66994 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations

DEPARTMENT OF TRANSPORTATION

Research and Special Programs

Administration

49 CFR Part 195

[Docket No. RSPA–97–2762; Amdt. 195–73]

RIN 2137–AD24

Controlling Corrosion on Hazardous

Liquid and Carbon Dioxide Pipelines

AGENCY: Research and Special Programs

Administration (RSPA), DOT.

ACTION: Final rule.

SUMMARY: This Final Rule makes

changes in some of the corrosion control

standards for hazardous liquid and

carbon dioxide pipelines. The 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 changes

are intended to improve the clarity and

effectiveness of the present standards,

and reduce the potential for pipeline

accidents due to corrosion.

DATES: This Final Rule takes effect

January 28, 2002. The incorporation by

reference of the publication listed in the

rule is approved by the Director of the

Federal Register January 28, 2002.

Compliance dates: Under

§ 195.563(c), operators of certain

effectively coated buried piping in

breakout tank areas or pump stations are

not required to cathodically protect that

piping until December 29, 2003. Under

§ 195.567(a), operators of cathodically

protected pipelines or pipeline

segments that lack test leads for external

corrosion control are not required to

install test leads until December 29,

2004. Under § 195.573(a)(2), operators

are not required to determine the

circumstances in which a close-interval

survey or comparable technology is

practicable and necessary until

December 29, 2003. Under § 195.573(b),

operators of unprotected pipe are not

required to reevaluate the need for

corrosion control on the pipe at least

every 3 years until December 29, 2003.

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:

Background

Corrosion causes a significant

proportion of hazardous liquid

pipelines accidents. Based on this

finding, we reviewed the corrosion

control standards in 49 CFR part 195 to

determine if the standards need to be

made clearer, more effective, or

consistent with acceptable safety

practices. We believe that improving the

standards will have the potential to

reduce the number of accidents caused

by corrosion.

The review began September 8, 1997,

when we held a public meeting in Oak

Brook, Illinois to discuss how 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).

We held the public meeting in

conjunction with meetings of National

Association of Corrosion Engineers

International (NACE), a professional

technical society dedicated to corrosion

control. 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 remain

generally unchanged.

Based on this conclusion, we began to

consider whether the more

comprehensive part 192 gas standards,

possibly with some changes, would be

appropriate for part 195’s hazardous

liquid and carbon dioxide pipelines. We

met then, from time to time, with

representatives of NACE, the pipeline

industry, and state pipeline safety

agencies for technical input. At these

meetings, we also examined whether the

part 192 standards need to be more

effective or clearer. The meetings raised

various concerns about the effectiveness

and clarity of some of the part 192

corrosion control standards and the

suitability of applying those standards

to hazardous liquid and carbon dioxide

pipelines. We also took into account

that the National Association of Pipeline

Safety Representatives, the Gas Piping

Technology Committee, and the

National Transportation Safety Board

had at various times recommended

changes to part 192 and part 195

corrosion control standards. So, to

gather public comment on our concerns

and the changes these organizations

recommended, we held another public

meeting on April 28, 1999, in San

Antonio, Texas, and invited the public

to submit written comments. The

comment period remained open until

June 30, 1999 (64 FR 16885; April 7,

1999).

Notice of Proposed Rulemaking

Sixty-two persons filed written

comments in response to the San

Antonio meeting notice. We then

summarized these comments in a notice

of proposed rulemaking (NPRM)

published last year (65 FR 76968; Dec.

8, 2000). The NPRM proposed to add to

part 195 a new subpart H called

Corrosion Control. Subpart H would

prescribe corrosion control standards for

all new and existing steel pipelines to

which part 195 applies. At this time, we

also decided to address the concerns,

recommendations, and comments that

pertain primarily to the corrosion

control standards in part 192 in a

separate notice of proposed rulemaking

on gas pipelines.

Although there was little support in

the record for allowing NACE Standard

RP0169–96, ‘‘Control of External

Corrosion on Underground or

Submerged Metallic Piping Systems,’’ to

serve as an alternative to standards

proposed in subpart H, we specifically

requested further comment on this issue

due to NACE’s standing in the field of

corrosion. Unfortunately, no one

commenting on the NPRM responded to

that request, perhaps because of earlier

discussions of the issue in Oak Brook

and San Antonio. While NACE urged us

to reference the entire NACE Standard,

not just section 6 as we proposed, NACE

did not assert that the NACE Standard

could serve as an acceptable alternative

to proposed subpart H.

The NPRM discussed each of the

standards proposed for inclusion in

subpart H. Many of these standards are

identical to present corrosion control

requirements in part 195, and many of

the standards are substantially like the

present requirements in part 192.

Proposed subpart H also includes

standards that, while based on present

part 192 requirements, include changes

which we think are beneficial

improvements.

Discussion of Comments

We received comments from the

following entities in response to the

NPRM: Alberta Energy Company (AEC),

City of Dallas Water Utilities, Enron

Transportation Services Company

(Enron), Environmental Defense,

Equilon Pipeline Company (Equilon),

L.A. ‘‘Roy’’ Bash, NACE, Phillips Pipe

Line Company (Phillips), State of Iowa

Utilities Board (Iowa), State of

Washington Utilities and Transportation

Commission (WUTC), and Tosco

Corporation (Tosco). Most commenters

supported the rulemaking, and all but

the City of Dallas recommended changes

to some of the proposed standards.

The City of Dallas related its

experience with a major pipeline spill

caused partly by corrosion. Gasoline

containing MTBE, a fuel oxygenate

which effects the taste and odor of

water, entered a lake resulting in a water

supply crisis. The City stated that it is

critical for DOT to adopt rules to require

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations 66995

1Paragraph 1.3 reads:

The provisions of this standard shall be applied

under the direction of competent persons who, by

reason of knowledge of the physical sciences and

the principles of engineering and mathematics,

required by education and related practical

experience, are qualified to engage in the practice

of corrosion control on buried or submerged

metallic piping systems. Such persons may be

registered professional engineers or persons

recognized as corrosion specialists or cathodic

protection specialists by NACE if their professional

activities include suitable experience in external

corrosion control of buried or submerged metallic

piping systems.

all pipelines, especially those

transporting gasoline with MTBE near a

municipal water resource, to be

regularly monitored for corrosion,

cracks, and leaks; and that any

deficiencies found, be timely repaired.

This rulemaking will accomplish

what the City of Dallas is seeking with

respect to corrosion. In particular,

§§ 195.573, 195.579, and 195.583 will

require operators to monitor pipelines

regularly for corrosion and correct any

deficiencies found in corrosion control.

Additionally, new § 195.585 specifies

corrective action for any harmful

corrosion found. The timeliness of

correcting corrosion control deficiencies

and harmful corrosion is covered by

existing §§ 195.401(b) and 195.452(h).

The requirement for operators to

patrol their pipelines regularly for signs

of failures is longstanding (§ 195.412(a)).

However, we recently broadened

requirements by publishing standards

on integrity management which will

require pipelines in or near highconsequence areas, such as drinking

water sources, to be internally inspected

or pressure tested at regular intervals for

corrosion, cracks, and other defects (65

FR 75377; Dec. 1, 2000). These new

standards currently apply to operators

with 500 or more miles of hazardous

liquid pipelines, and we have proposed

similar standards for the remaining

hazardous liquid operators subject to

part 195 (66 FR 15821; Mar. 21, 2001).

The following material, which is

organized by sections of final subpart H,

summarizes comments on the NPRM. In

addition, the material explains how we

treated the comments and other

considerations in developing final

subpart H. If a subsection is not

mentioned, no significant comments

were received on the corresponding

proposed rule and we are adopting the

proposed rule as final.

Section 195.551. This informational

section provides the content of subpart

H. Subpart H contains minimum

requirements for protecting steel

pipelines against corrosion.

In commenting on proposed

§ 195.551, Tosco suggested we replace

the term ‘‘steel’’ with ‘‘metallic’’ so

subpart H would apply to pipelines

made of any metal. Indeed, our

corrosion control standards for gas

pipelines apply to any metallic pipeline

(49 CFR 192.451(a)). However, in

contrast to gas pipelines, hazardous

liquid and carbon dioxide pipelines are

almost exclusively made of steel. For

this reason, many of the existing

standards in part 195, including

corrosion control standards, apply only

to steel pipelines. Our review of the

corrosion control standards did not

disclose a need to expand their coverage

to include pipelines made of metals

other than steel. In commenting on the

NPRM, no one, including Tosco,

presented information to explain why

the coverage should be expanded.

Nevertheless, operators are required to

provide us an opportunity to review the

safety of any pipeline that is to be

constructed with a material other than

steel (§ 195.8). In the case of a metallic

pipeline made from a material other

than steel, such as aluminum, our

review would include the operator’s

plan for corrosion control.

Section 195.553. This new section

was not in the NPRM. It provides

definitions of terms used in subpart H.

The definitions of ‘‘active corrosion,’’

‘‘electrical survey,’’ and ‘‘pipeline

environment,’’ proposed in § 195.569(c),

drew no adverse comment.

Additionally, final § 195.553 establishes

definitions of ‘‘buried’’ and ‘‘you.’’ The

definition of ‘‘buried’’ reflects the

common corrosion control practice of

treating any portion of pipe in contact

with the soil as if that portion were

buried. The term ‘‘you’’ has the same

meaning as ‘‘operator.’’

Section 195.555. This section, based

on proposed § 195.553, keeps in effect

the existing qualification standards in

§ 195.403(c) for corrosion control

supervisors. Under § 195.403(c), 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, to insure

compliance.

While Tosco and WUTC supported

the proposed rule, Phillips objected to

it. Phillips believed that part 195 should

include qualifications for supervisors of

all operation and maintenance

activities, not just corrosion control. In

the negotiated rulemaking on

qualification of pipeline personnel (64

FR 46866; Aug. 27, 1999), we removed

the requirements in § 195.403(c)

concerning qualifications of supervisors

of operations and maintenance

activities, effective October 28, 2002.

We did so based on the requirement

under subpart G of part 195, that on this

date, individuals performing regulated

operation and maintenance activities

must be fully qualified, thus lessening

the need to regulate the qualifications of

their supervisors. After revising

§ 195.403(c), our more specific review of

the corrosion control standards called

attention to the special role that

supervisors play in carrying out

corrosion control activities. As we

explained in the NPRM, individuals

qualified to do such activities as taking

electrical readings, usually hand the

data collected over to supervisors who

make critical decisions about corrosion

control adequacy and the need for

corrective action. None of the

commenters, including Phillips, argued

that corrosion control supervisors do

not need to have the qualifications

required by existing § 195.403(c). So

given the special role of corrosion

control supervisors and the apparent

acceptability of the existing supervisor

qualification requirements, we continue

to believe those requirements should

remain in effect after October 28, 2002.

This decision does not affect the

expiration on October 28, 2002, of

qualification requirements for

supervisors of other operation and

maintenance activities.

Equilon and NACE believed

qualifications for supervisors should be

no less rigorous than stated in paragraph

1.3 of NACE Standard RP0169–96.

These NACE provisions address the

need for corrosion control supervisors to

have a minimum level of technical

competency.1 In our corrosion control

review, we considered this NACE

provision as well as 49 CFR 192.453,

which provides that gas pipeline

corrosion control procedures must be

carried out by or under the direction of

a person qualified in corrosion control

methods. Also, in the San Antonio

meeting notice, we asked if more

specific standards are needed for

individuals who direct corrosion control

procedures. Everybody who responded

opposed changing § 192.453, and most

responders also opposed establishing

specific technical qualifications like

those in NACE Standard RP0169–96.

We expect that individuals who qualify

as a supervisor under proposed

§ 195.553, will have appropriate

technical training or experience in

corrosion control. Given that neither our

review, nor comments on the NPRM

disclosed anything in the pipeline

industry’s safety record to demonstrate

the need for more specific technical

qualifications, we did not adopt the

Equilon and NACE comment.

Sections 195.557, 195.559, and

195.561. These three standards on

66996 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations

external coating are based on proposed

§ 195.555 and 195.557. Collectively, the

standards require buried or submerged

pipelines to have external coating with

particular attributes, and require

operators to inspect pipe coating and

repair any damage. As stated in

proposed § 195.555, the standards are

limited to pipelines constructed,

relocated, replaced, or otherwise

changed after certain effective dates in

§ 195.401(c); and limited to certain

converted pipelines. In final § 195.557,

we have clarified that aboveground

breakout tank bottoms need not be

coated. We determined that such a

requirement is impractical and not a

customary corrosion control practice.

In the NPRM, we proposed in

§ 195.555 to limit the applicability of

proposed §§ 195.557 (external coating),

195.559 (cathodic protection), and

195.561 (test leads) to pipelines

constructed, replaced, relocated, or

otherwise changed after the applicable

effective date. We based proposed

§ 195.555, for the most part, on existing

§ 195.200, titled Scope, which similarly

limits the applicability of corresponding

existing §§ 195.238, 195.242, and

195.244. However, we inadvertently

omitted from § 195.555 the pipe

movement exception included in

§ 195.200. In this Final Rule, the

substance of proposed § 195.555

regarding external coating and cathodic

protection is in § 195.557(a), which does

include the omitted exception for pipe

movement. We addressed the proposed

limit on test leads differently, as

discussed below under the heading,

section 195.567.

Tosco believes it would be helpful to

include in subpart H the past effective

dates cross-referenced in proposed

§ 195.555. Tosco believes the dates are

not widely known. We did not adopt

this comment because the dates are

already stated in § 195.401(c) for

purposes of indicating the applicability

of standards in addition to corrosion

control standards, and we do not want

to create an unnecessary redundancy in

part 195.

Final § 195.557 specifies which

pipelines must have external coating.

Rather than cross-referencing § 195.5(b)

to indicate which converted pipelines

must have coating, we transferred to

final § 195.557 the coating aspect of

§ 195.5(b). We transferred the cathodic

protection aspect to final § 195.563(b);

and the test lead aspect is covered by

§ 195.567.

Equilon and NACE suggested we

establish an additional standard to

minimize damage to coating when

operators install pipe by boring, driving,

directional drilling, or any similar

method. Final § 195.559(d) requires

external coating to have enough strength

to resist damage due to handling and

soil stress. We believe this standard is

broad enough to cover the potential pipe

installation problems raised by these

commenters.

Phillips advised against requiring the

installation of coating on older existing

bare or ineffectively coated pipelines.

We believe Phillips may be referencing

existing hazardous liquid pipelines

constructed before the applicable

effective dates stated in § 195.401(c).

These pipelines are not subsequently

replaced, relocated, or otherwise

changed. Final § 195.557 does not

require these older pipelines to be

coated.

Tosco suggested that § 195.557 should

include the dates for which pipelines

must have external coating. The final

rule accomplishes this objective by

cross-referencing § 195.401(c). Restating

the dates listed in § 195.401(c) would be

unnecessarily redundant since the dates

are in § 195.401(c) for purposes other

than corrosion control.

Section 195.563. Final § 195.563

combines cathodic protection

requirements proposed in §§ 195.555,

195.559, and 195.563. It also crossreferences final § 195.573(b), which

requires cathodic protection of

unprotected pipe found to have active

corrosion. As a result, all pipelines that

must have cathodic protection under

subpart H are identified in a single

section.

Final § 195.563(a), which is based on

proposed §§ 195.559(a) and (b), requires

cathodic protection on each pipeline

that must have an external coating

under § 195.557(a). The cross-reference

to § 195.557(a) limits the cathodic

protection requirement to those

pipelines constructed, relocated,

replaced, or otherwise changed after

certain dates, as proposed under

§ 195.555. Section 195.563(a) does not

contain the second sentence of proposed

§ 195.559(a) which would require

operators to have a test procedure to

determine whether adequate cathodic

protection was achieved. We now

believe this sentence is redundant due

to the routine monitoring conducted to

determine the adequacy of cathodic

protection, required by final

§ 195.573(a). Also, amended

§ 195.402(c)(3) requires operators to

have procedures to carry out

§ 195.573(a). Although proposed

§ 195.559(b) only referred to completion

of construction as the beginning of the

period during which cathodic

protection must be installed, final

§ 195.563(a) reflects the broader

applicability indicated by proposed

§ 195.555.

We proposed in § 195.559(a), which

was based on existing § 195.242(a), a

requirement that operators install

cathodic protection systems on all

buried or submerged pipelines ‘‘to

mitigate corrosion that might result in

structural failure.’’ Equilon and NACE

suggested this proposed rule would be

clearer if we replaced ‘‘structural

failure’’ with ‘‘structural failure or

penetration of pipe or tank wall.’’ In

light of their comment, we believe the

phrase, ‘‘to mitigate corrosion that might

result in structural failure,’’ creates

confusion. It could be interpreted to

require protection only against severe

external corrosion. Moreover, since it is

clear that existing § 195.242(a) requires

cathodic protection against all external

corrosion, the phrase seems

superfluous. Therefore, we did not use

it in final § 195.563(a).

Equilon and NACE also commented

on the § 195.559(b) proposed

requirement that a cathodic protection

system be installed not later than 1 year

after completing construction. They

believe cathodic protection should be in

effective operation at the end of 1 year,

to guard against significant corrosion

that could be caused by stray currents

or galvanic long-line currents. We

believe effective operation is implicit in

the existing and proposed standards on

installation of cathodic protection.

Nevertheless, to avoid confusion on this

point, in final § 195.563(a) we replaced

‘‘installed’’ with ‘‘in operation.’’ This

change is consistent with the

comparable standard for gas pipelines in

§ 192.455(a)(2). Under final § 195.571,

when the cathodic protection system is

placed in operation, it would have to

comply with one or more of the

applicable criteria and other

considerations for cathodic protection

contained in paragraphs 6.2 and 6.3 of

NACE Standard RP0169–96. Subsequent

electrical tests and other steps required

by final § 195.573(a) will assure that

adequate protection is maintained.

WUTC raised the concern that under

proposed § 195.559(b) corrosion could

go uncontrolled on some facilities for up

to 2 years. Based on a Washington State

administrative rule, WUTC

recommended that § 195.559(b) require

that facilities be cathodically protected

within 90 days after they are buried or

submerged. We did not propose to

change the currently required time limit

(1 year after completing construction)

because our review of the corrosion

control standards and the comments

from the San Antonio meeting did not

indicate any need to reduce the

installation time limit. After considering

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations 66997

WUTC’s comment, we still believe 1

year after construction is acceptable as

a generally applicable time limit

considering that soil conditions may

need time to stabilize in order to

support cathodic protection.

Final § 195.563(b) requires cathodic

protection on certain converted

pipelines. This requirement does not

differ substantively from the cathodic

protection aspect of the corrosion

control requirement of § 195.5(b).

Therefore, we are modifying § 195.5(b)

to cross-reference the new subpart H

standards.

Under final § 195.563(c), which is

based on proposed § 195.563, all buried

or submerged pipelines, that have an

effective external coating must have

cathodic protection. This requirement

does not apply to breakout tanks. This

requirement is substantially the same as

existing § 195.414(a), which requires

that all effectively coated pipelines must

be cathodically protected, except for

breakout tank areas and buried pumping

station piping.

However, Equilon and NACE each

stated it saw no need to except buried

piping in breakout tank areas and

pumping stations from the requirement

to cathodically protect effectively coated

pipelines. We agree that the exception

seems to lack a sound safety basis. For

example, NACE Standard RP0169–96

does not have a similar exception from

cathodic protection. Also, we believe it

is now common practice in the

hazardous liquid pipeline industry to

cathodically protect effectively coated

buried piping in breakout tank areas and

pump stations. So, in view of the

Equilon and NACE comments, and our

further consideration, we decided to

terminate the exception for buried

piping in breakout tank areas and

pumping stations. Therefore, the final

rule keeps the exception in effect only

until December 29, 2003. This period

will give operators time to install

cathodic protection on any effectively

coated piping in breakout tank areas and

pumping stations where it is not already

installed. Also, since no one commented

on application of the proposed rule to

the bottoms of breakout tanks and there

may not be many older breakout tanks

that have effectively coated bottoms, the

final rule does not change the present

exception for breakout tank bottoms.

Initially, we did not propose

regulations similar to §§ 195.414(b) and

(c), which require cathodic protection in

areas of active corrosion found through

electrical inspections previously

required on bare pipelines, breakout

tank areas, and buried pumping station

piping. We reasoned that §§ 195.414(b)

and (c) are no longer necessary because

the inspection deadlines had expired.

However, we now recognize that the

cathodic protection provisions of

§§ 195.414(b) and (c) are continuing

requirements, and so we included them

in subpart H as final § 195.563(d).

Section 195.565. This section,

concerning the installation of cathodic

protection on breakout tanks, is the

same as proposed § 195.559(c). There

were no comments on proposed

§ 195.559(c).

Section 195.567. In this section

concerning test leads, paragraphs (a)

and (b) are based on proposed § 195.561

and existing § 195.244. The existing test

lead standards in § 195.244 apply to

onshore pipelines constructed, replaced,

relocated, or otherwise changed after

certain past dates; and to onshore

converted pipelines if required by

§ 195.5(b). The NPRM did not propose

to vary this application. However, upon

further consideration of the importance

of test leads in determining the

adequacy of cathodic protection, we are

applying final § 195.567 to all onshore

pipelines that must have cathodic

protection under subpart H. This

increased coverage will affect pipelines

or segments of pipelines that must have

cathodic protection under existing

§§ 195.414 and 195.416(d) (i.e.,

effectively coated pipelines and places

on bare pipelines, breakout tank areas,

and pumping station piping where

active corrosion is found through

electrical inspection). The increased

coverage will also affect converted

pipelines that were not substantially in

compliance with existing § 195.244

when placed in service, as § 195.5(b)

now permits. To ease the burden of

compliance on existing cathodically

protected pipelines or pipeline

segments on which test leads are not

now required by existing § 195.244 or

§ 195.5(b), final § 195.567(a) allows

operators 3 years to identify these

pipelines or pipeline segments and

install test leads as necessary to meet

§ 195.567(b). On existing unprotected

pipelines, any newly identified segment

that must have cathodic protection as a

result of an electrical survey under final

§ 195.573(b), must have test leads in

time to carry out the annual monitoring

test under final § 195.573(a).

Final § 195.567 is consistent with

acceptable practices. The practices

recommended for test leads in NACE

Standard RP0169–96 and in ASME

B31.4 are not limited to new, relocated

or replaced pipelines. Also, our gas

pipeline regulations in 49 CFR 192.469

and 192.471 for test stations and test

leads, apply to all gas pipelines that

must be cathodically protected under 49

CFR part 192. Moreover, existing

§ 195.416(a) requires annual testing of

each cathodically protected pipeline to

determine the adequacy of cathodic

protection; and operators normally

comply with this requirement by

obtaining electrical measurements

through test leads. So we believe

§ 195.567 will have only a minimal

impact on hazardous liquid pipeline

companies.

Based on existing § 195.244(b)(1), we

proposed in § 195.561(b)(1) that

operators install test leads with enough

looping or slack to prevent the leads

from being unduly stressed or broken

during backfilling. Equilon and NACE

suggested that to assure test lead wires

remain effective, we should add the

phrase ‘‘to remain mechanically secure

and electrically conductive.’’ We believe

the objective of this phrase is within the

purpose of the existing rule, and

therefore, added the phrase to final

§ 195.567(b)(2) for emphasis.

The long term integrity of test leads is

also covered by final § 195.567(c). Based

on proposed § 195.573, this standard

requires maintenance of test leads.

There were no comments on the

proposed rule, however we edited the

final rule for clarity.

Equilon and NACE also commented

on testing cathodic protection of

offshore pipelines. They contended that

test lead readings at platforms or at

shore locations may be of little benefit

in determining the adequacy of cathodic

protection of offshore pipelines. As an

alternative to such readings, they

suggested we require operators to

analyze or inspect each cathodic

protection system before the end of its

design life. In our experience, test leads

for offshore pipelines normally are

installed only on platforms or on shore

because of the difficulty of accessing

leads at underwater locations. For this

reason, § 195.567 does not apply to

buried or submerged portions of

offshore pipelines. Since pipeline

corrosion in an offshore environment

generally occurs at a uniform rate, we

believe readings taken by operators at

offshore platforms or on shore are used

satisfactorily to determine the adequacy

of protection over the entire pipeline.

Moreover, this test method is acceptable

for offshore gas pipelines under

paragraph A862.15 of the ASME B31.8

Code. Because there is no information to

support the need to require the use of

an alternative testing method, we chose

not to take action on the commenters’

suggestion.

WUTC commented that because the

proposed standard does not prescribe

the number or precise location of test

leads, government inspectors may

disagree with operators over whether

66998 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations

test readings are sufficient to determine

the adequacy of cathodic protection. To

ameliorate this situation, WUTC

suggested that we require operators to

conduct close-interval electrical surveys

every 5 years. Although final § 195.567

does not specify the number or precise

location of test leads, it does provide a

performance standard for the location of

test leads. Under § 195.567(b)(1) test

leads must be installed at sufficiently

frequent intervals to obtain electrical

measurements indicating the adequacy

of cathodic protection. Section 4.5 of

NACE Standard RP0169–96, which lists

many customary test lead locations, may

be used as a guide to comply with

§ 195.567(b)(1). Additionally, the final

rule on monitoring external corrosion

control, § 195.573, will require operators

to use close-interval surveys in some

situations and install additional test

leads where warranted.

Section 195.569. This section, which

is based on proposed § 195.565,

provides that whenever an operator

learns that any portion of a buried

pipeline is exposed, the exposed portion

must be examined for external corrosion

if the pipe is bare or has deteriorated

coating. Further, if external corrosion

requiring remedial action is found, the

operator must investigate pipe in the

vicinity of the exposed portion (by

visual examination, indirect method, or

both) to determine if there is any

additional external corrosion requiring

remedial action.

Phillips requested more flexibility in

the proposed requirement to look for

additional corrosion. Phillips

commented that the extent of further

investigation should depend on the type

of corrosion found and whether the

corrosion could be expected to extend

beyond the exposed segment. We do not

believe there is a clear understanding of

the relationship between the type of

corrosion and the likelihood of finding

similar corrosion in the vicinity of the

exposed pipe to justify limits on the

requirement for additional investigation.

Pipe and soil conditions are generally

too variable to make such predictions

with accuracy. Therefore, we did not

adopt Phillips’ comment.

WUTC believed subpart H should

include additional requirements for

operators to do more to determine the

condition of coating than just visually

examine it whenever pipelines are

exposed. WUTC stated that the

standards should require operators to

conduct surveys to identify areas with

coating defects and take remedial

measures such as re-coating the

pipeline. Although the final rules do not

specifically require pipe coating

surveys, operators must conduct

electrical tests periodically to determine

the adequacy of corrosion control on

their buried pipelines. Low cathodic

protection potential readings obtained

during these tests often are a sign of

coating defects. So, in areas with low

potential readings, many operators

supplement cathodic protection tests

with coating surveys to help them

identify places where the pipeline must

be excavated to look for corrosion cells

or to determine where additional

cathodic protection must be applied.

The need to mandate the use of coating

surveys in addition to electrical tests for

corrosion, was not evident from our

review of the regulations.

Section 195.571. This standard,

proposed as § 195.567, incorporates by

reference the criteria and other

considerations in section 6 of NACE

Standard RP0169–96, as standards for

the adequacy of cathodic protection.

Environmental Defense and Iowa

argued that because cathodic protection

criteria are fundamental to safety, the

criteria should be stated in part 195

rather than incorporated by reference.

Iowa believed that acquiring and

maintaining a separate document is

arbitrary and unnecessarily

burdensome. In considering these

comments, we reviewed OMB Circular

A119 and the National Technology

Transfer and Advancement Act of 1995.

Both documents direct Federal agencies

to use consensus standards where

practical to meet their policy objectives

rather than develop government-unique

standards. We also reviewed the rules of

the Federal Register on incorporation

by reference. In light of these Federal

policies, we think it is appropriate for

us to incorporate the NACE criteria and

other considerations by reference, as

proposed.

Enron, Environmental Defense, and L.

A. (Roy) Bash urged us to adopt the

criteria in Appendix D of part 192

instead of the NACE criteria. Enron

commented that many operators are

successfully using Appendix D for

hazardous liquid pipelines; and

Environmental Defense viewed

Appendix D as more specific and

therefore more enforceable. Roy Bash

submitted technical documentation in

support of two Appendix D criteria, 300

mV shift and E-log-I. In the NPRM we

discussed our reluctance to propose

Appendix D as the new standard for

hazardous liquid pipelines because the

Appendix D 300 mV shift and E-log-I

criteria are not incorporated in the

NACE Standard. Furthermore, we

explained that under paragraph 6.2.1 of

the NACE Standard, operators may use

any criteria which they can demonstrate

achieves corrosion control comparable

to section 6 criteria. Also, operators may

continue to use criteria which they have

successfully applied to existing

pipelines, on these pipelines. While this

provision may satisfy Enron, and should

satisfy Roy Bash’s concern about the

continued use of the 300 mV shift and

E-log-I criteria, the lack of specificity in

paragraph 6.2.1 may be indicative of

Environmental Defense’s concern. Yet,

we do not believe the performance

wording of paragraph 6.2.1 alone is

sufficient reason not to reference section

6 of the NACE Standard. On the

contrary, we generally favor

performance standards over

specification standards because they

encourage operators to develop and

apply better alternatives. If however, an

operator chooses to use alternative

criteria, we will carefully examine the

operator’s rationale for determination

that the criteria met the ‘‘comparable to’’

or ‘‘successfully applied’’ tests of

paragraph 6.2.1 of the NACE Standard.

WUTC was concerned that the criteria

in section 6 of the NACE Standard

would not be mandatory because

paragraph 6.1.1 refers to paragraph 1.2,

which states that the Standard is a

guide; and also refers to paragraph 1.4,

which allows deviations from the

Standard. Proposed § 195.567 refers

solely to the criteria and other

consideration provisions of section 6,

which are contained in paragraphs 6.2

and 6.3 of the NACE Standard. We did

not intend to allow operators to treat

section 6 as a guide or to deviate from

the criteria and other considerations in

section 6. Therefore, the final rule refers

to paragraphs 6.2 and 6.3, instead of

section 6.

WUTC was also concerned about

special conditions, such as elevated

temperatures, disbonded coatings,

thermal insulating coatings, shielding,

bacterial attack, and unusual

contaminants in the electrolyte, which

may cause cathodic protection to be

ineffective. WUTC believed the rules on

coating and cathodic protection should

address these special conditions. The

theory behind final § 195.571 is that if

all external surfaces of a pipeline are

cathodically protected according to the

criteria and other considerations in

paragraphs 6.2 and 6.3 of the NACE

Standard, external corrosion will be

controlled successfully. In practice, if an

operator learns though in-line

inspection or other means that because

of a special condition external corrosion

is not being controlled successfully, the

operator must take corrective action.

The operator could either remedy the

condition or adjust the cathodic

protection system to assure the

adequacy of cathodic protection in the

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations 66999

2Paragraph 10.1.1.3 reads: Where practicable and

determined necessary by sound engineering

practice, a detailed (close-interval) potential survey

should be conducted to (a) assess the effectiveness

of the cathodic protection system; (b) provide base

line operating data; (c) locate areas of inadequate

protection levels; (d) identify locations likely to be

adversely affected by construction, stray currents,

or other unusual environmental conditions; or (e)

select areas to be monitored periodically.

area of the special condition. We believe

this requirement is implicit in final

§ 195.571. Section 195.573(e) also

would require corrective action if the

condition is detected by monitoring

under § 195.573.

In addition, WUTC was concerned

that the proposed rules did not specify

how long the cathodic protection

current may be shut off when measuring

polarization decay under the minimum

100 mV criterion. WUTC suggested that

the limit be no more than 48 hours,

unless a recording chart shows

continuing significant decay beyond

that time. To satisfy the100 mV criterion

by the decay method, operators must

determine that a negative polarization

voltage shift of at least 100 mV occurs

after the immediate voltage shift caused

by shutting off the cathodic protection

current. Whether this minimum

negative voltage shift occurs in minutes

or hours after the current is cut off, it

is irrelevant to satisfying the criterion.

We recognize that the longer the current

remains off, the greater the opportunity

for the pipeline to corrode. However, in

our experience decay tests have not

posed a serious problem in this regard

to warrant establishing a time limit.

Finally, WUTC opposed use of the net

protective current criterion on bare or

ineffectively coated hazardous liquid

pipelines. WUTC was concerned about

the criterion being applied only at

predetermined current discharge points

identified through leaks, leak history, or

electrical surveys, preventing the

pipeline from having complete cathodic

protection against corrosion leaks.

WUTC suggested that if we allow use of

the criterion, we limit its use to

pipelines constructed before part 195

went into effect. According to part 195’s

terms, the net protective current

criterion applies only to bare or

ineffectively coated pipelines. Because

all pipelines subject to part 195

construction standards must be

effectively coated, the net protective

current criterion will mostly be used on

older pipelines constructed before those

standards took effect. The effective dates

for different groups of pipelines are

stated in § 195.401(c).

WUTC’s primary concern seems to be

that we did not propose a requirement

that operators fully cathodically protect

bare or ineffectively coated pipelines.

We did not propose such action for

several practical reasons. To

cathodically protect these pipelines over

their entire surface area without first

coating or recoating them would require

very high levels of impressed currents.

Cathodic protection systems producing

such high current levels would be costly

to install, maintain, and operate. Also,

to coat all bare or ineffectively coated

buried pipelines in order to facilitate

cathodic protection could be a costly

endeavor. We also considered the

possibility that raising pipe sections to

coat them would likely create

unanticipated stresses and disturb pipe

foundations, introducing new risk

factors not present in the existing

pipelines.

Section 195.573. This section is based

on proposed § 195.569. It requires

operators to monitor the performance of

cathodic protection facilities and

monitor unprotected pipe for active

corrosion.

Final § 195.573(a) enhances proposed

§ 195.569 with regard to determinations

of the adequacy of cathodic protection.

We edited § 195.573(a) to clearly state

that operators must conduct tests to

determine whether cathodic protection

complies with § 195.571 and not

whether cathodic protection is

adequate, as proposed. In addition, we

are concerned that proposed § 195.569

does not provide latitude in monitoring

separately protected short segments of

bare or ineffectively coated pipelines, as

does the corresponding rule for

monitoring protected gas pipelines (49

CFR 192.465(a)). The gas rule allows

monitoring of short protected segments

over a 10-year period where annual

monitoring is impractical. We

considered adding a similar provision to

§ 195.573(a) but decided that the 10-year

period would add more latitude than

circumstances warrant on bare or

ineffectively coated hazardous liquid

pipelines. Many operators now monitor

short protected segments of bare or

ineffectively coated lines on the same

cycle as adjoining unprotected

segments. So, rather than use the gas

rule provision, we added a provision

that allows monitoring at 3-year

intervals which is consistent with the

monitoring cycle we are adopting for

unprotected sections (see discussion of

§ 195.573(b) below).

We also addressed the problem of

how to test pipelines to determine the

adequacy of cathodic protection. In

complying with existing § 195.416(a),

which was the basis of proposed

§ 195.569, operators generally

conducted electrical surveys. This

action involves measuring potentials at

pre-established test stations, to

determine the adequacy of cathodic

protection. In practice, however, this

method of compliance has not always

been sufficient to assure protection of

all pipeline surfaces. Corrosion

problems often arise in areas between

test stations where there may be

interference currents, different

environmental conditions, damaged

coatings, or malfunctioning anodes. So,

in order to check on cathodic protection

adequacy in greater detail, many

operators augment test station data with

periodic close-interval electrical surveys

or use newer technologies. As WUTC

pointed out in its comments, these more

detailed surveys also help operators

determine if additional test stations are

needed to assure the adequacy of

cathodic protection.

Paragraph 10.1.1.3 of NACE Standard

RP0169–96 recommends that operators

use close-interval surveys where they

are practicable and sound engineering

judgment indicates they are necessary.2

For this reason and because we believe

the general method of monitoring

cathodic protection at established test

stations may not always be sufficient,

we have referenced the NACE provision

in final § 195.573(a)(2). Although the

final rule does not prescribe a frequency

of close-interval surveys, operators will

have to describe in their maintenance

procedures the circumstances in which

a close-interval survey or comparable

technology is practicable and necessary

to accomplish the objectives of

paragraph 10.1.1.3 of the NACE

Standard, and then follow those

procedures.

In order to provide operators with

time to prepare for compliance with the

new close-interval survey requirement,

the compliance date for existing

pipelines will not be mandatory until

December 29, 2003.

Final § 195.573(b), which is based on

proposed § 195.569(c), requires that

operators must reevaluate their

unprotected pipe and cathodically

protect the pipe where active corrosion

is found. Operators must determine if

active corrosion exists by electrical

survey where practical, or otherwise by

a review and analysis of certain

maintenance records and the pipeline

environment. Proposed definitions of

the terms ‘‘active corrosion,’’ ‘‘electrical

survey,’’ and ‘‘pipeline environment’’

are combined with other definitions in

final § 195.553. Also, final § 195.573(b)

applies to ‘‘pipe’’ rather than

‘‘pipelines’’ as proposed, because we

did not intend for the proposed rule to

apply to unprotected breakout tank

bottoms. Integrity inspection of the

bottoms of breakout tanks is covered by

existing § 195.432.

67000 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations

Equilon, Environmental Defense, and

NACE argued that because unprotected

pipelines may deteriorate as they age,

operators should reevaluate these

pipelines at intervals of less than 5

years, the maximum interval proposed

in the NPRM. They suggested that to be

consistent with part 192 we set the

maximum interval at 3 years, not to

exceed 39 months. Like these

commenters, Iowa also saw a need to

add 3 months to the maximum interval,

whether it be 5 or 3 years, to provide

scheduling and operational flexibility.

In view of the three comments

favoring a 3-year inspection interval and

the Technical Hazardous Liquid

Pipeline Safety Standards Committee’s

unanimous recommendation to

establish a maximum 3-year interval

(see the Advisory Committee

Consideration heading below), we

reconsidered whether the appropriate

maximum inspection interval should be

3 or 5 years. We considered the fact that

the relation between relevant risk

factors on unprotected pipelines and an

appropriate inspection interval is

uncertain. As discussed in the NPRM,

we are also seeking to make the

corrosion control standards for gas and

hazardous liquid pipelines consistent

wherever reasonable. At present part

192 prescribes a maximum inspection

interval of 3 years for unprotected gas

pipelines; and part 195 prescribes 5

years. Although there is no evidence in

the record to demonstrate conclusively

the advantage of a 3-year interval over

a 5-year interval, taking into

consideration the risk to the public and

environment, we believe the more

conservative 3-year interval is the

prudent choice. Furthermore, we

believe this choice is reasonable based

on our enforcement experience, as well

as, discussions with industry

representatives which indicate that

many hazardous liquid pipeline

operators inspect their unprotected

pipelines every 3 years. Therefore, the

final rule is changed from the proposed

maximum 5-year interval to a maximum

3-year interval.

In order to provide operators with

time to prepare for compliance with the

new 3-year inspection interval,

compliance will not be mandatory until

December 29, 2003.

Equilon and NACE suggested that inline inspection may be a more

appropriate alternative to electrical

survey than analysis of leak repairs and

other matters as proposed in

§ 195.569(c). However, the proposed

rule did not limit an operator’s choice

of alternatives to an analysis of leak

repairs. Rather, where electrical surveys

are impractical, we proposed the use of

any alternative means of determining

whether active corrosion exists, as long

as that means includes a review and

analysis of leak repair and inspection

records, corrosion monitoring records,

exposed pipe inspection records, and

the pipeline environment. Under the

final rule, if operators have in-line

inspection data and want to use it as an

alternative to electrical surveys where

such surveys are impractical, they may

do so provided they interpret the data

in light of the required review and

analysis of other pertinent information.

WUTC suggested we put the following

sentence in the final rule: ‘‘Each

operator shall take prompt remedial

action to correct any deficiencies

indicated by the monitoring.’’ We

discussed in the NPRM why we did not

propose such a requirement. We stated

that it is unnecessary to direct such

action due to the existing requirements

under § 195.401(b). This section

requires operators to correct within a

reasonable time any condition that

could adversely affect safe operation of

a pipeline system; and if an immediate

hazard exists, to cease operating the

affected part of the system until the

condition is corrected. In addition, on

pipelines that could affect high

consequence areas, new § 195.452(h)

requires operators to take prompt

actions to address integrity issues and to

repair certain conditions within specific

time limits. However, in light of

WUTC’s comment, we established

§ 195.573(e) to draw attention to the

remedial action required by existing

§§ 195.401(b) and 195.452(h).

WUTC also was concerned that the

discretion built into the proposed

definition of ‘‘active corrosion’’ would

allow operators to ignore corrosion leaks

detrimental to public safety or the

environment. WUTC suggested we

require operators to classify and

schedule all corrosion leaks for repair.

In response, we believe the purpose of

proposed § 195.569(c) is to require

operators to look for and cathodically

protect certain areas of corrosion before

leaks occur. Operator response to leaks,

whether due to corrosion or other

causes, is not covered by new subpart H.

Leak response is governed by existing

§ 195.401(b) or § 195.452(h), which

together require timely corrective action

for all unsafe conditions on pipelines

subject to Part 195.

Section 195.575. This standard

requires electrical isolation to provide

for adequate cathodic protection. The

standard is based on proposed

§ 195.571.

Enron expressed support for the

proposed rule; however, Tosco believed

we should specify the frequency of

inspection and electrical tests.

We did not adopt Tosco’s comment

because the purpose of the proposed

inspection and electrical tests is to

ensure that electrical isolation is

adequate when it is installed. All postinstallation inspections and tests of

cathodic protection facilities are

covered by final § 195.573.

In final paragraph (d), for clarity, we

changed the proposed wording ‘‘where

a combustible atmosphere is

anticipated’’ to read ‘‘where a

combustible atmosphere is reasonable to

foresee.’’ Similarly in paragraph (e), we

changed the proposed ‘‘where fault

currents or unusual risk of lightning

may be anticipated’’ to read ‘‘where it is

reasonable to foresee fault currents or an

unusual risk of lightning.’’

Section 195.577. The purpose of this

standard, which is based on proposed

§ 195.575, is to minimize the adverse

effects of stray currents on pipelines and

the effects of impressed currents on

adjacent structures. Expressing support

for the proposed rule, Tosco stated that

the proposed program to identify, test

for, and minimize the detrimental

effects of stray currents may result in

operators participating in corrosion

coordinating groups. We agree that such

coordination may be necessary for an

effective program.

Section 195.579. This standard,

proposed as § 195.577, requires

operators to investigate the effects of

transporting hazardous liquid or carbon

dioxide which could corrode the

pipeline, and take adequate steps to

mitigate corrosion. Tosco suggested that

in the final rule we clarify that the

investigation may be done by review of

operating history. A review of relevant

operating history may be a satisfactory

investigation in some situations.

However, we did not explicitly include

this option in final § 195.579. We used

the proposed wording because we think

it is broad enough to permit operators to

use any method of investigation that

will provide a sound basis for deciding

how to mitigate internal corrosion

adequately.

Under proposed § 195.577(d), if

operators discover harmful corrosion

inside removed pipe, they must

investigate further to determine if

additional harmful corrosion exists in

the vicinity of the removed pipe.

Phillips suggested that the extent of

further investigation should depend

upon the type of corrosion found and

whether that corrosion could be

expected to extend beyond the exposed

segment. We do not believe there is a

clear understanding of the relationship

between the type of corrosion and the

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations 67001

likelihood of finding similar corrosion

in the vicinity of removed pipe to justify

limits on a requirement for additional

investigation. The effect of corrosive

liquids on pipe may be too variable to

make such predictions with accuracy.

Therefore, we did not adopt Phillips’

comment.

Section 195.581. This section, based

on proposed § 195.579, modifies an

existing requirement (§ 195.416(i)) that

all pipelines exposed to the atmosphere

must be protected against atmospheric

corrosion by a suitable coating. Final

§ 195.581 gives operators flexibility

when deciding to coat pipelines where

atmospheric corrosion will be limited to

a light surface oxide, or will not affect

the safe operation of the pipeline before

the next scheduled inspection. Splash

zones of offshore pipelines and soil-toair interfaces of onshore pipelines are

omitted from this exception.

Iowa opposed allowing pipe with

metal loss to remain unprotected or

unrepaired. Iowa stated that public

safety should not depend on an

operator’s judgment of whether a

corroding pipe will not fail before the

next inspection (which could be up to

3 years). Yet under the proposed rule, if

an operator chose not to coat, it would

have to show that testing, investigation,

or experience supports the decision. In

other words, safety would not depend

solely on an operator’s judgment. Also,

the need for coating would be reviewed

again in 3 years. A 3-year delay in

coating a pipeline judged to be safe

should not jeopardize public safety,

considering that atmospheric corrosion

generally progresses at a slow rate.

Therefore, we did not adopt Iowa’s

comment. Nevertheless, mindful of

Iowa’s concern, we edited the final

wording to clarify that any decision not

to coat a particular pipeline must be

supported by testing, investigation, or

experience relevant to that pipeline.

Tosco called the proposed rule ‘‘a

positive revision.’’ However, Enron

recommended that we add ‘‘active’’ as a

descriptor of ‘‘atmospheric corrosion.’’

It believed the term ‘‘active atmospheric

corrosion’’ would clarify that the rule

does not apply to harmless corrosion.

We did not adopt Enron’s comment

because we think the proposed

exceptions will satisfy Enron’s

objective. Also, ‘‘active atmospheric

corrosion’’ is a term that may not be in

general use in the industry.

Section 195.583. Under this section,

proposed as § 195.581, operators must

periodically inspect exposed pipelines

for atmospheric corrosion, giving

particular attention to areas such as soilto-air interfaces. Onshore pipelines

must be inspected every 3 years; and

offshore pipelines every year. If any

inspection reveals atmospheric

corrosion, the operator must protect the

pipeline against atmospheric corrosion

in accordance with § 195.581.

Enron, Equilon, Iowa, and NACE

advocated adding a 3 months grace

period to the maximum 3-year

inspection interval. We agree that this

period is useful to allow operators

scheduling and operational flexibility,

and included it in final § 195.583.

Tosco wanted to make certain that the

proposed remedial action would not be

required for light surface oxide. By the

cross reference to § 195.581, final

§ 195.583 allows operators latitude

when deciding to coat pipelines which

exhibit only a light surface oxide.

AEC urged us to allow operators to

use means of assessment other than

periodic visual inspection. As an

example, AEC commented that by using

in-line inspection and a corrosion

growth model, operators could predict

when a pipeline should be reinspected

or repaired. This approach, according to

AEC, would enable operators to allocate

resources for maximum benefits instead

of periodically scattering them across

entire systems. AEC’s comment

indicates two things: first, AEC

apparently misunderstood the proposed

rule to mandate visual inspection; and

second, AEC would like operators

themselves to decide appropriate

inspection frequencies with the aid of a

corrosion growth model. As to the first

item, the proposed rule would not limit

operators to using visual means of

inspection. They could use any means

capable of detecting atmospheric

corrosion, including in-line inspection

devices. As to growth models, AEC did

not suggest which model, if any, can

successfully predict the growth of

atmospheric corrosion on exposed

pipelines in changing and varied

environments. Furthermore, AEC did

not suggest how operators would decide

when to inspect exposed pipe that has

no history of corrosion. Since the record

of this rulemaking proceeding lacks

information on these important issues,

we have adopted the proposed

inspection frequencies as final.

However, we would welcome receiving

more complete information that could

possibly serve as a basis for changing

the rule as AEC suggests.

AEC also suggested we extend the

proposed maximum inspection interval

for onshore pipelines from 3 years to 5

years. It believes that extending the time

to 5 years is appropriate because

atmospheric corrosion rates are low, and

exposed pipe is typically located

outside high consequence areas where

the maximum interval for reevaluation

of pipeline integrity is 5 years (see

§ 195.452(j)(3)). In developing the

proposed rule, we considered whether 3

or 5 years would be the appropriate

maximum interval. We proposed 3 years

primarily because the ASME B31.4

Code, a widely accepted consensus

standards code for hazardous liquid

pipelines, specifies a minimum 3-year

inspection frequency for atmospheric

corrosion onshore. Generally,

atmospheric corrosion rates are found to

be low and therefore, we must assume

this factor was considered when the 3-

year consensus standard was adopted.

However, a low rate by itself does not

seem to justify a longer interval. Also,

the 5-year interval for integrity

reevaluation in high consequence areas

is based on various factors besides

corrosion rate, including the time

needed to carry out in-line inspections

or pressure testing on the pipelines

involved. Moreover, the 5-year

reevaluation applies in addition to other

monitoring frequencies required by part

195, such as annual cathodic protection

monitoring and biweekly right-of-way

inspections. Yet, we did not intend the

5-year period to serve as a yardstick for

determining the adequacy of other

monitoring frequencies.

Finally, AEC was concerned about the

possible adverse consequences of

visually inspecting soil-to-air interfaces

on pipe spans over creeks and ravines.

AEC suggested that if the interface is on

a steep bank, the process of visually

examining the pipe could accelerate

bank erosion causing water pollution

and overstress of the pipeline. We

believe the proposed inspection

requirement is flexible enough to allow

operators to take precautions in

inspecting soil-to-air interfaces on steep

banks to avoid or minimize the

disturbance AEC foresees. Should a

disturbance occur that affects the safe

operation of the pipeline, the operator

would have to correct the problem. We

did not change the final rule as a result

of this comment.

Section 195.585. This section, which

is substantively the same as proposed

§ 195.583, requires operators to take

certain actions to correct corroded pipe.

If general corrosion reduces pipe wall

thickness to less than that required for

the maximum operating pressure of the

pipeline or if localized corrosion pitting

exists to a degree that leakage might

result, the operator must: replace the

pipe; repair the pipe; or reduce the

maximum operating pressure

commensurate with the strength of the

pipe. We edited the final rule to clarify

that it is the ‘‘maximum operating

pressure’’ that must be reduced.

67002 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations

Environmental Defense believed this

section also should require operators to

account for why corrosion has become

so advanced. This commenter suggested

operators should review their corrosion

control systems to ensure that further

harmful corrosion will not occur. We

believe the combination of cathodic

protection criteria under § 195.571 and

periodic monitoring under § 195.573

will accomplish the objective of this

comment. Whenever an operator

discovers a corrosion control deficiency,

it must review its corrosion control

system and make adjustments as

necessary to provide adequate

protection against corrosion. If adequate

protection cannot be achieved, the pipe

involved may have to be replaced.

Section 195.587. This section is based

on proposed § 195.585. It authorizes, but

does not require, operators to use the

widely accepted ASME B31G criteria for

determining the remaining strength of

corroded steel pipe.

Iowa fully supported the proposed

rule. In contrast, WUTC was concerned

that because ASME B31G allows wall

loss of up to 80 percent without repair

or replacement, it does not provide a

reasonable measure of strength needed

to withstand cyclical stresses,

environmental loads, and other

combined forces.

Although WUTC is correct, we

consider B31G to be a guide to the

capability of corroded pipe to withstand

internal pressure. Final § 195.587

advises operators that B31G sets limits

on use of the criteria. One limitation

states that a pipe subject to significant

secondary stresses should not be kept in

service for the purpose of satisfying the

criteria (paragraph 1.2(d)). To ensure

that operators consider the effects of

secondary stresses, in final

§ 195.585(a)(1), we added the words

‘‘needed for serviceability’’ immediately

following ‘‘strength of the pipe.’’

Consequently, as a remedy for generally

corroded pipe, operators may reduce

maximum pressure commensurate with

the pipe strength needed for

serviceability. In determining the

amount of pressure reduction required,

operators may use B31G but also must

consider any significant secondary

stresses that may affect pipe

serviceability.

Section 195.589. Under this section,

proposed as § 195.587, operators must to

keep current records or maps of the

location of cathodically protected

pipelines; cathodic protection facilities

(including anodes) installed after the

Final Rule takes effect; and structures

bonded to cathodic protection systems.

Additionally, operators must keep

records of required maintenance

activities including inspections, tests,

analyses, checks, demonstrations,

examinations, investigations, reviews,

and surveys. These records must

demonstrate the adequacy of corrosion

control measures, or that corrosion

requiring control measures does not

exist. Operators will have to keep these

records for at least 5 years, except that

records related to § 195.569

(examination of pipeline when

exposed); §§ 195.573(a) and (c)

(monitoring external corrosion control);

and §§ 195.579(b)(3) and (c) (monitoring

internal corrosion control) will have to

be kept for as long as the pipeline

involved is in service.

Commenting on examinations of

exposed pipe, Equilon and NACE

believed that there is no need to keep

records of good pipe for as long as the

pipeline remains in service, and that

there is no need to keep records of

defective pipe after the latest in-line

inspection. Equilon and NACE also

contended that old records of internal

corrosion monitoring are of little benefit

without knowledge of flow rates,

upstream pipeline operations, fluid

properties, and other information. None

of these records are generally available.

We did not adopt either comment

because the proposed records provide a

useful history of pipeline condition and

are easy to maintain in electronic form.

The records may be helpful in assessing

corrosion control needs, and could be

used as a comparative base for

evaluating in-line inspection data.

We also considered the Equilon and

NACE comment that subpart H should

not require operators to keep records of

maintenance activities that occur before

subpart H takes effect. Final § 195.589

specifically states that records must be

kept for certain maintenance activities

‘‘required by this subpart.’’ For example,

final § 195.589 does not require

operators to keep records of corrosion

control monitoring conducted before

subpart H takes effect. However, until

subpart H takes effect, § 195.404(c)(3)

requires records of corrosion control

inspections and tests required by

subpart F of part 195. Operators must

continue to maintain records

established under that section for the

retention period prescribed.

Tosco believed we should revise

§ 195.404(c)(3) to indicate that corrosion

control records are required by subpart

H. However, no confusion about the

application of § 195.404(c)(3) to

corrosion control should occur because

this section applies only to inspections

and tests ‘‘required by this subpart,’’

meaning, required by subpart F. After

new subpart H goes into effect, Subpart

F will no longer require corrosion

control inspections and tests.

Phillips argued that the current 2-year

retention requirement in § 195.404(c)(3)

is adequate for auditing compliance,

since 2 years of records show the

current state of corrosion control.

However, as we explained in the NPRM,

5 years is the minimum retention period

that will assure the availability of

records for our compliance auditing.

Environmental Defense stated that it

would help government inspectors

determine the adequacy of cathodic

protection systems if we required

operators to keep records of the location

of existing cathodic protection facilities

and not just those facilities installed

after subpart H takes effect. While this

suggestion has merit, we did not

propose to require records of existing

facilities due to the difficulty of creating

such records, particularly for galvanic

anode systems. Also, in our experience

the lack of such a requirement has not

caused a significant problem due to the

number of operators who keep records

of the location of existing corrosion

control facilities.

Format and Organization

In accordance with Federal Register

guidelines, we drafted final subpart H in

an easier to read and understand format.

Section headings are in the form of

questions. We minimized passive voice

and used the word ‘‘you’’ as a substitute

for ‘‘operator.’’ Also, a few proposed

sections were eliminated, combined

with other sections, or separated into

two or more sections. This Final Rule

also changes §§ 195.5, 195.402, 195.404

and removes §§ 195.236, 195.238,

195.242, 195.244, 195.414, 195.416,

195.418 to account for the new subpart

H.

Advisory Committee Consideration

We presented the NPRM for

consideration by the Technical

Hazardous Liquid Pipeline Safety

Standards Committee (THLPSSC) at a

meeting in Washington, DC on February

7, 2001 (66 FR 132; Jan. 2, 2001). The

THLPSSC is RSPA’s statutory advisory

committee for hazardous liquid pipeline

safety. The committee has 15 members,

representing industry, government, and

the public. Each member is qualified to

consider the technical feasibility,

reasonableness, cost-effectiveness, and

practicability of proposed pipeline

safety standards. The committee voted

unanimously to approve proposed

subpart H but unanimously

recommended that we require operators

of bare or ineffectively coated pipe to

inspect the pipe for external corrosion

every 3 years. Our treatment of this

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations 67003

recommendation is discussed in the

Discussion of Comments section under

section 195.573. A transcript of the

February 7, 2001, meeting is available in

Docket No. RSPA–98–4470.

Regulatory Analyses and Notices

Executive Order 12866 and DOT

Policies and Procedures. RSPA does not

consider this 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 rulemaking to be

significant under DOT regulatory

policies and procedures (44 FR 11034:

February 26, 1979).

We prepared a Final Regulatory

Evaluation of the final rules and a copy

is in the docket. The evaluation states

that the 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 final 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 final rules would allow

use of appendix D criteria under

conditions stated in the NACE Standard.

The evaluation concludes that there

should be only minimal additional cost,

if any, for operators to comply with the

final rules.

Final § 195.563(c) (protecting

effectively coated pipelines), § 195.567

(test leads), and § 195.573(a)(2)

(monitoring cathodic protection by

close-interval surveys or comparable

technology) are changed from the

proposed rules. However, the changes

are consistent with industry practices

and should not result in more than

minimal additional costs.

Regulatory Flexibility Act. The final

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 rulemaking, I certify,

pursuant to section 605 of the

Regulatory Flexibility Act (5 U.S.C.

605), that this rulemaking will not have

a significant impact on a substantial

number of small entities.

Executive Order 13084. The final

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 rules will not significantly or

uniquely affect the communities of the

Indian tribal governments and will not

impose substantial direct compliance

costs, the funding and consultation

requirements of Executive Order 13084

do not apply.

Paperwork Reduction Act. Section

195.589 contains minor additional

information collection requirements.

Operators will be required to record the

location of certain newly installed

protection facilities, and keep these

records for as long as the pipeline

concerned is in service. In addition,

records of inspections, tests, and other

maintenance actions will 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

records of inspections and tests is 2

years or the prescribed interval of test or

inspection, whichever is longer (up to 5

years in some cases).

Hazardous liquid pipeline operators

are required to keep records under

Information Collection 2137–0047,

Transportation of Hazardous Liquids by

Pipeline: Record Keeping and Reporting

Requirements. Operators already

maintain records of the location of their

protection facilities for as long as the

pipeline is in service. They do so 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 will be minimal.

These records are largely computerized

and maintaining these records in a

computer file represents very minimal

costs. Because the additional paperwork

burdens of this final rule are likely to be

minimal, we believe that submitting an

analysis of the burdens to OMB under

the Paperwork Reduction Act is

unnecessary.

Unfunded Mandates Reform Act of

1995. This rulemaking will not impose

unfunded mandates under the

Unfunded Mandates Reform Act of

1995. It will 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 is the least

burdensome alternative that achieves

the objective of the rule.

National Environmental Policy Act.

We have analyzed the final rules for

purposes of the National Environmental

Policy Act (42 U.S.C. 4321 et seq.).

Because the rules parallel present

requirements or practices, we have

determined they will not significantly

affect the quality of the human

environment. An environmental

assessment document is available for

review in the docket. We also made a

finding of no significant impact.

Impact on Business Processes and

Computer Systems. We do not want to

impose new requirements that mandate

business process changes when the

resources necessary to implement those

requirements could otherwise be

applied to ‘‘Y2K’’ or related computer

problems. The final rules do not

mandate business process changes or

require modifications to computer

systems. Because the rules do not affect

the ability of organizations to respond to

those problems, we have not delayed

the effectiveness of the requirements.

Executive Order 13132. The final

rules have been analyzed in accordance

with the principles and criteria

contained in Executive Order 13132

(‘‘Federalism’’). The final rules do not

contain 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.

Executive Order 13211. This

rulemaking is not a ‘‘Significant energy

action’’ under Executive Order 13211. It

is not a significant regulatory action

under Executive Order 12866 and is not

likely to have a significant adverse effect

on the supply, distribution, or use of

energy. Further, this rulemaking has not

67004 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations

been designated by the Administrator of

the Office of Information and Regulatory

Affairs as a significant energy action.

List of Subjects in 49 CFR Part 195

Ammonia, Carbon dioxide,

Incorporation by reference, Petroleum,

Pipeline safety, Reporting and

recordkeeping requirements.

In consideration of the foregoing, 49

CFR part 195 is amended 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 is 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

Piping Systems’ (1996).

(ii) [Reserved]

3. Section 195.5(b) is revised to read

as follows:

§ 195.5 Conversion to service subject to

this part.

* * * * *

(b) A pipeline that 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 into service,

notwithstanding any previous deadlines

for compliance.

* * * * *

4. Section 195.402(c)(3) is 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) is

removed, and paragraphs (a)(1)(vi)

through (a)(1)(viii) are 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 are removed

and reserved: §§ 195.236, 195.238,

195.242, 195.244, 195.414, 195.416, and

195.418.

7. Subpart H is added to read as

follows:

Subpart H—Corrosion Control

Sec.

195.551 What do the regulations in this

subpart cover?

195.553 What special definitions apply to

this subpart?

195.555 What are the qualifications for

supervisors?

195.557 Which pipelines must have coating

for external corrosion control?

195.559 What coating material may I use for

external corrosion control?

195.561 When must I inspect pipe coating

used for external corrosion control?

195.563 Which pipelines must have

cathodic protection?

195.565 How do I install cathodic

protection on breakout tanks?

195.567 Which pipelines must have test

leads and how do I install and maintain

the leads?

195.569 Do I have to examine exposed

portions of buried pipelines?

195.571 What criteria must I use to

determine the adequacy of cathodic

protection?

195.573 What must I do to monitor external

corrosion control?

195.575 Which facilities must I electrically

isolate and what inspections, tests, and

safeguards are required?

195.577 What must I do to alleviate

interference currents?

195.579 What must I do to mitigate internal

corrosion?

195.581 Which pipelines must I protect

against atmospheric corrosion and what

coating material may I use?

195.583 What must I do to monitor

atmospheric corrosion control?

195.585 What must I do to correct corroded

pipe?

195.587 What methods are available to

determine the strength of corroded pipe?

195.589 What corrosion control information

do I have to maintain?

Subpart H—Corrosion Control

§ 195.551 What do the regulations in this

subpart cover?

This subpart prescribes minimum

requirements for protecting steel

pipelines against corrosion.

§ 195.553 What special definitions apply to

this subpart?

As used in this subpart—

Active corrosion means continuing

corrosion which, unless controlled,

could result in a condition that is

detrimental to public safety or the

environment.

Buried means covered or in contact

with soil.

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.

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.

You means operator.

§ 195.555 What are the qualifications for

supervisors?

You must require and verify that

supervisors maintain a thorough

knowledge of that portion of the

corrosion control procedures

established under § 195.402(c)(3) for

which they are responsible for insuring

compliance.

§ 195.557 Which pipelines must have

coating for external corrosion control?

Except bottoms of aboveground

breakout tanks, each buried or

submerged pipeline must have an

external coating for external corrosion

control if the pipeline is—

(a) Constructed, relocated, replaced,

or otherwise changed after the

applicable date in § 195.401(c), not

including the movement of pipe covered

by § 195.424; or

(b) Converted under § 195.5 and—

(1) Has an external coating that

substantially meets § 195.559 before the

pipeline is placed in service; or

(2) Is a segment that is relocated,

replaced, or substantially altered.

§ 195.559 What coating material may I use

for external corrosion control?

Coating material for external

corrosion control under § 195.557

must—

(a) Be designed to mitigate corrosion

of the buried or submerged pipeline;

(b) Have sufficient adhesion to the

metal surface to prevent under film

migration of moisture;

(c) Be sufficiently ductile to resist

cracking;

(d) Have enough strength to resist

damage due to handling and soil stress;

(e) Support any supplemental

cathodic protection; and

(f) If the coating is an insulating type,

have low moisture absorption and

provide high electrical resistance.

§ 195.561 When must I inspect pipe

coating used for external corrosion

control?

(a) You must inspect all external pipe

coating required by § 195.557 just prior

to lowering the pipe into the ditch or

submerging the pipe.

(b) You must repair any coating

damage discovered.

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations 67005

1A pipeline does not have an effective external

coating material if the current required to

cathodically protect the pipeline is substantially the

same as if the pipeline were bare.

§ 195.563 Which pipelines must have

cathodic protection?

(a) Each buried or submerged pipeline

that is constructed, relocated, replaced,

or otherwise changed after the

applicable date in § 195.401(c) must

have cathodic protection. The cathodic

protection must be in operation not later

than 1 year after the pipeline is

constructed, relocated, replaced, or

otherwise changed, as applicable.

(b) Each buried or submerged pipeline

converted under § 195.5 must have

cathodic protection if the pipeline—

(1) Has cathodic protection that

substantially meets § 195.571 before the

pipeline is placed in service; or

(2) Is a segment that is relocated,

replaced, or substantially altered.

(c) All other buried or submerged

pipelines that have an effective external

coating must have cathodic protection.1

Except as provided by paragraph (d) of

this section, this requirement does not

apply to breakout tanks and does not

apply to buried piping in breakout tank

areas and pumping stations until

December 29, 2003.

(d) Bare pipelines, breakout tank

areas, and buried pumping station

piping must have cathodic protection in

places where regulations in effect before

January 28, 2002 required cathodic

protection as a result of electrical

inspections. See previous editions of

this part in 49 CFR, parts 186 to 199.

(e) Unprotected pipe must have

cathodic protection if required by

§ 195.573(b).

§ 195.565 How do I install cathodic

protection on breakout tanks?

After October 2, 2000, when you

install cathodic protection under

§ 195.563(a) to protect the bottom of an

aboveground breakout tank of more than

500 barrels (79.5m3) capacity built to

API Specification 12F, API Standard

620, or API Standard 650 (or its

predecessor Standard 12C), you must

install the system in accordance with

API Recommended Practice 651.

However, installation of the system

need not comply with API

Recommended Practice 651 on any tank

for which you note in the corrosion

control procedures established under

§ 195.402(c)(3) why compliance with all

or certain provisions of API

Recommended Practice 651 is not

necessary for the safety of the tank.

§ 195.567 Which pipelines must have test

leads and what must I do to install and

maintain the leads?

(a) General. Except for offshore

pipelines, each buried or submerged

pipeline or segment of pipeline under

cathodic protection required by this

subpart must have electrical test leads

for external corrosion control. However,

this requirement does not apply until

December 27, 2004 to pipelines or

pipeline segments on which test leads

were not required by regulations in

effect before January 28, 2002.

(b) Installation. You must install test

leads as follows:

(1) Locate the leads at intervals

frequent enough to obtain electrical

measurements indicating the adequacy

of cathodic protection.

(2) Provide enough looping or slack so

backfilling will not unduly stress or

break the lead and the lead will

otherwise remain mechanically secure

and electrically conductive.

(3) Prevent lead attachments from

causing stress concentrations on pipe.

(4) For leads installed in conduits,

suitably insulate the lead from the

conduit.

(5) At the connection to the pipeline,

coat each bared test lead wire and bared

metallic area with an electrical

insulating material compatible with the

pipe coating and the insulation on the

wire.

(c) Maintenance. You must maintain

the test lead wires in a condition that

enables you to obtain electrical

measurements to determine whether

cathodic protection complies with

§ 195.571.

§ 195.569 Do I have to examine exposed

portions of buried pipelines?

Whenever you have knowledge that

any portion of a buried pipeline is

exposed, you must examine the exposed

portion for evidence of external

corrosion if the pipe is bare, or if the

coating is deteriorated. If you find

external corrosion requiring corrective

action under § 195.585, you 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.

§ 195.571 What criteria must I use to

determine the adequacy of cathodic

protection?

Cathodic protection required by this

subpart must comply with one or more

of the applicable criteria and other

considerations for cathodic protection

contained in paragraphs 6.2 and 6.3 of

NACE Standard RP0169–96

(incorporated by reference, see § 195.3).

§ 195.573 What must I do to monitor

external corrosion control?

(a) Protected pipelines. You must do

the following to determine whether

cathodic protection required by this

subpart complies with § 195.571:

(1) Conduct tests on the protected

pipeline at least once each calendar

year, but with intervals not exceeding

15 months. However, if tests at those

intervals are impractical for separately

protected short sections of bare or

ineffectively coated pipelines, testing

may be done at least once every 3

calendar years, but with intervals not

exceeding 39 months.

(2) Identify before December 29, 2003

or not more than 2 years after cathodic

protection is installed, whichever comes

later, the circumstances in which a

close-interval survey or comparable

technology is practicable and necessary

to accomplish the objectives of

paragraph 10.1.1.3 of NACE Standard

RP0169–96 (incorporated by reference,

see § 195.3).

(b) Unprotected pipe. You must

reevaluate your unprotected buried or

submerged pipe and cathodically

protect the pipe in areas in which active

corrosion is found, as follows:

(1) 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.

(2) For the period in the first column,

the second column prescribes the

frequency of evaluation.

Period Evaluation frequency

Before December 29,

2003.

At least once every 5

calendar years, but

with intervals not

exceeding 63

months.

Beginning December

29, 2003.

At least once every 3

calendar years, but

with intervals not

exceeding 39

months.

(c) Rectifiers and other devices. You

must electrically check for proper

performance each device in the first

column at the frequency stated in the

second column.

67006 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations

Device Check frequency

Rectifier ..................... At least six times

each calendar year,

but with intervals

not exceeding 21⁄2

months.

Reverse current

switch.

Diode .........................

Interference bond

whose failure would

jeopardize structural protection.

Other interference

bond.

At least once each

calendar year, but

with intervals not

exceeding 15

months.

(d) Breakout tanks. You must inspect

each cathodic protection system used to

control corrosion on the bottom of an

aboveground breakout tank to ensure

that operation and maintenance of the

system are in accordance with API

Recommended Practice 651. However,

this inspection is not required if you

note in the corrosion control procedures

established under § 195.402(c)(3) why

compliance with all or certain operation

and maintenance provisions of API

Recommended Practice 651 is not

necessary for the safety of the tank.

(e) Corrective action. You must

correct any identified deficiency in

corrosion control as required by

§ 195.401(b). However, if the deficiency

involves a pipeline in an integrity

management program under § 195.452,

you must correct the deficiency as

required by § 195.452(h).

§ 195.575 Which facilities must I

electrically isolate and what inspections,

tests, and safeguards are required?

(a) You must electrically isolate each

buried or submerged pipeline from

other metallic structures, unless you

electrically interconnect and

cathodically protect the pipeline and

the other structures as a single unit.

(b) You must install one or more

insulating devices where electrical

isolation of a portion of a pipeline is

necessary to facilitate the application of

corrosion control.

(c) You must inspect and electrically

test each electrical isolation to assure

the isolation is adequate.

(d) If you install an insulating device

in an area where a combustible

atmosphere is reasonable to foresee, you

must take precautions to prevent arcing.

(e) If a pipeline is in close proximity

to electrical transmission tower footings,

ground cables, or counterpoise, or in

other areas where it is reasonable to

foresee fault currents or an unusual risk

of lightning, you must protect the

pipeline against damage from fault

currents or lightning and take protective

measures at insulating devices.

§ 195.577 What must I do to alleviate

interference currents?

(a) For pipelines exposed to stray

currents, you must have a program to

identify, test for, and minimize the

detrimental effects of such currents.

(b) You must design and install each

impressed current or galvanic anode

system to minimize any adverse effects

on existing adjacent metallic structures.

§ 195.579 What must I do to mitigate

internal corrosion?

(a) General. If you transport any

hazardous liquid or carbon dioxide that

would corrode the pipeline, you must

investigate the corrosive effect of the

hazardous liquid or carbon dioxide on

the pipeline and take adequate steps to

mitigate internal corrosion.

(b) Inhibitors. If you use corrosion

inhibitors to mitigate internal corrosion,

you must—

(1) Use inhibitors in sufficient

quantity to protect the entire part of the

pipeline system that the inhibitors are

designed to protect;

(2) Use coupons or other monitoring

equipment to determine the

effectiveness of the inhibitors in

mitigating internal corrosion; and

(3) Examine the coupons or other

monitoring equipment at least twice

each calendar year, but with intervals

not exceeding 71⁄2 months.

(c) Removing pipe. Whenever you

remove pipe from a pipeline, you must

inspect the internal surface of the pipe

for evidence of corrosion. If you find

internal corrosion requiring corrective

action under § 195.585, you must

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.

(d) Breakout tanks. After October 2,

2000, when you install a tank bottom

lining in an aboveground breakout tank

built to API Specification 12F, API

Standard 620, or API Standard 650 (or

its predecessor Standard 12C), you must

install the lining in accordance with API

Recommended Practice 652. However,

installation of the lining need not

comply with API Recommended

Practice 652 on any tank for which you

note in the corrosion control procedures

established under § 195.402(c)(3) why

compliance with all or certain

provisions of API Recommended

Practice 652 is not necessary for the

safety of the tank.

§ 195.581 Which pipelines must I protect

against atmospheric corrosion and what

coating material may I use?

(a) You must clean and coat each

pipeline or portion of pipeline that is

exposed to the atmosphere, except

pipelines under paragraph (c) of this

section.

(b) Coating material must be suitable

for the prevention of atmospheric

corrosion.

(c) Except portions of pipelines in

offshore splash zones or soil-to-air

interfaces, you need not protect against

atmospheric corrosion any pipeline for

which you demonstrate by test,

investigation, or experience appropriate

to the environment of the pipeline that

corrosion will—

(1) Only be a light surface oxide; or

(2) Not affect the safe operation of the

pipeline before the next scheduled

inspection.

§ 195.583 What must I do to monitor

atmospheric corrosion control?

(a) You must inspect each pipeline or

portion of pipeline that is exposed to

the atmosphere for evidence of

atmospheric corrosion, as follows:

If the pipeline is

located:

Then the frequency of

inspection is:

Onshore .................... At least once every 3

calendar years, but

with intervals not

exceeding 39

months.

Offshore .................... At least once each

calendar year, but

with intervals not

exceeding 15

months.

(b) During inspections you must give

particular attention to pipe at soil-to-air

interfaces, under thermal insulation,

under disbonded coatings, at pipe

supports, in splash zones, at deck

penetrations, and in spans over water.

(c) If you find atmospheric corrosion

during an inspection, you must provide

protection against the corrosion as

required by § 195.581.

§ 195.585 What must I do to correct

corroded pipe?

(a) General corrosion. If you find pipe

so generally corroded that the remaining

wall thickness is less than that required

for the maximum operating pressure of

the pipeline, you must replace the pipe.

However, you need not replace the pipe

if you—

(1) Reduce the maximum operating

pressure commensurate with the

strength of the pipe needed for

serviceability based on actual remaining

wall thickness; or

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations 67007

(2) Repair the pipe by a method that

reliable engineering tests and analyses

show can permanently restore the

serviceability of the pipe.

(b) Localized corrosion pitting. If you

find pipe that has localized corrosion

pitting to a degree that leakage might

result, you must replace or repair the

pipe, unless you reduce the maximum

operating pressure commensurate with

the strength of the pipe based on actual

remaining wall thickness in the pits.

§ 195.587 What methods are available to

determine the strength of corroded pipe?

Under § 195.585, you may use the

procedure in ASME B31G, ‘‘Manual for

Determining the Remaining Strength of

Corroded Pipelines,’’ or the procedure

developed by AGA/Battelle, ‘‘A

Modified Criterion for Evaluating the

Remaining Strength of Corroded Pipe

(with RSTRENG disk),’’ to determine the

strength of corroded pipe based on

actual remaining wall thickness. These

procedures apply to corroded regions

that do not penetrate the pipe wall,

subject to the limitations set out in the

respective procedures.

§ 195.589 What corrosion control

information do I have to maintain?

(a) You must maintain current records

or maps to show the location of—

(1) Cathodically protected pipelines;

(2) Cathodic protection facilities,

including galvanic anodes, installed

after January 28, 2002; and

(3) Neighboring structures bonded to

cathodic protection systems.

(b) 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.

(c) You 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. You must retain these records for

at least 5 years, except that records

related to §§ 195.569, 195.573(a) and (b),

and 195.579(b)(3) and (c) must be

retained for as long as the pipeline

remains in service.

Issued in Washington, DC on December 19,

2001.

Ellen G. Engleman,

Administrator.

[FR Doc. 01–31655 Filed 12–26–01; 8:45 am]

BILLING CODE 4910–60–P