[Federal Register Volume 75, Number 200 (Monday, October 18, 2010)]
[Proposed Rules]
[Pages 63774-63780]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-26006]



[[Page 63774]]

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 195

[Docket No. PHMSA-2010-0229]
RIN 2137-AE66


Pipeline Safety: Safety of On-Shore Hazardous Liquid Pipelines

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), 
Department of Transportation (DOT).

ACTION: Advance notice of proposed rulemaking (ANPRM).

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SUMMARY: PHMSA is considering whether changes are needed to the 
regulations covering hazardous liquid onshore pipelines. In particular, 
PHMSA is seeking comment on whether it should extend regulation to 
certain pipelines currently exempt from regulation; whether other areas 
along a pipeline should either be identified for extra protection or be 
included as additional high consequence areas (HCAs) for Integrity 
management (IM) protection; whether to establish and/or adopt standards 
and procedures for minimum leak detection requirements for all 
pipelines; whether to require the installation of emergency flow 
restricting devices (EFRDs) in certain areas; whether revised valve 
spacing requirements are needed on new construction or existing 
pipelines; whether repair timeframes should be specified for pipeline 
segments in areas outside the HCAs that are assessed as part of the IM; 
and whether to establish and/or adopt standards and procedures for 
improving the methods of preventing, detecting, assessing and 
remediating stress corrosion cracking (SCC) in hazardous liquid 
pipeline systems. Comments should address the public safety and 
environmental aspects of new requirements, as well as the cost 
implications and regulatory burden.

DATES: Persons interested in submitting written comments on this ANPRM 
must do so by January 18, 2011. PHMSA will consider late filed comments 
so far as practicable.

ADDRESSES: You may submit comments identified by the docket number 
PHMSA-2010-0229 by any of the following methods:
    <bullet> Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
    <bullet> Fax: 1-202-493-2251.
    <bullet> Mail: Hand Delivery: U.S. DOT Docket Management System, 
West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue, SE., 
Washington, DC 20590-0001 between 9 a.m. and 5 p.m., Monday through 
Friday, except Federal holidays.
    Instructions: If you submit your comments by mail, submit two 
copies. To receive confirmation that PHMSA received your comments, 
include a self-addressed stamped postcard.

    Note:  Comments are posted without changes or edits to http://www.regulations.gov, including any personal information provided. 
There is a privacy statement published on http://www.regulations.gov.


FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202-366-
4571, by fax at 202-366-4566, or by mail at U.S. DOT, PHMSA, 1200 New 
Jersey Avenue, SE., PHP-10, Washington, DC 20590-0001.

SUPPLEMENTARY INFORMATION:

I. Background

    Congress has authorized Federal regulation of the transportation of 
hazardous liquid by pipeline under the Commerce Clause of the U.S. 
Constitution. That authorization is codified in the Pipeline Safety 
Laws (49 U.S.C. 60101 et seq.), a series of statutes that are 
administered by the DOT, PHMSA. PHMSA has used that authority to 
promulgate comprehensive minimum safety standards for the 
transportation of hazardous liquid by pipeline.
    Congress established the current framework for regulating hazardous 
liquid pipelines in the Hazardous Liquid Pipeline Safety Act of 1979, 
Public Law 96-129 (HLPSA). That law, modeled on the Natural Gas 
Pipeline Safety Act of 1968, Public Law 90-481, delegated to DOT the 
authority to develop, prescribe, and enforce minimum Federal safety 
standards for the transportation of hazardous liquids by pipeline. 
Congress has since enacted additional legislation that is currently 
codified in the Pipeline Safety Laws, including:
    <bullet> In 1992, Congress added the environment to the list of 
statutory factors that must be considered in establishing safety 
standards for hazardous liquid pipelines, mandated that regulations be 
issued to establish criteria for operators to use in identifying and 
inspecting pipelines located in areas that are unusually sensitive to 
environmental damage, that cross a navigable waterway, or that have a 
high population density, and required regulations be issued to define 
the term ``gathering line'' and establish safety standards for certain 
``regulated gathering lines,'' Public Law 102-502.
    <bullet> In 1996, Congress limited the operator identification 
requirement mandate to pipelines that cross a waterway where a 
substantial likelihood of commercial navigation exists, required that 
certain areas where a pipeline rupture would likely cause permanent or 
long-term environmental damage be considered in determining whether an 
area is unusually sensitive to environmental damage, and mandated that 
regulations be issued for the qualification and testing of certain 
pipeline personnel, Public Law 104-304.
    <bullet> In 2006, Congress mandated that regulations be issued for 
low-stress hazardous liquid pipelines and pipeline control room 
management, Public Law 109-468.
    PHMSA administers compliance with these statutes and has 
promulgated comprehensive safety standards and regulations for the 
transportation of hazardous liquid by pipeline. That includes 
regulations for the:
    <bullet> Design and construction of new pipeline systems or those 
that have been relocated, replaced, or otherwise changed (Subparts C 
and D of 49 CFR Part 195).
    <bullet> Pressure testing of new pipelines (Subpart E of 49 CFR 
Part 195).
    <bullet> Operation and maintenance of pipeline systems, including 
for inspecting and reburying pipelines in the Gulf of Mexico and its 
inlets, establishing programs for public awareness and damage 
prevention, managing the integrity of pipelines in HCAs, and managing 
the operation of pipeline control rooms (Subpart F of 49 CFR Part 195).
    <bullet> Protecting steel pipelines from the adverse effects of 
internal and external corrosion (Subpart H of 49 CFR Part 195).
    <bullet> Integrity management (IM) in High Consequence Areas (HCAs, 
49 CFR 195.452).
    As a result of PHMSA's review of the performance of the hazardous 
liquid IM program, PHMSA is considering new regulation in several 
areas.

II. Advance Notice of Proposed Rulemaking

    Within this ANPRM, PHMSA is seeking public comment on six specific 
topic areas:
    <bullet> Scope of the pipeline safety regulations and existing 
regulatory exceptions,
    <bullet> The criteria for designation as a High Consequence Area 
(HCA),
    <bullet> Leak detection and Emergency Flow Restricting Devices 
(EFRD),

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    <bullet> Valve spacing,
    <bullet> Repair criteria in non-HCA areas, and,
    <bullet> Stress Corrosion Cracking (SCC).
    Each topic is discussed in more detail in this document.

A. Scope of the Pipeline Safety Regulations and Existing Regulatory 
Exceptions

    The Pipeline Safety Regulations apply to most onshore \1\ pipeline 
facilities used for the transportation of hazardous liquids, as defined 
in 49 CFR 195.2, to include petroleum, petroleum products, or anhydrous 
ammonia. The Pipeline Safety Regulations apply to any pipeline that 
transports a highly volatile liquid, the transportation of hazardous 
liquid through a pipeline other than a gathering line that has a 
maximum operating pressure (MOP) of greater than 20% of specified 
minimum yield strength (SMYS), any hazardous liquid pipeline that 
crosses a waterway used for commercial navigation, the transportation 
of hazardous liquid through regulated onshore gathering lines, and the 
transportation of hazardous liquid through certain low-stress 
pipelines.
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    \1\ The Pipeline Safety Statutes provide PHMSA with jurisdiction 
over all offshore hazardous liquid pipelines. However, PHMSA does 
not exercise the full measure of that authority for reasons of 
policy. PHMSA allows States to regulate certain offshore hazardous 
liquid pipelines in their own waters under 49 CFR 195.1(b)(5). PHMSA 
also allows the Department of the Interior to regulate certain 
hazardous liquid pipelines on the OCS under 49 CFR 195.1(b)(7), a 
provision that codifies a 1996 Memorandum of Understanding between 
PHMSA and DOI.
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    The Pipeline Safety Regulations do not apply to all onshore 
hazardous liquid pipeline facilities. Exceptions are provided where 
required by statute, including for onshore production, refining, or 
manufacturing facilities; storage or in-plant piping systems associated 
with onshore production, refining, or manufacturing facilities; the 
transportation of hazardous liquid through low-pressure rural gathering 
lines that are less than 6-inches in diameter and not located in an 
area that is unusually sensitive to environmental damage; and the 
movement of hazardous liquid by non-pipeline modes of transportation. 
Regulations associated with these statutory exemptions are not under 
consideration in this ANPRM.
    Regulatory exceptions also exist in the current Pipeline Safety 
Regulations. These exceptions include facilities that were determined 
to not pose a significant risk to public safety at the time the rule 
was promulgated, for example: Pipelines used to transport hazardous 
liquids by gravity, pipelines used to gather hazardous liquids in 
certain rural areas, and pipelines used to move carbon dioxide beyond 
certain points in production, injection, or recovery operations.
    Regulatory exceptions also include facilities that are reserved for 
regulation by the States or other Federal agencies, such as offshore 
pipelines in State waters; producer-operated on the outer continental 
shelf (OCS); breakout tanks that receive and store hazardous liquid, 
but not for reinjection and continued transportation by pipeline; non-
transportation related onshore and offshore oil facilities; and 
underground storage facilities.
    PHMSA is seeking public comment on whether the regulatory 
exceptions noted above should be repealed or modified. In particular:
    A.1 Should PHMSA repeal or modify:
    [cir] The exception in section 195.1(b)(2) of the Pipeline Safety 
Regulations for the transportation of hazardous liquid through a 
pipeline by gravity?
    [cir] Any exception in sections 195.1(a)(4)(ii) or 195.11(a) for 
the gathering of hazardous liquids by pipeline in rural areas?
    [cir] The exception in section 195.1(b)(10) for the transportation 
of carbon dioxide by pipeline downstream of certain points in injection 
or recovery operations?
    [cir] The exception in sections 195.1(b)(5) for the transportation 
of hazardous liquid in offshore pipelines in State waters?
    [cir] The exceptions in sections 195.1(b)(6) and (7) for the 
transportation of hazardous liquid in a producer-operated pipeline on 
the OCS?
    [cir] The exception in section 195.2 for breakout tanks that are 
not used to relieve surges in a hazardous liquid pipeline system or to 
receive and store hazardous transported by pipeline for reinjection and 
continued transportation by pipeline?
    [cir] Any other exception or limitation in the Pipeline Safety 
Regulations that applies to the transportation of hazardous liquid by 
pipeline?
    A.2 Should PHMSA promulgate new or additional safety standards for:
    [cir] Underground hazardous liquid storage facilities?
    [cir] Any other pipeline facility used in the transportation of 
hazardous liquid by pipeline?
    A.3 Should PHMSA take these actions in any particular order to best 
protect the public, property, or the environment?
    If commenters suggest modification, PHMSA requests specific 
proposals for what elements of the exception should be modified. With 
regards to questions A.1-A.2, PHMSA requests commenters to provide 
information and supporting data related to:
    <bullet> The potential costs of repealing or modifying the existing 
regulatory exceptions listed above.
    <bullet> The potential quantifiable safety and societal benefits of 
repealing or modifying the exceptions listed above.
    <bullet> The potential impacts on small businesses of repealing or 
modifying the existing regulatory exceptions listed above.
    <bullet> The potential environmental impacts of repealing or 
modifying the existing regulatory exceptions listed above.

B. Definition of High Consequence Area

    A High Consequence Area (HCA) is currently defined in Sec.  195.450 
as a commercially navigable waterway, a high population area, or an 
other populated area. Some of these HCAs include areas with high 
population density, sole source drinking water supplies, and ecological 
resources that are unusually sensitive to environmental damage. PHMSA 
currently regulates approximately 173,000 miles of hazardous liquid 
pipelines. Approximately 76,000, or 44%, of these miles are in areas 
that could affect an HCA. The IM requirements specify how pipeline 
operators must identify, prioritize, assess, evaluate, repair and 
validate--through comprehensive analyses--the integrity of hazardous 
liquid pipelines that, in the event of a leak or failure, could affect 
HCAs within the United States.
    Although operators may voluntarily apply IM practices to pipe line 
segments that are deemed to not affect an HCA, the regulations do not 
require operators to do so.
    PHMSA is now considering what additional safety measures should be 
taken to increase the level of safety for those pipelines that could 
not affect HCA areas. PHMSA is considering whether the Integrity 
Management (IM) requirements in Part 195 should be the model for adding 
additional safety measures for pipelines that could not affect HCAs. 
PHMSA is also considering expanding the definition of an HCA so that 
more miles of pipe are subject to those requirements.
Questions
    B.1 Should PHMSA amend the existing criteria for identifying high 
consequence areas, to expand the miles of pipeline included in an HCA? 
If so, what amendments to the criteria should PHMSA consider? Is there 
information

[[Page 63776]]

or data that supports an amendment to the existing criteria? What are 
the potential costs and benefits associated with an amendment to the 
existing criteria? How would amendments to the current criteria impact 
State and Local governments and other entities?
    B.2 Does existing criteria capture any HCAs that, based on risk, do 
not provide a substantial benefit for inclusion as an HCA? Should PHMSA 
amend the existing criteria in any way which could better focus the 
identification of an HCA based on risk? Would it be more beneficial to 
include more miles of pipeline under existing HCA IM procedures, or, to 
focus more intense safety measures on the highest risk, highest 
consequence areas?
    B.3 Should the phrase ``commercially navigable waterways'', as used 
in the definition of an HCA, be revised to ``navigable waters'' or 
``waters of the United States'' consistent with the Clean Water Act? 
Are there any potential cost impacts or quantifiable benefits of such a 
change?
    B.4 What processes do pipeline operators undertake to determine 
whether areas surrounding pipeline right of ways (ROWs) meet the HCA 
criteria as set forth in 195.450? Are all areas that qualify as HCAs 
based on proximity to ROWs properly identified? Are there ways that 
PHMSA can improve the process of ROW HCA criteria determinations?
    B.5 What, if any, input and/or oversight should the general public 
and/or local communities play in the identification of HCAs? If 
commenters believe that the public or local communities should provide 
input and/or oversight, how should PHMSA gather information and 
interface with these entities? Should State and Local governments be 
involved in the HCA identification and oversight process?
    B.6 Should PHMSA develop additional safety measures, including 
those similar to IM, for areas outside of HCAs?
    B.7 Should major road crossings and/or railway crossings be 
included as HCAs?
    B.8 If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
    <bullet> The potential costs of modifying the existing regulatory 
requirements.
    <bullet> The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
    <bullet> The potential impacts on small businesses of modifying the 
existing regulatory requirements.
    <bullet> The potential environmental impacts of modifying the 
existing regulatory requirements.

C. Leak Detection Equipment and Emergency Flow Restricting Devices

    Better, more effective leak detection systems and technologies and 
Emergency Flow Restriction Devices (EFRDs) are a key means to reducing 
the consequences of hazardous liquid spills. EFRDs are ``check valves'' 
or remotely controlled valves (RCVs) that can be activated 
automatically or remotely from a control room, to isolate sections of a 
pipeline. The sooner these tools can detect a spill and isolate 
pipeline segments, the lower the impact of a pipeline accident. Leak 
detection can alert a pipeline operator to the presence and, with some 
methods, the location of a leak. An effective leak detection system can 
limit the consequences of a hazardous liquid spill by alerting the 
operator to the leak in a timely manner and allowing for faster 
response efforts. Leak detection systems may be incorporated into an 
operator's Supervisory Control and Data Acquisition (SCADA) system for 
controlling the pipeline. EFRDs can limit the volume of hazardous 
liquid released after the location of the release has been identified. 
EFRDs are a critical means of reducing the consequences of a pipeline 
accident.
    PHMSA is seeking to increase and improve the use of leak detection 
and EFRDs on hazardous liquids pipelines. To this end, PHMSA is 
considering whether to establish and/or adopt standards and procedures, 
through a rulemaking proceeding, for minimum leak detection 
requirements for all pipelines. PHMSA is also considering whether to 
require the installation of EFRDs in certain areas and/or provide 
additional guidance to operators on installing EFRDs in the optimum 
locations.
    PHMSA has performed or sponsored numerous workshops and studies on 
leak detection and EFRDs over the years. As a result of continued study 
of leak detection issues, and the recommendations of the advisory 
committee, the public and industry, PHMSA implemented specific leak 
detection requirements in its IM rule for hazardous liquid pipelines 
(65 FR 75378; December 1, 2000). Some methods of leak detection 
include--Dynamic flow modeling, tracer chemical, release detection 
cable, shut-in (static) release detection, and pressure point analysis 
release detection software (See 65 FR 75378, 75398-99 for detailed 
descriptions of these systems).
    The regulation, 49 CFR 195.452(i)(3), requires an operator to have 
a means to detect leaks on the sections of its pipeline system that 
could affect HCAs. An operator must also evaluate and modify its leak 
detection system to protect HCAs. An operator's evaluation must, at 
least, consider the following factors--length and size of the pipeline, 
type of product carried, the pipeline's proximity to the HCA, the 
swiftness of leak detection, location of nearest response personnel, 
leak history and risk assessment results. The IM regulations, Appendix 
C to Part 195, also specify that the location of pipeline segments as 
it relates to the ability of the operator to detect and respond to a 
leak is a risk factor to be considered when establishing the frequency 
of assessment.
    Under Section 21 of the Pipeline Inspection, Protection, Safety and 
Enforcement Act of 2006 (Pub. L. 109-468), Congress directed PHMSA to 
prepare a report on leak detection systems utilized by operators of 
hazardous liquid pipelines. Specifically, Congress asked for a 
discussion of the inadequacies of current leak detection systems, 
including their ability to detect ruptures, small leaks that are 
ongoing or intermittent, and what can be done to foster development of 
better technologies as well as address existing technological 
inadequacies. PHMSA completed the Leak Detection Technology Study on 
December 31, 2007. The study can be found at: http://www.phmsa.dot.gov/pipeline/ library. In short, the study found that no single solution 
exists to effectively detect all hazardous liquid pipeline leaks and 
few exist that reliably detect small leaks.
    On January 26, 2010, PHMSA issued an advisory bulletin, ADB-10-01 
(75 FR 4134), reminding operators of the importance of prompt and 
effective leak detection capability in protecting public safety and the 
environment. The bulletin advised operators of all hazardous liquid 
pipelines, not just those subject to the IM rule, to perform an 
engineering analysis to determine if a computer-based leak detection 
system is necessary to improve leak detection performance and line 
balance processes. In response to this bulletin and PHMSA's imposition 
of leak detection requirements in the IM rule, the National 
Transportation Safety Board (NTSB) closed an open safety recommendation 
on the installation of computer-based leak detection systems.
    In the Pipeline Safety Act of 1992 (Pub. L. 102-508), Congress 
directed the

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Office of Pipeline Safety (OPS) to survey and assess the effectiveness 
of EFRDs and other procedures, systems, and equipment used to detect 
and locate hazardous liquid pipeline ruptures, and to prescribe 
regulations on the circumstances where an operator of a hazardous 
liquid pipeline facility must use an EFRD or such other procedure, 
system, or equipment. In response to the mandate, an NTSB 
recommendation, and following a 1991 OPS report titled ``Emergency Flow 
Restricting Devices Study,'' the agency issued an ANPRM soliciting 
public input on EFRDs. (59 FR 2802; January 19, 1994). The ANPRM also 
sought comments on leak detection.
    OPS studied the issue for some time and explained in detail the 
research it had performed in the NPRM for hazardous liquid IM. (See 65 
FR 21695, 21700; April 24, 2000). In the final rule, OPS concluded that 
the decision to install EFRDs should not be mandatory but should be 
left to the operator, who must consider specific factors when making 
the determination. The rule, 49 CFR 195.452(i)(4), requires an operator 
to determine whether to install an EFRD based on the operator's risk 
analysis. In making this determination, an operator must, at least, 
consider the following factors: The swiftness of leak detection and 
pipeline shutdown capabilities, the type of commodity carried, the rate 
of potential leakage, the volume that can be released, topography or 
pipeline profile, the potential for ignition, proximity to power 
sources, location of nearest response personnel, specific terrain 
between the pipeline segment and the high consequence area, and 
benefits expected by reducing the spill size. The rule, Appendix C to 
part 195, also requires an operator to maintain certain records on the 
criteria for determining EFRD installation.
    There is currently no regulatory requirement to install EFRDs on 
pipelines not subject to the IM rule. Although the pipeline safety 
regulations, 49 CFR 195.260, require the installation of valves at 
locations that will minimize damage or pollution from accidental 
hazardous liquid discharges. Outside of HCA's, current regulations, 
Sec. Sec.  195.134 and 195.444 require operators who choose to install 
computational pipeline monitoring (CPM) leak detection systems to 
comply with the American Petroleum Institute (API) standard API 1130 
``Computational Pipeline Monitoring for Liquids: Pipeline Segment'' in 
designing, operating, maintaining, testing, recordkeeping, and 
dispatcher training on the system.
Questions
    C.1 Should leak detection requirements be expanded to all hazardous 
liquid pipeline systems under PHMSA's regulatory jurisdiction? Is there 
a specific subset of hazardous liquid pipeline not currently subject to 
leak detection requirements that should be? What are the potential 
quantifiable costs and benefits of expanding existing hazardous liquid 
pipeline leak detection requirements?
    C.2 What additional industry practices or standards are available 
for leak detection that PHMSA should consider for widespread adoption? 
Is there new or existing leak detection technology that PHMSA should be 
aware of and should consider for widespread adoption?
    C.3 How do existing industry practices or standards for leak 
detection address the following factors: Leak size and flow rate 
sensitivity, response time, leak location accuracy, rates of false 
alarms and misses, instrument accuracy, personnel training and 
qualification requirements, system size and complexity (including batch 
line factors), leak size or leak flow rate versus response time, 
release volume estimation accuracy, detection of pre-existing leaks, 
detection of a leak in a shut-in pipeline, detection of a leak in 
pipelines under a slack line condition and/or during transient 
conditions, sensitivity to flow conditions, sensitivity to multiphase 
flow, retrofit feasibility, system testing and maintenance 
requirements?
    C.4 Should current state regulations inform PHMSA's consideration 
of performance based leak detection standards? For example, the 
regulations of The Alaska Department of Environmental Conservation, (18 
Alaska Administrative Code 75.055), set out minimum detection 
sensitivity based on a percentage of daily pipeline throughput. What 
specific performance measures should PHMSA consider?
    C.5 If PHMSA adopts new leak detection requirements, should there 
be different performance standards for sensitive areas? For example, 
should PHMSA require operators to install more sensitive leak detection 
equipment, such as externally-based systems, in those areas?
    C.6 If new leak detection standards were developed, what key issues 
should they address?
    C.7 Are there statistics available on the extent to which the 
application of existing practices or standards has contributed to 
reduced spill volumes and consequences?
    C.8 What industry practices or standards are available for the 
location and performance requirements of EFRDs?
    C.9 Do such practices or standards, if any, set maximum spill 
volume requirements, EFRD activation timing, or methods for integration 
of EFRD operation with an operator's SCADA and leak detection systems?
    C.10 Should PHMSA specify the criteria where an operator must 
install an EFRD?
    C.11 Should PHMSA mandate the use of EFRDs in all locations?
    C.12 What leak detection methods or technologies require further 
research and development in order to demonstrate their efficacy?
    C.13 If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
    <bullet> The potential costs of modifying the existing regulatory 
requirements.
    <bullet> The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
    <bullet> The potential impacts on small businesses of modifying the 
existing regulatory requirements.
    <bullet> The potential environmental impacts of modifying the 
existing regulatory requirements.

D. Valve Spacing

    Under Sec.  195.258, valves must be installed in a location that is 
accessible to authorized employees. Under Sec.  195.260, a valve must 
be installed on each mainline at locations along the pipeline system 
that will minimize damage or pollution from accidental hazardous liquid 
discharge, as appropriate for the terrain in open country, for offshore 
areas, or for population areas. In addition, valves must be installed 
on each side of a water crossing more than 100 feet wide from high-
water mark to high-water mark and valves must be installed on each side 
of a reservoir holding water for human consumption. For areas covered 
by IM requirements, Sec.  195.452(i)(4) states that an operator must 
evaluate and, if appropriate, take additional measures to prevent and 
mitigate the consequences of pipeline failures that could affect an 
HCA. One of the actions that an operator may take to protect an HCA is 
to install EFRDs. EFRDs are check valves or remote control valves that 
are operated from a location remote from where the valve is located.
    In addition, the standard for the installation of valves at water 
crossings (100 foot wide bodies of water) may not adequately protect 
certain bodies of

[[Page 63778]]

water that are less than 100 feet wide. The current standard, which 
allows operators to make a subjective decision on the location of 
valves, may be too subjective. PHMSA is therefore reviewing the 
regulations to determine if the regulations should be revised to: (1) 
Cover more bodies of water under the provisions of Sec.  195.260(e); 
(2) require the installation of valves at specified locations 
throughout each pipeline system; and (3) mandate the use of EFRDs, in 
particular remote controlled valves, in all systems, not just in HCAs. 
PHMSA believes that these actions are necessary to properly mitigate 
the release of hazardous liquids after a failure of the pipeline system 
has occurred.
Questions
    D.1 What is the average distance between valves that are currently 
installed according to the requirements in Sec.  195.260(c)? Are these 
manually operated valves or are these valves controlled remotely?
    D.2 Should PHMSA adopt standards by which operators evaluate valve 
spacing and valve locations?
    D.3 Should PHMSA specify the maximum distance between valves? If 
so, is there an ideal spacing to reduce risks and potential 
consequences? What projected costs and benefits would result from this 
specification?
    D.4 Should PHMSA prescribe additional requirements for locating 
valves near HCAs beyond those currently prescribed for EFRDs?
    D.5 Should PHMSA revise the standard in Sec.  195.260(e) to include 
narrower bodies of water? If so, what projected costs and benefits 
would result from this change?
    D.6 Should PHMSA consider a requirement for all valves to be 
capable of being controlled remotely? If so, what projected costs and 
benefits would result from this requirement?
    D.7 Should PHMSA require installation of EFRDs to protect HCAs? If 
so, what projected costs and benefits would result from this 
requirement?
    D.8 If PHMSA proposes to revise the requirements relative to valve 
location, should the change be applicable to all pipelines or should 
PHMSA only apply this change to new construction? Could they also apply 
any time a segment of pipe is repaired or replaced? If such a 
requirement were to be adopted, under what circumstances should PHMSA 
consider waiving this requirement? How would limitations to the 
applicability of this requirement (such as, limitation to new 
construction) impact the projected costs and benefits resulting from 
the requirement?
    D.9 What are the cost impacts relative to changes in the 
requirements of valve location based on the type of valves installed?
    D.10 If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
    <bullet> The potential costs of modifying the existing regulatory 
requirements.
    <bullet> The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
    <bullet> The potential impacts on small businesses of modifying the 
existing regulatory requirements.
    <bullet> The potential environmental impacts of modifying the 
existing regulatory requirements.

E. Repair Criteria

    Operators have reported that up to 86 percent of all the pipelines 
subject to the pipeline safety regulations have been inspected with an 
in-line inspection tool (i.e., a ``smart pig''). Since the adoption of 
the IM requirements into Part 195, approximately 32,000 repairs have 
made to those pipelines that could affect an HCA, and over 67,000 
repairs have been made in pipelines deemed to not affect an HCA. The IM 
regulations (49 CFR 195.452(h)) require ``prompt action'' to address 
all anomalous conditions discovered. More specifically, the IM 
regulations mandate ``immediate'' pressure reduction, pipeline 
shutdown, or repair of the following conditions: 80 percent or greater 
wall loss; a predicted burst pressure less than the established maximum 
allowable operating pressure (MAOP) at the location of the anomaly; a 
dent located at the top of the pipeline (between the four and eight 
o'clock positions) with any indication of metal loss, cracking, or a 
stress riser or with a depth greater than six percent of the pipeline's 
diameter; or any anomaly that in the judgment of the person designated 
by the operator to evaluate assessment results requires immediate 
action. Furthermore, operators must remediate dents at the top of the 
pipeline with a depth greater than three percent of the pipeline 
diameter and dents on the bottom of the pipeline that have any 
indication of metal loss, cracking, or a stress riser.
    Finally, the integrity management regulations in 49 CFR 195.452 
require remediation within 180 days for various conditions, including: 
A dent with a depth greater than two percent of a pipeline's diameter 
that affects pipe curvature at a weld, a dent at the top of the 
pipeline with a depth greater than two percent of the pipeline's 
diameter, a dent at the bottom of the pipeline with a depth greater 
than six percent of the pipeline's diameter, a calculated operating 
pressure less than the current established MOP at the location of the 
anomaly, 50 percent or greater wall loss, a determined crack, corrosion 
along the longitudinal weld, or a gouge or groove deeper than 12.5 
percent of the nominal wall.
    The assessments operators have been conducting on their pipeline 
segments that could affect HCAs have often extended to areas beyond the 
HCAs. Up to now, PHMSA has enforced the IM repair criteria as only 
applying to the anomalous conditions discovered in the HCAs. If through 
the integrity assessment or information analysis, the operator 
discovers anomalous conditions in the areas outside the HCA, PHMSA has 
allowed operators to use the prompt remediation requirements in Sec.  
195.422 rather than the IM repair time frames. PHMSA is now considering 
if the IM repair time frames should also be enforced to apply to the 
pipeline segments located in non-HCA areas when anomalous conditions in 
these areas are discovered through the integrity assessment or 
information analysis. This would provide greater assurance that defects 
on non-HCA related areas are repaired in a timely manner. PHMSA would 
like input from the public on the following:
    E.1 Should anomalous conditions in non-HCA areas qualify as repair 
conditions subject to the IM repair schedules? If so, which ones? What 
projected costs and benefits would result from this requirement?
    E.2 Should PHMSA consider a risk tiering--where the conditions in 
the HCA areas would be addressed first, followed by the conditions in 
the non-HCA areas? How should PHMSA evaluate and measure risk in this 
context, and what risk factors should be considered?
    E.3 What should be the repair schedules for anomalous conditions 
discovered in non-HCA areas through the integrity assessment or 
information analysis? Would a shortened repair schedule significantly 
reduce risk? How should PHMSA determine guidelines for repair schedules 
in non-HCA areas?
    E.4 Have ILI tool capability advances resulted in a need to update 
the ``dent with metal loss'' repair criteria?
    E.5 Should PHMSA adopt explicit standards to account for the known 
accuracy of in-line inspection tools when comparing in-line inspection 
tool data with the repair criteria?

[[Page 63779]]

    E.6 Should PHMSA adopt standards for conducting in-line inspections 
using ``smart pigs,'' the qualification of persons interpreting in-line 
inspection data, the review of ILI results including the integration of 
other data sources in interpreting ILI results, and/or the quality and 
accuracy of in-line inspection tool performance, in order to gain a 
greater level of assurance that injurious pipeline defects are 
discovered?
    E.7 If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
    <bullet> The potential costs of modifying the existing regulatory 
requirements.
    <bullet> The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
    <bullet> The potential impacts on small businesses of modifying the 
existing regulatory requirements.
    <bullet> The potential environmental impacts of modifying the 
existing regulatory requirements.

F. Stress Corrosion Cracking

    Stress Corrosion Cracking (SCC) is the cracking induced from the 
combined influence of tensile stress and a corrosive medium. SCC has 
caused numerous pipeline failures on hazardous liquids pipelines, 
including a 2003 failure on a Kinder Morgan pipeline in Arizona,a 2004 
failure on an Explorer Pipeline Company pipeline in Oklahoma, a 2005 
failure on an Enterprise Products Operating line in Missouri, and a 
2008 failure on an Oneok NGL Pipeline in Iowa. Better, more effective 
methods of preventing, detecting, assessing and remediating SCC in 
pipelines are important to making further reductions in pipeline 
failures.
    PHMSA is seeking to improve understanding and mitigation of SCC 
threats on hazardous liquids pipelines. To this end, PHMSA is 
considering whether to establish and/or adopt standards and procedures, 
through a rulemaking proceeding, for improving the methods of 
preventing, detecting, assessing and remediating SCC in hazardous 
liquid pipeline systems.
    PHMSA has taken numerous steps over many years to improve the 
understanding and mitigation of SCC hazardous liquids pipelines. These 
have included public workshops and studies on SCC. Initiatives taken, 
sponsored and/or supported by PHMSA designed to enhance understanding 
of SCC include:
    <bullet> 1999 and 2004 SCC Studies-- Two comprehensive studies on 
SCC were conducted for PHMSA's predecessor agency, the Research and 
Special Programs Administration (RSPA). First, ``Stress Corrosion 
Cracking Study,'' Report No. DTRS56, prepared by General Physics 
Corporation in May 1999. Second, ``Stress Corrosion Cracking Study,'' 
Report No. DTRS56-02-D-70036, submitted by Michael Baker Jr., Inc., in 
September 2004. These studies sought to improve understanding of SCC 
and to identify practical methods to prevent, detect and address SCC as 
well as provide a framework for potential future research. The 2004 
study is available at: http://primis.phmsa.dot.gov/meetings/DocHome.mtg?doc=1.
    <bullet> Liquid IM Rules--The IM rule (65 FR 75378; December 1, 
2000) for hazardous liquid pipelines in high consequence areas included 
guidance on the types of internal inspection tools operators should use 
for the integrity assessments required as part of their IM plans. 
Appendix C to Part 195, ``Guidance for Implementation of an IM 
Program,'' provides that crack detection tools should be used for 
detecting cracks and crack-like features, including SCC, where such 
features are a risk factor on the pipeline segment.
    <bullet> 2003 Advisory Bulletin-- In response to three SCC-driven 
failures of hazardous liquid pipelines in the US in 2003 and other SCC 
incidents around the world, PHMSA issued an advisory bulletin, ``Stress 
Corrosion Cracking Threats to Gas and Hazardous Liquid Pipelines'' (68 
FR 58166; October 8, 2003), urging all pipeline owners and operators to 
consider SCC as a possible safety risk on their pipeline systems and to 
include SCC assessment and remediation in their IM plans, for those 
systems subject to IM rules. For systems not subject to the IM rules, 
the bulletin urged owners and operators to assess the impact of SCC on 
pipeline integrity and to plan integrity verification activities 
accordingly.
    <bullet> 2003 Public Workshop-- PHMSA sponsored a public workshop 
on SCC on December 3, 2003, in Houston, TX. Numerous PHMSA 
representatives, state officials, industry, consultants and officials 
from the National Energy Board of Canada attended and shared their 
respective experiences with SCC. The workshop also served as a forum 
for identifying issues for consideration in the 2004 Baker SCC study.
    <bullet> 2005 Rulemaking--PHMSA issued rules that covered direct 
assessment, a process of managing the effects of external corrosion, 
internal corrosion or SCC on pipelines made primarily of steel or iron. 
``Standards for Direct Assessment of Gas and Hazardous Liquid 
Pipelines'' (70 FR 61571; October 25, 2005). In the portion of the 
proposed rulemaking applicable to direct assessment of SCC on hazardous 
liquid pipeline facilities, PHMSA considered cross-referencing certain 
existing Part 192 gas regulations, and the associated American Society 
of Mechanical Engineers (ASME) B31.8S standard. B31.8S includes 
specific standards for SCC. PHMSA later determined that such a cross-
reference would be problematic for a variety of reasons, including the 
fact that B31.8S was developed for and limited to onshore gas pipeline 
systems. At that time, the Technical Hazardous Liquid Pipeline Safety 
Standards Committee (THLPSSC) recommended that PHMSA consider adopting 
a standard that NACE International was developing for direct assessment 
of SCC. PHMSA elected to consider the recently published NACE Standard 
``RP0204-2004, Stress Corrosion Cracking Direct Assessment 
Methodology'' for possible future rulemaking action.
Questions
    Existing Standards:
    F.1 Current Federal pipeline safety regulations for hazardous 
liquids, Sec.  195.553, Appendix C to Part 195, and Sec.  195.588, 
address direct assessment of SCC but do not set forth standards for 
performing direct assessment, other types of assessments, or how to 
prevent or remediate SCC. Does the NACE SP0204-2008 (formerly RP0204) 
Standard ``Stress Corrosion Cracking Direct Assessment Methodology'' 
address the full lifecycle concerns associated with SCC? Should PHMSA 
consider this, or any other standards to govern the SCC assessment 
procedures? Do these standards vary significantly from existing 
practices associated with SCC assessments?
    F.2 Are there statistics available on the extent to which the 
application of the NACE Standard, or other standards, have affected the 
number of SCC indications operators have detected on their pipelines 
and the number of SCC-related pipeline failures?
    F.3 Are there practices or standards that address prevention, 
detection, assessment, and remediation of SCC on hazardous liquid 
pipeline systems?
    F.4 If new standards were to be developed for SCC, what key issues 
should they address?
    Existing Industry Practices:
    PHMSA is interested in the extent to which operators have 
implemented Canadian Energy Pipeline Association (CEPA) Stress 
Corrosion Cracking,

[[Page 63780]]

Recommended Practices 2nd Edition, 2007, and what the results have 
been.
    F.5 Are there statistics available on the extent to which hazardous 
liquid pipeline operators apply the CEPA practices?
    F.6 Are there statistics available that compare the number of SCC 
indications detected and SCC-related failures, between operators 
applying the CEPA practices and those applying other SCC standards or 
practices?
    F.7 Do the CEPA practices address the full lifecycle concerns 
associated with SCC?
    F.8 Are there additional industry practices that address SCC?
    The Effectiveness of SCC Detection Tools and Methods:
    F.9 Are there statistics available on the extent to which various 
tools and methods can accurately detect and determine the severity of 
SCC?
    F.10 Are tools or methods available to accurately detect and 
determine the severity of SCC when it is associated with longitudinal 
pipe seams?
    F.11 Should PHMSA require that operators perform a critical 
analysis of all factors that influence SCC to determine if SCC is a 
credible threat for each pipeline segment? What experience-based 
indications have proven reliable in determining whether SCC could be 
present?
    F.12 Should PHMSA require an integrity assessment using methods 
capable of detecting SCC whenever a credible threat of SCC is 
identified?
    F.13 Should PHMSA require a periodic analysis of the effectiveness 
of operator corrosion management programs, which integrate information 
about cathodic protection, coating anomalies, in-line inspection data, 
corrosion coupon data, corrosion inhibitor usage, analysis of corrosion 
products, environmental and soil data, and any other pertinent 
information related to corrosion management?
    F.14 What further action should be taken to address corrosion 
issues?
    F.15 If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
    <bullet> The potential costs of modifying the existing regulatory 
requirements.
    <bullet> The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
    <bullet> The potential impacts on small businesses of modifying the 
existing regulatory requirements.
    <bullet> The potential environmental impacts of modifying the 
existing regulatory requirements.

III. Regulatory Notices

A. Executive Order 12866 and DOT Regulatory Policies and Procedures

    E.O. 12866 requires agencies to regulate in the ``most cost-
effective manner,'' to make a ``reasoned determination that the 
benefits of the intended regulation justify its costs,'' and to develop 
regulations that ``impose the least burden on society.'' We therefore 
request comments, including specific data if possible, concerning the 
costs and benefits of revising the pipeline safety regulations to 
accommodate any of the changes suggested in this advance notice.

B. Executive Order 13132: Federalism

    Executive Order 13132 requires agencies to assure meaningful and 
timely input by state and local officials in the development of 
regulatory policies that may have a substantial, direct effect on the 
states, on the relationship between the national government and the 
states, or on the distribution of power and responsibilities among the 
various levels of government. PHMSA is inviting comments on the effect 
a possible rulemaking adopting any of the amendments discussed in this 
document may have on the relationship between national government and 
the states.

C. Regulatory Flexibility Act

    Under the Regulatory Flexibility Act of 1980 (5 U.S.C. 601 et 
seq.), we must consider whether a proposed rule would have a 
significant economic impact on a substantial number of small entities. 
``Small entities'' include small businesses, not-for-profit 
organizations that are independently owned and operated and are not 
dominant in their fields, and governmental jurisdictions with 
populations under 50,000. If your business or organization is a small 
entity and if adoption of any of the amendments discussed in this ANPRM 
could have a significant economic impact on your operations, please 
submit a comment to explain how and to what extent your business or 
organization could be affected.

D. National Environmental Policy Act

    The National Environmental Policy Act of 1969 (NEPA) requires 
Federal agencies to consider the consequences of Federal actions and 
that they prepare a detailed statement analyzing if the action 
significantly affects the quality of the human environment. Interested 
parties are invited to address the potential environmental impacts of 
this ANPRM. We are particularly interested in comments about compliance 
measures that would provide greater benefit to the human environment or 
on alternative actions the agency could take that would provide 
beneficial impacts.

E. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175 requires agencies to assure meaningful and 
timely input from Indian tribal government representatives in the 
development of rules that ``significantly or uniquely affect'' Indian 
communities and that impose ``substantial and direct compliance costs'' 
on such communities. We invite Indian tribal governments to provide 
comments on any aspect of this ANPRM that may affect Indian 
communities.

F. Paperwork Reduction Act

    Under 5 CFR Part 1320, PHMSA analyzes any paperwork burdens if any 
information collection will be required by a rulemaking. We invite 
comment on the need for any collection of information and paperwork 
burdens, if any.

G. Privacy Act Statement

    Anyone can search the electronic form of comments received in 
response to any of our dockets by the name of the individual submitting 
the comment (or signing the comment, if submitted on behalf of an 
association, business, labor union, etc.). DOT's complete Privacy Act 
Statement was published in the Federal Register on April 11, 2000 (65 
FR 19477).

    Authority: 49 U.S.C. 60101 et seq.; 49 CFR 1.53.

    Issued in Washington, DC, on October 8, 2010.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 2010-26006 Filed 10-15-10; 8:45 am]
BILLING CODE 4910-60-P