63774 Federal Register / Vol. 75, No. 200 / Monday, October 18, 2010 / Proposed Rules 

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). 

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: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• Fax: 1–202–493–2251. 

• 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 selfaddressed 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: 

• 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. 

• 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. 

• 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: 

• 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). 

• Pressure testing of new pipelines 

(Subpart E of 49 CFR Part 195). 

• 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). 

• Protecting steel pipelines from the 

adverse effects of internal and external 

corrosion (Subpart H of 49 CFR Part 

195). 

• 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: 

• Scope of the pipeline safety 

regulations and existing regulatory 

exceptions, 

• The criteria for designation as a 

High Consequence Area (HCA), 

• Leak detection and Emergency Flow 

Restricting Devices (EFRD), 


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1The 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. 

• Valve spacing, 

• Repair criteria in non-HCA areas, 

and, 

• 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 lowstress pipelines. 

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; nontransportation 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: 

Æ The exception in section 195.1(b)(2) 

of the Pipeline Safety Regulations for 

the transportation of hazardous liquid 

through a pipeline by gravity? 

Æ Any exception in sections 

195.1(a)(4)(ii) or 195.11(a) for the 

gathering of hazardous liquids by 

pipeline in rural areas? 

Æ 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? 

Æ The exception in sections 

195.1(b)(5) for the transportation of 

hazardous liquid in offshore pipelines 

in State waters? 

Æ The exceptions in sections 

195.1(b)(6) and (7) for the transportation 

of hazardous liquid in a produceroperated pipeline on the OCS? 

Æ 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? 

Æ 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: 

Æ Underground hazardous liquid 

storage facilities? 

Æ 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: 

• The potential costs of repealing or 

modifying the existing regulatory 

exceptions listed above. 

• The potential quantifiable safety 

and societal benefits of repealing or 

modifying the exceptions listed above. 

• The potential impacts on small 

businesses of repealing or modifying the 

existing regulatory exceptions listed 

above. 

• 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 § 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 


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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: 

• The potential costs of modifying the 

existing regulatory requirements. 

• The potential quantifiable safety 

and societal benefits of modifying the 

existing regulatory requirements. 

• The potential impacts on small 

businesses of modifying the existing 

regulatory requirements. 

• 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, shutin (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, 

§§ 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 preexisting 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: 

• The potential costs of modifying the 

existing regulatory requirements. 

• The potential quantifiable safety 

and societal benefits of modifying the 

existing regulatory requirements. 

• The potential impacts on small 

businesses of modifying the existing 

regulatory requirements. 

• The potential environmental 

impacts of modifying the existing 

regulatory requirements. 

D. Valve Spacing 

Under § 195.258, valves must be 

installed in a location that is accessible 

to authorized employees. Under 

§ 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, § 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 


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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 § 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 § 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 § 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: 

• The potential costs of modifying the 

existing regulatory requirements. 

• The potential quantifiable safety 

and societal benefits of modifying the 

existing regulatory requirements. 

• The potential impacts on small 

businesses of modifying the existing 

regulatory requirements. 

• 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 

§ 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 nonHCA 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? 


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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: 

• The potential costs of modifying the 

existing regulatory requirements. 

• The potential quantifiable safety 

and societal benefits of modifying the 

existing regulatory requirements. 

• The potential impacts on small 

businesses of modifying the existing 

regulatory requirements. 

• 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: 

• 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. 

• 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. 

• 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. 

• 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. 

• 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, 

§ 195.553, Appendix C to Part 195, and 

§ 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 SCCrelated 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, 


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63780 Federal Register / Vol. 75, No. 200 / Monday, October 18, 2010 / Proposed Rules 

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: 

• The potential costs of modifying the 

existing regulatory requirements. 

• The potential quantifiable safety 

and societal benefits of modifying the 

existing regulatory requirements. 

• The potential impacts on small 

businesses of modifying the existing 

regulatory requirements. 

• 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 

DEPARTMENT OF COMMERCE 

National Oceanic and Atmospheric 

Administration 

50 CFR Part 622 

[Docket No. 100803319–0475–01] 

RIN 0648–BA04 

Fisheries of the Caribbean, Gulf of 

Mexico, and South Atlantic; Reef Fish 

Fishery of the Gulf of Mexico; Red 

Grouper Management Measures 

AGENCY: National Marine Fisheries 

Service (NMFS), National Oceanic and 


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