76968 Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules

1For the period 1986 through 1999, corrosion

caused 25 percent of all incidents reported under

Part 195; 3 percent of all deaths; 2 percent of all

injuries; and 19 percent of all property damage.

the general financial disclosures

necessary to establish that the small

business is in fact small. The estimated

time for filling out an FCC Form 175 is

45 minutes. Each applicant will have to

submit information regarding the

ownership of the applicant, any joint

venture arrangements or bidding

consortia that the applicant has entered

into, and, if claiming eligibility for

bidding credits, financial information

demonstrating that the applicant

qualifies as a small business. Applicants

that do not have audited financial

statements available will be permitted to

certify the validity of their financial

showings. While many small businesses

have chosen to employ attorneys prior

to filing an application to participate in

an auction, the rules are intended to

enable a small business to file an

application on its own using the short

form application preparation guidelines

that are made available by the

Commission before any auction. When

an applicant wins a license, it will be

required to submit an FCC Form 601

license application, which will require

technical information regarding the

applicant’s proposals for providing

service and other information. This

application will require information

provided by an engineer who will have

knowledge of the system’s design. The

estimated time for completing an FCC

Form 601 is one hour and fifteen

minutes.

E. Significant Alternatives Minimizing

the Economic Impact on Small Entities

16. The RFA requires an agency to

describe any significant alternatives that

it has considered in reaching its

proposed approach, which may include

the following four alternatives: (1) The

establishment of differing compliance or

reporting requirements or timetables

that take into account the resources

available to small entities; (2) the

clarification, consolidation, or

simplification of compliance or

reporting requirements under the rule

for small entities; (3) the use of

performance, rather than design,

standards; and (4) an exemption from

coverage of the rule, or any part thereof,

for small entities.

17. In the 3rd FNPRM, the

Commission proposes that the part 1

unjust enrichment provisions will

govern partitioning and disaggregation

arrangements involving AMTS licenses

owned by small businesses that were

afforded a bidding credit and later elect

to partition or disaggregate their licenses

to an entity that does not qualify as a

small business. The alternative to

applying the unjust enrichment

provisions would be to allow an entity

who had benefited from the special

bidding provisions for small businesses

to become unjustly enriched by

partitioning or disaggregating its

licenses to parties that do not qualify for

such benefits.

18. The 3rd FNPRM solicits comment

on a variety of alternatives set forth

herein. Any significant alternative

presented in the comments will be

considered.

F. Federal Rules that May Duplicate,

Overlap, or Conflict With the Proposed

Rules

None.

List of Subjects 47 CFR Parts 13 and 80

Communications equipment, Radio.

Federal Communications Commission.

Magalie Roman Salas,

Secretary.

[FR Doc. 00–31309 Filed 12–7–00; 8:45 am]

BILLING CODE 6712–01–U

DEPARTMENT OF TRANSPORTATION

Research and Special Programs

Administration

49 CFR Part 195

[Docket No. RSPA–97–2762; Notice 3]

RIN 2137–AD24

Controlling Corrosion on Hazardous

Liquid and Carbon Dioxide Pipelines

AGENCY: Research and Special Programs

Administration (RSPA), DOT.

ACTION: Notice of proposed rulemaking.

SUMMARY: We are proposing to change

some of the corrosion control standards

for hazardous liquid and carbon dioxide

pipelines. The proposed changes are

based on our review of the adequacy of

the present standards compared to

similar standards for gas pipelines and

acceptable safety practices. The

proposed changes are intended to

improve the clarity and effectiveness of

the present standards and reduce the

potential for pipeline accidents due to

corrosion.

DATES: Persons interested in submitting

written comments on the proposed rules

must do so by February 6, 2001. Late

filed comments will be considered so far

as practicable.

ADDRESSES: You may submit written

comments by mailing or delivering an

original and two copies to the Dockets

Facility, U.S. Department of

Transportation, Room PL–401, 400

Seventh Street, SW., Washington, DC

20590–0001. The Dockets Facility is

open from 10:00 a.m. to 5:00 p.m.,

Monday through Friday, except on

Federal holidays when the facility is

closed. Or you may submit written

comments to the docket electronically at

the following web address: http://

dms.dot.gov. See the SUPPLEMENTARY

INFORMATION section for additional filing

information.

FOR FURTHER INFORMATION CONTACT: L.

M. Furrow by phone at 202–366–4559,

by fax at 202–366–4566, by mail at U.S.

Department of Transportation, 400

Seventh Street, SW., Washington, DC

20590, or by e-mail at

buck.furrow@rspa.dot.gov.

SUPPLEMENTARY INFORMATION:

Filing Information, Electronic Access,

and General Program Information

All written comments should identify

the docket and notice numbers stated in

the heading of this notice. Anyone who

wants confirmation of mailed comments

must include a self-addressed stamped

postcard. To file written comments

electronically, after logging onto http://

dms.dot.gov, click on ‘‘Electronic

Submission.’’ You can read comments

and other material in the docket at this

Web address: http://dms.dot.gov.

General information about our pipeline

safety program is available at this

address: http://ops.dot.gov.

Background

We have reviewed the corrosion

control standards in 49 CFR part 195 for

hazardous liquid and carbon dioxide

pipelines to see if any standards need to

be made clearer, more effective, or

consistent with acceptable safety

practices. Although the likelihood of

corrosion-caused accidents harming

people or the environment is relatively

low, we undertook the review because

corrosion is the second leading cause of

reported accidents on hazardous liquid

pipelines, and improving the standards

has the potential to reduce the number

of future accidents.1

The review began September 8, 1997,

when we held a public meeting on how

the part 195 corrosion control standards

and the corrosion control standards for

gas pipelines in 49 CFR part 192 might

be improved (62 FR 44436; Aug. 21,

1997). To attract participation by

corrosion experts, we held the public

meeting in Oakbrook, Illinois, in

conjunction with meetings of NACE

International, a professional technical

society dedicated to corrosion control.

Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules 76969

The Oakbrook meeting focused on

whether we should incorporate by

reference NACE Standard RP0169–96,

‘‘Control of External Corrosion on

Underground or Submerged Metallic

Piping Systems,’’ as a substitute for all

or some of the part 192 and part 195

standards. Two other significant topics

were whether part 192 and part 195

corrosion control standards need to be

updated to ensure safety, and whether

gas, hazardous liquid, and carbon

dioxide pipelines should be subject to

the same corrosion control standards.

For technical and other reasons,

including the document’s nonmandatory style, most meeting

participants and subsequent

commenters opposed incorporating the

entire NACE Standard RP0169–96 by

reference. But participants agreed

universally that part 192 and part 195

corrosion control standards are largely

sufficient, and although some changes

may be needed, the standards should be

generally the same.

Toward this end, we began to

consider whether the more

comprehensive part 192 standards,

possibly with some changes, would be

appropriate for hazardous liquid and

carbon dioxide pipelines. For technical

input, we met from time to time with

representatives of NACE, the pipeline

industry, and state pipeline safety

agencies. At these meetings, we also

examined whether the part 192

standards need to be more effective or

clearer. As guidance for this assessment,

the meeting participants developed the

following principles:

• Evaluate existing data and use the

evaluation to assess the need to change

standards.

• Continue to improve public safety

and environmental protection.

• Assess the need for corrosion

control standards throughout the

national pipeline system based on the

risk associated with different parts of

the system.

• Upgrade regulations to allow for

future changes in pipeline industry

technology and operating practices as

appropriate.

• Strive for uniform interpretation/

enforcement.

• To the extent practicable, involve

all interested parties in assessing the

need to change standards.

• Use the new cost/benefit policy

framework being developed for RSPA’s

pipeline safety advisory committees in

determining the costs and benefits of

potential changes to standards.

• Achieve balance between

performance and prescriptive language.

• Develop performance measures to

assess the effectiveness of corrosion

control programs.

• Focus on managing corrosion to

maintain pipeline integrity.

• Provide adequate regulatory

flexibility to allow operators to

implement alternative measures that

meet the performance requirements of

the corrosion regulations.

The meetings left us with various

concerns about the total effectiveness

and clarity of the part 192 corrosion

control standards and the suitability of

applying those standards to hazardous

liquid and carbon dioxide pipelines. We

also knew that the National Association

of Pipeline Safety Representatives

(NAPSR), the Gas Piping Technology

Committee (GPTC), and the National

Transportation Safety Board (NTSB) had

at various times recommended changes

to part 192 and part 195 corrosion

control standards. So, to get public

comment on our concerns and the

recommended changes, we held another

public meeting on April 28, 1999, in

San Antonio, Texas (64 FR 16885; April

7, 1999). We also invited comments on

the idea of allowing operators to follow

their own corrosion management plans

or NACE Standard RP0169–96 as an

alternative to all or part of the part 192

or part 195 corrosion control standards.

San Antonio Meeting

At least 180 persons attended the San

Antonio public meeting. However, only

a few persons made oral statements,

which are summarized as follows:

The Interstate Natural Gas Association

of America (INGAA) said that based on

the record of low numbers of deaths and

injuries, not much change in the part

192 standards is needed, even if

corrosion is the second leading cause of

reported pipeline incidents. INGAA

attributed the good safety record to

proper management of risk, saying it

would be nonproductive if changes to

generally applicable safety standards

caused operators to shift their limited

resources away from higher risk areas.

INGAA emphasized the use of cost/

benefit assessment in determining the

need for new or revised standards. At

least two other meeting participants

(Enron and Columbia Gulf) expressed

support for INGAA’s views.

The American Gas Association (AGA)

and American Public Gas Association

(APGA) jointly made a statement similar

to INGAA’s and pointed out that DOT

safety statistics do not justify changes in

the present standards. AGA/APGA

further noted that corrosion is not the

second leading cause of incidents on gas

distribution lines, but the last cause,

resulting in about 4 percent of all

reported incidents. The views of AGA/

APGA were supported by at least one

other meeting participant (Columbia

Gulf) and by a majority of the persons

who submitted written comments to the

docket after the meeting. These

subsequent written comments are

condensed below under the ‘‘Comments

after San Antonio’’ subheading.

Another participant, Global Cathodic

Protection, submitted a statement,

backed by 72 corrosion control

practitioners, that cathodic protection

criteria in appendix D of part 192 are

preferred to the criteria in NACE

Standard RP0169–96.

Equilon Enterprises, an operator of

petroleum pipelines, did not support

the alternative of corrosion management

plans, because of the burden of review

by government and the possibility that

government reviewers and operator

personnel may not be equally qualified

to evaluate the plans. In addition,

Equilon said that removing unnecessary

differences between part 192 and part

195 standards would minimize

confusion and disagreements between

operators and government inspectors.

On other points raised in the meeting

notice, Equilon preferred that part 195

not refer to NACE Standard RP0169–96.

But, Equilon did support the need for

qualification requirements for bosses

who lead corrosion control programs,

and it thought the part 192 standards

should disallow the use of bare

unprotected pipe.

An engineering consultant said the

‘‘instant-off’’ approach to measuring

cathodic protection was excessive.

Similarly, the Equilon representative

said that across-the-board use of the

negative 850 mV criterion with instantoff readings is not productive, and that

the 100 mV criterion is more costeffective in many cases. A university

professor said that corrosion control

technicians do not do instant-off tests

the same way. But another engineering

consultant noted that NACE has a

companion standard that covers instantoff tests: TM0497–97, Measurement

Techniques Related to Criteria for

Cathodic Protection on Underground or

Submerged Metallic Piping Systems.

Comments Submitted After the San

Antonio Meeting

Following the San Antonio public

meeting, the docket remained open to

receive written comments on the

matters addressed in the meeting notice.

Sixty-two persons filed written

comments. These commenters included

pipeline safety agencies in Arizona and

Iowa, two corrosion control firms

(Corrosion Control International and

Global Cathodic Protection), two

76970 Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules

2After the San Antonio meeting, RSPA adopted

final rules on personnel qualification that closely

paralleled the proposed rule (64 FR 46853; Aug. 27,

1999).

operators of petroleum pipelines (Mobil

Corporation and Tosco Refining

Company), seven pipeline trade

associations (American Gas Association

(AGA), American Public Gas

Association (APGA), Interstate Natural

Gas Association of America, New

England Gas Association, New York Gas

Group, Ohio Gas Association, and

American Petroleum Institute), six

operators of interstate gas pipelines

(CMS Energy, Columbia Energy Group,

Duke Energy, Enron Gas Pipeline Group,

KN Energy, and Phillips Pipe Line

Company), and 43 local gas distribution

companies.

General Comments. Most of the

written comments specifically address

RSPA concerns and other topics in the

San Antonio meeting notice. Still, there

were some general comments: Two gas

distribution operators said that

requiring operators to cathodically

protect cast iron or ductile iron pipe

would have a big impact on the

distribution industry. These operators

also suggested that small fittings made

of copper or brass and steel fittings with

a corrosion resistant coating should be

exempt from cathodic protection

requirements. Other rule changes they

suggested were intended to yield

savings by specifying that electronic or

remote data collection can be used to

meet the monitoring requirements and

by extending the interval for monitoring

rectifiers from every 2 months to twice

a year, particularly for newly

manufactured devices.

AGA/APGA welcomed minor rule

changes that address clarity,

consistency, technology, but said that

sweeping changes are not justified by

the safety data. They advised us to use

cost/benefit assessment and nonregulatory approaches to perceived

problems. Of the 62 commenters, 42

expressed support for the joint

comments of AGA/APGA. Others, such

as Mobil Corporation, Enron, and the

New England Gas Association, similarly

expressed doubt that substantial

changes to the standards were

warranted in view of the incident

record. One commenter, Kansas Gas

Service, backed up its claim that the

present standards are adequate by

referring to its own record: no reported

incidents for the period 1989–98. Tosco

Refining stated that making the

corrosion control maintenance

requirements in Parts 192 and 195 alike

would mitigate compliance difficulties

for companies that operate both gas and

petroleum pipelines.

Comments on RSPA Concerns: This

section of the preamble includes

summaries of comments that

specifically address RSPA’s concerns

about whether certain provisions of Part

192 corrosion control standards need to

be improved. The AGA/APGA

comments are identified because many

commenters supported the AGA/APGA

views. Summaries of comments on

changes recommended by NAPSR,

GPTC, and NTSB, on alternatives, and

on topics included in the ‘‘Public

Participation’’ section of the meeting

notice are discussed afterward.

Section 192.453 Personnel

Qualification

RSPA Concern: In view of the

proposed rules on qualification of

pipeline personnel (63 FR 57269; Oct.

27, 1998) 2, are more specific

qualification standards needed for

individuals who direct or carry out

corrosion control procedures?

Comments: All 23 comments on this

concern opposed changing § 192.453.

They said either the existing rule is

adequate or the proposed rules on

personnel qualification are sufficient.

Most of these commenters also opposed

establishing specific technical

qualifications for company managers.

They said these personnel need more

business than technical knowledge to

assure that corrosion and other

maintenance problems are handled

economically. AGA/APGA suggested

that any remaining qualification issues

be addressed in a non-regulatory way

through ongoing discussions with

industry training representatives at

DOT’s Transportation Safety Institute.

Section 192.455 External Corrosion:

New Pipelines

RSPA Concern: Should a cathodic

protection system be installed on

offshore pipelines in less than one year

after the pipeline is constructed, for

example, 60 days, because of the strong

corrosiveness of salt water?

Comments: The two comments on this

concern favored a 60-day installation

period.

RSPA Concern: Is it in the interest of

safety to exempt pipelines in particular

environments and temporary pipelines

from the coating and cathodic

protection requirements?

Comments: Three commenters

opposed the present exemptions, either

because corrosion leaks can happen

rapidly or because the installations are

so varied they should be handled by

waivers rather than general exemption.

At the same time, three commenters

supported the exemptions, contending

that corrosion is usually a long term

problem, many environments are not

conducive to corrosion, and required

monitoring would detect incipient

problems. AGA/APGA said that safety

data do not suggest the present

exemptions have been detrimental to

safety.

Section 192.457 External Corrosion:

Existing Pipelines

RSPA Concern: Should existing

compressor, regulator, and measuring

station piping continue to be excluded

from the requirement to cathodically

protect effectively coated transmission

line pipe?

Comments: Five commenters said the

piping should not be excluded, arguing

that it does not differ from pipe that

must be protected and that failures at

these locations may have serious

consequences. Three other commenters

said they cathodically protect all their

compressor, regulator, and measuring

station piping.

RSPA Concern: Is the present

requirement to cathodically protect

certain older existing pipelines only in

areas of ‘‘active corrosion’’ adequate for

public safety? If not, what would be a

cost-effective alternative standard?

Comments: Only one commenter

opposed the present rule. This

commenter contended that the entire

pipeline needs protection because spot

protection moves the corrosion problem

to other places on the line. However, 13

commenters, including AGA/APGA,

supported the present rule, saying that

it is a cost-effective approach to

protecting older lines, particularly since

not all corrosion is detrimental to safety.

Another commenter thought that adding

cathodic protection to old bare lines in

mildly corrosive or non-corrosive soils

could accelerate the rate of any

localized corrosion that might exist.

RSPA Concern: Is the meaning of

‘‘active corrosion’’ clear and technically

sound? If not, how should it be

changed?

Comments: None of the 12 comments

advocated changing the present

definition of ‘‘active corrosion.’’ Five

commenters, including AGA/APGA,

thought that possible changes would be

more prescriptive, less flexible, or not

appropriate for all areas.

Section 192.461 External Corrosion:

Coating

RSPA Concern: Should the implicit

requirement to coat field joints and

repairs be expressly stated?

Comments: Four commenters said this

requirement should be expressly stated.

But four other commenters worried that

singling out any item would raise

questions about items not listed.

Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules 76971

3For new aboveground pipelines, protection is

required everywhere the pipeline is exposed to the

Continued

Similarly, another commenter thought

the implicit requirement was adequate

for field joints.

RSPA Concern: Does coating need to

be compatible with the anticipated

service conditions, including the effects

of temperature?

Comments: Four commenters agreed

that such service compatibility is

necessary. And one of these commenters

suggested that a performance standard

would improve the effectiveness of the

existing rule in this regard. However,

another commenter said the existing

rule is adequate because service

compatibility is implied.

RSPA Concern: For offshore

pipelines, during installation, are

special measures necessary to protect

against damage to coating, including

field joint coating; and, to avoid

mechanical damage, are special coatings

needed on J-tubes, I-tubes and pipelines

installed by the bottom tow method?

Comments: There were no comments

on this concern.

Section 192.463 External Corrosion:

Cathodic Protection Criteria

RSPA Concern: Are the cathodic

protection system criteria in appendix D

of part 192, 300 mV shift and E-log-I,

obsolete, since they are not in section 6

of NACE Standard RP0169–96? If so,

should operators be allowed to continue

to use them on existing pipe, but not

new pipe?

Comments: Three commenters

favored dropping these two criteria or at

least E-log-I from appendix D. Six other

commenters said they would support

dropping the criteria only if the criteria

were known to be ineffective or no

longer in use. One commenter

acknowledged using E-log-I and two

others said the two criteria are adequate

and should be allowed. AGA/APGA and

one other commenter said the NACE

standard recognizes the use of other

successful criteria, such as those in

appendix D, and that safety data do not

show that the 300 mV shift and E-logI criteria result in higher leak rates or

incidents.

Section 192.465 External Corrosion:

Monitoring

RSPA Concern: Does the sampling

basis prescribed for inspecting short

sections of mains or transmission lines

not in excess of 100 feet and separately

protected service lines provide effective

corrosion control, particularly as it

applies to service lines that supply gas

to public buildings?

Comments: Two commenters thought

the present rule is ineffective, asserting

that a single inspection is not enough to

assess safety over a 10-year period, no

matter if public buildings are involved.

However, four commenters argued that

because corrosion is slow, there has

been no problem in sampling pipe to

detect corrosion before it becomes

critical. And two commenters said

sampling is a cost-effective way to

monitor scattered sites. AGA/APGA and

two other commenters said that safety

data do not show that sampled pipe has

more corrosion-caused leaks than other

pipe. Several commenters foresaw

difficulties in defining a ‘‘public

building.’’ Only one commenter thought

that more frequent monitoring is needed

for lines leading to public buildings

because of the increased potential for

serious consequences.

Section 192.467 External Corrosion:

Electrical Isolation

RSPA Concern: What remedial action

is needed when an electrical short in a

casing results in inadequate cathodic

protection of the pipeline outside the

casing?

Comments: Five commenters said

these shorts should be cleared because

other options are ineffective and

imposing more current to offset the

short could have adverse effects. But

two other commenters said that clearing

shorts can be costly if the line must be

taken out of service or replaced, and

that there is no consensus on adequate

remediation. Another observation by

one commenter was that the electrical

isolation requirements are not needed

since cathodic protection has to meet

the criteria for adequacy.

RSPA Concern: Should newly

constructed offshore pipelines be

electrically isolated from bare steel

platforms unless both are protected as a

single unit?

Comments: The lone commenter who

addressed this concern said that

isolation is needed, yet concluded that

a rule change was not needed because

annual surveys will identify any

problem.

RSPA Concern: Is electrical isolation

needed where contact with aboveground

structures would adversely affect

cathodic protection?

Comments: One commenter said we

should require isolation in all such

cases. Three commenters argued that

while isolation is needed a rule change

is not, because annual surveys will

identify any problem. Three other

commenters argued that isolation is not

needed if the alternative of sufficient

local protection is applied.

Section 192.471 External Corrosion:

Test Leads

RSPA Concern: Are accessible test

leads needed on offshore risers that are

electrically isolated and not accessible

for testing?

Comments: The two commenters who

addressed this concern said the present

rule is adequate because operators must

demonstrate adequate cathodic

protection, which necessitates test

leads.

RSPA Concern: For aluminum

pipelines, should all test leads be

insulated aluminum conductors and

installed to avoid harm to the pipe?

Comments: There were two comments

on this concern. One said test leads and

connection material must be compatible

with aluminum. The other said test

leads must be insulated aluminum

conductors and installed to avoid harm

to the pipe.

Section 192.473 External Corrosion:

Interference Currents

RSPA Concern: Where light rail

systems exist, should operators

specifically be required to identify and

test for stray currents and keep records

of the test results?

Comments: Four commenters said

such a specific requirement was needed

for light rail. But three commenters

disagreed, arguing the present rule is

adequate because it requires operators to

test for all sources of stray current,

including large junk yard magnets and

electric cranes.

Section 192.475 Internal Corrosion

RSPA Concern: Are special

requirements needed to deal with the

problem of internal corrosion in storage

field piping, as evidenced by piping

leaks in West Virginia and several

Midwestern states?

Comments: Three commenters felt the

present rule is adequate for all

situations and specific requirements for

storage fields are not needed. In

contrast, one commenter thought the

rule should specifically recognize the

problems posed by such piping and

require more coupons or traps where

liquid might collect, pipe design that

avoids liquid collection, use of lined

pipe, periodic pigging, or dehydration.

Another commenter thought operators

should have to prepare a procedure and

follow it to minimize internal corrosion.

Section 192.479 Atmospheric

Corrosion: General

RSPA Concern: Should new and

existing pipelines be subject to the same

protection requirements?

Comments: One commenter saw no

need to change the distinction between

new and existing pipelines.3 Six others

76972 Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules

atmosphere, unless the operator can demonstrate

that a corrosive atmosphere does not exist. For old

pipelines, protection is required only where

harmful corrosion is found.

4NAPSR’s recommendations were published in

Notice 2 of Docket No. PS–124 (58 FR 59431; Nov.

9, 1993).

supported treating all aboveground

pipelines alike regardless of age, but two

of these commenters said the rule

should apply only to ‘‘active corrosion,’’

not to all corrosion.

RSPA Concern: Is protection needed

where corrosion is a light surface oxide

or where corrosion will not likely affect

the safe operation of the pipeline before

the next scheduled inspection?

Comments: Six commenters thought

the rule should be changed to exclude

surface oxide because it does not affect

pipe integrity. However, one commenter

thought surface oxide indicates a

coating problem that operators should

identify and track through continuing

surveillance. One other commenter said

that even if corrosion is more than

superficial, if there is no question of

safety before the next inspection, then

there is no present need for remedial

action. Another commenter

recommended limiting the rule to

‘‘active corrosion’’ to exclude both

superficial corrosion and corrosion that

would not likely advance to an

unacceptable stage before the next

inspection.

RSPA Concern: Is special protection

needed in the splash zone of offshore

pipelines and at soil to air interfaces of

onshore pipelines?

Comments: Three of the four

comments on this concern thought the

existing corrosion rules for buried and

aboveground protection are adequate.

The fourth commenter said any need for

special protection would be recognized

during required inspections.

Section 192.481 Atmospheric

Corrosion: Monitoring

RSPA Concern: Should the inspection

interval for onshore pipelines be

extended beyond 3 years in view of the

generally low incidence of serious

problems on protected pipelines?

Comments: Two commenters said the

present 3-year monitoring cycle is not

too burdensome. In contrast, seven

commenters recommended extending

the inspection period beyond 3 years,

saying that atmospheric corrosion is a

long-term process. Six of these

commenters recommended inspection

every 5 years, an interval coincident

with the interval of gas leakage surveys.

One other commenter suggested the rule

let operators determine what inspection

intervals are appropriate for the

pipelines involved.

RSPA Concern: For onshore pipelines,

are more frequent inspections needed at

soil-to-air interfaces, under thermal

insulation, at disbonded coatings, and at

pipe supports?

Comments: The consensus of the four

comments on this concern was that no

more frequent inspections than annual

are needed at these locations. Two

commenters said the corrosion problem

at these locations is too site-specific for

a general inspection rule requiring

removal of coating or jackets.

RSPA Concern: For offshore

pipelines, are more frequent inspections

needed under poorly bonded coatings

and at splash zones, support clamps,

and deck penetrations?

Comments: There were no comments

on this concern.

Section 192.491 Records

RSPA Concern: Should operators keep

records of findings of non-corrosive

conditions if

Section 192.455 Is Changed To

Remove the Benefit of Such Findings?

Comments: Two commenters agreed

that if records of non-corrosive

conditions no longer have a purpose,

the recordkeeping requirement should

be removed. But another commenter

thought records of exposed pipe

inspections under § 192.459 should be

kept even if no corrosion is found. This

commenter thought such records would

be useful in surveillance under

§ 192.613 and in evaluating the

significance of damaged pipe or coating.

RSPA Concern: Is the period for

keeping corrosion control monitoring

records, ‘‘as long as the pipeline

remains in service,’’ necessary for safety

or accident investigation? If not, what is

an appropriate period?

Comments: One commenter believed

the present retention period is needed to

provide a very helpful general history of

pipelines. But another commenter said

that old records are never used once

adverse conditions are corrected. Two

commenters suggested the retention

period could be reduced to 5 years or

two inspection cycles, whichever is

longer. A similar comment was 5 years

or the next inspection cycle, whichever

is longer.

Recommendations To Change

Standards

National Association of Pipeline Safety

Representatives

Recommendation: With regard to

§§ 192.457 and 192.465, NAPSR

recommended changes to clarify the

meaning of an ‘‘electrical survey’’ and

where alternatives to electrical surveys

may be used.

Comments: Three commenters

reported that the State-Industry

Regulatory Review Committee (SIRRC)

had reached a consensus on ‘‘electrical

survey’’ and alternatives. SIRRC was

formed by NAPSR and industry

representatives to work out differences

of opinion over NAPSR’s 1992

recommendations to revise part 192.4 In

a report transmitted to RSPA by a letter

dated May 3, 1999, SIRRC concludes

that electrical surveys are seldom used

on distribution systems, so there is no

advantage to requiring electrical surveys

as a preferred corrosion inspection

method on distribution systems. SIRRC

further concludes that if electrical

surveys are not used, all available

information should be used to

determine if active corrosion exists. Set

out below are SIRRC’s suggested

revisions of § 192.457(b)(3) and

§ 192.465(e). SIRRC also said that in the

suggested revision, ‘‘pipeline

environment’’ refers to whether soil

resistivity is high or low, wet or dry,

contains contaminants that may

promote corrosion, or has any other

known condition that might influence

the probability of active corrosion.

[192.457(b)(3)] Bare or coated distribution

lines. The operator shall determine the areas

of active corrosion by electrical survey or by

analysis and review of the pipeline

condition. Analysis and review shall include,

but is not limited to, leak repair history,

exposed pipe condition reports, and the

pipeline environment. For the purpose of this

section, an electrical survey is a series of

closely spaced pipe-to-soil readings over a

pipeline which are subsequently analyzed to

identify any locations where a corrosive

current is leaving the pipe.

[192.465(e)] (i) For transmission pipelines,

after the initial evaluation required by

paragraphs (b) and (c) of § 192.455 and

paragraph (b) of § 192.457, each operator

shall, not less than every 3 years at intervals

not exceeding 39 months, reevaluate its

unprotected pipelines and cathodically

protect them in accordance with this subpart

in areas in which active corrosion is found.

The operator shall determine the areas of

active corrosion by electrical survey, or

where an electrical survey is impractical, by

analysis and review of the pipeline

condition. Analysis and review shall include,

but is not limited to, leak repair history,

exposed pipe condition reports, and the

pipeline environment.

(ii) For distribution pipelines, after the

initial evaluation required by paragraphs (b)

and (c) of § 192.455 and paragraph (b) of

§ 192.457, each operator shall, not less than

every 3 years at intervals not exceeding 39

months, reevaluate its unprotected pipelines

and cathodically protect them in accordance

with this subpart in areas in which active

corrosion is found. The operator shall

determine the areas of active corrosion by

electrical survey or by analysis and review of

Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules 76973

the pipeline condition. Analysis and review

shall include, but is not limited to, leak

repair history, exposed pipe condition

reports, and the pipeline environment.

(iii) For the purpose of this section, an

electrical survey is a series of closely spaced

pipe-to-soil readings over a pipeline which

are subsequently analyzed to identify any

locations where a corrosive current is leaving

the pipe.

Recommendation: With regard to

§ 192.459, NAPSR recommended we

require operators to record the condition

of protective coatings whenever they

inspect exposed portions of buried

pipeline, arguing the records would

provide a useful history of the condition

of the pipelines as well as evidence that

exposed pipe had been inspected as

required.

Comments: Three commenters

reported that SIRRC reached a

consensus on recording the condition of

coating when inspecting exposed pipe.

SIRRC said that coating condition is

important in evaluating the overall

condition of a pipeline, and that this

information helps meet continuing

surveillance and active corrosion rules.

SIRRC’s suggested revision of § 192.459

follows:

Whenever an operator has knowledge that

any portion of a buried pipeline is exposed,

the exposed portion must be examined to

determine the condition of the coating, or if

the pipeline is bare or the coating is

deteriorated, the exterior condition of the

pipe. A record of the examination results

shall be made in accordance with

§ 192.491(c). If external corrosion is found,

remedial action must be taken to the extent

required by § 192.483 and the applicable

paragraphs of §§ 192.485, 192.487, or

192.489.

Recommendation: With regard to

§ 192.467(d), NAPSR recommended

changes that would require operators to

test pipeline casings annually for

electrical isolation, and to clarify what

must be done to minimize pipeline

corrosion if isolation is not achieved.

Comments: Three commenters

reported that SIRRC did not agree on

whether shorted casings are a problem

or on the need to test casings, but agreed

that § 192.483 should be amended to

include options for dealing with shorted

casings. SIRRC said its suggested

options are consistent with common

industry practice. SIRRC also

recognized that the options were not

intended as a substitute for proper

cathodic protection of pipe under

§ 192.463. SIRRC’s suggested revision of

§ 192.483 follows:

(d) If it is determined that a casing is

electrically shorted to a pipeline, the operator

shall: (1) clear the short, if practical; (2) fill

the casing with a corrosion inhibiting

material; (3) monitor for leakage with leak

detection equipment at least once each

calendar year at intervals not exceeding 15

months; or (4) conduct an initial inspection

with an internal inspection device capable of

detecting external corrosion in a cased

pipeline, and repeat at least every 5 years at

intervals not to exceed 63 months.

Recommendation: With regard to

§ 192.479(b), NAPSR recommended that

regardless of the date of installation, all

aboveground pipelines or portions of a

pipeline that are exposed to the

atmosphere be cleaned and either

coated or jacketed with a material

suitable for the prevention of

atmospheric corrosion, unless the

pipeline is in a non-corrosive

atmosphere.

Comments: Two commenters reported

that SIRRC reached a consensus that all

aboveground pipe should be subject to

the same protection requirement.

SIRRC’s suggested revision of § 192.479,

which would remove the present

distinction between pipelines installed

before and after particular dates, is set

forth below. SIRRC also explained that

the term ‘‘active corrosion’’ does not

include non-damaging corrosive films.

[192.479] (a) Each aboveground pipeline or

portion of a pipeline that is exposed to the

atmosphere must be cleaned and either

coated or jacketed with a material suitable for

the prevention of atmospheric corrosion. An

operator need not comply with this

paragraph, if the operator can demonstrate by

test, investigation, or experience in the area

of application that active corrosion does not

exist.

(b) If active corrosion is found on an

aboveground pipeline or portion of pipeline,

the operator shall (1) take prompt remedial

action consistent with the severity of the

corrosion to the extent required by the

applicable paragraphs of §§ 192.485, 192.487,

or 192.489; and (2) clean and either coat or

jacket the areas of atmospheric corrosion

with a material suitable for the prevention of

atmospheric corrosion.

Recommendation: With regard to the

provision in § 192.487(a) that permits

general corrosion in distribution line

pipe to be repaired instead of replaced,

NAPSR recommended that the

provision refer to generally accepted

guidelines for determining what

corroded areas may be repaired.

Comments: Two commenters reported

that SIRRC did not address this issue. In

addition, these commenters suggested

we allow operators to assess the

serviceability of distribution line pipe

that has wall thickness less than 30

percent of nominal wall thickness

instead of requiring the replacement of

such pipe.

Recommendation: With regard to

§ 192.489(b), NAPSR recommended that

we clarify that internal sealing is not an

appropriate method of strengthening

graphitized pipe.

Comments: Two commenters reported

that SIRRC agreed to drop this

recommendation, since advances in

technology may produce strength

enhancing liners.

Gas Piping Technology Committee

The following recommendations are

from an April 1995, rulemaking petition

by GPTC:

Recommendation: Remove from

§ 192.467 the requirement that pipe be

electrically isolated from metallic

casings. GPTC argued there are no safety

benefits from clearing shorted casings.

Comments: There were no comments

on this recommendation. But see the

comments above on § 192.467.

Recommendation: Amend §§ 192.465

and 192.481 to allow operators to take

up to 39 months to carry out inspections

of unprotected pipelines that must be

done at 3-year intervals. GPTC said the

extra time would add flexibility to the

standards, with no reduction in safety.

Comments: The one comment on this

recommendation supported the 39-

month period but preferred a 5-year

interval to match the interval of leakage

surveys. Also, see the comments above

on §§ 192.465 and 192.481.

National Transportation Safety Board

As a result of a 1996 accident on a

butane pipeline operated by Koch

Pipeline Company near Lively, Texas,

NTSB recommended two changes to the

Part 195 corrosion control standards:

Recommendation: Revise Part 195 to

require pipeline operators to determine

the condition of pipeline coating

whenever pipe is exposed and, if

degradation is found, to evaluate the

coating condition of the pipeline. (P–

98–35)

Comments: There were no comments

on this recommendation. But see the

SIRRC comment above on § 192.459.

Recommendation: Revise Part 195 to

include performance measures for the

adequate cathodic protection of liquid

pipelines. (P–98–36)

Comment: The only comment favored

adding to Part 195 either Appendix D or

NACE cathodic protection criteria.

Alternatives

In the San Antonio meeting notice, we

suggested two alternatives to the present

corrosion control standards: corrosion

management plans and NACE Standard

RP0169–96. Many operators get

excellent results by applying pipelinespecific plans that contain corrosion

control methods and management

techniques not required by Part 192 or

Part 195 standards. NACE Standard

76974 Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules

RP0169–96 is widely accepted as the

most authoritative source of up-to-date

pipeline corrosion control practices.

Comments: Two commenters favored

corrosion management plans, saying

they would be consistent with the riskbased approach to regulation and costeffective, since many operators already

use them. They also said that to qualify

a pipeline for exemption from the

standards, the plans should be designed

to produce equal or better results than

the standards. However, another

commenter opposed the plan

alternative, arguing that the review and

evaluation process would further dilute

government and industry resources and

detract from higher priority safety

matters. And the American Petroleum

Institute opposed the plan alternative,

saying that corrosion should be treated

as part of an overall integrity

management plan that may be

developed after the conclusion of

RSPA’s risk management demonstration

projects.

Topics 4 and 6 under the next

heading drew additional comments on

the alternatives.

Topics of Particular Interest

1. Whether any existing standards

deter or disallow the use of new

technologies, and, if so, how.

Comments: The two comments on this

topic were that while none of the

standards disallows the use of new

technology, unclear standards may deter

such use.

2. The costs and benefits of any

suggested changes to standards and

alternatives to standards.

Comments: The only comment was

that we should apply cost/benefit

analysis to any suggested changes.

3. The amount of time operators may

need to prepare for compliance with any

suggested standards or alternatives.

Comments: The only comment was

that the time needed for compliance

depends on the suggested rule change.

4. With regard to the corrosion

management plan and NACE Standard

alternatives—

a. The bases for evaluating the

adequacy of corrosion management

plans.

Comments: Two commenters said the

primary basis should be whether

corrosion is mitigated by the plan. AGA/

APGA and another commenter

suggested we defer further consideration

of the plan alternative until completion

of work by the State/Industry/DOT

Regulatory Alternative Feasibility Team,

which is considering risk-based

alternatives to safety standards.

b. The best way to facilitate agency

review of operator decisions under the

alternatives (e.g., prior notification,

reporting, recordkeeping).

Comments: Both comments on this

topic were that we should review the

decisions the same as we review

decisions in operators’ operating and

maintenance plans.

c. Whether NACE Standard RP0169–

96 is adequate for pipeline corrosion

control and, if so, should we incorporate

it by reference in our corrosion control

standards?

Comments: Only one commenter

thought NACE Standard RP0169–96

would be a cost-effective alternative to

existing corrosion control standards.

Although another commenter said it

would be all right to reference NACE

Standard RP0169–96, the commenter

also said it would be better to use it as

a basis for changing the standards. Ten

other commenters opposed using NACE

Standard RP0169–96. Of these, two said

the document is not adequate by itself,

and it would complicate the standards

if only parts were referenced. AGA/

APGA and two other commenters said

NACE Standard RP0169–96 is too

conservative and too costly to apply, but

AGA/APGA and another two

commenters thought it could serve as

guidance for corrosion management

plans. The reason given by one

commenter for opposing NACE

Standard RP0169–96 was that it does

not distinguish non-hazardous corrosion

from corrosion detrimental to public

safety.

5. For hazardous liquid pipelines—

a. Whether additional standards are

needed to further reduce the possibility

of damage to environmentally sensitive

areas.

Comments: One commenter thought

Part 195 should cross reference

Appendix D or NACE RP0169 criteria

for cathodic protection.

b. If Part 192 standards were applied

to hazardous liquid pipelines, the

changes, if any, that would be needed to

account for differences between gas and

liquid pipelines.

Comments: There were no comments

on this topic.

6. For gas distribution systems—

a. Root causes of corrosion leaks on

coated, uncoated, protected, and

unprotected metallic lines.

Comments: AGA/APGA and one other

commenter said that corrosion leaks on

distribution lines have a low probability

of resulting in reportable incidents.

Three additional commenters said that

corrosion leaks on properly protected

pipe are rare, and that most corrosion

leaks occur on unprotected bare steel

that is too costly to protect. These

commenters contended the best

approach to combating corrosion leaks

is through aggressive leak surveys.

b. Descriptions of operating/

maintenance practices to minimize

corrosion leaks on cathodically

unprotected lines.

Comments: Six commenters reported

the use of a ranking system to prioritize

segments of bare steel pipe for

replacement, based on age, location,

leaks, size, and cathodic protection.

Other practices included replacement

rather than repair of bare steel, and not

uprating or reconnecting cast iron,

ductile iron, or bare steel pipe. Another

commenter said its practices are

designed to enhance economic value

rather than just meet Part 192

requirements.

c. Descriptions of risk-based corrosion

management programs.

Comments: The only commenter said

a plan should preserve the intent of the

code but allow for geography and

operating condition differences.

d. The best approach to monitoring

corrosion control in urban wall-to-wall

paved areas.

Comments: One commenter suggested

taking readings at test stations no

further than one block (660 feet) apart,

while another advised 1200 feet apart.

Still another commenter stressed the

importance of creating access openings.

7. The amount of buried piping at

compressor, regulator, and measuring

stations that is not cathodically

protected.

Comments: Three commenters said all

their piping in these locations is

protected. AGA/APGA said the data are

not available, but the piping poses a low

risk.

8. Explicit examples of adequate

compliance with particular standards

that have had varied interpretations.

Comments: AGA/APGA reported that

while government compliance

personnel interpret some standards

inconsistently, the safety statistics

support adequate compliance.

9. To provide an acceptable level of

safety on existing pipelines, must

cathodic protection preserve the

pipeline indefinitely or merely slow the

rate of corrosion until the pipeline has

to be rehabilitated or replaced?

Comments: Two commenters said the

decision should be based on a cost/

benefit assessment, considering the

possible use of new materials and the

future need to move or replace a

pipeline due to construction by others.

One other comment was that corrosion

can only be mitigated and to try to do

otherwise would be too expensive.

Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules 76975

5 ‘‘Breakout tank’’ is defined in § 195.2 as ‘‘a tank

used to (a) relieve surges in a hazardous liquid

pipeline system or (b) receive and store hazardous

liquids transported by a pipeline for reinjection and

continued transportation by pipeline.’’

Proposed Subpart H—Corrosion

Control

In view of the above concerns,

recommendations, and comments, we

are proposing to add to part 195 a new

subpart H called Corrosion Control.

Subpart H would prescribe corrosion

control standards for new and existing

steel pipelines to which Part 195

applies. Concerns, recommendations,

and comments that pertain primarily to

the corrosion control standards in Part

192 will be addressed in a future

rulemaking proceeding on gas pipelines.

Because commenters showed little

enthusiasm for the alternatives of NACE

Standard RP0169–96 and corrosion

management plans, we did not include

either alternative in proposed Subpart H

(except as provided in proposed

§ 195.567 regarding cathodic protection

criteria). Nevertheless, because NACE

Standard RP0169–96 is so widely

respected, we would like to keep the

floor open for further discussion of the

merits of adopting it as an overall

corrosion control standard for pipelines.

In this regard, we invite interested

persons to comment again on the pros

and cons of referencing the entire NACE

Standard RP0169–96 as an alternative to

proposed Subpart H. This request for

comment is not a rulemaking proposal.

We recognize that a further notice of

proposed rulemaking would be required

before the entire NACE Standard

RP0169–96 could be incorporated by

reference as a Part 195 safety standard.

Proposed Subpart H includes many

standards that are identical to present

corrosion control requirements in Part

195 and standards that are substantially

like present requirements in Part 192.

The proposed subpart also includes

standards that, while based on present

Part 192 requirements, include changes

we think are beneficial improvements,

considering acceptable safety practices.

We do not intend that proposed subpart

H results in a lessening of current

requirements. Each of the sections in

proposed Subpart H is discussed below.

Section 195.551 Scope.

Proposed § 195.551 characterizes the

activities that are covered by the

proposed standards in subpart H (i.e.,

protecting steel pipelines against

external, internal, and atmospheric

corrosion). Section 195.551 is

informational in nature and would not

impose any obligations.

Like the present corrosion control

standards in part 195 (§§ 195.236,

195.238, 195.242, 195.244, 195.414,

195.416, and 195.418), proposed

Subpart H would apply only to steel

pipelines. In contrast, comparable

corrosion control standards for gas

pipelines (subpart I of Part 192) apply

to pipelines made of any metal.

However, because hazardous liquid and

carbon dioxide pipelines are made of

steel almost exclusively, such broad

coverage is not warranted for pipelines

regulated by part 195.

Nevertheless, under § 195.8, operators

must give us an opportunity to review

the safety of any pipeline that is to be

constructed with a material other than

steel. In the case of a non-steel metallic

pipeline, that review would include the

operator’s plans for corrosion control.

You should note that ‘‘breakout

tanks’’ 5 come within the scope of

proposed subpart H, because part 195

defines ‘‘pipeline’’ to include breakout

tanks (§ 195.2). Consistent with the

convention stated in § 195.1(c),

proposed subpart H standards

applicable to breakout tanks include

standards that concern breakout tanks

specifically and, to the extent

applicable, standards that concern

pipeline systems, or pipelines,

generally. Proposed standards that

concern only pipe, such as §§ 195.583

and 195.585, do not apply to breakout

tanks because these standards do not

affect parts of pipelines other than pipe.

Section 195.553 Qualification of

Supervisors

The new personnel qualification

standards in subpart G of part 195 (64

FR 46866; Aug. 27, 1999) apply to

individuals who perform covered tasks

on pipelines, including regulated

corrosion control activities. However,

supervision of covered tasks is not,

itself, a covered task. So supervision of

corrosion control activities does not

come under Subpart G.

We know that prevention of

corrosion-caused accidents does not

depend solely on how well personnel

perform covered tasks on pipelines.

Prevention also depends on the

correctness of critical decisions that

flow from those tasks. Indeed, many

Part 195 corrosion control standards

require operators not only to perform

tasks on pipelines, but to decide if

corrective action is needed as a result of

the tasks. For example, under

§ 195.416(d), operators must

periodically inspect bare pipe and then

determine if cathodic protection is

needed.

Individuals assigned to perform

covered corrosion control tasks on

pipelines, such as collecting pipe-to-soil

data, may be qualified under subpart G

without knowing what corrective action,

if any, should be taken as a result of the

tasks. Generally these critical corrosion

control decisions are made by

supervisory personnel who are in charge

of carrying out the corrosion control

procedures under § 195.402(c). It is

reasonable, we think, that individuals

who direct others to carry out corrosion

control procedures should have

sufficient knowledge of the procedures

so they understand what they are

directing.

At present, § 195.403(c) regulates the

qualifications of individuals assigned to

supervise the performance of corrosion

control procedures. This rule requires

each operator to ‘‘require and verify that

its supervisors maintain a thorough

knowledge of that portion of the

procedures established under § 195.402

for which they are responsible to insure

compliance.’’ However, § 195.403(c) has

been changed. On October 28, 2002, this

rule will apply only to supervisors of

emergency response procedures (64 FR

46866). Consequently, we are proposing,

under § 195.553, to preserve the

substance of § 195.403(c) as it now

applies to supervisors of corrosion

control procedures.

Section 195.555 External Corrosion

Control; Applicability

Proposed § 195.555 designates the

pipelines covered by proposed

§§ 195.557, 195.559, and 195.561. As

stated below, these three proposed

standards are identical to the present

corrosion control standards in

§§ 195.238, 195.242, and 195.244

governing coating, cathodic protection,

and test leads. Like the standards they

would replace, the proposed standards

would apply only to pipelines

constructed, relocated, replaced, or

otherwise changed after §§ 195.238,

195.242, and 195.244 went into effect

and to certain converted pipelines (see

§ 195.5(b)). The effective dates of

§§ 195.238, 195.242, and 195.244 are

given in § 195.401(c) and vary by

pipeline. Proposed § 195.555 crossreferences §§ 195.401(c) and 195.5(b).

One other existing corrosion control

standard, § 195.236, applies to the same

pipelines as §§ 195.238, 195.242, and

195.244. But this standard, which

requires protection against external

corrosion, is written in terms that may

be too general. We think the standard

adds nothing substantive to the more

specific requirements for external

corrosion protection in §§ 195.238 and

195.242. So we are proposing to drop

§ 195.236 and not include it in proposed

subpart H.

76976 Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules

Section 195.557 External Corrosion

Control; Protective Coating

Proposed § 195.557 is identical to

§ 195.238, which prescribes standards

for external coating on certain buried or

submerged pipeline components.

Section 195.559 External Corrosion

Control; Cathodic Protection System

Proposed § 195.559 is identical to

§ 195.242, which requires certain buried

or submerged facilities to be

cathodically protected.

Section 195.561 External Corrosion

Control; Test Leads

Proposed § 195.561 is substantially

the same as § 195.244, which prescribes

standards for the installation of test

leads to measure cathodic protection on

certain onshore pipelines. However, we

are also proposing that at the connection

to the pipeline, each bared test lead wire

and bared metallic area must be coated

with an electrical insulating material

compatible with the pipe coating and

the insulation on the wire. This

provision is now in effect for gas

pipelines under § 192.471(c).

Section 195.563 External Corrosion

Control; Additional Cathodic Protection

Requirements

Proposed § 195.563 is comparable to

§ 195.414(a), which requires all

effectively coated pipelines to be

cathodically protected, except for piping

in breakout tank areas and pump

stations. To avoid any duplication of

proposed § 195.559, proposed § 195.563

would apply only to pipelines that are

not protected under proposed § 195.559.

Also, we omitted the compliance dates

in § 195.414(a) from proposed § 195.563

because the dates have passed.

Section 195.565 External Corrosion

Control; Examination of Buried Pipeline

When Exposed

Proposed § 195.565 is comparable to

existing § 195.416(e), which requires

operators to investigate the extent of

active corrosion found on exposed

pipelines. We recently revised a parallel

standard, § 192.459, to clarify the means

and bounds of corrosion investigations

on exposed gas pipelines (64 FR 56978;

Oct. 22, 1999). In view of this rule

change, we used § 192.459 as a model

for proposed § 195.565 to provide the

same clarity for similar investigations

required on hazardous liquid and

carbon dioxide pipelines. We believe

this proposal and the associated

recordkeeping under proposed

§ 195.587 are consistent with SIRRC’s

suggested changes to § 192.459 quoted

above in the discussion of NAPSR’s

§ 192.459 recommendation. Under

proposed § 195.565, operators may use

indirect methods, including electrical

surveys or smart pigs, besides

excavation and observation to look for

corrosion in the vicinity of an exposed

portion of pipeline.

During the course of looking for

corrosion on an exposed pipeline,

operators observe the condition of

protective coating on the pipeline.

Proposed § 195.565 would codify this

inherent step by requiring operators to

first see if the coating is deteriorated

before they examine the exposed

pipeline for corrosion. Operators’

records of inspections preserve

information about examinations of

exposed pipe for future use, such as

assessing the condition of the pipeline

for purposes of corrosion control. We

think the combination of proposed

§ 195.565 and records of examinations

of exposed pipe would provide an

adequate response to NTSB

recommendation P–98–35 that part 195

require operators to determine the

condition of external coating on

exposed pipelines. Proposed § 195.587

(see below) would require operators to

keep records of examinations of exposed

pipe for as long as the pipe remains in

service rather than 2 years as now

required by § 195.404(c)(3).

Section 195.567 External Corrosion

Control; Cathodic Protection Criteria

NTSB has recommended that Part 195

include performance measures for the

adequacy of cathodic protection

(recommendation P–98–36). We support

NTSB’s recommendation. Consequently,

we are proposing, in § 195.567, that

cathodic protection comply with the

criteria and other considerations in

section 6 of NACE Standard RP0169–96.

In developing this proposal, we

considered that in our experience

operators universally apply either NACE

criteria or criteria in appendix D of part

192 to determine the adequacy of

cathodic protection on pipelines that

come under part 195. Similarly, the

comments we received on performance

measures for cathodic protection were

divided between the NACE criteria and

the appendix D criteria. And in its April

1995 report of a review of the part 195

standards, NAPSR supported either set

of criteria.

While NACE and Appendix D criteria

overlap in many respects, two Appendix

D criteria (300 mV shift and E-log-I) are

not among the NACE criteria. We

believe they were omitted because they

are outmoded and lack technical

validation; and the comments did not

dissuade us of this concern. Given our

uncertainty about appendix D, we felt

compelled to limit our proposal to

section 6 of NACE Standard RP0169–96.

Still it is important to recognize that

under proposed § 195.567 operators

would not have to use only criteria

included in section 6 of NACE Standard

RP0169–96. Paragraph 6.2.1 of NACE

Standard RP0169–96 permits operators

to use any criteria that achieves

corrosion control comparable to that

attained with criteria included in

section 6. In addition, paragraph 6.2.1

permits operators to continue to use on

existing pipelines criteria that have been

successfully applied to those pipelines.

Thus proposed § 195.567 would not

deny operators the opportunity to use

appendix D criteria that are not

included in section 6 of NACE Standard

RP0169–96 as long as the operators can

meet the tests of comparability or

successful application stated in

paragraph 6.2.1 for the use of alternative

criteria. Although section 6 of NACE

Standard RP0169–96 does not provide

measures of comparability or successful

application, to comply with paragraph

6.2.1, we believe there would have to be

an absence of corrosion leaks on the

pipeline between cathodic protection

inspections. And, if the integrity of the

pipeline has been checked between

cathodic protection inspections by an

internal inspection device, pressure

testing, or direct examination, there

would have to be no signs of metal loss

due to corrosion.

On the issue of correct application of

the negative (cathodic) 0.85 volt

criterion, we find no difference between

the NACE and appendix D criteria. Both

require that voltage drops other than

those across the structure-to-electrolyte

boundary must be ‘‘considered’’ for

valid interpretation of measurements

taken for the negative (cathodic) 0.85

volt criterion. NACE explains that

consideration means the application of

sound engineering practice in

determining the significance of voltage

drops by methods such as measuring or

calculating the voltage drop, reviewing

the historical performance of the

cathodic protection system, evaluating

the physical and electrical

characteristics of the pipe and its

environment, and determining whether

or not there is physical evidence of

corrosion.

Section 195.569 External Corrosion

Control; Monitoring

Proposed § 195.569(a) is substantially

the same as § 195.416(a), which requires

annual tests of the adequacy of cathodic

protection. The only difference is that

proposed § 195.569(a) references

proposed § 195.567 as the measure of

adequacy. Proposed § 195.569(b) is

Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules 76977

6The term ‘‘bare pipe’’ refers to pipe that is bare

and to pipe that is ineffectively coated (see

§ 195.414(a)).

7Bare pipe and piping in breakout tank areas and

pump stations are treated separately under

§ 194.414. So we do not consider unprotected

piping in breakout tank areas and pump stations to

come under the requirements of § § 194.416(d)

concerning the periodic inspection of bare pipe.

identical to § 195.416(c), which requires

bimonthly inspections of cathodic

protection rectifiers. Although proposed

§ 195.569(d) has no parallel in part 195,

it is comparable to § 192.465(c), which

requires periodic inspections of items

critical to cathodic protection. We think

such inspections are common practice

on pipelines subject to part 195.

Proposed § 195.569(e) is identical to

§ 195.416(j), which requires inspections

of systems used to protect the bottoms

of aboveground breakout tanks.

Proposed § 195.569(c) is comparable

to existing § 195.416(d), which requires

electrical inspection of unprotected

‘‘bare pipe’’ 6 at least every 5 years to

determine if protection is needed.

However, like § 192.465(e), proposed

§ 195.569(c) would clarify that the

purpose of the inspections is to detect

‘‘active corrosion’’ and would allow

operators to use alternative means of

determining active corrosion where an

electrical survey is impractical. The

term ‘‘active corrosion’’ would be

defined essentially as it is in

§ 192.457(c), but with the additional

consideration of risk to the

environment. Moreover, as SIRRC

recommended for gas pipelines under

§ 192.465(e) (see above), the alternative

means of determining active corrosion

would have to include an analysis and

review of the pipeline’s condition,

based on leak repair history, exposed

pipe inspection records, and the

pipeline environment. In accordance

with SIRRC’s recommendation, we also

included definitions of ‘‘electrical

survey’’ and ‘‘pipeline environment’’ in

proposed § 195.569(c).

Another difference between proposed

§§ 195.569(c) and 195.416(d) is that, like

§ 192.465(e), proposed § 195.569(c)

would require inspections of all

unprotected pipelines, not just

unprotected bare pipe. The impact of

this change would be on unprotected

buried piping in breakout tank areas and

pump stations. At present, part 195 does

not have a periodic inspection

requirement for corrosion on

unprotected piping in breakout tank

areas and pump stations. 7 Only minor

costs should result from this change in

coverage, for we believe that periodic

inspection of unprotected piping in

breakout tank areas and pump stations

is a common industry practice. The

requirements for initial electrical

inspection of bare pipelines (§ 195.414

(b)) and of piping in breakout tank areas

and pump stations (§ 195.414(c)) have

not been included in proposed Subpart

H because the periods allowed for

compliance have expired.

We have not proposed to increase the

minimum frequency of inspections from

every 5 years to every 3 years, which is

the minimum frequency required by

§ 192.465(e) for inspecting unprotected

gas pipelines. Our safety data do not

show that increasing the minimum

frequency to every 3 years would be

likely to result in fewer reported

corrosion-caused accidents on

hazardous liquid or carbon dioxide

pipelines. Moreover, the ASME B31.4

Code, a set of voluntary safety standards

widely followed by operators of

pipelines subject to part 195, specifies a

minimum frequency of every 5 years for

inspecting unprotected pipelines. While

NACE Standard RP0169–96 requires

periodic inspections to determine the

need to protect unprotected pipelines, it

does not prescribe the frequency of

those inspections.

We also considered the need to

propose a standard comparable to

§ 192.465(d), which requires gas

pipeline operators to take ‘‘prompt’’

remedial action to correct any

deficiencies detected by monitoring

external corrosion control. But we

decided such a proposal is unnecessary

because § 195.401(b) requires operators

to correct within a reasonable time any

condition that could adversely affect

safe operation, and if an immediate

hazard exists, to cease operating the

affected facility until the condition is

corrected. Also, § 195.401(b) regulates

the timing of corrective responses to any

unsafe corrosion control deficiency, not

just deficiencies in external corrosion

control.

Section 195.571 External Corrosion

Control: Electrical Isolation

Proposed § 195.571 is comparable to

§ 192.467, which requires electrical

isolation on gas pipelines to provide for

adequate cathodic protection and

safeguards for insulating devices. Such

isolation is also a common practice on

pipelines subject to part 195. However,

we are not proposing to include the

requirements of § 192.467(c) concerning

isolation of pipelines from metallic

casings. We agree with GPTC and

commenters who believe the safety need

to clear shorted casings is not apparent.

Therefore, we have not included in

proposed Subpart H SIRRC’s

recommended measures to remedy

shorted casings.

Section 195.573 External Corrosion

Control: Test Stations

Proposed § 195.573 is identical to

§ 195.416(b), which requires

maintenance of test leads to provide for

monitoring the adequacy of cathodic

protection.

Section 195.575 External Corrosion

Control: Interference Currents

Proposed § 195.575 is comparable to

§ 192.473, which requires operators to

minimize the detrimental effects of

interference currents on gas pipelines

and adjacent structures. Although at

present there are no standards in part

195 concerning interference problems,

we believe that most operators already

have a testing program to minimize

interference problems. Proposed

§ 195.575 has minor editorial

differences from the wording of

§ 192.473.

Section 195.577 Internal Corrosion

Control

Proposed § 195.577 is comparable to

§ 195.418, which requires protective

measures to mitigate the effects of

internal corrosion. However, proposed

§ 195.577(d) differs somewhat from

§ 195.418(d), which requires operators

to investigate the extent of general

corrosion found inside pipe that is

removed from a pipeline. Proposed

§ 195.577(d) would clarify the required

investigation by adopting wording

similar to that of proposed § 195.565,

which concerns the extent of external

corrosion on exposed pipe. Also, under

proposed § 195.577(d), an investigation

would be required if the removed pipe

is corroded to the extent that it must be

remedied under proposed § 195.583,

rather than if the pipe is generally

corroded such that the wall thickness is

less than that required by the pipe’s

specification tolerances, as § 195.418(d)

now requires. This change would allow

operators to take full advantage of

criteria for determining the strength of

corroded pipe (see proposed § 195.585).

The change would also require

consideration of the effect of corrosion

pitting as well as general corrosion,

consistent with the parallel requirement

for gas pipelines in § 192.475(b).

Another difference between the

proposed and existing standards is that

proposed § 195.577(d) drops the

remedial measures § 195.418(d)

prescribes for corroded pipe. Remedial

measures for corroded pipe would be

governed by proposed § 195.583. This

change would improve the present rule

by basing the need for remediation on

the strength of corroded pipe and by

allowing the use of qualified repair

76978 Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules

8Section 195.416(f) was revised by Amendment

195–68 (64 FR 69660; Decemeber 14, 1999).

methods that are not allowed under

§ 195.418(d).

Section 195.579 Atmospheric

Corrosion Control; General

Proposed § 195.579 is comparable to

§ 195.416(i), which requires that all

pipelines exposed to the atmosphere

must be protected against atmospheric

corrosion by a suitable coating. The

comments indicate § 195.416(i) may be

overly burdensome, because it does not

give operators leeway to avoid coating

pipelines that have only a harmless light

surface oxide or other mild form of

corrosion that is unlikely to harm the

pipeline before the next scheduled

inspection. So proposed § 195.579

includes an exception for these

circumstances. The test, investigation,

or experience used to justify an

exception must be appropriate to the

environment of the particular pipeline

facility. In addition, this exception

would not apply to splash zones of

offshore pipelines or to soil-to-air

interfaces of onshore pipelines.

We did not adopt SIRRC’s

recommendation regarding comparable

§ 192.479 (see above) to except all but

‘‘active corrosion’’ from the atmospheric

corrosion protection requirement. The

intent of the recommendation is to

distinguish harmless rust from serious

metal loss, but we believe this objective

is better accomplished by more

descriptive wording.

Section 195.581 Atmospheric

Corrosion Control; Monitoring

Proposed § 195.581 is comparable to

§ 192.481, which requires operators of

gas pipelines to reevaluate the adequacy

of atmospheric corrosion protection at

least every 3 years on onshore pipelines

and at least every year on offshore

pipelines. Although § 195.416(i)

requires maintenance of protection on

hazardous liquid and carbon dioxide

pipelines, this standard may be too

general because it lacks minimum

inspection frequencies.

In deciding what inspection

frequency is most appropriate for

onshore pipelines, we considered the

majority of comments on § 192.481 that

favored lengthening the minimum

inspection frequency from every 3 years

to every 5 years. But we gave section

463.3 of the ASME B31.4 Code greater

weight. This voluntary code, which is

widely followed by operators of

pipelines subject to Part 195, specifies a

minimum 3-year inspection frequency

for atmospheric corrosion protection

onshore. We also considered that GPTC,

in its recommendation regarding

§ 192.481, did not suggest extending the

minimum 3-year frequency more than a

marginal amount to provide flexibility.

Also, two commenters said the present

3-year frequency is not too burdensome.

There were no comments on the

frequency of inspection offshore, and

the ASME B31.4 Code does not specify

a minimum frequency.

Proposed § 195.581 would require

periodic ‘‘inspection’’ rather than

‘‘reevaluation’’ to avoid the possibility

that decisions about the adequacy of

protection might not be based on

current observations. The proposed rule

also recognizes the importance of

paying special attention during

inspections to particular pipeline areas

that have historically been sources of

corrosion problems, such as splash

zones and pipe surfaces underneath

thermal insulation. We feel that most

operators already inspect aboveground

pipelines for corrosion at the proposed

frequencies and give careful attention to

potential problem areas.

Section 195.583 Remedial Measures;

General

Proposed § 195.583(a) is comparable

to § 195.416 (f), which regulates the

repair of pipe that has general

corrosion. 8 But proposed § 195.583(a)

reflects the wording of § 192.485(a), a

repair rule similar to § 195.416(f) that

bases the need for corrective action on

whether the remaining wall thickness

supports the maximum allowable

operating pressure. At present,

§ 195.416 (f) bases the need for

corrective action on whether the

remaining wall thickness is within the

pipe specification tolerances. The

revised wording would allow operators

to take full advantage of criteria for

determining the strength of corroded

pipe (see proposed § 195.585). Proposed

§ 195.583(b) is identical to § 195.416(g),

which regulates remedial measures for

localized corrosion pitting.

Section 195.585 Remedial Measures;

Remaining Strength

Proposed § 195.585 is substantially

the same as § 195.416(h), which

authorizes the use of widely accepted

criteria for determining the remaining

strength of corroded pipe.

Section 195.587 Records

For hazardous liquid and carbon

dioxide pipelines, requirements to keep

records related to corrosion control are

in § 195.404. Under § 195.404(a),

operators must maintain current maps

and records that identify and show the

location of facilities that are

cathodically protected. In addition,

§ 195.404(c)(3) requires operators to

keep records of required inspections

and tests for at least 2 years or until the

next inspection or test, whichever is

longer.

We are proposing to adopt new

recordkeeping requirements for

hazardous liquid and carbon dioxide

pipelines comparable to those for gas

pipelines in § 192.491. Under proposed

§ 195.587(a), operators would have to

keep current records or maps of the

location of cathodically protected

piping (as they must now under

§ 195.404(a)), of cathodic protection

facilities, and of bonded structures.

Also, under proposed § 195.587(b),

operators would have to keep a record

of each analysis, check, demonstration,

examination, inspection, investigation,

review, survey, and test required by

proposed Subpart H in sufficient detail

to demonstrate the adequacy of

corrosion control measures or that

corrosion requiring control measures

does not exist. Records required by

§ 195.587(b) would have to be retained

for at least 5 years, except that records

related to determining the adequacy of,

or need for, external or internal

corrosion control (records related to

proposed §§ 195.565, 195.569(a) and (c),

and 195.577(c) and (d)) would have to

be kept as long as the pipeline is in

service.

The majority of comments on the

appropriate period to keep records

related to determining if external or

internal corrosion control is adequate or

needed did not support keeping these

records for as long as the pipeline

remains in service. Instead they mostly

suggested a retention period of 5 years

or the next one or two monitoring

cycles, whichever is longer. But we

agree with the single commenter who

said keeping such records for the service

life of the pipeline provides a very

helpful general history. In our

experience, a history of corrosion

control monitoring is very useful in

assessing the condition of a pipeline. If

corrosion problems emerge on a

pipeline, its monitoring history is

considered in deciding the extent and

kind of remedial action needed.

As for other records under proposed

§ 195.587(b) (e.g., records of rectifier

inspections under proposed

§ 195.569(b)), we believe the retention

period must be compatible with the

normal cycle of routine compliance

investigations by government inspection

personnel and long enough to provide

meaningful history for investigation of

an accident or safety problem. A

minimum 5-year retention requirement

would assure that the records are

available during routine inspection

Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules 76979

visits, and provide a more complete

history for analyzing problems.

Proposed § 195.587(a)(2), which is

based on § 192.491(a), would require

operators to have current records or

maps identifying the location of

cathodic protection facilities, galvanic

anodes, and structures bonded to

cathodic protection systems. Such

records are not now required by Part

195, and although operators may have

them, to minimize the recordkeeping

burden, the records would only be

required for installations made after the

final rule goes into effect.

The record retention times proposed

by § 195.587(b) would only apply to

records of actions that occur after

Subpart H takes effect. The retention

times now required by § 195.404(c)(3)

would continue to apply to records of

corrosion tests and inspections done

before Subpart H takes effect.

Regulatory Analyses and Notices

Executive Order 12866 and DOT

Policies and Procedures

RSPA does not consider this proposed

rulemaking to be a significant regulatory

action under Section 3(f) of Executive

Order 12866 (58 FR 51735; Oct. 4,

1993). Therefore, the Office of

Management and Budget (OMB) has not

received a copy of this rulemaking to

review. RSPA also does not consider

this proposed rulemaking to be

significant under DOT regulatory

policies and procedures (44 FR 11034:

February 26, 1979).

We prepared a Draft Regulatory

Evaluation of the proposed rules and a

copy is in the docket. The evaluation

states that the proposed rules are, on the

whole, comparable either to existing

safety standards currently in part 195

for hazardous liquid pipelines or to

existing safety standards in part 192 for

gas pipelines. The evaluation also states

that the information presented at public

meetings and meetings with industry

and state representatives strongly

suggests that imposing gas pipeline

safety standards for corrosion control on

hazardous liquid pipelines would not

require a significant departure from

customary safety practices on liquid

pipelines.

An important feature of the proposed

rules not found in part 192 or part 195

is the reference to cathodic protection

criteria in NACE Standard RP0169–96.

The evaluation states that these criteria

are well known and widely followed

throughout the industry, as indicated by

meetings with industry representatives

and by the voluntary standards in the

ASME B31.4 Code. The evaluation

further states that operators who do not

now apply the NACE criteria are likely

to apply the criteria in appendix D of

part 192. The proposed rules would

allow use of appendix D criteria under

conditions stated in the NACE standard.

The evaluation concludes there

should be only minimal additional cost,

if any, for operators to comply with the

proposed rules. If you disagree with this

conclusion, please provide information

to the public docket described above.

Regulatory Flexibility Act

The proposed rules are consistent

with customary practices for corrosion

control in the hazardous liquid and

carbon dioxide pipeline industry.

Therefore, based on the facts available

about the anticipated impacts of this

proposed rulemaking, I certify, pursuant

to section 605 of the Regulatory

Flexibility Act (5 U.S.C. 605), that this

proposed rulemaking would not have a

significant impact on a substantial

number of small entities. If you have

any information that this conclusion

about the impact on small entities is not

correct, please provide that information

to the public docket described above.

Executive Order 13084

The proposed rules have been

analyzed in accordance with the

principles and criteria contained in

Executive Order 13084, ‘‘Consultation

and Coordination with Indian Tribal

Governments.’’ Because the proposed

rules would not significantly or

uniquely affect the communities of the

Indian tribal governments and would

not impose substantial direct

compliance costs, the funding and

consultation requirements of Executive

Order 13084 do not apply.

Paperwork Reduction Act

Section 195.587 proposes minor

additional information collection

requirements. Operators would be

required to record the location of certain

newly installed protection facilities, and

keep the records for as long as the

pipeline concerned is in service. In

addition, records of inspections, tests,

and surveys would have to be kept for

as long as the pipeline is in service or

for 5 years, depending on the nature of

the information recorded. The present

minimum retention period for these

records is 2 years or the prescribed

interval of test or inspection, whichever

is longer (up to 5 years in some cases).

However, we believe operators

already maintain records of the location

of their protection facilities for as long

as the pipeline is in service to be able

to find the facilities for their own

purposes and to carry out existing

monitoring requirements in part 195.

Also, we believe the burden of retaining

inspection, test, and survey records for

the longer period proposed would be

minimal. These records are largely

computerized. Maintaining these

records on a floppy disk or computer

file represents very minimal costs. So,

because the additional paperwork

burdens of this proposed rule are likely

to be minimal, we believe that

submitting an analysis of the burdens to

OMB under the Paperwork Reduction

Act is unnecessary. If you disagree with

this conclusion, please submit your

comments to the public docket.

Unfunded Mandates Reform Act of 1995

This proposed rulemaking would not

impose unfunded mandates under the

Unfunded Mandates Reform Act of

1995. It would not result in costs of

$100 million or more to either State,

local, or tribal governments, in the

aggregate, or to the private sector, and

would be the least burdensome

alternative that achieves the objective of

the rule.

National Environmental Policy Act

We have analyzed the proposed rules

for purposes of the National

Environmental Policy Act (42 U.S.C.

4321 et seq.). Because the proposed

rules parallel present requirements or

practices, we have preliminarily

determined that the proposed rules

would not significantly affect the

quality of the human environment. An

environmental assessment document is

available for review in the docket. A

final determination on environmental

impact will be made after the end of the

comment period. If you disagree with

our preliminary conclusion, please

submit your comments to the docket as

described above.

Impact on Business Processes and

Computer Systems

We do not want to impose new

requirements that would mandate

business process changes when the

resources necessary to implement those

requirements would otherwise be

applied to ‘‘Y2K’’ or related computer

problems. The proposed rules would

not mandate business process changes

or require modifications to computer

systems. Because the proposed rules

would not affect the ability of

organizations to respond to those

problems, we are not proposing to delay

the effectiveness of the requirements.

Executive Order 13132

The proposed rules have been

analyzed in accordance with the

principles and criteria contained in

Executive Order 13132 (‘‘Federalism’’).

76980 Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules

The proposed rules do not propose any

regulation that (1) has substantial direct

effects on the States, the relationship

between the national government and

the States, or the distribution of power

and responsibilities among the various

levels of government; (2) imposes

substantial direct compliance costs on

State and local governments; or (3)

preempts state law. Therefore, the

consultation and funding requirements

of Executive Order 13132 do not apply.

Nevertheless, during our review of the

existing corrosion control standards,

representatives of state pipeline safety

agencies gave us advice both in private

sessions and in the two public meetings

we held. In addition, our pipeline safety

advisory committees, which include

representatives of state governments,

were, on two occasions in 1999, briefed

on the corrosion control review project.

List of Subjects in 49 CFR Part 195

Ammonia, Carbon dioxide,

Petroleum, Pipeline safety, Reporting

and recordkeeping requirements.

In consideration of the foregoing, we

propose to amend 49 CFR part 195 as

follows:

PART 195—[AMENDED]

1. The authority citation for part 195

continues to read as follows:

Authority: 49 U.S.C. 5103, 60102, 60104,

60108, 60109, 60118; and 49 CFR 1.53.

2. Section 195.3 would be amended

by adding paragraphs (b)(8) and (c)(7) to

read as follows:

§ 195.3 Matter incorporated by reference.

* * * * *

(b) * * *

(8) NACE International, 1440 South

Creek Drive, Houston, TX 77084.

(c) * * *

(7) NACE International (NACE):

(i) NACE Standard RP0169–96,

‘‘Control of External Corrosion on

Underground or Submerged Metallic

Pipeline Systems’’ (1996).

(ii) [Reserved]

3. Section 195.5(b) would be revised

to read as follows:

§ 195.5 Conversion to service subject to

this part.

* * * * *

(b) A pipeline which qualifies for use

under this section need not comply with

the corrosion control requirements of

subpart H of this part until 12 months

after it is placed in service,

notwithstanding any earlier deadlines

for compliance. The requirements of

§§ 195.557, 195.559, and 195.561 apply

to each pipeline which substantially

meets those requirements before it is

placed in service or which is a segment

that is replaced, relocated, or

substantially altered.

* * * * *

4. Section 195.402(c)(3) would be

revised to read as follows:

§ 195.402 Procedural manual for

operations, maintenance, and emergencies.

* * * * *

(c) * * *

(3) Operating, maintaining, and

repairing the pipeline system in

accordance with each of the

requirements of this subpart and subpart

H of this part.

* * * * *

§ 195.404 [Amended]

5. In § 195.404, paragraph (a)(1)(v)

would be removed, and paragraphs

(a)(1)(vi) through (a)(1)(viii) would be

redesignated as paragraphs (a)(1)(v)

through (a)(1)(vii).

§§ 195.236, 195.238, 195.242, 195.244,

195.414, 195.416, 195.418 [Removed]

6. The following sections would be

removed and reserved: §§ 195.236,

195.238, 195.242, 195.244, 195.414,

195.416, and 195.418.

7. Subpart H would be added to read

as follows:

Subpart H—Corrosion Control

Sec.

195.551 Scope.

195.553 Qualification of supervisors.

195.555 External corrosion control;

Applicability.

195.557 External corrosion control;

Protective coating.

195.559 External corrosion control;

Cathodic protection system.

195.561 External corrosion control; Test

leads.

195.563 External corrosion control;

Additional cathodic protection

requirements.

195.565 External corrosion control;

Examination of a buried pipeline when

exposed.

195.567 External corrosion control;

Cathodic protection criteria.

195.569 External corrosion control;

Monitoring.

195.571 External corrosion control;

Electrical isolation.

195.573 External corrosion control; Test

stations.

195.575 External corrosion control;

Interference currents.

195.577 Internal corrosion control.

195.579 Atmospheric corrosion control;

General.

195.581 Atmospheric corrosion control;

Monitoring.

195.583 Remedial measures; General.

195.585 Remedial Measures; Remaining

strength.

195.587 Records.

Subpart H—Corrosion Control

§ 195.551 Scope.

This subpart prescribes minimum

requirements for protecting steel

pipelines against corrosion.

§ 195.553 Qualification of supervisors.

Each operator must require and verify

that its supervisors maintain a thorough

knowledge of that portion of the

corrosion control procedures

established under § 195.402 for which

they are responsible for insuring

compliance.

§ 195.555 External corrosion control;

Applicability.

The requirements of §§ 195.557,

195.559, and 195.561 apply only to—

(a) Pipelines constructed, relocated,

replaced, or otherwise changed after the

applicable date in § 195.401(c); and

(b) Converted pipelines, if required by

§ 195.5(b).

§ 195.557 External corrosion control;

Protective coating.

(a)(1) No component of a pipeline

may be buried or submerged unless that

component has an external protective

coating that—

(i) Is designed to mitigate corrosion of

the buried or submerged component;

(ii) Has sufficient adhesion to the

metal surface to prevent under film

migration of moisture;

(iii) Is sufficiently ductile to resist

cracking;

(iv) Has enough strength to resist

damage due to handling and soil stress;

and

(v) Supports any supplemental

cathodic protection.

(2) In addition, if any insulating-type

coating is used, it must have low

moisture absorption and provide high

electrical resistance.

(b) All pipe coating must be inspected

just prior to lowering the pipe into the

ditch or submerging the pipe, and any

damage discovered must be repaired.

§ 195.559 External corrosion control;

Cathodic protection system.

(a) A cathodic protection system must

be installed for all buried or submerged

facilities to mitigate corrosion that

might result in structural failure. A test

procedure must be developed to

determine whether adequate cathodic

protection has been achieved.

(b) A cathodic protection system must

be installed not later than 1 year after

completing the construction.

(c) For the bottoms of aboveground

breakout tanks with greater than 500

barrels (79.5 m3) capacity built to API

Specification 12F, API Standard 620, or

API Standard 650 (or its predecessor

Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules 76981

Standard 12C), the installation of a

cathodic protection system under

paragraph (a) of this section after

October 2, 2000, must be in accordance

with API Recommended Practice 651,

unless the operator notes in the

procedural manual (§ 195.402(c)) why

compliance with all or certain

provisions of API Recommended

Practice 651 is not necessary for the

safety of a particular breakout tank.

(d) For the internal bottom of

aboveground breakout tanks built to API

Specification 12F, API Standard 620, or

API Standard 650 (or its predecessor

Standard 12C), the installation of a tank

bottom lining after October 2, 2000,

must be in accordance with API

Recommended Practice 652, unless the

operator notes in the procedural manual

(§ 195.402(c)) why compliance with all

or certain provisions of API

Recommended Practice 652 is not

necessary for the safety of a particular

breakout tank.

§ 195.561 External corrosion control; Test

leads.

(a) Except for offshore pipelines,

electrical test leads used for corrosion

control or electrolysis testing must be

installed at intervals frequent enough to

obtain electrical measurements

indicating the adequacy of the cathodic

protection.

(b) Test leads must be installed as

follows:

(1) Enough looping or slack must be

provided to prevent test leads from

being unduly stressed or broken during

backfilling.

(2) Each lead must be attached to the

pipe so as to prevent stress

concentration on the pipe.

(3) Each lead installed in a conduit

must be suitably insulated from the

conduit.

(4) Each bared test lead wire and

bared metallic area at point of

connection to the pipeline must be

coated with an electrical insulating

material compatible with the pipe

coating and the insulation on the wire.

§ 195.563 External corrosion control;

Additional cathodic protection

requirements.

(a) Each pipeline not subject to

§ 195.559 that has an effective external

surface coating material must be

cathodically protected. This

requirement does not apply to breakout

tank areas and buried pumping station

piping.

(b) For the purposes of this subpart,

a pipeline does not have an effective

external coating and shall be considered

bare if the current required to

cathodically protect it is substantially

the same as if it were bare.

§ 195.565 External corrosion control;

Examination of a buried pipeline when

exposed.

Whenever an operator has knowledge

that any portion of a buried pipeline is

exposed, the exposed portion must be

examined for evidence of external

corrosion, if the pipe is bare or if the

coating is deteriorated. If external

corrosion requiring remedial action

under § 195.583 is found, the operator

must investigate circumferentially and

longitudinally beyond the exposed

portion (by visual examination, indirect

method, or both) to determine whether

additional corrosion requiring remedial

action exists in the vicinity of the

exposed portion.

§ 195.567 External corrosion control;

Cathodic protection criteria.

Cathodic protection required by this

subpart must comply with one or more

of the applicable criteria and other

considerations for cathodic protection

contained in section 6 of NACE

Standard RP0169–96.

§ 195.569 External corrosion control;

Monitoring.

(a) Each operator must, at intervals

not exceeding 15 months, but at least

once each calendar year, conduct tests

on each buried, in contact with the

ground, or submerged pipeline facility

in its pipeline system that is under

cathodic protection to determine

whether the protection is adequate

under § 195.567.

(b) Each operator must, at intervals

not exceeding 21⁄2 months, but at least

six times each calendar year, inspect

each of its cathodic protection rectifiers.

(c) Each operator must, at intervals

not exceeding 5 years, reevaluate its

unprotected pipelines and cathodically

protect them in accordance with this

subpart in areas in which active

corrosion is found. The operator must

determine the areas of active corrosion

by electrical survey, or where an

electrical survey is impractical, by other

means that include review and analysis

of leak repair and inspection records,

corrosion monitoring records, exposed

pipe inspection records, and the

pipeline environment. In this section:

(1) Active corrosion means continuing

corrosion which, unless controlled,

could result in a condition that is

detrimental to public safety or the

environment.

(2) Electrical survey means a series of

closely spaced pipe-to-soil readings over

a pipeline that are subsequently

analyzed to identify locations where a

corrosive current is leaving the pipeline.

(3) Pipeline environment includes soil

resistivity (high or low), soil moisture

(wet or dry), soil contaminants that may

promote corrosive activity, and other

known conditions that could affect the

probability of active corrosion.

(d) Each reverse current switch, each

diode, and each interference bond

whose failure would jeopardize

structural protection must be

electrically checked for proper

performance six times each calendar

year, but with intervals not exceeding

21⁄2 months. Each other interference

bond must be checked at least once each

calendar year, but with intervals not

exceeding 15 months.

(e) For aboveground breakout tanks

where corrosion of the tank bottom is

controlled by a cathodic protection

system, the cathodic protection system

must be inspected to ensure it is

operated and maintained in accordance

with API Recommended Practice 651,

unless the operator notes in the

procedure manual (§ 195.402(c)) why

compliance with all or certain

provisions of API Recommended

Practice 651 is not necessary for the

safety of a particular breakout tank.

§ 195.571 External corrosion control;

Electrical isolation.

(a) Each buried or submerged pipeline

must be electrically isolated from other

metallic structures, unless the pipeline

and the other structures are electrically

interconnected and cathodically

protected as a single unit.

(b) One or more insulating devices

must be installed where electrical

isolation of a portion of a pipeline is

necessary to facilitate the application of

corrosion control.

(c) Inspection and electrical tests must

be made to assure that electrical

isolation is adequate.

(d) An insulating device may not be

installed in an area where a combustible

atmosphere is anticipated unless

precautions are taken to prevent arcing.

(e) Where a pipeline is located in

close proximity to electrical

transmission tower footings, ground

cables or counterpoise, or in other areas

where fault currents or unusual risk of

lightning may be anticipated, it must be

provided with protection against

damage due to fault currents or

lightning, and protective measures must

also be taken at insulating devices.

§ 195.573 External corrosion control; Test

stations.

Each operator must maintain the test

leads required for cathodic protection in

such a condition that electrical

measurements can be obtained to ensure

adequate protection.

76982 Federal Register / Vol. 65, No. 237 / Friday, December 8, 2000 / Proposed Rules

§ 195.575 External corrosion control;

Interference currents.

(a) Each operator whose pipeline

system is subjected to stray currents

must have a program to identify, test for,

and minimize the detrimental effects of

such currents.

(b) Each impressed current or galvanic

anode system must be designed and

installed to minimize any adverse

effects on existing adjacent metallic

structures.

§ 195.577 Internal corrosion control.

(a) No operator may transport any

hazardous liquid or carbon dioxide that

would corrode the pipe or other

components of its pipeline system,

unless it has investigated the corrosive

effect of the hazardous liquid or carbon

dioxide on the system and has taken

adequate steps to mitigate corrosion.

(b) If corrosion inhibitors are used to

mitigate internal corrosion the operator

must use inhibitors in sufficient

quantity to protect the entire part of the

system that the inhibitors are designed

to protect and shall also use coupons or

other monitoring equipment to

determine their effectiveness.

(c) The operator must, at intervals not

exceeding 71⁄2 months, but at least twice

each calendar year, examine coupons or

other types of monitoring equipment to

determine the effectiveness of the

inhibitors or the extent of any corrosion.

(d) Whenever pipe is removed from a

pipeline, the operator must inspect the

internal surface of the pipe for evidence

of corrosion. If internal corrosion

requiring remedial action under

§ 195.583 is found, the operator shall

investigate circumferentially and

longitudinally beyond the removed pipe

(by visual examination, indirect

method, or both) to determine whether

additional corrosion requiring remedial

action exists in the vicinity of the

removed pipe.

§ 195.579 Atmospheric corrosion control;

General.

Each pipeline or portion of pipeline

that is exposed to the atmosphere must

be cleaned and coated with a material

suitable for the prevention of

atmospheric corrosion. However, except

for portions of pipelines in offshore

splash zones and soil-to-air interfaces,

protection against atmospheric

corrosion is not required if the operator

demonstrates by test, investigation, or

experience that corrosion will be

limited to a light surface oxide or else

will not affect the safe operation of the

pipeline before the next scheduled

inspection.

§ 195.581 Atmospheric corrosion control;

Monitoring.

(a) Each operator must, at intervals

not exceeding 3 years for onshore

pipelines or 15 months, but at least once

each calendar year, for offshore

pipelines, inspect each pipeline or

portion of pipeline that is exposed to

the atmosphere for evidence of

atmospheric corrosion. Particular

attention must be given to pipe at soilto-air interfaces, under thermal

insulation, under disbonded coatings, at

pipe supports, in splash zones, at deck

penetrations, and in spans over water.

(b) If atmospheric corrosion is found,

the operator must provide protection

against atmospheric corrosion as

required by § 195.579.

§ 195.583 Remedial measures; General.

(a) Any pipe that is found to be

generally corroded so that the remaining

wall thickness is less than that required

for the maximum operating pressure of

the pipeline must be replaced. However,

generally corroded pipe need not be

replaced if—

(1) The operating pressure is reduced

to be commensurate with the strength of

the pipe, based on the actual remaining

wall thickness; or

(2) The pipe is repaired by a method

that reliable engineering tests and

analyses show can permanently restore

the serviceability of the pipe.

(b) If localized corrosion pitting is

found to exist to a degree where leakage

might result, the pipe must be replaced

or repaired, or the operating pressure

must be reduced commensurate with

the strength of the pipe based on the

actual remaining wall thickness in the

pits.

§ 195.585 Remedial Measures; Remaining

strength.

Under § 195.583, the strength of the

pipe based on actual remaining wall

thickness may be determined by the

procedure in ASME B31G Manual for

Determining the Remaining Strength of

Corroded Pipelines or by the procedure

developed by AGA/Battelle—A

Modified Criterion for Evaluating the

Remaining Strength of Corroded Pipe

(with RSTRENG disk). Application of

the procedure in the ASME B31G

manual or the AGA/Battelle Modified

Criterion is applicable to corroded

regions (not penetrating the pipe wall)

in existing steel pipelines in accordance

with limitations set out in the respective

procedures.

§ 195.587 Records.

(a) Each operator must maintain

current records or maps to show the

location of—

(1) Cathodically protected pipelines;

(2) Cathodic protection facilities and

galvanic anodes installed after [effective

date of final rule]; and

(3) Neighboring structures bonded to

cathodic protection systems. Records or

maps showing a stated number of

anodes, installed in a stated manner or

spacing, need not show specific

distances to each buried anode.

(b) Each operator must maintain a

record of each analysis, check,

demonstration, examination, inspection,

investigation, review, survey, and test

required by this subpart in sufficient

detail to demonstrate the adequacy of

corrosion control measures or that

corrosion requiring control measures

does not exist. These records must be

retained for at least 5 years, except that

records related to §§ 195.565, 195.569(a)

and (c), and 195.577(c) and (d) must be

retained for as long as the pipeline

remains in service.

Issued in Washington, DC on December 1,

2000.

Stacey L. Gerard,

Associate Administrator for Pipeline Safety.

[FR Doc. 00–31224 Filed 12–7–00; 8:45 am]

BILLING CODE 4910–60–P