas mains are utilized to serve customers that are predominately
commercial in nature and where the street and/or sidewalk paving generally
extends from the centerline of a thoroughfare to the established building line
on either side.
Change to a segment of pipeline
means a physical change in the pipeline or significant changes in operating
pressure.
Commission means Arkansas Public
Service Commission or any person whom the Commission has delegated authority in
the matter concerned.
Control Room means an operations
center staffed by personnel charged with the responsibility for remotely
monitoring and controlling a pipeline facility.
Controller means a qualified
individual who remotely monitors and controls the safety-related operations of
a pipeline facility via a SCADA system from a control room, and who has
operational authority and accountability for the remote operational functions
of the pipeline facility.
Customer Meter means the meter
that measures the transfer of gas from an operator to a consumer.
Distribution Line means a
pipeline other than a gathering or transmission line.
Electrical Survey means a series
of closely spaced pipe-to-soil readings over pipelines which are subsequently
analyzed to identify locations where a corrosive current is leaving the
pipeline.
Gas means natural, manufactured,
liquefied natural, flammable gas or gas which is toxic or corrosive.
Gathering Line means a pipeline
that transports gas from a current production facility to a transmission line
or main.
High Pressure Distribution System
means a distribution system in which the gas pressure in the main is higher
than the pressure provided to the customer.
Key Valves means shut off valves
in a distribution system or transmission line which may be necessary to isolate
segments of a system or line for emergency purposes.
Line Section means a continuous
run of transmission line between adjacent compressor stations, between a
compressor station and storage facilities, between a compressor station and a
block valve, or between adjacent block valves.
Listed Specification means a
specification listed in Section I of Appendix B to Part 192.
Low-Pressure Distribution System
means a distribution system in which the gas pressure in the main is
substantially the same as the pressure provided to the customer.
Main means a distribution line
that serves as a common source of supply for more than one service line.
Master Meter System means a
pipeline system for distribution gas within, but not limited to, a definable
area, such as a mobile home park, housing project, or apartment complex, where
the operator purchases metered gas from an outside source for resale through a
gas distribution pipeline system. The gas distribution pipeline system supplies
the ultimate consumer who either purchases the gas directly through a meter or
by other means, such as rents.
Maximum Actual Operating Pressure
means the maximum pressure that occurs during normal operations over a period
of one year.
Maximum Allowable Operating Pressure
(MAOP) means the maximum pressure at which a pipeline or
segment of a pipeline may be operated under this code.
Mobile Home Park means two or
more mobile homes located on a contiguous tract of land.
Municipality means a city, county
or any other political subdivision of the State of Arkansas.
Operator means a person
who:
(1) Engages in the transportation
of gas; or
(2) Operates a
distribution system within a mobile home park, public housing authority, or
multiple building complex. The system is not owned, nor the responsibility of a
public or municipal utility, and is used to transport gas from a master meter
or a public/municipal utility main to consumers who may or may not be metered.
Gas is not consumed solely by the owner/operator.
Person means an individual, firm,
joint venture, partnership, corporation, association, State, municipality,
cooperative association, or joint stock association, and includes any trustee,
receiver, assignee, or personal representative thereof.
Petroleum Gas means propane,
propylene, butane (normal butane or isobutanes), and butylene (including
isomers), or mixtures composed predominantly of these gases, having a vapor
pressure not exceeding 208 p.s.i.g. (1434 kPa) gage at 100°F
(38°C).
Petroleum Refinery means an
industrial or manufacturing facility or plant primarily engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants or
other products through the processing of petroleum crude oil that is subject
to:
(A) The federal Environmental
Protection Agency Standards of Performance for New Stationary Sources set forth
in Subpart GGG of 40 CFR part 60 or successor regulations;
(B) The federal
EnvironmentalProtection Agency Chemical Accident Prevention
Provisions set forth in Subparts, A, B, D, E, F, G, and H of 40 CFR Part 68 or
successor regulations; and
(C) The federal Occupational Safety and
Health Administration Regulations governing process safety management of highly
hazardous chemicals set forth in
29 CFR
§
1910.119 or successor regulations;
Pipe means any pipe or tubing
used in the transportation of gas, including pipe-type holders.
Pipeline or Pipeline System means
all parts of those physical facilities through which gas moves in
transportation, including, but not limited to, pipe, valves and other
appurtenances attached to pipe, compressor units, metering stations, regulator
stations, delivery stations, holders, and fabricated assemblies.
Pipeline Environment includes
soil resistivity (high or low), soil moisture (wet or dry), soil contaminants
that may promote corrosive activity, and other known conditions that could
affect the probability of active corrosion.
Pipeline Facilities includes
without limitation, new and existing pipe, pipe rights-of-way, and any
equipment, facility or building used in the transportation of gas or the
treatment of gas during the course of transportation of gas.
Production Facilities includes
without limitation, piping or equipment used in the production, extraction,
recovery, lifting, stabilization, separation or treatment of natural gas or
associated storage or measurement from the wellhead to a meter where the gas is
transferred to a custodian other than the well operator for gathering or
transport, commonly known as a 'custodial transfer meter'.
Production Process means the
extraction of gas from the geological source of supply to the surface of the
earth, thence through the lines and equipment used to treat, compress and
measure the gas between the wellhead and the meter where it is either sold or
delivered to a custodian other than the well operator for
gathering and transport to a place of sale, sometimes called 'custodial
transfer meter'.
Supervisory Control and Data Acquisition (SCADA)
System means a computer-based system or systems used by a
controller in a control room that collects and displays information about a
pipeline facility and may have the ability to send commands back to the
pipeline facility.
Service Line means a distribution
line that transports gas from a common source of supply to an individual
customer, to two adjacent or adjoining residential or small commercial
customers, or to multiple residential or small commercial customers served
through a meter header or manifold. A service line ends at the outlet of the
customer meter or at the connection to a customer's piping, whichever is
further downstream, or at the connection to customer piping if there is no
meter.
Service Regulator means the
device on a service line that controls the pressure of gas delivered from a
higher pressure to the pressure provided to the customer. A service regulator
may serve one customer or multiple customers through a meter header or
manifold.
SMYS means specific minimum yield
strength, and is:
(1) For steel pipe manufactured in accordance
with a listed specification, the yield strength specified as a minimum in that
specification; or
(2) For steel
pipe manufactured in accordance with an unknown or unlisted specification, the
yield strength determined in accordance with § 192.107(b).
System means all pipeline
facilities used by a particular operator in the transportation of gas,
including, but not limited to line pipe, valves and other appurtenances
connected to line pipe, compressor units, fabricated assemblies associated with
compressor units, metering (including customers' meters) and delivery stations,
and fabricated assemblies in metering and delivery stations.
Test Failure means a break or
rupture that occurs during strength proof testing of transmission or gathering
lines that are of such magnitude as to require repair before continuation of
the test.
Transmission Line means a
pipeline, other than a gathering line, that:
(1) Transports gas from a gathering line or
storage facility to a gas distribution center, storage facility or large volume
customer that is not down-stream from a gas distribution center;
(2) Operates at a hoop stress of 20 percent
or more SMYS; or
(3) A pipeline
that transports gas within a storage field.
NOTE: A large volume customer may receive similar
volumes of gas as a distribution center, and includes factories, power plants,
and institutional users of gas.
Transportation of Gas means the
gathering, transmission or distribution of gas by pipeline or the storage of
gas in or affecting interstate, intrastate, or foreign commerce.
§ 192.5
Class Locations.
(a) This section classifies pipeline
locations for the purposes of this part. The following criteria apply to
classifications under this section.
(1) A
"class location unit" is an area that extends 220 yards (200 meters) on either
side of the centerline of any continuous 1-mile (1.6 kilometers) length of
pipeline.
(2) Each separate
dwelling unit in a multiple dwelling unit building is counted as a separate
building intended for human occupancy.
(b) Except as provided in paragraph (c) of
this section, pipeline locations are classified as follows:
(1) A Class 1 location is any class location
unit that has 10 or fewer buildings intended for human occupancy.
(2) A Class 2 location is any class location
unit that has more than 10 but fewer than 46 buildings intended for human
occupancy.
(3) A Class 3 location
is:
(i) Any class location unit that has 46 or
more buildings intended for human occupancy; or
(ii) An area where the pipeline lies within
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 20 or more persons on at least 5 days a
week for 10 weeks in any 12 month period. (The days and weeks need not be
consecutive.)
(4) A
Class 4 location is any class location unit where buildings with four or more
stories above ground are prevalent.
(c) The boundaries of Class locations 2, 3,
and 4 may be adjusted as follows:
(1) A Class
4 location ends 220 yards (200 meters) from the nearest building with four or
more stories above ground.
(2) When
all buildings intended for human occupancy within a Class 2 or 3 location are
in a single cluster, the class location ends 220 yards (200 meters) from the
nearest building in the cluster.
§ 192.7.
What documents are
incorporated by reference partly or wholly in this part?
(a) Any documents or portions thereof
incorporated by reference in this part are included in this part as though set
out in full. When only a portion of a document is referenced, the remainder is
not incorporated in this subpart.
(b) All incorporated materials are available
for inspection in the Office of Pipeline Safety, Pipeline and Hazardous
Materials Safety Administration, 1200 New Jersey Avenue, SE, Washington, DC
20590-0001or at the National Archives and Records Administration (NARA). For
information on the availability of this material at NARA, call 202-741-6030 or
go to:
http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
These materials have been approved for incorporation by
reference by the Director of the Federal Register in accordance with
5
U.S.C. 552(a) and
1 CFR part 51. In
addition, the incorporated materials are available from the respective
organizations listed in paragraph (c)(1) of this section.
(c) The full titles of documents incorporated
by reference, in whole or in part, are provided herein. The numbers in
parentheses indicate applicable editions. For each incorporated document,
citations of all affected sections are provided. Earlier editions of currently
listed documents or editions of documents listed in previous editions of 49 CFR
part 192 may be used for materials and components designed, manufactured, or
installed in accordance with these earlier documents at the time they were
listed. The user must refer to the appropriate previous edition of 49 CFR part
192 for a listing of the earlier listed editions or documents.
(1)
Incorporated by reference (IBR).
List of Organizations and Addresses:
A. Pipeline Research Council International,
Inc. (PRCI), c/o Technical Toolboxes, 3801 Kirby Drive, Suite 520, Houston, TX
77098.
B. American Petroleum
Institute (API), 1220 L Street, NW, Washington, DC 20005.
C. American Society for Testing and Materials
(ASTM), 100 Barr Harbor Drive, West Conshohocken, PA 19428.
D. ASME International (ASME), Three Park
Avenue, New York, NY 10016-5990.
E.
Manufacturers Standardization Society of the Valve and Fittings Industry, Inc.
(MSS), 127 Park Street NE, Vienna, VA 22180.
F. National Fire Protection Association
(NFPA), 1 Batterymarch Park, P.O. Box 9101, Quincy, MA 02269-9101.
G. Plastics Pipe Institute, Inc. (PPI), 1825
Connecticut Avenue, NW, Suite 680, Washington, DC 20009.
H. NACE International (NACE), 1440 South
Creek Drive, Houston, TX 77084.
I.
Gas Technology Institute (GTI), 1700 South Mount Prospect Road, Des Plaines, IL
60018.
(2)
Documents incorporated by reference.
|
|
Source and name of referenced material
|
49 CFR reference
|
|
A.
|
Pipeline Research Council International
(PRCI):
(1) AGA Pipeline Research Committee, Project
PR-3-805, "A Modified Criterion for Evaluating the Remaining Strength of
Corroded Pipe," (December 22, 1989). The RSTRENG Program may be used for
calculating remaining strength.
|
§§ 192.485(c); 192.933(a)(1);
192.933(d)(1)(i).
|
|
B.
|
American Petroleum Institute (API):
(1) ANSI/API Specification 5L/ISO 3183 "Specification
for Line Pipe" (44th edition, 2007), includes errata (January 2009) and
addendum (February 2009).
|
§§ 192.55(e); 192.112; 192.113; Item I,
Appendix B to Part 192.
|
|
|
(2) API Recommended Practice 5L1 "Recommended
Practice for Railroad Transportation of Line Pipe,"
(6th edition, July 2002)
|
§ 192.65(a)(1)
|
|
|
(3) API Recommended Practice 5LW, "Transportation of
Line Pipe on Barges and Marine Vessels" (2nd
edition, December 1996, effective March 1, 1997).
|
§ 192.65(b)
|
|
|
(4) ANSI/API Specification 6D, "Specifications for
Pipeline Valves" (23rd edition (April 2008,
effective October 1, 2008) and errata 3 (includes 1 and 2, February
2009)).
|
§ 192.145(a).
|
|
|
(5) API Recommended Practice 80, "Guidelines for the
Definition of Onshore Gas Gathering Lines," (1st
edition, April 2000).
|
§§ 192.8(a); 192.8(a)(1); 192.8(a)(2);
192.8(a)(3); 192.8(a)(4).
|
|
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(6) API Standard 1104, "Welding of Pipelines and
Related Facilities" (20th edition, October 2005,
errata/addendum, (July 2007) and errata 2 (2008)).
|
§§ 192.225; 192.227(a); 192.229 (c)(1);
192.241(c); Item II, Appendix B.
|
|
|
(7) API Recommended Practice 1162, "Public Awareness
Programs for Pipeline Operators," (1st edition,
December 2003).
|
§§ 192.616(a); 192.616(b);
192.616(c).§
|
|
|
(8) API "Recommended Practice 1165 "Recommended
Practice for Pipeline SCADA Displays," (API RP 1165)(First edition (January
2007)).
|
192.631(c)(1).
|
|
C.
|
American Society for Testing and Materials
(ASTM):
|
|
|
|
(1) ASTM A53/A53M-07 "Standard Specification for
Pipe, Steel, Black and Hot - Dipped, Zinc-Coated, Welded and Seamless"
(September 1, 2007).
|
§§ 192.113; Item I, Appendix B to Part
192.
|
|
|
(2) ASTM A106/A106M-08, "Standard Specification for
Seamless Carbon Steel Pipe for High-Temperature Service" (July 15,
2008).
|
§§ 192.113; Item I, Appendix B to Part
192.
|
|
|
(3) ASTM A333/A333M-05 (2005) "Standard Specification
for Seamless and Welded Steel Pipe for Low-Temperature Service".
|
§§ 192.113; Item I, Appendix B to Part
192.
|
|
|
(4) ASTM A372/A372M-03 (Reapproved 2008) "Standard
Specification for Carbon and Alloy Steel Forgings for Thin-Walled Pressure
Vessels" (March 1, 2008).
|
§192.177(b)(1).
|
|
|
(5) ASTM A381-96 (Reapproved 2005) "Standard
Specification for Metal-Arc Welded Steel Pipe For Use With High-Pressure
Transmission Systems" (October 1, 2005).
|
§§192.113; Item I, Appendix B to Part
192.
|
|
|
(6) ASTM Designation: A 578/A578M-96 (Re-approved
2001) "Standard Specification for Straight-Beam Ultrasonic Examination of Plain
and Clad Steel Plates for Special Applications."
|
§§192.112(c)(2)(iii)
|
|
|
(7) ASTM A671-06 "Standard Specification for
Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures" (May
1, 2006).
|
§§ 192.113; Item I, Appendix B to Part
192.
|
|
|
(8) ASTM A672-08 "Standard Specification for
Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate
Temperatures" (May 1, 2008).
|
§§ 192.113; Item I, Appendix B to Part
192.
|
|
|
(9) ASTM A691-98 (Reapproved 2007) "Standard
Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for
High-Pressure Service at High Temperatures" (November 1, 2007).
|
§§ 192.113; Item I, Appendix B to Part
192.
|
|
|
(10) ASTM D638-03 "Standard Test Method for Tensile
Properties of Plastics."
|
§§ 192.283(a)(3); 192.283(b)(1).
|
|
|
(11) ASTM D2513-87 "Standard Specification for
Thermoplastic Gas Pressure Pipe, Tubing, and Fittings".
|
§ 192.63(a)(1).
|
|
|
(12) ASTM D2513-99 "Standard Specification for
Thermoplastic Gas Pressure Pipe, Tubing, and Fittings".
|
§§192.123(e)(2); 192.191(b); 192.281(b)(2);
192.283(a)(1)(i); Item I, Appendix B to Part 192.
|
|
|
(13) ASTM D2517-00 "Standard Specification for
Reinforced Epoxy Resin Gas Pressure Pipe and Fittings".
|
§§192.191(a); 192.281(d)(1);
192.283(a)(1)(ii); Item I, Appendix B to Part 192.
|
|
|
(14) ASTM F1055-1998 "Standard Specification for
Electrofusion Type Polyethylene Fittings for Outside Diameter Controller
Polyethylene Pipe And Tubing".
|
§ 192.283(a)(1)(iii).
|
|
D.
|
ASME International (ASME):
|
|
|
|
(1) ASME/ANSI B16.1-2005 "Gray Iron Pipe Flanges and
Flanged Fittings: (Classes 25, 125, and 250." (August 31, 2006)..
|
§192.147(c).
|
|
|
(2) ASME/ANSI B16.5-2003 "Pipe Flanges and Flanged
Fittings." (October 2004)
|
§§ 192.147(a); 192.279.
|
|
|
(3) ASME/ANSI B31G-1991 (Reaffirmed; 2004) "Manual
for Determining the Remaining Strength of Corroded Pipelines".
|
§§ 192.485(c); 192.933(a).
|
|
|
(4) ASME/ANSI B31.8-2007 (February 2004) "Gas
Transmission and Distribution Piping Systems" (November 30, 2007).
|
§ 192.619(a)(1)(i).
|
|
|
(5) ASME/ANSIB31.8S-2004 "Supplement to B31.8 on
Managing System Integrity of Gas Pipelines".
|
§§ 192.903(c); 192.907(b); 192.911,
Introductory text; 192.911(i); 192.911(k); 192.911(l); 192.911(m); 192.913(a)
Introductory text; 192.913(b)(1); 192.917(a) Introductory text; 192.917(b);
192.917(c); 192.917(e)(1); 192.917(e)(4); 192.921(a)(1); 192.923(b)(1);
192.923(b)(2); 192.923(b)(3); 192.925(b) Introductory text; 192.925(b)(1);
192.925(b)(2); 192.925(b)(3); 192.925(b)(4); 192.927(b); 192.927(c)(1)(i);
192.929(b)(1); 192.929(b)(2); 192.933(a); 192.933(d)(1); 192.933(d)(1)(i);
192.935(a); 192.935(b)(1)(iv); 192.937(c)(1); 192.939(a)(1)(i);
192.939(a)(1)(ii); 192.939(a)(3); 192.945(a);.
|
|
|
(6) 2007 ASME Boiler and Pressure Vessel Code,
Section I, "Rules for Construction of Power Boilers 2007," (2007 edition, July
1, 2007).
|
§192.153(b)
|
|
|
(7) 2007 ASME Boiler and Pressure Vessel Code,
Section VIII, Division 1, "Rules for Construction of Pressure Vessels 2" (2007
edition, July 1, 2007).
|
§§ 192.153(a) 192.153(b); 192.153(d);
192.165(b)(3).
|
|
|
(8) 2007 ASME Boiler and Pressure Vessel Code,
Section VIII, Division 2, "Alternative Rules, Rules for Construction of
Pressure Vessels" (2007 edition, July 1, 2007).
|
§§ 192.153(b); 192.165(b)(3).
|
|
|
(9) 2007 ASME Boiler and Pressure Vessel Code,
Section IX, "Welding and Brazing Procedures, Welders, Brazers, and Welding and
Brazing Operators" (2007 edition, July 1, 2007).
|
§§ 192.227(a); Item II, Appendix B to Part
192.
|
|
E.
|
Manufacturers Standardization Society of the Valve
and Fitting Industry, Inc. (MSS):
|
|
|
|
(1) MSS SP-44-2006, Standard Practice, "Steel
Pipeline Flanges" (2006 edition)
|
§ 192.147(a).
|
|
|
(2) [Reserved]...............
|
|
|
F.
|
National Fire Protection Association (NFPA):
|
|
|
|
(1) NFPA 30 (2008 edition, August 15, 2007),)
"Flammable and Combustible Liquids Code." (2008 edition; approved August 15,
2007)
|
§ 192.735(b)
|
|
|
(2) NFPA 58 (2004) "Liquefied Petroleum Gas Code
(LP-Gas Code)."
|
§§ 192.11(a); 192.11(b); 192.11(c).
|
|
|
(3) NFPA 59 (2004) "Utility LP-Gas Plant
Code."...
|
§§ 192.11(a); 192.11(b); 192.11(c).
|
|
|
(4) NFPA 70 (2008) "National Electrical Code" (NEC
2008) (Approved August 15, 2007)..
|
§§ 192.163(e); 192.189(c).
|
|
G.
|
Plastics Pipe Institute, Inc. (PPI):
|
|
|
|
(1) PPI TR-3/2008 HDB/HDS/PDB/SDB/MRS Policies (2008)
"Policies and Procedures for Developing Hydrostatic Design Basis (HDB),
Pressure Design Basis (PDB), Strength Design Basis (SDB), and Minimum Required
Strength (MRS) Ratings for Thermoplastic Piping Materials or Pipe" (May
2008).
|
§ 192.121.
|
|
H.
|
NACE International (NACE):
|
|
|
|
(1) NACE Standard RP0502-2008, Standard Practice,
"Pipeline External Corrosion Direct Assessment Methodology" (reaffirmed March
2008).
|
§§ 192.923(b)(1); 192.925(b) Introductory
text; 192.925(b)(1); 192.925(b)(1)(ii); 192.925(b)(2) Introductory text;
192.925(b)(3) Introductory text; 192.925(b)(3)(ii); 192.925(b)(3)(iv);
192.925(b)(4) Introductory text; 192.925(b)(4)(ii); 192.931(d);
192.935(b)(1)(iv); 192.939(a)(2).
|
|
I.
|
Gas Technology Institute (GTI):
|
|
|
|
(1) GRI 02/0057 (2002) "Internal Corrosion Direct
Assessment of Gas Transmission Pipelines Methodology".
|
§ 192.927(c)(2).
|
§ 192.8
How are onshore gathering
lines and regulated onshore gathering lines determined?
(a) An operator must use API RP 80
(incorporated by reference,
see
§ 192.7), to determine if
an onshore pipeline (or part of a connected series of pipelines) is an onshore
gathering line. The determination is subject to the limitations listed below.
After making this determination, an operator must determine if the onshore
gathering line is a regulated onshore gathering line under paragraph (b) of
this section.
(1) The beginning of gathering,
under section 2.2(a)(1) of API RP 80, may not extend beyond the furthermost
downstream point in a production operation as defined in section 2.3 of API RP
80. This furthermost downstream point does not include equipment that can be
used in either production or transportation, such as separators or dehydrators,
unless that equipment is involved in the processes of "production and
preparation for transportation or delivery of hydrocarbon gas" within the
meaning of "production operation."
(2) The endpoint of gathering, under section
2.2(a)(1)(A) of API RP 80, may not extend beyond the first downstream natural
gas processing plant, unless the operator can demonstrate, using sound
engineering principles, that gathering extends to a further downstream
plant.
(3) If the endpoint of
gathering, under section 2.2(a)(1)(C) of API RP 80, is determined by the
commingling of gas from separate production fields, the fields may not be more
than 50 miles from each other, unless the Administrator finds a longer
separation distance is justified in a particular case (see
49 CFR §
190.9).
(4) The endpoint of gathering, under section
2.2(a)(1)(D) of API RP 80, may not extend beyond the furthermost downstream
compressor used to increase gathering line pressure for delivery to another
pipeline.
(b) For
purposes of § 192.9, "regulated onshore gathering line" means:
(1) Each onshore gathering line (or segment
of onshore gathering line) with a feature described in the second column that
lies in an area described in the third column; and
(2) As applicable, additional lengths of line
described in the fourth column to provide a safety buffer:
|
Type
|
Feature
|
Area
|
Safety buffer
|
|
A..
|
-Metallic and the MAOP produces a hoop stress of 20
percent or more of SMYS. If the stress level is unknown, an operator must
determine the stress level according to the applicable provisions in subpart C
of this part.
-Non-metallic and the MAOP is more than 125 p.s.i.g.
(862kPa).
|
Class 2, 3, or 4 location (see § 192.5)..
|
None
|
|
B..
|
-Metallic and the MAOP produces a hoop stress of less
than 20 percent of SMYS. If the stress level is unknown, an operator must
determine the stress level according to the applicable provisions in subpart C
of this part.
-Non-metallic and the MAOP is 125 p.s.i.g. (862 kPa) or
less.
|
Area 1.Class 3 or 4 location
Area 2. An area within a Class 2
location the operator determines by using any of the following three
methods:
(a) A class 2 location ..
(b) An area extending 150 feet (45.7m) on each side of
the centerline of any continuous 1 mile (1.6km) of pipeline and including more
than 10 but fewer than 46 dwellings.
(c) An area extending 150 feet (45.7m) on each side of
the centerline of any continuous 1000 feet (305 m) of pipeline and including 5
or more dwellings.
|
If the gathering line is in Area 2(b) or 2(c), the
additional lengths of line extend upstream and downstream from the area to a
point where the line is at least 150 feet (45.7m) from the nearest dwelling in
the area. However, if a cluster of dwellings in Area 2(b) or 2(c) qualifies a
line as Type B, the type B classification ends 150 feet (45.7m) from the
nearest dwelling in the cluster.
|
§ 192.9
What requirements apply
to gathering lines?(a)
Requirements. An operator of a gathering line must follow the
safety requirements of this part as prescribed by this section.
(b)
Offshore lines. An
operator of an offshore gathering line must comply with requirements of this
part applicable to transmission lines, except the requirements in §
192.150 and in subpart O of this part.
(c)
Type A lines. An
operator of a Type A regulated onshore gathering line must comply with the
requirements of this part applicable to transmission lines, except the
requirements in § 192.150 and in subpart O of this part. However, an
operator of a Type A regulated onshore gathering line in a Class 2 location may
demonstrate compliance with subpart N by describing the processes it uses to
determine the qualification of persons performing operations and maintenance
tasks.
(d)
Type B
lines. An operator of a Type B regulated onshore gathering line must
comply with the following requirements:
(1)
If a line is new, replaced, relocated, or otherwise changed, the design,
installation, construction, initial inspection, and initial testing must be in
accordance with requirements of this part applicable to transmission
lines;
(2) If the pipeline is
metallic, control corrosion according to requirements of subpart I of this part
applicable to transmission lines;
(3) Carry out a damage prevention program
under § 192.614;
(4) Establish
a public education program under § 192.616;
(5) Establish the MAOP of the line under
§ 192.619; and
(6) Install and
maintain line markers according to the requirements for transmission lines in
§ 192.707.
(e)
Compliance deadlines. An operator of a regulated onshore
gathering line must comply with the following deadlines, as applicable.
(1) An operator of a new, replaced,
relocated, or otherwise changed line must be in compliance with the applicable
requirements of this section by the date the line goes into service, unless an
exception in § 192.13 applies.
(2) If a regulated onshore gathering line
existing on April 14, 2006 was not previously subject to this part, an operator
has until the date stated in the second column to comply with the applicable
requirement for the line listed in the first column, unless the Administrator
finds a later deadline is justified in a particular case:
|
Requirement
|
Compliance deadline
|
|
Control corrosion according to Subpart I requirements
for transmission lines.
|
April 15, 2009.
|
|
Carry out a damage prevention program under §
192.614.
|
October 15, 2007.
|
|
Establish MAOP under § 192.619.
|
October 15, 2007
|
|
Install and maintain line markers under §
192.707.
|
April 15, 2008.
|
|
Establish a public education program under §
192.616.
|
April 15, 2008
|
|
Other provisions of this part as required by paragraph
(c) of this section for Type A lines.
|
April 15, 2009.
|
(3)
If, after April 14, 2006, a change in class location or increase in dwelling
density causes an onshore gathering line to be a regulated onshore gathering
line, the operator has 1 year for Type B lines and 2 years for Type A lines
after the line becomes a regulated onshore gathering line to comply with this
section.
§
192.11
Petroleum Gas Systems.
(a) Each plant that supplies petroleum gas by
pipeline to a natural gas distribution system must meet the requirements of
this part and ANSI/NFPA 58 and 59.
(b) Each pipeline system subject to this part
that transports only petroleum gas or petroleum gas/air mixtures must meet the
requirements of this part and ANSI/NFPA 58 and 59.
(c) In the event of a conflict between this
part and ANSI/NFPA 58 and 59, ANSI/NFPA 58 and 59 prevail.
§ 192.13
What general
requirements apply to pipelines regulated under this part?
(a) No person may operate a segment of
pipeline listed in the first column that is readied for service after the date
in the second column, unless:
(1) The pipeline
has been designed, installed, constructed, initially inspected, and initially
tested in accordance with this part; or
(2) The pipeline qualifies for use under this
part according to the requirements in § 192.14.
|
Pipeline
|
Date
|
|
Offshore gathering line
|
July 31, 1977
|
|
Regulated onshore gathering line to which this part did
not apply until April 14, 2006.
|
March 15, 2007.
|
|
All other pipelines ..
|
March 12, 1971.
|
(b) No person may operate a segment of
pipeline listed in the first column that is replaced, relocated, or otherwise
changed after the date in the second column, unless the replacement, relocation
or change has been made according to the requirements in this part.
|
Pipeline
|
Date
|
|
Offshore gathering line
|
July 31, 1977
|
|
Regulated onshore gathering line to which this part did
not apply until April 14, 2006.
|
March 15, 2007.
|
|
All other pipelines ..
|
November 12, 1970.
|
(c)
Each operator shall maintain, modify as appropriate, and follow the plans,
procedures, and programs that it is required to establish under this
part.
§ 192.14
Conversion to Service Subject to this Part.
(a) A steel pipeline previously used in
service not subject to this part qualifies for use under this part if the
operator prepares and follows a written procedure to carry out the following
requirements:
(1) The design, construction,
operation, 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.
(2) The pipeline
right-of-way, all above-ground 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.
(3) All known unsafe defects and conditions
must be corrected in accordance with this part.
(4) The pipeline must be tested in accordance
with Subpart J of this part to substantiate the maximum allowable operating
pressure permitted by Subpart L of this part.
(b) Each operator must keep for the life of
the pipeline a record of investigations, tests, repairs, replacements, and
alterations made under the requirements of paragraph (a) of this
section.
§ 192.15
Rules of Regulatory Construction.
(a) As used in this part:
Includes means "including but not
limited to".
May means "is permitted to" or
"is authorized to".
May not means "is not permitted
to" or "is not authorized to".
Shall is used in the mandatory
and imperative sense.
(b)
In this part:
(1) Words importing the singular
include the plural;
(2) Words
importing the plural include the singular; and
(3) Words importing the masculine gender
include the feminine.
§ 192.16
Customer
Notification.
(a) This section applies
to each operator 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 section, "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 §
192.465 if the customer's buried piping is metallic, survey for leaks according
to § 192.723, and if an unsafe condition is found, shut off the flow of
gas, advise the customer of the need to repair the unsafe condition, or repair
the unsafe condition.
(b) Each
operator shall notify each customer once in writing of the following
information:
(1) The operator does not
maintain the customer's buried piping.
(2) If the customer's buried piping is not
maintained, it may be subject to the potential hazards of corrosion and
leakage.
(3) Buried gas piping
should be-
(i) Periodically inspected for
leaks;
(ii) Periodically inspected
for corrosion if the buried piping is metallic; and
(iii) Repaired if any unsafe condition is
discovered.
(4) When
excavating near buried gas piping, the piping should be located in advance, and
the excavation done by hand.
(5)
The operator (if applicable), plumbing contractors, and heating contractors can
assist in locating, inspecting, and repairing the customer's buried
piping.
(c) Each
operator shall notify each customer not later than August 14, 1996, or 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.
(d) Each operator must make the following
records available for inspection by the Administrator or a State agency
participating under
49 U.S.C.
60105 or
60106:
(1) A copy of the notice currently in use;
and
(2) Evidence that notices have
been sent to customers within the previous 3 years.
§ 192.17
Filing of
Operation, Inspection and Maintenance Plan.
Each operator shall file with Pipeline Safety, Public Service
Commission, a plan for operation, inspection and maintenance of each pipeline
facility which he owns or operates. In addition, each change to this plan must
be filed with Pipeline Safety within 20 days after the change is made. Once
filed, this plan becomes a part of these standards as though incorporated and
must be followed by the operator.
SUBPART B
-MATERIALS
§ 192.51
Scope.
This subpart prescribes minimum requirements for the selection
and qualification of pipe and components for use in pipelines.
§ 192.53
General.
Materials for pipe and components must be:
(a) Able to maintain the structural integrity
of the pipeline under temperature and other environmental conditions that may
be anticipated;
(b) Chemically
compatible with any gas that they transport and with any other material in the
pipeline with which they are in contact; and
(c) Qualified in accordance with the
applicable requirements of this subpart.
§ 192.55
Steel Pipe.
(a) New steel pipe is qualified for use under
this part if:
(1) It was manufactured in
accordance with a listed specification;
(2) It meets the requirements of:
(i) Section II of Appendix B to this part;
or
(ii) If it was manufactured
before November 12, 1970, either Section II or III of Appendix B to this part;
or
(3) It is used in
accordance with paragraph (c) or (d) of this section.
(b) Used steel pipe is qualified for use
under this part if:
(1) It was manufactured in
accordance with a listed specification and it meets the requirements of
paragraph II-C of Appendix B to this part;
(2) It meets the requirements of:
(i) Section II of Appendix B to this part;
or
(ii) It was manufactured before
November 12, 1970, either Section II or III of Appendix B to this part;
or
(3) It has been used
in an existing line of the same or higher pressure and meets the requirements
of paragraph II-C of Appendix B to this part; or
(4) It is used in accordance with paragraph
(c) of this section.
(c)
New or used steel pipe may be used at a pressure resulting in a hoop stress of
less than 6,000 p.s.i. (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 part.
(d)
Steel pipe that has not been previously 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.
(e) New steel
pipe that has been cold expanded must comply with the mandatory provisions of
API Specification 5L.
§
192.57
(Removed and Reserved). § 192.59 Plastic
Pipe.
§ 192.59
Plastic Pipe.
(a) New plastic pipe is
qualified for use under this part if:
(1) It
is manufactured in accordance with a listed specification; and
(2) It is resistant to chemicals with which
contact may be anticipated.
(b) Used plastic pipe is qualified for use
under this part if:
(1) It was manufactured in
accordance with a listed specification;
(2) It is resistant to chemicals with which
contact may be anticipated;
(3) It
has been used only in natural gas service;
(4) Its dimensions are still within the
tolerances of the specification to which it was manufactured; and
(5) It is free of visible defects.
(c) For the purpose of paragraphs
(a)(1) and (b)(1) of this section, when a 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:
(1) Meets the strength and design criteria
required of pipe included in the listed specification; and
(2) Is manufactured from plastic compounds
which meet the criteria for material required of pipe included in that listed
specification.
§
192.61
(Removed and Reserved).
§ 192.63
Marking of
Materials.
(a) Except as provided in
paragraph (d) of this section, each valve, fitting, length of pipe, and other
component must be marked:
(1) As prescribed in
the specification or standard to which it was manufactured, except that
thermoplastic fittings must be marked in accordance with ASTM D2513-87
(incorporated by reference, see § 192.7); and
(2) To indicate size, material, manufacturer,
pressure rating, and temperature rating, and as appropriate, type, grade, and
model.
(b) Surfaces of
pipe and components that are subject to stress from internal pressure may not
be field die stamped.
(c) If any
item is marked by die stamping, the die must have blunt or rounded edges that
will minimize stress concentrations.
(d) Paragraph (a) of this section does not
apply to items manufactured before November 12, 1970, that meet all of the
following:
(1) The item is identifiable as to
type, manufacturer, and model.
(2)
Specifications or standards giving pressure, temperature, and other appropriate
criteria for the use of items are readily available.
(e) Operators shall reidentify pipe if
specification markings are obliterated during the coating and/or wrapping
process. This reidentification is not necessary if pipe is immediately
installed in a system.
§
192.65
Transportation of Pipe.
(a)
Railroad. In a pipeline
to be operated at a hoop stress of 20 percent or more of SMYS, an operator may
not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or
more, that is transported by railroad unless:
(1) The transportation is performed in
accordance with API Recommended Practice 5L1 (incorporated by reference,
see
§ 192.7).
(2) In the case of pipe transported before
November 12, 1970, the pipe is tested in accordance with Subpart J of this Part
to at least 1.25 times the maximum allowable operating pressure if it is to be
installed in a class 1 location and to at least 1.5 times the maximum allowable
operating pressure if it is to be installed in a class 2, 3, or 4 location.
Notwithstanding any shorter time period permitted under Subpart J of this Part,
the test pressure must be maintained for at least 8 hours.
(b)
Ship or barge. In a
pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an
operator may not use pipe having an outer diameter to wall thickness ratio of
70 to 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
Recommended Practice 5LW (incorporated by reference, see
§ 192.7).
SUBPART
C
-PIPE DESIGN§
192.101
Scope.
This subpart prescribes the minimum requirements for the design
of pipe.
§ 192.103
General.
Pipe must be designed with sufficient wall thickness, or must
be installed with adequate protection, to withstand anticipated external
pressures and loads that will be imposed on the pipe after installation.
§ 192.105
Design
Formula for Steel Pipe.(a) The design
pressure for steel pipe is determined in accordance with the following formula:
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P= Design pressure in pounds per square inch (kPa)
gage.
S= Yield strength in pounds per square inch (kPa)
determined in accordance with § 192.107.
D= Nominal outside diameter of the pipe in inches
(millimeters).
t= Nominal wall thickness of the pipe in inches
(millimeters). If this is unknown, it is determined in accordance with §
192.109. Additional wall thickness required for concurrent external loads in
accordance with § 192.103 may not be included in computing design
pressure.
F= Design factor determined in accordance with
§ 192.111.
E= Longitudinal joint factor determined in
accordance with § 192.113.
T= Temperature derating factor determined in
accordance with § 192.115.
(b) If steel pipe that has been subjected to
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 75
percent of the pressure determined under paragraph (a) of this section 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 1 hour.
§ 192.107
Yield Strength (S) for
Steel Pipe.
(a) For pipe that is
manufactured in accordance with a specification listed in Section I of Appendix
B of this part, the yield strength to be used in the design formula in §
192.105 is the SMYS stated in the listed specification, if that value is
known.
(b) For pipe that is
manufactured in accordance with a specification not listed in Section I of
Appendix B to this part or whose specification or tensile properties are
unknown, the yield strength to be used in the design formula in § 192.105
is one of the following:
(1) If the pipe is
tensile tested in accordance with Section II-D of Appendix B to this part, the
lower of the following:
(i) 80 percent of the
average yield strength determined by the tensile tests.
(ii) The lowest yield strength determined by
the tensile tests, but not more than 52,000 p.s.i.
(2) If the pipe is not tensile tested as
provided in Subparagraph (b)(1) of this paragraph, 24,000 p.s.i. (165
MPa).
§
192.109
Nominal Wall Thickness (t) for Steel Pipe.
(a) If the nominal wall thickness for steel
pipe is not known, it is determined by measuring the thickness of each piece of
pipe at quarter points on one end.
(b) However, if the pipe is of uniform grade,
size, and thickness and there are more than 10 lengths, only 10 percent of the
individual lengths, but not less than 10 lengths, need 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 § 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 1.14 times the smallest measurement taken on pipe less than 20 inches
(508 millimeters) in outside diameter, nor more than 1.11 times the smallest
measurement taken on pipe 20 inches (508 millimeters) or more in outside
diameter.
§ 192.111
Design Factor (F) for Steel Pipe.
(a) Except as otherwise provided in
paragraphs (b), (c), and (d) of this section, the design factor to be used in
the design formula in § 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
|
(b) A
design factor of 0.60 or less must be used in the design formula in §
192.105 for steel pipe in Class 1 locations that:
(1) Crosses the right-of-way of an unimproved
public road, without a casing;
(2)
Crosses without a casing, or makes a parallel encroachment on, the right-of-way
of either a hard surfaced road, a highway, a public street, or a
railroad;
(3) Is supported by a
vehicular, pedestrian, railroad, or pipeline bridge; or
(4) Is used in a fabricated assembly,
(including separators, mainline valve assemblies, cross-connections, and river
crossing headers) or is used within five 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.
(c) For Class
2 locations, a design factor of 0.50, or less, must be used in the design
formula in § 192.105 for uncased steel pipe that crosses the right-of-way
of a hard surfaced road, a highway, a public street, or a railroad.
(d) For Class 1 or Class 2 locations, a
design factor of 0.50, or less, must be used in the design formula in §
192.105 for each compressor station, regulator station, and measuring station.
§ 192.112
Additional Design Requirements for Steel Pipe Using Alternative Maximum
Allowable Operating Pressure
For a new or existing pipeline segment to be eligible for
operation at the alternative maximum allowable operating pressure (MAOP)
calculated under § 192.620, a segment must meet the following additional
design requirements. Records for alternative MAOP must be maintained, for the
useful life of the pipeline, demonstrating compliance with these
requirements:
|
To address this design issue:
|
The pipeline segment must meet these additional
requirements:
|
|
(a) General standards for steel
pipe
(b) Fracture control
(c)Plate/coil quality control
(d) Seam quality control
(e) Mill hydrostatic test
(f) Coating
(g) Fittings and flanges
(h) Compressor stations
|
(1) The plate, skelp, or coil used for the pipe must be
micro-alloyed, fine grain, fully killed, continuously cast steel with calcium
treatment.
(2) The carbon equivalents of the steel used for pipe
must not exceed 0.25 percent by weight, as calculated by the Ito-Bessyo formula
(Pcm formula) or 0.43 percent by weight, as calculated by the International
Institute of Welding (IIW) formula.
(3) The ratio of the specified outside diameter of the
pipe to the specified wall thickness must be less than 100. The wall thickness
or other mitigative measures must prevent denting and ovality anomalies during
construction, strength testing and anticipated operational stresses.
(4) The pipe must be manufactured using API Specific
5L, product specification level 2 (incorporated by reference, see § 192.7)
for maximum operating pressures and minimum and maximum operating temperatures
and other requirements under this section.
(1) The toughness properties for pipe must address the
potential for initiation, propagation and arrest of fractures in accordance
with:
(i) API specification 5L (incorporated by reference,
see 192.7);
(ii) American Society of Mechanical Engineers (ASME)
B31.8 (incorporated by reference, see § 192.7); and
(iii) Any correction factors needed to address pipe
grades, pressures, temperatures, or gas compositions not expressly addressed in
API Specification 5L, product specification level 2 or ASME B31.8 (incorporated
by reference, see § 192.7).
(2) Fracture control must:
(i) Ensure resistance to fracture initiation while
addressing the full range of operating temperatures, pressures, gas
compositions, pipe grade and operating stress levels, including maximum
pressure and minimum temperatures for shut-in conditions that the pipeline is
expected to experience. If these parameters change during operation of the
pipeline such that they are outside the bounds of what was considered in the
design evaluation, the evaluation must be reviewed and updated to assure
continued resistance to fracture initiation over the operating life of the
pipeline;
(ii) Address adjustments to toughness of pipe for each
grade used and the decompression behavior of the gas at operating
parameters;
(iii) Ensure at least 99 percent probability of
fracture arrest within eight pipe lengths with a probability of not less than
90 percent within five pipe lengths; and
(iv) Include fracture toughness testing that is
equivalent to that described in supplementary requirements SR5A, SR5B, and SR6
of API Specification 5L (incorporated by reference, see § 192.7) and
ensures ductile fracture and arrest with the following exceptions:
(A) The results of the Charpy impact test prescribed in
SR5A must indicate at least 80 percent minimum shear area for any single test
on each heat of steel; and
(B) The results of the drop weight test prescribed in
SR6 must indicate 80 percent average shear area with a minimum single test
result of 60 percent shear area for any steel test samples. The test results
must ensure a ductile fracture and arrest.
(3) If it is not physically possible to achieve the
pipeline toughness properties of paragraphs (b)(1) and (2) of this section,
additional design features, such as mechanical or composite crack arrestors
and/or heavier walled pipe of proper design and spacing, must be used to ensure
fracture arrest as described in paragraph (b)(2)(iii) of this section.
(1) There must be an internal quality management
program at all mills involved in producing steel, plate, coil, skelp, and/or
rolling pipe to be operated at alternative MAOP. These programs must be
structured to eliminate or detect defects and inclusions affecting pipe
quality.
(2) A mill inspection program or internal quality
management
program must include (i) and either (ii) or (iii): (i)
An ultrasonic test of the ends and at least 35 percent of the surface of the
plate/coil or pipe to identify imperfections that impair serviceability such as
laminations, cracks, and inclusions. At least 95 percent of the lengths of pipe
manufactured must be tested. For all pipelines designed after December 22,
2008, the test must be done in accordance with ASTM A578/A578M Level B, or API
5L Paragraph 7.8.10 (incorporated by reference, see § 192.7) or equivalent
method, and either
(ii) A macro etch test or other equivalent method to
identify inclusions that may form centerline segregation during the continuous
casting process. Use of sulfur prints is not an equivalent method. The test
must be carried out on the first or second slab of each sequence graded with an
acceptance criteria of one or two on the Mannesmann scale or equivalent; or
(iii) A quality assurance monitoring program
implemented by the operator that includes audits of: (a) all steelmaking and
casting facilities, (b) quality control plans and manufacturing procedure
specifications,(c) equipment maintenance and records of conformance, (d)
applicable casting superheat and speeds, and (e) centerline segregation
monitoring records to ensure mitigation of centerline segregation during the
continuous casting process.
(1) There must be a quality assurance program for pipe
seam welds to assure tensile strength provided in the API Specification 5L
(incorporated by reference, see § 192.7) for appropriate grades.
(2) There must be a hardness test, using Vickers (Hv10)
hardness test method or equivalent test method, to assure a maximum hardness of
280 Vickers of the following:
(i) A cross section of the weld seam of one pipe from
each heat plus one pipe from each welding line per day; and
(ii) For each sample cross section, a minimum of 13
readings (three for each heat affected zone, three in the weld metal, and two
in each section of the pipe base metal).
(3) All of the seams must be ultrasonically tested
after cold expansion and mill hydrostatic testing.
(1) All pipe to be used in a new pipeline segment must
be hydrostatically tested at the mill at a test pressure corresponding to a
hoop stress of 95 percent SMYS for 10 seconds. The test pressure may include a
combination of internal test pressure and the allowance for end loading
stresses imposed by the pipe mill hydrostatic testing equipment as allowed by
API Specification 5L, Appendix K (incorporated by reference, see §
192.7).
(2) Pipe in operation prior to December 22, 2008, must
have been hydrostatically tested at the mill at a test pressure corresponding
to a hoop stress of 90 percent SMYS for 10 seconds.
(1) The pipe must be protected against external
corrosion by a non-shielding coating.
(2) Coating on pipe used for trenchless installation
must be non-shielding and resist abrasions and other damage possible during
installation.
(3) A quality assurance inspection and testing program
for the coating must cover the surface quality of the bare pipe, surface
cleanliness and chlorides, blast cleaning, application temperature control,
adhesion, cathodic disbondment, moisture permeation, bending, coating
thickness, holiday detection, and repair.
(1) There must be certification records of flanges,
factory induction bends and factory weld ells. Certification must address
material properties such as chemistry, minimum yield strength and minimum wall
thickness to meet design conditions.
(2) If the carbon equivalents of flanges, bends and
ells are greater than 0.42 percent by weight, the qualified welding procedures
must include a pre-heat procedure.
(3) Valves, flanges and fittings must be rated based
upon the required specification rating class for the alternative MAOP.
(1) A compressor station must be designed to limit the
temperature of the nearest downstream segment operating at alternative MAOP to
a maximum of 120 degrees Fahrenheit (49 degrees Celsius) or the higher
temperature allowed in paragraph (h)(2) of this section unless a long-term
coating integrity monitoring program is implemented in accordance with
paragraph (h)(3) of this section.
(2) If research, testing and field monitoring tests
demonstrate that the coating type being used will withstand a higher
temperature in long-term operations, the compressor station may be designed to
limit downstream piping to that higher temperature. Test results and acceptance
criteria addressing coating adhesion, cathodic disbondment, and coating
condition must be provided to each PHMSA pipeline safety regional office where
the pipeline is in service at least 60 days prior to operating above 120
degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State
pipeline safety authority when the pipeline is located in a State where PHMSA
has an interstate agent agreement, or an intrastate pipeline is regulated by
that State.
(3) Pipeline segments operating at alternative MAOP may
operate at temperatures above 120 degrees Fahrenheit (49 degrees Celsius) if
the operator implements a long-term coating integrity monitoring program. The
monitoring program must include examinations using direct current voltage
gradient (DCVG) alternating current voltage gradient (ACVG), or an equivalent
method of monitoring coating integrity. An operator must specify the
periodicity at which these examinations occur and criteria for repairing
identified indications. An operator must submit its long-term coating integrity
monitoring program to each PHMSA pipeline safety regional office in which the
pipeline is located for review before the pipeline segments may be operated at
temperatures in excess of 120 degrees Fahrenheit (49 degrees Celsius). An
operator must also notify a State pipeline safety authority when the pipeline
is located in a State where PHMSA has an interstate agent agreement, or an
intrastate pipeline is regulated by that State.
|
§
192.113
Longitudinal Joint Factor (E) for Steel
Pipe.
The longitudinal joint factor to be used in the design formula
in § 192.105 is determined in accordance with the following table:
|
Longitudinal Specification
|
Pipe Class |
Joint Factor (E) |
|
ASTM A53/A53M .....................
|
Seamless
.......................................................................
|
1.00
|
|
Electric resistance welded
.............................................
|
1.00
|
|
Furnace butt welded
......................................................
|
0.60
|
|
ASTM 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."
§ 192.115
Temperature
Derating Factor (T) for Steel Pipe.
The temperature derating factor to be used in the design
formula in § 192.105 is determined as follows:
|
Gas Temperature in Degrees Fahrenheit (Celsius)
|
Temperature Derating Factor (T)
|
|
250°F (121°C) or less
........................................
|
1.000
|
|
300°F
(149°C)...................................................
|
0.967
|
|
350°F
(177°C)...................................................
|
0.933
|
|
400°F
(204°C)...................................................
|
0.900
|
|
450°F
(232°C)...................................................
|
0.867
|
For intermediate gas temperatures, the derating factor is
determined by interpolation.
§
192.117
(Removed and Reserved).
§ 192.119
(Removed and
Reserved).
§ 192.121
Design of Plastic Pipe.
Subject to the limitations of § 192.123, the design
pressure for plastic pipe is determined by either of the following
formulas:
P=2S (DF)
P= (DF)
Where:
P = Design pressure, gauge, psig (kPa).
S = For thermoplastic pipe, the HDB is determined
in accordance with the listed specification at a temperature equal to 73°F
(23°C), 100°F (38°C), 120°F (49°C), or 140°F
(60°C). In the absence of an HDB established at the specified temperature,
the HDB of a higher temperature may be used in determining a design pressure
rating at the specified temperature by arithmetic interpolation using the
procedure in Part D.2 of PPI TR-3/2008, HDB/PDB/SDB/MRS
Policies (incorporated by reference, see § 192.7). For reinforced
thermosetting plastic pipe, 11,000 psig (75,842 kPa). [Note: Arithmetic
interpolation is not allowed for PA-11 pipe.]
t = Specified wall thickness, inches (mm).
D = Specified outside diameter, inches
(mm).
SDR = Standard dimension ratio, the ratio of the
average specified outside diameter to the minimum specified wall thickness,
corresponding to a value from a common numbering system that was derived from
the American National Standards Institute preferred number series 10.
D F = 0.32 or
= 0.40 for PA-11 pipe produced after January 23, 2009 with a
nominal pipe size (IPS or CTS) 4-inch or less, and a SDR or 11 or greater (i.e.
thicker pipe wall).
§ 192.123
Design Limitations for Plastic Pipe.
(a) Except as provided in paragraph (e) and
paragraph (f) of this section, the design pressure may not exceed a gauge
pressure of 100 psig (689 kPa) for plastic pipe used in:
(1) Distribution systems; or
(2) Class 3 and 4 locations.
(b) Plastic pipe may not be used
where operating temperature of the pipe will be:
(1) Below -20°F (-29°C); or below
-40°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
(2) Above the following applicable
temperatures:
(i) For thermoplastic pipe, the
temperature at which the HDB used in the design formula under § 192.121 is
determined.
(ii) For reinforced
thermosetting plastic pipe, 150ºF (66ºC).
(c) The wall thickness for
thermoplastic pipe may not be less than 0.062 in. (1.57 millimeters).
(d) The wall thickness for reinforced
thermosetting plastic pipe may not be less than that listed in the following
table:
|
Nominal size in inches (millimeters)
_________________________
|
Minimum wall thickness inches (millimeters)
____________________________
|
|
2 (51) .............................
|
0.060 (1.52)
|
|
3 (76) .............................
|
0.060 (1.52)
|
|
4 (102) ............................
|
0.070 (1.78)
|
|
6 (152) ............................
|
0.100 (2.54)
|
(e)
The design pressure for thermoplastic pipe produced after July 14, 2004 may
exceed a gauge pressure of 100 psig (689 kPa) provided that:
(1) The design pressure does not exceed 125
psig (862 kPa);
(2) The material is
a PE2406 or a PE3408 as specified within ASTM D2513-99 (incorporated by
reference, see
§ 192.7);
(3) The pipe size is nominal pipe size (IPS)
12 or less; and
(4) The design
pressure is determined in accordance with the design equation defined in
§192.121.
(f) The
design pressure for polyamide-11 (PA-11) pipe produced after January 23, 2009
may exceed a gauge pressure of 100 psig (689 kPa) provided that:
(1) The design pressure does not exceed 200
psig (1379 kPa);
(2) The pipe size
is nominal pipe size (IPS or CTS) 4-inch or less; and
(3) The pipe has a standard dimension ratio
of SDR-11 or greater (i.e.,thicker pipe wall).
§ 192.125
Design of Copper Pipe.(a) Copper pipe
used in mains must have a minimum wall thickness of 0.065 inches (1.65
millimeters) and must be hard drawn.
(b) Copper pipe used in service lines must
have wall thickness not less than that indicated in the following table:
|
Standard Size, inch (millimeter)
|
Nominal O.D., inch (millimeter)
|
Wall Thickness, Nominal
|
inch (millimeter) 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)
|
(c)
Copper pipe used in mains and service line may not be used at pressures in
excess of 100 p.s.i. (689 kPa) gage.
(d) Copper pipe that does not have an
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
ft.3 (6.9/m3) under
standard conditions. Standard conditions refers to 60°F and 14.7 p.s.i.a.
(15.6°C and one atmosphere).
SUBPART D
-DESIGN OF PIPELINE
COMPONENTS
§ 192.141
Scope.
This subpart prescribes minimum requirements for the design and
installation of pipeline components and facilities. In addition, it prescribes
requirements relating to protection against accidental overpressuring.
§ 192.143
General
Requirements.(a) Each component of a
pipeline must be 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.
(b) The design and
installation of pipeline components and facilities must meet applicable
requirements for corrosion control found in subpart I of this part.
§ 192.144
Qualifying
Metallic Components.
Notwithstanding any requirement of this subpart which
incorporates by reference an edition of a document listed in § 192.7 or
Appendix B of this part, a metallic component manufactured in accordance with
any other edition of that document is qualified for use under this part
if-
(a) It can be shown through visual
inspection of the cleaned component that no defect exists which might impair
the strength or tightness of the component; and
(b) The edition of the document under 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
§ 192.7 or Appendix B of this part:
(1)
Pressure testing;
(2) Materials;
and
(3) Pressure and temperature
ratings.
§
192.145
Valves.(a)
Except for cast iron and plastic valves, each valve must meet the minimum
requirements of API 6D (incorporated by reference, see
§
192.7), 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.
(b) Each cast iron
and plastic valve must comply with the following:
(1) The valve must have a maximum service
pressure rating for temperatures that equal or exceed the maximum service
temperature; and
(2) The valve must
be tested as part of the manufacturing, as follows:
(i) With the valve in the fully open
position, the shell must be tested with no leakage to a pressure at least 1.5
times the maximum service rating.
(ii) After the shell test, the seat must be
tested to a pressure not less than 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.
(iii) After the last pressure test is
completed, the valve must be operated through its full travel to demonstrate
freedom from interference.
(c) Each valve must be able to meet the
anticipated operating conditions.
(d) No valve having shell (Body, bonnet,
cover, and/or end flange) components made of ductile iron may be used at
pressures exceeding 80 percent 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 80 percent of the pressure
ratings for comparable steel valves at their listed temperature, if:
(1) The temperature-adjusted service pressure
does not exceed 1,000 p.s.i. (7 MPa); and
(2) Welding is not used on any ductile iron
component in the fabrication of the valve shells or their assembly.
(e) No valve having shell (body,
bonnet, 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.
§ 192.147
Flanges and Flange Accessories.
(a) Each flange or flange accessory (other
than cast iron) must meet the minimum requirements of ASME/ANSI B16.5, MSS
SP-44, or the equivalent.
(b) Each
flange assembly must be able to 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.
(c) Each flange on a
flanged joint in cast iron pipe must conform in dimensions, drilling, face and
gasket design to ASME/ANSI B16.1 and be cast integrally with the pipe, valve,
or fitting.
§
192.149
Standard Fittings.
(a) The minimum metal thickness of threaded
fittings may not be less than specified for the pressures and temperatures in
the applicable standards referenced in this part, or their
equivalent.
(b) Each steel
butt-welding fitting must 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.
§
192.150
Passage of Internal Inspection Devices
(a) Except as provided in paragraphs (b) and
(c) of this section, 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.
(b) This
section does not apply to:
(1)
Manifolds;
(2) Station piping such
as at compressor stations, meter stations, or regulator stations;
(3) Piping associated with storage
facilities, other than a continuous run of transmission line between a
compressor station and storage facilities;
(4) Cross-overs;
(5) Sizes of pipe for which an instrumented
internal inspection device is not commercially available;
(6) Transmission lines, operated in
conjunction with a distribution system which are installed in Class 4
locations; and
(7) Other piping
that, under § 190.9 of this chapter, the Administrator finds in a
particular case would be impracticable to design and construct to accommodate
the passage of instrumented internal inspection devices.
(c) An operator encountering emergencies,
construction time constraints or other unforeseen construction problems need
not construct a new or replacement segment of a transmission line to meet
subparagraph (a) of this paragraph, if the operator determines and documents
why impracticability prohibits compliance with subparagraph (a) of this
paragraph. Within 30 days after discovering the emergency or construction
problem the operator must petition, under § 190.9 of this chapter, for
approval that design and construction to accommodate passage of instrumented
internal inspection devices would be impracticable. If the petition is denied,
within 1 year after the date of the notice of denial, the operator must modify
that segment to allow passage of instrumented internal inspection
devices.
§ 192.151
Tapping.
(a) Each mechanical
fitting used to make a hot tap must be designed for at least the operating
pressure of the pipeline.
(b) Where
a ductile iron pipe is tapped, 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.
(c) Where a threaded tap is made in cast iron
or ductile iron pipe, the diameter of the tapped hole may not be more than 25
percent of the nominal diameter of the pipe unless the pipe is reinforced,
except that:
(1) Existing taps may be used
for replacement service, if they are free of cracks and have good threads;
and
(2) A 1 1/4 inch (32
millimeters) tap may be made in a 4 inch (102 millimeters) cast iron or ductile
iron pipe, without reinforcement. However, in areas where climate, soil, and
service conditions may create unusual external stresses on cast iron pipe,
unreinforced taps may be used only on 6 inch (152 millimeters) or larger
pipe.
§
192.153
Components Fabricated by Welding.
(a) Except for branch connections and
assemblies of standard pipe and fittings 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
Section VIII, Division 1 of the ASME Boiler and Pressure Vessel Code.
(b) Each prefabricated unit that uses plate
and longitudinal seams must be designed, constructed, and tested in accordance
with section I, Division 1, or section VIII, Division 2 of the ASME Boiler and
Pressure Vessel Code, except for the following:
(1) Regularly manufactured butt-welding
fittings.
(2) Pipe that has been
produced and tested under a specification listed in Appendix B.
(3) Partial assemblies such as split rings or
collars.
(4) Prefabricated units
that the manufacturer certifies have been tested to at least twice the maximum
pressure to which they will be subjected under the anticipated operating
conditions.
(c)
Orange-peel bull plugs and orange-peel swages may not be used on pipelines that
are to operate at a hoop stress of 20 percent or more of the SMYS of the
pipe.
(d) Except for flat closures
designed in accordance with Section VIII of the ASME Boiler and Pressure Vessel
Code, flat closures and fish tails may not be used on pipe that either operates
at 100 p.s.i. (689 kPa) gage, or more, or is more than 3 inches (76
millimeters) nominal diameter.
§
192.155
Welded Branch Connections.
Each welded branch connection made to pipe in the form of a
single connection, or in a header or manifold as a series of connections, must
be designed to ensure that the strength of the pipeline system is not reduced,
taking into account the stresses in the remaining pipe wall due to the opening
in the pipe or header, the shear stresses produced by the pressure acting on
the area of the branch opening and any external loadings due to thermal
movement, weight, and vibration.
§
192.157
Extruded Outlets.
Each extruded outlet must be suitable for anticipated service
conditions and must be at least equal to the design strength of the pipe and
other fittings in the pipeline to which it is attached.
§ 192.159
Flexibility.
Each pipeline must be designed with enough flexibility to
prevent thermal expansion or contraction from causing excessive stresses in the
pipe or components, excessive bending or unusual loads at joints, or
undesirable forces or moments at points of connection to equipment, or at
anchorage or guide points.
§
192.161
Supports and Anchors.
(a) Each pipeline and its associated
equipment must have enough anchors or supports to:
(1) Prevent undue strain on connected
equipment;
(2) Resist longitudinal
forces caused by a bend or offset in the pipe; and
(3) Prevent or damp out excessive
vibration.
(b) Each
exposed pipeline must have enough supports or anchors to protect the exposed
pipe joints from the maximum end force caused by internal pressure and any
additional forces caused by temperature expansion or contraction or by the
weight of the pipe and its contents.
(c) Each support or anchor on an exposed
pipeline must be made of durable, noncombustible material and must be designed
and installed as follows:
(1) Free expansion
and contraction of the pipeline between supports or anchors may not be
restricted;
(2) Provision must be
made for the service conditions involved; and
(3) Movement of the pipeline may not cause
disengagement of the support equipment.
(d) Each support on an exposed pipeline
operated at a stress level of 50 percent or more of SMYS must comply with the
following:
(1) A structural support may not be
welded directly to the pipe;
(2)
The support must be provided by a member that completely encircles the pipe;
and
(3) If an encircling member is
welded to a pipe, the weld must be continuous and cover the entire
circumference.
(e) Each
underground pipeline that is 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.
(f) Each underground pipeline that is being
connected to new branches must have a firm foundation for both the header and
the branch to prevent detrimental lateral and vertical movement.
§ 192.163
Compressor
Stations: Design and Construction.(a)
Location of compressor building. 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
fire-fighting equipment.
(b)
Building construction. Each building on a compressor station
site must be made of noncombustible materials if it contains either:
(1) Pipe more than 2 inches (51 millimeters)
in diameter that is carrying gas under pressure; or
(2) Gas handling equipment other than gas
utilization equipment used for domestic purposes.
(c)
Exits. Each operating
floor of a main compressor building must have at least two 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.
(d)
Fenced
areas. Each fence around a compressor station must have at least two
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 200 feet (61 meters) of any compressor plant
building must open outward and, when occupied, must be openable from the inside
without a key.
(e)
Electrical facilities. Electrical equipment and wiring
installed in compressor stations must conform to the National Electrical Code,
ANSI/NFPA 70, so far as that code is applicable.
§ 192.165
Compressor Stations:
Liquid Removal.
(a) Where entrained
vapors in gas may liquefy under the anticipated pressure and temperature
conditions, the compressor must be protected against the introduction of those
liquids in quantities that could cause damage.
(b) Each liquid separator used to remove
entrained liquids at a compressor station must:
(1) Have a manually operable means of
removing these liquids;
(2) Where
slugs of liquid could be carried into the compressors, have either automatic
liquid removal facilities, an automatic compressor shut-down device, or a high
liquid level alarm; and
(3) Be
manufactured in accordance with Section VIII of the ASME Boiler and Pressure
Vessel Code, except that liquid separators constructed of pipe and fittings
without internal welding must be fabricated with a design factor of 0.4 or
less.
§
192.167
Compressor Station: Emergency Shut-Down.
(a) Except for unattended field compressor
stations of 1,000 horsepower (746 kilowatts) or less, each compressor station
must have an emergency shutdown system that meets the following:
(1) It must be able to block gas out of the
station and blow down the station piping.
(2) It must discharge gas from the blowdown
piping at a location where the gas will not create a hazard.
(3) It must provide means for the shutdown of
gas compressing equipment, gas fires, and electrical facilities in the vicinity
of gas headers and in the compressor building except, that:
(i) Electrical circuits that supply 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
(ii) Electrical circuits needed
to protect equipment from damage may remain energized.
(4) It must be operable from at least two
locations, each of which is:
(i) Outside the
gas area of the station;
(ii) Near
the exit gates, if the station is fenced, or near emergency exits, if not
fenced; and
(iii) Not more than
500 feet (153 meters) from the limits of the station.
(b) If a compressor station
supplies gas 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 the unintended outage on the
distribution system.
§
192.169
Compressor Stations: Pressure Limiting
Devices.
(a) Each compressor station
must have 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 10
percent.
(b) Each vent line that
exhausts gas from the pressure relief valves of a compressor station must
extend to a location where the gas may be discharged without hazard.
§ 192.171
Compressor
Stations: Additional Safety Equipment.
(a) Each compressor station must have
adequate fire protection facilities. If fire pumps are a part of these
facilities, their operation may not be affected by the emergency shutdown
system.
(b) Each compressor station
prime mover, 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.
(c) Each compressor unit in a compressor
station must have a shutdown or alarm device that operates in the event of
inadequate cooling or lubrication of the unit.
(d) Each compressor station gas engine that
operates with pressure gas injection must be equipped so that the stoppage of
the engine automatically shuts off the fuel and vents the engine distribution
manifold.
(e) Each muffler for a
gas engine in a compressor station must have vent slots or holes in baffles of
each compartment to prevent gas from being trapped in the muffler.
§ 192.173
Compressor
Stations: Ventilation.
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.
§ 192.175
Pipe-Type and
Bottle-Type Holders.(a) Each pipe-type
and bottle-type holder 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.
(b) Each pipe-type or
bottle-type holder must have minimum clearance from other holders in accordance
with the following formula in which:
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to view image
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, p.s.i.
(KPa) gage.
F = Design factor as set forth in § 192.111
of this part.
§ 192.177
Additional Provisions for Bottle-Type Holders.
(a) Each bottle-type holder must be:
(1) Located on a site entirely surrounded by
fencing that prevents access by unauthorized persons and with minimum clearance
from the fence as follows:
|
Maximum Allowable Operating
Pressure
|
Minimum Clearance Feet
(meters)
|
|
Less than 1,000 p.s.i. (7 MPa) gage
|
25 (7.6)
|
|
1,000 p.s.i. (7 MPa) or more
|
100 (31)
|
(2)
Designed using the design factors set forth in § 192.111; and
(3) Buried with a minimum cover in accordance
with § 192.327.
(b)
Each bottle-type holder manufactured from steel that is not weldable under
field conditions must comply with the following:
(1) A bottle-type holder made from alloy
steel must meet the chemical and tensile requirements for the various grades of
steel in ASTM A372/A372M.
(2) The
actual yield-tensile ratio of the steel may not exceed 0.85.
(3) Welding may not be performed on the
holder after it has been heat treated or stress relieved, except that copper
wires may be attached to the small diameter portion of the bottle end closure
for cathodic protection if a localized thermite welding process is
used.
(4) The holder must be given
a mill hydrostatic test at a pressure that produces a hoop stress at least
equal to 85 percent of the SMYS.
(5) The holder, connection pipe, and
components must be leak tested after installation as required by Subpart J of
this part.
§
192.179
Transmission Line Valves.
(a) Each transmission line must have
sectionalizing block valves spaced as follows, unless in a particular case the
Administrator finds that alternative spacing would provide an equivalent level
of safety:
(1) Each point on the pipeline in a
Class 4 location must be within 2 1/2 miles (4 kilometers) of a
valve.
(2) Each point on the
pipeline in a Class 3 location must be within 4 miles (6.4 kilometers) of a
valve.
(3) Each point on the
pipeline in a Class 2 location must be within 7 1/2 miles (12 kilometers) of a
valve.
(4) Each point on the
pipeline in a Class 1 location must be within 10 miles (16 kilometers) of a
valve.
(b) Each
sectionalizing block valve on a transmission line must comply with the
following:
(1) The valve and the operating
device to open or close the valve must be readily accessible and protected from
tampering and damage.
(2) The valve
must be supported to prevent settling of the valve or movement of the pipe to
which it is attached.
(c) Each section of transmission line 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.
§ 192.181
Distribution
Line Valves.(a) Each high-pressure
distribution system 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.
(b) Each regulator
station controlling the flow or pressure of gas in a distribution system must
have a valve installed on the inlet piping at a distance from the regulator
station sufficient to permit the operation of the valve during an emergency
that might preclude access to the station.
(c) Each valve on a main installed for
operating or emergency purposes must comply with the following:
(1) The valve must be placed in a readily
accessible location so as to facilitate its operation in an
emergency.
(2) The operating stem
or mechanism must be readily accessible.
(3) If the valve is installed in a buried box
or enclosure, the box or enclosure must be installed so as to avoid
transmitting external loads to the main.
§ 192.183
Vaults: Structural
Design Requirements.(a) Each
underground vault or pit for 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.
(b) There must be enough working space so
that all of the equipment required in the vault or pit can be properly
installed, operated, and maintained.
(c) Each pipe entering, or within, a
regulator vault or pit must be steel for sizes 10 inches (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 gasses or liquids through the opening and to avert strains in the
pipe.
§ 192.185
Vaults: Accessibility.
Each vault must be located in an accessible location and, so
far as practical, away from:
(a)
Street intersections or points where traffic is heavy or dense;
(b) Points of minimum elevation, catch
basins, or places where the access cover will be in the course of surface
waters; and
(c) Water, electric,
steam, or other facilities.
§
192.187
Vaults: Sealing, Venting, and Ventilation.
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:
(a) When the internal volume exceeds 200
cubic feet (5.7 cubic meters):
(1) The vault
or pit must be ventilated with two ducts, each having at least the ventilating
effect of a pipe 4 inches (102 millimeters) in diameter;
(2) The ventilation must be enough to
minimize the formation of combustible atmosphere in the vault or pit;
and
(3) The ducts must be high
enough above grade to disperse any gas-air mixtures that might be
discharged.
(b) When the
internal volume is more than 75 cubic feet (2.1 cubic meters) but less than 200
cubic feet (5.7 cubic meters):
(1) If the
vault or pit is sealed, each 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;
(2) If the vault or pit is
vented, there must be a means of preventing external sources of ignition from
reaching the vault atmosphere; or
(3) If the vault or pit is ventilated,
paragraph (a) or (c) of this section applies.
(c) If a vault or pit covered by paragraph
(b) of this section 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 20 to 1, no additional
ventilation is required.
§
192.189
Vaults: Drainage and Waterproofing.
(a) Each vault must be designed so as to
minimize the entrance of water.
(b)
A vault containing gas piping may not be connected by means of a drain
connection to any other underground structure.
(c) Electrical equipment in vaults must
conform to the applicable requirements of Class 1, Group D, of the National
Electrical Code, ANSI/NFPA 70.
§
192.191
Design Pressure of Plastic Fittings.
(a) Thermosetting fittings for plastic pipe
must conform to ASTM D 2517, (incorporated by reference, see
§ 192.7).
(b) Thermoplastic
fittings for plastic pipe must conform to ASTM D 2513-99, (incorporated by
reference, see
§ 192.7).
§ 192.193
Valve Installation in
Plastic Pipe.
Each valve installed in plastic pipe must be designed so as to
protect the plastic material against excessive torsional or shearing loads when
the valve or shutoff is operated, and from any other secondary stresses that
might be exerted through the valve or its enclosure.
§ 192.195
Protection Against
Accidental Overpressuring.(a)
General requirements. Except as provided in § 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 §§ 192.199 and
192.201.
(b)
Additional
requirements for distribution 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:
(1) Have pressure regulation devices 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
(2) Be designed so as to prevent accidental
overpressuring.
§
192.197
Control of Pressure of Gas Delivered from
High-Pressure Distribution Systems.
(a) Each operator shall establish a maximum
actual operating pressure for each distribution system as required by §
192.622.
(b) If the maximum actual
operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or
less, and a service regulator having the following characteristics is used, no
other pressure limiting device is required:
(1) A regulator capable of reducing line
pressure to pressures required to safely operate the customers' gas utilization
equipment.
(2) A regulator with an
internal relief valve vented to the outside atmosphere or an overpressure
control device.
(3) A single port
valve with the orifice size commensurate with the inlet pressure to assure
adequate volume and pressure to the customer and also assures the overpressure
control device prevents the build-up of pressure that would cause the unsafe
operation of the customers' gas utilization equipment.
(4) A valve seat made of resilient material
designed to withstand abrasion of the gas, impurities in gas, cutting of the
valve, and to resist permanent deformation when pressed against the valve
port.
(5) Pipe connections to the
regulator not exceeding 2 inches (51 millimeters) in diameter.
(6) A regulator that, under normal operating
conditions, will regulate the downstream pressure within the necessary limits
of accuracy and prevents the build-up of pressure under no flow conditions that
would cause the unsafe operation of the customers' gas utilization
equipment.
(7) A self contained
regulator with no external static or control lines.
(c) If the maximum actual operating pressure
of the distribution system is 60 p.s.i. (414 kPa) gage, or less, and a
regulator that does not have all the characteristics listed in paragraph (b) of
this section is used, or if the gas contains materials that seriously affects
the operation of the regulator, there must be suitable protective devices
installed to prevent over-pressuring the customers' gas utilization equipment
if the regulator fails.
(d) If the
maximum actual operating pressure of the distribution system exceed 60 p.s.i.
(414 kPa) gage, one of the following methods must be used to regulate and limit
to a safe value, the pressure delivered to the customers' gas utilization
equipment:
(1) A service regulator having the
characteristics listed in paragraph (b) this part, and another regulator
located upstream from the service regulator. The upstream regulator may not be
set to maintain a pressure higher than 60 p.s.i. (414 kPa) gage. If the
upstream regulator does not have an internal relief valve of sufficient
capacity to limit the pressure to the service regulator to 60 p.s.i.(414 kPa)
gage, a device must be installed between the upstream regulator and service
regulator to limit the pressure to the service regulator to 60 p.s.i.(414 kPa)
gage or less in case the upstream regulator fails to function properly. This
device may be either a regulator, relief valve, or an automatic shutoff that
shuts if the pressure on the inlet of the service regulator exceeds 60 p.s.i.
(414 kPa) gage, and remains closed until manually reset.
(2) A service regulator and a monitoring
regulator set to limit, to a safe value, the pressure delivered to the
customer. Both regulators must be constructed to withstand the maximum inlet
pressure.
(3) A service regulator
and an automatic shutoff device that closes upon an unsafe rise in pressure
downstream from the regulator and remains closed until manually
reset.
(e) If the
maximum actual operating pressure does not exceed 125 p.s.i. (862 kPa) gage, a
service regulator having the characteristics listed in paragraph (b) of this
section and a manufacturer's inlet working pressure rating of 125 p.s.i. (862
kPa) gage or higher, may be used. If the internal relief valve capacity will
prevent the downstream pressure from exceeding a safe value, or an overpressure
control device is installed, no additional pressure limiting device is
required.
§ 192.199
Requirements for Design of Pressure Relief and Limiting Devices.
Except for rupture discs, each pressure relief or pressure
limiting device must:
(a) Be
constructed of materials such that the operation of the device will not be
impaired by corrosion;
(b) Have
valves and valve seats that are designed not to stick in a position that will
make the device inoperative;
(c) Be
designed and installed so that it 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;
(d) Have support made of noncombustible
material;
(e) Have discharge
stacks, vents, or outlet ports designed to prevent accumulation of water, ice,
or snow, located where gas can be discharged into the atmosphere without undue
hazard;
(f) Be designed and
installed so that the 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;
(g)
Where installed at a district regulator station to protect a pipeline system
from overpressuring, be designed and installed to prevent any single incident
such as an explosion in a vault or damage by a vehicle from affecting the
operation of both the overpressure protective device and the district
regulator; and
(h) Except for a
valve that will isolate the system under protection from its source of
pressure, be designed to prevent unauthorized operation of any stop valve that
will make the pressure relief valve or pressure limiting device
inoperative.
(i) Each regulator
station must be provided with reasonable protection from physical damage due to
vehicles or other causes by being placed in a suitable location or by
installation of barricades.
§
192.201
Required Capacity of Pressure Relieving and
Limiting Stations.
(a) Each pressure
relief station or pressure limiting station or group of those stations
installed to protect a pipeline must have enough capacity, and must be set to
operate, to insure the following:
(1) In a
low pressure distribution system, the pressure may not cause the unsafe
operation of any connected and properly adjusted gas utilization
equipment.
(2) In pipelines other
than a low pressure distribution system:
(i)
If the maximum allowable operating pressure is 60 p.s.i. (414 kPa) or more, the
pressure may not exceed the maximum allowable operating pressure plus 10
percent, or the pressure that produces a hoop stress of 75 percent of SMYS,
whichever is lower;
(ii) If the
maximum allowable operating pressure is 12 p.s.i. (83 kPa) gage or more, but
less than 60 p.s.i. (414 kPa) gage, the pressure may not exceed the maximum
allowable operating pressure plus 6 p.s.i. (41kPa) gage; or
(iii) If the maximum allowable operating
pressure is less than 12 p.s.i. (83 kPa) gage, the pressure may not exceed the
maximum allowable operating pressure plus 50 percent.
(b) When more than one pressure
regulating 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.
(c) Relief
valves or other pressure limiting 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.
§
192.203
Instrument, Control, and Sampling Pipe and
Components.
(a) Applicability. This
section applies to the design of instrument, control and sampling pipe and
components. It does not apply to permanently closed systems, such as
fluid-filled temperature responsive devices.
(b) Materials and design. All materials
employed for pipe and components must be designed to meet the particular
conditions of service and the following:
(1)
Each takeoff connection and 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.
(2) Except for takeoff lines that can be
isolated from sources of pressure by other valving, a shutoff valve must be
installed in each take-off line as near as practicable to the point of
take-off. Blowdown valves must be installed where necessary.
(3) Brass or copper material may not be used
for metal temperatures greater than 400°F (204°C).
(4) Pipe or components that may contain
liquids must be protected by heating or other means from damage due to
freezing.
(5) Pipe or components in
which liquids may accumulate must have drains or drips.
(6) Pipe or components subject to clogging
from solids or deposits must have suitable connections for cleaning.
(7) The arrangement of pipe, components, and
supports must provide safety under anticipated operating stresses.
(8) Each joint between sections of 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.
(9) Each control
line must be protected from anticipated causes of damage and must be designed
and installed to prevent damage to any one control line from making both the
regulator and the over-pressure protective device inoperative.
SUBPART E
-WELDING OF STEEL IN PIPELINES§
192.221
Scope.
(a)
This subpart prescribes minimum requirements for welding steel materials in
pipelines.
(b) This subpart does
not apply to welding that occurs during the manufacture of steel pipe or steel
pipeline components.
§
192.225
Welding - Procedures.
(a) Welding must be performed by a qualified
welder in accordance with welding procedures qualified under section 5 of API
1104 (incorporated by reference, see
§ 192.7).or section
IX of the ASME Boiler and Pressure Vessel Code "Welding and Brazing
Qualifications": (incorporated by reference, see
§ 192.7)
to produce welds meeting the requirements of this subpart. The quality of the
test welds used to qualify welding procedures shall be determined by
destructive testing in accordance with the applicable welding
standard(s).
(b) Each welding
procedure must be recorded in detail, including the results of the qualifying
tests. This record must be retained and followed whenever the procedure is
used.
§ 192.227
Qualification of Welders.(a)
Except as provided in paragraph (b) of this section, each welder must be
qualified in accordance with section 6 of API 1104 (incorporated by reference,
see
§ 192.7) or section IX of the ASME Boiler and
Pressure Vessel Code (incorporated by reference, see
§
192.7). However, a welder qualified under an earlier edition than listed in
§ 192.7 of this part may weld but may not requalify under that earlier
edition.
(b) A welder may qualify
to perform welding on pipe to be operated at a pressure that produces a hoop
stress of less than 20 percent of SMYS by performing an acceptable test weld,
for the process to be used, under the test set forth in Section I of Appendix C
to this part. Each welder who is to make a welded service line connection to a
main must first perform an acceptable test weld under section II of Appendix C
of this part as a requirement of the qualifying test.
§ 192.229
Limitations on
Welders.(a) No welder whose
qualification is based on nondestructive testing may weld compressor station
pipe and components.
(b) No welder
may weld with a particular welding process unless, within the preceding 6
calendar months, he has engaged in welding with that process.
(c) A welder qualified under §
192.227(a):
(1) May not weld on pipe to be
operated at a pressure that produces a hoop stress of 20 percent or more of
SMYS unless within the preceding 6 calendar months the welder has had one weld
tested and found acceptable under the sections 6 or 9 of API Standard 1104
(incorporated by reference, see
§ 192.7). Alternatively,
welders 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 7 1/2 months. A welder
qualified under an earlier edition of a standard listed in § 192.7 of this
part may weld but may not requalify under that earlier edition; and
(2) May not weld on pipe to be operated at a
pressure that produces a hoop stress of less than 20 percent of SMYS unless the
welder is tested in accordance with paragraph (c)(1) of this section or
requalifies under paragraph (d)(1) or d(2) of this section.
(d) A welder qualified under
§ 192.227(b) may not weld unless:
(1)
Within the preceding 15 calendar months, but at least once each calendar year,
the welder has requalified under § 192.227(b); or
(2) Within the preceding 7 1/2 calendar
months, but at least twice each calendar year, the welder has had -
(i) A production weld cut out, tested, and
found acceptable in accordance with the qualifying test; or
(ii) For welders who work only on service
lines 2 inches (51 millimeters) or smaller in diameter, two sample welds tested
and found acceptable in accordance with the test in section III of Appendix C
of this part.
§ 192.231
Protection from
Weather.
The welding operation must be protected from weather conditions
that would impair the quality of the completed weld.
§ 192.233
Miter Joints.
(a) A miter joint on steel pipe to be
operated at a pressure that produces a hoop stress of 30 percent or more of
SMYS may not deflect the pipe more than 3°.
(b) A miter joint on steel pipe to be
operated at a pressure that produces a hoop stress of less than 30 percent, but
more than 10 percent, of SMYS may not deflect the pipe more than 12 1/2°
and must be a distance equal to one pipe diameter or more away from any other
miter joint, as measured from the crotch of each joint.
(c) A miter joint on steel pipe to be
operated at a pressure that produces a hoop stress of 10 percent or less of
SMYS may not deflect the pipe more than 90°.
§ 192.235
Preparation for
Welding.
Before beginning any welding, the welding surfaces must be
clean and free of any material that may be detrimental to the weld, and the
pipe or component must be aligned to provide the most favorable condition for
depositing the root bead. This alignment must be preserved while the root bead
is being deposited.
§
192.241
Inspection and Test of Welds.
(a) Visual inspection of welding must be
conducted by an individual qualified by appropriate training and experience to
ensure that:
(1) The welding is performed in
accordance with the welding procedure, and
(2) The weld is acceptable under paragraph
(c) of this section.
(b)
The welds on a pipeline to be operated at a pressure that produces a hoop
stress of 20 percent or more of SMYS must be nondestructively tested in
accordance with § 192.243, except that welds that are visually inspected
and approved by a qualified welding inspector need not be nondestructively
tested if:
(1) The pipe has a nominal diameter
of less than 6 inches (152 millimeters); or
(2) The pipeline is to be operated at a
pressure that produces a hoop stress of less than 40 percent of SMYS and the
welds are so limited in number that nondestructive testing is
impractical.
(c) The
acceptability of a weld that is nondestructively tested or visually inspected
is determined according to the standards in Section 9 of API Standard 1104
(incorporated by reference, see
§ 192.7). However, if a
girth weld is unacceptable under those standards for a reason other than a
crack, and if Appendix A to API 1104 applies to the weld, the acceptability of
the weld may be further determined under that appendix.
(d) Each operator must designate in writing a
welding inspector to perform visual inspections of welds under this
paragraph.
§
192.243
Nondestructive Testing.
(a) Nondestructive testing of welds must be
performed by any process, other than trepanning, that will clearly indicate
defects that may affect the integrity of the weld.
(b) Nondestructive testing of welds must be
performed:
(1) In accordance with written
procedures; and
(2) By persons who
have been trained and qualified in accordance with the requirements of API
Standard 1104. These persons must also be qualified on the equipment employed
in the nondestructive testing.
(c) Procedures must be established for the
proper interpretation of each nondestructive test of a weld to ensure the
acceptability of the weld under § 192.241(c).
(d) When nondestructive testing is required
under § 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:
(1) In Class 1
locations, at least 10 percent.
(2)
In Class 2 locations, at least 15 percent.
(3) In Class 3 and 4 locations at crossings
of major or navigable rivers and within railroad or public highway
rights-of-way, including tunnels, bridges, and overhead road crossings, 100
percent unless impracticable, in which case at least 90 percent. Nondestructive
testing must be impracticable for each girth weld not tested.
(4) At pipeline tie-ins, including tie-ins of
replacement sections, 100 percent.
(e) Except for a welder whose work is
isolated from the principal welding activity, a sample of each welder's work
for each day must be nondestructively tested, when nondestructive testing is
required under § 192.241(b).
(f) When nondestructive testing is required
under § 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.
§ 192.245
Repair or Removal of
Defects.
(a) Each weld that is
unacceptable under § 192.241(c) must be removed or repaired. A weld must
be removed if it has a crack that is more than 8 percent of the weld
length.
(b) Each weld that is
repaired must have 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.
(c) Repair of a crack, or of any defect in a
previously repaired area must be in accordance with the written weld repair
procedures that have been qualified under § 192.225. Repair procedures
must provide that the minimum mechanical properties specified for the welding
procedures used to make the original weld are met upon completion of the final
weld repair.
SUBPART
F
-JOINING OF MATERIALS OTHER THAN BY WELDING
§ 192.271
Scope.
(a) This subpart prescribes minimum
requirements for joining materials in pipelines, other than by
welding.
(b) This subpart does not
apply to joining during the manufacture of pipe or pipeline
components.
(c) Where pipe is to be
joined or connections made by threaded couplings all threads will meet the
standards of API Standard 5B. All joints will be made up power-tight using a
suitable thread sealant.
§
192.273
General.
(a) The pipeline must be designed and
installed so that each joint will sustain the longitudinal pullout or thrust
forces caused by contraction or expansion of the piping or by anticipated
external or internal loading.
(b)
Each joint must be made in accordance with written procedures that have been
proven by test or experience to produce strong gas-tight joints.
(c) Each joint must be inspected to insure
compliance with this subpart.
§
192.275
Cast Iron Pipe.
(a) Each caulked bell and spigot joint in
cast iron pipe must be sealed with mechanical leak clamps.
(b) Each mechanical joint in cast iron 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.
(c) Cast
iron pipe may not be joined by threaded joints.
(d) Cast iron pipe may not be joined by
brazing.
§ 192.277
Ductile Iron Pipe.(a) Ductile
iron pipe may not be joined by threaded joints.
(b) Ductile iron pipe may not be joined by
brazing.
§ 192.279
Copper Pipe.
Copper pipe may not be threaded, except that copper pipe used
for joining screw fittings or valves may be threaded if the wall thickness is
equivalent to the comparable size of Schedule 40 or heavier wall pipe listed in
Table C1 of ASME/ANSI B16.5.
§
192.281
Plastic Pipe.
(a)
General. A plastic pipe
joint that is 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.
(b)
Solvent cement joints. Each solvent cement joint on plastic
pipe must comply with the following:
(1) The
mating surfaces of the joint must be clean, dry, and free of material which
might be detrimental to the joint.
(2) The solvent cement must conform to ASTM
D2513-99, (incorporated by reference, see § 192.7).
(3) The joint may not be heated to accelerate
the setting of the cement.
(4)
Plastic pipe manufactured from different materials shall not be joined by
solvent cement joints.
(c)
Heat-fusion joints. Each
heat-fusion joint on plastic pipe must comply with the following:
(1) A butt heat-fusion joint must be joined
by a device that holds the heater element square to the ends of the piping,
compresses the heated ends together, and holds the pipe in proper alignment
while the plastic hardens.
(2) A
socket heat-fusion joint must be joined by a device that heats the mating
surfaces of the joint uniformly and simultaneously to the proper
temperature.
(3) An electrofusion
joint must be joined utilizing the equipment and techniques of the fittings
manufacturer or equipment and techniques shown, by testing joints to the
requirements of § 192.283(a)(1)(iii), to be at least equivalent to those
of the fittings manufacturer.
(4)
Heat may not be applied with a torch or other open flame.
(d)
Adhesive joints. Each
adhesive joint on thermosetting plastic pipe must comply with the following:
(1) The plastic fittings and adhesives must
conform to the specifications listed in ASTM Designation D 2517.
(2) The materials and adhesive must be
compatible with each other.
(e)
Mechanical joints. Each
compression type mechanical joint on plastic pipe must comply with the
following:
(1) Mechanical joints must be
gas-tight and installed with materials that will prevent tensile
pullouts.
(2) The gasket material
in the coupling must be compatible with the plastic.
(3) An internal tubular rigid stiffener
designed for plastic pipe with either lock inserts, serrations or grip rings
shall be used in joining polyethylene pipe with compression type
fittings.
(4) An internal tubular
rigid stiffener free of rough or sharp edges with a smooth fit into the pipe
shall be used in joining rigid plastic pipe with compression type
fittings.
(5) The internal tubular
stiffener shall be flush with the end of the pipe and extend past the
compressed area of the pipe.
(6)
Split tubular stiffeners shall not be used.
§ 192.283
Plastic Pipe:
Qualifying Joining Procedures.(a)
Heat Fusion, Solvent Cement, and Adhesive Joints. Before any
written procedure established under § 192.273(b) 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:
(1) The
burst test requirements of-
(i) In the case of
thermoplastic pipe, paragraph 6.6 (sustained pressure test) or paragraph 6.7
(Minimum Hydrostatic Burst Test) or paragraph 8.9 (Sustained Static Pressure
Test) of ASTM D2513-99 (incorporated by reference, see
§
192.7);
(ii) In the case of
thermosetting plastic pipe, paragraph 8.5 (Minimum Hydrostatic Burst Pressure)
or paragraph 8.9 (Sustained Static Pressure Test) of ASTM D2517 (incorporated
by reference, see
§ 192.7); or
(iii) In the case of electrofusion fittings
for polyethylene (PE) 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 Designation
F1055 (incorporated by reference, see
§ 192.7).
(2) For procedures intended for
lateral 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
(3) For procedures intended for non-lateral
pipe connections, follow the tensile test requirements of ASTM D638
(incorporated by reference, see
§ 192.7), except that the
test may be conducted at ambient temperature and humidity if the specimen
elongates no less than 25 percent or failure initiates outside the joint area,
the procedure qualifies for use.
(b)
Mechanical Joints.
Before any written procedure established under § 192.273(b) is used for
makingmechanical plastic pipe joints that are designed to withstand tensile
forces, the procedure must be qualified by subjecting five specimen joints made
according to the procedure to the following tensile test:
(1) Use an apparatus for the test as
specified in ASTM D638 (except for conditioning), (incorporated by reference,
see § 192.7)
(2) The specimen
must be of such length that the distance between the grips of the apparatus and
the end of the stiffener does not affect the joint strength.
(3) The speed of testing is 0.20 in. (5.0mm)
per minute, plus or minus 25 percent.
(4) Pipe specimens less than 4 in. (102mm) in
diameter are qualified if the pipe yields to an elongation of no less than 25
percent or failure initiates outside the joint area.
(5) Pipe specimens 4 in. (102mm) and larger
in diameter shall be pulled until the pipe is subjected to a tensile stress
equal to or greater than the maximum thermal stress that would be produced by a
temperature change of 100°F (38°C) or until the pipe is pulled from the
fitting. If the pipe pulls from the fitting, the lowest value of the five test
results or the manufacturer's rating, whichever is lower, must be used in the
design calculations for stress.
(6)
Each specimen that fails at the grips must be retested using new
pipe.
(7) Results obtained pertain
only to the specific outside diameter, and material of the pipe tested, except
that testing of a heavier wall pipe may be used to qualify pipe of the same
material but with lesser wall thickness.
(c) A copy of each written procedure being
used for joining plastic pipe must be available to the persons making and
inspecting joints.
(d) Pipe or
fittings manufactured before July 1, 1980 may be used in accordance with
procedures that the manufacturer certifies will produce a joint as strong as
the pipe.
§ 192.285
Plastic Pipe: Qualifying Persons To Make Joints.
(a) No person may make a plastic pipe joint
unless that person has been qualified under the applicable joining procedure
by:
(1) Appropriate training or experience in
the use of the procedure; and
(2)
Making a specimen joint from pipe sections joined according to the procedure
that passes the inspection and test set forth in paragraph (b) of this
section.
(b) The
specimen joint must be:
(1) Visually examined
during and after 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
(2) In the case of a heat
fusion, solvent cement, or adhesive joint:
(i)
Tested under any one of the test methods listed under § 192.283(a)
applicable to the type of joint and material being tested;
(ii) Examined by ultrasonic inspection and
found not to contain flaws that would cause failure; or
(iii) Cut into at least three longitudinal
straps, each of which is:
(A) Visually
examined and found not to contain voids or discontinuities on the cut surfaces
of the joint area; and
(B) Deformed
by bending, torque, or impact, and, if failure occurs, it must not initiate in
the joint area.
(c) A person must be requalified under an
applicable procedure, if during any 12 month period that person:
(1) Does not make any joints under that
procedure; or
(2) Has three joints
or 3 percent of the joints made, whichever is greater, under that procedure
that are found unacceptable by testing under § 192.513.
(d) Each operator shall establish
a method to determine that each person making joints in plastic pipelines in
the operator's system is qualified in accordance with this section.
§ 192.287
Plastic
Pipe: Inspection of Joints.
No person may carry out the inspection of joints in plastic
pipes required by §§ 192.273(c) and 192.285(b) unless that person has
been qualified by appropriate training or experience in evaluating the
acceptability of plastic pipe joints made under the applicable joining
procedure.
SUBPART
G
-GENERAL CONSTRUCTION REQUIREMENTS FOR TRANSMISSION LINES
AND MAINS
§ 192.301
Scope.
This subpart prescribes minimum requirements for constructing
transmission lines and mains.
§
192.303
Compliance with Specifications or Standards.
(a) Each transmission line or main must be
constructed in accordance with comprehensive written specifications or
standards that are consistent with this Code. Applications or petitions for
Certificates of Convenience and Necessity for new construction filed with the
Commission shall stipulate that design, construction, testing, operation and
maintenance of facility will comply with the requirements of the Arkansas Gas
Pipeline Code.
(b) Each operator of
a mobile home park, Federal housing development, or multi-building complex
having a master meter, who constructs a distribution system must submit
construction plans to the local gas operator for approval before construction
is started. The plan shall show the following: location, type, size and
specification of pipe; number of services; operating pressure; plans for
corrosion control of the pipe, i.e., coating of pipe and cathodic protection.
This review will assure all material and construction procedures meet the
requirements of this Code. Each owner or operator must certify in writing to
the operator supplying gas that the system shall be constructed, tested and
inspected in accordance with this Code. This certification must be made to the
gas operator before service is connected to the system and will be kept on file
by each party for the life of the system.
§ 192.305
Inspection:
General.
Each transmission line or main must be inspected to ensure that
it is constructed in accordance with this part.
§ 192.307
Inspection of
Materials.
Each length of pipe and each other component must be visually
inspected at the site of installation to ensure that it has not sustained any
visually determinable damage that could impair its serviceability.
§ 192.309
Repair of
Steel Pipe.(a) Each imperfection or
damage that 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:
(1) The minimum thickness required by the
tolerances in the specification to which the pipe was manufactured;
or
(2) The nominal wall thickness
required for the design pressure of the pipeline.
(b) Each of the following dents must be
removed from steel pipe to be operated at a pressure that produces a hoop
stress of 20 percent, 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:
(1) A dent that
contains a stress concentrator such as a scratch, gouge, groove, or arc
burn.
(2) A dent that affects the
longitudinal weld or a circumferential weld.
(3) In pipe to be operated at a pressure that
produces a hoop stress of 40 percent or more of SMYS, a dent that has a depth
of:
(i) More than 1/4 inch (6.4 millimeters)
in pipe 12 3/4 inches (324 millimeters) or less in outer diameter; or
(ii) More than 2 percent of the nominal pipe
diameter in pipe over 12 3/4 inches (324 millimeters) in outer diameter.
For the purpose of this section a "dent" is a depression that
produces a gross disturbance in the curvature of the pipe wall without reducing
the pipe-wall thickness. The depth of a dent is measured as the gap between the
lowest point of the dent and a prolongation of the original contour of the
pipe.
(c) Each arc burn on steel pipe to be
operated at a pressure that produces a hoop stress of 40 percent, 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:
(1) The minimum wall
thickness required by the tolerances in the specification to which the pipe was
manufactured; or
(2) The nominal
wall thickness required for the design pressure of the pipeline.
(d) A gouge, groove, arc burn, or
dent may not be repaired by insert patching or by pounding out.
(e) Each gouge, groove, arc burn, or dent
that is removed from a length of pipe must be removed by cutting out the
damaged portion as a cylinder.
§
192.311
Repair of Plastic Pipe.
Each imperfection or damage that would impair the
serviceability of plastic pipe must be repaired or removed.
§ 192.313
Bends and
Elbows.
(a) Each field bend in steel
pipe, other than a wrinkle bend made in accordance with § 192.315, must
comply with the following:
(1) A bend must not
impair the serviceability of the pipe.
(2) Each bend must have a smooth contour and
be free from buckling, cracks, or any other mechanical damage.
(3) On pipe containing the longitudinal weld,
the longitudinal weld must be as near as practicable to the neutral axis of the
bend unless:
(i) The bend is made with an
internal bending mandrel; or
(ii)
The pipe is 12 inches (305 millimeters) or less in outside diameter or has a
diameter to wall thickness ratio less than 70.
(b) Each circumferential weld of steel pipe
which is located where the stress during bending causes a permanent deformation
in the pipe must be non-destructively tested either before or after the bending
process.
(c) Wrought-steel welding
elbows and transverse segments of these elbows may not be used for changes in
direction on steel pipe that is 2 inches (51 millimeters) or more in diameter
unless the arc length, as measured along the crotch, is at least 1 inch (25
millimeters).
§
192.315
Wrinkle Bends in Steel Pipe.
(a) A wrinkle bend may not be made on steel
pipe to be operated at a pressure that produces a hoop stress of 30 percent, or
more, of SMYS.
(b) Each wrinkle
bend on steel pipe must comply with the following:
(1) The bend must not have any sharp
kinks.
(2) When measured along the
crotch of the bend, the wrinkles must be a distance of at least one pipe
diameter.
(3) On pipe 16 inches
(406 millimeters) or larger in diameter, the bend may not have a deflection of
more than 1 1/2° for each wrinkle.
(4) On pipe containing a longitudinal weld
the longitudinal seam must be as near as practicable to the neutral axis of the
bend.
§
192.317
Protection from Hazards.
(a) The operator must take all practicable
steps to protect each transmission line or main must be protected from
washouts, floods, unstable soil, landslides, or other hazards that may cause
the pipeline to move or to sustain abnormal loads.
(b) Each aboveground transmission line or
main 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.
(c)
Pipelines, including pipe risers in inland navigable waters must be protected
from accidental damage by vessels.
§ 192.319
Installation of Pipe in
a Ditch.
(a) When installed in a
ditch, each transmission line that is to be operated at a pressure producing
hoop stress of 20 percent 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.
(b) Each ditch for a
transmission line or main must be backfilled in a manner that:
(1) Provides firm support under the pipe;
and
(2) Prevents damage to the pipe
and pipe coating from equipment or from the backfill material.
§ 192.321
Installation of Plastic Pipe.(a) The
installation of plastic pipe must be carried out by, or under the direction of
a person qualified by experience or training in the installation of plastic
pipe. Procedures established by the operator or those recommended by the pipe
manufacturer shall be followed during all phases of installation.
(b) Plastic pipe must be installed below
ground level except as provided by paragraph (h) of this section.
(c) Plastic pipe that is installed in a vault
or any other below grade enclosure must be completely encased in gas-tight
metal pipe and fittings that are adequately protected from corrosion.
(d) Plastic pipe shall be installed so as to
minimize shear or tensile stresses resulting from construction, backfill,
thermal contraction or external loading. As a minimum, the operator shall
comply with the following:
(1) Pipe that is
pulled or plowed-in during the installation process shall be given sufficient
time to cool and contract to its original length prior to joining or sufficient
slack placed in the pipe to compensate for contraction.
(2) Plastic pipe shall not be bent to a
radius less than the minimum recommended by the manufacturer.
(3) Butt joints, taps and socket joints are
not permitted in bends with a radius of less than 125 times the pipe
diameter.
(4) Plastic pipe shall be
installed with sufficient slack to allow for thermal expansion and contraction.
This slack is critical for pipe inserted into existing mains and joined to
metal pipe. The thermal expansion and contraction factor for plastic pipe is
approximately 1 inch per 100 feet for every 10 degrees Fahrenheit change in
temperature.
(e)
Thermoplastic pipe that is not encased must have a minimum wall thickness of
0.090 inches (2.29 millimeters) except that pipe with an outside diameter of
0.875 inches (22.3 millimeters) or less may have a minimum wall thickness of
0.062 inches (1.58 millimeters).
(f) Plastic pipe that is not encased must
have an electrically conducting 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.
(g) Plastic pipe that is
being encased must be inserted into the casing pipe in a manner that will
protect the plastic. The leading end of the plastic must be closed before
insertion.
(h) Plastic pipe may be
installed on bridges provided that it is:
(1)
Installed with protection from mechanical damage, such as installation in a
metallic casing;
(2) Protected from
ultraviolet radiation; and
(3) Not
allowed to exceed the pipe temperature limits specified in §
192.123.
§
192.323
Casing.
Each casing used on a transmission line or main under a
railroad or highway must comply with the following:
(a) The casing must be designed to withstand
the superimposed loads.
(b) If
there is a possibility of water entering the casing, the ends must be
sealed.
(c) If the ends of an
unvented casing are 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 72 percent of
SMYS.
(d) If vents are installed on
a casing, the vents must be protected from the weather to prevent water from
entering the casing.
§
192.325
Underground Clearance.
(a) Each transmission line must be installed
with at least 12 inches (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.
(b) Each main must be installed with enough
clearance from any other underground structure to allow proper maintenance and
to protect against damage that might result from proximity to other
structures.
(c) In addition to
meeting the requirements of paragraph (a) or (b) of this section, 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.
(d)
Each pipe-type or bottle-type holder must be installed with a minimum clearance
from any other holder as prescribed in § 192.175(b).
§ 192.327
Cover.
(a) Except as provided in paragraphs (c) and
(e) of this section, each buried transmission line must be installed with a
minimum cover as follows:
|
Location
|
Normal Soil Inches (Millimeters)
|
Consolidated Rock Inches (Millimeters)
|
|
Class 1 locations
|
30 (762)
|
18 (457)
|
|
Class 2,3, and 4 locations
|
36 (914)
|
24 (610)
|
|
Drainage ditches of public roads and railroad
crossings
|
36 (914)
|
24 (610)
|
(b)
Except as provided in paragraphs (c) and (d) of this section, each buried main
must be installed with at least 24 inches (610 millimeters) of cover.
(c) Where an underground structure prevents
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.
(d) A main may be installed with less than 24
inches (610 millimeters) of cover if the law of the State or municipality:
(1) Establishes a minimum cover of less than
24 inches (610 millimeters);
(2)
Requires that mains be installed in a common trench with other utility lines;
and
(3) Provides adequately for
prevention of damage to the pipe by external forces.
(e) Except as provided in paragraph (c) of
this section, all pipe installed in a navigable river, stream, or harbor must
be installed with a minimum cover of 48 inches (1,219 millimeters) in soil or
24 inches (610 millimeters) in consolidated rock between the top of the pipe
and the underwater natural bottom (as determined by recognized and generally
accepted practices).
§
192.328
Additional Construction Requirements for Steel Pipe
Using Alternative Maximum Allowable Operating Pressure.
For a new or existing pipeline segment to be eligible for
operation at the alternative maximum allowable operating pressure calculated
under § 192.620, a segment must meet the following additional construction
requirements. Records must be maintained, for the useful life of the pipeline,
demonstrating compliance with these requirements:
|
To address this construction issue:
|
The pipeline segment must meet this additional
construction requirement:
|
|
(a) Quality assurance
|
(1) The construction of the pipeline segment must be
done under a quality assurance plan addressing pipe inspection, hauling and
stringing, field bending, welding, non-destructive examination of girth welds,
applying and testing field applied coating, lowering of the pipeline into the
ditch, padding and backfilling, and hydrostatic testing.
(2) The quality assurance plan for applying and testing
field applied coating to girth welds must be:
(i) Equivalent to that required under §
192.112(f)(3) for pipe; and
(ii) Performed by an individual with the knowledge,
skills, and ability to assure effective coating application.
|
|
(b) Girth welds
|
(1) All girth welds on a new pipeline segment must be
non-destructively examined in accordance with § 192.243(b) and (c).
|
|
(c) Depth of cover
|
(1) Notwithstanding any lesser depth of cover otherwise
allowed in § 192.327, there must be at least 36 inches (914 millimeters)
of cover or equivalent means to protect the pipeline from outside force
damage.
(2) In areas where deep tilling or other activities
could threaten the pipeline, the top of the pipeline must be installed at least
one foot below the deepest expected penetration of the soil.
|
|
(d) Initial strength testing
|
(1) The pipeline segment must not have experienced
failures indicative of systemic material defects during strength testing,
including initial hydrostatic testing. A root cause analysis, including
metallurgical examination of the failed pipe, must be performed for any failure
experienced to verify that it is not indicative of a systemic concern. The
results of this root cause analysis must be reported to each PHMSA pipeline
safety regional office where the pipe is in service at least 60 days prior to
operating at the alternative MAOP. An operator must also notify a State
pipeline safety authority when the pipeline is located in a State where PHMSA
has an interstate agent agreement, or an intrastate pipeline is regulated by
that State.
|
|
(e) Interference currents
|
(1) For a new pipeline segment, the construction must
address the impacts of induced alternating current from parallel electric
transmission lines and other known sources of potential interference with
corrosion control.
|
SUBPART
H
-CUSTOMER METERS, SERVICE REGULATORS, AND SERVICE
LINES§ 192.351
Scope.
This subpart prescribes minimum requirements for installing
customer meters, service regulators, service lines, service line valves, and
service line connections to mains.
§ 192.353
Customer Meters and
Regulators: Location.
(a) Each meter
and service regulator, whether inside or outside 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.
(b) Each service
regulator installed within a building must be located as near as practical to
the point of service line entrance.
(c) Each meter installed within a building
must be located in a ventilated place and not less than 3 feet (914
millimeters) from any source of ignition or any source of heat which might
damage the meter.
(d) Where
feasible, meters and regulators previously installed inside of buildings will
be relocated to outside of building when the regulator or meter is removed for
any reason.
§
192.355
Customer Meters and Regulators: Protection from
Damage.
(a)
Protection from
vacuum or back pressure. If the customer's equipment might create
either a vacuum or a back pressure, a device must be installed to protect the
system.
(b)
Service
regulator vents and relief vents. Service regulator vents and relief
vents must terminate outdoors, and the outdoor terminal must:
(1) Be rain and insect resistant;
(2) Be located at a place where gas from the
vent can escape freely into the atmosphere and away from any opening into the
building; and
(3) Be protected from
damage caused by submergence in areas where flooding may occur.
(c)
Pits and
vaults. Each pit or vault that houses a customer meter or regulator at
a place where vehicular traffic is anticipated must be able to support that
traffic.
(d)
Protection
from physical damage. Each customer regulator and meter must be
provided with reasonable protection from physical damage due to vehicles or
other causes by being placed in a suitable location or by installation of
barricades.
§
192.357
Customer Meters and Regulators:
Installation.
(a) Each meter and each
regulator must be installed so as to minimize anticipated stresses upon the
connecting piping and the meter.
(b) When close all-thread nipples are used,
the wall thickness remaining after the threads are cut must meet the minimum
wall thickness requirements of this part.
(c) Connections made of lead or other easily
damaged material may not be used in the installation of meters or
regulators.
(d) Each regulator that
might release gas in its operation must be vented to the outside
atmosphere.
§
192.359
Customer Meter Installations: Operating
Pressure.
(a) A meter may not be used
at a pressure that is more than 67 percent of the manufacturer's shell test
pressure.
(b) Each newly installed
meter manufactured after November 12, 1970, must have been tested to a minimum
of 10 p.s.i. (69 kPa) gage.
(c) A
rebuilt or repaired tinned steel case meter may not be used at a pressure that
is more than 50 percent of the pressure used to test the meter after rebuilding
or repairing.
§
192.361
Service Lines: Installation.
(a)
Depth. Each buried
service line must be installed with at least 12 inches (305 millimeters) of
cover in private property and at least 18 inches (457 millimeters) of cover in
streets and roads. However, where an underground structure prevents
installation at those depths, the service line must be able to withstand any
anticipated external load.
(b)
Support and backfill. Each service 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.
(c)
Grading for drainage.
Where condensate 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.
(d)
Protection against piping strain
and external loading. Each service line must be installed so as to
minimize anticipated piping strain and external loading.
(e)
Installation of service lines
into buildings. Each underground service line installed below grade
through the outer foundation wall of a building must:
(1) In the case of a metal service line, be
protected against corrosion;
(2) In
the case of plastic service line, be protected from shearing action and
backfill settlement; and
(3) Be
sealed at the foundation wall to prevent leakage into the building.
(f)
Installation of
service lines under buildings. Where an underground service line is
installed under a building;
(1) It must be
encased in a gas tight conduit;
(2)
The conduit and the service line must, if the service line supplies the
building it underlies, extend into a normally usable and accessible part of the
building; and
(3) The space between
the conduit 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.
(g)
Locating underground service lines. Each underground
nonmetallic service line that is not encased must have a means of locating the
pipe that complies with § 192.321(f).
(h)
Service lines installed by other
than gas company personnel. These person(s) shall certify to the gas
company that the line(s) were installed in accordance with this code.
§ 192.363
Service
Lines: Valve Requirements.
(a) Each
service line must have a service-line valve that meets the applicable
requirements of Subparts B and D of this part. A valve incorporated in a meter
bar, that allows the meter to be bypassed, may not be used as a service-line
valve.
(b) A soft seat service line
valve may not be used if its ability to control the flow of gas could be
adversely affected by exposure to anticipated heat.
(c) Each service-line valve on a
high-pressure service line, installed above ground 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.
§
192.365
Service Lines: Location of Valves.
(a)
Relation to regulator or
meter. Each service-line valve must be installed upstream of the
regulator or, if there is no regulator, upstream of the meter.
(b)
Outside valves. Each
service line must have a shut-off valve in a readily accessible location that,
if feasible, is outside of the building.
(c)
Underground valves. Each
underground 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.
§ 192.367
Service Lines: General
Requirements for Connections to Main Piping.
(a)
Location. Each service
line connection 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.
(b)
Compression-type connection to mains. Each compression-type
service line to main connection must:
(1) Be
designed and installed to effectively sustain the longitudinal pull-out or
thrust forces caused by contraction or expansion of the piping, or by
anticipated external or internal loading; and
(2) If gaskets are used in connecting the
service line to the main connection fitting, have gaskets that are compatible
with the kind of gas in the system.
(3) Plastic service lines connected to mains
with mechanical joints shall be joined in accordance with the procedures in
§ 192.281(e).
(c)
Each sleeve over tie-in shear point. Each plastic service line
connected to a main shall have a plastic sleeve installed over the shear point
at the tie-in and the sleeve shall extend longitudinally along the line a
sufficient length to reduce the concentration of the shear force. If it is not
possible to install a sleeve due to foreign lines, mechanical joints, etc., the
service line will be supported by well compacted soil or by other
means.
§ 192.369
Service Lines: Connection to Cast Iron or Ductile Iron Mains.
(a) Each service line connected to a cast
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 §
192.273.
(b) If a threaded tap is
being inserted, the requirements of §§ 192.151(b) and (c) must also
be met.
§ 192.371
Service Lines: Steel.
Each steel service line to be operated at less than 100 p.s.i.
(689 kPa) gage must be constructed of pipe designed for a minimum of 100 p.s.i.
(689 kPa) gage.
§
192.373
Service Lines: Cast Iron and Ductile Iron.
(a) Cast or ductile iron pipe less than 6
inches (152 millimeters) in diameter may not be installed for service
lines.
(b) If cast iron pipe or
ductile iron pipe is installed for use as a service line, the part of the
service line which extends through the building wall must be of steel
pipe.
(c) A cast iron or ductile
iron service line may not be installed in unstable soil or under a
building.
§ 192.375
Service Lines: Plastic.(a) Each
plastic service line outside a building must be installed below ground level,
except that it may terminate above the ground and outside the building, if:
(1) The above ground part of the plastic
service line is protected against deterioration and external damage;
and
(2) The plastic service line is
not used to support external loads.
(b) Each plastic service line inside a
building must be protected against external damage.
§ 192.377
Service Lines:
Copper.
Each copper service line installed within a building must be
protected against external damage.
§ 192.379
New Service Lines Not
in Use.
Each service line that is not placed in service upon completion
of installation must comply with one of the following until the customer is
supplied with gas:
(a) The valve that
is closed to prevent the flow of gas to the customer must be provided with a
locking device or other means designed to prevent the opening of the valve by
persons other than those authorized by the operator.
(b) A mechanical device or fitting that will
prevent the flow of gas must be installed in the service line or in the meter
assembly.
(c) The customer's piping
must be physically disconnected from the gas supply and the open pipe ends
sealed.
§ 192.381
Service Lines: Excess Flow Valve Performance Standards.
(a) Excess flow valves to be used on single
residence service lines that operate continuously throughout the year at a
pressure not less than 10 p.s.i. (69 kPa) gage must be manufactured and tested
by the manufacturer according to an industry specification, or the
manufacturer's specification, to ensure that each valve will:
(1) Function properly up to the maximum
operating pressure at which the valve is rated;
(2) Function properly at all temperatures
reasonably expected in the operating environment of the service line;
(3) At 10 p.s.i. (69 kPa) gage:
(i) Close at, or not more than 50 percent
above, the rated closure flow rate specified by the manufacturer; and
(ii) Upon closure, reduce gas flow -
(A) For an excess flow valve designed to
allow pressure to equalize across the valve, to no more than 5 percent of the
manufacturer's specified closure flow rate, up to a maximum of 20 cubic feet
per hour (0.57 cubic meters per hour); or
(B) For an excess flow valve designed to
prevent equalization of pressure across the valve, to no more than 0.4 cubic
feet per hour (.01 cubic meters per hour); and
(4) Not to close when the pressure is less
than the manufacturer's minimum specified operating pressure and the flow rate
is below the manufacturer's minimum specified closure flow rate.
(b) An excess flow valve must meet
the applicable requirements of subparts B and D of this part.
(c) An operator must mark or otherwise
identify the presence of an excess flow valve in the service line.
(d) An operator shall locate an excess flow
valve as near as practical to the fitting connecting the service line to its
source of gas supply.
(e) An
operator should not install an 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 the necessary operation and
maintenance activities on the service, such as blowing liquids from the
line.
§ 192.383
Excess Flow Valve Installation.
(a) Definitions. As used in this section:
Replaced service line means a gas service line
where the fitting that connects the service line to the main is replaced or the
piping connected to this fitting is replaced.
Service line serving single-family residence
means a gas service line that begins at the fitting that connects the service
line to the main and serves only one single family residence.
(b)
Installation required.
An excess flow valve (EFV) installation must comply with the performance
standards in § 192.381. The operator must install an EFV on any new or
replaced service line serving a single-family residence after February 12,
2010, unless one or more of the following conditions is present:
(1) The service line does not operate at a
pressure of 10 psig or greater throughout the year;
(2) The operator has prior experience with
contaminants in the gas stream that could interfere with the EFV's operation or
cause loss of service to a residence;
(3) An EFV could interfere with necessary
operation or maintenance activities, such as blowing liquids from the line;
or
(4) An EFV meeting performance
standards in § 192.381 is not commercially available to the
operator.
(c)
Reporting. Each operator must report the EFV measures detailed
in the annual report required by § 191.11.
SUBPART I
-REQUIREMENTS FOR CORROSION
CONTROL§ 192.451
Scope.
This subpart prescribes minimum requirements for the protection
of metallic pipelines from external, internal, and atmospheric
corrosion.
§ 192.452
How does this subpart apply to converted pipelines and regulated onshore
gathering lines?(a)
Converted
pipelines. Notwithstanding the date the pipeline was installed or any
earlier deadlines for compliance, each pipeline which qualifies for use under
this part in accordance with § 192.14 must meet the requirements of this
subpart specifically applicable to pipelines installed before August 1, 1971,
and all other applicable requirements within 1 year after the pipeline is
readied for service. However, the requirements of this subpart specifically
applicable to pipelines installed after July 31, 1971, apply if the pipeline
substantially meets those requirements before it is readied for service or it
is a segment which is replaced, relocated, or substantially altered.
(b)
Regulated onshore gathering
lines. For any regulated onshore gathering line under § 192.9
existing on April 14, 2006, that was not previously subject to this part, and
for any onshore gathering line that becomes a regulated onshore gathering line
under § 192.9 after April 14, 2006, because of a change in class location
or increase in dwelling density:
(1) The
requirements of this subpart specifically applicable to pipelines installed
before August 1, 1971, apply to the gathering line regardless of the date the
pipeline was actually installed; and
(2) The requirements of this subpart
specifically applicable to pipelines installed after July 31, 1971, apply only
if the pipeline substantially meets those requirements.
§ 192.453
General.
The corrosion control procedures required by §
192.605(b)(2), including those for design, installation, operation and
maintenance of cathodic protection systems, must be carried out by, or under
the direction of, a person qualified by experience and training in pipeline
corrosion control methods.
§
192.455
External Corrosion Control: Buried or Submerged
Pipelines Installed After July 31, 1971.
(a) Except as provided in paragraphs (b),
(c), and (f) of this section, each buried or submerged pipeline installed after
July 31, 1971, must be protected against external corrosion, including the
following:
(1) It must have an external
protective coating meeting the requirements of § 192.461.
(2) It must have a cathodic protection system
designed to protect the pipeline in its entirety in accordance with this
subpart, installed and placed in operation within one year after completion of
construction.
(b) An
operator need not comply with paragraph (a) of this section, if the operator
can demonstrate by tests, investigation, or experience in the area of
application, including, as a minimum, soil resistivity measurements and tests
for corrosion accelerating bacteria, that a corrosive environment does not
exist. However, within 6 months after an installation made pursuant to the
preceding sentence, the operator shall conduct tests, including pipe-to-soil
potential measurements with respect to either a continuous reference electrode
or an electrode using close spacing, not to exceed 20 feet (6 meters), and soil
resistivity measurements at potential profile peak locations, to adequately
evaluate the potential profile along the entire pipeline. If the tests made
indicate that a corrosive condition exists, the pipeline must be cathodically
protected in accordance with paragraph (a)(2) of this section.
(c) An operator need not comply with
paragraph (a) of this section, if the operator can demonstrate by tests,
investigation, or experience that:
(1) For a
copper pipeline, a corrosive environment does not exist; or
(2) For a temporary pipeline with an
operating period of service not to exceed 5 years beyond installation,
corrosion during the 5 year period of service of the pipeline will not be
detrimental to public safety.
(d) Notwithstanding the provisions of
paragraph (b) or (c) of this section, if a pipeline is externally coated, it
must be cathodically protected in accordance with paragraph (a)(2) of this
section.
(e) Aluminum may not be
installed in a buried or submerged pipeline if that aluminum is exposed to an
environment with a natural pH in excess of 8, unless tests or experience
indicates its suitability in the particular environment involved.
(f) This section does not apply to
electrically isolated, metal alloy fittings in plastic pipelines if:
(1) For the size fitting to be used, an
operator can show by tests, investigation, or experience in the area of
application, that adequate corrosion control is provided by the alloy
composition; and
(2) The fitting is
designed to prevent leakage caused by localized corrosion pitting.
§ 192.457
External Corrosion Control: Buried or Submerged Pipelines Installed Before
August 1, 1971.(a) Except for buried
piping at compressor, regulator, and measuring stations, each buried or
submerged transmission line 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 subpart. For the purposes
of this subpart, 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.
(b) Except
for cast iron or ductile iron, each of the following buried or submerged
pipelines installed before August 1, 1971, must be cathodically protected in
accordance with this subpart in areas in which active corrosion is found:
(1) Bare or ineffectively coated transmission
lines.
(2) Bare or coated pipes at
compressor, regulator, and measuring stations.
(3) Bare or coated distribution
lines.
§
192.459
External corrosion control: Examination of buried
pipeline when exposed.
Whenever an operator has knowledge that any portion of a buried
pipeline is exposed, the exposed portion, if bare or the coating is
deteriorated, must be examined for evidence of external corrosion. If external
corrosion requiring remedial action under §§ 192.483 through 192.489
is found, the operator shall investigate circumferentially and longitudinally
beyond the exposed portion (by visual examination, indirect method, or both) to
determine whether additional corrosion requiring remedial action exists in the
vicinity of the exposed portion.
§
192.461
External Corrosion Control: Protective
Coating.(a) Each external protective
coating, whether conductive or insulating, applied for the purpose of external
corrosion control must:
(1) Be applied on a
properly prepared surface;
(2) Have
sufficient adhesion to the metal surface to effectively resist underfilm
migration of moisture;
(3) Be
sufficiently ductile to resist cracking;
(4) Have sufficient strength to resist damage
due to handling and soil stress; and
(5) Have properties compatible with any
supplemental cathodic protection.
(b) Each external protective coating which is
an electrically insulating type must also have low moisture absorption and high
electrical resistance.
(c) Each
external protective coating must be inspected just prior to lowering the pipe
into the ditch and backfilling, and any damage detrimental to effective
corrosion control must be repaired.
(d) Each external protective coating must be
protected from damage resulting from adverse ditch conditions or damage from
supporting blocks.
(e) If coated
pipe is installed by boring, driving, or other similar methods, precautions
must be taken to minimize damage to the coating during installation.
§ 192.463
External
Corrosion Control: Cathodic Protection.
(a) Each cathodic protection system required
by this subpart must provide a level of cathodic protection that complies with
one or more of the applicable criteria contained in Appendix D of this subpart.
If none of these criteria is applicable, the cathodic protection system must
provide a level of cathodic protection at least equal to that provided by
compliance with one or more of these criteria.
(b) If amphoteric metals are included in a
buried or submerged pipeline containing a metal of different anodic potential:
(1) The amphoteric metals must be
electrically isolated from the remainder of the pipeline and cathodically
protected; or
(2) The entire buried
or submerged pipeline must be cathodically protected at a cathodic potential
that meets the requirements of Appendix D of this part for amphoteric
metals.
(c) The amount
of cathodic protection must be controlled so as not to damage the protective
coating or the pipe.
§
192.465
External Corrosion Control: Monitoring.
(a) Each pipeline that is under cathodic
protection must be tested at least once each calendar year, but with intervals
not exceeding 15 months, to determine whether the cathodic protection meets the
requirements of § 192.463. However, if tests at those intervals are
impractical for separately protected short sections of mains or transmission
lines, not in excess of 100 feet (30 meters), or separately protected service
lines, these pipelines may be surveyed on a sampling basis. At least 10 percent
of these protected structures, distributed over the entire system must be
surveyed each calendar year, with a different 10 percent checked each
subsequent year, so that the entire system is tested in each 10 year
period.
(b) Each cathodic
protection rectifier or other impressed current power source must be inspected
six times each calendar year, but with intervals not exceeding 2 1/2 months, to
insure that it is operating. Evidence of proper functioning may be current
output, normal power consumption, a signal indicating normal D.C. power, or
satisfactory electrical state of the protected piping.
(c) Each reverse current switch, each diode,
and each interference bond whose failure would jeopardize structure protection
must be electrically checked for proper performance six times each calendar
year, but with intervals not exceeding 2 1/2 months. Each other interference
bond must be checked at least once each calendar year, but with intervals not
exceeding 15 months.
(d) Each
operator shall take prompt remedial action to correct any deficiencies
indicated by the monitoring.
(e)
After the initial evaluation required by §§ 192.455(b) and (c) and
192.457(b), each operator must, not less than every 3 years at intervals not
exceeding 39 months, reevaluate its unprotected pipelines and cathodically
protect them in accordance with this subpart in areas in which active corrosion
is found. 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, and the pipeline environment.
§ 192.467
External Corrosion
Control: Electrical Isolation.
(a)
Each buried or submerged pipeline must be electrically isolated from other
underground metallic structures, unless the pipeline and the other structures
are electrically interconnected and cathodically protected as a single
unit.
(b) One or more insulating
devices must be installed where electrical isolation of a portion of a pipeline
is necessary to facilitate the application of corrosion control.
(c) Except for unprotected copper inserted in
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.
(d) Inspection and electrical tests must be
made to assure that electrical isolation is adequate.
(e) An insulating device may not be installed
in an area where a combustible atmosphere is anticipated unless precautions are
taken to prevent arcing.
(f) Where
a pipeline is located in close 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.
§ 192.469
External Corrosion
Control: Test Stations.
Each pipeline under cathodic protection required by this
subpart must have sufficient test stations or other contact points for
electrical measurement to determine the adequacy of cathodic protection.
§ 192.471
External
Corrosion Control: Test Leads.(a) Each
test lead wire must be connected to the pipeline so as to remain mechanically
secure and electrically conductive.
(b) Each test lead wire must be attached to
the pipeline so as to minimize stress concentration on the pipe.
(c) Each bared test lead wire and bared
metallic area at point of connection to the pipeline must be coated with an
electrical insulating material compatible with the pipe coating and the
insulation on the wire.
§
192.473
External Corrosion Control: Interference
Currents.(a) Each operator whose
pipeline system is subjected to stray currents shall have in effect a
continuing program to minimize the detrimental effects of such
currents.
(b) Each impressed
current type cathodic protection system or galvanic anode system must be
designed and installed so as to minimize any adverse effects on existing
adjacent underground metallic structures.
§ 192.475
Internal Corrosion
Control: General.
(a) Corrosive gas
may not be transported by pipeline, unless the corrosive effect of the gas on
the pipeline has been investigated and steps have been taken to minimize
internal corrosion.
(b) Whenever
any pipe is removed from a pipeline for any reason, the internal surface must
be inspected for evidence of corrosion. If internal corrosion is found:
(1) The adjacent pipe must be investigated to
determine the extent of internal corrosion;
(2) Replacement must be made to the extent
required by the applicable paragraphs of §§ 192.485, 192.487, or
192.489; and
(3) Steps must be
taken to minimize the internal corrosion.
(c) Gas containing more than 0.1 grain of
hydrogen sulfide per 100 cubic feet (2.32 milligrams/m3) at standard conditions
may not be stored in pipe-type or bottle-type holders.
§ 192.476
Internal Corrosion
Control: Design and Construction of Transmission Line.
(a)
Design and construction.
Except as provided in paragraph (b) of this section, 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:
(1) Be configured to
reduce the risk that liquids will collect in the line;
(2) Have effective liquid removal features
whenever the configuration would allow liquids to collect; and
(3) Allow use of devices for monitoring
internal corrosion at locations with significant potential for internal
corrosion.
(b)
Exceptions to applicability. The design and construction
requirements of paragraph (a) of this section do not apply to the following:
(1) Offshore pipeline; and
(2) Pipeline installed or line pipe, valve,
fitting or other line component replaced before May 23, 2007.
(c)
Change to existing
transmission line. 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 onshore
transmission line and provide for removal of liquids and monitoring of internal
corrosion as appropriate.
(d)
Records. An operator must maintain records demonstrating
compliance with this section. Provided the records show why incorporating
design features addressing paragraph (a)(1), (a)(2), or (a)(3) of this section
is impracticable or unnecessary, an operator may fulfill this requirement
through written procedures supported by as-built drawings or other construction
records.
§ 192.477
Internal Corrosion Control: Monitoring.
If corrosive gas is being transported, coupons or other
suitable means must be used to determine the effectiveness of the steps taken
to minimize internal corrosion. Each coupon or other means of monitoring
internal corrosion must be checked two times each calendar year, but with
intervals not exceeding 7 1/2 months.
§ 192.479
Atmospheric Corrosion
Control: General.
(a) Each operator
must clean and coat each pipeline or portion of pipeline that is exposed to the
atmosphere, except pipelines under paragraph (c) of this section.
(b) Coating material must be suitable for the
prevention of atmospheric corrosion.
(c) Except portions of pipelines in offshore
splash zones or 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--
(1) Only be a light
surface oxide; or
(2) Not affect
the safe operation of the pipeline before the next scheduled
inspection.
§
192.481
Atmospheric Corrosion Control: Monitoring.
(a) Each operator must inspect each pipeline
or portion of pipeline that is exposed to the atmosphere for evidence of
atmospheric corrosion, as follows:
|
If the pipeline is located..
|
Then the frequency of inspections is:
|
|
Onshore
|
At least once every 3 calendar years, but with
intervals not exceeding 39 months.
|
|
Offshore
|
At least once each calendar year, but with intervals
not exceeding 15 months.
|
(b)
During inspections the operator must give particular attention to pipe at
soil-to-air interfaces, under thermal insulation, under disbonded coatings, at
pipe supports, in splash zones, at deck penetrations, and in spans over
water.
(c) If atmospheric corrosion
is found during an inspection, the operator must provide protection against the
corrosion as required by § 192.479.
§ 192.483
Remedial Measures:
General.
(a) Each segment of metallic
pipe that 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 §
192.461.
(b) Each segment of
metallic pipe that replaces pipe removed from a buried or submerged pipeline
because of external corrosion must be cathodically protected in accordance with
this subpart.
(c) Except for cast
iron or ductile iron pipe, each segment of buried or submerged pipe that is
required to be repaired because of external corrosion must be cathodically
protected in accordance with this subpart.
§ 192.485
Remedial Measures:
Transmission Lines.
(a)
General corrosion. Each segment of transmission line with
general corrosion and with a remaining wall thickness less than that required
for the MAOP 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 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.
(b)
Localized
corrosion pitting. Each 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.
(c) Under paragraphs (a)
and (b) of this section, the strength of pipe based on actual remaining wall
thickness may be determined by the procedure in ASME/ANSI B31G or the procedure
in AGA Pipeline Research Committee Project PR 3-805 (with RSTRENG disk). Both
procedures apply to corroded regions that do not penetrate the pipe wall,
subject to the limitations prescribed in the procedures.
§ 192.487
Remedial Measures:
Distribution Lines Other Than Cast Iron or Ductile Iron Lines.
(a)
General corrosion.
Except for cast iron or ductile iron pipe, each segment of generally corroded
distribution line pipe with a remaining wall thickness less than that required
for the MAOP of the pipeline, or a remaining wall thickness less than 30
percent of the nominal wall thickness, must be replaced. 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.
(b)
Localized corrosion
pitting. Except 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.
§ 192.489
Remedial Measures: Cast
Iron and Ductile Iron Pipelines.(a)
General graphitization. Each segment 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.
(b)
Localized
graphitization. Each segment 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.
§ 192.490
Direct
assessment.
Each operator that uses direct assessment as defined in §
192.903 on an onshore transmission line made primarily of steel or iron to
evaluate the effects of a threat in the first column must carry out the direct
assessment according to the standard listed in the second column. These
standards do not apply to methods associated with direct assessment, such as
close interval surveys, voltage gradient surveys, or examination of exposed
pipelines, when used separately from the direct assessment process.
|
Threat
|
Standard1
|
|
External corrosion
|
§ 192.9252
|
|
Internal corrosion in pipelines that transport dry
gas
|
§ 192.927
|
|
Stress corrosion cracking
|
§ 192.929
|
1 For lines not
subject to subpart O of this part, the terms "covered segment" and "covered
pipeline segment" in §§ 192.925, 192.927, and 192.929 refer to the
pipeline segment on which direct assessment is performed.
2 In § 192.925(b), the provision
regarding detection of coating damage applies only to pipelines subject to
subpart O of this part.
§
192.491
Corrosion Control Records.
(a) Each operator shall maintain records or
maps to show the location of cathodically protected piping, cathodic protection
facilities, other than unrecorded galvanic anodes installed before August 1,
1971, and neighboring structures bonded to the cathodic protection
system.
(b) Each of the following
records must be retained for as long as the pipeline remains in service:
(1) Each record or map required by paragraph
(a) of this section;
(2) Records of
each test, survey, or inspection required by this subpart, in sufficient detail
to demonstrate the adequacy of corrosion control measures or that a corrosive
condition does not exist.
SUBPART J
-TEST REQUIREMENTS
§ 192.501
Scope.
This subpart prescribes minimum leak-test and strength-test
requirements for pipelines.
§
192.503
General Requirements.
(a) No person may operate a new segment of
pipeline, or return to service a segment of pipeline that has been relocated or
replaced, until:
(1) It has been tested in
accordance with this subpart and § 192.619 to substantiate the maximum
allowable operating pressure; and
(2) Each detected leak has been
eliminated.
(b) The test
medium must be liquid, air, natural gas, or inert gas that is:
(1) Compatible with the material of which the
pipeline is constructed;
(2)
Relatively free of sedimentary materials; and
(3) Except for natural gas,
nonflammable.
(c) Except
as provided in § 192.505(a), if air, natural gas, or inert gas is used as
the test medium, the following maximum hoop stress limitations apply:
|
Class location
|
Maximum hoop stress allowed as percentage of
SMYS
|
|
Natural Gas
|
Air or inert gas
|
|
1........
|
80
|
80
|
|
2........
|
30
|
75
|
|
3........
|
30
|
50
|
|
4........
|
30
|
40
|
(d)
Each joint used to tie-in a test segment of pipeline is excepted from the
specific test requirements of this subpart, but each non-welded joint must be
leak tested at not less than its operating pressure.
§ 192.505
Strength Test
Requirements for Steel Pipeline to Operate at a Hoop Stress of 30 Percent or
More of SMYS.(a) Except for service
lines, each segment of a steel pipeline that is to operate at a hoop stress of
30 percent or more SMYS must be strength tested in accordance with this section
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 300 feet (91 meters) of a pipeline, a hydrostatic test must be
conducted to a test pressure of at least 125 percent of maximum operating
pressure on that segment of the pipeline within 300 feet (91 meters) of such a
building, but in no event may the test section be less than 600 feet (183
meters) unless the length of the newly installed or relocated pipe is less than
600 feet (183 meters). However, if the buildings are evacuated while the hoop
stress exceeds 50 percent of SMYS, air or inert gas may be used as the test
medium.
(b) In a Class 1 or Class 2
location, each compressor station, regulator station, and measuring station,
must be tested to at least Class 3 location test requirements.
(c) Except as provided in paragraph (e) of
this section, the strength test must be conducted by maintaining the pressure
at or above the test pressure for at least 8 hours.
(d) If a component other than pipe is the
only item being replaced or added to a pipeline, a strength test after
installation is not required, if the manufacturer of the component certifies
that:
(1) The component was tested to at
least the pressure required for the pipeline to which it is being
added;
(2) The component was
manufactured under a quality control system that ensures that each item
manufactured is at least equal in strength to a prototype and that the
prototype was tested to at least the pressure required for the pipeline to
which it is being added; or
(3) The
component carries a pressure rating established through applicable ASME/ANSI,
MSS specifications, or by unit strength calculations as described in §
192.143.
(e) For
fabricated units and short sections of pipe, for which a post installation test
is impractical, a preinstallation strength test must be conducted by
maintaining the pressure at or above the test pressure for at least 4
hours.
§ 192.507
Test Requirements for Pipelines to Operate at a Hoop Stress Less Than 30
Percent of SMYS and at or Above 100 P.S.I. (689 kPa) Gage.
Except for service lines and plastic pipelines, each segment of
a pipeline that is to be operated at a hoop stress less than 30 percent of SMYS
and at or above 100 p.s.i. (689 kPa) gage must be tested in accordance with the
following:
(a) The test procedure used
must reasonably ensure discovery of leaks in the segment being
tested.
(b) If, during the test,
the segment is to be stressed to 20 percent or more of SMYS and natural gas,
inert gas, or air is the test medium:
(1) A
leak test must be made at a pressure between 100 p.s.i. (689 kPa) gage and the
pressure required to produce a hoop stress of 20 percent of SMYS; or
(2) The line must be walked to check for
leaks while the hoop stress is held at approximately 20 percent of
SMYS.
(c) The pressure
must be maintained at or above the test pressure for at least 1 hour.
§ 192.509
Test
Requirements for Pipelines to Operate Below 100 P.S.I. (689 kPa) Gage.
Except for service lines and plastic pipelines, each segment of
a pipeline that is to be operated below 100 p.s.i.g.. must be leak tested in
accordance with the following:
(a) The
test procedure used must reasonably ensure discovery of leaks in the segment
being tested.
(b) Each main that is
to be operated at less than 1 p.s.i. (6.9 kPa) gage must be tested to at least
10 p.s.i. (69 kPa) gage and each main to be operated at or above 1 p.s.i. (6.9
kPa) gage must be tested to at least 90 p.s.i. (621 kPa) gage.
§ 192.511
Test
Requirements for Service Lines.(a)
Each segment of a service line (other than plastic) must be leak tested in
accordance with this section before being placed in service. If feasible, the
service line connection to the main must be included in the test; if not
feasible, it must be given a leakage test at the operating pressure when placed
in service.
(b) Each segment of a
service line (other than plastic) intended to be operated at pressure of less
than 1 p.s.i. (6.9 kPa) gage shall be given a leak test at a pressure of 10
p.s.i. (69 kPa) gage. This test shall be conducted with a 3 inch (76
millimeters) dial gauge with a maximum scale of 30 p.s.i. (207 kPa) gage. This
test may be conducted with a mercury gauge capable of testing to 10 inches (254
millimeters) of mercury.
(c) Each
segment of a service line (other than plastic) intended to be operated at a
pressure of at least 1 p.s.i. (6.9 kPa) gage but not more than 40 p.s.i. (276
kPa) gage must be given a leak test at a pressure of not less than 50 p.s.i.
(345 kPa) gage on a 100 p.s.i. (689 kPa) gage scale gauge.
(d) Each segment of a service line (other
than plastic) intended to be operated at pressures of more than 40 p.s.i.g..
must be tested to at least 90 p.s.i.g.. on 100 p.s.i.g.. scale gauge, except
that each segment of a steel service line stressed to 20 percent or more of
SMYS must be tested in accordance with § 192.507.
(e) The test procedure used must reasonably
ensure discovery of leaks in the segment being tested.
§ 192.513
Test Requirements for
Plastic Pipelines.(a) Each segment of
a plastic pipeline must be tested in accordance with this section.
(b) The test procedure used must reasonably
ensure discovery of leaks in the segment being tested.
(c) The test pressure must be at least 150
percent of the maximum operating pressure or 50 p.s.i. (345 kPa) gage whichever
is greater. However, the maximum test pressure may not be more than three times
the pressure determined under § 192.121, at a temperature not less than
the pipe temperature during the test.
(d) During the test, the temperature of
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.
§ 192.515
Environmental Protection and Safety Requirements.
(a) In conducting tests under this subpart,
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 50 percent 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.
(b) The operator shall
insure that the test medium is disposed of in a manner that will minimize
damage to the environment.
§
192.517
Records.
(a) Each operator shall make and retain for
the useful life of the pipeline, a record of each test performed under
§§ 192.505 and 192.507. The record must contain at least the
following information:
(1) The operator's
name, the name of the operator's employee responsible for making the test and
the name of any test company used.
(2) Test medium used.
(3) Test pressure.
(4) Test duration.
(5) Pressure recording charts or other
records of pressure readings.
(6)
Evaluation variations, whenever significant for the particular test.
(7) Leaks and failures noted and their
disposition.
(b) Each
operator must maintain a record of each test required by §§ 192.509,
192.511, and 192.513 for at least 5 years.
SUBPART K
-UPRATING
§ 192.551
Scope.
This subpart prescribes minimum requirements for increasing
maximum allowable operating pressures (uprating) for pipelines.
§ 192.553
General.
(a)
Pressure
increases. Whenever the requirements of this subpart 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:
(1) At the end of each
incremental increase, the pressure must be held constant while the entire
segment of pipeline that is affected is checked for leaks.
(2) Each leak detected must be 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.
(b)
Records. Each
operator who uprates a segment of pipeline shall retain for the life of the
segment a record of each investigation required by this subpart, of all work
performed, and of each pressure test conducted, in connection with the
uprating.
(c)
Written
plan. Each operator who uprates a segment of pipeline shall establish
a written procedure that will ensure that each applicable requirement of this
subpart is complied with.
(d)
Limitation on increase in maximum allowable operating
pressure. Except as provided in § 192.555(c), a new maximum
allowable operating pressure established under this subpart may not exceed the
maximum that would be allowed under § 192.619 and 192.621 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 (§ 192.105) is unknown, the
MAOP may be increased as provided in § 192.619(a)(1).
§ 192.555
Uprating To a Pressure
That Will Produce a Hoop Stress of 30 Percent or More of SMYS in Steel
Pipelines.
(a) Unless the requirements
of this 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 30 percent
or more of SMYS and that is above the established maximum allowable operating
pressure.
(b) Before increasing
operating pressure above the previously established pressure the operator
shall:
(1) Review the design, operating and
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 part; and
(2)
Make any repairs, replacements, or alterations in the segment of pipeline that
are necessary for safe operation at the increased pressure.
(c) After complying with paragraph
(b) of this section, 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 § 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).
(d) After complying with paragraph (b) of
this section, an operator that does not qualify under paragraph (c) of this
section may increase the previously established maximum allowable operating
pressure if at least one of the following requirements is met:
(1) The segment of pipeline is successfully
tested in accordance with the requirements of this part for a new line of the
same material in the same location.
(2) An increased maximum allowable 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:
(i) It is impractical to test it in
accordance with the requirements of this part;
(ii) The new maximum operating pressure does
not exceed 80 percent of that allowed for a new line of the same design in the
same location; and
(iii) The
operator determines that the new maximum allowable operating pressure is
consistent with the condition of the segment of pipeline and the design
requirements of this part.
(e) Where a segment of pipeline is uprated in
accordance with paragraph (c) or (d)(2) of this section, the increase in
pressure must be made in increments that are equal to:
(1) 10 percent of the pressure before the
uprating; or
(2) 25 percent of the
total pressure increase, whichever produces the fewer number of
increments.
§
192.557
Uprating Steel Pipelines to a Pressure That Will
Produce a Hoop Stress Less Than 30 Percent of SMYS; Plastic, Cast Iron, and
Ductile Iron Pipelines.(a) Unless the
requirements of this section have been met, no person may subject:
(1) A segment of steel pipeline to an
operating pressure that will produce a hoop stress less than 30 percent of SMYS
and that is above the previously established maximum allowable operating
pressure; or
(2) A plastic, cast
iron, or ductile iron pipeline segment to an operating pressure that is above
the previously established maximum allowable operating pressure.
(b) Before increasing operating
pressure above the previously established maximum allowable operating pressure,
the operator shall:
(1) Review the design,
operating, and maintenance history of the segment of pipeline;
(2) Make a leakage survey (if it has been
more than 1 year since the last survey) 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;
(3) Make any
repairs, replacements or alterations in the segment of pipeline that are
necessary for safe operation at the increased pressure;
(4) Reinforce or anchor offsets, bends 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;
(5) Isolate the
segment of pipeline in which the pressure is to be increased from any adjacent
segment that will continue to be operated at a lower pressure; and
(6) If the pressure in mains or service
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.
(c) After complying with paragraph (b) of
this section, the increase in maximum allowable operating pressure must be made
in increments that are equal to 10 p.s.i. (69 kPa) gage or 25 percent of the
total pressure increase, whichever produces the fewer number of increments.
Whenever the requirements of paragraph (b)(6) of this section apply, there must
be at least two approximately equal incremental increases.
(d) If records for cast iron or ductile iron
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:
(1) In estimating the stresses, if the
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.
(2) Unless the actual maximum cover depth is
known, the operator shall measure the actual cover in at least three places
where the cover is most likely to be greatest and shall use the greatest cover
measured.
(3) Unless the actual
nominal wall thickness is known, the operator shall determine the wall
thickness by cutting and measuring coupons from at least three 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:
|
Pipe Size Inches (millimeters)
|
ALLOWANCE Inches (millimeters) Cast Iron
Pipe
|
|
Cast Iron Pipe
|
Ductile iron pipe
|
|
Pit Cast Pipe
|
Centrifugally Cast Pipe
|
|
3-8 (76-203)
|
0.075(1.91)
|
0.065(1.65)
|
0.065(1.65)
|
|
10-12 (254 to 305)
|
0.08(2.03)
|
0.07(1.78)
|
0.07(1.78)
|
|
14-24 (356 to 610)
|
0.08(2.03)
|
0.08(2.03)
|
0.075(1.91)
|
|
30-42 (762 to 1067)
|
0.09(2.29)
|
0.09(2.29)
|
0.075(1.91)
|
|
48 (1219)
|
0.09(2.29)
|
0.09(2.29)
|
0.08(2.03)
|
|
54-60 (1372 to 1524)
|
0.09(2.29)
|
-------------
|
-------------
|
(4)
For cast iron pipe, unless the pipe manufacturing process is known, the
operator shall assume that the pipe is pit cast pipe with a bursting tensile
strength of 11,000 p.s.i. (76 MPa) gage and a modulus of rupture of 31,000
p.s.i. (214 MPa) gage.
SUBPART L
-OPERATIONS
§ 192.601
Scope.
This subpart prescribes minimum requirements for the operation
of pipeline facilities.
§
192.603
General Provisions.
(a) No person may operate a segment of
pipeline unless it is operated in accordance with this subpart.
(b) Each operator shall keep records
necessary to administer the procedures established under §
192.605.
(c) The Administrator or
the State Agency that has submitted a current certification under the pipeline
safety laws (49
U.S.C. 60101
et seq) with
respect to the pipeline facility governed by an operator's plans and procedures
may, after notice and opportunity for hearing as provided in
49 CFR
190.237 or the relevant State procedures,
require the operator to amend its plans and procedures as necessary to provide
a reasonable level of safety.
§
192.605
Procedural Manual for Operations, Maintenance, and
Emergencies.
(a)
General. Each operator shall prepare and follow for each
pipeline, a manual of written procedures for conducting operations and
maintenance activities and for emergency response. For transmission lines, the
manual must also include procedures for handling abnormal operations. This
manual must be reviewed and updated by the operator at intervals not exceeding
15 months, but at least once each calendar year. This manual must be prepared
before operations of a pipeline system commence. Appropriate parts of the
manual must be kept at locations where operations and maintenance activities
are conducted.
(b)
Maintenance and normal operations. The manual required by
paragraph (a) of this section must include procedures for the following, if
applicable, to provide safety during maintenance and operations:
(1) Operating, maintaining, and repairing the
pipeline in accordance with each of the requirements of this subpart and
subpart M of this part.
(2)
Controlling corrosion in accordance with the operations and maintenance
requirements of subpart I of this part.
(3) Making construction records, maps, and
operating history available to appropriate personnel.
(4) Gathering of data needed for reporting
incidents under Part 191 in a timely and effective manner.
(5) Starting up and shutting down any part of
the pipeline in a manner designed to assure operation within the MAOP limits
prescribed by this part, plus the build-up allowed for operation of
pressure-limiting and control devices.
(6) Maintaining compressor stations,
including provisions for isolating units or sections of pipe and for purging
before returning to service.
(7)
Starting, operating and shutting down gas compressor units.
(8) Periodically reviewing the work done by
operator personnel to determine the effectiveness, and adequacy of the
procedures used in normal operation and maintenance and modifying the
procedures when deficiencies are found.
(9) Taking adequate precautions in excavated
trenches to protect personnel from the hazards of unsafe accumulations of vapor
or gas, and making available when needed at the excavation emergency rescue
equipment, including a breathing apparatus and, a rescue harness and
line.
(10) Systematic and routine
testing and inspection of pipe-type or bottle-type holders including:
(i) Provision for detecting external
corrosion before the strength of the container has been impaired;
(ii) Periodic sampling and testing of gas in
storage to determine the dew point of vapors contained in the stored gas which,
if condensed, might cause internal corrosion or interfere with the safe
operation of the storage plant; and
(iii) Periodic inspection and testing of
pressure limiting equipment to determine that it is in safe operating condition
and has adequate capacity.
(11) Responding promptly to a report of a gas
odor inside or near a building, unless the operator's emergency procedures
under § 192.615(a)(3) specifically apply to these reports.
(12) Implementing the applicable control room
management procedures required by § 192.631.
(c)
Abnormal operations. For
transmission lines, the manual required by subparagraph (a) of this paragraph
must include procedures for the following to provide safety when operating
design limits have been exceeded:
(1)
Responding to, investigating, and correcting the cause of:
(i) Unintended closure of valves or
shutdowns;
(ii) Increase or
decrease in pressure or flow rate outside normal operating limits;
(iii) Loss of communications;
(iv) Operation of any safety device;
and
(v) Any other foreseeable
malfunction of a component, deviation from normal operation, or personnel error
which may result in a hazard to persons or property.
(2) Checking variations from normal operation
after abnormal operation has ended at sufficient critical locations in the
system to determine continued integrity and safe operation.
(3) Notifying responsible operator personnel
when notice of an abnormal operation is received.
(4) Periodically reviewing the response of
operator personnel to determine the effectiveness of the procedures controlling
abnormal operation and taking corrective action where deficiencies are
found.
(5) The requirements of this
paragraph do not apply to natural gas distribution operators that are operating
transmission lines in connection with their distribution system.
(d)
Safety-related
condition reports. The manual required by subparagraph (a) of this
paragraph must include instructions enabling personnel who perform operation
and maintenance activities to recognize conditions that potentially may be
safety-related conditions that are subject to the reporting requirements of
§ 191.23.
(e)
Surveillance, emergency response, and accident investigation.
The procedures required by §§ 192.613(a), 192.615, and 192.617 must
be included in the manual required by paragraph (a) of this section.
§ 192.607
[Removed and
Reserved]
§ 192.609
Change in Class Location: Required Study.
Whenever an increase in population density indicates a change
in class location for a segment of an existing steel pipeline operating at hoop
stress that is more than 40 percent of SMYS, or indicates that the hoop stress
corresponding to the established maximum allowable operating pressure for a
segment of existing pipeline is not commensurate with the present class
location, the operator shall immediately make a study to determine:
(a) The present class location for the
segment involved;
(b) The design,
construction, and testing procedures followed in the original construction, and
a comparison of these procedures with those required for the present class
location by the applicable provisions of this part;
(c) The physical condition of the segment to
the extent it can be ascertained from available records;
(d) The operating and maintenance history of
the segment;
(e) The maximum actual
operating pressure and the corresponding operating hoop stress, taking pressure
gradient into account, for the segment of pipeline involved; and
(f) The actual area affected by the
population density increase, and physical barriers or other factors which may
limit further expansion of the more densely populated area.
§ 192.611
Change in
Class Location: Confirmation or Revision of Maximum Allowable Operating
Pressure.
(a) If the hoop stress
corresponding to the established maximum allowable operating pressure of a
segment of pipeline is not commensurate with the present class location, and
the segment is in satisfactory physical condition, the maximum allowable
operating pressure of that segment of pipeline must be confirmed or revised
according to one of the following requirements:
(1) If the segment involved has been
previously tested in place for a period of not less than 8 hours.
(i) The maximum allowable operating pressure
is 0.8 times the test pressure in Class 2 locations, 0.667 times the test
pressure in Class 3 locations, or 0.555 times the test pressure in Class 4
locations. The corresponding hoop stress may not exceed 72 percent of the SMYS
of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or
50 percent of SMYS in Class 4 locations.
(ii) The alternative maximum allowable
operating pressure is 0.8 times the test pressure in Class 2 locations and
0.667 times the test pressure in Class 3 locations. For pipelines operating at
alternative maximum allowable pressure per § 192.620, the corresponding
hoop stress may not exceed 80 percent of the SMYS of the pipe in Class 2
locations and 67 percent of the SMYS in Class 3 locations.
(2) The maximum allowable operating pressure
of the segment involved must be reduced so that the corresponding hoop stress
is not more than that allowed by this part for new segments of pipelines in the
existing class location.
(3) The
segment involved must be tested in accordance with the applicable requirements
of Subpart J of this part, and its maximum allowable operating pressure must
then be established according to the following criteria:
(i) The maximum allowable operating pressure
after the requalification test is 0.8 times the test pressure for Class 2
locations, 0.667 times the test pressure for Class 3 locations, and 0.555 times
the test pressure for Class 4 locations.
(ii) The corresponding hoop stress may not
exceed 72 percent of the SMYS of the pipe in Class 2 locations, 60 percent of
SMYS in Class 3 locations, or 50 percent of SMYS in Class 4
locations.
(iii) For pipeline
operating at an alternative maximum allowable operating pressure per §
192.620, the alternative maximum allowable operating pressure after the
requalification test is 0.8 times the test pressure for Class 2 locations and
0.667 times the test pressure for Class 3 locations. The corresponding hoop
stress may not exceed 80 percent of the SMYS of the pipe in Class 2 locations
and 67 percent of SMYS in Class 3 locations.
(b) The maximum allowable operating pressure
confirmed or revised in accordance with this section, may not exceed the
maximum allowable operating pressure established before the confirmation or
revision.
(c) Confirmation or
revision of the maximum allowable operating pressure of a segment of pipeline
in accordance with this section does not preclude the application of
§§ 192.553 and 192.555.
(d) Confirmation or revision of the maximum
allowable operating pressure that is required as a result of a study under
§ 192.609 must be completed within 24 months of the change in class
location. Pressure reduction under paragraph (a) (1) or (2) of this section
within the 24-month period does not preclude establishing a maximum allowable
operating pressure under paragraph (a)(3) of this section at a later
date.
§ 192.613
Continuing Surveillance.(a)
Each operator shall have a procedure for continuing surveillance of its
facilities to determine and take appropriate action concerning changes in class
location, failures, leakage history, corrosion, substantial changes in cathodic
protection requirements, and other unusual operating and maintenance
conditions.
(b) If a segment of
pipeline is determined to be in unsatisfactory condition but no immediate
hazard exists, the operator shall initiate a program to recondition or phase
out the segment involved, or, if the segment cannot be reconditioned or phased
out, reduce the maximum allowable operating pressure in accordance with
§§ 192.619(a) and (b).
§ 192.614
Damage Prevention
Program.
(a) Except as provided in
paragraphs (d) and (e) of this section, each operator of a buried pipeline must
carry out, in accordance with this section, a written program to prevent damage
to that pipeline from excavation activities. For the purpose of this section,
the term "excavation activities" include excavation, blasting, boring,
tunneling, backfilling, the removal of the above ground structures by either
explosive or mechanical means, and other earth moving operations.
(b) An operator may comply with any of the
requirements of paragraph (c) of this section through participation in a public
service program, such as a one-call system, but such participation does not
relieve the operator of responsibility for compliance with this section.
However, an operator must perform the duties of paragraph (c)(3) of this
section through participation in a one-call system, if that one-call system is
a qualified one-call system. In areas that are covered by more than one
qualified one-call system, an operator need only join one of the qualified
one-call systems if there is a central telephone number for excavators to call
for excavation activities, or if the one-call systems in those areas
communicate with one another. An operator's pipeline system must be covered by
a qualified one-call system where there is one in place. For the purpose of
this section, a one-call system is considered a "qualified one-call system" if
it meets the requirements of section (b)(1) or (b)(2) of this section.
(1) The state has adopted a one-call damage
prevention program under
49 CFR §
198.37; or
(2) The one-call system:
(i) Is operated in accordance with
49 CFR
§
198.39;
(ii) Provides a pipeline operator an
opportunity similar to a voluntary participant to have a part in management
responsibilities; and
(iii)
Assesses a participating pipeline operator a fee that is proportionate to the
costs of the one-call system's coverage of the operator's pipeline.
(c) The damage
prevention program required by paragraph (a) of this section must, at a
minimum:
(1) Include the identity, on a
current basis, of persons who normally engage in excavation activities in the
area in which the pipeline is located.
(2) Provides for notification of the public
in the vicinity of the pipeline and actual notification of the persons
identified in paragraph (c)(1) of this section of the following as often as
needed to make them aware of the damage prevention program:
(i) The program's existence and purpose;
and
(ii) How to learn the location
of underground pipelines before excavation activities are begun.
(3) Provide a means of receiving
and recording notification of planned excavation activities.
(4) If the operator has buried pipelines in
the area of excavation activity, provide for actual notification of persons who
give notice of their intent to excavate of the type of temporary marking to be
provided and how to identify the markings.
(5) Provide for temporary marking of buried
pipelines in the area of excavation activity before, as far as practical, the
activity begins.
(6) Provide as
follows for inspection of pipelines that an operator has reason to believe
could be damaged by excavation activities:
(i)
The inspection must be done as frequently as necessary during and after the
activities to verify the integrity of the pipeline; and
(ii) In the case of blasting, any inspection
must include leakage surveys.
(d) A damage prevention program under this
section is not required for pipelines to which access is physically controlled
by the operator.
(e) Pipelines
operated by persons other than municipalities (including operators of master
meters) whose primary activity does not include the transportation of gas need
not comply with the following:
(1) The
requirement of paragraph (a) of this section that the damage prevention program
be written; and
(2) The
requirements of paragraphs (c)(1) and (c)(2) of this section.
§ 192.615
Emergency Plans.
(a) Each operator
shall establish written procedures to minimize the hazard resulting from a gas
pipeline emergency. At a minimum, the procedures must provide for the
following:
(1) Receiving, identifying, and
classifying notices of events which require immediate response by the
operator.
(2) Establishing and
maintaining adequate means of communication with appropriate fire, police, and
other public officials.
(3) Prompt
and effective response to a notice of each type of emergency, including the
following:
(i) Gas detected inside or near a
building.
(ii) Fire located near or
directly involving a pipeline facility.
(iii) Explosion occurring near or directly
involving a pipeline facility.
(iv)
Natural disaster.
(4)
The availability of personnel, equipment, tools, and materials, as needed at
the scene of an emergency.
(5)
Actions directed toward protecting people first and then property.
(6) Emergency shutdown and pressure reduction
in any section of the operator's pipeline system necessary to minimize hazards
to life or property.
(7) Making
safe any actual or potential hazard to life or property.
(8) Notifying appropriate fire, police, and
other public officials of gas pipeline emergencies and coordinating with them
both planned responses and actual responses during an emergency.
(9) Safely restoring any service
outage.
(10) Beginning action under
§ 192.617, if applicable, as soon after the end of the emergency as
possible.
(11) Actions required to
be taken by a controller during an emergency in accordance with §
192.631.
(b) Each
operator shall:
(1) Furnish its supervisors
who are responsible for emergency action a copy of that portion of the latest
edition of the emergency procedures established under paragraph (a) of this
section as necessary for compliance with those procedures.
(2) Train the appropriate operating personnel
to assure that they are knowledgeable of the emergency procedures and verify
that the training is effective.
(3)
Review employee activities to determine whether the procedures were effectively
followed in each emergency.
(c) Each operator shall establish and
maintain liaison with appropriate fire, police, and other public officials to:
(1) Learn the responsibility and resources of
each government organization that may respond to a gas pipeline
emergency;
(2) Acquaint the
officials with the operator's ability in responding to a gas pipeline
emergency;
(3) Identify the types
of gas pipeline emergencies of which the operator notifies the officials;
and
(4) Plan how the operator and
officials can engage in mutual assistance to minimize hazards to life or
property.
(d) Maintain a
current map of the entire gas system or sectional maps of large systems. These
maps will be of sufficient detail to approximate the location of mains and
transmission lines.
(e) Identify
all key valves which may be necessary for the safe operation of the system. The
location of these valves shall be designated on appropriate records, drawings
or maps.
§ 192.616
Public Awareness.(a) Except for
an operator of a master meter or petroleum gas system covered under paragraph
(j) of this section, 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, see § 192.7).
(b) The operator's program must follow the
general program recommendations of API RP 1162 and assess the unique attributes
and characteristics of the operator's pipeline and facilities.
(c) The operator must follow the general
program recommendations, including baseline and supplemental requirements of
API RP 1162, unless the operator provides justification in its program or
procedural manual as to why compliance with all or certain provisions of the
recommended practice is not practicable and not necessary for safety.
(d) The operator's program must specifically
include provisions to educate the public, appropriate government organizations,
and persons engaged in excavation related activities on:
(1) Use of a one-call notification system
prior to excavation and other damage prevention activities;
(2) Possible hazards associated with
unintended releases from a gas pipeline facility;
(3) Physical indications that such a release
may have occurred;
(4) Steps that
should be taken for public safety in the event of a gas pipeline release;
and
(5) Procedures for reporting
such an event.
(e) The
program must include activities to advise affected municipalities, school
districts, businesses, and residents of pipeline facility locations.
(f) The program and the media used must be as
comprehensive as necessary to reach all areas in which the operator transports
gas.
(g) The program must be
conducted in English and in other languages commonly understood by a
significant number and concentration of the non-English speaking population in
the operator's area.
(h) Operators
in existence on June 20, 2005, must have completed their written programs no
later than June 20, 2006. The operator of a master meter or petroleum gas
system covered under paragraph (j) of this section must complete development of
its written procedure by June 13, 2008. Upon request, operators must submit
their completed programs to PHMSA or, in the case of an intrastate pipeline
facility operator, the appropriate State agency.
(i) The operator's program documentation and
evaluation results must be available for periodic review by appropriate
regulatory agencies.
(j) Unless the
operator transports gas as a primary activity, the operator of a master meter
or petroleum gas system is not required to develop a public awareness program
as prescribed in paragraphs (a) through (g) of this section. Instead the
operator must develop and implement a written procedure to provide its
customers public awareness messages twice annually. If the master meter or
petroleum gas system 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:
(1) A description of the purpose and
reliability of the pipeline;
(2) An
overview of the hazards of the pipeline and prevention measures used;
(3) Information about damage
prevention;
(4) How to recognize
and respond to a leak; and
(5) How
to get additional information.
§ 192.617
Investigation of
Failures.
Each operator shall establish procedures for analyzing
accidents and failures, including the selection of samples of the failed
facility or equipment for laboratory examination, where appropriate, for the
purpose of determining the causes of the failure and minimizing the possibility
of a recurrence.
§
192.619
Maximum Allowable Operating Pressure: Steel or
Plastic Pipelines
(a) No person may
operate a segment of steel or plastic pipeline at a pressure that exceeds a
maximum allowable operating pressure determined under paragraph (c) or (d) of
this section, or the lowest of the following:
(1) The design pressure of the weakest
element in the segment, determined in accordance with Subparts C and D of this
part. However, for steel pipe in pipelines being converted under § 192.14
or uprated under subpart K of this part, if any variable necessary to determine
the design pressure under the design formula (§ 192.105) is unknown, one
of the following pressures is to be used as design pressure:
(i) Eighty percent of the first test pressure
that produces yield under section N5 of Appendix N of ASME B31.8 (incorporated
by reference, see § 192.7), reduced by the appropriate factor in paragraph
(a)(2)(ii) of this section; or
(ii)
If the pipe is 12 3/4 in. (324 mm) or less in outside diameter and is not
tested to yield under this paragraph, 200 p.s.i. (1379 kPa).
(2) The pressure obtained by
dividing the pressure to which the segment was tested after construction as
follows:
(i) For plastic pipe in all
locations, the test pressure is divided by a factor of 1.5.
(ii) For steel pipe operated at 100 p.s.i.
(689 kPa) gage or more, the test pressure is divided by a factor determined in
accordance with the following table:
|
Class location
|
Factors Segment-
|
|
Installed before (Nov.12, 1970)
|
Installed after (Nov. 11, 1970)
|
Converted under § 192.14
|
|
1........
|
1.1
|
1.1
|
1.25
|
|
2........
|
1.25
|
1.25
|
1.25
|
|
3.........
|
1.4
|
1.5
|
1.5
|
|
4.........
|
1.4
|
1.5
|
1.5
|
(3) The highest actual operating pressure to
which the segment was subjected during the 5 years preceding the applicable
date in the second column. This pressure restriction applies unless the segment
was tested according to the requirements in paragraph (a)(2) of this section
after the applicable date in the third column or the segment was uprated
according to the requirements in subpart K of this part:
|
Pipeline segment
|
Pressure date
|
Test date
|
|
-Onshore gathering line that first became subject to
this part (other than § 192.612) after April 13, 2006.
-Onshore transmission line that was a gathering line
not subject to this part before March 15, 2006.
|
M arch 15, 2006, or date line becomes subject to this
part, whichever is later.
|
5 years preceding applicable date in second
column.
|
|
Offshore gathering lines....
|
July 1, 1976
|
July 1, 1971
|
|
All other pipelines.....
|
July 1, 1970
|
July 1, 1965
|
(4)
The pressure determined by the operator to be the maximum safe pressure after
considering the history of the segment, particularly known corrosion and the
actual operating pressure.
(b) No person may operate a segment to which
paragraph (a)(4) of this section is applicable, unless over-pressure protective
devices are installed on the segment in a manner that will prevent the maximum
allowable operating pressure from being exceeded, in accordance with §
192.195.
(c) The requirements on
pressure restrictions in this section do not apply in the following instance.
An operator may operate a segment of pipeline found to be in satisfactory
condition, considering its operating and maintenance history, at the highest
actual operating pressure to which the segment was subjected during the 5 years
preceding the applicable date in the second column of the table in paragraph
(a)(3) of this section. An operator must still comply with §
192.611.
(d) The operator of a
pipeline segment of steel pipeline meeting the conditions prescribed in §
192.620(b) may elect to operate the segment at a maximum allowable operating
pressure determined under § 192.620(a).
(e) The maximum allowable operating pressure
shall be designated following the above procedures and posted on system maps,
drawings, regulator stations or other appropriate records.
§ 192.620
Alternative Maximum
Allowable Operating Pressure for Certain Steel Pipelines.
(a)
How does an operator calculate
the alternative maximum allowable operating pressure? An operator
calculates the alternative maximum allowable operating pressure by using
different factors in the same formulas used for calculating maximum allowable
operating pressure under § 192.619(a) as follows:
(1) In determining the alternative design
pressure under § 192.105, use a design factor determined in accordance
with § 192.111(b), (c), or (d) or, if none of these paragraphs apply, in
accordance with the following table:
|
Class Location
|
Alternative Design Factor (F)
|
|
1
|
0.80
|
|
2
|
0.67
|
|
3
|
0.56
|
(i) For
facilities installed prior to December 22, 2008, for which § 192.111(b),
(c) or (d) applies, use the following design factors as alternatives for the
factors specified in those paragraphs: § 192.111(b) - 0.67 or less;
192.111(c) and (d) - 0.56 or less.
(ii) [Reserved]
(2) The alternative maximum allowable
operating pressure is the lower of the following:
(i) The design pressure of the weakest
element in the pipeline segment, determined under the subparts C and D of this
part.
(ii) The pressure obtained by
dividing the pressure to which the pipeline segment was tested after
construction by a factor determined in the following table:
|
Class Location
|
Alternative Test Factor
|
|
1
|
1.25
|
|
2
|
1.50
1
|
|
3
|
1.50
|
1 For Class 2 alternative maximum allowable operating
pressure segments installed prior to December 22, 2008, the alternative test
factor is 1.25.
(b)
When may an operator use the
alternative maximum allowable operating pressure calculated under paragraph (a)
of this section? An operator may use an alternative maximum allowable
operating pressure calculated under paragraph (a) of the section if the
following conditions are met:
(1) The
pipeline segment is in a class 1, 2, or 3 location:
(2) The pipeline segment is constructed of
steel pipe meeting the additional design requirements in §
192.112;
(3) A supervisory control
and data acquisition system provides remote monitoring and control of the
pipeline segment. The control provided must include monitoring of pressures and
flows, monitoring compressor start-ups and shut-downs, and remote closure of
valves per paragraph (d)(3) of this section;
(4) The pipeline segment meets the additional
construction requirements described in § 192.328;
(5) The pipeline segment does not contain any
mechanical couplings used in place of girth welds;
(6) If a pipeline segment has been previously
operated, the segment has not experienced any failure during normal operations
indicative of a systemic fault in material as determined by a root cause
analysis, including metallurgical examination of the failed pipe. The results
of this root cause analysis must be reported to each PHMSA pipeline safety
regional office where the pipeline is in service at least 60 days prior to
operation at the alternative MAOP. An operator must also notify a State
pipeline safety authority when the pipeline is located in a State where PHMSA
has an interstate agent agreement, or an intrastate pipeline is regulated by
that State; and
(7) At least 95
percent of girth welds on a segment that was constructed prior to December 22,
2008, must have been non-destructively examined in accordance with §
192.243(b) and (c).
(c)
What is an operator electing to use the alternative maximum allowable
operating pressure required to do? If an operator elects to use the
alternative maximum allowable operating pressure calculated under paragraph (a)
of this section for a pipeline segment, the operator must do each of the
following:
(1) Notify each PHMSA pipeline
safety regional office where the pipeline is in service of its election with
respect to a segment at least 180 days before operating at the alternative
maximum allowable operating pressure. An operator must also notify a State
pipeline safety authority when the pipeline is located in a State where PHMSA
has an intrastate agent agreement, or an intrastate pipeline is regulated by
that State.
(2) Certify, by
signature of a senior executive officer of the company, as follows:
(i) The pipeline segment meets the conditions
described in paragraph (b) of this section; and
(ii) The operating and maintenance procedures
include the additional operating and maintenance requirements of paragraph (d)
of this section; and
(iii) The
review and any needed program upgrade of the damage prevention program required
by paragraph (d)(4)(v) of this section has been completed.
(3) Send a copy of the certification required
by paragraph (c)(2) of this section to each PHMSA pipeline safety regional
office where the pipeline is in service 30 days prior to operating at the
alternative MAOP. An operator must also send a copy to a State pipeline safety
authority when the pipeline is located in a State where PHMSA has an interstate
agent agreement, or an intrastate pipeline is regulated by that
State.
(4) For each pipeline
segment, do one of the following:
(i) Perform
a strength test as described in in § 192.505 at a test pressure calculated
under paragraph (a) of this section or
(ii) For a pipeline segment in existence
prior to December 22, 2008, certify, under paragraph (c)(2) of this section,
that the strength test performed under § 192.505 was conducted at test
pressure calculated under paragraph (a) of this section, or conduct a new
strength test in accordance with paragraph (c)(4)(i) of this section.
(5) Comply with the additional
operation and maintenance requirements described in paragraph (d) of this
section.
(6) If the performance of
a construction task associated with implementing alternative MAOP that occurs
after December 22, 2008, can affect the integrity of the pipeline segment,
treat that task as a "covered task", notwithstanding the definition in §
192.801(b) and implement the requirements of subpart N as
appropriate.
(7) Maintain, for the
useful life of the pipeline, records demonstrating compliance with paragraphs
(b), (c)(6), and (d) of this section.
(8) A Class 1 and Class 2 pipeline location
can be upgraded one class due to class changes per § 192.611(a)(3)(i). All
class location changes from Class 1 to Class 2 and from Class 2 to Class 3 must
have all anomalies evaluated and remediated per: The "original pipeline class
grade" § 192.620(d)(11) anomaly repair requirements; and all anomalies
with a wall loss equal to or greater than 40 percent must be excavated and
remediated. Pipelines in Class 4 may not operate at an alternative
MAOP.
(d)
What
additional operation and maintenance requirements apply to operation at the
alternative maximum allowable operating pressure? In addition to
compliance with other applicable safety standards in this part, if an operator
establishes a maximum allowable operating pressure for a pipeline segment under
paragraph (a) of this section, an operator must comply with the additional
operation and maintenance requirements as follows:
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To address increased risk of a maximum allowable
operating pressure based on higher stress levels in the following areas:
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Take the following additional step:
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(1) Identifying and evaluating threats.
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Develop a threat matrix consistent with § 192.917
to do the following:
(i) Identify and compare the increased risk of
operating the pipeline at the increased stress level under this section with
conventional operation; and
(ii) Describe and implement procedures used to mitigate
the risk.
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(2) Notifying the public.
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(i) Recalculate the potential impact circle as defined
in § 192.903 to reflect use of the alternative maximum operating pressure
calculated under paragraph (a) of this section and pipeline operating
conditions; and
(ii) In implementing the public education program
required under § 192.616, perform the following:
(A) Include persons occupying property within 220 yards
of the centerline and within the potential impact circle within the targeted
audience; and
(B) Include information about the integrity management
activities performed under this section within the message provided to the
audience.
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(3) Responding to an emergency in an area defined as a
high consequence are in § 192.903.
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(i) Ensure that the identification of high consequence
areas reflects the larger potential impact circle recalculated under paragraph
(d)(2)(i) of this section.
(ii) If personnel response time to mainline valves on
either side of the high consequence area exceeds one hour (under normal driving
conditions and speed limits) from the time the event is identified in the
control room, provide remote valve control through a supervisory control and
data acquisition (SCADA) system, other leak detection system, or an alternate
method of control.
(iii) Remote valve control must include the ability to
close and monitor the valve position (open or closed), and monitor pressure
upstream and downstream.
(iv) A line break valve control system using
differential pressure, rate of pressure drop or other widely-accepted method is
an acceptable alternative to remove valve control.
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(4) Protecting the right-of-way.
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(i) Patrol the right-of-way at intervals not exceeding
45 days, but at least 12 times each calendar year, to inspect for excavation
activities, ground movement, wash outs, leakage, or other activities or
conditions affecting the safety operation of the pipeline.
(ii) Develop and implement a plan to monitor for and
mitigate occurrences of unstable soil and ground movement.
(iii) If observed conditions indicate the possible loss
of cover, perform a depth of cover study and replace cover as necessary to
restore the depth of cover or apply alternative means to provide protection
equivalent to the originally-required depth of cover.
(iv) Use line-of-sight line markers satisfying the
requirements of § 192.707(d) except in agricultural areas, large water
crossings or swamp, steep terrain, or where prohibited by Federal Energy
Regulatory Commission orders, permits, or local law.
(v) Review the damage prevention program under §
192.614(a) in light of national consensus practices, to ensure the program
provides adequate protection of the right-of-way. Identify the standards or
practices considered in the review, and meet or exceed those standards or
practices by incorporating appropriate changes into the program.
(vi) Develop and implement a right-of-way management
plan to protect the pipeline segment from damage due to excavation
activities.
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(5) Controlling internal corrosion.
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(i) Develop and implement a program to monitor for and
mitigate the presence of, deleterious gas stream constituents.
(ii) At points where gas with potentially deleterious
contaminants enters the pipeline, use filter separators or separators and gas
quality monitoring equipment.
(iii) Use gas quality monitoring equipment that
includes a moisture analyzer, chromatograph, and periodic hydrogen sulfide
sampling.
(iv) Use cleaning pigs and sample accumulated liquids.
Use inhibitors when corrosive gas or liquids are present.
(v) Address deleterious gas stream constituents as
follows:
(A) Limit carbon dioxide to 3 percent by volume;
(B) Allow no free water and otherwise limit water to
seven pounds per million cubic feet of gas; and
(C) Limit hydrogen sulfide to 1.0 grain per hundred
cubic feet (16 ppm) of gas, where the hydrogen sulfide is greater than 0.5
grain per hundred cubic feet (8 ppm) of gas, implement a pigging and inhibitor
injection program to address deleterious gas stream constituents, including
follow-up sampling and quality testing of liquids at receipt points.
(vi) Review the program at least quarterly based on the
gas stream experience and implement adjustments to monitor for, and mitigate
the presence of, deleterious gas stream constituents.
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(6) Controlling interference that can impact external
corrosion.
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(i) Prior to operating an existing pipeline segment at
an alternate maximum allowable operating pressure calculated under this
section, or within six months after placing a new pipeline segment in service
at an alternate maximum allowable operating pressure calculated under this
section, address any interference currents on the pipeline section.
(ii) To address interference currents, perform the
following:
(A) Conduct an interference survey to detect the
presence and level of any electrical current that could impact external
corrosion where interference is suspected;
(B) Analyze the results of the survey; and
(C) Take any remedial action needed within 6 months
after completing the survey to protect the pipeline segment from deleterious
current.
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(7) Confirming external corrosion control through
indirect assessment.
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(i) Within six months after placing the cathodic
protection of a new pipeline segment in operation, or within six months after
certifying a segment under § 192.620(c)(1) of an existing pipeline segment
under this section, assess the adequacy of the cathodic protection through an
indirect method such as close-interval survey, and the integrity of the coating
using direct current voltage gradient (DCVG) or alternating current voltage
gradient (ACVG).
(ii) Remediate any construction damaged coating with a
voltage drop classified as moderate or severe (IR drop greater than 35% for
DCVG or 50 dBµv for ACVG) under section 4 of NACE RP-0502-2002
(incorporated by reference, see § 192.7).
(iii) Within six months after completing the baseline
internal inspection required under paragraph (d)(9) of this section, integrate
the results of the indirect assessment required under paragraph (d)(7)(i) of
this section with the results of the baseline internal inspection and take any
needed remedial actions.
(iv) For all pipeline segments in high consequence
areas, perform periodic assessments as follows:
(A) Conduct periodic close interval surveys with
current interrupted to confirm voltage drops in association with periodic
assessments under subpart O of this part.
(B) Locate pipe-to-soil test stations at half-mile
intervals within each high consequence area ensuring at least one station is
within each high consequence area, if practicable.
(C) Integrate the results with those of the baseline
and periodic assessments for integrity done under paragraphs (d)(9) and (d)(10)
of this section.
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(8) Controlling external corrosion through cathodic
protection.
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(i) If an annual test station reading indicates
cathodic protection below the level of protection required in subpart I of this
part, complete remedial action within six months of the failed reading or
notify each PHMSA pipeline safety regional office where the pipeline is in
service demonstrating that the integrity of the pipeline is not compromised if
the repair takes longer than 6 months. An operator must also notify the State
pipeline safety authority when the pipeline is located in a State where PHMSA
has an interstate agent agreement, or an intrastate pipeline is regulated by
that State; and
(ii) After remedial action to address a failed reading,
confirm restoration of adequate corrosion control by a close interval survey on
either side of the affected test station to the next test station unless the
reason for the failed reading is determined to be a rectifier connection or
power input problem that can be remediated and otherwise verified.
(iii) If the pipeline segment has been in operation,
the cathodic protection system on the pipeline segment must have been
operational within 12 months of the completion of construction.
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(9) Conducting a baseline assessment of
integrity.
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(i) Except as provided in paragraph (d)(9)(iii) of this
section, for a new pipeline segment operating at the new alternative maximum
allowable operating pressure, perform a baseline internal inspection of the
entire pipeline segment as follows:
(A) Assess using a geometry tool after the initial
hydrostatic test and backfill and within six months after placing the new
pipeline segment in service; and
(B) Assess using a high resolution magnetic flux tool
within three years after placing the new pipeline segment in service at the
alternative maximum allowable operating pressure.
(ii) Except as provided in paragraph (d)(9)(iii) of
this section, for an existing pipeline segment, perform a baseline internal
assessment using a geometry tool and a high resolution magnetic flux tool
before, but within two years prior to, raising pressure to the alternative
maximum allowable operating pressure as allowed under this section.
(iii) If headers, mainline valve by-passes, compressor
station piping, meter station piping, or other short portion of a pipeline
segment operating at alternative maximum allowable operating pressure cannot
accommodate a a geometry tool and a high resolution magnetic flux tool, use
direct assessment (per § 192.925, § 192.927 and/or § 192.929) or
pressure testing (per subpart J of this part) to assess that portion.
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(10) Conducting periodic assessments of
integrity.
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(i) Determine a frequency for subsequent periodic
integrity assessments as if all the alternative maximum allowable operating
pressure pipeline segments were covered by subpart O of this part; and
(ii) Conduct periodic internal inspections using a high
resolution magnetic flux tool on the frequency determined under paragraph
(d)(10)(i) of this section, or
(iii) Use direct assessment (per § 192.925, §
192.927 and/or § 192.929) or pressure testing (per subpart J of this part)
for periodic assessment of a portion of a segment to the extent permitted for a
baseline assessment under paragraph (d)(9)(iii) of this section.
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(11) Making repairs.
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(i) Perform the following when evaluating an
anomaly:
(A) Use the most conservative calculation for
determining remaining strength or an alternative validated calculation based on
pipe diameter, wall thickness, grade, operating pressure, operating stress
level, and operating temperature: and
(B) Take into account the tolerance of the tools used
in the inspection.
(ii) Repair a defect immediately if any of the
following apply:
(A) The defect is a dent discovered during the baseline
assessment for integrity under paragraph (d)(9) of this section and the defect
meets the criteria for immediate repair in §192.309(b)
(B) The defect meets the criteria for immediate repair
in § 192.933(d).
(C) The alternative maximum allowable operating
pressure was based on a design factor of 0.67 under paragraph (a) of this
section and the failure pressure is less than 1.25 times the alternative
maximum allowable operating pressure.
(D) The alternative maximum allowable operating
pressure was based on a design factor of 0.56 under paragraph (a) of this
section and the failure pressure is less than 1.4 times the alternative maximum
allowable operating pressure.
(iii) If paragraph (d)(11)(ii) of this section does not
require immediate repair, repair a defect within one year if any of the
following apply:
(A) The defect meets the criteria for repair within one
year in § 192.933(d).
(B) The alternative maximum allowable operating
pressure was based on a design factor of 0.80 under paragraph (a) of this
section and the failure pressure is less than 1.25 times the alternative
maximum allowable operating pressure.
(C) The alternative maximum allowable operating
pressure was based on a design factor of 0.67 under paragraph (a) of this
section and the failure pressure is less than 1.50 times the alternative
maximum allowable operating pressure.
(D) The alternative maximum allowable operating
pressure was based on a design factor of 0.56 under paragraph (a) of this
section and the failure pressure is less than or equal to 1.80 times the
alternative maximum allowable operating pressure.
(iv) Evaluate any defect not required to be repaired
under paragraph (d)(11)(ii) or (iii) of this section to determine its growth
rate, set the maximum interval for repair or re-inspection, and repair or
re-inspect within that interval.
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(e)
Is there any change in overpressure protection associated with
operating at the alternative maximum allowable operating pressure?
Notwithstanding the required capacity of pressure relieving and limiting
stations otherwise required by § 192.201, if an operator establishes a
maximum allowable operating pressure for a pipeline segment in accordance with
paragraph (a) of this section, an operator must:
(1) Provide overpressure protection that
limits mainline pressure to a maximum of 104 percent of the maximum allowable
operating pressure; and
(2) Develop
and follow a procedure for establishing and maintaining accurate set points for
the supervisory control and data acquisition system.
§ 192.621
Maximum
Allowable Operating Pressure: High-Pressure Distribution Systems.
(a) No person may operate a segment of a high
pressure distribution system at a pressure that exceeds the lowest of the
following pressures, as applicable:
(1) The
design pressure of the weakest element in the segment, determined in accordance
with Subparts C and D of this part.
(2) 60 p.s.i. (414 kPa) gage for a segment of
a distribution system otherwise designed to operate at over 60 p.s.i. (414 kPa)
gage, unless the service lines in the segment are equipped with service
regulators or other pressure limiting devices in series that meet the
requirements of § 192.197(c).
(3) 25 p.s.i. (172 kPa) gage in segments of
cast iron pipe in which there are unreinforced bell and spigot
joints.
(4) The pressure limits to
which a joint could be subjected without the possibility of its
parting.
(5) The pressure
determined by the operator to be the maximum safe pressure after considering
the history of the segment, particularly known corrosion and the actual
operating pressures.
(b)
No person may operate a segment of pipeline to which paragraph (a)(5) of this
section applies, unless overpressure protective devices are installed on the
segment in a manner that will prevent the maximum allowable operating pressure
from being exceeded, in accordance with § 192.195.
(c) The maximum allowable operating pressure
shall be designated following the above procedures and posted on system maps,
drawings, regulator stations or other appropriate records.
§ 192.622
Maximum Actual
Operating Pressure: High-Pressure Distribution Systems.
(a) Each operator shall establish a maximum
actual operating pressure if the actual operating pressure is less than the
established maximum allowable operating pressure. The maximum actual operating
pressure will be the pressure for orifice sizing in customer regulators as
required by § 192.197. The maximum actual operating pressure may be
increased to a pressure not exceeding the maximum allowable operating pressure
during emergency operating conditions. Normal seasonal gas demands are not
considered emergency operating conditions. Upon termination of the emergency
the pressure must be reduced to a pressure not exceeding the established
maximum actual operating pressure. The maximum actual operating pressure shall
be posted on system maps, drawings, regulator stations or other appropriate
records.
(b) Before increasing the
established maximum actual operating pressure, under normal conditions, the
operator shall:
(1) Calculate the rated
capability of each overpressure control device installed at each customer's
service.
(2) If the overpressure
control device is not capable of maintaining a safe pressure to the customer's
gas utilization equipment, a new or additional device must be installed to
provide a safe pressure to the customer.
§ 192.623
Maximum and Minimum
Allowable Operating Pressure: Low-Pressure Distribution Systems.
(a) No person may operate a low-pressure
distribution system at a pressure high enough to make unsafe the operation of
any connected and properly adjusted low-pressure gas burning
equipment.
(b) No person may
operate a low-pressure distribution system at a pressure lower than the minimum
pressure at which the safe and continuing operation of any connected and
properly adjusted low-pressure gas burning equipment can be assured.
(c) The maximum allowable operating pressure
shall be designated following the above procedures and posted on system maps,
drawings, regulator stations or other appropriate records.
§ 192.625
Odorization of
Gas.
(a) A combustible gas in a
distribution line must contain a natural odorant or be odorized so that at a
concentration in air of one-fifth of the lower explosive limit, the gas is
readily detectable by a person with a normal sense of smell.
(b) After December 31, 1976, a combustible
gas in a transmission line in a Class 3 or Class 4 location must comply with
the requirements of paragraph (a) of this section unless:
(1) At least 50 percent of the length of the
line downstream from that location is in a Class 1 or Class 2
location;
(2) The line transports
gas to any of the following facilities which received gas without an odorant
from that line before May 5, 1975;
(i) An
underground storage field;
(ii) A
gas processing plant;
(iii) A gas
dehydration plant; or
(iv) An
industrial plant using gas in a process where the presence of an odorant:
(A) Makes the end product unfit for the
purpose for which it is intended;
(B) Reduces the activity of a catalyst;
or
(C) Reduces the percentage
completion of a chemical reaction;
(3) In the case of a lateral line which
transports gas to a distribution center, at least 50 percent of the length of
that line is in a Class 1 or Class 2 location; or
(4) The combustible gas is hydrogen intended
for use as a feedstock in a manufacturing process.
(c) In the concentrations in which it is
used, the odorant in combustible gases must comply with the following:
(1) The odorant must not be harmful to
persons, materials, or pipes; and
(2) The products of combustion from the
odorant may not be toxic when breathed nor may they be corrosive or harmful to
those materials to which the products of combustion will be exposed.
(d) The odorant may not be soluble
in water to an extent greater than 2.5 parts to 100 parts by weight.
(e) Equipment for odorization must introduce
the odorant without wide variations in the level of odorant.
(f) To assure the proper concentration of
odorant in accordance with this section, each operator must conduct periodic
sampling of combustible gases using an instrument capable of determining the
percentage of gas in air at which the odor becomes readily
detectable.
(g) Each operator shall
conduct an odorant concentration test by performing a room odorant test or
measuring with an instrument designed for this purpose. Systems odorized by
centrally located equipment and designed to provide properly odorized gas to a
large number of customers, shall have test points at key locations where
odorant concentration tests shall be taken. These test points shall be
designated in such a manner to allow sampling of gas at the furthest points
from the odorizer(s). These tests shall be conducted at intervals not exceeding
3 months and recorded. As a minimum, records of the most current and previous
test shall be maintained by the operator.
(h) Individual taps from unodorized
facilities shall be provided with odorization equipment of proper size and
serviced frequently enough to ensure an ample supply at all times. Odorant
concentration test of this type facility shall be conducted each six months by
an acceptable method. Odorant test records of the most current and previous
test of each customer shall be maintained by the operator.
§ 192.627
Tapping Pipelines Under
Pressure.
Each tap made on a pipeline under pressure must be performed by
a crew qualified to make hot taps.
§ 192.629
Purging of
Pipelines.
(a) When a pipeline is
being purged of air by use of gas, the gas must be released into one end of the
line in a moderately rapid and continuous flow. If gas cannot be supplied in
sufficient quantity to prevent the formation of a hazardous mixture of gas and
air, a slug of inert gas must be released into the line before the
gas.
(b) When a pipeline is being
purged of gas by use of air, the air must be released into one end of the line
in a moderately rapid and continuous flow. If air cannot be supplied in
sufficient quantity to prevent the formation of a hazardous mixture of gas and
air, a slug of inert gas must be released into the line before the
air.
(c) When a low pressure gas
system is being purged of water by natural gas, the allowable operating
pressure may not be exceeded. If the pressure required to purge the water
exceeds the established maximum allowable operating pressure, air will be used
to purge the system.
§
192.631
Control Room Management
(a)
General
(1) This section applies to each 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 section, except that for each control room
where an operator's activities are limited to either or both of:
(i) Distribution with less than 250,000
services, or
(ii) Transmission
without a compressor station, the operator must have and follow written
procedures that implement only paragraphs (d) (regarding fatigue), (i)
(regarding compliance validation), and (j) (regarding compliance and
deviations) of this section.
(2) The procedures required by this section
must be integrated, as appropriate, with operating and emergency procedures
required by §§ 192.605 and 192.615. 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 paragraphs (b),
(c)(5), (d)(2) and (d)(3), (f) and (g) of this section must be implemented no
later than October 1, 2011. The procedures required by paragraphs (c)(1)
through (4), (d)(1), (d)(4), and (e) must be implemented no later than August
1, 2012. The training procedures required by paragraph (h) must be implemented
no later than August 1, 2012, except that any training required by another
paragraph of this section must be implemented no later than the deadline for
that paragraph.
(b)
Roles and responsibilities. Each operator 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:
(1) A controller's authority
and responsibility to make decisions and take actions during normal
operations;
(2) A controller's role
when an abnormal 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;
(3) A controller's role during an emergency,
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; and
(4) A method of
recording controller shift-changes and any hand-over of responsibility between
controllers.
(c)
Provide adequate information. Each 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:
(1) Implement sections 1, 4, 8, 9, 11.1, and
11.3 of API RP 1165 (incorporated by reference, see § 192.7) 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;
(2) Conduct a point-to-point verification
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;
(3) Test and verify an internal communication
plan to provide adequate means for manual operation of the pipeline safely, at
least once each calendar year, but at intervals not to exceed 15
months;
(4) Test any backup SCADA
systems at least once each calendar year, but at intervals not to exceed 15
months; and
(5) Establish and
implement procedures for when a different controller assumes responsibility,
including the content of information to be exchanged.
(d)
Fatigue mitigation. Each
operator 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;
(1) Establish shift lengths and schedule
rotations that provide controllers off-duty time sufficient to achieve eight
hours of continuous sleep;
(2)
Educate controllers and supervisors in fatigue mitigation strategies and how
off-duty activities contribute to fatigue.
(3) Train controllers and supervisors to
recognize the effects of fatigue; and
(4) Establish a maximum limit on 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.
(e)
Alarm
management. Each operator 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:
(1) Review SCADA safety-related alarm
operations using a process that ensures alarms are accurate and support safe
pipeline operations.
(2) Identify
at least once each calendar 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;
(3) Verify the correct safety-related alarm
set-point values and alarm descriptions at least once each calendar year, but
at intervals not to exceed 15 months;
(4) Review the alarm management plan required
by this paragraph at least once each calendar year, but at intervals not
exceeding 15 months, to determine the effectiveness of the plan;
(5) Monitor the content and volume of general
activity being directed to and required of each controller at least once each
calendar year, but at intervals not to exceed 15 months, that will assure
controllers have sufficient time to analyze and react to incoming alarms;
and
(6) Address deficiencies
identified through the implementation of paragraphs (e)(1) through (e)(5) of
this section.
(f)
Change management. Each operator must assure that changes that
could affect control room operations are coordinated with the control room
personnel by performing each of the following:
(1) Establish communications between control
room representatives, operator's management, and associated field personnel
when planning and implementing physical changes to pipeline equipment or
configuration;
(2) Require its
field personnel to contact the control room when emergency conditions exist and
when making field changes that affect control room operations; and
(3) Seek control room or control room
management participation in planning prior to implementation of significant
pipeline hydraulic or configurations changes.
(g)
Operating experience.
Each operator 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:
(1)
Review incidents that must be reported pursuant to 49 CFR part 191 to determine
if control room actions contributed to the event and, if so, correct, where
necessary, deficiencies related to:
(i)
Controller fatigue;
(ii) Field
equipment;
(iii) The operation of
any relief device;
(iv)
Procedures;
(v) SCADA system
configuration; and
(vi) SCADA
system performance.
(2)
Include lessons learned from the operator's experience in the training program
required by this section.
(h)
Training. Each operator
must establish 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 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:
(1) Responding to
abnormal operating conditions likely to occur simultaneously or in
sequence;
(2) Use of a computerized
simulator of non-computerized (tabletop) method for training controllers to
recognize abnormal operating conditions;
(3) Training controllers on their
responsibilities for communication under the operator's emergency response
procedures;
(4) Training that will
provide a controller a working knowledge of the pipeline system, especially
during the development of abnormal operating conditions; and
(5) For pipeline operating setups that are
periodically, but infrequently used, providing an opportunity for controllers
to review relevant procedures in advance of their application.
(i)
Compliance
validation. Upon request, operators must submit their procedures to
PHMSA or, in the case of an intrastate pipeline facility regulated by a State,
to the appropriate State agency.
(j)
Compliance and
deviation. An operator must maintain for review during inspection:
(1) Records that demonstrate compliance with
the requirements of this section; and
(2) Documentation to demonstrate that any
deviation from the procedures required by this section was necessary for the
safe operation of a pipeline facility.
SUBPART M
-MAINTENANCE
§ 192.701
Scope.
This subpart prescribes minimum requirements for maintenance of
pipeline facilities.
§
192.703
General.
(a) No person may operate a segment of
pipeline, unless it is maintained in accordance with this subpart.
(b) Each segment of pipeline that becomes
unsafe must be replaced, repaired, or removed from service.
(c) Hazardous leaks must be repaired
promptly.
§ 192.705
Transmission Lines: Patrolling.
(a) Each operator shall have a patrol program
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.
(b)
The frequency of patrols is determined by the size of the line, the operating
pressure, 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 location of line
|
At highway and railroad crossings
|
At all other places
|
|
1, 2.......
|
7 1/2 months, but at least twice each .ca..lendar
year.
|
15 months, but at least once each calendar year.
|
|
3........
|
4 1/2 months, but at least four times .e.a. ch calendar
year.
|
7 1/2 months, but at least twice each calendar
year.
|
|
4........
|
4 1/2 months, but at least four times .e.a. ch calendar
year.
|
4 1/2 months, but at least four times each calendar
year.
|
(c)
Methods of patrolling include walking, driving, flying or other appropriate
means of traversing the right-of-way.
§ 192.706
Transmission Lines:
Leakage Surveys.
Leakage surveys of a transmission line must be conducted at
intervals not exceeding 15 months, but at least once each calendar year.
However, in the case of a transmission line which transports gas in conformity
with § 192.625 without an odor or odorant, leakage surveys using leak
detector equipment must be conducted:
(a) In Class 3 locations, at intervals not
exceeding 7 1/2 months, but at least twice each calendar year; and
(b) In Class 4 locations, at intervals not
exceeding 4 1/2 months, but at least four times each calendar year.
§ 192.707
Line Markers
for Mains and Transmission Lines.
(a)
Buried pipelines. Except as provided in paragraph (b) of this
section, a line marker must be placed and maintained as close as practical over
each buried main and transmission line:
(1)
At each crossing of a public road and railroad; and
(2) Wherever necessary to identify the
location of the transmission line or main to reduce the possibility of damage
or interference. When a pipeline crosses a divided roadway, a marker shall be
placed on each side of the roadway.
(b)
Exceptions for buried
pipelines. Line markers are not required for the following pipelines:
(1) Mains and transmission lines located at
crossings of or under waterways and other bodies of water.
(2) Mains in Class 3 or Class 4 locations
where a damage prevention program is in effect under § 192.614:
(3) Transmission lines in Class 3 or 4
locations where placement of a line marker is impractical.
(c)
Pipelines above ground.
Line markers must be placed and maintained along each section of a main and
transmission line that is located above-ground in an area accessible to the
public.
(d)
Marker
warning. The following must be written legibly on a background of
sharply contrasting color on each line marker:
(1) The word "Warning", "Caution", or
"Danger", followed by the words "Gas Pipeline" all of which, except for markers
in heavily developed urban areas, must be in letters at least one inch (25
millimeters) high with one-quarter inch (6.4 millimeters) stroke.
(2) The name of the operator and the
telephone number (including area code) where the operator can be reached at all
times.
§
192.709
Transmission Lines: Record-Keeping.
Each operator shall maintain the following records for
transmission lines for the periods specified:
(a) The date, location, and description of
each repair made to pipe (including pipe-to-pipe connections) must be retained
for as long as the pipe remains in service.
(b) The date, location, and description of
each repair made to parts of the pipeline system other than pipe must be
retained for at least 5 years. However, repairs generated by patrols, surveys,
inspections, or tests required by subparts L and M of this part must be
retained in accordance with paragraph (c) of this section.
(c) A record of each patrol, survey,
inspection, and test required by subparts L and M of this part must be retained
for at least 5 years or until the next patrol, survey, inspection, or test is
completed, whichever is longer.
§ 192.711
Transmission Lines:
General Requirements for Repair Procedures.
(a)
Temporary repairs. Each
operator must take immediate temporary measures to protect the public whenever:
(1) A leak, imperfection, or damage that
impairs its serviceability is found in a segment of steel transmission line
operating at or above 40 percent of the SMYS; and
(2) It is not feasible to make a permanent
repair at the time of discovery.
(b)
Permanent repairs. An
operator must make permanent repairs on its pipeline system according to the
following:
(1) Non integrity management
repairs: The operator must make permanent repairs as soon as
feasible.
(2) Integrity management
repairs: When an operator discovers a condition on a pipeline covered under
Subpart O - Gas Transmission Pipeline Integrity Management, the operator must
remediate the condition as prescribed by § 192.933(d).
(c)
Welded Patch.
Except as provided in § 192.717(b)(3), no operator may use a welded patch
as a means of repair.
§
192.713
Transmission Lines: Permanent Field Repair of
Imperfections and Damages.
(a) Each
imperfection or damage that impairs the serviceability of pipe in a steel
transmission line operating at or above 40 percent of SMYS must be--
(1) Removed by cutting out and replacing a
cylindrical piece of pipe; or
(2)
Repaired by a method that reliable engineering tests and analyses show can
permanently restore the serviceability of the pipe.
(b) Operating pressure must be at a safe
level during repair operations.
§ 192.715
Transmission Lines:
Permanent Field Repair of Welds.
Each weld that is unacceptable under § 192.241(c) must be
repaired as follows:
(a) If it is
feasible to take the segment of transmission line out of service, the weld must
be repaired in accordance with the applicable requirements of §
192.245.
(b) A weld may be repaired
in accordance with § 192.245 while the segment of transmission line is in
service if:
(1) The weld is not
leaking;
(2) The pressure in the
segment is reduced so that it does not produce a stress that is more than 20
percent of the SMYS of the pipe; and
(3) Grinding of the defective area can be
limited so that at least 1/8 inch (3.2 millimeters) thickness in the pipe weld
remains.
(c) A defective
weld which cannot be repaired in accordance with paragraph (a) or (b) of this
section must be repaired by installing a full encirclement welded split sleeve
of appropriate design.
§
192.717
Transmission Lines: Permanent Field Repair of
Leaks.
Each permanent field repair of a leak on a transmission line
must be made by-
(a) Removing the leak
by cutting out and replacing a cylindrical piece of pipe; or
(b) Repairing the leak by one of the
following methods:
(1) Install a full
encirclement welded split sleeve of appropriate design, unless the transmission
line is joined by mechanical couplings and operates at less than 40 percent of
SMYS.
(2) If the leak is due to a
corrosion pit, install a properly designed bolt-on-leak clamp.
(3) If the leak is due to a corrosion pit and
on pipe of not more than 40,000 p.s.i. (267 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 of the diameter of the pipe
in size.
(4) If the leak is on a
submerged offshore pipeline or submerged pipeline in inland navigable waters,
mechanically apply a full encirclement split sleeve of appropriate
design.
(5) Apply a method that
reliable engineering tests and analyses show can permanently restore the
serviceability of the pipe.
§ 192.719
Transmission Lines:
Testing of Repairs.(a) Testing of
replacement pipe. If a segment 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.
(b) Testing of repairs made by welding. Each
repair made by welding in accordance with §§ 192.713, 192.715, and
192.717 must be examined in accordance with § 192.241.
§ 192.721
Distribution
Systems: Patrolling.(a) The frequency
of patrolling mains must be determined by the severity of the conditions which
could cause failure or leakage, and the consequent hazards to public
safety.
(b) Mains in places or on
structures where anticipated physical movement or external loading could cause
failure or leakage must be patrolled -
(1) In
business districts, at intervals not exceeding 4 1/2 months, but at least 4
times each calendar year; and
(2)
Outside business districts, at intervals not exceeding 7 1/2 months, but at
least twice each calendar year.
§ 192.723
Distribution Systems:
Leakage Surveys and Procedures.(a)
Each operator of a distribution system shall conduct periodic leakage surveys
in accordance with this section. These surveys must be performed by, or under
the direct supervision of, personnel trained and qualified in both the use of
appropriate equipment and the classification of leaks. In addition, maps that
approximate the location of the mains and transmission lines being surveyed
must be available.
(b) The type and
scope of the leakage control program must be determined by the nature of the
operations and the local conditions, but it must meet the following minimum
requirements.
(1) A leakage survey with leak
detector equipment shall be conducted in business districts including test of
the atmosphere in electric, gas, sewer, telephone, and water system manholes,
at cracks in pavement and sidewalks and at other locations providing an
opportunity for finding gas leaks. This survey shall be performed with a flame
ionization unit or a gas detector at intervals not exceeding 15 months, but at
least once each calendar year.
(2)
A leakage survey with leak detector equipment must be conducted outside
business districts as frequently as necessary, but at intervals not exceeding 5
calendar years not exceeding 63 months. However, for cathodically unprotected
distribution lines subject to §192.465(e) on which electrical surveys for
corrosion are impractical, a leakage survey must be conducted at least once
every 3 calendar years at intervals not exceeding 39 months.
(i) A leakage survey of all underground
natural gas distribution systems outside of a business district, that are
owned/operated or the responsibility of a public or municipal utility shall be
performed as frequently as necessary but at intervals not exceeding five (5)
calendar years.
(ii) A leakage
survey of all underground natural gas distribution systems, not owned nor the
responsibility of a public or municipal utility and used to transport gas from
a master meter or utility company gas main to multiple buildings, shall be
performed as frequently as necessary but at intervals not exceeding five (5)
years. Owners/operators of these systems shall be responsible to ensure these
surveys are accomplished.
(c) The type and scope of the surveys
required in (i) and (ii) above, must ensure detection, location, evaluation and
classification of any gas leakage. The following methods may be employed
depending on the design and size of the system or facility:
(1) Flame Ionization Detector.
(2) Combustible Gas Indicator (includes bar
holing).
(3) Pressure Drop or No
Flow. Only to be used to establish the presence or absence of leakage on a
distribution system. Where leakage is indicated, further evaluation by another
detection method must be accomplished to locate, evaluate and classify leaks.
When this method is used to verify no leakage exists a test record certified by
a qualified person, organization or agency, must be retained with records of
survey.
NOTE: Test duration must be of sufficient length to
detect leakage, and the following should be considered:
Volume under test and the time for the test medium to become
temperature stabilized.
(d) All leaks detected shall be classified to
assure a standardized priority of repair is established. There is no precise
means presently developed to accurately classify leaks, however, there are four
general categories that must be considered when judging the severity of gas
leaks:
(1) Proportion. The quantity of gas
escaping based on gas indicator readings, pressure of line or container from
which gas is escaping and concentration of odor.
(2) Location. The centralized location of
escaping gas; under buildings and paved surfaces, near occupied buildings, near
source of ignition or in open areas where the concentration of gas is
improbable.
(3) Dispersion. The
areas to which escaping gas may spread. Based on depth of line, type of soil,
pressure, surface cover, moisture, frozen soil and other soil
conditions.
(4) Evaluation. All
factors must be evaluated, applying experience and good judgement in arriving
at the proper classification.
(e) To standardize leak classification, using
the above factors, all leaks shall be classified in the following categories:
(1) Class 1. Leaks that represent an existing
or probable hazard to persons or property and requires immediate repair or
continuous action until the hazardous condition no longer exists.
(2) Class 2. Leaks that are considered
non-hazardous at the time of detection, but could become hazardous if repair is
not accomplished in a reasonable length of time. Repair as soon as possible,
but within a period not to exceed five months.
(3) Class 3. Leaks that are non-hazardous at
the time of detection and can be expected to remain non-hazardous. These leaks
should be re-evaluated during the next scheduled survey. Repair as time and
expenditures permit.
(f)
In addition to leak surveys, any leak or gas odor reported from the public,
fire, police or other authorities or notification of damage to facilities by
outside sources shall require prompt investigation. Thorough investigations
shall be performed on all suspected leaks to determine the degree of existing
hazard to person or property. This includes entering structures in a reported
or suspected leakage area and checking for presence of gas.
(1) Leaks reported on customer's piping shall
be investigated by trained and qualified employees who must judge the degree of
hazard and establish the required repair priority. If a hazardous leak exists
on customer's piping, the service shall be immediately terminated upstream of
the leak. If the leak is not presently hazardous but may become hazardous, the
customer shall be given a reasonable time to repair the leak.
(g) A leak repair record shall be
made for every leak detected or identified. Leaks discovered on customer's
piping, downstream of the meter, shall be documented on operator's service
orders and retained until the customer's piping has been repaired to the
satisfaction of the operator. Corrosion leaks shall be documented on permanent
records and shall be retained for as long as the segment of pipeline on which
the leak was located is in service. As a minimum, leak records other than
corrosion shall be maintained on the two most current leak surveys. Each leak
record shall contain, as a minimum, the following:
(1) Date leak discovered.
(2) Location.
(3) Classification.
(4) Cause of leak.
(5) Unique identifier for person making the
repair or responsible for maintaining the records of work
accomplished.
(h) Leaks
may be reclassified by responsible and suitable experienced persons whose name
shall appear on the documents.
§
192.725
Test Requirements for Reinstating Service
Lines.(a) Except as provided in
paragraph (b) of this section, each disconnected service line must be tested in
the same manner as a new service line, before being reinstated.
(b) Each service line temporarily
disconnected from the main must be tested from the point of disconnection to
the service line valve in the same manner as a new service line, before
reconnecting. However, if provisions are made to maintain continuous service,
such as installation of a bypass, any part of the original service line used to
maintain continuous service need not be tested.
§ 192.727
Abandonment or
Deactivation of Facilities.
(a) Each
operator shall conduct abandonment or deactivation of pipelines in accordance
with the requirements of this section.
(b) Each pipeline abandoned in place must be
disconnected from all sources and supplies of gas, purged of gas, and the ends
sealed. However, the pipeline need not be purged when the volume of gas is so
small that there is no potential hazard.
(c) Except for service lines, each inactive
pipeline that is not being maintained under this part must be disconnected from
all sources and supplies of gas, purged of gas, and the ends sealed. However,
the pipeline need not be purged when the volume of gas is so small that there
is no potential hazard.
(d)
Whenever service to a customer is discontinued, one of the following must be
complied with:
(1) The valve that is closed
to prevent the flow of gas to the customer must be provided with a locking
device or other means designed to prevent the opening of the valve by persons
other than those authorized by the operator.
(2) A mechanical device or fitting that will
prevent the flow of gas must be installed in the service line or in the meter
assembly.
(3) The customer's piping
must be physically disconnected from the gas supply and the open pipe ends
sealed.
(e) If air is
used for purging, the operator shall ensure that a combustible mixture is not
present after purging.
(f) Each
abandoned vault must be filled with a suitable compacted material.
(g) For each abandoned offshore pipeline
facility or each abandoned onshore pipeline facility 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.
(1) The preferred method to submit 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
http://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 e-mail 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; e-mail
InformationResourcesManager@phmsa.dot.gov. 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.
(2) [Reserved].
§ 192.731
Compressor
Stations: Inspection and Testing of Relief Devices.
(a) Except for rupture discs, each pressure
relieving device in a compressor station must be inspected and tested in
accordance with §§ 192.739 and 192.743, and must be operated
periodically to determine that it opens at the correct set pressure.
(b) Any defective or inadequate equipment
found must be promptly repaired or replaced.
(c) Each remote control shutdown device must
be inspected and tested, at intervals not exceeding 15 months, but at least
once each calendar year, to determine that it functions properly.
§ 192.735
Compressor
Stations: Storage of Combustible Materials.
(a) Flammable or combustible materials 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.
(b)
Above-ground oil or gasoline storage tanks must be protected in accordance with
National Fire Protection Association Standard No. 30.
§ 192.736
Compressor Stations:
Gas Detection.
(a) Not later than
September 16, 1996, each compressor building in a compressor station must have
a fixed gas detection and alarm system, unless the building is:
(1) Constructed so that at least 50 percent
of its upright side area is permanently open; or
(2) Located in an unattended field compressor
station of 1,000 horsepower (746 kW) or less.
(b) Except when shutdown of the system is
necessary for maintenance under paragraph (c) of this section, each gas
detection and alarm system required by this section must:
(1) Continuously monitor the compressor
building for a concentration of gas in air of not more than 25 percent of the
lower explosive limit; and
(2) If
that concentration of gas is detected, warn persons about to enter the building
and persons inside the building of the danger.
(c) Each gas detection and alarm system
required by this section must be maintained to function properly. The
maintenance must include performance tests.
§ 192.739
Pressure Limiting and
Regulating Stations: Inspection and Testing.
(a) Each pressure limiting station, relief
device (except rupture discs), and pressure regulating station and its
equipment must be subjected, at intervals not exceeding 15 months, but at least
once each calendar year, to inspections and tests. These inspections and tests
shall include the following:
(1) Pressure
regulating devices.
(i) Each regulator must be
inspected to ensure it is in good working order, controls pressure and capacity
within acceptable limits for the system in which it is installed.
(ii) Shuts off pressure within acceptable
limits.
(iii) Second stage
regulator will withstand and control first stage inlet pressure if a relief
valve is not installed between regulators.
(iv) Properly installed control lines,
controllers, actuators and protected from conditions that may prevent proper
operation.
(v) Except as provided
in paragraph (b) of this section, set to control or relieve at the correct
pressure consistent with the pressure limits of § 192.201(a);
and
(2) Pressure
limiting and relief devices.
(i) Monitor
regulators tested for proper operating parameters.
(ii) Except as provided in paragraph (b) of
this section set to control or relieve at the correct pressure consistent with
the pressure limits of § 192.201 (a); and
(iii) Vent stacks are free of obstructions,
properly routed, vented outside of building and vents adequately
covered.
(iv) Block valves
connecting relief devices to a system shall be locked in the open position and
block valves in manually-fed above ground bypasses shall be locked in the
closed position.
(b) For steel pipelines whose MAOP is
determined under § 192.619(c), if the MAOP is 60 p.s.i. (414 kPa) gage or
more, the control or relief pressure limit is as follows:
|
If the MAOP produces a hoop stress that is:
|
Then the pressure limit is:
|
|
Greater than 72 percent of SMYS
|
MAOP plus 4 percent
|
|
Unknown as a precentage of SMYS
|
A pressure that will prevent unsafe operation of the
pipeline considering its operating and maintenance history and MAOP
|
§
192.741
Pressure Limiting and Regulating Stations:
Telemetering or Recording Gauges.(a)
Each distribution system supplied by more than one district pressure regulating
station must be equipped with telemetering or recording pressure gauges to
indicate the gas pressure in the district.
(b) On distribution systems supplied by a
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.
(c) If there are
indications of abnormally high or low pressure, the regulator and the auxiliary
equipment must be inspected and the necessary measures employed to correct any
unsatisfactory operating conditions.
§ 192.743
Pressure Limiting and
Regulating Stations: Capacity of Relief Devices.
(a) Pressure relief devices at pressure
limiting stations and pressure regulating stations must have sufficient
capacity to protect the facilities to which they are connected. Except as
provided in § 192.739(b), the capacity must be consistent with the
pressure limits of § 192.201(a). This capacity must be determined at
intervals not exceeding 15 months, but at least once each calendar year, by
testing the devices in place or by review and calculations.
(b) If review and calculations are used to
determine if a 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.
(c) If a relief device is of insufficient
capacity, a new or additional device must be installed to provide the capacity
required by paragraph (a) of this section.
§ 192.745
Valve Maintenance:
Transmission Lines.(a) Each valve, the
use of which may be necessary for the safe operation of a transmission line,
must be identified and readily accessible. These valves must be inspected,
lubricated when necessary and partially operated at intervals not exceeding 15
months, but at least once each calendar year.
(b) Each operator must take prompt remedial
action to correct any valve found inoperable, unless the operator designates an
alternative valve.
§
192.747
Valve Maintenance: Distribution Systems.
(a) Each valve, the use of which may be
necessary for the safe operation of a distribution system must be identified
and readily accessible. These valves must be inspected, lubricated when
necessary and partially operated at intervals not exceeding 15 months, but at
least once each calendar year.
(b)
Each operator must take prompt remedial action to correct any valve found
inoperable, unless the operator designates an alternative valve.
§ 192.749
Vault
Maintenance.
(a) Each vault housing
pressure regulating and pressure limiting equipment, and having a volumetric
internal content of 200 cubic feet (5.66 cubic meters) or more, must be
inspected, at intervals not exceeding 15 months, but at least once each
calendar year, to determine that it is in good physical condition and
adequately ventilated.
(b) If gas
is found in the vault, the equipment in the vault must be inspected for leaks,
and any leaks found must be repaired.
(c) The ventilating equipment must also be
inspected to determine that it is functioning properly.
(d) Each vault cover must be inspected to
assure that it does not present a hazard to public safety.
§ 192.751
Prevention of
Accidental Ignition.
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:
(a) When a hazardous amount of gas is being
vented into open air, each potential source of ignition must be removed from
the area and a fire extinguisher must be provided.
(b) Gas or electric welding or cutting may
not be performed on pipe or on pipe components that contain a combustible
mixture of gas and air in the area of work.
(c) Post warning signs, where
appropriate.
§
192.753
Caulked Bell and Spigot Joints.
(a) Each cast iron caulked bell and spigot
joint that is subject to pressures of more than 25 p.s.i. (172kPa) gage must be
sealed with:
(1) A mechanical leak cl
or
(2) A material or device which:
(i) Does not reduce flexibility of the
joint;
(ii) Permanently bonds,
either chemically or mechanically, or both, with the bell and spigot metal
surfaces or adjacent pipe metal surfaces; and
(iii) Seals and bonds in a manner that meets
the strength, environmental, and chemical compatibility requirements of
§§ 192.53(a) and (b) and § 192.143.
(b) Each cast iron caulked bell
and spigot joint that is subject to pressures of 25 p.s.i. (172kPa) gage or
less and is exposed for any reason must be sealed by a means other than
caulking.
§ 192.755
Protecting Cast Iron Pipelines.
When an operator has knowledge that the support for a segment
of a buried cast iron pipeline is disturbed:
(a) That segment of the pipeline must be
protected, as necessary, against damage during the disturbance by:
(1) Vibrations from heavy construction
equipment, trains, trucks, buses or blasting;
(2) Impact force by vehicles;
(3) Earth movement;
(4) Apparent future excavations near the
pipeline; or
(5) Other foreseeable
outside forces which may subject that segment of the pipeline to bending
stress.
(b) 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 §§ 192.317(a),
192.319, and 192.361(b) - (d).
SUBPART N
- Qualification of Pipeline
Personnel
§ 192.801
Scope.
(a) This subpart prescribes the
minimum requirements for operator qualification of individuals performing
covered tasks on a pipeline facility.
(b) For the purpose of this subpart, a
covered task is an activity, identified by the operator, that:
(1) Is performed on a pipeline
facility;
(2) Is an operations or
maintenance task;
(3) Is performed
as a requirement of this part; and
(4) Affects the operation or integrity of the
pipeline.
§
192.803
Definitions.
Abnormal operating condition means a condition
identified by the operator that may indicate a malfunction of a component or
deviation from normal operations that may:
(a) Indicate a condition exceeding design
limits; or
(b) Result in a
hazard(s) to persons, property, or the environment.
Evaluation means a process, established and
documented by the operator, to determine an individual's ability to perform a
covered task by any of the following:
(a) Written examination;
(b) Oral examination;
(c) Work performance history
review;
(d) Observation during:
(1) Performance on the job,
(2) On the job training, or
(3) Simulations;
(e) Other forms of assessment.
Qualified means that an individual has been
evaluated and can:
(a) Perform
assigned covered tasks; and
(b)
Recognize and react to abnormal operating conditions.
§ 192.805
Qualification
program.
Each operator shall have and follow a written qualification
program. The program shall include provisions to:
(a) Identify covered tasks;
(b) Ensure through evaluation that
individuals performing covered tasks are qualified;
(c) Allow individuals that are not qualified
pursuant to this subpart to perform a covered task if directed and observed by
an individual that is qualified;
(d) Evaluate an individual if the operator
has reason to believe that the individual's performance of a covered task
contributed to an incident as defined in Part 191;
(e) Evaluate an individual if the operator
has reason to believe that the individual is no longer qualified to perform a
covered task;
(f) Communicate
changes that affect covered tasks to individuals performing those covered
tasks;
(g) Identify those covered
tasks and the intervals at which evaluation of the individual's qualifications
is needed;
(h) After December 16,
2004, provide training, as appropriate, 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; and
(i) After December 16, 2004, notify the
Administrator or a state agency participating under 49 U.S.C. Chapter 601 if
the operator significantly modifies the program after the Administrator or
state agency has verified that it complies with this section.
§ 192.807
Recordkeeping.
Each operator shall maintain records that demonstrate
compliance with this subpart.
(a)
Qualification records shall include:
(1)
Identification of qualified individual(s);
(2) Identification of the covered tasks the
individual is qualified to perform;
(3) Date(s) of current qualification;
and
(4) Qualification
method(s).
(b) Records
supporting an individual's 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 years.
§
192.809
General.
(a) Operators must have a written
qualification program by April 27, 2001. The program must be available for
review by the Administrator or by a state agency participating under 49 U.S.C.
Chapter 601 if the program is under the authority of that state
agency.
(b) Operators must complete
the qualification of individuals performing covered tasks by October 28,
2002.
(c) Work performance history
review may be used as a sole evaluation method for individuals who were
performing a covered task prior to October 26, 1999.
(d) After October 28, 2002, work performance
history may not be used as a sole evaluation method.
(e) After December 16, 2004 observation of
on-the-job performance may not be used as the sole method of
evaluation.
SUBPART
O
- GAS TRANSMISSION PIPELINE INTEGRITY MANAGEMENT
§ 192.901
What do the regulations
in this subpart cover?
This subpart prescribes minimum requirements for an integrity
management program on any gas transmission pipeline covered under this part.
For gas transmission pipelines constructed of plastic, only the requirements in
§§ 192.917, 192.921, 192.935 and 192.937 apply.
§ 192.903
What definitions apply
to this subpart?
The following definitions apply to this subpart.
Assessment is the use of testing
techniques as allowed in this subpart to ascertain the condition of a covered
pipeline segment.
Confirmatory direct assessment is
an integrity assessment method using more focused application of the principles
and techniques of direct assessment to identify internal and external corrosion
in a covered transmission pipeline segment.
Covered segment or covered pipeline
segment means a segment of gas transmission pipeline located in
a high consequence area. The terms gas and transmission line are defined in
§ 192.3.
Direct assessment is an integrity
assessment method that utilizes a process to evaluate certain threats
(i.e., external corrosion, internal corrosion and stress
corrosion cracking) to a covered pipeline segment's integrity. The process
includes the gathering and integration of risk factor data, indirect
examination or analysis to identify areas of suspected corrosion, direct
examination of the pipeline in these areas, and post assessment
evaluation.
High consequence area means an
area established by one of the methods described in paragraphs (1) or (2) as
follows:
(1) An area defined as-
(i) A Class 3 location under § 192.5;
or
(ii) A Class 4 location under
§ 192.5; or
(iii) Any area in
a Class 1 or Class 2 location where the potential impact radius is greater than
660 feet (200 meters), and the area within a potential impact circle contains
20 or more buildings intended for human occupancy; or
(iv) Any area in a Class 1 or Class 2
location where the potential impact circle contains an identified
site.
(2) The area
within a potential impact circle containing--
(i) 20 or more buildings intended for human
occupancy, unless the exception in paragraph (4) applies; or
(ii) An identified site.
(3) Where a potential impact circle is
calculated under either method (1) or (2) to establish a high consequence area,
the length of the high consequence area extends axially along the length of the
pipeline from the outermost edge of the first potential impact circle that
contains either an identified site or 20 or more buildings intended for human
occupancy to the outermost edge of the last contiguous potential impact circle
that contains either an identified site or 20 or more buildings intended for
human occupancy. (See Figure E.I.A. in Appendix E.)
(4) If in identifying a high consequence area
under paragraph (1)(iii) of this definition or paragraph (2)(i) of this
definition, the radius of the potential impact circle is greater than 660 feet
(200 meters), the operator may identify a high consequence area based on a
prorated number of buildings intended for human occupancy within a distance 660
feet (200 meters) from the centerline of the pipeline until December 17, 2006.
If an operator chooses this approach, the operator must prorate the number of
buildings intended for human occupancy based on the ratio of an area with a
radius of 660 feet (200 meters) to the area of the potential impact circle
(
i.e., the prorated number of buildings intended for human
occupancy is equal to 20 x ( 660 feet [or 200 meters]) / ( potential impact
radius in feet [or meters])
2).
Identified site
means
each of the following areas:
(a) An outside area or open structure that is
occupied by twenty (20) or more persons on at least 50 days in any twelve (12)-
month period. (The days need not be consecutive). Examples include but are not
limited to, beaches, playgrounds, recreational facilities, camping grounds,
outdoor theaters, stadiums, recreational areas near a body of water, or areas
outside a rural building such as a religious facility; or
(b) A building 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).
Examples include, but are not limited to, religious facilities, office
buildings, community centers, general stores, 4-H facilities, or roller skating
rinks; or
(c) A facility occupied
by persons who are confined, are of impaired mobility, or would be difficult to
evacuate. Examples include but are not limited to hospitals, prisons, schools,
day-care facilities, retirement facilities or assisted-living facilities.
Potential impact circle is a
circle of radius equal to the potential impact radius (PIR).
Potential impact radius (PIR)
means the radius of a circle within which the potential failure of a pipeline
could have significant impact on people or property. PIR is determined by the
formula r = 0.69 * (square root of (p*d2)), where
'r' is the radius of a circular area in feet surrounding the point of failure,
'p' is the maximum allowable operating pressure (MAOP) in the pipeline segment
in pounds per square inch and 'd' is the nominal diameter of the pipeline in
inches.
Note: 0.69 is the factor for natural gas. This number will vary
for other gases depending upon their heat of combustion. An operator
transporting gas other than natural gas must use section 3.2 of ASME/ANSI
B31.8S-2001 (Supplement to ASME B31.8; (incorporated by reference,
see
§ 192.7)) to calculate the impact radius formula.
Remediation is a repair or
mitigation activity an operator takes on a covered segment to limit or reduce
the probability of an undesired event occurring or the expected consequences
from the event.
§
192.905
How does an operator identify a high consequence
area?
(a) General. To determine which
segments of an operator's transmission pipeline system are covered by this
subpart, an operator must identify the high consequence areas. An operator must
use method (1) or (2) from the definition in § 192.903 to identify a high
consequence area. An operator may apply one method to its entire pipeline
system, or an operator may apply one method to individual portions of the
pipeline system. An operator must describe in its integrity management program
which method it is applying to each portion of the operator's pipeline system.
The description must include the potential impact radius when utilized to
establish a high consequence area. (See Appendix E.I. for guidance on
identifying high consequence areas.)
(b)
(1)
Identified sites. An operator must identify an identified site, for purposes of
this subpart, from information the operator has obtained from routine operation
and maintenance activities and from public officials with safety or emergency
response or planning responsibilities who indicate to the operator that they
know of locations that meet the identified site criteria. These public
officials could include officials on a local emergency planning commission or
relevant Native American tribal officials.
(2) If a public official with safety or
emergency response or planning responsibilities informs an operator that it
does not have the information to identify an identified site, the operator must
use one of the following sources, as appropriate, to identify these sites.
(i) Visible marking (e.g., a sign);
or
(ii) The site is licensed or
registered by a Federal, State, or local government agency; or
(iii) The site is on a list (including a list
on an internet web site) or map maintained by or available from a Federal,
State, or local government agency and available to the general
public.
(c)
Newly-identified areas. When an operator has information that
the area around a pipeline segment not previously identified as a high
consequence area could satisfy any of the definitions in § 192.903, the
operator must complete the evaluation using method (1) or (2). If the segment
is determined to meet the definition as a high consequence area, it must be
incorporated into the operator's baseline assessment plan as a high consequence
area within one year from the date the area is identified.
§ 192.907
What must an operator
do to implement this subpart?(a)
General. No later than December 17, 2004, an operator of a
covered pipeline segment must develop and follow a written integrity management
program that contains all the elements described in § 192.911 and that
addresses the risks on each covered transmission pipeline segment. The initial
integrity management program must consist, at a minimum, of a framework that
describes the process for implementing each program element, how relevant
decisions will be made and by whom, a time line for completing the work to
implement the program element, and how information gained from experience will
be continuously incorporated into the program. The framework will evolve into a
more detailed and comprehensive program. An operator must make continual
improvements to the program.
(b)
Implementation Standards. In carrying out this subpart, an
operator must follow the requirements of this subpart and of ASME/ANSI B31.8S
(incorporated by reference, see § 192.7) and its appendices, where
specified. An operator may follow an equivalent standard or practice only when
the operator demonstrates the alternative standard or practice provides an
equivalent level of safety to the public and property. In the event of a
conflict between this subpart and ASME/ANSI B31.8S, the requirements in this
subpart control.
§
192.909
How can an operator change its integrity management
program?
(a)
General.
An operator must document any change to its program and the reasons for the
change before implementing the change.
(b)
Notification. An
operator must notify OPS, in accordance with § 192.949, of any change to
the program that may substantially affect the program's implementation or may
significantly modify the program or schedule for carrying out the program
elements. An operator must also notify a State or local pipeline safety
authority when either a covered segment is located in a State where OPS has an
interstate agent agreement, or an intrastate covered segment is regulated by
that State. An operator must provide the notification within 30 days after
adopting this type of change into its program.
§ 192.911
What are the elements
of an integrity management program?
An operator's initial integrity management program begins with
a framework (see § 192.907) and evolves into a more detailed and
comprehensive integrity management program, as information is gained and
incorporated into the program. An operator must make continual improvements to
its program. The initial program framework and subsequent program must, at
minimum, contain the following elements. (When indicated, refer to ASME/ANSI
B31.8S (incorporated by reference, see § 192.7) for more detailed
information on the listed element.)
(a) An identification of all high consequence
areas, in accordance with § 192.905.
(b) A baseline assessment plan meeting the
requirements of §§ 192.919 and 192.921.
(c) An identification of threats to each
covered pipeline segment, which must include data integration and a risk
assessment. An operator must use the threat identification and risk assessment
to prioritize covered segments for assessment (§ 192.917) and to evaluate
the merits of additional preventive and mitigative measures (§ 192.935)
for each covered segment.
(d) A
direct assessment plan, if applicable, meeting the requirements of §
192.923, and depending on the threat assessed, of §§ 192.925,
192.927, or 192.929.
(e) Provisions
meeting the requirements of § 192.933 for remediating conditions found
during an integrity assessment.
(f)
A process for continual evaluation and assessment meeting the requirements of
§ 192.937.
(g) If applicable,
a plan for confirmatory direct assessment meeting the requirements of §
192.931.
(h) Provisions meeting
the requirements of § 192.935 for adding preventive and mitigative
measures to protect the high consequence area.
(i) A performance plan as outlined in
ASME/ANSI B31.8S, section 9 that includes performance measures meeting the
requirements of § 192.945.
(j) Record keeping provisions meeting the
requirements of § 192.947.
(k)
A management of change process as outlined in ASME/ANSI B31.8S, section 11.
(l) A quality assurance process as
outlined in ASME/ANSI B31.8S, section 12.
(m) A communication plan that includes the
elements of ASME/ANSI B31.8S, section 10, and that includes procedures for
addressing safety concerns raised by -(1) OPS; and (2) a State or local
pipeline safety authority when a covered segment is located in a State where
OPS has an interstate agent agreement.
(n) Procedures for providing (when
requested), by electronic or other means, a copy of the operator's risk
analysis or integrity management program to - (1) OPS; and (2) A State or local
pipeline safety authority when a covered segment is located in a State where
OPS has an interstate agent agreement.
(o) Procedures for ensuring that each
integrity assessment is being conducted in a manner that minimizes
environmental and safety risks.
(p) A process for identification and
assessment of newly-identified high consequence areas. (See § 192.905 and
§ 192.921.)
§
192.913
When may an operator deviate its program from
certain requirements of this subpart?
(a)
General. ASME/ANSI
B31.8S (incorporated by reference, see § 192.7) provides the essential
features of a performance-based or a prescriptive integrity management program.
An operator that uses a performance-based approach that satisfies the
requirements for exceptional performance in paragraph (b) of this section may
deviate from certain requirements in this subpart, as provided in paragraph (c)
of this section.
(b)
Exceptional performance. An operator must be able to
demonstrate the exceptional performance of its integrity management program
through the following actions.
(1) To deviate
from any of the requirements set forth in paragraph (c) of this section, an
operator must have a performance-based integrity management program that meets
or exceed the performance-based requirements of ASME/ANSI B31.8S and includes,
at a minimum, the following elements -
(i) A
comprehensive process for risk analysis;
(ii) All risk factor data used to support the
program;
(iii) A comprehensive data
integration process;
(iv) A
procedure for applying lessons learned from assessment of covered pipeline
segments to pipeline segments not covered by this subpart;
(v) A procedure for evaluating every
incident, including its cause, within the operator's sector of the pipeline
industry for implications both to the operator's pipeline system and to the
operator's integrity management program;
(vi) A performance matrix that demonstrates
the program has been effective in ensuring the integrity of the covered
segments by controlling the identified threats to the covered
segments;
(vii) Semi-annual
performance measures beyond those required in § 192.945 that are part of
the operator's performance plan. (See § 192.911(i).) An operator must
submit these measures, by electronic or other means, on a semi-annual frequency
to OPS in accordance with § 192.951; and
(viii) An analysis that supports the desired
integrity reassessment interval and the remediation methods to be used for all
covered segments.
(2) In
addition to the requirements for the performance-based plan, an operator must -
(i) Have completed at least two integrity
assessments on each covered pipeline segment the operator is including under
the performance-based approach, and be able to demonstrate that each assessment
effectively addressed the identified threats on the covered segment.
(ii) Remediate all anomalies identified in
the more recent assessment according to the requirements in § 192.933, and
incorporate the results and lessons learned from the more recent assessment
into the operator's data integration and risk assessment.
(c)
Deviation.
Once an operator has demonstrated that it has satisfied the requirements of
paragraph (b) of this section, the operator may deviate from the prescriptive
requirements of ASME/ANSI B31.8S and of this subpart only in the following
instances.
(1) The time frame for
reassessment as provided in § 192.939 except that reassessment by some
method allowed under this subpart (e.g., confirmatory direct assessment) must
be carried out at intervals no longer than seven years;
(2) The time frame for remediation as
provided in § 192.933 if the operator demonstrates the time frame will not
jeopardize the safety of the covered segment.
§ 192.915
What knowledge and
training must personnel have to carry out an integrity management
program?
(a)
Supervisory
personnel. The integrity management program must provide that each
supervisor whose responsibilities relate to the integrity management program
possesses and maintains a thorough knowledge of the integrity management
program and of the elements for which the supervisor is responsible. The
program must provide that any person who qualifies as a supervisor for the
integrity management program has appropriate training or experience in the area
for which the person is responsible.
(b)
Persons who carry out assessments
and evaluate assessment results. The integrity management program must
provide criteria for the qualification of any person -
(1) Who conducts an integrity assessment
allowed under this subpart; or
(2)
Who reviews and analyzes the results from an integrity assessment and
evaluation; or
(3) Who makes
decisions on actions to be taken based on these assessments.
(c)
Persons responsible
for preventive and mitigative measures. The integrity management
program must provide criteria for the qualification of any person -
(1) Who implements preventive and mitigative
measures to carry out this subpart, including the marking and locating of
buried structures; or
(2) Who
directly supervises excavation work carried out in conjunction with an
integrity assessment.
§ 192.917
How does an operator
identify potential threats to pipeline integrity and use the threat
identification in its integrity program?
(a)
Threat identification.
An operator must identify and evaluate all potential threats to each covered
pipeline segment. Potential threats that an operator must consider include, but
are not limited to, the threats listed in ASME/ANSI B31.8S (incorporated by
reference, see § 192.7), section 2, which are grouped under the following
four categories:
(1) Time dependent threats
such as internal corrosion, external corrosion, and stress corrosion
cracking;
(2) Static or resident
threats, such as fabrication or construction defects;
(3) Time independent threats such as third
party damage and outside force damage; and
(4) Human error.
(b)
Data gathering and
integration. To identify and evaluate the potential threats to a
covered pipeline segment, an operator must gather and integrate existing data
and information on the entire pipeline that could be relevant to the covered
segment. In performing this data gathering and integration, an operator must
follow the requirements in ASME/ANSI B31.8S, section 4. At a minimum, an
operator must gather and evaluate the set of data specified in Appendix A to
ASME/ANSI B31.8S, and consider both on the covered segment and similar
non-covered segments, past incident history, corrosion control records,
continuing surveillance records, patrolling records, maintenance history,
internal inspection records and all other conditions specific to each
pipeline.
(c)
Risk
assessment. An operator must conduct a risk assessment that follows
ASME/ANSI B31.8S, section 5, and considers the identified threats for each
covered segment. An operator must use the risk assessment to prioritize the
covered segments for the baseline and continual reassessments (§§
192.919, 192.921, 192.937), and to determine what additional preventive and
mitigative measures are needed (§192.935) for the covered
segment.
(d)
Plastic
Transmission Pipeline. An operator of a plastic transmission pipeline
must assess the threats to each covered segment using the information in
sections 4 and 5 of ASME B31.8S, and consider any threats unique to the
integrity of plastic pipe.
(e)
Actions to address particular threats. If an operator
identifies any of the following threats, the operator must take the following
actions to address the threat.
(1) Third
party damage. An operator must utilize the data integration required in
paragraph (b) of this section and ASME/ ANSI B31.8S, Appendix A7 to determine
the susceptibility of each covered segment to the threat of third party damage.
If an operator identifies the threat of third party damage, the operator must
implement comprehensive additional preventive measures in accordance with
§ 192.935 and monitor the effectiveness of the preventive measures. If, in
conducting a baseline assessment under § 192.921, or a reassessment under
§ 192.937, an operator uses an internal inspection tool or external
corrosion direct assessment, the operator must integrate data from these
assessments with data related to any encroachment or foreign line crossing on
the covered segment, to define where potential indications of third party
damage may exist in the covered segment. An operator must also have procedures
in its integrity management program addressing actions it will take to respond
to findings from this data integration.
(2) Cyclic fatigue. An operator must evaluate
whether cyclic fatigue or other loading condition (including ground movement,
suspension bridge condition) could lead to a failure of a deformation,
including a dent or gouge, or other defect in the covered segment. An
evaluation must assume the presence of threats in the covered segment that
could be exacerbated by cyclic fatigue. An operator must use the results from
the evaluation together with the criteria used to evaluate the significance of
this threat to the covered segment to prioritize the integrity baseline
assessment or reassessment.
(3)
Manufacturing and construction defects. If an operator identifies the threat of
manufacturing and construction defects (including seam defects) in the covered
segment, an operator must analyze the covered segment to determine the risk of
failure from these defects. The analysis must consider the results of prior
assessments on the covered segment. An operator may consider manufacturing and
construction related defects to be stable defects if the operating pressure on
the covered segment has not increased over the maximum operating pressure
experienced during the five years preceding identification of the high
consequence area. If any of the following changes occur in the covered segment,
an operator must prioritize the covered segment as a high risk segment for the
baseline assessment or a subsequent reassessment.
(i) Operating pressure increases above the
maximum operating pressure experienced during the preceding five
years;
(ii) MAOP increases;
or
(iii) The stresses leading to
cyclic fatigue increase.
(4) ERW pipe. If a covered pipeline segment
contains low frequency electric resistance welded pipe (ERW), lap welded pipe
or other pipe that satisfies the conditions specified in ASME/ANSI B31.8 S,
Appendices A4.3 and A4.4, and any covered or non covered segment in the
pipeline system with such pipe has experienced seam failure, or operating
pressure on the covered segment has increased over the maximum operating
pressure experienced during the preceding five years, an operator must select
an assessment technology or technologies with a proven application capable of
assessing seam integrity and seam corrosion anomalies. The operator must
prioritize the covered segment as a high risk segment for the baseline
assessment or a subsequent reassessment.
(5) Corrosion. If an operator identifies
corrosion on a covered pipeline segment that could adversely affect the
integrity of the line (conditions specified in § 192.933), the operator
must evaluate and remediate, as necessary, all pipeline segments (both covered
and non-covered) with similar material coating and environmental
characteristics. An operator must establish a schedule for evaluating and
remediating, as necessary, the similar segments that is consistent with the
operator's established operating and maintenance procedures under Part 192 for
testing and repair.
§
192.919
What must be in the baseline assessment
plan?
An operator must include each of the following elements in its
written baseline assessment plan:
(a)
Identification of the potential threats to each covered pipeline segment and
the information supporting the threat identification. (See
§192.917.);
(b) The methods
selected to assess the integrity of the line pipe, including an explanation of
why the assessment method was selected to address the identified threats to
each covered segment. The integrity assessment method an operator uses must be
based on the threats identified to the covered segment. (See § 192.917.)
More than one method may be required to address all the threats to the covered
pipeline segment;
(c) A schedule
for completing the integrity assessment of all covered segments, including,
risk factors considered in establishing the assessment schedule;
(d) If applicable, a direct assessment plan
that meets the requirements of §§ 192.923, and depending on the
threat to be addressed, of § 192.925, § 192.927, or § 192.929;
and
(e) A procedure to ensure that
the baseline assessment is being conducted in a manner that minimizes
environmental and safety risks.
§ 192.921
How is the baseline
assessment to be conducted?
(a)
Assessment methods. An operator must assess the integrity of
the line pipe in each covered segment by applying one or more of the following
methods depending on the threats to which the covered segment is susceptible.
An operator must select the method or methods best suited to address the
threats identified to the covered segment (See § 192.917).
(1) Internal inspection tool or tools capable
of detecting corrosion, and any other threats to which the covered segment is
susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by
reference, see § 192.7), section 6.2 in selecting the appropriate internal
inspection tools for the covered segment.
(2) Pressure test conducted in accordance
with subpart J of this part. An operator must use the test pressures specified
in Table 3 of section 5 of ASME /ANSI B31.8S, to justify an extended
reassessment interval in accordance with § 192.939.
(3) Direct assessment to address threats of
external corrosion, internal corrosion, and stress corrosion cracking. An
operator must conduct the direct assessment in accordance with the requirements
listed in §192.923 and with, as applicable, the requirements specified in
§§ 192.925, 192.927 or 192.929;
(4) Other technology that an operator
demonstrates can provide an equivalent understanding of the condition of the
line pipe. An operator choosing this option must notify the Office of Pipeline
Safety (OPS) 180 days before conducting the assessment, in accordance with
§ 192.949. An operator must also notify a State or local pipeline safety
authority when either a covered segment is located in a State where OPS has an
interstate agent agreement, or an intrastate covered segment is regulated by
that State.
(b)
Prioritizing segments. An operator must prioritize the covered
pipeline segments for the baseline assessment according to a risk analysis that
considers the potential threats to each covered segment. The risk analysis must
comply with the requirements in § 192.917.
(c)
Assessment for particular
threats. In choosing an assessment method for the baseline assessment
of each covered segment, an operator must take the actions required in §
192.917(e) to address particular threats that it has identified.
(d)
Time period. An operator
must prioritize all the covered segments for assessment in accordance with
§ 192.917 (c) and paragraph (b) of this section. An operator must assess
at least 50% of the covered segments beginning with the highest risk segments,
by December 17, 2007. An operator must complete the baseline assessment of all
covered segments by December 17, 2012.
(e)
Prior assessment. An
operator may use a prior integrity assessment conducted before December 17,
2002 as a baseline assessment for the covered segment, if the integrity
assessment meets the baseline requirements in this subpart and subsequent
remedial actions to address the conditions listed in § 192.933 have been
carried out. In addition, if an operator uses this prior assessment as its
baseline assessment, the operator must reassess the line pipe in the covered
segment according to the requirements of § 192.937 and §
192.939.
(f)
Newly
identified areas. When an operator identifies a new high consequence
area (see § 192.905), an operator must complete the baseline assessment of
the line pipe in the newly identified high consequence area within ten (10)
years from the date the area is identified.
(g)
Newly installed pipe. An
operator must complete the baseline assessment of a newly installed segment of
pipe covered by this subpart within ten (10) years from the date the pipe is
installed. An operator may conduct a pressure test in accordance with paragraph
(a)(2) of this section, to satisfy the requirement for a baseline
assessment.
(h)
Plastic
transmission pipeline. If the threat analysis required in §
192.917(d) on a plastic transmission pipeline indicates that a covered segment
is susceptible to failure from causes other than third-party damage, an
operator must conduct a baseline assessment of the segment in accordance with
the requirements of this section and of § 192.917. The operator must
justify the use of an alternative assessment method that will address the
identified threats to the covered segment.
§ 192.923
How is direct
assessment used and for what threats?
(a)
General. An operator may
use direct assessment either as a primary assessment method or as a supplement
to the other assessment methods allowed under this subpart. An operator may
only use direct assessment as the primary assessment method to address the
identified threats of external corrosion (ECDA), internal corrosion (ICDA), and
stress corrosion cracking (SCCDA).
(b)
Primary Method. An
operator using direct assessment as a primary assessment method must have a
plan that complies with the requirements in -
(1) ASME/ANSI B31.8S (incorporated by
reference, see § 192.7), section 6.4; NACE SP0502-2008 (incorporated by
reference, see § 192.7); and § 192.925 if addressing external
corrosion (ECDA).
(2) ASME/ANSI
B31.8S, section 6.4 and Appendix B2, and § 192.927 if addressing internal
corrosion (ICDA).
(3) ASME/ANSI
B31.8S Appendix A3, and § 192.929 if addressing stress corrosion cracking
(SCCDA).
(c)
Supplemental method. An operator using direct assessment as a
supplemental assessment method for any applicable threat must have a plan that
follows the requirements for confirmatory direct assessment in §
192.931.
§ 192.925
What are the requirements for using External Corrosion Direct Assessment
(ECDA)?
(a)
Definition. ECDA is a four-step process that combines
preassessment, indirect inspection, direct examination, and post assessment to
evaluate the threat of external corrosion to the integrity of a
pipeline.
(b)
General
requirements. An operator that uses direct assessment to assess the
threat of external corrosion must follow the requirements in this section, in
ASME/ANSI B31.8S (incorporated by reference, see § 192.7), section 6.4,
and in NACE SP0502-2008 (incorporated by reference,
see §
192.7). An operator must develop and implement a direct assessment plan that
has procedures addressing preassessment, indirect examination, direct
examination, and post-assessment. If the ECDA detects pipeline coating damage,
the operator must also integrate the data from the ECDA with other information
from the data integration (§ 192.917(b)) to evaluate the covered segment
for the threat of third party damage, and to address the threat as required by
§ 192.917 (e)(1).
(1) Preassessment. In
addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE
SP0502-2008, section 3, the plan's procedures for preassessment must include -
(i) Provisions for applying more restrictive
criteria when conducting ECDA for the first time on a covered segment;
and
(ii) The basis on which an
operator selects at least two different, but complementary indirect assessment
tools to assess each ECDA Region. If an operator utilizes an indirect
inspection method that is not discussed in Appendix A of NACE SP0502-2008, the
operator must demonstrate the applicability, validation basis, equipment used,
application procedure, and utilization of data for the inspection
method.
(2) Indirect
examination. In addition to the requirements in ASME/ANSI B31.8S section 6.4
and NACE SP0502-2008, section 4, the plan's procedures for indirect examination
of the ECDA regions must include -
(i)
Provisions for applying more restrictive criteria when conducting ECDA for the
first time on a covered segment;
(ii) Criteria for identifying and documenting
those indications that must be considered for excavation and direct
examination. Minimum identification criteria include the known sensitivities of
assessment tools, the procedures for using each tool, and the approach to be
used for decreasing the physical spacing of indirect assessment tool readings
when the presence of a defect is suspected;
(iii) Criteria for defining the urgency of
excavation and direct examination of each indication identified during the
indirect examination. These criteria must specify how an operator will define
the urgency of excavating the indication as immediate, scheduled or monitored;
and
(iv) Criteria for scheduling
excavation of indications for each urgency level.
(3) Direct examination. In addition to the
requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502-2008, section 5,
the plan's procedures for direct examination of indications from the indirect
examination must include -
(i) Provisions for
applying more restrictive criteria when conducting ECDA for the first time on a
covered segment;
(ii) Criteria for
deciding what action should be taken if either:
(A) Corrosion defects are discovered that
exceed allowable limits (Section 5.5.2.2 of NACE SP0502-2008), or
(B) Root cause analysis reveals conditions
for which ECDA is not suitable (Section 5.6.2 of NACE SP0502-2008);
(iii) Criteria and notification
procedures for any changes in the ECDA Plan, including changes that affect the
severity classification, the priority of direct examination, and the time frame
for direct examination of indications; and
(iv) Criteria that describe how and on what
basis an operator will reclassify and reprioritize any of the provisions that
are specified in section 5.9 of NACE SP0502-2008.
(4) Post assessment and continuing
evaluation. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and
NACE SP0502-2008, section 6, the plan's procedures for post assessment of the
effectiveness of the ECDA process must include-
(i) Measures for evaluating the long-term
effectiveness of ECDA in addressing external corrosion in covered segments;
and
(ii) Criteria for evaluating
whether conditions discovered by direct examination of indications in each ECDA
region indicate a need for reassessment of the covered segment at an interval
less than that specified in § 192.939. (See Appendix D of NACE
SP0502-2008.).
§ 192.927
What are the
requirements for using Internal Corrosion Direct Assessment (ICDA)?
(a)
Definition. Internal
Corrosion Direct Assessment (ICDA) is a process an operator uses to identify
areas along the pipeline where fluid or other electrolyte introduced during
normal operation or by an upset condition may reside, and then focuses direct
examination on the locations in covered segments where internal corrosion is
most likely to exist. The process identifies the potential for internal
corrosion caused by microorganisms, or fluid with CO2,
O2, hydrogen sulfide or other contaminants present in
the gas.
(b)
General
requirements. An operator using direct assessment as an assessment
method to address internal corrosion in a covered pipeline segment must follow
the requirements in this section and in ASME/ANSI B31.8S (incorporated by
reference, see
§ 192.7), section 6.4 and Appendix B2. The
ICDA process described in this section applies only for a segment of pipe
transporting nominally dry natural gas, and not for a segment with electrolyte
nominally present in the gas stream. If an operator uses ICDA to assess a
covered segment operating with electrolyte present in the gas stream, the
operator must develop a plan that demonstrates how it will conduct ICDA in the
segment to effectively address internal corrosion, and must provide
notification in accordance with § 192.921 (a)(4) or §
192.937(c)(4).
(c)
The ICDA
plan. An operator must develop and follow an ICDA plan that provides
for preassessment, identification of ICDA regions and excavation locations,
detailed examination of pipe at excavation locations, and post-assessment
evaluation and monitoring.
(1)
Preassessment. In the preassessment stage, an operator must
gather and integrate data and information needed to evaluate the feasibility of
ICDA for the covered segment, and to support use of a model to identify the
locations along the pipe segment where electrolyte may accumulate, to identify
ICDA regions, and to identify areas within the covered segment where liquids
may potentially be entrained. This data and information includes, but is not
limited to -
(i) All data elements listed in
Appendix A2 of ASME/ANSI B31.8S;
(ii) Information needed to support use of a
model that an operator must use to identify areas along the pipeline where
internal corrosion is most likely to occur.(See paragraph (a) of this section.)
This information, includes, but is not limited to, location of all gas input
and withdrawal points on the line; location of all low points on covered
segments such as sags, drips, inclines, valves, manifolds, dead-legs, and
traps; the elevation profile of the pipeline in sufficient detail that angles
of inclination can be calculated for all pipe segments; and the diameter of the
pipeline, and the range of expected gas velocities in the pipeline;
(iii) Operating experience data that would
indicate historic upsets in gas conditions, locations where these upsets have
occurred, and potential damage resulting from these upset conditions;
and
(iv) Information on covered
segments where cleaning pigs may not have been used or where cleaning pigs may
deposit electrolytes.
(2) ICDA region identification. An operator's
plan must identify where all ICDA Regions are located in the transmission
system, in which covered segments are located. An ICDA Region extends from the
location where liquid may first enter the pipeline and encompasses the entire
area along the pipeline where internal corrosion may occur and where further
evaluation is needed. An ICDA Region may encompass one or more covered
segments. In the identification process, an operator must use the model in GRI
02-0057, "Internal Corrosion Direct Assessment of Gas Transmission Pipelines -
Methodology," (incorporated by reference, see § 192.7). An operator may
use another model if the operator demonstrates it is equivalent to the one
shown in GRI 02-0057. A model must consider changes in pipe diameter, locations
where gas enters a line (potential to introduce liquid) and locations down
stream of gas draw-offs (where gas velocity is reduced) to define the critical
pipe angle of inclination above which water film cannot be transported by the
gas.
(3) Identification of
locations for excavation and direct examination. An operator's plan must
identify the locations where internal corrosion is most likely in each ICDA
region. In the location identification process, an operator must identify a
minimum of two locations for excavation within each ICDA Region within a
covered segment and must perform a direct examination for internal corrosion at
each location, using ultrasonic thickness measurements, radiography, or other
generally accepted measurement technique. One location must be the low point
(e.g., sags, drips, valves, manifolds, dead-legs, traps) within the covered
segment nearest to the beginning of the ICDA Region. The second location must
be further downstream, within a covered segment, near the end of the ICDA
Region. If corrosion exists at either location, the operator must-
(i) evaluate the severity of the defect
(remaining strength) and remediate the defect in accordance with §
192.933;
(ii) as part of the
operator's current integrity assessment either perform additional excavations
in each covered segment within the ICDA region, or use an alternative
assessment method allowed by this subpart to assess the line pipe in each
covered segment within the ICDA region for internal corrosion; and
(iii) evaluate the potential for internal
corrosion in all pipeline segments (both covered and non-covered) in the
operator's pipeline system with similar characteristics to the ICDA region
containing the covered segment in which the corrosion was found, and as
appropriate, remediate the conditions the operator finds in accordance with
§ 192.933.
(4)
Post-assessment evaluation and monitoring. An operator's plan must provide for
evaluating the effectiveness of the ICDA process and continued monitoring of
covered segments where internal corrosion has been identified. The evaluation
and monitoring process includes-
(i)
Evaluating the effectiveness of ICDA as an assessment method for addressing
internal corrosion and determining whether a covered segment should be
reassessed at more frequent intervals than those specified in § 192.939.
An operator must carry out this evaluation within a year of conducting an ICDA;
and
(ii) Continually monitoring
each covered segment where internal corrosion has been identified using
techniques such as coupons, UT sensors or electronic probes, periodically
drawing off liquids at low points and chemically analyzing the liquids for the
presence of corrosion products. An operator must base the frequency of the
monitoring and liquid analysis on results from all integrity assessments that
have been conducted in accordance with the requirements of this subpart, and
risk factors specific to the covered segment. If an operator finds any evidence
of corrosion products in the covered segment, the operator must take prompt
action in accordance with one of the two following required actions and
remediate the conditions the operator finds in accordance with § 192.933.
(A) Conduct excavations of covered segments
at locations downstream from where the electrolyte might have entered the pipe;
or
(B) Assess the covered segment
using another integrity assessment method allowed by this subpart.
(5)
Other
requirements. The ICDA plan must also include -
(i) Criteria an operator will apply in making
key decisions (e.g., ICDA feasibility, definition of ICDA Regions, conditions
requiring excavation) in implementing each stage of the ICDA process;
(ii) Provisions for applying more restrictive
criteria when conducting ICDA for the first time on a covered segment and that
become less stringent as the operator gains experience; and
(iii) Provisions that analysis be carried out
on the entire pipeline in which covered segments are present, except that
application of the remediation criteria of § 192.933 may be limited to
covered segments.
§ 192.929
What are the
requirements for using Direct Assessment for Stress Corrosion Cracking
(SCCDA)?
(a)
Definition. Stress Corrosion Cracking Direct Assessment
(SCCDA) is a process to assess a covered pipe segment for the presence of SCC
primarily by systematically gathering and analyzing excavation data for pipe
having similar operational characteristics and residing in a similar physical
environment.
(b)
General
Requirements. An operator using direct assessment as an integrity
assessment method to address stress corrosion cracking in a covered pipeline
segment must have a plan that provides, at minimum, for -
(1) Data gathering and integration. An
operator's plan must provide for a systematic process to collect and evaluate
data for all covered segments to identify whether the conditions for SCC are
present and to prioritize the covered segments for assessment. This process
must include gathering and evaluating data related to SCC at all sites an
operator excavates during the conduct of its pipeline operations where the
criteria in ASME/ANSI B31.8S (incorporated by reference, see § 192.7),
Appendix A3.3 indicate the potential for SCC. This data includes at minimum,
the data specified in ASME/ANSI B31.8S, Appendix A3.
(2) Assessment method. The plan must provide
that if conditions for SCC are identified in a covered segment, an operator
must assess the covered segment using an integrity assessment method specified
in ASME/ANSI B31.8S, Appendix A3, and remediate the threat in accordance with
ASME/ANSI B31.8S, Appendix A3, section A3.4.
§ 192.931
How may Confirmatory
Direct Assessment (CDA) be used?
An operator using the confirmatory direct assessment (CDA)
method as allowed in § 192.937 must have a plan that meets the
requirements of this section and of § 192.925 (ECDA) and § 192.927
(ICDA).
(a)
Threats.
An operator may only use CDA on a covered segment to identify damage resulting
from external corrosion or internal corrosion.
(b)
External corrosion plan.
An operator's CDA plan for identifying external corrosion must comply with
§ 192.925 with the following exceptions.
(1) The procedures for indirect examination
may allow use of only one indirect examination tool suitable for the
application.
(2) The procedures for
direct examination and remediation must provide that -
(i) All immediate action indications must be
excavated for each ECDA region; and
(ii) At least one high risk indication that
meets the criteria of scheduled action must be excavated in each ECDA
region.
(c)
Internal corrosion plan. An operator's CDA plan for
identifying internal corrosion must comply with § 192.927 except that the
plan's procedures for identifying locations for excavation may require
excavation of only one high risk location in each ICDA region.
(d) Defects requiring near-term remediation.
If an assessment carried out under paragraph (b) or (c) of this section reveals
any defect requiring remediation prior to the next scheduled assessment, the
operator must schedule the next assessment in accordance with NACE SP0502-2008
(incorporated by reference, see § 192.7), section 6.2 and 6.3. If the
defect requires immediate remediation, then the operator must reduce pressure
consistent with § 192.933 until the operator has completed reassessment
using one of the assessment techniques allowed in § 192.937.
§ 192.933
What actions
must be taken to address integrity issues?
(a)
General requirements. An
operator must take prompt action to address all anomalous conditions the
operator discovers through the integrity assessment. In addressing all
conditions, an operator must evaluate all anomalous conditions and remediate
those that could reduce a pipeline's integrity. An operator must be able to
demonstrate that the remediation of the condition will ensure the condition is
unlikely to pose a threat to the integrity of the pipeline until the next
reassessment of the covered segment.
(1)
Temporary pressure reduction. If an operator is unable to respond within the
time limits for certain conditions specified in this section, the operator must
temporarily reduce the operating pressure of the pipeline or take other action
that ensures the safety of the covered segment. An operator must determine any
temporary reduction in operating pressure required by this section using
ASME/ANSI B31G (incorporated by reference, see § 192.7) or AGA Pipeline
Research Committee Project PR-3-805 ("RSTRENG," incorporated by reference, see
§ 192.7) or reduce the operating pressure to a level not exceeding 80
percent of the level at the time the condition was discovered. (See appendix A
to this part for information on availability of incorporation by reference
information.) An operator must notify PHMSA in accordance with § 192.949
if it cannot meet the schedule for evaluation and remediation required under
paragraph (c) of this section and cannot provide safety through temporary
reduction in operating pressure or other action. An operator must also notify a
State pipeline safety authority when either a covered segment is located in a
State where PHMSA has an interstate agent agreement, or an intrastate covered
segment is regulated by that State.
(2) Long-term pressure reduction. When a
pressure reduction exceeds 365 days, the operator must notify PHMSA under
§ 192.949 and explain the reasons for the remediation delay. This notice
must include a technical justification that the continued pressure reduction
will not jeopardize the integrity of the pipeline. The operator also must
notify a State pipeline safety authority when either a covered segment is
located in a State where PHMSA has an interstate agent agreement, or an
intrastate covered segment is regulated by that State.
(b)
Discovery of condition.
Discovery of 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. A condition that presents a potential threat
includes, but is not limited to, those conditions that require remediation or
monitoring listed under paragraphs (d)(1) through (d)(3) of this section. An
operator must promptly, but no later than 180 days after conducting an
integrity assessment, obtain sufficient information about a condition to make
that determination, unless the operator demonstrates that the 180-day period is
impracticable.
(c)
Schedule
for evaluation and remediation. An operator must complete remediation
of a condition according to a schedule prioritizing the conditions for
evaluation and remediation. Unless a special requirement for remediating
certain conditions applies, as provided in paragraph (d) of this section, an
operator must follow the schedule in ASME/ANSI B31.8S (incorporated by
reference, see § 192.7), section 7, Figure 4. If an operator cannot meet
the schedule for any condition, the operator must explain the reasons why it
cannot meet the schedule and how the changed schedule will not jeopardize
public safety.
(d)
Special
requirements for scheduling remediation.
(1)
Immediate repair
conditions. An operator's evaluation and remediation schedule must
follow ASME/ANSI B31.8S, section 7 in providing for immediate repair
conditions. To maintain safety, an operator must temporarily reduce operating
pressure in accordance with paragraph (a) of this section or shut down the
pipeline until the operator completes the repair of these conditions. An
operator must treat the following conditions as immediate repair conditions:
(i) A calculation of the remaining strength
of the pipe shows a predicted failure pressure less than or equal to 1.1 times
the maximum allowable operating pressure at the location of the anomaly.
Suitable remaining strength calculation methods include, ASME/ANSI B31G;
RSTRENG; or an alternative equivalent method of remaining strength calculation.
These documents are incorporated by reference and available at the addresses
listed in Appendix A to Part 192.
(ii) A dent that has any indication of metal
loss, cracking or a stress riser.
(iii) An indication or anomaly that in the
judgment of the person designated by the operator to evaluate the assessment
results requires immediate action.
(2) One-year conditions. Except for
conditions listed in paragraph (d)(1) and (d)(3) of this section, an operator
must remediate any of the following within one year of discovery of the
condition:
(i) A smooth dent located between
the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) with a depth
greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for
a pipeline diameter less than Nominal Pipe Size (NPS) 12).
(ii) A dent with a depth greater than 2% of
the pipeline's diameter (0.250 inches in depth for a pipeline diameter less
than NPS 12) that affects pipe curvature at a girth weld or at a longitudinal
seam weld.
(3) Monitored
conditions. An operator does not have to schedule the following conditions for
remediation, but must record and monitor the conditions during subsequent risk
assessments and integrity assessments for any change that may require
remediation:
(i) A dent with a depth greater
than 6% of the pipeline diameter (greater than 0.50 inches in depth for a
pipeline diameter less than NPS 12) located between the 4 o'clock position and
the 8 o'clock position (bottom 1/3 of the pipe).
(ii) A dent located between the 8 o'clock and
4 o'clock positions (upper 2/3 of the pipe) with a depth greater than 6% of the
pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter
less than Nominal Pipe Size (NPS) 12), and engineering analyses of the dent
demonstrate critical strain levels are not exceeded.
(iii) A dent with a depth greater than 2% of
the pipeline's diameter (0.250 inches in depth for a pipeline diameter less
than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam
weld, and engineering analyses of the dent and girth or seam weld demonstrate
critical strain levels are not exceeded. These analyses must consider weld
properties.
§ 192.935
What additional
preventive and mitigative measures must an operator take?
(a)
General Requirements. An
operator must take additional measures beyond those already required by Part
192 to prevent a pipeline failure and to mitigate the consequences of a
pipeline failure in a high consequence area. An operator must base the
additional measures on the threats the operator has identified to each pipeline
segment. (See § 192.917.) An operator must conduct, in accordance with one
of the risk assessment approaches in ASME/ANSI B31.8S (incorporated by
reference, see
§ 192.7), section 5, a risk analysis of
its pipeline to identify additional measures to protect the high consequence
area and enhance public safety. Such additional measures include, but are not
limited to, installing Automatic Shut-off Valves or Remote Control Valves,
installing computerized monitoring and leak detection systems, replacing pipe
segments with pipe of heavier wall thickness, providing additional training to
personnel on response procedures, conducting drills with local emergency
responders and implementing additional inspection and maintenance
programs.
(b)
Third Party
Damage and Outside Force Damage.
(1)
Third party damage. An operator must enhance its damage
prevention program, as required under § 192.614 of this part, with respect
to a covered segment to prevent and minimize the consequences of a release due
to third party damage. Enhanced measures to an existing damage prevention
program include, at a minimum-
(i) Using
qualified personnel (see § 192.915) for work an operator is conducting
that could adversely affect the integrity of a covered segment, such as
marking, locating, and direct supervision of known excavation work.
(ii) Collecting in a central database
information that is location specific on excavation damage that occurs in
covered and non covered segments in the transmission system and the root cause
analysis to support identification of targeted additional preventative and
mitigative measures in the high consequence areas. This information must
include recognized damage that is not required to be reported as an incident
under Part 191.
(iii) Participating
in one-call systems in locations where covered segments are present.
(iv) Monitoring of excavations conducted on
covered pipeline segments by pipeline personnel. If an operator finds physical
evidence of encroachment involving excavation that the operator did not monitor
near a covered segment, an operator must either excavate the area near the
encroachment or conduct an above ground survey using methods defined in NACE
SP0502-2008 (incorporated by reference, see
§ 192.7). An
operator must excavate, and remediate, in accordance with ANSI/ASME B31.8S and
§ 192.933 any indication of coating holidays or discontinuity warranting
direct examination.
(2)
Outside force damage. If an operator determines that outside force (e.g., earth
movement, floods, unstable suspension bridge) is a threat to the integrity of a
covered segment, the operator must take measures to minimize the consequences
to the covered segment from outside force damage. These measures include, but
are not limited to, increasing the frequency of aerial, foot or other methods
of patrols, adding external protection, reducing external stress, and
relocating the line.
(c)
Automatic shut-off valves (ASV) or Remote control valves
(RCV). If an operator determines, based on a risk analysis, that an
ASV or RCV would be an efficient means of adding protection to a high
consequence area in the event of a gas release, an operator must install the
ASV or RCV. In making that determination, an operator must, at least, consider
the following factors -swiftness of leak detection and pipe shutdown
capabilities, the type of gas being transported, operating pressure, the rate
of potential release, pipeline profile, the potential for ignition, and
location of nearest response personnel.
(d)
Pipelines operating below 30%
SMYS. An operator of a transmission pipeline operating below 30% SMYS
located in a high consequence area must follow the requirements in paragraphs
(d)(1) and (d)(2) of this section. An operator of a transmission pipeline
operating below 30% SMYS located in a Class 3 or Class 4 area but not in a high
consequence area must follow the requirements in paragraphs (d)(1), (d)(2) and
(d)(3) of this section.
(1) Apply the
requirements in paragraphs (b)(1)(i) and (b)(1)(iii) of this section to the
pipeline; and
(2) Either monitor
excavations near the pipeline, or conduct patrols as required by § 192.705
of the pipeline at bi-monthly intervals. If an operator finds any indication of
unreported construction activity, the operator must conduct a follow up
investigation to determine if mechanical damage has occurred.
(3) Perform semi-annual leak surveys
(quarterly for unprotected pipelines or cathodically protected pipe where
electrical surveys are impractical).
(e)
Plastic transmission
pipeline. An operator of a plastic transmission pipeline must apply
the requirements in paragraphs (b)(1)(i), (b)(1)(iii) and b(1)(iv) of this
section to the covered segments of the pipeline.
§ 192.937
What is a continual
process of evaluation and assessment to maintain a pipeline's integrity?
(a)
General. After
completing the baseline integrity assessment of a covered segment, an operator
must continue to assess the line pipe of that segment at the intervals
specified in § 192.939 and periodically evaluate the integrity of each
covered pipeline segment as provided in paragraph (b) of this section. An
operator must reassess a covered segment on which a prior assessment is
credited as a baseline under § 192.921(e) by no later than December 17,
2009. An operator must reassess a covered segment on which a baseline
assessment is conducted during the baseline period specified in §
192.921(d) by no later than seven years after the baseline assessment of that
covered segment unless the evaluation under paragraph (b) of this section
indicates earlier reassessment.
(b)
Evaluation. An operator must conduct a periodic evaluation as
frequently as needed to assure the integrity of each covered segment. The
periodic evaluation must be based on a data integration and risk assessment of
the entire pipeline as specified in § 192.917. For plastic transmission
pipelines, the periodic evaluation is based on the threat analysis specified in
§ 192.917(d). For all other transmission pipelines, the evaluation must
consider the past and present integrity assessment results, data integration
and risk assessment information (§ 192.917), and decisions about
remediation (§ 192.933) and additional preventive and mitigative actions
(§ 192.935). An operator must use the results from this evaluation to
identify the threats specific to each covered segment and the risk represented
by these threats.
(c)
Assessment methods. In conducting the integrity reassessment,
an operator must assess the integrity of the line pipe in the covered segment
by any of the following methods as appropriate for the threats to which the
covered segment is susceptible (see § 192.917), or by confirmatory direct
assessment under the conditions specified in § 192.931.
(1) Internal inspection tool or tools capable
of detecting corrosion, and any other threats to which the covered segment is
susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by
reference, see
§ 192.7), section 6.2 in selecting the
appropriate internal inspection tools for the covered segment.
(2) Pressure test conducted in accordance
with subpart J of this part. An operator must use the test pressures specified
in Table 3 of section 5 of ASME/ANSI B31.8S, to justify an extended
reassessment interval in accordance with § 192.939.
(3) Direct assessment to address threats of
external corrosion, internal corrosion, or stress corrosion cracking. An
operator must conduct the direct assessment in accordance with the requirements
listed in § 192.923 and with as applicable, the requirements specified in
§§ 192.925, 192.927 or 192.929;
(4) Other technology that an operator
demonstrates can provide an equivalent understanding of the condition of the
line pipe. An operator choosing this option must notify the Office of Pipeline
Safety (OPS) 180 days before conducting the assessment, in accordance with
§ 192.949. An operator must also notify a State or local pipeline safety
authority when either a covered segment is located in a State where OPS has an
interstate agent agreement, or an intrastate covered segment is regulated by
that State.
(5) Confirmatory direct
assessment when used on a covered segment that is scheduled for reassessment at
a period longer than seven years. An operator using this reassessment method
must comply with § 192.931.
§ 192.939
What are the required
reassessment intervals?
An operator must comply with the following requirements in
establishing the reassessment interval for the operator's covered pipeline
segments.
(a)
Pipelines
operating at or above 30% SMYS. An operator must establish a
reassessment interval for each covered segment operating at or above 30% SMYS
in accordance with the requirements of this section. The maximum reassessment
interval by an allowable reassessment method is seven years. If an operator
establishes a reassessment interval that is greater than seven years, the
operator must, within the seven-year period, conduct a confirmatory direct
assessment on the covered segment, and then conduct the follow-up reassessment
at the interval the operator has established. A reassessment carried out using
confirmatory direct assessment must be done in accordance with § 192.931.
The table that follows this section sets forth the maximum allowed reassessment
intervals.
(1)
Pressure test or
internal inspection or other equivalent technology. An operator that
uses pressure testing or internal inspection as an assessment method must
establish the reassessment interval for a covered pipeline segment by -
(i) Basing the interval on the identified
threats for the covered segment (see § 192.917) and on the analysis of the
results from the last integrity assessment and from the data integration and
risk assessment required by § 192.917; or
(ii) Using the intervals specified for
different stress levels of pipeline (operating at or above 30% SMYS) listed in
ASME/ANSI B31.8S, section 5, Table 3.
(2)
External Corrosion Direct
assessment. An operator that uses ECDA that meets the requirements of
this subpart must determine the reassessment interval according to the
requirements in paragraphs 6.2 and 6.3 of NACE SP0502-2008 (incorporated by
reference, see
§ 192.7).
(3)
Internal Corrosion or SCC Direct
Assessment. An operator that uses ICDA or SCCDA in accordance with the
requirements of this subpart must determine the reassessment interval according
to the following method. However, the reassessment interval cannot exceed those
specified for direct assessment in ASME/ANSI B31.8S, section 5, Table 3.
(i) Determine the largest defect most likely
to remain in the covered segment and the corrosion rate appropriate for the
pipe, soil and protection conditions;
(ii) Use the largest remaining defect as the
size of the largest defect discovered in the SCC or ICDA segment; and
(iii) Estimate the reassessment interval as
half the time required for the largest defect to grow to a critical
size.
(b)
Pipelines Operating Below 30% SMYS. An operator must establish
a reassessment interval for each covered segment operating below 30% SMYS in
accordance with the requirements of this section. The maximum reassessment
interval by an allowable reassessment method is seven years. An operator must
establish reassessment by at least one of the following -
(1) Reassessment by pressure test, internal
inspection or other equivalent technology following the requirements in
paragraph (a)(1) of this section except that the stress level referenced
in(a)(1) (ii) would be adjusted to reflect the lower operating stress level. If
an established interval is more than seven years, the operator must conduct by
the seventh year of the interval either a confirmatory direct assessment in
accordance with § 192.931, or a low stress reassessment in accordance with
§ 192.941.
(2) Reassessment by
ECDA following the requirements in paragraph (a)(2) of this section.
(3) Reassessment by ICDA or SCCDA following
the requirements in paragraph (a)(3) of this section.
(4) Reassessment by confirmatory direct
assessment at 7-year intervals in accordance with § 192.931, with
reassessment by one of the methods listed in (b)(1)-(b)(3) of this section by
year 20 of the interval.
(5)
Reassessment by the low stress assessment method at 7-year intervals in
accordance with § 192.941 with reassessment by one of the methods listed
in paragraphs (b)(1) through (b)(3) of this section by year 20 of the
interval.
(6) The following table
sets forth the maximum reassessment intervals. Also refer to Appendix E.II for
guidance on Assessment Methods and Assessment Schedule for Transmission
Pipelines Operating Below 30% SMYS. In case of conflict between the rule and
the guidance in the Appendix, the requirements of the rule control. An operator
must comply with the following requirements in establishing a reassessment
interval for a covered segment: An operator must comply with the following
requirements in establishing a reassessment interval for a covered segment:
|
Maximum Reassessment Interval
|
|
Assessment Method
|
Pipeline operating at or above 50% SMYS
|
Pipeline operating at or above 30% SMYS, up to 50%
SMYS
|
Pipeline operating below 30% SMYS
|
|
Internal Inspection Tool, Pressure Test or Direct
Assessment
|
10 years(*)
|
15 years(*)
|
20 years(**)
|
|
Confirmatory Direct Assessment
|
7 years
|
7 years
|
7 years
|
|
Low stress Reassessment
|
Not applicable
|
Not applicable
|
7 years + ongoing actions specified in §
192.941
|
(*) A Confirmatory direct assessment as described in §
192.931 must be conducted by year 7 in a 10-year interval and years 7 and 14 of
a 15-year interval.
(**) A low stress reassessment or Confirmatory direct
assessment must be conducted by years 7 and 14 of the interval.
§
192.941
What is a low stress reassessment?
(a)
General. An operator of
a transmission line that operates below 30% SMYS may use the following method
to reassess a covered segment in accordance with § 192.939. This method of
reassessment addresses the threats of external and internal corrosion. The
operator must have conducted a baseline assessment of the covered segment in
accordance with the requirements of §§ 192.919 and 192.921.
(b)
External Corrosion. An
operator must take one of the following actions to address external corrosion
on the low stress covered segment.
(1)
Cathodically Protected Pipe. To address the threat of external
corrosion on cathodically protected pipe in a covered segment, an operator must
perform an electrical survey (i.e. indirect examination tool/method) at least
every 7 years on the covered segment. An operator must use the results of each
survey as part of an overall evaluation of the cathodic protection and
corrosion threat for the covered segment. This evaluation must consider, at
minimum, the leak repair and inspection records, corrosion monitoring records,
exposed pipe inspection records, and the pipeline environment.
(2)
Unprotected Pipe or Cathodically
Protected Pipe Where Electrical Surveys are Impractical. If an
electrical survey is impractical on the covered segment an operator must -
(i) Conduct leakage surveys as required by
§ 192.706 at 4-month intervals; and
(ii) Every 18 months, identify and remediate
areas of active corrosion by evaluating leak repair and inspection records,
corrosion monitoring records, exposed pipe inspection records, and the pipeline
environment.
(c)
Internal Corrosion. To
address the threat of internal corrosion on a covered segment, an operator must
-
(1) Conduct a gas analysis for corrosive
agents at least once each calendar year;
(2) Conduct periodic testing of fluids
removed from the segment. At least once each calendar year test the fluids
removed from each storage field that may affect a covered segment;
and
(3) At least every seven (7)
years, integrate data from the analysis and testing required by paragraphs
(c)(1)-(c)(2) with applicable internal corrosion leak records, incident
reports, safety- related condition reports, repair records, patrol records,
exposed pipe reports, and test records, and define and implement appropriate
remediation actions.
§ 192.943
When can an operator
deviate from these reassessment intervals?
(a)
Waiver from reassessment interval
in limited situations. In the following limited instances, OPS may
allow a waiver from a reassessment interval required by § 192.939 if OPS
finds a waiver would not be inconsistent with pipeline safety.
(1)
Lack of internal inspection
tools. An operator who uses internal inspection as an assessment
method may be able to justify a longer reassessment period for a covered
segment if internal inspection tools are not available to assess the line pipe.
To justify this, the operator must demonstrate that it cannot obtain the
internal inspection tools within the required reassessment period and that the
actions the operator is taking in the interim ensure the integrity of the
covered segment.
(2)
Maintain product supply. An operator may be able to justify a
longer reassessment period for a covered segment if the operator demonstrates
that it cannot maintain local product supply if it conducts the reassessment
within the required interval.
(b)
How to apply. If one of
the conditions specified in paragraph (a)(1) or (a)(2) of this section applies,
an operator may seek a waiver of the required reassessment interval. An
operator must apply for a waiver in accordance with
49 U.S.C.
60118(c), at least 180 days
before the end of the required reassessment interval, unless local product
supply issues make the period impractical. If local product supply issues make
the period impractical, an operator must apply for the waiver as soon as the
need for the waiver becomes known.
§ 192.945
What methods must an
operator use to measure program effectiveness?
(a)
General. An operator
must include in its integrity management program methods to measure whether the
program is effective in assessing and evaluating the integrity of each covered
pipeline segment and in protecting the high consequence areas. These measures
must include the four overall performance measures specified in ASME/ANSI
B31.8S (incorporated by reference, see
§ 192.7 of this
part), section 9.4, and the specific measures for each identified threat
specified in ASME/ANSI B31.8S, Appendix A. An operator must submit the four
overall performance measures as part of the annual report required by §
191.17 of this subchapter.
(b)
External Corrosion Direct assessment. In addition to the
general requirements for performance measures in paragraph (a) of this section,
an operator using direct assessment to assess the external corrosion threat
must define and monitor measures to determine the effectiveness of the ECDA
process. These measures must meet the requirements of § 192.925.
§ 192.947
What records
must an operator keep?
An operator must maintain, for the useful life of the pipeline,
records that demonstrate compliance with the requirements of this subpart. At
minimum, an operator must maintain the following records for review during an
inspection.
(a) A written integrity
management program in accordance with § 192.907;
(b) Documents supporting the threat
identification and risk assessment in accordance with § 192.917;
(c) A written baseline assessment plan in
accordance with § 192.919;
(d)
Documents to support any decision, analysis and process developed and used to
implement and evaluate each element of the baseline assessment plan and
integrity management program. Documents include those developed and used in
support of any identification, calculation, amendment, modification,
justification, deviation and determination made, and any action taken to
implement and evaluate any of the program elements;
(e) Documents that demonstrate personnel have
the required training, including a description of the training program, in
accordance with § 192.915;
(f)
Schedule required by § 192.933 that prioritizes the conditions found
during an assessment for evaluation and remediation, including technical
justifications for the schedule.
(g) Documents to carry out the requirements
in §§ 192.923 through 192.929 for a direct assessment plan;
(h) Documents to carry out the requirements
in § 192.931 for confirmatory direct assessment;
(i) Verification that an operator has
provided any documentation or notification required by this subpart to be
provided to OPS, and when applicable, 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.
§ 192.949
How does an operator
notify PHMSA
An operator must provide any notification required by this
subpart by -
(a) Sending the
notification to the 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;
(b) Sending the notification by fax to (202)
366-4566; or
(c) Entering the
information directly on the Integrity Management Database (IMDB) Web site at
http://primis.phmsa.dot.gov/gasimp/.
§ 192.951
Where does
an operator file a report?
An operator must send any performance report required by this
subpart to the Information Resources Manager through the online reporting
system provided by PHMSA for electronic reporting available at the PHMSA Home
Page at http://phmsa.dot.gov.
SUBPART P
- GAS DISTRIBUTION PIPELINE
INTEGRITY MANAGEMENT (IM)
§
192.1001
What definitions apply to this subpart?
The following definitions apply to this subpart:
Excavation Damage means any
impact that results in the need to repair or replace an underground facility
due to a weakening, or the partial or complete destruction, of the facility,
including, but not limited to, the protective coating, lateral support,
cathodic protection or the housing for the line device or facility.
Hazardous Leak means a leak that
represents an existing or probably hazard to persons or property and requires
immediate repair or continuous action until the conditions are no longer
hazardous.
Integrity Management Plan or IM
Plan means a written explanation of the mechanisms or
procedures the operator will use to implement its integrity management program
and to ensure compliance with this subpart.
Integrity Management Program or IM
Program means an overall approach by an operator to ensure the
integrity of its gas distribution system.
Mechanical fitting means a
mechanical device used to connect sections of pipe. The term "Mechanical
fitting" applies only to:
(1) Stab
Type fittings;
(2) Nut Follower
Type fittings;
(3) Bolted Type
fittings; or
(4) Other Compression
Type fittings.
Small LPG Operator means an
operator of a liquefied petroleum gas (LPG) distribution pipeline that serves
fewer than 100 customers from a single source.
§ 192.1003
What do the
regulations in this subpart cover?
General. This subpart prescribes minimum
requirements for an IM program for any gas distribution pipeline covered under
this part, including liquefied petroleum gas systems. A gas distribution
operator, other than a master meter operator or a small LPG operator, must
follow the requirements in §§ 192.1005-192.1013 of this subpart. A
master meter operator or small LPG operator of a gas distribution pipeline must
follow the requirements in § 192.1015 of this subpart.
§ 192.1005
What must a gas
distribution operator (other than a master meter or small LPG operator) do to
implement this subpart?
No later than August 2, 2011 a gas distribution operator must
develop and implement an integrity management program that includes a written
integrity management plan as specified in § 192.1007.
§ 192.1007
What are the required
elements of an integrity management plan?
A written integrity management plan must contain procedures for
developing and implementing the following elements:
(a)
Knowledge. An operator
must demonstrate an understanding of its gas distribution system developed from
reasonably available information.
(1) Identify
the characteristics of the pipeline's design and operations and the
environmental factors that are necessary to assess the applicable threats and
risks to its gas distribution pipeline.
(2) Consider the information gained from past
design, operations, and maintenance.
(3) Identify additional information needed
and provide a plan for gaining that information over time through normal
activities conducted on the pipeline (for example, design, construction,
operations or maintenance activities).
(4) Develop and implement a process by which
the IM program will be reviewed periodically and refined and improved as
needed.
(5) Provide for the
capture and retention 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.
(b)
Identify Threats. The
operator must 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
operations, 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.
(c)
Evaluate and rank risk. An operator 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.
(d)
Identify and
implement measures to 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).
(e)
Measure performance, monitor results, and evaluate
effectiveness.
(1) Develop and
monitor performance 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 re-evaluating the threats and risks.
These performance measures must include the following:
(i) Number of hazardous leaks either
eliminated or repaired as required by § 192.703(c) of this subchapter (or
total number of leaks if all leaks are repaired when found), categorized by
cause;
(ii) Number of excavation
damages;
(iii) Number of
excavation tickets (receipt of information by the underground facility operator
from the notification center);
(iv) Total number of leaks either eliminated
or repaired, categorized by cause;
(v) Number of hazardous leaks either
eliminated or repaired as required by § 192.703(c) (or total number of
leaks if all leaks are repaired when found), categorized by material; and
(vi) Any additional measures the
operator determines are needed to evaluate the effectiveness of the operator's
IM program in controlling each identified threat.
(f)
Periodic Evaluation
and Improvement. An operator must reevaluate threats and risks on its
entire pipeline and consider the relevance of threats in one 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 years. The operator must consider the
results of the performance monitoring in these evaluations.
(g)
Report results. Report,
on an annual basis, the four measures listed in paragraphs (e)(1)(i) through
(e)(1)(iv) of this section, as part of the annual report required by §
191.11. An operator also must report the four measures to the state pipeline
safety authority if a state exercises jurisdiction over the operator's
pipeline.
§
192.1009
What must an operator report when a mechanical
fitting fails?
(a) Except as provided
in paragraph (b) of this section, 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, on a Department of
Transportation Form PHMSA F-7100.1-2. The report(s) must be submitted in
accordance with § 191.12.
(b)
The mechanical fitting failure reporting requirements in paragraph (a) of this
section do not apply to the following:
(1)
Master meter operators;
(2) Small
LPG operator as defined in § 192.1001: or
(3) LNG facilities.
§ 192.1011
What
records must an operator keep?
An operator must maintain records demonstrating compliance with
the requirements of this subpart for at least 10 years. The records must
include copies of superseded integrity management plans developed under this
subpart.
§ 192.1013
When may an operator deviate from required periodic inspections under
this part?(a) An operator may propose
to reduce the frequency of periodic inspections and tests required in this part
on the basis of the engineering analysis and risk assessment required by this
subpart.
(b) An operator must
submit its proposal to the PHMSA Associate Administrator for Pipeline Safety
or, in the case of an intrastate pipeline facility regulated by the State, the
appropriate State agency. The applicable oversight agency may accept the
proposal on its own authority, with or without conditions and limitations, on a
showing that the operator's proposal, which includes the adjusted interval,
will provide an equal or greater overall level of safety,
(c) An operator may implement an 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.
§ 192.1015
What must a master
meter or small liquefied petroleum gas (LPG) operator do to implement this
subpart?
(a)
General.
No later than August 2, 2011, the operator of a master meter system or a small
LPG operator must develop and implement an IM program that includes a written
IM plan as specified in paragraph (b) of this section. The IM program for these
pipelines should reflect the relative simplicity of these types of
pipelines.
(b)
Elements. A written integrity management plan must address, at
a minimum, the following elements:
(1)
Knowledge. The operator must 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 (for example, design, construction,
operations or maintenance activities).
(2)
Identify threats. The
operator must 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.
(3)
Rank risks. The operator must evaluate the risks to its
pipeline and estimate the relative importance of each identified
threat.
(4)
Identify and
implement measures to mitigate risks. The operator must determine and
implement measures designed to reduce the risks from failure of its
pipeline.
(5)
Measure
performance, monitor 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.
(6)
Periodic evaluation and
improvement. 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 years. The operator must consider the
results of the performance monitoring in these evaluations.
(c)
Records. The
operator must maintain, for a period of at least 10 years, the following
records:
(1) A written IM plan in accordance
with this section, including superseded IM plans;
(2) Documents supporting threat
identification; and
(3) Documents
showing the location 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 TO PART 192 - RESERVED
APPENDIX B TO PART 192 - QUALIFICATION OF
PIPE
I.
Listed Pipe
Specifications.
API 5L-Steel Pipe, "API Specification for Line Pipe"
(incorporated by reference, see
§ 192.7).
ASTM A53/A53M-Steel Pipe, "Standard Specification for Pipe,
Steel Black and Hot-Dipped, Zinc-Coated, Welded and Seamless" (incorporated by
reference, see § 192.7).
ASTM A106-Steel Pipe, "Standard Specification for Seamless
Carbon Steel Pipe for High Temperature Service" (incorporated by reference,
see
§ 192.7).
ASTM A333/A333M-Steel Pipe, "Standard Specification for
Seamless and Welded Steel Pipe for Low Temperature Service" (incorporated by
reference, see
§ 192.7).
ASTM A381-Steel pipe, "Standard Specification for
Metal-Arc-Welded Steel Pipe for Use with High-Pressure Transmission Systems"
(incorporated by reference, see
§ 192.7).
ASTM A671-Steel pipe, "Standard Specification for
Electric-Fusion- Welded Pipe for Atmospheric and Lower Temperatures"
(incorporated by reference, see
§ 192.7).
ASTM A672-Steel pipe, "Standard Specification for
Electric-Fusion- Welded Steel Pipe for High-Pressure Service at Moderate
Temperatures" (incorporated by reference, see
§
192.7).
ASTM A691-Steel pipe "Standard Specification for Carbon and
Alloy Steel Pipe, Electric-Fusion-Welded for High Pressure Service at High
Temperatures" (incorporated by reference, see
§
192.7).
ASTM D2513-99-Thermoplastic pipe and tubing, "Standard
Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings"
(incorporated by reference, see
§ 192.7).
ASTM D2517-Thermosetting plastic pipe and tubing, "Standard
Specification Reinforced Epoxy Resin Gas Pressure Pipe and Fittings"
(incorporated by reference, see
§ 192.7).
II.
Steel Pipe of
Unknown or Unlisted Specification.
A.
Bending
Properties. For pipe 2 inches (51 millimeters) or less in
diameter, a length of pipe must be cold bent through at least 90 degrees around
a cylindrical mandrel that has a diameter 12 times the diameter of the pipe,
without developing cracks at any portion and without opening the longitudinal
weld. For pipe more than 2 inches (51 millimeters) in diameter, the pipe must
meet the requirements of the flattening tests set forth in ASTM A53
(incorporated by reference, see § 192.7) except that the number of tests
must be at least equal to the minimum required in paragraph II-D of this
appendix to determine yield strength.
B.
Weldability.
A girth weld must be made in the pipe by a welder who is qualified under
subpart E of this part. The weld must be made under the most severe conditions
under which welding will be allowed in the field and by means of the same
procedure that will be used in the field. On pipe more than 4 inches (102
millimeters) in diameter, at least one test weld must be made for each 100
lengths of pipe. On pipe 4 inches (102 millimeters) or less in diameter, at
least one test weld must be made for each 400 lengths of pipe. The weld must be
tested in accordance with API Standard 1104 (incorporated by reference, see
§ 192.7). If the requirements of API Standard 1104 cannot be met,
weldability may be established by making chemical tests for carbon and
manganese, and proceeding in accordance with section IX of the ASME Boiler and
Pressure Vessel Code (incorporated by reference, see
§
192.7). The same number of chemical tests must be made as are required for
testing a girth weld.
C.
Inspection. The pipe must be clean enough to
permit adequate inspection. It must be visually inspected to ensure that it is
reasonably round and straight and there are no defects which might impair the
strength or tightness of the pipe.
D.
Tensile
properties. If the tensile properties of the pipe are not
known, the minimum yield strength may be taken as 24,000 p.s.i. (165 MPa) or
less, or the tensile properties may be established by performing tensile test
as set forth in API Specification 5L (incorporated by reference,
see
§ 192.7). All test specimens shall be selected at
random and the following number of tests must be performed.
Number of Tensile Tests - All Sizes
|
10 lengths or less
|
1 set of tests for each length.
|
|
11 to 100 lengths
|
1 set of tests for each 5 lengths, but not less than 10
tests.
|
|
Over 100 lengths
|
1 set of tests for each 10 lengths, but not less than
20 tests.
|
If the yield-tensile ratio, based on the properties determined
by those tests, exceeds 0.85, the pipe may be used only as provided in §
192.55 (c).
III.
Steel Pipe Manufactured Before November 12, 1970, to Earlier
Editions of Listed Specifications.
Steel pipe manufactured before November 12, 1970, in accordance
with a specification of which a later edition is listed in Section I of this
appendix, is qualified for use under this part if the following requirements
are met:
A.
Inspection. The pipe must be clean enough to
permit adequate inspection. It must be visually inspected to ensure that it is
reasonably round and straight and that there are no defects which might impair
the strength or tightness of the pipe.
B.
Similarity of specification
requirements. The edition of the listed specification under
which the pipe was manufactured must have substantially the same requirements
with respect to the following properties as a later edition of that
specification listed in Section I of this appendix:
(1) Physical (mechanical) properties of pipe,
including yield and tensile strength, elongation, and yield to tensile ratio,
and testing requirements to verify those properties.
(2) Chemical properties of pipe and testing
requirements to verify those properties.
C.
Inspection or test of welded
pipe. On pipe with welded seams, one of the following
requirements must be met:
(1) The edition of
the listed specification to which the pipe was manufactured must have
substantially the same requirements with respect to nondestructive inspection
of welded seams and the standards for acceptance or rejection and repair as a
later edition of the specification listed in Section I of this
appendix.
(2) The pipe must be
tested in accordance with Subpart J of this part to at least 1.25 times the
maximum allowable operating pressure if it is to be installed in a Class 1
location and to at least 1.5 times the maximum allowable operating pressure if
it is to be installed in a Class 2, 3 or 4 location. Notwithstanding any
shorter time period permitted under Subpart J of this part, the test pressure
must be maintained for at least 8 hours.
APPENDIX C TO PART 192 - QUALIFICATION OF WELDERS FOR LOW
STRESS LEVEL PIPE
I.
Basic Test.
The test is made on pipe 12 inches (305 millimeters) or less in
diameter. The test weld must be made with the pipe in a horizontal fixed
position so that the test weld includes at least one section of overhead
position welding. The beveling, root opening and other details must conform to
the specifications of the procedure under which the welder is being qualified.
Upon completion, the test weld is cut into four coupons and subjected to a root
bend test. If, as a result of this test, two or more of the four coupons
develop a crack in the weld material or between the weld material and base
metal, that is more than 1/8inch (3.2 millimeters) long in any direction, the
weld is unacceptable. Cracks that occur on the corner of the specimen during
testing are not considered. A welder who successfully passes a butt-weld
qualification test under this section shall be qualified to weld on all pipe
diameters less than or equal to 12 inches.
II.
Additional Tests for
Welders of Service Line Connections to Mains.
A service line connection fitting is welded to a pipe section
with the same diameter as a typical main. The weld is made in the same position
as it is made in the field. The weld is unacceptable if it shows a serious
undercutting or if it has rolled edges. The weld is tested by attempting to
break the fitting off the run pipe. The weld is unacceptable if it breaks and
shows incomplete fusion, overlap, or poor penetration at the junction of the
fitting and run pipe.
III.
Periodic Tests for Welders of Small Service
Lines.
Two samples of the welder's work, each about 8 inches (203
millimeters) long with the weld located approximately in the center, are cut
from steel service line and tested as follows:
(1) One sample is centered in a guided bend
testing machine and bent to the contour of the die for a distance of 2 inches
(51 millimeters) on each side of the weld. If the sample shows any breaks or
cracks after removal from the bending machine, it is unacceptable.
(2) The ends of the second sample are
flattened and the entire joint subjected to a tensile strength test. If failure
occurs adjacent to or in the weld metal, the weld is unacceptable. If a tensile
strength testing machine is not available, this sample must also pass the
bending test prescribed in Subparagraph (1) of this paragraph.
APPENDIX D TO PART 192 - CRITERIA FOR CATHODIC PROTECTION
AND DETERMINATION OF MEASUREMENTS
I.
Criteria for Cathodic
Protection.A. Steel, cast iron, and
ductile iron structures.
(1) A negative
(cathodic) voltage of at least 0.85 volt, with reference to a saturated
copper-copper sulfate half cell. Determination of this voltage must be made
with the protective current applied, and in accordance with Sections II and IV
of this appendix.
(2) A negative
(cathodic) voltage shift of at least 300 millivolts. Determination of this
voltage shift must be made with the protective current applied, and in
accordance with Sections II and IV of this appendix. This criterion of voltage
shift applies to structures not in contact with metal of different anodic
potentials.
(3) A minimum negative
(cathodic) polarization voltage shift of 100 millivolts. This polarization
voltage shift must be determined in accordance with Sections III and IV of this
appendix.
(4) A voltage at least as
negative (cathodic) as that originally established at the beginning of the
Tafel segment of the E-log-I curve. This voltage must be measured in accordance
with Section IV of this appendix.
(5) A net protective current from the
electrolyte into the structure surface as measured by an earth current
technique applied at predetermined current discharge (anodic) points of the
structure.
B. Aluminum
structures.
(1) Except as provided in
Subparagraphs (3) and (4) of this paragraph, a minimum negative (cathodic)
voltage shift of 150 millivolts, produced by the application of protective
current. The voltage shift must be determined in accordance with Sections II
and IV of this appendix.
(2) Except
as provided in Subparagraphs (3) and (4) of this paragraph, a minimum negative
(cathodic) polarization voltage shift of 100 millivolts. This polarization
voltage shift must be determined in accordance with Sections III and IV of this
appendix.
(3) Notwithstanding the
alternative minimum criteria in Subparagraphs (1) and (2) of this paragraph,
aluminum, if cathodically protected at voltages in excess of 1.20 volts as
measured with reference to a copper-copper sulfate half cell, in accordance
with Section IV of this appendix, and compensated for the voltage (IR) drops
other than those across the structure-electrolyte boundary, may suffer
corrosion resulting from the buildup of alkali on the metal surface. A voltage
in excess of 1.20 volts may not be used unless previous test results indicate
no appreciable corrosion will occur in the particular environment.
(4) Since aluminum may suffer from corrosion
under high pH conditions, and since application of cathodic protection tends to
increase the pH at the metal surface, careful investigation or testing must be
made before applying cathodic protection to stop pitting attack on aluminum
structures in environments with a natural pH in excess of 8.
C. Copper structures. A minimum
negative (cathodic) polarization voltage shift of 100 millivolts. This
polarization voltage shift must be determined in accordance with Sections III
and IV of this appendix.
D. Metals
of different anodic potentials. A negative (cathodic) voltage, measured in
accordance with Section IV of this appendix, equal to that required for the
most anodic metal in the system must be maintained. If amphoteric structures
are involved that could be damaged by high alkalinity covered by Subparagraphs
(3) and (4) of paragraph B of this section, they must be electrically isolated
with insulating flanges, or the equivalent.
II.
Interpretation of Voltage
Measurement. Voltage (IR) drops other than those across the
structure-electrolyte boundary must be considered for valid interpretation of
the voltage measurement in paragraphs A(1) and (2) and paragraph B(1) of
Section I of this appendix.
III.
Determination of Polarization Voltage Shift. The polarization
voltage shift must be determined by interrupting the protective current and
measuring the polarization decay. When the current is initially interrupted, an
immediate voltage shift occurs. The voltage reading after the immediate shift
must be used as the base reading from which to measure polarization decay in
paragraphs A(3), B(2), and C of Section I of this appendix.
IV.
Reference Half Cells.
A. Except as provided in paragraphs B and C
of this section, negative (cathodic) voltage must be measured between the
structure surface and a saturated copper-copper sulfate half cell contacting
the electrolyte.
B. Other standard
reference half cells may be substituted for the saturated copper-copper sulfate
half cell. Two commonly used reference half cells are listed below along with
their voltage equivalent to -0.85 volt as referred to a saturated copper-
copper sulfate half cell:
(1) Saturated KCl
calomel half cell: -0.78 volt.
(2)
Silver-silver chloride half cell used in sea water: -0.80 volt.
C. In addition to the standard
reference half cells, an alternate metallic material or structure may be used
in place of the saturated copper sulfate half cell if its potential stability
is assured and if its voltage equivalent referred to a saturated copper-copper
sulfate half cell is established.
APPENDIX E TO PART 192 - GUIDANCE ON DETERMINING HIGH
CONSEQUENCE AREAS AND ON CARRYING OUT REQUIREMENTS IN THE INTEGRITY MANAGEMENT
RULE
I.
Guidance on
Determining a High Consequence Area
To determine which segments of an operator's transmission
pipeline system are covered for purposes of the integrity management program
requirements, an operator must identify the high consequence areas. An operator
must use method (1) or (2) from the definition in § 192.903 to identify a
high consequence area. An operator may apply one method to its entire pipeline
system, or an operator may apply one method to individual portions of the
pipeline system. (Refer to figure E.I.A for a diagram of a high consequence
area).
Determining High Consequence
Area
Click here
to view image
Figure E.I.A
II.
Guidance on Assessment Methods
and Additional Preventive and Mitigative Measures for Transmission
Pipelines
(a) Table E.II.1 gives
guidance to help an operator implement requirements on additional preventive
and mitigative measures for addressing time dependent and independent threats
for a transmission pipeline operating below 30% SMYS not in an HCA (i.e.
outside of potential impact circle) but located within a Class 3 or Class 4
Location.
(b) Table E.II.2 gives
guidance to help an operator implement requirements on assessment methods for
addressing time dependent and independent threats for a transmission pipeline
in an HCA.
(c) Table E.II.3 gives
guidance on preventative & mitigative measures addressing time dependent
and independent threats for transmission pipelines that operate below 30% SMYS,
in HCAs.
Table E.II.1
Preventive and Mitigative Measures for Transmission
Pipelines Operating Below 30% SMYS not in an HCA but in a Class 3 or Class 4
Location
|
(Column 1) Threat
|
Existing 192 Requirements
|
(Column 4)
Additional(to 192 requirements) Preventive and
Mitigative Measures
|
|
(Column 2) Primary
|
(Column 3) Secondary
|
|
External Corrosion
|
455-(Gen. Post 1971), 457-(Gen. Pre-1971)
459-(Examination), 461-(Ext. coating) 463-(CP), 465-(Monitoring) 467-(Elect
isolation), (469-Test stations)
471-(Test leads), 473-(Interference)
479-(Atmospheric), 481-(Atmospheric) 485-(Remedial),
705-(Patrol) 706-(Leak survey), 711 -(Repair - gen.) 717-(Repair -
perm.)
|
603-(Gen Oper'n) 613-(Surveillance)
|
For Cathodically Protected Transmission
Pipeline:
. Perform semi-annual leak surveys.
For Unprotected Transmission Pipelines or for
Cathodically Protected Pipe where Electrical Surveys are Impractical:
. Perform quarterly leak surveys
|
|
Internal Corrosion
|
475-(Gen IC), 477-(IC monitoring) 485-(Remedial),
705-(Patrol) 706-(Leak survey), 711-(Repair - gen.) 717-(Repair - perm.)
|
53(a)-(Materials) 603-(Gen Oper'n)
613-(Surveillance)
|
. Perform semi-annual leak surveys.
|
|
3rd Party Damage
|
103-(Gen. Design), 111-(Design factor) 317-(Hazard
prot), 327-(Cover)
614-(Dam. Prevent), 616-(Public education)
705-(Patrol), 707-(Line markers)
711 (Repair - gen.), 717-(Repair - perm.)
|
615-(Emerg. Plan)
|
. Participation in state one-call system,
. Use of qualified operator employees and contractors
to perform marking and locating of buried structures and in direct supervision
of excavation work, AND
. Either monitoring of excavations near operator's
transmission pipelines, or bi-monthly patrol of transmission pipelines in class
3 and 4 locations. Any indications of unreported construction activity would
require a follow up investigation to determine if mechanical damage
occurred.
|
Table E.II.2
Assessment Requirements for Transmission Pipelines in
HCAs (Re-assessment intervals are maximum allowed)
|
|
Re-Assessment Requirements (see Note 3)
|
|
At or above 50% SMYS
|
At or above 30% SMYS up to 50% SMYS
|
Below 30% SMYS
|
|
Baseline Assessment Method (see Note 3)
|
Max Re-Assessment Interval
|
Assessment Method
|
Max Re-Assessment Interval
|
Assessment Method
|
Max Re-Assessment Interval
|
Assessment Method
|
|
Pressure Testing
|
7
|
CDA
|
7
|
CDA
|
Ongoing
|
Preventative & Mitigative (P&M) Measures (see
Table E.II.3), (see Note 2)
|
|
10
|
Pressure Test or ILI or DA
|
|
|
|
Repeat inspection cycle every 10 years
|
15(see Note 1)
|
Pressure Test or ILI or DA (see Note 1)
|
|
|
|
Repeat inspection cycle every 15 years
|
|
Pressure Test or ILI or DA
|
|
20
|
|
|
|
Repeat inspection cycle every 20 years
|
|
In-Line Inspection
|
7
|
CDA
|
7
|
CDA
|
Ongoing
|
Preventative & Mitigative (P&M) Measures (see
Table E.II.3), (see Note 2)
|
|
10
|
ILI or DA or Pressure Test
|
|
|
|
Repeat inspection cycle every 10 years
|
15(see Note 1)
|
ILI or DA or Pressure Test (see Note 1)
|
|
|
Repeat inspection cycle every 15 years
|
20
|
ILI or DA or Pressure Test
|
|
|
|
|
Repeat inspection cycle every 20 years
|
|
Direct Assessment
|
7
|
CDA
|
7
|
CDA
|
Ongoing
|
Preventative & Mitigative (P&M) Measures (see
Table E.II.3), (see Note 2)
|
|
10
|
DA or ILI or Pressure Test
|
|
|
|
|
|
Repeat inspection cycle every 10 years
|
15(see Note 1)
|
DA or ILI or Pressure Test (see Note 1)
|
|
|
|
|
Repeat inspection cycle every 15 years
|
20
|
DA or ILI or Pressure Test
|
|
|
|
|
Repeat inspection cycle every 20 years
|
Note 1: Operator may choose to utilize CDA at year 14, then
utilize ILI, Pressure Test, or DA at year 15 as allowed under ASME
B31.8S
Note 2: Operator may choose to utilize CDA at year 7 and 14 in
lieu of P&M
Note 3: Operator may utilize "other technology that an operator
demonstrates can provide an equivalent understanding of the condition of line
pipe"
Table E.II.3
Preventative & Mitigative Measures addressing Time
Dependent and Independent Threats for Transmission Pipelines that Operate Below
30% SMYS, in HCAs
|
Threat
|
Existing 192 Requirements
|
Additional (to 192 requirements) Preventive &
Mitigative Measures
|
|
Primary
|
Secondary
|
|
External Corrosion
|
455 - (Gen. Post 1971) 457 - (Gen. pre-1971) 459 -
(Examination) 461 - (Ext. coating) 463 - (CP) 465 - (Monitoring) 467 - (Elect
isolation)
|
603 - (Gen Oper) 613 - (Surveil)
|
For Cathodically protected Trmn.
Pipelines
. Perform an electrical survey (i.e. indirect
examination tool/method) at least every 7 years. Results are to be utilized as
part of an overall evaluation of the CP system and corrosion threat for the
covered segment. Evaluation shall include consideration of leak repair and
ispection records, corrosion monitoring records, exposed pipe inspection
records, and the pipeline environment.
|
|
External Corrosion
|
469 - (Test stations) 471 - (Test leads) 473 -
(Interference) 479 - (Atmospheric) 481 - (Atmospheric) 485 - (Remedial) 705 -
(Patrol) 706 - (Leak survey) 711 - (repair - gen.) 717 - (Repair perm.)
|
|
For Unprotected Trmn. Pipelines or for
Cathodically protected Pipe where Electrical Surveys are
Impracticable
. Conduct quarterly leak surveys AND
. Every 1 1/2 years, determine areas of active
corrosion by evaluation of leak repair and inspection records, corrosion
monitoring records, exposed pipe inspection records, and the pipeline
environment.
|
|
Internal Corrosion
|
475 - (Gen IC) 477 - (IC monitoring) 485 - (Remedial)
705 - (Patrol) 706 - (Leak survey) 711 - (repair - gen.) 717 - (Repair
perm.)
|
53 (a) - (Materials) 603 - (Gen Oper) 613 -
(Surveil)
|
. Obtain and review gas analysis data each calendar
year for corrosive agents from transmission pipelines in HCAs,
. Periodic testing of fluid removed from pipelines.
Specifically, once each calendar year from each storage field that may affect
transmission pipelines in HCAs, AND
. At least every 7 years, integrate data obtained with
applicable internal corrosion leak records, incident reports, safety related
condition reports, repair records, patrol records, exposed pipe reports, and
test records.
|
|
3rd Party Damage
|
103 - (Gen. Design) 111 - (Design factor) 317 - (Hazard
prot) 327 (cover) 614 - (Dam. Prevent) 616 - (Public educat) 705 - (Patrol) 707
- (Line markers) 711 - (repair - gen.) 717 - (Repair-perm.)
|
615 - (Emerg Plan)
|
. Participation in state one-call system,
. Use of qualified operator employees and contractors
to perform makring and locating of buried structures and in direct supervison
of excavation work, AND
. Either monitoring of excavations near operator's
transmission pipelines, or bi-monthly patrol of transmission pipelines in HCAs
or class 3 or 4 locations. Any indications of unreported construction activity
would require a follow up investigation to determine if mechanical damage
occurred.
|
PART 193
-
Liquefied Natural Gas Facilities: Federal Safety Standards
Subpart A
-General
§ 193.2001
Scope of part.
(a) This part prescribes safety standards for
LNG facilities used in the transportation of gas by pipeline that is subject to
the pipeline safety laws (49
U.S.C. 60101
et seq.) and
Part 192 of this chapter.
(b) This
part does not apply to:
(1) LNG facilities
used by ultimate consumers of LNG or natural gas.
(2) LNG facilities used in the course of
natural gas treatment or hydrocarbon extraction which do not store
LNG.
(3) In the case of a marine
cargo transfer system and associated facilities, any matter other than siting
pertaining to the system or facilities between the marine vessel and the last
manifold (or in the absence of a manifold, the last valve) located immediately
before a storage tank.
(4) Any LNG
facility located in navigable waters (as defined in Section 3(8) of the Federal
Power Act (16
U.S.C. 796(8)).
§ 193.2003
[Reserved]
§ 193.2005
Applicability.(a) Regulations
in this part governing siting, design, installation, or construction of LNG
facilities (including material incorporated by reference in these regulations)
do not apply to LNG facilities in existence or under construction when the
regulations go into effect.
(b) If
an existing LNG facility (or facility under construction before March 31, 2000
is replaced, relocated or significantly altered after March 31, 2000, the
facility must comply with the applicable requirements of this part governing,
siting, design, installation, and construction, except that:
(1) The siting requirements apply only to LNG
storage tanks that are significantly altered by increasing the original storage
capacity or relocated, and
(2) To
the extent compliance with the design, installation, and construction
requirements would make the replaced, relocated, or altered facility
incompatible with the other facilities or would otherwise be impractical, the
replaced, relocated, or significantly altered facility may be designed,
installed, or constructed in accordance with the original specifications for
the facility, or in another manner subject to the approval of the
Administrator.
§
193.2007
Definitions.
As used in this part:
Administrator means the
Administrator, Pipeline and Hazardous Materials Safety Administration or his or
her delegate.
Ambient vaporizer means a
vaporizer which derives heat from naturally occurring heat sources, such as the
atmosphere, sea water, surface waters, or geothermal waters.
Cargo transfer system means a
component, or system of components functioning as a unit, used exclusively for
transferring hazardous fluids in bulk between a tank car, tank truck, or marine
vessel and a storage tank.
Component means any part, or
system of parts functioning as a unit, including, but not limited to, piping,
processing equipment, containers, control devices, impounding systems,
lighting, security devices, fire control equipment, and communication
equipment, whose integrity or reliability is necessary to maintain safety in
controlling, processing, or containing a hazardous fluid.
Container means a component other
than piping that contains a hazardous fluid.
Control system means a component,
or system of components functioning as a unit, including control valves and
sensing, warning, relief, shutdown, and other control devices, which is
activated either manually or automatically to establish or maintain the
performance of another component.
Controllable emergency means an
emergency where reasonable and prudent action can prevent harm to people or
property.
Design pressure means the
pressure used in the design of components for the purpose of determining the
minimum permissible thickness or physical characteristics of its various parts.
When applicable, static head shall be included in the design pressure to
determine the thickness of any specific part.
Determine means make an
appropriate investigation using scientific methods, reach a decision based on
sound engineering judgment, and be able to demonstrate the basis of the
decision.
Dike means the perimeter of an
impounding space forming a barrier to prevent liquid from flowing in an
unintended direction.
Emergency means a deviation from
normal operation, a structural failure, or severe environmental conditions that
probably would cause harm to people or property.
Exclusion zone means an area
surrounding an LNG facility in which an operator or government agency legally
controls all activities in accordance with § 193.2057 and § 193.2059
for as long as the facility is in operation.
Fail-safe means a design feature
which will maintain or result in a safe condition in the event of malfunction
or failure of a power supply, component, or control device.
g means the standard acceleration
of gravity of 9.806 meters per second2 (32.17 feet
per second2).
Gas, except when designated as
inert, means natural gas, other flammable gas, or gas which is toxic or
corrosive.
Hazardous fluid means gas or
hazardous liquid.
Hazardous liquid means LNG or a
liquid that is flammable or toxic.
Heated vaporizer means a
vaporizer which derives heat from other than naturally occurring heat
sources.
Impounding space means a volume
of space formed by dikes and floors which is designed to confine a spill of
hazardous liquid.
Impounding system includes an
impounding space, including dikes and floors for conducting the flow of spilled
hazardous liquids to an impounding space.
Liquefied natural gas or
LNG means natural gas or synthetic gas having
methane (CH4) as its major constituent which has been
changed to a liquid.
LNG facility means a pipeline
facility that is used for liquefying natural gas or synthetic gas or
transferring, storing, or vaporizing liquefied natural gas.
LNG plant means an LNG facility
or system of LNG facilities functioning as a unit.
M3 means a volumetric unit which is
one cubic meter, 6.2898 barrels, 35.3147 ft.3, or
264.1720 U.S. gallons, each volume being considered as equal to the
other.
Maximum allowable working pressure
means the maximum gage pressure permissible at the top of the
equipment, containers or pressure vessels while operating at design
temperature.
Normal operation means
functioning within ranges of pressure, temperature, flow, or other operating
criteria required by this part.
Operator means a person who owns
or operates an LNG facility.
Person means any individual,
firm, joint venture, partnership, corporation, association, state,
municipality, cooperative association, or joint stock association and includes
any trustee, receiver, assignee, or personal representative thereof.
Pipeline facility means new and
existing piping, rights-of-way, and any equipment, facility, or building used
in the transportation of gas or in the treatment of gas during the course of
transportation.
Piping means pipe, tubing, hoses,
fittings, valves, pumps, connections, safety devices or related components for
containing the flow of hazardous fluids.
Storage tank means a container
for storing a hazardous fluid.
Transfer piping means a system of
permanent and temporary piping used for transferring hazardous fluids between
any of the following: Liquefaction process facilities, storage tanks,
vaporizers, compressors, cargo transfer systems, and facilities other than
pipeline facilities.
Transfer system includes transfer
piping and cargo transfer system.
Vaporization means an addition of
thermal energy changing a liquid to a vapor or gaseous state.
Vaporizer means a heat transfer
facility designed to introduce thermal energy in a controlled manner for
changing a liquid to a vapor or gaseous state.
Waterfront LNG plant means an LNG
plant with docks, wharves, piers, or other structures in, on, or immediately
adjacent to the navigable waters of the United States or Puerto Rico and any
shore area immediately adjacent to those waters to which vessels may be secured
and at which LNG cargo operations may be conducted.
§ 193.2009
Rules of regulatory
construction.(a) As used in this part:
(1)
Includes
means including but not limited to;
(2)
May means
is permitted to or is authorized to;
(3)
May not
means is not permitted to or is not authorized to; and
(4)
Shall or
must is used in the mandatory and imperative
sense.
(b) In this part:
(1) Words importing the singular include the
plural; and
(2) Words importing the
plural include the singular.
§ 193.2011
Reporting.
Incidents, safety-related conditions, and annual pipeline
summary data for LNG plants or facilities must be reported in accordance with
the requirements of Part 191 of this subchapter.
§ 193.2013
Incorporation by
reference.(a) Any document or portion
thereof incorporated by reference in this part is included in this part as
though it were printed in full. When only a portion of a document is
referenced, then this part incorporates only that referenced portion of the
document and the remainder is not incorporated. Applicable editions are listed
in paragraph (c) of this section in parentheses following the title of the
referenced material. Earlier editions listed in previous editions of this
section may be used for components manufactured, designed, or installed in
accordance with those earlier editions at the time they were listed. The user
must refer to the appropriate previous edition of 49 CFR for a listing of the
earlier editions.
(b) All
incorporated materials are available for inspection in the Pipeline and
Hazardous Materials Safety Administration, PHP-30, 1200 New Jersey Avenue, SE.,
Washington, DC, 20590-0001, or at the National Archives and Records
Administration (NARA). For information on the availability of this material at
NARA, call 202-741-6030 or go to:
http://www.archives.gov/federal_register/code_of_federal_regulations/IBR_locations.html.
Documents incorporated by reference are available from the
publishers as follows:
A. American Gas
Association (AGA), 400 North Capitol Street, NW, Washington, DC
20001.
B. American Petroleum
Institute (API), 1220 L Street, NW, Washington, DC 20005.
C. American Society of Civil Engineers
(ASCE), Parallel Centre, 1801 Alexander Bell Drive, Reston, VA
20191-4400.
D. ASME International
(ASME), Three Park Avenue, New York, NY 10016-5990.
E. Gas Technology Institute (GTI, 1700 S.
Mount Prospect Road, Des Plaines, IL 60018.
F. National Fire Protection Association
(NFPA), 1 Batterymarch Park, P. O. Box 9101, Quincy, MA 02269-9101.
(c) Documents
incorporated by reference.
|
Source and name of referenced material
|
49 CFR reference
|
|
A. American Gas Association (AGA):
|
|
|
(1) "Purging Principles and Practices,"
(3rd edition, 2001).
|
§§ 193.2513; 193.2517; 193.2615.
|
|
B. American Petroleum Institute (API):
|
|
|
(1) API Standard 620 "Design and Construction of Large,
Welded, Low-Pressure Storage Tanks" (11th edition
February 2008, addendum 1, March 2009).
|
§§ 193.2101(b); 193.2321(b)(2).
|
|
C. American Society of Civil Engineers (ASCE):
|
|
|
(1) ASCE/SEI 7-05 "Minimum Design Loads for Buildings
and Other Structures," (2005 edition, includes supplement No. 1 and
Errata).
|
§ 193.2067(b)(1).
|
|
D. ASME International (ASME):
|
|
|
(1) 2007 ASME Boiler and Pressure Vessel Code, Section
(2007 edition, July 1, 2007).
|
§ 193.2321(a).
|
|
(2) 2007 ASME Boiler and Pressure Vessel Code, Section
VIII, Division 2, "Rules for Construction of Pressure Vessels- Alternative
Rules,: (2007 edition, July 1, 2007).
|
§ 193.2321(a).
|
|
E. Gas Technology Institute (GTI) formerly the Gas
Research Institute (GRI):
|
|
|
(1) GTI-04/0032 LNGFIRE3: A Thermal Radiation Model for
LNG Fires," (March 2004).
|
§ 193.2057(a).
|
|
(2) GTI-04/0049 (April 2004) "LNG Vapor Dispersion
Prediction with the DEGADIS 2.1: Dense Gas Dispersion Model for LNG Vapor
Dispersion".
|
§ 193.2059.
|
|
(3) GRI-96/0396.5 "Evaluation of Mitigation Methods for
Accidental LNG Releases, Volume 5: Using FEM3A for LNG Accident Consequence
Analyses," (April 1997).
|
§ 193.2059
|
|
F. National Fire Protection Association (NFPA):
|
|
|
(1) NFPA 59A (2001) "Standard for the Production,
Storage, and Handling of Liquefied Natural Gas (LNG)."
|
§§ 193.2019; 193.2051; 193.2057; 193.2059;
193.2101(a); 193.2301; 193.2303; 193.2401; 193.2521; 193.2639; 193.2801.
|
|
(2) NFPA 59A, "Standard for the Production, Storage,
and Handling of Liquefied Natural Gas (LNG)" (2006 edition, Approved August 18,
2005)
|
§§ 192.2101(b); 193.2321(b).
|
§
193.2015
[Reserved]
§ 193.2017
Plans and
procedures.
(a) Each operator shall
maintain at each LNG plant the plans and procedures required for that plant by
this part. The plans and procedures must be available upon request for review
and inspection by the Administrator or any State Agency that has submitted a
current certification or agreement with respect to the plant under the pipeline
safety laws (49
U.S.C. 60101
et seq.). In
addition, each change to the plans or procedures must be available at the LNG
plant for review and inspection within 20 days after the change is
made.
(b) The Administrator or the
State Agency that has submitted a current certification under section 5(a) of
the Natural Gas Pipeline Safety Act with respect to the pipeline facility
governed by an operator's plans and procedures may, after notice and
opportunity for hearing as provided in
49 CFR
190.237 or the relevant State procedures,
require the operator to amend its plans and procedures as necessary to provide
a reasonable level of safety.
(c)
Each operator must review and update the plans and procedures required by this
part-
(1) When a component is changed
significantly or a new component is installed; and
(2) At intervals not exceeding 27 months, but
at least once every 2 calendar years.
§ 193.2019
Mobile and temporary
LNG facilities.(a) Mobile and
temporary LNG facilities for peakshaving application, for service maintenance
during gas pipeline systems repair/alteration, or for other short term
applications need not meet the requirements of this part if the facilities are
in compliance with applicable sections of NFPA 59A (incorporated by reference,
see § 193.2013).
(b) The state
agency having jurisdiction over pipeline safety in the State in which the
portable LNG equipment is to be located must be provided with a location
description for the installation at least 2 weeks in advance, including to the
extent practical, the details of siting, leakage containment or control, fire
fighting equipment, and methods employed to restrict public access, except that
in the case of emergency where such notice is not possible, as much advance
notice as possible must be provided.
Subpart B
-Siting Requirements
§ 193.2051
Scope.
Each LNG facility designed, constructed, replaced, relocated or
significantly altered after March 31, 2000 must be provided with siting
requirements in accordance with the requirements of this part and of NFPA 59A
(incorporated by reference, see § 193.2013). In the event of a conflict
between this part and NFPA 59A, this part prevails.
§ 193.2057
Thermal radiation
protection.
Each LNG container and LNG transfer system must have a thermal
exclusion zone in accordance with section 2.2.3.2 of NFPA 59A (incorporated by
reference, see § 193.2013) with the following exceptions:
(a) The thermal radiation distances must be
calculated using Gas Technology Institute's (GTI) report or computer model
GTI-04/0032 LNGFIRE3: A Thermal Radiation Model for LNG Fires (incorporated by
reference, see
§ 193.2013). The use of other alternate
models which take into account the same physical factors and have been
validated by experimental test data may be permitted subject to the
Administrator's approval.
(b) In
calculating exclusion distances, the wind speed producing the maximum exclusion
distances shall be used except for wind speeds that occur less than 5 percent
of the time based on recorded data for the area.
(c) In calculating exclusion distances, the
ambient temperature and relative humidity that produce the maximum exclusion
distances shall be used except for values that occur less than five percent of
the time based on recorded data for the area.
§ 193.2059
Flammable vapor-gas
dispersion protection.
Each LNG container and LNG transfer system must have a
dispersion exclusion zone in accordance with sections 2.2.3.3 and 2.2.3.4 of
NFPA 59A (incorporated by reference, see § 193.2013) with the following
exceptions:
(a) Flammable vapor-gas
dispersion distances must be determined in accordance with the model described
in the Gas Research Institute report GRI-89/0242 (incorporated by reference,
see § 193.2013), "LNG Vapor Dispersion Prediction with the DEGADIS Dense
Gas Dispersion Model." Alternatively, in order to account for additional cloud
dilution which may be caused by the complex flow patterns induced by tank and
dike structure, dispersion distances may be calculated in accordance with the
model described in the Gas Research Institute report GRI 96/0396.5
(incorporated by reference, see § 193.2013), "Evaluation of Mitigation
Methods for Accidental LNG Releases. Volume 5: Using FEM3A for LNG Accident
Consequence Analyses." The use of alternate models which take into account the
same physical factors and have been validated by experimental test data shall
be permitted, subject to the Administrator's approval.
(b) The following dispersion parameters must
be used in computing dispersion distances:
(1)
Average gas concentration in air = 2.5 percent.
(2) Dispersion conditions are a combination
of those which result in longer predicted downwind dispersion distances than
other weather conditions at the site at least 90 percent of the time,based on
figures maintained by National Weather Service of the U.S. Department of
Commerce, or as an alternative where the model used gives longer distances at
lower wind speeds, Atmospheric Stability (Pasquill Class) F, wind speed = 4.5
miles per hour (2.01 meters/sec) at reference height of 10 meters, relative
humidity = 50.0 percent, and atmospheric temperature = average in the
region.
(3) The elevation for
contour (receptor) output H = 0.5 meters.
(4) A surface roughness factor of 0.03 meters
shall be used. Higher values for the roughness factor may be used if it can be
shown that the terrain both upwind and downwind of the vapor cloud has dense
vegetation and that the vapor cloud height is more than ten times the height of
the obstacles encountered by the vapor cloud.
(c) The design spill shall be determined in
accordance with section 2.2.3.5 of NFPA 59A
(incorporated by reference, see § 193.2013).
§ 193.2061-193.2065
[Reserved]
§
193.2067
Wind forces.
(a) LNG facilities must be designed to
withstand without loss of structural or functional integrity;
(1) The direct effect of wind
forces;
(2) The pressure
differential between the interior and exterior of a confining, or partially
confining, structure; and
(3) In
the case of impounding systems for LNG storage tanks, impact forces and
potential penetrations by wind borne missiles.
(b) The wind forces at the location of the
specific facility must be based on one of the following:
(1) For shop fabricated containers of LNG or
other hazardous fluids with a capacity of not more than 70,000 gallons,
applicable wind load data in ASCE/SEI 7-05 (incorporated by reference,
see
§ 193.2013).
(2) For all other LNG facilities:
(i) An assumed sustained wind velocity of not
less than 150 miles per hour, unless the Administrator finds a lower velocity
is justified by adequate supportive data; or
(ii) The most critical combination of wind
velocity and duration, with respect to the effect on the structure, having a
probability of exceedance in a 50-year period of 0.5 percent or less, if
adequate wind data are available and the probabilistic methodology is reliable.
§
193.2069-193.2073
[Reserved]
Subpart C
- Design
§ 193.2101
Scope.
(a) Each LNG facility designed after March
31, 2000 must comply with requirements of this Part and of NFPA 59A (2001)
(incorporated by reference, see § 193.2013). If there is
a conflict between this Part and NFPA 59A, this Part prevails. Unless otherwise
specified, all references to NFPA 59A in this Part are to the 2001
edition.
(b) Stationary LNG storage
tanks must comply with Section 7.2.2 of NFPA 59A (2006) (incorporated by
reference, see
§ 193.2013) for seismic design of field
fabricated tanks. All other LNG storage tanks must comply with API Standard 620
(incorporated by reference, see
§ 193.2013) for seismic
design.
Materials
§ 193.
2103-193-2117
[Reserved]
§ 193.2119
Records.
Each operator shall keep a record of all materials for
components, buildings, foundations, and support systems, as necessary to verify
that material properties meet the requirements of this part. These records must
be maintained for the life of the item concerned.
Design of Components and Buildings
§ 193.2121-193.2153
[Reserved]
Impoundment Design and Capacity
§ 193.2155
Structural
requirements.(a) The structural
members of an impoundment system must be designed and constructed to prevent
impairment of the system's performance reliability and structural integrity as
a result of the following:
(1) The imposed
loading from-
(i) Full hydrostatic head of
impounded LNG;
(ii) Hydrodynamic
action, including the effect of any material injected into the system for spill
control;
(iii) The impingement of
the trajectory of an LNG jet discharged at any predictable angle;
and,
(iv) Anticipated hydraulic
forces from a credible opening in the component or item served, assuming that
the discharge pressure equals design pressure.
(2) The erosive action from a spill,
including jetting of spilling LNG, and any other anticipated erosive action
including surface water runoff, ice formation, dislodgment of ice formation,
and snow removal.
(3) The effect of
the temperature, any thermal gradient, and any other anticipated degradation
resulting from sudden or localized contact with LNG.
(4) Exposure to fire from impounded LNG or
from sources other than impounded LNG.
(5) If applicable, the potential impact and
loading on the dike due to-
(i) Collapse of
the component or item served or adjacent components; and
(ii) If the LNG facility adjoins the
right-of-way of any highway or railroad, collision by or explosion of a train,
tank car, or tank truck that could reasonably be expected to cause the most
severe loading.
(b) An LNG storage tank must not be located
within a horizontal distance of one mile (1.6 km) from the ends, or 1/4
mile (0.4 km) from the nearest point of a runway, whichever is longer. The
height of LNG structures in the vicinity of an airport must also comply with
Federal Aviation Administration requirements in
14 CFR Section
1.1.
§ 193.2157-193.2159
[Reserved]
§ 193.2161
Dikes; general.
An outer wall of a component served by an impounding system may
not be used as a dike unless the outer wall is constructed of concrete.
§ 193.2163-193.2165
[Reserved]
§ 193.2167
Covered systems.
A covered impounding system is prohibited except for concrete
wall designed tanks where the concrete wall is an outer wall serving as a
dike.
§
193.2169-193.2171
[Reserved]
§ 193.2173
Water removal.
(a) Impoundment areas must be constructed
such that all areas drain completely to prevent water collection. Drainage
pumps and piping must be provided to remove water from collecting in the
impoundment area. Alternative means of draining may be acceptable subject to
the Administrator's approval.
(b)
The water removal system must have adequate capacity to remove water at a rate
equal to 25% of the maximum predictable collection rate from a storm of 10-year
frequency and 1-hour duration, and other natural causes. For rainfall amounts,
operators must use the "Rainfall Frequency Atlas of the United States"
published by the National Weather Service of the U.S. Department of
Commerce.
(c) Sump pumps for water
removal must-
(1) Be operated as necessary to
keep the impounding space as dry as practical; and
(2) If sump pumps are designed for automatic
operation, have redundant automatic shutdown controls to prevent operation when
LNG is present.
§
193.2175-193.2179
[Reserved]
§ 193.2181
Impoundment capacity;
LNG storage tanks.
Each impounding system serving an LNG storage tank must have a
minimum volumetric liquid impoundment capacity of:
(a) 110 percent of the LNG tank's maximum
liquid capacity for an impoundment serving a single tank;
(b) 100 percent of all tanks or 110 percent
of the largest tank's maximum liquid capacity, whichever is greater, for the
impoundment serving more than one tank; or
(c) If the dike is designed to account for a
surge in the event of catastrophic failure, then the impoundment capacity may
be reduced to 100 percent in lieu of 110 percent.
§ 193.2183-193.2185
[Reserved]
LNG Storage Tanks
§ 193.2187
Nonmetallic membrane
liner.
A flammable nonmetallic membrane liner may not be used as an
inner container in a storage tank.
§
193.2189-193.2233
[Reserved]
Subpart D
-Construction
§ 193.2301
Scope.
Each LNG facility constructed after March 31, 2000 must comply
with requirements of this part and of NFPA 59A (incorporated by reference, see
§ 193.2013). In the event of a conflict between this part and NFPA 59A,
this part prevails.
§
193.2303
Construction acceptance.
No person may place in service any component until it passes
all applicable inspections and tests prescribed by this subpart and NFPA 59A
(incorporated by reference, see § 193.2013).
§ 193.2304
Corrosion control
overview.(a) Subject to paragraph (b)
of this section, components may not be constructed, repaired, replaced, or
significantly altered until a person qualified under § 193.2707(c) reviews
the applicable design drawings and materials specifications from a corrosion
control viewpoint and determines that the materials involved will not impair
the safety or reliability of the component or any associated
components.
(b) The repair,
replacement, or significant alteration of components must be reviewed only if
the action to be taken-
(1) Involves a change
in the original materials specified;
(2) Is due to a failure caused by corrosion;
or
(3) Is occasioned by inspection
revealing a significant deterioration of the component due to corrosion.
§
193.2305-193.2319
[Reserved].
§ 193.2321
Nondestructive
tests.
(a) The butt welds in metal
shells of storage tanks with internal design pressure above 15 psig must be
nondestructively examined in accordance with the ASME Boiler and Pressure
Vessel Code (Section VIII Division 1) (incorporated by reference, see §
193.2013), except that 100 percent of welds that are both longitudinal (or
meridional) and circumferential (or latitudinal) of hydraulic load bearing
shells with curved surfaces that are subject to cryogenic temperatures must be
nondestructively examined in accordance with the ASME Boiler and Pressure
Vessel Code (Section VIII Division 1) (incorporated by reference, see
193.2013).
(b) For storage tanks
with internal design pressures at 15 psig or less, ultrasonic examinations of
welds on metal containers must comply with the following:
(1) Section 7.3.1.2 of NFPA 59A (2006)
(incorporated by reference, see
§ 193.2013);
(2) Appendices Q and C of API 620 Standard
(incorporated by reference, see
§ 193.2013);
(c) Ultrasonic examination records
must be retained for the life of the facility. If electronic records are kept,
they must be retained in a manner so that they cannot be altered by any means;
and
(d) The ultrasonic equipment
used in the examination of welds must be calibrated at a frequency no longer
than eight hours. Such calibrations must verify the examination of welds
against a calibration standard. If the ultrasonic equipment is found to be out
of calibration, all previous weld inspections that are suspect must be
reexamined.
§
193.2323-193.2329
[Reserved].
Subpart E
-Equipment
§ 193.2401
Scope.
After March 31, 2000, each new, replaced, relocated or
significantly altered vaporization equipment, liquefaction equipment, and
control systems must be designed, fabricated, and installed in accordance with
requirements of this part and of NFPA 59A (incorporated by reference, see
§ 193.2013). In the event of a conflict between this part and NFPA 59A,
this part prevails.
VAPORIZATION EQUIPMENT
§ 193.2403-193.2439
[Reserved].
§ 193.2441
Control center.
Each LNG plant must have a control center from which operations
and warning devices are monitored as required by this part. A control center
must have the following capabilities and characteristics:
(a) It must be located apart or protected
from other LNG facilities so that it is operational during a controllable
emergency.
(b) Each remotely
actuated control system and each automatic shutdown control system required by
this part must be operable from the control center.
(c) Each control center must have personnel
in continuous attendance while any of the components under its control are in
operation, unless the control is being performed from another control center
which has personnel in continuous attendance.
(d) If more than one control center is
located at an LNG plant, each control center must have more than one means of
communication with each other center.
(e) Each control center must have a means of
communicating a warning of hazardous conditions to other locations within the
plant frequented by personnel.
§
193.2443
[Reserved].
§ 193.2445
Sources of
power.
(a) Electrical control systems,
means of communication, emergency lighting, and firefighting systems must have
at least two sources of power which function so that failure of one source does
not affect the capability of the other source.
(b) Where auxiliary generators are used as a
second source of electrical power-
(1) They
must be located apart or protected from components so that they are not
unusable during a controllable emergency; and
(2) Fuel supply must be protected from
hazards.
Subpart
F
-Operations
§
193.2501
Scope.
This subpart prescribes requirements for the operation of LNG
facilities
§ 193.2503
Operating procedures.
Each operator shall follow one or more manuals of written
procedures to provide safety in normal operation and in responding to an
abnormal operation that would affect safety. The procedures must include
provisions for:
(a) Monitoring
components or buildings according to the requirements of §
193.2507.
(b) Startup and shutdown,
including for initial startup, performance testing to demonstrate that
components will operate satisfactory in service.
(c) Recognizing abnormal operating
conditions.
(d) Purging and
inserting components according to the requirements of §
193.2517.
(e) In the case of
vaporization, maintaining the vaporization rate, temperature and pressure so
that the resultant gas is within limits established for the vaporizer and the
downstream piping.
(f) In the case
of liquefaction, maintaining temperatures, pressures, pressure differentials
and flow rates, as applicable, within their design limits for:
(1) Boilers;
(2) Turbines and other prime
movers;
(3) Pumps, compressors, and
expanders;
(4) Purification and
regeneration equipment; and
(5)
Equipment within cold boxes.
(g) Cooldown of components according to the
requirements of § 193.2505.
§ 193.2505
Cooldown.
(a) The cooldown of each system of components
that is subjected to cryogenic temperatures must be limited to a rate and
distribution pattern that keeps thermal stresses within design limits during
the cooldown period, paying particular attention to the performance of
expansion and contraction devices.
(b) After cooldown stabilization is reached,
cryogenic piping systems must be checked for leaks in areas of flanges, valves,
and seals.
§
193.2507
Monitoring operations.
Each component in operation or building in which a hazard to
persons or property could exist must be monitored to detect fire or any
malfunction or flammable fluid that could cause a hazardous condition.
Monitoring must be accomplished by watching or listening from an attended
control center for warning alarms, such as gas, temperature, pressure, vacuum,
and flow alarms, or by conducting an inspection or test at intervals specified
in the operating procedures.
§
193.2509
Emergency procedures.
(a) Each operator shall determine the types
and places of emergencies other than fires that may reasonably be expected to
occur at an LNG plant due to operating malfunctions, structural collapse,
personnel error, forces of nature, and activities adjacent to the
plant.
(b) To adequately handle
each type of emergency identified under paragraph (a) of this section and each
fire emergency, each operator shall follow one or more manuals of written
procedures. The procedures must provide for the following:
(1) Responding to controllable emergencies,
including notifying personnel and using equipment appropriate for handling the
emergency.
(2) Recognizing an
uncontrollable emergency and taking action to minimize harm to the public and
personnel, including prompt notification of appropriate local officials of the
emergency and possible need for evacuation of the public in the vicinity of the
LNG plant.
(3) Coordinating with
appropriate local officials in preparation of an emergency evacuation plan,
which sets forth the steps required to protect the public in the event of an
emergency, including catastrophic failure of an LNG storage tank.
(4) Cooperating with appropriate local
officials in evacuations and emergencies requiring mutual assistance and
keeping these officials advised of:
(i) The
LNG plant fire control equipment, its location, and quantity of units located
throughout the plant;
(ii)
Potential hazards at the plant, including fires;
(iii) Communication and emergency control
capabilities at the LNG plant; and,
(iv) The status of each emergency.
§
193.2511
Personnel safety.
(a) Each operator shall provide any special
protective clothing and equipment necessary for the safety of personnel while
they are performing emergency response duties.
(b) All personnel who are normally on duty at
a fixed location, such as a building or yard, where they could be harmed by
thermal radiation from a burning pool of impounded liquid, must be provided a
means of protection at that location from the harmful effects of thermal
radiation or a means of escape.
(c)
Each LNG plant must be equipped with suitable first-aid material, the location
of which is clearly marked and readily available to personnel.
§ 193.2513
Transfer
procedures.
(a) Each transfer of LNG
or other hazardous fluid must be conducted in accordance with one or more
manuals of written procedures to provide for safe transfers.
(b) The transfer procedures must include
provisions for personnel to:
(1) Before
transfer, verify that the transfer system is ready for use, with connections
and controls in proper positions, including if the system could contain a
combustible mixture, verifying that it has been adequately purged in accordance
with a procedure which meets the requirements of AGA "Purging Principles and
Practice."
(2) Before transfer,
verify that each receiving container or tank vehicle does not contain any
substance that would be incompatible with the incoming fluid and that there is
sufficient capacity available to receive the amount of fluid to be
transferred.
(3) Before transfer,
verify the maximum filling volume of each receiving container or tank vehicle
to ensure that expansion of the incoming fluid due to warming will not result
in overfilling or overpressure;
(4)
When making bulk transfer of LNG into a partially filled (excluding cooldown
heel) container, determine any differences in temperature or specific gravity
between the LNG being transferred and the LNG already in the container and, if
necessary, provide a means to prevent rollover due to stratification.
(5) Verify that the transfer operations are
proceeding within design conditions and that overpressure or overfilling does
not occur by monitoring applicable flow rates, liquid levels, and vapor
returns.
(6) Manually terminate the
flow before overfilling or overpressure occurs; and,
(7) Deactivate cargo transfer systems in a
safe manner by depressurizing, venting, and disconnecting lines and conducting
any other appropriate operations.
(c) In addition to the requirements of
paragraph (b) of this section, the procedures for cargo transfer must be
located at the transfer area and include provisions for personnel to:
(1) Be in constant attendance during all
cargo transfer operations;
(2)
Prohibit the backing of tank trucks in the transfer area, except when a person
is positioned at the rear of the truck giving instructions to the
driver;
(3) Before transfer, verify
that:
(i) Each tank car or tank truck
complies with applicable regulations governing its use;
(ii) All transfer hoses have been visually
inspected for damage and defects;
(iii) Each tank truck is properly immobilized
with chock wheels, and electrically grounded; and,
(iv) Each tank truck engine is shut off
unless it is required for transfer operations;
(4) Prevent a tank truck engine that is off
during transfer operations from being restarted until the transfer lines have
been disconnected and any released vapors have dissipated;
(5) Prevent loading LNG into a tank car or
tank truck that is not in exclusive LNG service or that does not contain a
positive pressure if it is in exclusive LNG service, until after the oxygen
content in the tank is tested and if it exceeds 2 percent by volume, purged in
accordance with a procedure that meets the requirements of AGA "Purging
Principles and Practice";
(6)
Verify that all transfer lines have been disconnected and equipment cleared
before the tank car or tank truck is moved from the transfer position;
and,
(7) Verify that transfers into
a pipeline system will not exceed the pressure or temperature limits of the
system.
§
193.2515
Investigations of failures.
(a) Each operator shall investigate the cause
of each explosion, fire, or LNG spill or leak which results in:
(1) Death or injury requiring
hospitalization; or
(2) Property
damage exceeding $10,000.
(b) As a result of the investigation,
appropriate action must be taken to minimize recurrence of the
incident.
(c) If the Administrator
or relevant state agency under the pipeline safety laws (49
U.S.C. 60101
et seq.)
investigates an incident, the operator involved shall make available all
relevant information and provide reasonable assistance in conducting the
investigation. Unless necessary to restore or maintain service, or for safety,
no component involved in the incident may be moved from its location or
otherwise altered until the investigation is complete or the investigating
agency otherwise provides. Where components must be moved for operational or
safety reasons, they must not be removed from the plant site and must be
maintained intact to the extent practicable until the investigation is complete
or the investigating agency otherwise provides.
§ 193.2517
Purging.
When necessary for safety, components that could accumulate
significant amounts of combustible mixtures must be purged in accordance with a
procedure which meets the provisions of the AGA "Purging Principles and
Practice" after being taken out of service and before being returned to
service.
§ 193.2519
Communication systems.(a) Each
LNG plant must have a primary communication system that provides for verbal
communications between all operating personnel at their work stations in the
LNG plant.
(b) Each LNG plant in
excess of 70,000 gallons (265,000 liters) storage capacity must have an
emergency communication system that provides for verbal communications between
all persons and locations necessary for the orderly shutdown of operating
equipment and the operation of safety equipment in time of emergency. The
emergency communication system must be independent of and physically separated
from the primary communication system and the security communication system
under § 193.2909.
(c) Each
communication system required by this part must have an auxiliary source of
power, except sound-powered equipment.
§ 193.2521
Operating
records.
Each operator shall maintain a record of results of each
inspection, test and investigation required by this subpart. For each LNG
facility that is designed and constructed after March 31, 2000 the operator
shall also maintain related inspection, testing, and investigation records that
NFPA 59A (incorporated by reference, see § 193.2013) requires. Such
records, whether required by this part or NFPA 59A, must be kept for a period
of not less than five years.
Subpart G
-Maintenance
§ 193.2601
Scope.
This subpart prescribes requirements for maintaining components
at LNG plants.
§
193.2603
General.
(a) Each component in service, including its
support system, must be maintained in a condition that is compatible with its
operational or safety purpose by repair, replacement, or other means.
(b) An operator may not place, return, or
continue in service any component which is not maintained in accordance with
this subpart.
(c) Each component
taken out of service must be identified in the records kept under §
193.2639.
(d) If a safety device is
taken out of service for maintenance, the component being served by the device
must be taken out of service unless the same safety function is provided by an
alternate means.
(e) If the
inadvertent operation of a component taken out of service could cause a
hazardous condition, that component must have a tag attached to the controls
bearing the words "do not operate" or words of comparable meaning.
§ 193.2605
Maintenance
procedures.(a) Each operator shall
determine and perform, consistent with generally accepted engineering practice,
the periodic inspections or tests needed to meet the applicable requirements of
this subpart and to verify that components meet the maintenance standards
prescribed by this subpart.
(b)
Each operator shall follow one or more manuals of written procedures for the
maintenance of each component, including any required corrosion control. The
procedure must include:
(1) The details of the
inspections or tests determined under paragraph (a) of this section and their
frequency of performance; and
(2) A
description of other actions necessary to maintain the LNG plant in accordance
with the requirements of this subpart.
(c) Each operator shall include in the manual
required by paragraph (b) of this section instructions enabling personnel who
perform operation and maintenance activities to recognize conditions that
potentially may be safety-related conditions that are subject to the reporting
requirements of § 191.23 of this subchapter.
§ 193.2607
Foreign
material.
(a) The presence of foreign
material, contaminants, or ice shall be avoided or controlled to maintain the
operational safety of each component.
(b) LNG plant grounds must be free from
rubbish, debris, and other material which present a fire hazard. Grass areas on
the LNG plant grounds must be maintained in a manner that does not present a
fire hazard.
§
193.2609
Support systems.
Each support system or foundation of each component must be
inspected for any detrimental change that could impair support.
§ 193.2611
Fire
protection.
(a) Maintenance activities
on fire control equipment must be scheduled so that a minimum of equipment is
taken out of service at any one time and is returned to service in a reasonable
period of time.
(b) Access routes
for movement of fire control equipment within each LNG plant must be maintained
to reasonably provide for use in all weather conditions.
§ 193.2613
Auxiliary power
sources.
Each auxiliary power source must be tested monthly to check its
operational capability and tested annually for capacity. The capacity test must
take into account the power needed to start up and simultaneously operate
equipment that would have to be served by that power source in an
emergency.
§ 193.2615
Isolating and purging.(a)
Before personnel begin maintenance activities on components handling flammable
fluids which are isolated for maintenance, the component must be purged in
accordance with a procedure which meets the requirements of AGA "Purging
Principles and Practice," unless the maintenance procedures under §
193.2605 provide that the activity can be safely performed without
purging.
(b) If the component or
maintenance activity provides an ignition source, a technique in addition to
isolation valves (such as removing spool pieces or valves and blank flanging
the piping, or double block and bleed valving) must be used to ensure that the
work area is free of flammable fluids.
§ 193.2617
Repairs.
(a) Repair work on components must be
performed and tested in a manner which:
(1)
As far as practicable, complies with the applicable requirements of Subpart D
of this part; and
(2) Assures the
integrity and operational safety of the component being repaired.
(b) For repairs made while a
component is operating, each operator shall include in the maintenance
procedures under § 193.2605 appropriate precautions to maintain the safety
of personnel and property during repair activities.
§ 193.2619
Control
systems.
(a) Each control system must
be properly adjusted to operate within design limits.
(b) If a control system is out of service for
30 days or more, it must be inspected and tested for operational capability
before returning it to service.
(c)
Control systems in service, but not normally in operation, such as relief
valves and automatic shutdown devices, and control systems for internal shutoff
valves for bottom penetration tanks must be inspected and tested once each
calendar year, not exceeding 15 months, with the following exceptions:
(1) Control systems used seasonally, such as
for liquefaction or vaporization, must be inspected and tested before use each
season.
(2) Control systems that
are intended for fire protection must be inspected and tested at regular
intervals not to exceed 6 months.
(d) Control systems that are normally in
operation, such as required by a base load system, must be inspected and tested
once each calendar year but with intervals not exceeding 15 months.
(e) Relief valves must be inspected and
tested for verification of the valve seat lifting pressure and
reseating.
§
193.2621
Testing transfer hoses.
Hoses used in LNG or flammable refrigerant transfer systems
must be:
(a) Tested once each calendar
year, but with intervals not exceeding 15 months, to the maximum pump pressure
or relief valve setting; and
(b)
Visually inspected for damage or defects before each use.
§ 193.2623
Inspecting LNG storage
tanks.
Each LNG storage tank must be inspected or tested to verify
that each of the following conditions does not impair the structural integrity
or safety of the tank:
(a) Foundation
and tank movement during normal operation and after a major meteorological or
geophysical disturbance.
(b) Inner
tank leakage.
(c) Effectiveness of
insulation.
(d) Frost
heave.
§ 193.2625
Corrosion protection.(a) Each
operator shall determine which metallic components could, unless corrosion is
controlled, have their integrity or reliability adversely affected by external,
internal, or atmospheric corrosion during their intended service
life.
(b) Components whose
integrity or reliability could be adversely affected by corrosion must be
either-
(1) Protected from corrosion in
accordance with §§ 193.2627 through 193.2635, as applicable;
or
(2) Inspected and replaced under
a program of scheduled maintenance in accordance with procedures established
under § 193.2605.
§ 193.2627
Atmospheric corrosion
control.
Each exposed component that is subject to atmospheric corrosive
attack must be protected from atmospheric corrosion by:
(a) Material that has been designed and
selected to resist the corrosive atmosphere involved; or
(b) Suitable coating or jacketing.
§ 193.2629
External
corrosion control; buried or submerged components.
(a) Each buried or submerged component that
is subject to external corrosive attack must be protected from external
corrosion by:
(1) Material that has been
designed and selected to resist the corrosive environment involved;
or
(2) The following means:
(i) An external protective coating designed
and installed to prevent corrosion attack and to meet the requirements of
§ 192.461 of this chapter; and
(ii) A cathodic protection system designed to
protect components in their entirety in accordance with the requirements of
§ 192.463 of this chapter and placed in operation before October 23, 1981,
or within 1 year after the component is constructed or installed, whichever is
later.
(b)
Where cathodic protection is applied, components that are electrically
interconnected must be protected as a unit.
§ 193.2631
Internal corrosion
control.
Each component that is subject to internal corrosive attack
must be protected from internal corrosion by:
(a) Material that has been designed and
selected to resist the corrosive fluid involved; or
(b) Suitable coating, inhibitor, or other
means.
§ 193.2633
Interference currents.(a) Each
component that is subject to electrical current interference must be protected
by a continuing program to minimize the detrimental effects of
currents.
(b) Each cathodic
protection system must be designed and installed so as to minimize any adverse
effects it might cause to adjacent metal components.
(c) Each impressed current power source must
be installed and maintained to prevent adverse interference with communications
and control systems.
§
193.2635
Monitoring corrosion control.
Corrosion protection provided as required by this subpart must
be periodically monitored to give early recognition of ineffective corrosion
protection, including the following, as applicable:
(a) Each buried or submerged component under
cathodic protection must be tested at least once each calendar year, but with
intervals not exceeding 15 months, to determine whether the cathodic protection
meets the requirements of § 192.463 of this chapter.
(b) Each cathodic protection rectifier or
other impressed current power source must be inspected at least six times each
calendar year, but with intervals not exceeding 21/2 months, to ensure
that it is operating properly.
(c)
Each reverse current switch, each diode, and each interference bond whose
failure would jeopardize component protection must be electrically checked for
proper performance at least six times each calendar year, but with intervals
not exceeding 21/2 months. Each other interference bond must be checked at
least once each calendar year, but with intervals not exceeding 15
months.
(d) Each component that is
protected from atmospheric corrosion must be inspected at intervals not
exceeding 3 years.
(e) If a
component is protected from internal corrosion, monitoring devices designed to
detect internal corrosion, such as coupons or probes, must be located where
corrosion is most likely to occur. However, monitoring is not required for
corrosion resistant materials if the operator can demonstrate that the
component will not be adversely affected by internal corrosion during its
service life. Internal corrosion control monitoring devices must be checked at
least two times each calendar year, but with intervals not exceeding 71/2
months.
§ 193.2637
Remedial measures.
Prompt corrective or remedial action must be taken whenever an
operator learns by inspection or otherwise that atmospheric, external, or
internal corrosion is not controlled as required by this subpart.
§ 193.2639
Maintenance
records.(a) Each operator shall keep a
record at each LNG plant of the date and type of each maintenance activity
performed on each component to meet the requirements of this part. For each LNG
facility that is designed and constructed after March 31, 2000 the operator
shall also maintain related periodic inspection and testing records that NFPA
59A (incorporated by reference, see § 193.2013) requires. Maintenance
records, whether required by this part or NFPA 59A, must be kept for a period
of not less than five years.
(b)
Each operator shall maintain records or maps to show the location of
cathodically protected components, neighboring structures bonded to the
cathodic protection system, and corrosion protection equipment.
(c) Each of the following records must be
retained for as long as the LNG facility remains in service:
(1) Each record or map required by paragraph
(b) of this section.
(2) Records of
each test, survey, or inspection required by this subpart in sufficient detail
to demonstrate the adequacy of corrosion control measures.
Subpart H
-
Personnel Qualifications and Training§
193.2701
Scope.
This subpart prescribes requirements for personnel
qualifications and training.
§
193.2703
Design and fabrication.
For the design and fabrication of components, each operator
shall use-
(a) With respect to design,
persons who have demonstrated competence by training or experience in the
design of comparable components.
(b) With respect to fabrication, persons who
have demonstrated competence by training or experience in the fabrication of
comparable components.
§
193.2705
Construction, installation, inspection, and
testing.
(a) Supervisors and other
personnel utilized for construction, installation, inspection, or testing must
have demonstrated their capability to perform satisfactorily the assigned
function by appropriate training in the methods and equipment to be used or
related experience and accomplishments.
(b) Each operator must periodically determine
whether inspectors performing construction, installation, and testing duties
required by this part are satisfactorily performing their assigned
function.
§
193.2707
Operations and maintenance.
(a) Each operator shall utilize for operation
or maintenance of components only those personnel who have demonstrated their
capability to perform their assigned functions by-
(1) Successful completion of the training
required by §§ 193.2713 and 193.2717;
(2) Experience related to the assigned
operation or maintenance function; and,
(3) Acceptable performance on a proficiency
test relevant to the assigned function.
(b) A person who does not meet the
requirements of paragraph (a) of this section may operate or maintain a
component when accompanied and directed by an individual who meets the
requirements.
(c) Corrosion control
procedures under § 193.2605(b), including those for the design,
installation, operation, and maintenance of cathodic protection systems, must
be carried out by, or under the direction of, a person qualified by experience
and training in corrosion control technology.
§ 193.2709
Security.
Personnel having security duties must be qualified to perform
their assigned duties by successful completion of the training required under
§ 193.2715.
§
193.2711
Personnel health.
Each operator shall follow a written plan to verify that
personnel assigned operating, maintenance, security, or fire protection duties
at the LNG plant do not have any physical condition that would impair
performance of their assigned duties. The plan must be designed to detect both
readily observable disorders, such as physical handicaps or injury, and
conditions requiring professional examination for discovery.
§ 193.2713
Training; operations
and maintenance.(a) Each operator
shall provide and implement a written plan of initial training to instruct-
(1) All permanent maintenance, operating, and
supervisory personnel-
(i) About the
characteristics and hazards of LNG and other flammable fluids used or handled
at the facility, including, with regard to LNG, low temperatures, flammability
of mixtures with air, odorless vapor, boiloff characteristics, and reaction to
water and water spray;
(ii) About
the potential hazards involved in operating and maintenance activities;
and,
(iii) To carry out aspects of
the operating and maintenance procedures under §§ 193.2503 and
193.2605 that relate to their assigned functions; and
(2) All personnel-
(i) To carry out the emergency procedures
under § 193.2509 that relate to their assigned functions; and
(ii) To give first-aid; and,
(3) All operating and appropriate
supervisory personnel-
(i) To understand
detailed instructions on the facility operations, including controls,
functions, and operating procedures; and
(ii) To understand the LNG transfer
procedures provided under § 193.2513.
(b) A written plan of continuing instruction
must be conducted at intervals of not more than 2 years to keep all personnel
current on the knowledge and skills they gained in the program of initial
instruction.
§
193.2715
Training; security.
(a) Personnel responsible for security at an
LNG plant must be trained in accordance with a written plan of initial
instruction to:
(1) Recognize breaches of
security;
(2) Carry out the
security procedures under § 193.2903 that relate to their assigned
duties;
(3) Be familiar with basic
plant operations and emergency procedures, as necessary to effectively perform
their assigned duties; and,
(4)
Recognize conditions where security assistance is needed.
(b) A written plan of continuing instruction
must be conducted at intervals of not more than 2 years to keep all personnel
having security duties current on the knowledge and skills they gained in the
program of initial instruction.
§ 193.2717
Training; fire
protection.
(a) All personnel involved
in maintenance and operations of an LNG plant, including their immediate
supervisors, must be trained according to a written plan of initial
instruction, including plant fire drills, to:
(1) Know the potential causes and areas of
fire;
(2) Know the types, sizes,
and predictable consequences of fire; and
(3) Know and be able to perform their
assigned fire control duties according to the procedures established under
§ 193.2509 and by proper use of equipment provided under §
193.2801.
(b) A written
plan of continuing instruction, including plant fire drills, must be conducted
at intervals of not more than 2 years to keep personnel current on the
knowledge and skills they gained in the instruction under paragraph (a) of this
section.
(c) Plant fire drills must
provide personnel hands-on experience in carrying out their duties under the
fire emergency procedures required by § 193.2509.
§ 193.2719
Training;
records.
(a) Each operator shall
maintain a system of records which-
(1)
Provide evidence that the training programs required by this subpart have been
implemented; and
(2) Provide
evidence that personnel have undergone and satisfactorily completed the
required training programs.
(b) Records must be maintained for 1 year
after personnel are no longer assigned duties at the LNG plant.
Subpart I
- Fire
Protection§ 193.2801
Scope.
Each operator must provide and maintain fire protection at LNG
plants according to sections 9.1 through 9.7 and section 9.9 of NFPA 59A
(incorporated by reference, see § 193.2013). However, LNG plants existing
on March 31, 2000, need not comply with provisions on emergency shutdown
systems, water delivery systems, detection systems, and personnel qualification
and training until September 12, 2005.
§ 193.2803-193.2821
[Reserved].
Subpart
J
-Security
§
193.2901
Scope.
This subpart prescribes requirements for security at LNG
plants. However, the requirements do not apply to existing LNG plants that do
not contain LNG.
§
193.2903
Security procedures.
Each operator shall prepare and follow one or more manuals of
written procedures to provide security for each LNG plant. The procedures must
be available at the plant in accordance with § 193.2017 and include at
least:
(a) A description and schedule
of security inspections and patrols performed in accordance with §
193.2913;
(b) A list of security
personnel positions or responsibilities utilized at the LNG plant;
(c) A brief description of the duties
associated with each security personnel position or responsibility;
(d) Instructions for actions to be taken,
including notification of other appropriate plant personnel and law enforcement
officials, when there is any indication of an actual or attempted breach of
security;
(e) Methods for
determining which persons are allowed access to the LNG plant;
(f) Positive identification of all persons
entering the plant and on the plant, including methods at least as effective as
picture badges; and,
(g) Liaison
with local law enforcement officials to keep them informed about current
security procedures under this section.
§ 193.2905
Protective
enclosures.
(a) The following
facilities must be surrounded by a protective enclosure:
(1) Storage tanks;
(2) Impounding systems;
(3) Vapor barriers;
(4) Cargo transfer systems;
(5) Process, liquefaction, and vaporization
equipment;
(6) Control rooms and
stations;
(7) Control
systems;
(8) Fire control
equipment;
(9) Security
communications systems; and, (10) Alternative power sources.
The protective enclosure may be one or more separate enclosures
surrounding a single facility or multiple facilities.
(b) Ground elevations outside a
protective enclosure must be graded in a manner that does not impair the
effectiveness of the enclosure.
(c)
Protective enclosures may not be located near features outside of the facility,
such as trees, poles, or buildings, which could be used to breach the
security.
(d) At least two accesses
must be provided in each protective enclosure and be located to minimize the
escape distance in the event of emergency.
(e) Each access must be locked unless it is
continuously guarded. During normal operations, an access may be unlocked only
by persons designated in writing by the operator. During an emergency, a means
must be readily available to all facility personnel within the protective
enclosure to open each access.
§
193.2907
Protective enclosure construction.
(a) Each protective enclosure must have
sufficient strength and configuration to obstruct unauthorized access to the
facilities enclosed.
(b) Openings
in or under protective enclosures must be secured by grates, doors or covers of
construction and fastening of sufficient strength such that the integrity of
the protective enclosure is not reduced by any opening.
§ 193.2909
Security
communications.
A means must be provided for:
(a) Prompt communications between personnel
having supervisory security duties and law enforcement officials; and
(b) Direct communications between all on-duty
personnel having security duties and all control rooms and control
stations.
§
193.2911
Security lighting.
Where security warning systems are not provided for security
monitoring under § 193.2913, the area around the facilities listed under
§ 193.2905(a) and each protective enclosure must be illuminated with a
minimum in service lighting intensity of not less than 2.2 lux (0.2
ftc) between sunset and sunrise.
§ 193.2913
Security
monitoring.
Each protective enclosure and the area around each facility
listed in § 193.2905(a) must be monitored for the presence of unauthorized
persons. Monitoring must be by visual observation in accordance with the
schedule in the security procedures under § 193.2903(a) or by security
warning systems that
continuously transmit data to an attended location. At an LNG
plant with less than 40,000 m3 (250,000 bbl) of
storage capacity, only the protective enclosure must be monitored.
§ 193.2915
Alternative
power sources.
An alternative source of power that meets the requirements of
§ 193.2445 must be provided for security lighting and security monitoring
and warning systems required under §§ 193.2911 and 193.2913.
§ 193.2917
Warning
signs.
(a) Warning signs must be
conspicuously placed along each protective enclosure at intervals so that at
least one sign is recognizable at night from a distance of 30 m (100 ft.) from
any way that could reasonably be used to approach the enclosure.
(b) Signs must be marked with at least the
following on a background of sharply contrasting color: The words "NO
TRESPASSING", or words of comparable meaning.
PART 199
-DRUG AND ALCOHOL
TESTING
Subpart A
-General
§ 199.1
Scope.
(a) This part requires
operators of pipeline facilities subject to part 192, 193, or 195 of this
chapter to test covered employees for the presence of prohibited drugs and
alcohol.
§ 199.2
Applicability.
(a) This part
applies to pipeline operators only with respect to employees located within the
territory of the United States, including those employees located within the
limits of the "Outer Continental Shelf" as that term is defined in the Outer
Continental Shelf Lands Act (43
U.S.C. 1331).
(b) This part does not apply to any person
for whom compliance with this part would violate the domestic laws or policies
of another country.
(c) This part
does not apply to covered functions performed on-
(1) Master meter systems, as defined in
§ 191.3 of this chapter; or
(2) Pipeline systems that transport only
petroleum gas or petroleum gas/air mixtures.
§ 199.3
Definitions.
As used in this part-
"Accident" means an incident reportable under Part
191 involving gas pipeline facilities or LNG facilities.
"Administrator" means the Administrator, Pipeline
and Hazardous Materials Safety Administration or his or her delegate.
"Covered employee, employee, or individual to be
tested" means a person who performs a covered function, including
persons employed by operators, contractors engaged by operators, and persons
employed by such contractors.
"Covered function" means an operations,
maintenance, or emergency-response function regulated by part 192, 193, or 195
of this chapter that is performed on a pipeline or on an LNG facility.
"DOT Procedures" means the Procedures for
Transportation Workplace Drug and Alcohol Testing Programs published by the
Office of the Secretary of Transportation in part 40 of this title.
"Fail a drug test" means that the confirmation
test result shows positive evidence of the presence under DOT Procedures of a
prohibited drug in an employee's system.
"Operator" means a person who owns or operates
pipeline facilities subject to Part 192.
"Pass a drug test" means that initial testing or
confirmation testing under DOT Procedures does not show evidence of the
presence of a prohibited drug in a person's system.
"Performs a covered function" includes actually
performing, ready to perform, or immediately available to perform a covered
function.
"Positive rate for random drug testing" means the
number of verified positive results for random drug tests conducted under this
part plus the number of refusals of random drug tests required by this part,
divided by the total number of random drug tests results (i.e., positives,
negatives, and refusals) under this part.
"Prohibited drug" means any of the following
substances specified in Schedule I or Schedule II of the Controlled Substances
Act (21 U.S.C.
812) : marijuana, cocaine, opiates,
amphetamines, and phencyclidine (PCP).
"Refuse to submit, refuse, or refuse to take"means
behavior consistent with DOT Procedures concerning refusal to take a drug test
or refusal to take an alcohol test.
"State agency" means an agency of any of the
several states, the District of Columbia, or Puerto Rico that participates
under the pipeline safety laws (49
U.S.C. 60101
et
seq.).
§ 199.5
DOT Procedures.
The anti-drug and alcohol programs required by this part must
be conducted according to the requirements of this part and DOT Procedures.
Terms and concepts used in this part have the same meaning as in DOT
Procedures. Violations of DOT Procedures with respect to anti-drug and alcohol
programs required by this part are violations of this part.
§ 199.7
Stand-down
waivers.
(a) Each operator who seeks a
waiver under §40.21 of this title from the stand-down restriction must
submit an application for waiver in duplicate to the Associate Administrator
for Pipeline Safety, Pipeline and Hazardous Materials Safety Administration,
U.S. Department of Transportation, 1200 New Jersey Avenue, SE, Washington, DC
20590-0001.
(b) Each application
must-
(1) Identify §40.21 of this title
as the rule from which the waiver is sought;
(2) Explain why the waiver is requested and
describe the employees to be covered by the waiver;
(3) Contain the information required by
§40.21 of this title and any other information or arguments available to
support the waiver requested; and
(4) Unless good cause is shown in the
application, be submitted at least 60 days before the proposed effective date
of the waiver.
(c) No
public hearing or other proceeding is held directly on an application before
its disposition under this section. If the Associate Administrator determines
that the application contains adequate justification, he or she grants the
waiver. If the Associate Administrator determines that the application does not
justify granting the waiver, he or she denies the application. The Associate
Administrator notifies each applicant of the decision to grant or deny an
application.
§
199.9
Preemption of State and local laws.
(a) Except as provided in paragraph (b) of
this section, this subpart preempts any State or local law, rule, regulation,
or order to the extent that:
(1) Compliance
with both the State or local requirement and this subpart is not
possible;
(2) Compliance with the
State or local requirement is an obstacle to the accomplishment and execution
of any requirement in this subpart; or
(3) The State or local requirement is a
pipeline safety standard applicable to interstate pipeline
facilities.
(b) This
subpart shall not be construed to preempt provisions of State criminal law that
impose sanctions for reckless conduct leading to actual loss of life, injury,
or damage to property, whether the provisions apply specifically to
transportation employees or employers or to the general public.
Subpart B
- Drug
Testing
§ 199.100
Purpose.
The purpose of this subpart is to establish programs designed
to help prevent accidents and injuries resulting from the use of prohibited
drugs by employees who perform covered functions for operators of certain
pipeline facilities subject to part 192, 193, or 195 of this chapter.
§ 199.101
Anti-Drug
Plan.
(a) Each operator shall maintain
and follow a written anti-drug plan that conforms to the requirements of this
subpart and the DOT Procedures. The plan must contain:
(1) Methods and procedures for compliance
with all the requirements of this subpart, including the employee assistance
program;
(2) The name and address
of each laboratory that analyzes the specimens collected for drug
testing;
(3) The name and address
of the operator's Medical Review Officer, and Substance Abuse Professional;
and
(4) Procedures for notifying
employees of the coverage and provisions of the plan.
(b) The Administrator or the State Agency
that has submitted a current certification under the pipeline safety law (49
U.S.C. 60101
et seq.) with
respect to the pipeline facility governed by an operator's plans and procedures
may, after notice and opportunity for hearing as provided in
49 CFR
190.237 or the relevant State procedures,
require the operator to amend its plans and procedures as necessary to provide
a reasonable level of safety.
§
199.103
Use of Persons Who Fail or Refuse a Drug
Test.(a) An operator may not knowingly
use as an employee any person who:
(1) Fails
a drug test required by this subpart and the medical review officer makes a
determination under DOT Procedures; or
(2) Refuses to take a drug test required by
this subpart.
(b)
Paragraph (a)(1) of this section does not apply to a person who has:
(1) Passed a drug test under DOT
Procedures;
(2) Been considered by
the medical review officer in accordance with DOT Procedures and been
determined by a substance abuse professional to have successfully completed
required education or treatment; and
(3) Not failed a drug test required by this
subpart after returning to duty.
§ 199.105
Drug Tests
Required.
Each operator shall conduct the following drug tests for the
presence of a prohibited drug:
(a)
Pre-employment testing. No operator may hire or contract for the use of any
person as an employee unless that person passes a drug test or is covered by an
anti-drug program that conforms to the requirements of this subpart.
(b) Post-accident testing. As soon as
possible but no later than 32 hours after an accident, an operator shall drug
test each employee whose performance either contributed to the accident or
cannot be completely discounted as a contributing factor to the accident. An
operator may decide not to test under this paragraph but such a decision must
be based on the best information available immediately after the accident that
the employee's performance could not have contributed to the accident or that,
because of the time between that performance and the accident, it is not likely
that a drug test would reveal whether the performance was affected by drug
use.
(c) Random testing.
(1) Except as provided in paragraphs (c)(2)
through (4) of this section, the minimum annual percentage rate for random drug
testing shall be 50 percent of covered employees.
(2) The Administrator's decision to increase
or decrease the minimum annual percentage rate for random drug testing is based
on the reported positive rate for the entire industry. All information used for
this determination is drawn from the drug MIS reports required by this subpart.
In order to ensure reliability of the data, the Administrator considers the
quality and completeness of the reported data, may obtain additional
information or reports from operators, and may make appropriate modifications
in calculating the industry positive rate. Each year, the Administrator will
publish in the Federal Register the minimum annual percentage rate for random
drug testing of covered employees. The new minimum annual percentage rate for
random drug testing will be applicable starting January 1 of the calendar year
following publication.
(3) When the
minimum annual percentage rate for random drug testing is 50 percent, the
Administrator may lower this rate to 25 percent of all covered employees if the
Administrator determines that the data received under the reporting
requirements of § 199.119 for two consecutive calendar years indicate that
the reported positive rate is less than 1.0 percent.
(4) When the minimum annual percentage rate
for random drug testing is 25 percent, and the data received under the
reporting requirements of § 199.119 for any calendar year indicate that
the reported positive rate is equal to or greater than 1.0 percent, the
Administrator will increase the minimum annual percentage rate for random drug
testing to 50 percent of all covered employees.
(5) The selection of employees for random
drug testing shall be made by a scientifically valid method, such as a random
number table or a computer-based random number generator that is matched with
employees' Social Security numbers, payroll identification numbers, or other
comparable identifying numbers. Under the selection process used, each covered
employee shall have an equal chance of being tested each time selections are
made.
(6) The operator shall
randomly select a sufficient number of covered employees for testing during
each calendar year to equal an annual percentage rate not less than the minimum
annual percentage rate for random drug testing determined by the Administrator.
If the operator conducts random drug testing through a consortium, the number
of employees to be tested may be calculated for each individual operator or may
be based on the total number of covered employees covered by the consortium who
are subject to random drug testing at the same minimum annual percentage rate
under this subpart or any DOT drug testing rule.
(7) Each operator shall ensure that random
drug tests conducted under this subpart are unannounced and that the dates for
administering random tests are spread reasonably throughout the calendar
year.
(8) If a given covered
employee is subject to random drug testing under the drug testing rules of more
than one DOT agency for the same operator, the employee shall be subject to
random drug testing at the percentage rate established for the calendar year by
the DOT agency regulating more than 50 percent of the employee's
function.
(9) If an operator is
required to conduct random drug testing under the drug testing rules of more
than one DOT agency, the operator may-
(i)
Establish separate pools for random selection, with each pool containing the
covered employees who are subject to testing at the same required rate;
or
(ii) Randomly select such
employees for testing at the highest percentage rate established for the
calendar year by any DOT agency to which the operator is subject.
(d) Testing based on
reasonable cause. Each operator shall drug test each employee when there is
reasonable cause to believe the employee is using a prohibited drug. The
decision to test must be based on a reasonable and articulable belief that the
employee is using a prohibited drug on the basis of specific, contemporaneous
physical, behavioral, or performance indicators of probable drug use. At least
two of the employee's supervisors, one of whom is trained in detection of the
possible symptoms of drug use, shall substantiate and concur in the decision to
test an employee. The concurrence between the two supervisors may be by
telephone. However, in the case of operators with 50 or fewer employees subject
to testing under this subpart, only one supervisor of the employee trained in
detecting possible drug use symptoms shall substantiate the decision to
test.
(e) Return-to-duty testing. A
covered employee who refuses to take or has a positive drug test may not return
to duty in the covered function until the covered employee has complied with
applicable provisions of DOT Procedures concerning substance abuse
professionals and the return-to-duty process.
(f) Follow-up testing. A covered employee who
refuses to take or has a positive drug test shall be subject to unannounced
follow-up drug tests administered by the operator following the covered
employee's return to duty. The number and frequency of such follow-up testing
shall be determined by a substance abuse professional, but shall consist of at
least six tests in the first 12 months following the covered employee's return
to duty. In addition, follow-up testing may include testing for alcohol as
directed by the substance abuse professional, to be performed in accordance
with 49 CFR 40 . Follow-up testing shall not exceed 60 months from the date of
the covered employee's return to duty. The substance abuse professional may
terminate the requirement for follow-up testing at any time after the first six
tests have been administered, if the substances abuse professional determines
that such testing is no longer necessary.
§ 199.107
Drug Testing
Laboratory.(a) Each operator shall use
for the drug testing required by this subpart only drug testing laboratories
certified by the Department of Health and Human Services under the DOT
Procedures.
(b) The drug testing
laboratory must permit:
(1)I nspections by the operator
before the laboratory is awarded a testing contract; and
(2) Unannounced inspections, including
examination of records, at any time, by the operator, the Administrator, and if
the operator is subject to state agency jurisdiction, a representative of that
state agency.
§
199.109
Review of Drug Testing Results.
(a) MRO appointment. Each operator shall
designate or appoint a medical review officer (MRO).
I f an operator does not have a
qualified individual on staff to serve as MRO, the operator may contract for
the provision of MRO services as part of its anti-drug program.
(b) MRO qualifications. Each MRO must be a
licensed physician who has the qualifications required by DOT
Procedures.
(c) MRO duties. The MRO
must perform functions for the operator as required by DOT
Procedures.
(d) MRO reports. The
MRO must report all drug test results to the operator in accordance with DOT
Procedures.
(e) Evaluation and
rehabilitation may be provided by the operator, by a substance abuse
professional under contract with the operator, or by a substance abuse
professional not affiliated with the operator. The choice of substance abuse
professional and assignment of costs shall be made in accordance with the
operator/employee policies.
(f) The
operator shall ensure that a substance abuse professional, who determines that
a covered employee requires assistance in resolving problems with drug abuse,
does not refer the covered employee to the substance abuse professional's
private practice or to a person or organization from which the substance abuse
professional receives remuneration or in which the substance abuse professional
has a financial interest. This paragraph does not prohibit a substance abuse
professional from referring a covered employee for assistance provided through:
(1) A public agency, such as a State, county,
or municipality;
(2) The operator
or a person under contract to provide treatment for drug problems on behalf of
the operator;
(3) The sole source
of therapeutically appropriate treatment under the employee's health insurance
program; or
(4) The sole source of
therapeutically appropriate treatment reasonably accessible to the
employee.
§
199.111
Retention of Samples and Additional Testing.
(a) Samples that yield positive results on
confirmation must be retained by the laboratory in properly secured, long-term,
frozen storage for at least 365 days as required by the DOT Procedures.
Within this 365-day period, the employee or the employee's
representative, the operator, the Administrator, or, if the operator is subject
to the jurisdiction of a state agency, the state agency may request that the
laboratory retain the sample for an additional period.
I f, within the 365-day period,
the laboratory has not received a proper written request to retain the sample
for a further reasonable period specified in the request, the sample may be
discarded following the end of the 365-day period.
(b)I f the medical review officer
(MRO) determines there is no legitimate medical explanation for a confirmed
positive test result other than the unauthorized use of a prohibited drug, and
if timely additional testing is requested by the employee according to DOT
Procedures, the split specimen must be tested. The employee may specify testing
by the original laboratory or by a second laboratory that is certified by the
Department of Health and Human Services. The operator may require the employee
to pay in advance the cost of shipment (if any) and reanalysis of the sample,
but the employee must be reimbursed for such expense if the additional test is
negative.
(c)I f the employee specifies
testing by a second laboratory, the original laboratory must follow approved
chain-of-custody procedures in transferring a portion of the sample.
(d) Since some analytes may deteriorate
during storage, detected levels of the drug below the detection limits
established in the DOT Procedures, but equal to or greater than the established
sensitivity of the assay, must, as technically appropriate, be reported and
considered corroborative of the original positive results.
§ 199.113
Employee Assistance
Program.(a) Each operator shall
provide an employee assistance program (EAP) for its employees and supervisory
personnel who will determine whether an employee must be drug tested based on
reasonable cause. The operator may establish the EAP as a part of its internal
personnel services or the operator may contract with an entity that provides
EAP services. Each EAP must include education and training on drug use. At the
discretion of the operator, the EAP may include an opportunity for employee
rehabilitation.
(b) Education under
each EAP must include at least the following elements: display and distribution
of informational material; display and distribution of a community service
hot-line telephone number for employee assistance; and display and distribution
of the employer's policy regarding the use of prohibited drugs.
(c) Training under each EAP for supervisory
personnel who will determine whether an employee must be drug tested based on
reasonable cause must include one 60-minute period of training on the specific,
contemporaneous physical, behavioral, and performance indicators of probable
drug use.
§ 199.115
Contractor Employees.
With respect to those employees who are contractors or employed
by a contractor, an operator may provide by contract that the drug testing,
education, and training required by this subpart be carried out by the
contractor provided:
(a) The operator
remains responsible for ensuring that the requirements of this subpart are
complied with; and
(b) The
contractor allows access to property and records by the operator, the
Administrator, and if the operator is subject to the jurisdiction of a state
agency, a representative of the state agency for the purpose of monitoring the
operator's compliance with the requirements of this subpart.
§ 199.117
Record
Keeping.
(a) Each operator shall keep
the following records for the periods specified and permit access to the
records as provided by paragraph (b) of this section:
(1) Records that demonstrate the collection
process conforms to this subpart must be kept for at least 3 years.
(2) Records of employee drug test that
indicate a verified positive result, records that demonstrate compliance with
the recommendations of a substance abuse professional, and MI S annual report data shall be
maintained for a minimum of five years.
(3) Records of employee drug test results
that show employees passed a drug test must be kept for at least 1
year.
(4) Records confirming that
supervisors and employees have been trained as required by this part must be
kept for at least 3 years.
(b)I nformation regarding an
individual's drug testing results or rehabilitation must be released upon the
written consent of the individual and as provided by DOT Procedures.
§ 199.119
Reporting of
Anti-Drug Testing Results(a) Each
large operator (having more than 50 covered employees) shall submit an annual
MI S report to PHMSA of its
anti-drug testing using the Management
I nformation System
(MI S) form and instructions as
required by 49 CFR Part 40 (at § 40.25 and appendix H to Part 40), not
later than March 15 of each year for the prior calendar year (January 1 through
December 31). The Administrator shall require by written notice that small
operators (50 or fewer covered employees) not otherwise required to submit
annual MI S reports to prepare and submit
such reports to PHMSA.
(b) Each
report required under this section shall be submitted to the Office of Pipeline
Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department
of Transportation, PHP-60, 1200 New Jersey Avenue, SE., Washington, DC
20590.
(c) To calculate the total
number of covered employees eligible for random testing throughout the year, as
an operator, you must add the total number of covered employees eligible for
testing during each random testing period for the year and divide that total by
the number of random testing periods. Covered employees, and only covered
employees, are to be in an employer's random testing pool, and all covered
employees must be in the random pool.
I f you are an employer
conducting random testing more often than once per month (e.g., you select
daily, weekly, bi-weekly), you do not need to compute this total number of
covered employees rate more than on a once per month basis.
(d) As an employer, you may use a service
agent (e.g., C/TPA) to perform random selections for you; and your covered
employees may be part of a larger random testing pool of covered employees.
However, you must ensure that the service agent you use is testing at the
appropriate percentage established for your industry and that only covered
employees are in the random testing pool.
(e) Each operator that has a covered employee
who performs multi-DOT agency functions (e.g., an employee performs pipeline
maintenance duties and drives a commercial motor vehicle), count the employee
only on the MIS report for the DOT agency under which he or she is randomly
tested. Normally, this will be the DOT agency under which the employee performs
more than 50% of his or her duties. Operators may have to explain the testing
data for these employees in the event of a DOT agency inspection or
audit.
(f) A service agent (e.g.,
Consortia/Third Party Administrator as defined in 49 CFR Part 40) may prepare
the MIS report on behalf of an operator. However, each report shall be
certified by the operator's anti-drug manager or designated representative for
accuracy and completeness.
Subpart C
-Alcohol Misuse Prevention
Program§ 199.200
Purpose.
The purpose of this subpart is to establish programs designed
to help prevent accidents and injuries resulting from the misuse of alcohol by
employees who perform covered functions for operators of certain pipeline
facilities subject to part 192 of this code.
§ 199.201
[Reserved]
§ 199.202
Alcohol Misuse Plan.
Each operator must maintain and follow a written alcohol misuse
plan that conforms to the requirements of this part and DOT Procedures
concerning alcohol testing programs. The plan shall contain methods and
procedures for compliance with all the requirements of this subpart, including
required testing, record keeping, reporting, education and training
elements.
§§ 199.203-199.205 [Reserved]
§ 199.209
Other
Requirements Imposed by Operators.(a)
Except as expressly provided in this subpart, nothing in this subpart shall be
construed to affect the authority of operators, or the rights of employees,
with respect to the use or possession of alcohol, including authority and
rights with respect to alcohol testing and rehabilitation.
(b) Operators may, but are not required to,
conduct pre-employment alcohol testing under this subpart. Each operator that
conducts pre-employment alcohol testing must-
(1) Conduct a pre-employment alcohol test
before the first performance of covered functions by every covered employee
(whether a new employee or someone who has transferred to a position involving
the performance of covered functions);
(2) Treat all covered employees the same for
the purpose of pre-employment alcohol testing (i.e., you must not test some
covered employees and not others);
(3) Conduct the pre-employment tests after
making a contingent offer of employment or transfer, subject to the employee
passing the pre-employment alcohol test;
(4) Conduct all pre-employment alcohol tests
using the alcohol testing procedures in DOT Procedures; and
(5) Not allow any covered employee to begin
performing covered functions unless the result of the employee's test indicates
an alcohol concentration of less than 0.04.
§ 199.211
Requirements for
Notice.
Before performing an alcohol test under this subpart, each
operator shall notify a covered employee that the alcohol test is required by
this subpart. No operator shall falsely represent that a test is administered
under this subpart.
§
199.213
[Reserved]
§ 199.215
Alcohol
Concentration.
Each operator shall prohibit a covered employee from reporting
for duty or remaining on duty requiring the performance of covered functions
while having an alcohol concentration of 0.04 or greater. No operator having
actual knowledge that a covered employee has an alcohol concentration of 0.04
or greater shall permit the employee to perform or continue to perform covered
functions.
§ 199.217
On-duty Use.
Each operator shall prohibit a covered employee from using
alcohol while performing covered functions. No operator having actual knowledge
that a covered employee is using alcohol while performing covered functions
shall permit the employee to perform or continue to perform covered
functions.
§ 199.219
Pre-duty Use.
Each operator shall prohibit a covered employee from using
alcohol within four hours prior to performing covered functions, or, if an
employee is called to duty to respond to an emergency, within the time period
after the employee has been notified to report for duty. No operator having
actual knowledge that a covered employee has used alcohol within four hours
prior to performing covered functions or within the time period after the
employee has been notified to report for duty shall permit that covered
employee to perform or continue to perform covered functions.
§ 199.221
Use following an
Accident.
Each operator shall prohibit a covered employee who has actual
knowledge of an accident in which his or her performance of covered functions
has not been discounted by the operator as a contributing factor to the
accident from using alcohol for eight hours following the accident, unless he
or she has been given a post-accident test under § 199.225(a), or the
operator has determined that the employee's performance could not have
contributed to the accident.
§
199.223
Refusal to Submit to a Required Alcohol
Test.
Each operator shall require a covered employee to submit to a
post-accident alcohol test required under § 199.225(a), a reasonable
suspicion alcohol test required under § 199.225(b), or a follow-up alcohol
test required under § 199.225(d). No operator shall permit an employee who
refuses to submit to such a test to perform or continue to perform covered
functions.
§ 199.225
Alcohol Tests Required.
Each operator shall conduct the following types of alcohol
tests for the presence of alcohol:
(a)
Post-accident.
(1) As soon as practicable
following an accident, each operator shall test each surviving covered employee
for alcohol if that employee's performance of a covered function either
contributed to the accident or cannot be completely discounted as a
contributing factor to the accident. The decision not to administer a test
under this paragraph shall be based on the operator's determination, using the
best available information at the time of the determination, that the covered
employee's performance could not have contributed to the accident.
(2)
(i) If
a test required by this section is not administered within two hours following
the accident, the operator shall prepare and maintain on file a record stating
the reasons the test was not promptly administered. If a test required by
paragraph (a) is not administered within eight hours following the accident,
the operator shall cease attempts to administer an alcohol test and shall state
in the record the reasons for not administering the test.
(ii) Removed and reserved.
(3) A covered employee who is
subject to post-accident testing who fails to remain readily available for such
testing, including notifying the operator or operator representative of his/her
location if he/she leaves the scene of the accident prior to submission to such
test, may be deemed by the operator to have refused to submit to testing.
Nothing in this section shall be construed to require the delay of necessary
medical attention for injured people following an accident or to prohibit a
covered employee from leaving the scene of an accident for the period necessary
to obtain assistance in responding to the accident or to obtain necessary
emergency medical care.
(b) Reasonable suspicion testing.
(1) Each operator shall require a covered
employee to submit to an alcohol test when the operator has reasonable
suspicion to believe that the employee has violated the prohibitions in this
subpart.
(2) The operator's
determination that reasonable suspicion exists to require the covered employee
to undergo an alcohol test shall be based on specific, contemporaneous,
articulable observations concerning the appearance, behavior, speech, or body
odors of the employee. The required observations shall be made by a supervisor
who is trained in detecting the symptoms of alcohol misuse. The supervisor who
makes the determination that reasonable suspicion exists shall not conduct the
breath alcohol test on that employee.
(3) Alcohol testing is authorized by this
section only if the observations required by subparagraph (b)(2) of this
paragraph are made during, just preceding, or just after the period of the work
day that the employee is required to be in compliance with this subpart. A
covered employee may be directed by the operator to undergo reasonable
suspicion testing for alcohol only while the employee is performing covered
functions; just before the employee is to perform covered functions; or just
after the employee has ceased performing covered functions.
(4)
(i) If
a test required by this paragraph is not administered within two hours
following the determination under subparagraph (b)(2) of this paragraph, the
operator shall prepare and maintain on file a record stating the reasons the
test was not promptly administered. If a test required by this paragraph is not
administered within eight hours following the determination under subparagraph
(b)(2) of this paragraph, the operator shall cease attempts to administer an
alcohol test and shall state in the record the reasons for not administering
the test. Records shall be submitted to PHMSA upon request of the
Administrator.
(ii) Removed and
reserved.
(iii) Notwithstanding the
absence of a reasonable suspicion alcohol test under this paragraph, an
operator shall not permit a covered employee to report for duty or remain on
duty requiring the performance of covered functions while the employee is under
the influence of or impaired by alcohol, as shown by the behavioral, speech, or
performance indicators of alcohol misuse, nor shall an operator permit the
covered employee to perform or continue to perform covered functions, until:
(A) An alcohol test is administered and the
employee's alcohol concentration measures less than 0.02; or
(B) The start of the employee's next
regularly scheduled duty period, but not less than 8 hours following the
determination under subparagraph (b)(2) of this paragraph that there is
reasonable suspicion to believe that the employee has violated the prohibitions
in this subpart.
(iv)
Except as provided in subparagraph (b)(4)(ii), no operator shall take any
action under this subpart against a covered employee based solely on the
employee's behavior and appearance in the absence of an alcohol test. This does
not prohibit an operator with the authority independent of this subpart from
taking any action otherwise consistent with law.
(c) Return-to-duty testing. Each
operator shall ensure that before a covered employee returns to duty requiring
the performance of a covered function after engaging in conduct prohibited by
§§ 199.215 through 199.223, the employee shall undergo a
return-to-duty alcohol test with a result indicating an alcohol concentration
of less than 0.02.
(d) Follow-up
testing.
(1) Following a determination under
§ 199.243(b) that a covered employee is in need of assistance in resolving
problems associated with alcohol misuse, each operator shall ensure that the
employee is subject to unannounced follow-up alcohol testing as directed by a
substance abuse professional in accordance with the provisions of §
199.243(c)(2)(ii).
(2) Follow-up
testing shall be conducted when the covered employee is performing covered
functions; just before the employee is to perform covered functions; or just
after the employee has ceased performing such functions.
(e) Retesting of covered employees with an
alcohol concentration of 0.02 or greater but less than 0.04. Each operator
shall retest a covered employee to ensure compliance with the provisions of
§ 199.237, if an operator chooses to permit the employee to perform a
covered function within eight hours following the administration of an alcohol
test indicating an alcohol concentration of 0.02 or greater but less than
0.04.
§ 199.227
Retention of Records.(a)
General requirement. Each operator shall maintain records of its alcohol misuse
prevention program as provided in this paragraph. The records shall be
maintained in a secure location with controlled access.
(b) Period of retention. Each operator shall
maintain the records in accordance with the following schedule:
(1) Five years. Records of employee alcohol
test results with results indicating an alcohol concentration of 0.02 or
greater, documentation of refusals to take required alcohol tests, calibration
documentation, employee evaluation and referrals, and MIS annual report data
shall be maintained for a minimum of five years.
(2) Two years. Records related to the
collection process (except calibration of evidential breath testing devices),
and training shall be maintained for a minimum of two years.
(3) One year. Records of all test results
below 0.02 (as defined in 49 CFR Part 40) shall be maintained for a minimum of
one year.
(c) Types of
records. The following specific records shall be maintained:
(1) Records related to the collection
process:
(i) Collection log books, if
used.
(ii) Calibration
documentation for evidential breath testing devices.
(iii) Documentation of breath alcohol
technician training.
(iv) Documents
generated in connection with decisions to administer reasonable suspicion
alcohol tests.
(v) Documents
generated in connection with decisions on post-accident tests.
(vi) Documents verifying existence of a
medical explanation of the inability of a covered employee to provide adequate
breath for testing.
(2)
Records related to test results:
(i) The
operator's copy of the alcohol test form, including the results of the
test.
(ii) Documents related to the
refusal of any covered employee to submit to an alcohol test required by this
subpart.
(iii) Documents presented
by a covered employee to dispute the result of an alcohol test administered
under this subpart.
(3)
Records related to other violations of this subpart.
(4) Records related to evaluations:
(i) Records pertaining to a determination by
a substance abuse professional concerning a covered employee's need for
assistance.
(ii) Records concerning
a covered employee's compliance with the recommendations of the substance abuse
professional.
(5)
Record(s) related to the operator's MIS annual testing data.
(6) Records related to education and
training:
(i) Materials on alcohol misuse
awareness, including a copy of the operator's policy on alcohol
misuse.
(ii) Documentation of
compliance with the requirements of § 199.231.
(iii) Documentation of training provided to
supervisors for the purpose of qualifying the supervisors to make a
determination concerning the need for alcohol testing based on reasonable
suspicion.
(iv) Certification that
any training conducted under this subpart complies with the requirements for
such training.
§ 199.229
Reporting of Alcohol
Testing Results.(a) Each large
operator (having more than 50 covered employees) shall submit an annual MIS
report to PHMSA of its alcohol testing results using the Management Information
System (MIS) form and instructions as required by 49 CFR Part 40 (at §
40.25 and appendix H to Part 40),
not later than March 15 of each year for the previous calendar year (January 1
through December 31). The Administrator may require by written notice that
small operators (50 or fewer covered employees) not otherwise required to
submit annual MIS reports to prepare and submit such reports to
PHMSA.
(b) Each operator that has a
covered employee who performs multi-DOT agency functions (e.g., an employee
performs pipeline maintenance duties and drives a commercial motor vehicle),
count the employee only on the MIS report for the DOT agency under which he or
she is tested. Normally, this will be the DOT agency under which the employee
performs more than 50% of his or her duties. Operators may have to explain the
testing data for these employees in the event of a DOT agency inspection or
audit.
(c) Each report required
under this section shall be submitted to the Office of Pipeline Safety,
Pipeline and Hazardous Materials Safety Administration, U.S. Department of
Transportation, PHP-60, 1200 New Jersey Avenue, SE., Washington, DC
20590-0001.
(d) A service agent
(e.g., Consortia/Third Party Administrator as defined in Part 40) may prepare
the MIS report on behalf of an operator. However, each report shall be
certified by the operator's anti-drug manager or designated representative for
accuracy and completeness.
§
199.231
Access to Facilities and Records.
(a) Except as required by law or expressly
authorized or required in this subpart, no employer shall release covered
employee information that is contained in records required to be maintained in
§ 199.227.
(b) A covered
employee is entitled, upon written request, to obtain copies of any records
pertaining to the employee's use of alcohol, including any records pertaining
to his or her alcohol tests. The operator shall promptly provide the records
requested by the employee. Access to an employee's records shall not be
contingent upon payment for records other than those specifically
requested.
(c) Each operator shall
permit access to all facilities utilized in complying with the requirements of
this subpart to the Secretary of Transportation, any DOT agency, or a
representative of a state agency with regulatory authority over the
operator.
(d) Each operator shall
make available copies of all results for employer alcohol testing conducted
under this subpart and any other information pertaining to the operator's
alcohol misuse prevention program, when requested by the Secretary of
Transportation, any DOT agency with regulatory authority over the operator, or
a representative of a state agency with regulatory authority over the operator.
The information shall include name-specific alcohol test results, records, and
reports.
(e) When requested by the
National Transportation Safety Board as part of an accident investigation, an
operator shall disclose information related to the operator's administration of
any post-accident alcohol tests administered following the accident under
investigation.
(f) An operator
shall make records available to a subsequent employer upon receipt of the
written request from the covered employee. Disclosure by the subsequent
employer is permitted only as expressly authorized by the terms of the
employee's written request.
(g) An
operator may disclose information without employee consent as provided by DOT
Procedures concerning certain legal proceedings.
(h) An operator shall release information
regarding a covered employee's records as directed by the specific, written
consent of the employee authorizing release of the information to an identified
person. Release of such information by the person receiving the information is
permitted only in accordance with the terms of the employee's
consent.
§ 199.233
Removal from Covered Function.
Except as provided in §§ 199.239 through 199.243, no
operator shall permit any covered employee to perform covered functions if the
employee has engaged in conduct prohibited by §§ 199.215 through
199.223 or an alcohol misuse rule of another DOT agency.
§ 199.235
Required Evaluation and
Testing.
No operator shall permit a covered employee who has engaged in
conduct prohibited by §§ 199.215 through 199.223 to perform covered
functions unless the employee has met the requirements of §
199.243.
§ 199.237
Other Alcohol-related Conduct.
(a) No operator shall permit a covered
employee tested under the provisions of § 199.225, who is found to have an
alcohol concentration of 0.02 or greater but less than 0.04, to perform or
continue to perform covered functions, until:
(1) The employee's alcohol concentration
measures less than 0.02 in accordance with a test administered under §
199.225(e); or
(2) The start of the
employee's next regularly scheduled duty period, but not less than eight hours
following administration of the test.
(b) Except as provided in paragraph (a) of
this section, no operator shall take any action under this subpart against an
employee based solely on test results showing an alcohol concentration less
than 0.04. This does not prohibit an operator with authority independent of
this subpart from taking any action otherwise consistent with law.
§ 199.239
Operator
Obligation to Promulgate a Policy on the Misuse of Alcohol.
(a) General requirement. Each operator shall
provide educational materials that explain these alcohol misuse requirements
and the operator's policies and procedures with respect to meeting those
requirements.
(1) The operator shall ensure
that a copy of these materials is distributed to each covered employee prior to
the start of alcohol testing under this subpart, and to each person
subsequently hired for or transferred to a covered position.
(2) Each operator shall provide written
notice to representatives of employee organizations of the availability of this
information.
(b)
Required content. The materials to be made available to covered employees shall
include detailed discussion of at least the following:
(1) The identity of the person designated by
the operator to answer covered employee's questions about the
materials.
(2) The categories of
employees who are subject to the provisions of this subpart.
(3) Sufficient information about the covered
functions performed by those employees to make clear what period of the work
day the covered employee is required to be in compliance with this
subpart.
(4) Specific information
concerning covered employee conduct that is prohibited by this
subpart.
(5) The circumstances
under which a covered employee will be tested for alcohol under this
subpart.
(6) The procedures that
will be used to test for the presence of alcohol, protect the covered employee
and the integrity of the breath testing process, safeguard the validity of the
test results, and ensure that those results are attributed to the correct
employee.
(7) The requirement that
a covered employee submit to alcohol tests administered in accordance with this
subpart.
(8) An explanation of what
constitutes a refusal to submit to an alcohol test and the attendant
consequences.
(9) The consequences
for covered employees found to have violated the prohibitions under this
subpart, including the requirement that the employee be removed immediately
from covered functions, and the procedures under § 199.243.
(10) The consequences for covered employees
found to have an alcohol concentration of 0.02 or greater but less than
0.04.
(11) Information concerning
the effects of alcohol misuse on an individual's health, work, and personal
life; signs and symptoms of an alcohol problem (the employee's or a
coworker's); and including intervening evaluating and resolving problems
associated with the misuse of alcohol including intervening when an alcohol
problem is suspected, confrontation, referral to any available EAP, and/or
referral to management.
(c) Optional provisions. The materials
supplied to covered employees may also include information on additional
operator policies with respect to the use or possession of alcohol, including
any consequences for an employee found to have a specified alcohol level, that
are based on the operator's authority independent of this subpart. Any such
additional policies or consequences shall be clearly described as being based
on independent authority.
§
199.241
Training for Supervisors.
Each operator shall ensure that persons designated to determine
whether reasonable suspicion exists to require a covered employee to undergo
alcohol testing under §
199.225(b)
receive at least 60 minutes of training on the physical, behavioral, speech,
and performance indicators of probable alcohol misuse.
§ 199.243
Referral, Evaluation,
and Treatment.
(a) Each covered
employee who has engaged in conduct prohibited by §§
199.215 through
199.223 of this subpart shall be
advised of the resources available to the covered employee in evaluating and
resolving problems associated with the misuse of alcohol, including the names,
addresses, and telephone numbers of substance abuse professionals and
counseling and treatment programs.
(b) Each covered employee who engages in
conduct prohibited under §§
199.215 through
199.223 shall be evaluated by a
substance abuse professional who shall determine what assistance, if any, the
employee needs in resolving problems associated with alcohol misuse.
(c)
(1)
Before a covered employee returns to duty requiring the performance of a
covered function after engaging in conduct prohibited by §§
199.215 through
199.223 of this subpart, the
employee shall undergo a return-to-duty alcohol test with a result indicating
an alcohol concentration of less than 0.02.
(2) In addition, each covered employee
identified as needing assistance in resolving problems associated with alcohol
misuse:
(i) Shall be evaluated by a substance
abuse professional to determine that the employee has properly followed any
rehabilitation program prescribed under paragraph (b) of this
section.
(ii) Shall be subject to
unannounced follow-up alcohol tests administered by the operator following the
employee's return to duty. The number and frequency of such follow-up testing
shall be determined by a substance abuse professional, but shall consist of at
least six tests in the first 12 months following the employee's return to duty.
In addition, follow-up testing may include testing for drugs, as directed by
the substance abuse professional, to be performed in accordance with 49 CFR
Part 40 . Follow-up testing shall not exceed 60 months from the date of the
employee's return to duty. The substance abuse professional may terminate the
requirement for follow-up testing at any time after the first six tests have
been administered, if the substance abuse professional determines that such
testing is no longer necessary.
(d) Evaluation and rehabilitation may be
provided by the operator, by a substance abuse professional under contract with
the operator, or by a substance abuse professional not affiliated with the
operator. The choice of substance abuse professional and assignment of costs
shall be made in accordance with the operator/employee agreements and
operator/employee policies.
(e) The
operator shall ensure that a substance abuse professional who determines that a
covered employee requires assistance in resolving problems with alcohol misuse
does not refer the employee to the substance abuse professional's private
practice or to a person or organization from which the substance abuse
professional receives remuneration or in which the substance abuse professional
has a financial interest. This paragraph does not prohibit a substance abuse
professional from referring an employee for assistance provided through:
(1) A public agency, such as a State, county,
or municipality;
(2) The operator
or a person under contract to provide treatment for alcohol problems on behalf
of the operator;
(3) The sole
source of therapeutically appropriate treatment under the employee's health
insurance program; or
(4) The sole
source of therapeutically appropriate treatment reasonably accessible to the
employee.
§
199.245
Contractor Employees.
(a) With respect to those covered employees
who are contractors or employed by a contractor, an operator may provide by
contract that the alcohol testing, training and education required by this
subpart be carried out by the contractor provided:
(b) The operator remains responsible for
ensuring that the requirements of this subpart and 49 CFR Part 40 are complied
with; and
(c) The contractor allows
access to property and records by the operator, the Administrator, any DOT
agency with regulatory authority over the operator or covered employee, and if
the operator is subject to the jurisdiction of a state agency, a representative
of the state agency for the purposes of monitoring the operator's compliance
with the requirements of this subpart and 49 CFR Part 40.
