Docket
|
Date
|
Order No.
|
Subject Matter of Docket/Order
|
U-2424
|
01/02/73
|
--
|
Adoption of Arkansas Gas Pipeline Code.
|
U-2683
|
01/30/76
|
--
|
General Revisions to Code.
|
U-2794
|
02/24/77
|
--
|
General Revisions to Code.
|
U-2908
|
02/03/78
|
--
|
General Revisions to Code.
|
U-2999
|
02/15/79
|
--
|
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
|
03/11/81
|
3
|
Amends requirements concerning plastic pipe joining and
external corrosion control monitoring.
|
82-059-R
|
04/16/82
|
6
|
Adds Part 190 - Pipeline Safety Enforcement Procedures,
and updates industry standards publications.
|
83-015-R
|
03/07/83
|
2
|
Adds requirements for a Damage Prevention Program, and
provides flexibility in scheduling inspections and tests.
|
84-034-R
|
07/06/84
|
4
|
General Code revisions.
|
85-086-R
|
08/21/85
|
3
|
Revised Part 191 - Transportation of Natural and Other
Gas by Pipeline: Annual Reports and Incident Reports. Also revised the Code
format. Complete republication by Order No. 4.
|
|
|
|
regarding plastic pipe, welder qualification,
preheating, stress relieving, nondestructive testing, bends and elbows.
|
88-005-R
|
07/14/88
|
4
|
Revised Part 190 to provide for waivers, extensions,
response to accident recommendations, and re-numbered paragraphs. Part 192
amended for Class locations, MAOP, testing repairs, odorization testing, damage
prevention, & R/V calculation.
|
89-034-R
|
08/02/89
|
3
|
Part 191 amended to include Safety-Related Condition
Reports. Part 192 amended for deletion of outdated references, adding
requirements for safety-related conditions to be included in O & M plans,
testing requirements for tie-in joints. Added Part 199 - Drug Testing.
Establishes an employee drug testing program required of operators subject to
Part 192.
|
90-015-R
|
03/23/90
|
3
|
General revisions with emphasis on updating of
Standards & Specifications; class location vs. MAOP; cast/ductile iron,
& copper pipe; Part 199 - changes caused by deletion of "Rehabilitation
Committee" & its definition; changes in Drug tests required.
|
91-056-R
|
06/06/91
|
3
|
Care when using tracer wire with plastic pipe, and
lubrication requirements for valves.
|
92-036-R
|
05/12/92
|
3
|
Parts 192 and 199 changed to reflect requirement of
operators to amend plans and procedures as necessary for safety. Preface and
Part 190 changed to reflect increase in civil penalties.
|
93-020-R
|
04/26/93
|
3
|
Parts 191 and 192 changed to include certain gathering
lines containing 100 ppm or more of hydrogen sulphide. Part 192 further changed
by correcting certain discrepancies not previously discovered. Code format
revised and complete republication of the Arkansas Gas Pipeline Code.
|
94-025-R
|
09/12/94
|
4
|
Update of referenced Standards & Specifications;
addition of requirement for gas detection in certain compressor station
buildings; clarification of leakage survey requirements. Part 199 changes to
record keeping, and a new requirement for an annual report on the anti-drug
program.
|
95-116-R
|
04/27/95
|
3
|
Definitions section and Parts 190 and 192 changed to
reflect the requirement that certain new and replacement pipelines be designed
and constructed to accommodate instrumented internal inspection devices. Part
190 changed to clarify the language in the issuance and handling of show cause
orders. Part 192 changed to require meters which have been installed indoors to
be in a ventilated place and not less than 3 feet from any source of ignition
or source of heat which might damage the meter, to require detailed procedures
in O&M manuals, that operators review and update their O&M manuals each
year, and that operators prepare and follow procedures to safeguard personnel
from unsafe accumulations of vapors or gas in excavated trenches. Part 199
reformatted to add Subpart B, Alcohol Misuse Prevention Program. Preface
changed to include new title of Part 199. Complete republication of the
Arkansas Gas Pipeline Code.
|
96-181-R
|
08/20/96
|
3
|
Preface and Part 190 changed to reflect increased civil
penalties. Part 192 changed to include notification requirement for
customer-owned service lines, to extend existing excavation damage prevention
requirements for gas pipelines in urban areas to gas pipelines in rural areas,
and to require, with limited exceptions, line markers for transmission lines in
urban areas. Part 199 changed to allow for the possibility of a reduced random
drug testing rate, and to require reporting of information concerning missed
tests. Complete republication of the Arkansas Gas Pipeline Code.
|
97-034-R
|
04/03/97
|
3
|
Preface changed to explain the codification of the
Natural Gas Pipeline Safety Act. Definition of "petroleum gas" added and
definition of "transmission line" revised in the Definitions section. Numerous
minor changes to Parts 191 and 192. Addition of performance standards for
excess flow valves to Part 192. Appendices A and B to Part 192 updated. Minor
revisions to Part 199. Complete republication of the Arkansas Gas Pipeline
Code.
|
99-130-R
|
08/02/99
|
3
|
All Parts changed to include metric equivalents for
English measures. Part 192 changed to require that Excess Flow Valves ("EFO")
close at 50% or less of the manufacturer's rated closure flow rate while
operating at 10 pounds per square inch gauge (psig); 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
|
08/26/04
|
4
|
Part 190.15 revised to include falsification of
paperwork as probable violation. Part 192.17 revised to allow the use of a
certified letter for notification of probable violation. New Subpart N -
Operator Qualification added. Minor changes to Subpart I and M. Complete
republication of the Arkansas Gas Pipeline Code.
|
04-088-R
|
08/26/04
|
3
|
Adopted Federal Office of Pipeline Safety Amendments
192-86A , 192-89, 192-89A, 192-93, 192-95, 199-19 and 199-21.
|
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 $25,000 for each violation for each day that such violation persists,
except that the maximum civil penalty shall not exceed $500,000 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; and 199, Drug and Alcohol Testing. The paragraphs in Parts 191, 192,
and 199 correspond to the paragraph numbers of Parts 191, 192, and 199 of Title
49, Code of Federal Regulations, Minimum Federal Safety Standards.
DEFINITIONS
DEFINITIONS OF WORDS/PHRASES USED IN THE ARKANSAS GAS PIPELINE
CODE
"Abandoned" means permanently removed from
service.
"Administrator" means the Administrator of the
Research and Special Programs Administration or any person to whom authority in
the matter concerned has been delegated by the U.S. Secretary of
Transportation.
"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.
"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.
"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 1 of Appendix B.
"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 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.
"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 psig (1434 kPa) gage at 100°F (38°C).
"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 appurtenance attached to pipe,
compressor units, metering stations, regulator stations, delivery stations,
holders, and fabricated assemblies.
"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, including any facility that removes hydrogen sulfide
from gas.
"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 paragraph 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 distribution center, storage
facility, or large volume customer that is not downstream from a distribution
center. A large volume customer may receive similar volumes of gas as a
distribution center, and includes factories, power plants, and institutional
users of gas.
(2) Operates at a
hoop stress of 20 percent or more of SMYS; or
(3) Transports gas within a storage field.
"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 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 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, 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. Pipeline Safety, Arkansas Public Service Commission, upon
receiving petitions initiated under this paragraph, shall provide the
Administrator a written recommendation as to the disposition of any petition
received by Pipeline Safety. Where the Administrator does not reverse or modify
a recommendation made by Pipeline Safety 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, application may be made to the Commission for exemption
from a particular standard. The application for exemption hall 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 paragraph 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
Arkansas Public Service 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 commission staff 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
paragraph 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 Paragraph 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 Paragraph
190.21(a);
(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 twenty-five thousand dollars ($25,000)
for each violation for each day that the violation persists, except that the
maximum civil penalty shall not exceed five hundred thousand dollars ($500,000)
for any related series of violations. Before assessing a civil penalty, the
Commission shall follow the procedures established by Paragraphs 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 in
rural areas outside of any incorporated or unincorporated city, town or
village, or any designated residential or commercial area such as a
subdivision, business or shopping center, or community development; however, it
shall apply to the gathering, transmission or distribution of gas containing
100 or more parts-per-million of hydrogen sulfide from the wellhead through any
pipeline, rural or non-rural, to and through any pipeline facility that removes
hydrogen sulfide. 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 Arkansas Public Service Commission, Office of Pipeline Safety,
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 that resulted in:
(1) A death or personal injury requiring
in-patient hospitalization; or
(2)
Estimated property damage, including cost of lost gas, of the operator or
others, or both, of $50,000 or more; or
(3) An event that is significant, in the
judgement of the operator, even though it did not meet the criteria of
subparagraphs (l) or (2).
Incidents reportable under Subparagraphs (1), (2), or (3)
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 shall be made by telephone to 800-424-8802 (in Washington, D.C.,
267-2675) and shall 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 682-5705 or 682-5706 during normal business hours Monday through
Friday. Reports during other than normal hours will be made to Pipeline Safety
personnel in accordance with instructions issued by Pipeline Safety, Public
Service Commission.
(d) In addition
to the requirements of Paragraph (a) of this section, all as 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, 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 paragraphs 191.23 and 191.25 will
be submitted directly to: Information Resources Manager, Office of Pipeline
Safety, Research and Special Programs Administration, U.S. Department of
Transportation, Room 2335, 400 Seventh Street SW, Washington, DC 20590. 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
RSPA F7100.1 as soon as practicable but not more than 20 days after detection
of an incident required to be reported under Paragraph 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) The incident report required by this
section need not be submitted with respect to master meter systems or LNG
facilities.
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 RSPA 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; or
(3) LNG facilities.
191.13
Distribution Systems
Reporting Transmission Pipelines: Trans-mission 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 Paragraphs 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 Paragraphs 191.9 and 191.11.
191.15
Transmission and Gathering
Systems: Incident Report.
(a) Each
operator of a transmission system or a gathering system subject to the
jurisdiction of the Commission, shall submit Department of Transportation Form
RSPA F7100.2 as soon as practicable but not more than 20 days after detection
of an incident required to be reported under Paragraph 191.5(a) or
(d).
(b) The incident report
required by Paragraph (a) of this section need not be submitted with respect to
LNG facilities.
(c) 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 and Gathering Systems: Annual Report.
(a) 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 RSPA F7100.2-1. This
report must be submitted for the preceding calendar year, not later than
February 15 of each year.
(b) The
annual report required by Paragraph (a) of this section need not be submitted
with respect to LNG facilities.
191.19
Report Forms.
Copies of the prescribed report forms are available without
charge upon request from the addresses given in Paragraph 191.7. Additional
copies in this prescribed format may be reproduced and used if in the same size
and kind of paper. In addition, the information required by these forms may be
submitted by any other means that is acceptable to the Administrator.
191.23
Reporting
Safety-Related Conditions.
(a) Except
as provided in paragraph (b) of this section, each operator shall report in
accordance with paragraph 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 paragraph 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
Scope.
(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 in rural areas outside of any incorporated
or unincorporated city, town or village and any designated residential or
commercial area such as a subdivision, business or shopping center; however, it
shall apply to the gathering, transmission or distribution of gas containing
100 or more parts-per-million of hydrogen sulfide from the wellhead through any
pipeline, rural or non-rural, to and through any pipeline facility that removes
hydrogen sulfide.
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
Incorporation by
Reference.
(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 Research and Special Programs Administration, 400 Seventh
Street, SW., Washington, DC, and at the Office of the Federal Register, 800
North Capitol Street, NW., Suite 700, Washington, DC. 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 Appendix A to this part.
(c) The full titles for the publications
incorporated by reference in this part are provided in Appendix A to this part.
Numbers in parentheses indicate applicable editions. Earlier editions of
documents listed or editions of documents formerly listed in previous editions
of Appendix A may be used for materials and components manufactured, designed
or installed in accordance with those earlier editions or earlier documents at
the time they were listed. The user must refer to the appropriate previous
edition of 49 CFR for a listing of the earlier listed editions or
documents.
192.9
Gathering Lines.
Except as provided in §§192.1 and 192.150, and in
subpart O, each operator of a gathering line must comply with the requirements
of this part applicable to transmission lines.
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 a 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
General.
(a) No person may
operate a segment of pipeline that is readied for service after March 12, 1971,
unless:
(1) The pipeline has been designed,
installed, constructed, initially inspected, and initially tested in accordance
with this part; or
(2) The pipeline
qualified for use under this part in accordance with Paragraph
192.14.
(b) No person
may operate a segment of pipeline that is replaced, relocated, or otherwise
changed after November 12, 1970, unless that replacement, relocation, or change
has been made in accordance with this part.
(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 Paragraph 192.465 if the customer's
buried piping is metallic, survey for leaks according to Paragraph 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 psi (41 MPa) where no close coiling or close bending is to be
done, if visual examination indicates that the pipe is in good condition and
that it is free of split seams and other defects that would cause leakage. If
it is to be welded, steel pipe that has not been manufactured to a listed
specification must also pass the weldability tests prescribed in Paragraph II-B
of Appendix B to this 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.
(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 D
2513; or
(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.
In a pipeline to be operated at a hoop stress of 20 percent or
more of SMYS, no operator may use a pipe having an outer diameter to wall
thickness ratio of 70 to 1 or more, that is transported by railroad
unless:
(a) The transportation is
performed in accordance with API RP 5L1.
(b) 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.
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:
Click
here to view image
P = Design pressure in pounds per square inch
(kPa) gage.
S = Yield strength in pounds per square inch (kPa)
determined in accordance with Paragraph 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
Paragraph 192.109. Additional wall thickness required for concurrent external
loads in accordance with Paragraph 192.103 may not be included in computing
design pressure.
F = Design factor determined in accordance with
Paragraph 192.111.
E = Longitudinal joint factor determined in
accordance with Paragraph 192.113.
T = Temperature derating factor determined in
accordance with Paragraph 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 Paragraph 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 Paragraph
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
psi.
(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 Paragraph 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 Paragraph 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 Paragraph
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 Paragraph 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 Paragraph 192.105 for each compressor station, regulator station,
and measuring station.
192.113
Longitudinal Joint Factor (E)
for Steel Pipe.
The longitudinal joint factor to be used in the design formula
in Paragraph 192.105 is determined in accordance with the following
table:
Specification
|
Pipe Class
|
Longitudinal Joint Factor (E
|
ASTM A 53
|
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 Paragraph 192.105 is determined as follows:
Gas Temperature in Degrees Fahrenheit (Celsius)
|
Temperature Derating Factor (T)
|
250EF (121EC) or less
..................................
|
......................... 1.000
|
300EF (149EC)
.............................................
|
......................... 0.967
|
350EF (177EC)
.............................................
|
......................... 0.933
|
400EF (204EC)
.............................................
|
......................... 0.900
|
450EF (232EC)
.............................................
|
......................... 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 Paragraph 192.123, the design
pressure for plastic pipe is determined in accordance with either of the
following formulas:
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P = Design pressure, gauge, kPa (psi).
S = For thermoplastic pipe the long-term
hydrostatic strength 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): for reinforced thermosetting plastic pipe,
11,000 psi. (75,842 kPa).
T = Specified wall thickness, mm (in).
D = Specified outside diameter, mm (in).
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.
192.123
Design Limitations
for Plastic Pipe.
(a) The design
pressure may not exceed a gauge pressure of 689 kPa (100 psig.) 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) In the case of thermoplastic pipe, above
the temperature at which the long-term hydrostatic strength used in the design
formula under Paragraph 192.121 is determined, except that in the case of
reinforced thermosetting plastic pipe, above 150°F ( 66°C).
(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 in inches (millimeters)
|
2 (51) ...................................
|
.................... 0.060 (1.52)
|
3 (76) ....................................
|
.................... 0.060 (1.52)
|
4 (102) .................................
|
.................... 0.070 (1.78)
|
6 (152) ..................................
|
.................... 0.060 (2.54)
|
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. O.D., inch (millimeter)
|
Wall Thickness, inch (millimeter) Nominal
Tolerance
|
2 (13) ........
|
.625 (16) ...........
|
.040 (1.06)
|
.0035 (.0889)
|
e (16) ........
|
.750 (19) ...........
|
.042 (1.07)
|
.0035 (.0889)
|
: (19) ........
|
.875 (22) ...........
|
.045 (1.14)
|
.004 (.102)
|
1 (25) ........
|
1.125 (29) ............
|
.050 (1.27)
|
.004 (.102)
|
1 3 (32) ......
|
1.375 (35) ...........
|
.055 (1.40)
|
.0045 (.1143)
|
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 psi. (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 psia
(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.
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.
192.144
Qualifying Metallic
Components.
Notwithstanding any requirement of this subpart which
incorporates by reference an edition of a document listed in Appendix A 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
Appendix A:
(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, or equivalent, of API 6D. 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.
(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 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 psi. (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 pressure containing parts made of 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
line section of a transmission line where the line pipe, valve, fitting, or
other line component is replaced 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 Paragraph 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 an impracticability prohibits compliance with subparagraph (a) of this
paragraph. Within 30 days after discovering the emergency or construction
problem the operator must petition, under Paragraph 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 13 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 psi. (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.
(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.
(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:
C = Minimum clearance between pipe containers or
bottles in inches (millimeters).
Click
here to view image
D = Outside diameter of pipe containers or bottles
in inches (millimeters).
P = Maximum allowable operating pressure, psi.
(KPa) gage.
F = Design factor as set forth in Paragraph
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 l,000 psi. (7 MPa) gage
................
|
....25 (7.6)
|
1,000 psi. (7 MPa) or more
..........................
|
..100 (31)
|
(2)
Designed using the design factors set forth in Paragraph 192.111; and
(3) Buried with a minimum cover in accordance
with Paragraph 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 A 372/A 372M.
(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 22 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 72 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.
(b) Thermoplastic fittings for plastic pipe
must conform to ASTM D-2513.
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 Paragraph 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 Paragraphs 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 Paragraph
192.622.
(b) If the maximum actual
operating pressure of the distribution system is 60 psi. (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 psi. (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 psi. (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 psi. (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 psi.(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 psi.(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 psi. (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 psi. (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 psi. (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 psi. (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 psi. (83 kPa) gage or more, but less
than 60 psi. (414 kPa) gage, the pressure may not exceed the maximum allowable
operating pressure plus 6 psi. (41kPa) gage; or
(iii) If the maximum allowable operating
pressure is less than 12 psi. (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 400EF (204EC).
(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 - General.
(a) Welding
must be performed by a qualified welder in accordance with welding procedures
qualified to produce welds meeting the requirements of this subpart. The
quality of the test welds used to qualify the procedure shall be determined by
destructive testing.
(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 3 of API Standard 1104 or Section IX of the ASME Boiler and Pressure
Vessel Code. However, a welder qualified under an earlier edition than listed
in Appendix A 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. A welder who makes welded service line connections to mains must
also perform an acceptable test weld under Section II of Appendix C to this
part as a part 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 Paragraph
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 section 3 or 6 of API Standard 1104, except
that a welder qualified under an earlier edition previously listed in Appendix
A of this part may weld but 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 Paragraph 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
Paragraph 192.227(b); or
(2) Within
the preceding 7 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
122½° 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 to insure 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 Paragraph 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 6 of API Standard 1104.
However, if a girth weld is unacceptable under those standards for a reason
other than a crack, and if the Appendix to API Standard 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 Paragraph 192.241(c).
(d) When nondestructive testing is required
under Paragraph 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 Paragraph 192.241(b).
(f) When nondestructive testing is required
under Paragraph 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 Paragraph 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 Paragraph 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. The
joining of plastic pipe must be performed by a person qualified by experience
or training in the joining of plastic pipe. Each joint must be made in
accordance with written procedures that have been proven by destructive burst
test to provide joints at least as strong as the pipe being joined. Plastic
pipe shall not be joined by a threaded or miter joint. Plastic pipe
manufactured from polyethylene shall be joined by heat fusion or mechanical
joints.
(b)
Solvent
cement joints. Each solvent cement joint on plastic pipe must
comply with the following:
(1) Plastic pipe
manufactured from different materials shall not be joined by solvent cement
joints.
(2) The plastic fittings
and solvent cement must conform to the specifications listed in ASTM
Designation D 2513.
(3) The mating
surfaces of the joint must be clean, dry, and free of material which might be
detrimental to the joint.
(4) The
joint may not be heated to accelerate the setting of the cement.
NOTE: Failure to comply with safety requirements may
result in personal injury.
(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 of the fittings manufacturer or equipment and
techniques shown, by testing joints to the requirements of paragraph
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 Paragraph 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 Pressure (Quick Burst)) of ASTM D 2513;
(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 D 2517.
(iii) In the case of electrofusion fittings
for polyethylene pipe and tubing, paragraph 9.1 (Minimum Hydraulic Burst
Pressure Test), paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile
Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM Designation
F1055.
(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 nonlateral
pipe connections, follow the tensile test requirements of ASTM D 638, 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 Paragraph
192.273(b) is used for making mechanical 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 D 638 (except for conditioning).
(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 Paragraph 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 Paragraph 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 Paragraphs 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: inches (324 millimeters) or less in outer diameter; or
(ii) More than 2 percent of the nominal pipe
diameter in pipe over 12: 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 Paragraph 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 12½° 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 transmission line
or main that is constructed above ground 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.
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.
(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.
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 Paragraph 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).
(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) All pipe which is installed in a
navigable river, stream, or harbor must have a minimum cover of 48 inches (1219
millimeters) in soil or 24 inches (610 millimeters) in consolidated rock
between the top of the pipe and the natural bottom. However, less than the
minimum cover is permitted in accordance with Paragraph (c) of this
section.
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 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.
(c)
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 psi. (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
Paragraph 192.281(e).
(c) 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
Paragraph 192.273.
(b) If a
threaded tap is being inserted, the requirements of Paragraphs 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 psi.
(689 kPa) gage must be constructed of pipe designed for a minimum of 100 psi.
(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 psi. (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 psi. (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 Customer Notification.
(a)
Definitions. As used in
this section:
Costs associated with installation means the
costs directly connected with installing an excess flow valve, for example,
costs of parts, labor, inventory and procurement. It does not include
maintenance and replacement costs until such costs are incurred.
Replaced service line means a natural 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 customer means the person who
pays the gas bill, or where service has not yet been established, the person
requesting service.
(b)
Which customers must receive notification. Notification is
required on each newly installed service line or replaced service line that
operates continuously throughout the year at a pressure not less than 68.9 kPa
(10 psig) and that serves a single residence. On these lines an operator of a
natural gas distribution system must notify the service line customer once in
writing.
(c)
What to put in
the written notice.
(1) An
explanation for the customer that an excess flow valve meeting the performance
standards prescribed under § 192.381 is available for the operator to
install if the customer bears the costs associated with installation;
(2) An explanation for the customer of the
potential safety benefits that may be derived from installing an excess flow
valve. The explanation must include that an excess flow valve is designed to
shut off the flow of gas automatically if the service line breaks;
(3) A description of installation,
maintenance, and replacement costs. The notice must explain that if the
customer requests the operator to install an EFV, the customer bears all costs
associated with installation, and what those costs are. The notice must alert
the customer that costs for maintaining and replacing an EFV may later be
incurred, and what those costs will be, to the extent known.
(d)
When notification and
installation must be made.
(1) After
February 3, 1999 an operator must notify each service line customer set forth
in paragraph (b) of this section:
(i) On new
service lines when the customer applies for service.
(ii) On replaced service lines when the
operator determines the service line will be replaced.
(2) If a service line customer requests
installation an operator must install the EFV at a mutually agreeable
date.
(e)
What
records are required.
(1) An 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.
(i) A copy of the notice currently in use;
and
(ii) Evidence that notice has
been sent to the service line customers set forth in paragraph (b) of this
section, within the previous three years.
(2) [Reserved]
(f)
When notification is not
required. The notification requirements do not apply if the operator
can demonstrate -
(1) That the operator will
voluntarily install an excess flow valve or that the state or local
jurisdiction requires installation;
(2) That excess flow valves meeting the
performance standards in §192.381 are not available to the
operator;
(3) That an operator has
prior experience with contaminants in the gas stream that could interfere with
the operation of an excess flow valve, cause loss of service to a residence, or
interfere with necessary operation or maintenance activities, such as blowing
liquids from the line.
(4) That an
emergency or short time notice replacement situation made it impractical for
the operator to notify a service line customer before replacing a service line.
Examples of these situations would be where an operator has to replace a
service line quickly because of -
(i) Third
party excavation damage;
(ii) Grade
1 leaks as defined in the Appendix G - 192 - 11 of the Gas Piping Technology
Committee guide for gas transmission and distribution systems;
(iii) A short notice service line relocation
request.
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
Applicability to 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 Paragraph 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.
192.453
General.
The corrosion control procedures required by Paragraph
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 Paragraph 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 Secs. 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 Paragraph 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 22 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 22 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. In this section:
(1) Active corrosion means continuing
corrosion which, unless controlled, could result in a condition that is
detrimental to public safety.
(2)
Electrical survey means a series of closely spaced pipe-to-soil readings over a
pipeline that are subsequently analyzed to identify locations where a corrosive
current is leaving the pipeline.
(3) 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.
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.
192.477
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 7½ months.
192.479
Atmospheric Corrosion Control:
General.
Sec. 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 inspection 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 Sec. 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 Paragraph
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.
192.491
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 paragraph 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 Paragraph 192.505(a), if air, natural gas, or inert gas is used
as the test medium, the following maximum hoop stress limitations apply:
Maximum Hoop Stress Allowed as Percentage of
SMYS
|
Class Location
|
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;
or
(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.
(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 PSI. (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 psi. (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 psi. (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 PSI. (689 kPa) Gage.
Except for service lines and plastic pipelines, each segment of
a pipeline that is to be operated below 100 psig. 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 psi. (6.9 kPa) gage must be tested to at least 10
psi. (69 kPa) gage and each main to be operated at or above 1 psi. (6.9 kPa)
gage must be tested to at least 90 psi. (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 psi. (6.9 kPa)
gage shall be given a leak test at a pressure of 10 psi. (69 kPa) gage. This
test shall be conducted with a 3 inch (76 millimeters) dial gauge with a
maximum scale of 30 psi. (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 psi. (6.9 kPa) gage but not more than 40 psi. (276 kPa) gage must be
given a leak test at a pressure of not less than 50 psi. (345 kPa) gage on a
100 psi. (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 psig. must
be tested to at least 90 psig. on 100 psig. 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 Paragraph 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 psi. (345 kPa) gage whichever
is greater. However, the maximum test pressure may not be more than three times
the pressure determined under Paragraph 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 Paragraphs 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 Sec. Sec. 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 Paragraph 192.555(c), a new
maximum allowable operating pressure established under this subpart may not
exceed the maximum that would be allowed under Sec. 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 (Paragraph 192.105) is unknown,
the MAOP may be increased as provided in Paragraph 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 Paragraph 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 psi. (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:
ALLOWANCE Inches (millimeters) Cast Iron
Pipe
|
Pipe Size Inches (millimeters)
|
Pit Cast Pipe
|
Centrifugally Cast Pipe
|
Ductile Iron Pipe
|
2-8(51-203)
|
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 psi. (76 MPa) gage and a modulus of rupture of 31,000 psi.
(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 paragraph
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 Sec. 192.615(a)(3) specifically apply to these reports.
(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 paragraph
191.23.
(e) Surveillance, emergency
response, and accident investigation. The procedures required by paragraphs
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, the maximum
allowable operating pressure is 0.8 times the test pressure in Class 2
locations, 0.667 times the test pressure in Class 3 locations, or 0.555 times
the test pressure in Class 4 locations. The corresponding hoop stress may not
exceed 72 percent of the SMYS of the pipe in Class 2 locations, 60 percent of
SMYS in Class 3 locations, or 50 percent of SMYS in Class 4
locations.
(2) The maximum
allowable operating pressure of the segment involved must be reduced so that
the corresponding hoop stress is not more than that allowed by this part for
new segments of pipelines in the existing class location.
(3) The segment involved must be tested in
accordance with the applicable requirements of Subpart J of this part, and its
maximum allowable operating pressure must then be established according to the
following criteria:
(i) The maximum allowable
operating pressure after the requalification test is 0.8 times the test
pressure for Class 2 locations, 0.667 times the test pressure for Class 3
locations, and 0.555 times the test pressure for Class 4 locations.
(ii) The corresponding hoop stress may not
exceed 72 percent of the SMYS of the pipe in Class 2 locations, 60 percent of
SMYS in Class 3 locations, or 50 percent of SMYS in Class 4
locations.
(b) The maximum allowable operating pressure
confirmed or revised in accordance with this section, may not exceed the
maximum allowable operating pressure established before the confirmation or
revision.
(c) Confirmation or
revision of the maximum allowable operating pressure of a segment of pipeline
in accordance with this section does not preclude the application of paragraphs
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 paragraph 192.609 must be completed
within 18 months of the change in class location. Pressure reduction under
paragraph (a)(1) or (2) of this section within the 18-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
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 Paragraphs 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 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
Paragraph 192.617, if applicable, as soon after the end of the emergency as
possible.
(b) Each
operator shall:
(1) Furnish its supervisors
who are responsible for emergency action a copy of that portion of the latest
edition of the emergency procedures established under Paragraph (a) of this
section as necessary for compliance with those procedures.
(2) Train the appropriate operating personnel
to assure that they are knowledgeable of the emergency procedures and verify
that the training is effective.
(3)
Review employee activities to determine whether the procedures were effectively
followed in each emergency.
(c) Each operator shall establish and
maintain liaison with appropriate fire, police, and other public officials to:
(1) Learn the responsibility and resources of
each government organization that may respond toa 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 Education.
Each operator shall establish a continuing educational program
to enable customers, the public, appropriate government organizations, and
persons engaged in excavation related activities to recognize a gas pipeline
emergency for the purpose of reporting it to the operator or the appropriate
public officials. The program and the media used must be as comprehensive as
necessary to reach all areas in which the operator transports gas. 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.
192.617
Investigation of
Failures.
Each operator shall establish procedures for analyzing
accidents and failures, including the selection of samples of the failed
facility or equipment for laboratory examination, where appropriate, for the
purpose of determining the causes of the failure and minimizing the possibility
of a recurrence.
192.619
Maximum Allowable Operating Pressure: Steel or Plastic Pipelines.
(a) Except as provided in Paragraph (c) of
this section, no person may operate a segment of steel or plastic pipeline at a
pressure that exceeds the lowest of the following:
(1) The design pressure of the weakest
element in the segment, determined in accordance with Subparts C and D of this
part. However, for steel pipe in pipelines being converted under Paragraph
192.14 or uprated under subpart K of this part, if any variable necessary to
determine the design pressure under the design formula (Paragraph 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 N5.0 of Appendix N of ASME/ANSI B31.8,
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 psi. (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 psi. (689
kPa) gage or more, the test pressure is divided by a factor determined in
accordance with the following table:
Factors, Segment
|
Class Location
|
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 July 1, 1970,
unless the segment was tested in accordance with Paragraph (a)(2) of this
section after July 1, 1965, or the segment was uprated in accordance with
Subpart K of this part.
(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 Paragraph
192.195.
(c) Notwithstanding the
other requirements of this section, 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 July 1, 1970, subject to the
requirements of Paragraph 192.611.
(d) The maximum allowable operating pressure
shall be designated following the above procedures and posted on system maps,
drawings, regulator stations or other appropriate records.
192.621
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 psi. (414 kPa) gage for a segment of a
distribution system otherwise designed to operate at over 60 psi. (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 Paragraph 192.197(c).
(3) 25 psi. (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 Paragraph 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 Paragraph 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.
(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.
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 .........................
|
72 months, but at ..............
least twice each calendar year.
|
15 months, but at least once each calendar year.
|
3 .........................
|
42 months, but at ..............
least four times each calendar year.
|
72 months, but at least twice each calendar
year.
|
4 .........................
|
42 months, but at ..............
least four times each calendar year.
|
42 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 Paragraph 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 72 months, but at least twice each calendar year; and
(b) In Class 4 locations, at intervals not
exceeding 42 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 Paragraph
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)
Each operator shall 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. As soon as feasible, the operator shall make
permanent repairs.
(b)
Except as provided in Paragraph 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 Paragraph 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 Paragraph
192.245.
(b) A weld may be repaired
in accordance with Paragraph 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 psi (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 Paragraphs
192.713, 192.715, and 192.717 must be examined in accordance with Paragraph
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 2 months, but at least 4 times each calendar year; and
(2) Outside business districts, at intervals
not exceeding 7 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
years. However, for cathodically unprotected distribution lines subject to
§ 192.465(e) on which electrical surveys for corrosion are impractical,
survey intervals may not exceed 3 years.
(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) Initials of 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
www.npms.rspa.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
Information Officer, Research and Special Programs Administration, Department
of Transportation, Room 7128, 400 Seventh Street, SW, Washington DC 20590; fax
(202) 366-4566; e-mail, roger.little@rspa.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) Data on
pipeline facilities abandoned before October 10, 2000 must be filed by before
April 10, 2001. Operators may submit reports by mail, fax or e-mail to the
Information Officer, Research and Special Programs Administration, Department
of Transportation, Room 7128, 400 Seventh Street, SW, Washington DC 20590; fax
(202) 366-4566; e-mail, roger.little@rspa.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.
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 Paragraphs 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.
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:
(a) Pressure regulating
devices.
(1) 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.
(2) Shuts off pressure within acceptable
limits.
(3) Second stage regulator
will withstand and control first stage inlet pressure if a relief valve is not
installed between regulators.
(4)
Properly installed control lines, controllers, actuators and protected from
conditions that may prevent proper operation.
(b) Pressure limiting and relief devices.
(1) Monitor regulators tested for proper
operating parameters.
(2) Set to
control or relieve at the correct pressures consistent with the pressure limits
of Sec. 192.201(a).
(3) Vent stacks
are free of obstructions, properly routed, vented outside of building and vents
adequately covered.
(4) 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.
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: Testing 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 consistent with
the pressure limits of Sec. 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 psi (172kPa) gage must be
sealed with:
(1) A mechanical leak clamp;
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
Paragraphs 192.53(a) and (b) and Paragraph 192.143.
(b) Each cast iron caulked bell
and spigot joint that is subject to pressures of 25 psi (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 Paragraphs 192.317(a),
192.319, and 192.361(b) - (d).
HIGH CONSEQUENCE AREAS
192.761
Definitions.
The following definitions apply to this section and Sec.
192.763:
A high consequence area means any of the following
areas:
(a) An area defined as a Class
3 location under Sec. 192.5;
(b) An
area defined as a Class 4 location under Sec. 192.5;
(c) For a pipeline not more than 12 inches in
nominal diameter and operating at a maximum allowable operating pressure of not
more than 1200 p.s.i.g., an area which extends 300 feet from the centerline of
the pipeline to the identified site;
(d) For a pipeline greater than 30 inches in
nominal diameter and operating at a maximum allowable operating pressure
greater than 1000 p.s.i.g., an area which extends 1000 feet from the centerline
of the pipeline to the identified site; and
(e) For a pipeline not described in paragraph
(c) or (d) of this section, an area which extends 660 feet from the centerline
of the pipeline to the identified site.
(f) An identified site. An identified site is
a building or outside area that--
(1) Is
visibly marked;
(2) Is licensed or
registered by a Federal, State, or local agency;
(3) Is known by public officials;
or
(4) Is on a list or map
maintained by or available from a Federal, State, or local agency or a publicly
or commercially available database; and
(5) Is 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, and assisted-living facilities; or
(6) There is evidence of use of the site by
at least 20 or more persons on at least 50 days in any 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, religious facilities, and recreational areas near bodies of
water.
SUBPART
N
- 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; and
(g) Identify those
covered tasks and the intervals at which evaluation of the individual's
qualifications is needed.
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.
(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.
Subpart
O
-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:
(a)
(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 radius 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) any area outside a Class 3 or Class 4
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
(4) the area within a potential impact circle
containing an identified site.
(b) The area within a potential impact circle
containing
(1) 20 or more buildings intended
for human occupancy, unless the exception in paragraph (d) applies; or
(2) an identified site.
(c) Where a potential impact
circle is calculated under either method (a) or (b) 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.)
(d) If in identifying a high
consequence area under paragraph (a)(3) or paragraph (b)(1), 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 December17, 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; ibr, 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 (a) or (b)
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)
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.
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.
(1) visible marking (e.g., a sign);
or
(2) the site is licensed or
registered by a Federal, State, or local government agency; or
(3) 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 (a) or (b). 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
(ibr, 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
e
lements 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 (ibr, 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 (ibr, 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 (ibr, 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 (ibr, 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 (ibr, see §192.7),
section 6.4; NACE RP0502-2002 (ibr, 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 (ibr, see §192.7), section 6.4, and in NACE
RP 0502-2002 (ibr, 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 RP
0502-2002, 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 RP0502-2002, 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 RP 0502-2002, 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 RP
0502-2002, 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 RP0502-2002), or (b) root
cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2
of NACE RP0502-2002);
(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 RP0502-2002.
(4)
Post assessment and
continuing evaluation. In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE RP 0502-2002, 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
RP0502-2002.)
§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 (ibr, 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," (ibr, 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 criteriaof §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 (ibr, 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 RP 0502-2002 (ibr, 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 that 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 that the condition is unlikely to pose a threat to the
integrity of the pipeline until the next reassessment of the covered segment.
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. If pressure is reduced, an operator must determine the
temporary reduction in operating pressure using ASME/ANSI B31G (ibr, see
§192.7) or AGA Pipeline Research Committee Project PR-3-805 ([RSTRENG];
ibr, see §192.7) or reduce the operating pressure to a level not exceeding
80% of the level at the time the condition was discovered. (See Appendix A to
this part 192 for information on availability of incorporation by reference
information). A reduction in operating pressure cannot exceed 365 days without
an operator providing a technical justification that the continued pressure
restriction will not jeopardize the integrity of the pipeline.
(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 that prioritizes 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 (ibr, see §192.7),
section 7, Figure 4. If an operator cannot meet the schedule for any condition,
the operator must justify the reasons why it cannot meet the schedule and that
the changed schedule will not jeopardize public safety. An operator must notify
OPS in accordance with §192.949 if it cannot meet the schedule and cannot
provide safety through a temporary reduction in operating pressure or other
action. 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.
(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 to1.1 times
the maximum allowable operating pressure at the location of the anomaly.
Suitable remaining strength calculationmethods 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 notexceeded. 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 (ibr, 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, suchas 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
RP-0502-2002 (ibr, 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, the requirements for a low stress external
corrosion reassessment in §192.941(b) and the requirements for a low
stress internal corrosion reassessment in §192.941(c). 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 (ibr, 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 RP0502-2002 (ibr, 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, on a
semi-annual basis, 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 (ibr, see §192.7), 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, by
electronic or other means, on a semi-annual frequency to OPS in accordance with
§192.951. An operator must submit its first report on overall performance
measures by August 31, 2004. Thereafter, the performance measures must be
complete through June 30 and December 31 of each year and must be submitted
within 2 months after those dates.
(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 OPS?
An operator must provide any notification required by this
subpart by -
(1) Sending the
notification to the Information Resources Manager, Office of Pipeline Safety,
Research and Special Programs Administration, U.S. Department of
Transportation, Room 7128, 400 Seventh Street SW, Washington DC
20590;
(2) Sending the notification
to the Information Resources Manager by facsimile to (202) 366-7128;
or
§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 -
(1) by mail to the Office of Pipeline Safety,
Research and Special Programs Administration, U.S. Department of
Transportation, Room 7128, 400 Seventh Street S.W., Washington, DC
20590;
(2) via facsimile to
(202)366-7128; or
(3) through the
online reporting system provided by OPS for electronic reporting available at
the OPS Home Page at http://ops.dot.gov.
APPENDIX A-INCORPORATED BY REFERENCE
I.
List of Organizations and
Addresses.
A. American Gas
Association (AGA), 1515 Wilson Boulevard, Arlington, VA 22209
B. American National Standards Institute
(ANSI), 11 West 42nd Street, New York, N.Y. 10036.
C. American Petroleum Institute (API), 1220
L. Street, NW., Washington, D.C. 20005.
D. The American Society of Mechanical
Engineers (ASME) United Engineering Center, 345 East 47th Street, New York,
N.Y. 10017.
E. American Society for
Testing and Materials (ASTM), 100 Barr Harbor Drive, West Conshohocken, PA
19428.
F. Manufacturers
Standardization Society of the Valve and Fittings Industry (MSS), 127 Park
Street, NW., Vienna, VA 22180.
G.
National Fire Protection Association (NFPA), 1 Batterymarch Park, P.O. Box
9101, Quincy, MA. 02269-9101.
II.
Documents Incorporated by
Reference. (Numbers in parentheses indicate applicable
editions.)
A.
American
Gas Association (AGA):
1. AGA
Pipeline Research Committee, Project PR-3-805, "A Modified Criterion for
Evaluating the Remaining Strength of Corroded Pipe" (December 22,
1989)
B.
American Petroleum Institute (API):
1. API Specification 5L "Specification for
Line Pipe" (41st edition, 1995).
2.
API Recommended Practice 5L1 "Recommended Practice for Railroad Transportation
of Line Pipe" (4th edition, 1990).
3. API Specification 6D "Specification for
Pipeline Valves (Gate, Plug, Ball, and Check Valves)" (21st edition,
1994).
4. API Standard 1104
"Welding of Pipelines and Related Facilities" (18th Edition, 1994).
C.
The American
Society for Testing and Materials (ASTM):
1. ASTM Designation: A 53 "Standard
Specification for Pipe, Steel, Black and Hot Dipped, Zinc-Coated, Welded and
Seamless" (A53-96).
2. ASTM
Designation A 106 "Standard Specification for Seamless Carbon Steel Pipe for
High-Temperature Service" (A106-95).
3. ASTM Designation: A 333/A 333M "Standard
Specification for Seamless and Welded Steel Pipe for Low-Temperature Service"
(A 333/A 333M-94).
4. ASTM
Designation: A 372/A 372M "Standard Specification for Carbon and Alloy Steel
Forgings for Thin-Walled Pressure Vessels" (A 372/A 372M-95).
5. ASTM Designation: A 381 "Standard
Specification for Metal-Arc-Welded Steel Pipe for Use with High-Pressure
Transmission Systems" (A 381-93).
6. ASTM Designation: A 671 "Standard
Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower
Temperatures" (A 671-94).
7. ASTM
Designation: A 672 "Standard Specification for Electric-Fusion-Welded Steel
Pipe for High-Pressure Service at Moderate Temperatures" (A 672-94).
8. ASTM Designation: A 691 "Standard
Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for
High-Pressure Service at High Temperatures" (A 691-93).
9. ASTM Designation D638 "Standard Test
Method for Tensile Properties of Plastics" (D638-96).
10. ASTM Designation D2513 "Standard
Specification for Thermoplastic Gas Pressure Pipe, Tubing and Fittings"
(D2513-87 edition for § 192.63(a)(1), otherwise D2513-96a).
11. ASTM Designation: D 2517 "Standard
Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (D
2517-94).
12. ASTM Designation: F
1055 "Standard Specification for Electrofusion Type Polyethylene Fittings for
Outside Diameter Controlled Polyethylene Pipe and Tubing (F 1055-95).
D.
The American
Society of Mechanical Engineers (ASME):
1. ASME/ANSI B16.1 "Cast Iron Pipe Flanges
and Flanged Fittings" (1989).
2.
ASME/ANSI B16.5 "Pipe Flanges and Flanged Fittings" (1988 with October 1988
Errata and ASME/ANSI B16.5a-1992 Addenda).
3. ASME/ANSI B31G "Manual for Determining the
Remaining Strength of Corroded Pipelines (1991).
4. ASME/ANSI B31.8 "Gas Transmission and
Distribution Systems (1995).
5.
ASME Boiler and Pressure Vessel Code, Section I "Power Boilers" (1995 edition
with 1995 Addenda).
6. ASME Boiler
and Pressure Vessel Code, Section VIII, Division 1 "Pressure Vessels" (1995
edition with 1995 Addenda).
7. ASME
Boiler and Pressure Vessel Code, Section VIII, Division 2 "Pressure Vessels:
Alternative Rules" (1995 edition with 1995 Addenda).
8. ASME Boiler and Pressure Vessel Code,
Section IX "Welding and Brazing Qualifications" (1995 edition with 1995
Addenda).
9. ASME/ANSI B31.8S- 2001
(Supplement to B31.8), "Managing System Integrity of Gas Pipelines," July19,
2002.
E.
Manufacturer's Standardization Society of the Valve and Fittings
Industry, Inc. (MSS):
1. MSS
SP44-96 "Steel Pipe Line Flanges" (includes 1996 errata) (1996).
2. [Reserved].
F.
National Fire Protection
Association (NFPA):
1. NFPA 30
"Flammable and Combustible Liquids Code" (1996).
2. ANSI/NFPA Standard 58 "Standard for the
Storage and Handling of Liquefied Petroleum Gases" (1995).
3. ANSI/NFPA Standard 59 "Standard for the
Storage and Handling of Liquefied Petroleum Gases at Utility Gas Plants"
(1995).
4. ANSI/NFPA 70 "National
Electrical Code" (1996).
G.
NACE
International
1. NACE
RP-0502-2002 "Pipeline External Corrosion Direct Assessment Methodology,"
2002.
H.
Gas
Research Institute
1. GRI
02-0057, "Internal Corrosion Direct Assessment of Gas Transmission Pipelines -
Methodology," April 1, 2002.
APPENDIX B-QUALIFICATION OF PIPE
I.
Listed Pipe Specifications.
Numbers in parentheses indicate applicable
editions.
NOTE: Galvanized pipe of any specification shall
not be used to transport natural gas.
API 5L -- Steel Pipe (1995).
ASTM A 53 -- Steel Pipe (1995a).
ASTM A 106 -- Steel Pipe (1994a).
ASTM A 333/A 333M -- Steel Pipe (1994).
ASTM A 381 -- Steel Pipe (1993).
ASTM A 671 -- Steel Pipe (1994).
ASTM A 672 -- Steel pipe (1994).
ASTM A 691 -- Steel Pipe (1993).
ASTM D 2513 -- Thermoplastic Pipe and Tubing (1995c).
ASTM D 2517 -- Thermosetting Plastic Pipe and Tubing
(1994).
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, 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 fields 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. 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. 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 psi. (165 MPa) or less, or
the tensile properties may be established by performing tensile tests as set
forth in API Specification 5L. 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
Paragraph 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.
QInspection. 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-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 c inch (3.2 millimeters) long in any direction, the
weld is unacceptable. Cracks that occur on the corner of the specimen during
testing are not considered.
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-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 (a) or (b) 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).
(a) If an operator selects
method (a), then:
(1) All pipeline in class 3
and class 4 locations is considered to be in a high consequence area.
(2) The operator is to calculate potential
impact circles, as defined in §192.903, centered on the centerline of the
pipeline for:
(i) any areas of its pipeline
system that are not in class 3 or class 4 locations which could include an
identified site as defined in §192.903, and
(ii) any pipeline in class 3 and class 4
locations for which the potential impact radius would be greater than 660 feet
(200 meters) and for which an identified site may exist in the area more than
660 feet (200 meters) but less than the potential impact radius from the
pipeline.
(3) The
operator is to evaluate the potential impact circles to determine if they
contain identified sites, as defined in §192.903, in accordance with
paragraph (c) of the same section.
(4) The operator is to complete
identification of high consequence areas by December 17, 2004. (b) If an
operator selects method (b) then:
(1) The
operator is to calculate potential impact circles, as defined in §192.903,
centered on the centerline of the pipeline for all areas of its pipeline where
the circles could contain 20 buildings intended for human occupancy or an
identified site.
(2) The operator
is to evaluate the potential impact circles to determine if they contain 20
buildings intended for human occupancy. Each separate dwelling unit in a
multiple dwelling unit building is counted as a separate building intended for
human occupancy.
(i) If 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 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 ]).
(3) The operator is to evaluate the potential
impact circles to determine if they contain identified sites, as defined in
§192.903, in accordance with paragraph (c) of this section.
(4) The operator is to complete
identification of high consequence areas by December 17, 2004.
(c) Operators are to
identify sites meeting the criteria of identified sites, as defined in
§192.903. The process for identification is in §192.905. Further
guidance was provided in (
68 FR 42456; July 17, 2003) titled
issuance
of advisory bulletin. Operators must document, and retain for review
during inspections, their rationale for selecting the source(s) used, including
why it/they are appropriate for use.
(d) Requirements for incorporating
newly-identified high consequence areas into an integrity management program
are in §192.905.
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)Assessments
|
(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
|
20
|
Pressure Test or ILI or DA
|
|
|
|
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 R
|
equirements
|
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
inspection 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 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 HCAs
or class 3 and 4 locations. Any indications of unreported construction activity
would require a follow up investigation to determine if mechanical damage
occurred.
|
PART 199
-DRUG AND ALCOHOL TESTING
SUBPART
A
-General
199.1
Scope and Compliance.
(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, Research
and Special Programs 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, Research and Special Programs Administration, Department of
Transportation, Washington, DC 20590.
(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 Paragraph 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 Paragraph 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
M
I S report to RSPA of its
anti-drug testing using the Management
I nformation System
(M
I 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 MIS reports to prepare and submit such reports to RSPA.
(b) Each report, required under this section,
shall be submitted to the Office of Pipeline Safety Compliance (OPS), Research
and Special Programs Administration, Department of Transportation, room 2103,
400 Seventh Street, SW., Washington, DC 20590. The operator may submit a paper
report or data electronically using the version of the MIS form provided by
DOT. This electronic version of the form can be accessed via the Internet at
the following Office of Pipeline Safety web address:
http://ops.dot.gov/drug.htm.
(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. If 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
[Removed and
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.
19903, 199.205 .
2[Removed and 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
[Removed and 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 paragraph 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 paragraph 199.225(a), a reasonable
suspicion alcohol test required under paragraph 199.225(b), or a follow-up
alcohol test required under paragraph 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
con-tributing 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 RSPA 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
paragraphs 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 Paragraph
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 paragraph
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
paragraph 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 paragraph 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
RSPA 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 RSPA.
(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 Compliance (OPS), Research
and Special Programs Administration, Department of Transportation, room 2103,
400 Seventh Street, SW., Washington, DC 20590. The operator may report data
electronically using the version of the MIS form provided by DOT. This form can
be accessed via the Internet at the following Office of Pipeline Safety web
address: http://ops.dot.gov/drug.htm.
(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
paragraph 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 paragraphs 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 paragraphs 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 paragraphs 199.215 through 199.223 to perform covered
functions unless the employee has met the requirements of paragraph
199.243.
199.237
Other Alcohol-related Conduct.
(a) No
operator shall permit a covered employee tested under the provisions of
paragraph 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 paragraph 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 paragraph 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 paragraph 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 paragraphs 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 paragraphs 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 paragraphs 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.