Regulatory Review: Hazardous Liquid and Carbon Dioxide Pipeline Safety Standards

SUMMARY: This rulemaking amends miscellaneous hazardous liquid and

carbon dioxide pipeline safety standards to provide clarity, eliminate

unnecessary or overly burdensome requirements, and foster economic

growth. The changes result from the regulatory review RSPA carried out

in response to the President's directive of January 28, 1992, on

reducing the burden of government regulation. The changes reduce costs

in the liquid pipeline industry without compromising safety.

EFFECTIVE DATE: This regulation is effective July 28, 1994. The

incorporation by reference of certain publications listed in the

regulations is approved by the Director of the Federal Register as of

July 28, 1994.

FOR FURTHER INFORMATION CONTACT: J. Willock, (202) 366-2392, regarding

the subject matter of this final rulemaking, or the Dockets Unit, (202)

366-5046, regarding copies of this final rulemaking or other material

that is referenced herein.

SUPPLEMENTARY INFORMATION:

Background

In a January 28, 1992, memorandum, the President wrote to

Department and agency heads about the need to reduce the burden imposed

by government regulation. The President was concerned that agencies

were not doing enough to review and revise existing regulations to

eliminate unnecessary and overly burdensome requirements. The President

recognized that regulations that do not keep pace with new technologies

and innovations impose needless costs and impede economic growth.

In response to the President's memorandum, DOT published a notice

requesting public comment on the Department's regulatory programs (57

FR 4745; Feb. 7, 1992). Commenters were asked to identify regulations

that substantially impede economic growth, may no longer be necessary,

are unnecessarily burdensome, impose needless costs or red tape, or

overlap or conflict with other DOT or federal regulations. The deadline

for submitting comments was March 2, 1992.

RSPA received comments from six organizations about the pipeline

safety regulations in part 195. Comments were from three regulated

pipeline companies, a pipeline trade association, a state pipeline

safety agency, and a federal agency. RSPA considered all comments in

its review of the regulations, and these comments are available in the

docket. Some comments will be considered in future rulemakings.

Additionally, RSPA has published a separate rulemaking ``Update of

Standards Incorporated by Reference'' (58 FR 14519; March 18, 1993)

which updates the editions of the industry standards that are

incorporated in part 195.

On November 27, 1992, RSPA published a Notice of Proposed

Rulemaking, NPRM, (57 FR 56304) proposing 18 changes to the regulations

based on the comments received from the public and asked for further

comments regarding the proposed changes. RSPA received comments from 21

organizations: 15 pipeline companies, 3 pipeline trade associations, 2

environmental organizations, and 1 county government. RSPA considered

all comments in preparation of the final rulemaking and the comments

are available in the Docket.

Advisory Committee

The Technical Hazardous Liquid Pipeline Safety Standards Committee

(THLPSSC), consisting of 15 members, was established by statute to

consider the feasibility, reasonableness, and practicability of

proposed pipeline regulations. RSPA implemented the committee balloting

process by mail. After initial balloting, the process allowed each

member to review the ballots, including comments, of all other members,

and to change his or her vote or initial comment if desired. Although

some THLPSSC members did not vote on every proposed change, a tally of

the second ballots showed that a large majority of THLPSSC members

found all the proposed changes technically feasible, reasonable, and

practicable. Nonetheless, in developing the final regulations, RSPA

considered all final THLPSSC votes and comments, including minority

positions. The following discussion explains how RSPA treated THLPSSC

positions and public comments on the proposed amendments in developing

the final rule.

Changes to Part 195 Safety Standards

The following discussion explains the changes to various standards

in part 195:

Section 195.1 Applicability.

Offshore production. Part 195 does not apply to pipelines used in

offshore production, whether on the Outer Continental Shelf or in state

offshore waters. However, this exception is clearly stated in part 195

only for production on the Outer Continental Shelf (Sec. 195.1(b)(5)).

To clarify that all offshore pipelines used in production are outside

part 195, RSPA proposed to delete from Sec. 195.1(b)(5) the phrase ``on

the Outer Continental Shelf''.

The 10 THLPSSC members who voted on the proposed amendment to

Sec. 195.1(b)(5) all approved the amendment.

In addition, RSPA received comments from three operators and two

pipeline-related associations in support of the amendment and no

adverse comments. Therefore, Sec. 195.1(b)(5) is amended as proposed in

the NPRM.

We also requested comments on whether there is a gap in the

regulation of production lines in state offshore waters. Only one

commenter responded. This commenter opined that existing state and

federal programs adequately regulate production lines in state waters.

In Louisiana, the Departments of Natural Resources and Environmental

Quality were said to have comprehensive regulations on facility

installation, operation, integrity, and removal, and sufficient

authority to address any ``gap'' that is identified. Since the other

states with production lines in state waters have similar regulations,

RSPA does not believe there is a gap in the regulation of production

lines in state waters.

In-plant piping. Part 195 does not apply to pipeline transportation

through onshore production, refining, or manufacturing facilities, or

storage or in-plant piping systems associated with such facilities

(Sec. 195.1(b)(6)). Because the physical distinction between a

regulated pipeline serving a plant and unregulated in-plant piping is

unclear, RSPA proposed to add a definition of ``in-plant piping

system'' to Sec. 195.2. The definition proposed was: ``In-plant piping

system means piping that is located on the grounds of a plant and used

to transfer hazardous liquid or carbon dioxide between plant facilities

or between plant facilities and a pipeline, not including any device

and associated piping that are necessary to control pressure in the

pipeline.'' The NPRM explained that we would consider in-plant piping

to extend to the plant boundary in the absence of a necessary pressure

control device on plant grounds.

All ten THLPSSC members who voted on this proposal supported it.

However, four members believed that because the NPRM primarily

concerned pipeline transportation rather than production, refining, or

manufacturing plants, it did not give plant owners adequate notice that

the proposed definition could affect plant piping. These members wanted

RSPA to publish a separate NPRM on the subject of in-plant piping.

RSPA does not agree that another NPRM is needed. The subject of in-

plant piping and the associated issues were clearly discussed in the

published NPRM. Also, all interested persons, including plant owners as

well as pipeline operators, were given an opportunity to comment on the

subject of in-plant piping.

RSPA received comments on the proposed definition from seven

operators, two pipeline-related associations, and one state agency. Two

operators and one association fully supported the proposal.

One operator and a pipeline-related association thought plant

owners were not adequately notified of the proposed rule, and that RSPA

should treat the subject in a separate NPRM. Our position on this issue

is given supra in response to a similar criticism by four THLPSSC

members.

Another operator was concerned that the proposed definition would

cause operator-owned components, such as pipe, meters, instruments, and

manifolds, that are located on plant grounds downstream from the

operator's pressure control device to fall outside part 195. The

operator was worried that other agencies would regulate these

components as non-transportation related facilities. We are not

persuaded, however, that the potential for such regulation is

sufficient reason to exclude the components from the definition of in-

plant piping system. The aim of the proposed definition was to

distinguish unregulated piping, not to limit the jurisdiction of other

government agencies.

In contrast, an operator of gathering and processing facilities was

concerned that part 195 would apply to plant piping that lies between

any necessary pressure control device and the connection to a pipeline.

This commenter apparently did not realize that such piping is subject

to part 195. RSPA has applied part 195 to such piping because it is

subject to pressure which is controlled by a device operators must have

to meet Sec. 195.406(b). However, this application has had little

effect on plant owners, because we hold the pipeline operator, not the

plant owner, responsible for compliance.

An operator commenting on the plant device exclusion in the

proposed definition advised us to change ``control pressure'' to

``prevent overpressure.'' This commenter said the change would avoid

making pipeline operators responsible under part 195 for nonessential

pressure control devices. We agree the suggested rewording would better

convey the intent of the proposal. But, in the final definition, we

have changed ``control pressure in the pipeline'' to ``control pressure

in the pipeline under Sec. 195.406(b)'' to convey the intent even more

precisely.

The state agency commented that if piping on plant grounds does not

include a device necessary to control pipeline pressure, the

jurisdiction of part 195 over the pipeline should not end at the plant

boundary. Instead, the state agency recommended ending jurisdiction at

a component inside the plant, such as a flange, where the pipeline can

be isolated for purposes of testing. Although operators may use such

components, part 195 does not require that they be on the pipeline.

Also, we believe the plant boundary is a more convenient demarcation of

in-plant piping than an unspecific inside-the-plant component. Thus,

the state agency's comment is not incorporated in the final definition.

The state agency, an operator, and a pipeline-related association

were concerned that because segments of transfer piping located off

plant grounds were not included in the proposed definition, a large

number of short pipelines would come under part 195. RSPA recognizes

that production, refining, or manufacturing plants often install

transfer piping off plant grounds. A plant may use this piping to

transfer hazardous liquids between its different facilities located on

the same grounds; between its different facilities located on separate

grounds (usually separated by a roadway, railway, waterway, or

industrial area); between its facilities and a transportation system,

such as a railroad or pipeline; or between its facilities and the

facilities of another plant or industrial consumer. The three

commenters thought the off-grounds segments should qualify as in-plant

piping if they connect facilities of the same plant. The association

also wanted to include under the definition off-grounds segments that

connect facilities of different plants. In addition, the operator and

association argued that the off-grounds segments pose minimum risk to

public safety and the environment, because the segments generally are

located in industrial areas, roadways, or railways. The association

further argued that a plant has the same operational control, including

response capability, over the off-grounds segments as it does over

piping on plant grounds.

In response to these comments, we note that Sec. 195.1(b)(6) echoes

section 201(3) of the Hazardous Liquid Pipeline Safety Act of 1979

(HLPSA), (49 U.S.C. app. 2001(3)), which excludes certain ``in-plant

piping systems'' from regulation under the HLPSA. Since neither the

HLPSA nor its legislative history explain ``in-plant piping,'' we adopt

an ordinary, reasonable understanding of the term. Therefore, we do not

accept the interpretation that the term includes piping that crosses

the property of others outside plant grounds. However, many plants are

separated by a public thoroughfare, and plant transfer piping crosses

the thoroughfare. A single public thoroughfare would include any road,

from a country lane to an interstate highway, but it does not include a

railroad. Because transfer piping that crosses such thoroughfares is

comparable in most respects to other in-plant piping, RSPA considers

the in-plant piping exception to include the thoroughfare crossings.

The thoroughfare exception does not apply to inter-facility lines or

delivery lines, because these lines are distinct from in-plant piping.

We did not intend the proposed definition of ``in-plant piping

systems'' to expand our present interpretation of the term. So the

final definition does not incorporate any of the comments concerning

piping located off plant grounds other than for thoroughfare crossings.

However, the proposed definition's first use of the term

``pipeline'' is changed to ``pipeline or other mode of

transportation.'' This change is needed to include, within the

definition, piping on plant grounds that transfer hazardous liquid or

carbon dioxide between plant facilities and modes of transportation

other than pipeline.

Terminal facilities. Part 195 does not apply to the transportation

of hazardous liquid or carbon dioxide by vessel, aircraft, tank truck,

tank car, or other vehicle, or by terminal facilities used exclusively

to transfer hazardous liquid or carbon dioxide between such modes of

transportation (Sec. 195.1(b)(7)). RSPA proposed to amend

Sec. 195.1(b)(7) to clarify that terminal facilities located off

terminal grounds are subject to part 195, and to distinguish

unregulated terminal facilities from a regulated pipeline entering or

leaving the terminal. As with the proposed in-plant piping definition,

any device and associated piping on terminal grounds necessary to

control pressure in a regulated pipeline would not be excepted from

part 195.

The THLPSSC voted to approve this proposal, but four members

believed the NPRM did not give terminal owners adequate notice that the

proposed amendment could affect their piping. These members wanted RSPA

to publish a separate NPRM on the subject. For the reasons stated supra

in response to a similar argument by these THLPSSC members concerning

in-plant piping, RSPA does not agree that another NPRM is needed.

Five operators and two pipeline-related associations commented on

the proposed amendment to Sec. 195.1(b)(7). Of these commenters, two

operators and one association agreed with the proposal.

A few commenters expressed the same concerns about the proposed

amendment to Sec. 195.1(b)(7) as they did about the proposed in-plant

piping definition. These concerns were that the NPRM did not adequately

notify plant (terminal) owners of the proposed rule, and that some

operator-owned components located on plant (terminal) grounds would

fall outside part 195. Our response to these concerns is the same as

stated supra regarding in-plant piping.

In regard to transfer lines located outside terminal grounds at

ports, an operator and a pipeline-related association pointed out that

the U.S. Coast Guard regulates transfers between terminal storage and

dock facilities. These commenters suggested that RSPA and Coast Guard

develop a memorandum of understanding to limit Coast Guard's

regulations to dock facilities.

We recognize that Coast Guard and RSPA jurisdictions overlap in

port areas, but the two agencies have different responsibilities. Also,

the overlap does not automatically result in regulatory conflicts, and

the commenters did not mention any. Nonetheless, though we have not

changed the final rule as a result of this comment, in enforcing part

195 at port areas, RSPA will act appropriately to resolve any

unnecessary regulatory burdens.

Carbon dioxide injection system. Section 195.1(b)(8) provides that

part 195 does not apply to ``[t]ransportation of carbon dioxide

downstream from a point in the vicinity of the well site at which

carbon dioxide is delivered to a production facility.'' RSPA proposed

to amend this section to clarify that the exception covers pipelines

used in the injection of carbon dioxide for oil recovery operations.

The THLPSSC approved the proposed amendment (10 voted in favor and

5 did not vote), and we received no adverse comments from the public.

The proposed amendment to Sec. 195.1(b)(8) is, therefore, adopted as

final.

Section 195.2 Definitions.

The proposed revision of the definition of ``Secretary'' is not

adopted in this rulemaking. Instead, it is being handled in an omnibus

rulemaking covering all regulations involving pipeline safety.

The definition of ``In-plant piping system'' is discussed above in

Sec. 195.1 Applicability.

Two commenters objected to the proposed definition for petroleum

products because of its use of the terms ``flammable'', ``toxic'', and

``corrosive'' which are not defined under part 195. The commenters

stated that absent specific definitions for these terms, their

applicability could be unclear.

RSPA agrees with the comments about the lack of clarity in the

proposed definition for petroleum products. So, the final rule for this

section includes new definitions for ``flammable'', ``toxic'', and

``corrosive'' that come from the definitions contained in 49 CFR part

173 for Transportation and Packaging of Hazardous Materials for the

terms ``flammable liquid'', ``poisonous material'', and ``corrosive

material'', respectively. RSPA has adopted the definition of

``poisonous material'' for ``toxic'' because it considers the terms

synonymous.

Sections 195.2, 195.106, 195.112, 195.212 and 195.413 (Nominal Outside

Diameter of the Pipe in Inches)

RSPA proposed to standardize the dimensioning of pipe size

throughout part 195 (Changes are made to Secs. 195.2, 195.106(b),

195.106(c), 195.112(c), 195.212(b)(3)(ii) and 195.413(a)). All 10

THLPSSC members who voted were in favor of the proposal and no

commenter objected thereto. Accordingly, the proposed amendment is

adopted as final.

Section 195.3 Matter incorporated by reference.

Section 195.3 sets out the general requirements for the

incorporation in the regulations of industry standards for the design,

construction and operation of hazardous liquid and carbon dioxide

pipelines. Paragraph 195.3(a) states that incorporation of a document

by reference has the same force as if the document were copied in the

regulations. Some operators have misinterpreted this section to mean

that they must comply with all of the terms contained in a referenced

document. Accordingly, RSPA hereby revises Sec. 195.3(a) to clarify

that an entire document is not incorporated when the document is

incorporated by reference; rather, only those portions specifically

referenced in the regulations are incorporated.

The rule is being revised to conform to a recent update of

references in another rulemaking (Update of Standards Incorporated by

Reference (58 FR 14519; March 18, 1993)). Also, references to ASME/ANSI

Codes B31.8 and B31.G are being added. The 10 THLPSSC members who voted

and 7 commenters favored the revision.

Section 195.5 Conversion to service subject to this part.

Section 195.5 regulates the conversion of steel pipelines to

hazardous liquid or carbon dioxide service that is subject to part 195.

Under Sec. 195.5(a)(4), a converted pipeline must be hydrostatically

tested to substantiate the maximum operating pressure (MOP) permitted

by Sec. 195.406.\1\

---------------------------------------------------------------------------

\1\Section 195.5(a)(4) actually uses the term ``maximum

allowable operating pressure,'' but for consistency with

Sec. 195.406, this term is changed below to MOP by removing the word

``allowable.''

---------------------------------------------------------------------------

To substantiate the MOP of a converted pipeline, an operator must

know the pipe design pressure (see current Sec. 195.406(a)(1)).

Consequently, if pipe design pressure is unknown, a steel pipeline may

not be converted under Sec. 195.5. Although the design pressure of

components is an MOP factor under Sec. 195.406(a)(2), pipeline

components are normally designed to be as strong or stronger than

attached pipe. Thus, pipe design is the critical factor in

substantiating MOP under Sec. 195.5(a)(4), and lack of knowledge of

component design pressure is not a significant safety concern.

RSPA proposed to amend Sec. 195.5 to permit conversion using an

approach found in section 845.214 and Appendix N of ASME B31.8 for gas

pipelines whose design pressure is unknown. Under this proposal,

operators would pressure test the pipeline under Appendix N until pipe

yield occurs. Instead of design pressure, this yield test pressure

would be used to compute MOP by applying certain reduction factors to

80 percent of the first pressure that produces pipe yield.

All THLPSSC members who voted on the proposed amendment to

Sec. 195.5 supported it in concept. However, two members thought the

wording of Appendix N should be copied directly into part 195 to avoid

referencing a gas pipeline code in liquid pipeline regulations. We

believe the principles of Appendix N apply equally to gas and liquid

pipelines. And since the B31.8 Code is widely used, operators of

hazardous liquid or carbon dioxide pipelines will not find it difficult

to obtain and apply Appendix N.

RSPA received five comments on the proposed amendment to

Sec. 195.5. Two operators and a pipeline-related association agreed

with the proposed amendment.

One operator suggested that if pipelines operating at less than 20

percent of specified minimum yield strength (SMYS) are subject to

Sec. 195.5, RSPA should allow operators up to 10 years to meet the

testing requirements. At present, none of the standards in part 195,

including Sec. 195.5, applies to pipelines operating at less than 20

percent of SMYS (see Sec. 195.1(b)(3)). However, this commenter may

have had in mind Sec. 206 of the Pipeline Safety Act of 1992 (Pub. L.

102-508), which provides that exceptions to regulations under the

Hazardous Liquid Pipeline Safety Act of 1979 (49 U.S.C. app. 2001 et

seq.), such as part 195, may not be based solely on low internal

stress. Because of this statutory mandate, RSPA has proposed to apply

part 195 to certain low-stress hazardous liquid pipelines (Docket PS-

117; 58 FR 12213; March 3, 1993). Still, that proposal would not

require any existing low-stress hazardous liquid pipeline to be tested

under Sec. 195.5, because such pipelines would not be converted

pipelines. Of course, if part 195 becomes applicable to low stress

pipelines, any pipeline converted to low stress hazardous liquid

service subject to part 195 would have to be tested under Sec. 195.5.

But, since testing is the backbone of the conversion process, RSPA does

not believe Sec. 195.5 should be amended to extend the time for testing

to 10 years.

A state agency was concerned that if test pressure must be measured

at the high elevation point of test segments, the test could stress the

low point of the segment beyond yield. However, the Appendix N test

method should not result in overstress at the low elevation, because

the method does not require increases in test pressure after the first

yield occurs in the test segment.

In a separate rulemaking proceeding (Docket No. PS-124; 57 FR

39572; August 31, 1992), RSPA proposed to allow the use of the Appendix

N method in converting pipelines to gas service under 49 CFR 192.14.

This gas pipeline conversion standard is similar to Sec. 195.5.

Comments to that notice argued that pressure testing to yield is

unnecessary to qualify certain pipelines that operate at low stress

(generally pipelines 12\3/4\ inches or less in nominal outside diameter

operating at pressures of 200 psig or less). RSPA believes these

comments are also relevant to hazardous liquid pipelines. All other

factors being equal, hazardous liquid pipelines operating at low

internal stress present less risk of failure from time-dependent

defects than higher stress hazardous liquid pipelines. Because of the

lower risk, RSPA has modified the final rule to provide that pipelines

12\3/4\ inches or less in nominal outside diameter to be operated at a

pressure of 200 psig or less may be converted without testing to yield.

The MOP of such pipelines may be determined under Sec. 195.406 by using

200 psig as pipe design pressure.

The proposed rule has been redrafted to improve clarity, to better

relate conversion to design pressure and MOP under Sec. 195.406, and to

include the changes discussed supra. In the final rule, the proposed

amendment to Sec. 195.5(a)(1) is revised and published as an amendment

to Sec. 195.406(a)(1). This latter section deals specifically with pipe

design pressure and MOP. As set forth infra, revised Sec. 195.406(a)(1)

provides that when pipe design pressure is unknown for steel pipelines

being converted, a reduced value of first yield hydrostatic test

pressure may be used as design pressure to compute MOP. If the pipeline

to be converted is 12\3/4\ inches or less in nominal outside diameter

and is not yield tested, 200 psig may be used as design pressure.

Section 195.8 Transportation of hazardous liquid or carbon dioxide in

pipelines constructed with other than steel pipe.

The proposal to replace the word ``he'' with ``the Secretary'' to

remove any implication of gender is not adopted in this rulemaking.

Instead, this proposal will be handled in an omnibus rulemaking to make

minor clarifications and error corrections covering all the pipeline

safety regulations.

Section 195.50 Reporting accidents and Sec. 195.52 Telephonic notice

of certain accidents.

Sections 195.50(f) and 195.52(a)(3) require operators to prepare

reports and give telephonic notice of accidents, respectively, when the

estimated property damage due to an accident exceeds $5,000. RSPA

discovered from its regulatory review and previous enforcement cases

that a significant amount of confusion exists among pipeline operators

as to which cost estimates must be included in calculating the

``estimated property damage to the property of the operator or others *

* *'' Frequently, when reporting accidents, pipeline operators fail to

include as ``property damage'' the fair market value of the product

released or those costs associated with clean-up and recovery efforts.

RSPA believes these costs should be included when reporting accidents.

Because the $5,000 reporting requirement requires the reporting of

minor accidents, RSPA proposed amending Secs. 195.50(f) and

195.52(a)(3) to increase the reporting threshold to $50,000, the same

level as required in 49 CFR part 192 and to include as property damage

the value of the product released and the costs associated with clean-

up and recovery efforts. The THLPSSC voted 10 to 0 in favor of the

change (5 members did not vote). Two of those favoring the proposed

changes recommended that RSPA modify the final rule to limit property

damage to fair market value of the lost product and initial clean-up

and product recovery costs. One member said that clean-up and recovery

costs should not be included in total property damage.

Three commenters disagreed with the proposed changes and

recommended that the rule be withdrawn. One complaint was that the

statistical base would be discontinuous because, in the future, RSPA

would not receive information on accidents costing between $5,000 and

$50,000. Another complaint was that the change could affect the

development of environmental protection requirements. RSPA understands

that a change in reporting levels will cause a slight skewing due to

truncation of the data, but believes requiring operators to report

accidents based solely on the $5,000 property damage criterion is

unnecessary and burdensome. Significant accidents will still be

reported because the other criteria (especially those that are

environmentally related) requiring reports will be unchanged: (1)

Explosion or fire, (2) loss of 50 barrels of liquid, (3) escape of five

barrels a day of highly volatile liquids, (4) a death, (5) bodily harm,

or (6) resulted in the pollution of any stream. Because these

requirements remain unchanged, those operators with more frequent small

releases will still be identified. As to a skewing of the data, those

organizations that keep track of such statistical data should be able

to make adjustments to account for such changes. Also, as explained in

the NPRM, this change will make the liquid safety reporting

requirements consistent with the gas safety reporting requirements

which will eliminate confusion. The rule change should have little, if

any, effect on the environment because the same spill volume reporting

criteria remain in effect. Only the dollar level of the reporting

criterion is being changed.

Two commenters supported the rule changes as they were written.

Five others favored the changes, but proposed modification of the rules

to explain more fully the meaning of ``estimated total damage'' in

order to spell out the items that must be covered. They said that

``estimated total damage'' is ambiguous and confusing and subject to

interpretation. One commenter stated that the costs of subsurface

restoration should be excluded from property damage because it is

nearly impossible to estimate the subsurface restoration costs within

the time allowed to report the accident.

RSPA agrees that early estimates of the costs to clean-up a liquid

spill may not be exact; however, the operator should, at a later date,

submit a revised report that provides more reliable cost figures for

the clean-up.

RSPA is clarifying the issue by amending Sec. 195.50(f) to read:

``(f) Estimated property damage, including cost of clean-up and

recovery, value of lost product, and damage to the property of the

operator or others, or both, exceeding $50,000'' and Sec. 195.52(a)(3)

to read: ``(3) Caused estimated property damage, including cost of

clean-up and recovery, value of lost product, and damage to the

property of the operator or others, or both, exceeding $50,000.''

Section 195.106 Internal design pressure.

Section 195.106(a) prescribes the formula for calculating the

design pressure of steel pipe. In addition, Sec. 195.106(b) regulates

the pipe yield strength used in the design pressure formula. When the

specified minimum yield strength (SMYS) of pipe is unknown,

Sec. 195.106(b) requires that yield strength be derived from tensile

tests on random samples of pipe. Based on a comparable gas pipeline

safety standard (49 CFR 192.107(b)(2)), RSPA proposed to amend

Sec. 195.106(b) to allow operators to use 24,000 psi as yield strength

if pipe of unknown SMYS is not tensile tested. Editing changes to

Sec. 195.106(b) were also proposed.

The 10 THLPSSC members who voted on the proposed amendment of

Sec. 195.106(b) supported it (5 did not vote). In addition, RSPA

received comments from four operators and one pipeline-related

association. The association and three of the operators agreed with the

proposal. One of these operators suggested further editing, part of

which RSPA has included in the final rule.

One operator was concerned that the proposed rule could

unjustifiably reduce the MOP of its pipelines. The operator said its

pipelines are made of Grade B pipe (yield strength at least 35,000 psi)

or better. However, some pipelines may contain pipe for which

documentation of yield strength or tensile testing does not exist. For

such pipe, without new tensile testing, yield strength would have to be

assumed to be 24,000 psi. The operator suggested that RSPA allow

operators to use appropriate evidence besides tensile tests to

demonstrate the yield strength of pipe.

In response to this comment, we note, first, that the proposed

amendment to Sec. 195.106(b) would not affect the design pressure of

existing pipelines unless they are replaced, relocated, or otherwise

changed (see Sec. 195.100). Second, Sec. 195.106(b) currently requires

operators to use as yield strength either SMYS or a value based on

tensile testing. So the operator's apparent difficulty in verifying

yield strength is a problem of compliance with the current rule. Third,

the proposed rule would relax the burden of tensile testing only when

MOP does not exceed the level that corresponds to a yield strength of

24,000 psi. When a higher MOP is desired, operators must use the

tensile testing option. Finally, RSPA is not aware of any acceptable

evidence of the yield strength of pipe of unknown SMYS apart from

appropriate tensile testing. Thus, the amendments to Sec. 195.106(b),

as discussed above, are adopted.

Section 195.204 Inspection-general.

The THLPSSC voted 10 to 0 in favor of the proposed change to make

the language gender neutral and, except for a minor correction, no

objections were received from commenters. The proposed change is

adopted as corrected.

Section 195.228 Welds; standards of acceptability.

One of the comments we received on proposed amendments to

nondestructive testing requirements under Sec. 195.234(e) (discussed

infra) concerned the standards for acceptance of weld flaws

(Sec. 195.228(b)). A pipeline-related association asked us to

incorporate by reference the alternative acceptance standards for girth

welds that are in the Appendix to American Petroleum Institute (API)

Standard 1104 (17th edition). For weld acceptability, Sec. 195.228(b)

now references the standards in Section 6 of API Standard 1104.

In a notice of proposed rulemaking involving our review of the gas

pipeline safety standards in 49 CFR part 192 (Docket PS-124; 57 FR

39572; August 31, 1992), RSPA proposed to allow gas operators to apply

the API appendix in addition to section 6 criteria. Although that

proposal was based on a petition by API to incorporate the appendix by

reference in both parts 192 and 195, we overlooked the request to

include such a proposal in the present rulemaking.

In the part 192 rulemaking, RSPA's gas pipeline safety advisory

committee voted to support the proposed amendment. Also, all but one of

the public comments were in favor of allowing use of the Appendix of

API Standard 1104.

The dissenting commenter was concerned that industry inspection

personnel may not be qualified to apply the appendix. However, this

commenter may not have recognized that under Secs. 192.243(b) and (c),

operators must ensure that nondestructive testing is performed in

accordance with written procedures by persons who have been properly

trained and qualified. Sections 195.234(b) and (c) provide similar

requirements for nondestructive testing of welds on hazardous liquid

and carbon dioxide pipelines. RSPA believes these requirements are

adequate to assure proper application of the appendix.

The Appendix of API Standard 1104 applies equally to girth welds in

gas and liquid pipelines. This amendment is not mandatory, rather it

provides pipeline operators an optional operating procedure. In view of

the prior opportunity for public comment on use of the appendix for gas

pipelines, the favorable response by public commenters and RSPA's

advisory committee, and the fact that use of the appendix would not be

mandatory, we believe that a further opportunity for public comment is

unnecessary to allow use of the appendix under Sec. 195.228(b). We feel

this amendment is a logical outgrowth of the Notice and furthers our

efforts to make parts 192 and 195 consistent wherever possible. This

amendment will not have a substantial impact on the regulated

community.

Thus, in accordance with 5 U.S.C. 553(b)(3)(B), we are amending

Sec. 195.228(b) to reference the appendix without further rulemaking

notice. However, should any person be adversely affected by this

decision or wish to change the final rule, that person may submit a

petition for reconsideration under RSPA's rulemaking procedures in 49

CFR 106.35.

The final rule provides that the appendix may be used only for

girth welds to which the appendix applies. For example, as section A.1

of the appendix states, neither welds in pump stations nor welds used

to connect fittings and valves are covered by the appendix. Also, the

appendix applies only to girth welds between pipe of equal nominal wall

thickness.

Section 195.234 Welds: Nondestructive testing.

Section 195.234(e) requires that ``100 percent of each day's girth

welds installed in * * * [certain] locations must be nondestructively

tested 100 percent unless impracticable, in which case at least 90

percent must be tested.'' RSPA proposed to amend Sec. 195.234(e) to

clarify that ``90 percent'' pertains to the number of girth welds that

must be tested over their entire circumference.

In addition, Sec. 195.234(g) requires: ``At pipeline tie-ins 100

percent of the girth welds must be nondestructively tested.'' RSPA

proposed to clarify that this standard applies to tie-ins of

replacement sections of pipeline.

The THLPSSC supported the proposed amendments, although one member

thought part 195 should define the word ``impracticable.'' We did not

adopt this recommendation because the word is used in its ordinary

dictionary sense.

Three operators and two pipeline-related associations commented on

the proposed amendments. Three commenters agreed with the proposal, one

suggested editing changes, and one made a related proposal discussed

supra under the heading, ``Sec. 195.228(b) Welds; standards of

acceptability.'' Although we did not adopt all the editing suggestions,

these comments helped us provide clarity to the final rule.

In addition, one commenter thought the proposed amendment of

Sec. 195.234(g) was unnecessary because Sec. 195.200 already indicates

that Sec. 195.234(g) applies to replacement sections. Moreover, the

commenter thought adding the proposed phrase to Sec. 195.234(g) would

create confusion over whether Secs. 195.234(a) through (f) apply to

replacement sections. While these observations have theoretical merit,

in practice, some operators have failed to recognize that ``pipeline

tie-ins'' include tie-ins of replacement sections. The clarifying

phrase adds emphasis where it is apparently needed to assure compliance

with the full extent of the rule. Section 195.234(g) is, therefore,

adopted as proposed.

Sections 195.246 Installation of pipe in a ditch and 195.248 Cover

over buried pipeline.

Section 195.246(b) is inconsistent with Sec. 195.413(b)(3) for pipe

in the Gulf of Mexico and its inlets (See Sec. 195.2 Definitions) under

water less than 15 feet deep but at least 12 feet deep, because

Sec. 195.246(b) permits the pipe to be without cover or to be above the

seabed if properly protected. Such pipe is a ``hazard to navigation''

under the definition of that term in Sec. 195.2, and must have the

minimum cover required by Sec. 195.413(b)(3). In addition,

Secs. 195.248(a) and (b) are inconsistent with Sec. 195.413(b)(3) for

pipe in the Gulf of Mexico and its inlets under water less than 12 feet

deep. Section 195.248(a) allows pipe to be less than 12 inches below

the seabed (i.e., a hazard to navigation). In certain instances,

Sec. 195.248(b) allows pipe to be without cover or less than 12 inches

below the seabed. Neither condition is allowed under

Sec. 195.413(b)(3). In light of these inconsistences, RSPA proposed in

the NPRM to amend Secs. 195.246(b) and 195.248(a) and (b) to correct

the problem.

Ten THLPSSC members favored the proposed changes (5 members did not

vote). One of the members favoring the changes said it would make more

sense to retain the existing regulation which operators have adhered to

for years. In similar manner, two commenters and one pipeline-related

organization agreed with the proposal. One commenter and two pipeline-

related organizations disagreed and suggested that references to a

depth of 15 feet in the rule be eliminated. RSPA proposed changes to

Secs. 195.246(b), 195.248(a) and 195.248(b) so these sections would

conform with Public Law 101-599 (section 1, 104 Stat. 3038 (1990))

which requires burial of pipe where the subsurface is under 15 feet of

water as measured from mean low water. Therefore, Secs. 195.246(b),

195.248(a) and 195.248(b) are adopted as proposed in the NPRM.

Section 195.262 Pumping equipment.

Section 195.262(d) regulates the location of pumping equipment. The

rule prohibits the installation of pumping equipment on property not

under the operator's control. It also prohibits installation less than

50 feet from the pump station boundary. RSPA proposed to amend

Sec. 195.262(d) to clarify that these two restraints on location apply

conjunctively not alternatively.

The THLPSSC members who voted on the proposed amendment supported

it in concept, but 5 members recommended further editing of the rule

for clarity. Although three of the five persons who commented on the

proposal supported it as proposed, the other two commenters thought

further clarifying changes were needed. In view of these comments and

THLPSSC views, we have modified the final rule based on identical

wording suggested by five THLPSSC members and one commenter.

Section 195.304 Testing of components.

Section 195.304(b) excludes from hydrostatic testing under part 195

any component that is the only item being replaced or added to a

pipeline system if the component or a prototype was tested at the

factory. RSPA proposed to amend Sec. 195.304(b) to clarify that the

excluded components do not include pipe.

The THLPSSC fully supported the proposed amendment. Of the six

comments from the public on the proposal, a pipeline-related

association and two operators agreed with it, while three operators

suggested changes.

An operator suggested that instead of amending Sec. 195.304(b), we

should revise the definition of ``component'' to exclude pipe. We did

not adopt this suggestion because the revision would affect every rule

in part 195 that uses the term ``component.'' Editing suggested by

another operator was not adopted because it concerned matters not

addressed in the NPRM.

One operator felt pipe should be excluded from hydrostatic testing

under Sec. 195.304(b) to the same extent as other components. The

operator said that hydrostatically testing short sections of mill

tested pipe is duplicative, costly, and not needed for safety. Although

the NPRM did not propose to alter the existing requirement that

replacement sections of pipe of any length must be hydrostatically

tested to part 195 standards before operation, we do not agree with

this commenter's contention. Normal pipe mill tests are not duplicative

of part 195 tests, and are not a proven safe alternative to part 195

requirements. However, for short sections of replacement pipe, part 195

test requirements could be met anywhere, including, by prior

arrangement with the operator, in the pipe mill. So if an operator

wishes to avoid field testing of short replacement sections of pipe, it

only needs to assure that the mill tests of those sections were done in

accordance with part 195 test requirements.

Section 195.406 Maximum operating pressure.

The changes to Sec. 195.406 are discussed supra under Sec. 195.5.

Section 195.412 Inspection of rights-of-way and crossings under

navigable waters.

Section 195.412(a) requires an operator, at intervals not exceeding

3 weeks, but at least 26 times each calendar year, to inspect the

surface conditions on or adjacent to each pipeline right-of-way.

Because some surface condition activities that affect the safety and

operation of pipelines are more visible from aerial patrols than from

walking or driving the right-of-way, RSPA proposed that the section be

changed to clarify that aerial patrols are an optional method of

compliance. No comments were received regarding the change and the

THLPSSC voted 10 to 0 in favor of the change (5 members did not vote).

Accordingly, the change to Sec. 195.412(a) is adopted as proposed.

Section (b) requires operators, at intervals not exceeding 5 years,

to inspect each crossing under a navigable waterway (except offshore)

to determine the condition of the crossing. The purpose of the

inspection is to look for any damage, unanticipated loading, or loss of

protection that could threaten the safety of the pipeline. We stated in

the NPRM that bored crossings are usually so deep that there is little

likelihood the pipeline could be affected by waterway-related events,

such as scouring or anchor dragging. We proposed to add an exception to

Sec. 195.412(b) to cover bored crossings that are too deep to be

subject to waterway-related damage.

The THLPSSC voted 10 to 0 in favor of the rule (5 members did not

vote). However, a state pipeline agency suggested the existing

regulation be retained. The agency stated that a pipeline operator

cannot be 100 percent sure a bored crossing is so deep it cannot be

affected as stated. RSPA received four additional comments, three of

which expressed an opinion that the phrase ``too deep to anticipate

damage from waterway conditions or vessel traffic'' is vague and

inappropriate. The other commenter said the proposal is unduly

restrictive and should be refocused from bored crossings to a more

generic performance standard potentially including all crossings.

In view of the comments received, RSPA agrees with those who opined

that ``too deep to anticipate damage from waterway conditions or vessel

traffic'' is too vague. In the absence of a recognized standard on the

subject, it is too speculative to judge when bored crossings are buried

at a sufficient depth to be safe from damage by external forces.

Therefore, it is in the interest of public safety that the current rule

requiring inspection at intervals not exceeding 5 years be retained.

Accordingly, the proposed change to Sec. 195.412(b) is not adopted.

Section 195.416 External Corrosion Control.

Section 195.416(a) states that each operator shall, at intervals

not exceeding 15 months, but at least once each calendar year, conduct

tests on each underground facility that is under cathodic protection to

determine whether protection is adequate. RSPA is clarifying the rule

to reduce any misunderstanding regarding what is meant by

``underground.'' The word ``underground'' in this paragraph has meant

any facility that is buried or in contact with the ground. This rule

clarification will not change the burden on operators because RSPA

compliance inspectors have consistently required any facility in

contact with the ground to be cathodically protected.

RSPA received two comments regarding the change to Sec. 195.416(a).

One commenter recommended that offshore pipelines be excluded from

annual testing requirements. RSPA believes there is no acceptable

substitute for regular testing to determine if corrosion protection of

all lines, both onshore and offshore, is adequate. Accordingly, ``in

contact with the ground or submerged'' is added to the rule to assure

that all underwater pipelines, both onshore and offshore, are included

in the definition. The other commenter suggested requiring the testing

of ``carrier pipes'' in casings. ``Carrier pipes'' are normally buried

and subject to the rule. The THLPSSC voted 10 to 0 in favor of the

proposed change (5 members did not vote). The revision to

Sec. 195.416(a) is adopted as modified.

Section 195.416(f) requires that any pipe found to be generally

corroded so that the remaining wall thickness is less than the minimum

thickness required by the pipe specification tolerances must either be

replaced with coated pipe that meets the requirements of part 195 or,

if the area is small, must be repaired. However, the operator need not

replace generally corroded pipe if the operating pressure is reduced to

be commensurate with the limits on operating pressure specified in

Sec. 195.406, based on the actual remaining wall thickness.

Section 195.416(g) states that if localized corrosion pitting is

found to exist to a degree where leakage might result, the pipe must be

replaced or repaired, or the operating pressure must be reduced

commensurate with the strength of the pipe based on the actual

remaining wall thickness in the pits.

RSPA recognizes that paragraphs (f) and (g) do not provide guidance

for an operator's use in determining the strength of the actual

remaining wall thickness of corroded steel pipe. To provide such

guidance, RSPA proposed amending Sec. 195.416(h) to adopt the ASME

Manual B31G procedure for determining the remaining strength of

corroded steel pipe in existing pipelines. Application of the procedure

was proposed to be in accordance with the limitations set out in the

B31G Manual. The rule would provide guidance as to whether a corroded

region (not penetrating the pipe wall) may be left in service; this

option might require a reduction in maximum allowable operating

pressure, but may be more economical than replacement or repair of the

corroded pipe.

Ten THLPSSC members voted for the proposal (5 members did not

vote).

Comments relative to Sec. 195.416(h) were received from five

commenters. One commenter said the proposal to change Sec. 195.416(h)

is inappropriate and should be redone to be consistent with

Sec. 192.485. Others stated that the proposal was unnecessarily

restrictive because it did not allow the use of other proven industry

developed methods for determining the remaining strength of corroded

pipelines. The most noteworthy method mentioned was ``A Modified

Criterion for Evaluating the Remaining Strength of Corroded Pipe (with

RSTRENG disk)'' developed by Battelle under the Pipeline Research

Committee of the American Gas Association (AGA). (Project PR 3-805,

December 1989, AGA catalog No. L51609). Project PR 3-805 was undertaken

to devise a modified criterion that, while still assuring pipeline

integrity, would eliminate as much as possible the excessive

specifications embodied in the ASME B31G manual. The AGA modified

criterion, using a complex analysis approach, can be carried out by

means of a PC-based program called RSTRENG. The modified criterion can

also be applied via tables or curves or a long-hand equation if a

simplified analysis is preferred.

The addition of the modified criterion to the rule does not

compromise safety because it merely accepts an established pipeline

industry guideline, and does not impose new requirements on the

operators. Accordingly, RSPA is amending Sec. 195.416(h) to include the

AGA/Battelle--A Modified Criterion for Evaluating the Remaining

Strength of Corroded Pipe (with the computer disk RSTRENG).

Rulemaking Analyses

Impact Assessment

This final rule is not considered a significant regulatory action

under section 3(f) of Executive Order 12866 and, therefore, was not

subject to review by the Office of Management and Budget. The rule is

not considered significant under the regulatory policies and procedures

of the Department of Transportation (44 FR 11034).

A Regulatory Evaluation has been prepared and is available in the

docket. RSPA estimates the proposed changes to existing rules would

result in an estimated savings of $1,534,000 per year for the hazardous

liquid pipeline industry at no cost to the industry, and with no

adverse effect on safety. As discussed above, these savings would come

largely from the use of new technology, greater flexibility in

constructing and operating pipelines, and the elimination of

unnecessary requirements.

Federalism Assessment

RSPA has analyzed the proposed rules under the criteria of

Executive Order 12612 (52 FR 41685; October 30, 1987). The regulations

have no substantial effects on the states, on the current federal-state

relationship, or on the current distribution of power and

responsibilities among the various levels of government. Thus,

preparation of a federalism assessment is not warranted.

Regulatory Flexibility Act

RSPA criteria for small companies or entities are those with less

than $1,000,000 in revenues and are independently owned and operated.

Few of the companies subject to this rulemaking meet these criteria.

Accordingly, based on the facts available concerning the impact of this

proposal, I certify under Section 605 of the Regulatory Flexibility Act

that this proposal would not have a significant economic impact on a

substantial number of small entities. This rule applies to intrastate

and interstate pipeline facilities used in the transportation of

hazardous liquids or carbon dioxide.

Paperwork Reduction Act

The documentation for the information collection requirements for

part 195 was submitted to the Office of Management and Budget (OMB)

during the original rulemaking processes. Currently, regulations in

part 195 are covered by OMB Control Numbers 2137-0047 (approved through

May 31, 1994), 2137-0578 (approved through October 31, 1994) and 2137-

0583 (approved through May 31, 1994). There are no new information

collection requirements in this final rule.

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, RSPA is amending 49 CFR part 195

as follows:

PART 195--[AMENDED]

1. The authority citation for part 195 continues to read as

follows:

Authority: 49 app. U.S.C. 2002 and 2015; and 49 CFR 1.53.

2. In Sec. 195.1, the introductory text of paragraph (b) is

republished, paragraph (b)(5) is revised, in paragraph (b)(6) a hyphen

is added between the words ``in'' and ``plant'', and paragraphs (b)(7)

and (b)(8) are revised to read as follows:

Sec. 195.1 Applicability.

* * * * *

(b) This part does not apply to--

* * * * *

(5) Transportation of hazardous liquid or carbon dioxide in

offshore pipelines which are located upstream from the outlet flange of

each facility where hydrocarbons or carbon dioxide are produced or

where produced hydrocarbons or carbon dioxide are first separated,

dehydrated, or otherwise processed, whichever facility is farther

downstream;

* * * * *

(7) Transportation of hazardous liquid or carbon dioxide--

(i) By vessel, aircraft, tank truck, tank car, or other non-

pipeline mode of transportation; or

(ii) Through facilities located on the grounds of a materials

transportation terminal that are used exclusively to transfer hazardous

liquid or carbon dioxide between non-pipeline modes of transportation

or between a non-pipeline mode and a pipeline, not including any device

and associated piping that are necessary to control pressure in the

pipeline under Sec. 195.406(b); and

(8) Transportation of carbon dioxide downstream from the following

point, as applicable:

(i) The inlet of a compressor used in the injection of carbon

dioxide for oil recovery operations, or the point where recycled carbon

dioxide enters the injection system, whichever is farther upstream; or

(ii) The connection of the first branch pipeline in the production

field that transports carbon dioxide to injection wells or to headers

or manifolds from which pipelines branch to injection wells.

* * * * *

3. In Sec. 195.2, the introductory text is republished, definitions

for Corrosive product, Flammable product, In-plant piping system,

Petroleum, Petroleum product, and Toxic product are added in

alphabetical order to read as follows:

Sec. 195.2 Definitions.

As used in this part--

* * * * *

Corrosive product means ``corrosive material'' as defined by

Sec. 173.136 Class 8-Definitions of this chapter.

* * * * *

Flammable product means ``flammable liquid'' as defined by

Sec. 173.120 Class 3-Definitions of this chapter.

* * * * *

In-plant piping system means piping that is located on the grounds

of a plant and used to transfer hazardous liquid or carbon dioxide

between plant facilities or between plant facilities and a pipeline or

other mode of transportation, not including any device and associated

piping that are necessary to control pressure in the pipeline under

Sec. 195.406(b).

* * * * *

Petroleum means crude oil, condensate, natural gasoline, natural

gas liquids, and liquefied petroleum gas.

Petroleum product means flammable, toxic, or corrosive products

obtained from distilling and processing of crude oil, unfinished oils,

natural gas liquids, blend stocks and other miscellaneous hydrocarbon

compounds.

* * * * *

Toxic product means ``poisonous material'' as defined by

Sec. 173.132 Class 6, Division 6.1-Definitions of this chapter.

Secs. 195.2, 195.112, 195.212, 195.413 [Amended]

4. In the list below, for each section indicated in the left

column, the phrase indicated in the middle column is removed and the

phrase indicated in the right column is added:

----------------------------------------------------------------------------------------------------------------

Section Remove Add

----------------------------------------------------------------------------------------------------------------

195.2, Gathering line............... 8 inches or less in nominal diameter 219.1 mm (8\5/8\ in) or less nominal

outside diameter.

195.112(c).......................... An outside diameter of 4 inches or A nominal outside diameter of 114.3

more. mm (4\1/2\ in) or more.

195.212(b)(3)(ii)................... The pipe is 12 inches or less in The pipe is 323.8 mm (12\3/4\ in) or

outside diameter. less nominal outside diameter.

195.413(a).......................... Except for gathering lines of 4-inch Except for gathering lines of 114.3

nominal diameter or smaller. mm (4\1/2\ in) nominal outside

diameter or smaller.

----------------------------------------------------------------------------------------------------------------

5. In Sec. 195.3, paragraph (a) is revised to read as follows:

Sec. 195.3 Matter incorporated by reference.

(a) Any document or portion thereof incorporated by reference in

this part is included in this part as though it were printed in full.

When only a portion of a document is referenced, then this part

incorporates only that referenced portion of the document and the

remainder is not incorporated. Applicable editions are listed in

paragraph (c) of this section in parentheses following the title of the

referenced material. Earlier editions listed in previous editions of

this section may be used for components manufactured, designed, or

installed in accordance with those earlier editions at the time they

were listed. The user must refer to the appropriate previous edition of

49 CFR for a listing of the earlier editions.

* * * * *

6. In Sec. 195.3, paragraphs (b)(1) through (b)(5) are redesignated

as paragraphs (b)(2) through (b)(6) and paragraph (b)(1) is added to

read as follows:

Sec. 195.3 Matter incorporated by reference.

* * * * *

(b) * * *

(1) American Gas Association (AGA), 1515 Wilson Boulevard,

Arlington, VA 22209.

* * * * *

7. In Sec. 195.3, paragraphs (c)(2)(iii) and (c)(2)(iv) are

redesignated as paragraphs (c)(2)(v) and (c)(2)(vi) and paragraphs

(c)(2)(iii) and (c)(2)(iv) are added to read as follows:

Sec. 195.3 Matter incorporated by reference.

* * * * *

(c) * * *

(2) * * *

(iii) ASME/ANSI B31.8 ``Gas Transmission and Distribution Piping

Systems'' (1989 with ASME/ANSI B31.8a-1990, B31.8b-1990, B31.8c-1992

Addenda and Special Errata issued July 6, 1990 and Special Errata

(Second) issued February 28, 1991).

(iv) ASME/ANSI B31G, ``Manual for Determining the Remaining

Strength of Corroded Pipelines'' (1991).

* * * * *

8. In Sec. 195.3, paragraphs (c)(1) through (c)(4) are redesignated

as paragraphs (c)(2) through (c)(5) and paragraph (c)(1) is added to

read as follows:

Sec. 195.3 Matter incorporated by reference.

* * * * *

(c) * * *

(1) American Gas Association (AGA): AGA Pipeline Research

Committee, Project PR-3-805, ``A Modified Criterion for Evaluating the

Remaining Strength of Corroded Pipe'' (December 1989). The RSTRENG

program may be used for calculating remaining strength.

* * * * *

9. Section 195.5 is amended by revising paragraphs (a)(1) and

(a)(4) to read as follows:

Sec. 195.5 Conversion to service subject to this part.

(a) * * *

(1) The design, construction, operation, and maintenance history of

the pipeline must be reviewed and, where sufficient historical records

are not available, appropriate tests must be performed to determine if

the pipeline is in satisfactory condition for safe operation. If one or

more of the variables necessary to verify the design pressure under

Sec. 195.106 or to perform the testing under paragraph (a)(4) of this

section is unknown, the design pressure may be verified and the maximum

operating pressure determined by--

(i) Testing the pipeline in accordance with ASME B31.8, Appendix N,

to produce a stress equal to the yield strength; and

(ii) Applying, to not more than 80 percent of the first pressure

that produces a yielding, the design factor F in Sec. 195.106(a) and

the appropriate factors in Sec. 195.106(e).

* * * * *

(4) The pipeline must be tested in accordance with subpart E of

this part to substantiate the maximum operating pressure permitted by

Sec. 195.406.

* * * * *

10. Section 195.50(f) is revised to read as follows:

Sec. 195.50 Reporting accidents.

* * * * *

(f) Estimated property damage, including cost of clean-up and

recovery, value of lost product, and damage to the property of the

operator or others, or both, exceeding $50,000.

11. Section 195.52(a)(3) is revised to read as follows:

Sec. 195.52 Telephonic notice of certain accidents.

(a) * * *

(3) Caused estimated property damage, including cost of cleanup and

recovery, value of lost product, and damage to the property of the

operator or others, or both, exceeding $50,000;

* * * * *

12. Section 195.106(b) is revised to read as follows:

Sec. 195.106 Internal design pressure.

* * * * *

(b) The yield strength to be used in determining the internal

design pressure under paragraph (a) of this section is the specified

minimum yield strength. If the specified minimum yield strength is not

known, the yield strength to be used in the design formula is one of

the following:

(1)(i) The yield strength determined by performing all of the

tensile tests of API Specification 5L on randomly selected specimens

with the following number of tests:

------------------------------------------------------------------------

Pipe size No. of tests

------------------------------------------------------------------------

Less than 168.3 mm (6\5/8\ in) One test for each 200 lengths.

nominal outside diameter.

168.3 through 323.8 mm (6\5/8\ One test for each 100 lengths.

through 12\3/4\ in) nominal

outside diameter.

Larger than 323.8 mm (12\3/4\ in) One test for each 50 lengths.

nominal outside diameter.

------------------------------------------------------------------------

(ii) If the average yield-tensile ratio exceeds 0.85, the yield

strength shall be taken as 165,474 kPa (24,000 psi). If the average

yield-tensile ratio is 0.85 or less, the yield strength of the pipe is

taken as the lower of the following:

(A) Eighty percent of the average yield strength determined by the

tensile tests.

(B) The lowest yield strength determined by the tensile tests.

(2) If the pipe is not tensile tested as provided in paragraph (b)

of this section, the yield strength shall be taken as 165,474 kPa

(24,000 psi).

* * * * *

13. In Sec. 195.106(c), the last sentence is revised to read as

follows:

Sec. 195.106 Internal design pressure.

* * * * *

(c) * * * However, the nominal wall thickness may not be more than

1.14 times the smallest measurement taken on pipe that is less than 508

mm (20 in) nominal outside diameter, nor more than 1.11 times the

smallest measurement taken on pipe that is 508 mm (20 in) or more in

nominal outside diameter.

* * * * *

14. In Sec. 195.204, the last sentence is revised to read as

follows:

Sec. 195.204 Inspection--general.

* * * No person may be used to perform inspections unless that

person has been trained and is qualified in the phase of construction

to be inspected.

15. Section 195.228(b) is revised to read as follows:

Sec. 195.228 Welds and welding inspection: Standards of acceptability.

* * * * *

(b) The acceptability of a weld is determined according to the

standards in section 6 of API Standard 1104. However, if a girth weld

is unacceptable under those standards for a reason other than a crack,

and if the Appendix to API Standard 1104 applies to the weld, the

acceptability of the weld may be determined under that appendix.

16. Section 195.234 is amended by revising the introductory text of

paragraph (e) and by revising paragraph (g) to read as follows:

Sec. 195.234 Welds: Nondestructive testing.

* * * * *

(e) All girth welds installed each day in the following locations

must be nondestructively tested over their entire circumference, except

that when nondestructive testing is impracticable for a girth weld, it

need not be tested if the number of girth welds for which testing is

impracticable does not exceed 10 percent of the girth welds installed

that day:

* * * * *

(g) At pipeline tie-ins, including tie-ins of replacement sections,

100 percent of the girth welds must be nondestructively tested.

17. Section 195.246 is amended by revising paragraph (b) to read as

follows:

Sec. 195.246 Installation of pipe in a ditch.

* * * * *

(b) Except for pipe in the Gulf of Mexico and its inlets, all

offshore pipe in water at least 3.7 m 12-ft-deep but not more than 61 m

(200 ft) deep, as measured from the mean low tide, must be installed so

that the top of the pipe is below the natural bottom unless the pipe is

supported by stanchions, held in place by anchors or heavy concrete

coating, or protected by an equivalent means.

18. Section 195.248 is amended by revising in the first column of

the table in paragraph (a) the language ``Other offshore areas under

water less than 12-ft-deep as measured from the mean low tide'' to read

``Gulf of Mexico and its inlets and other offshore areas under water

less than 12-ft-deep as measured from the mean low tide'' and by

revising the introductory text of paragraph (b) to read as follows:

Sec. 195.248 Cover over buried pipeline.

* * * * *

(b) Except for the Gulf of Mexico and its inlets, less cover than

the minimum required by paragraph (a) of this section and Sec. 195.210

may be used if--

* * * * *

19. Section 195.262(d) is revised to read as follows:

Sec. 195.262 Pumping equipment.

* * * * *

(d) Except for offshore pipelines, pumping equipment must be

installed on property that is under the control of the operator and at

least 15.2 m (50 ft) from the boundary of the pump station.

* * * * *

20. The introductory text of Sec. 195.304(b) is revised to read as

follows:

Sec. 195.304 Testing of components.

* * * * *

(b) A component, other than pipe, that is the only item being

replaced or added to the pipeline system need not be hydrostatically

tested under paragraph (a) of this section if the manufacturer

certifies that either--

* * * * *

21. Section 195.406 is amended by republishing the introductory

text of paragraph (a) and revising paragraph (a)(1) to read as follows:

Sec. 195.406 Maximum operating pressure.

(a) Except for surge pressures and other variations from normal

operations, no operator may operate a pipeline at a pressure that

exceeds any of the following:

(1) The internal design pressure of the pipe determined in

accordance with Sec. 195.106. However, for steel pipe in pipelines

being converted under Sec. 195.5, if one or more factors of the design

formula (Sec. 195.106) are unknown, one of the following pressures is

to be used as design pressure:

(i) Eighty percent of the first test pressure that produces yield

under section N5.0 of Appendix N of ASME B31.8, reduced by the

appropriate factors in Secs. 195.106 (a) and (e); or

(ii) If the pipe is 323.8 mm (12\3/4\ in) or less outside diameter

and is not tested to yield under this paragraph, 1379 kPa (200 psig).

* * * * *

22. Section 195.412(a) is revised to read as follows:

Sec. 195.412 Inspection of rights-of-way and crossings under navigable

waters.

(a) Each operator shall, at intervals not exceeding 3 weeks, but at

least 26 times each calendar year, inspect the surface conditions on or

adjacent to each pipeline right-of-way. Methods of inspection include

walking, driving, flying or other appropriate means of traversing the

right-of-way.

* * * * *

23. Section 195.416 is amended by revising paragraph (a),

redesignating paragraph (h) as paragraph (i) and adding a new paragraph

(h) to read as follows:

Sec. 195.416 External corrosion control.

(a) Each operator shall, at intervals not exceeding 15 months, but

at least once each calendar year, conduct tests on each buried, in

contact with the ground, or submerged pipeline facility in its pipeline

system that is under cathodic protection to determine whether the

protection is adequate.

* * * * *

(h) The strength of the pipe, based on actual remaining wall

thickness, for paragraphs (f) and (g) of this section may be determined

by the procedure in ASME B31G manual for Determining the Remaining

Strength of Corroded Pipelines or by the procedure developed by AGA/

Battelle--A Modified Criterion for Evaluating the Remaining Strength of

Corroded Pipe (with RSTRENG disk). Application of the procedure in the

ASME B31G manual or the AGA/Battelle Modified Criterion is applicable

to corroded regions (not penetrating the pipe wall) in existing steel

pipelines in accordance with limitations set out in the respective

procedures.

* * * * *

Issued in Washington, DC, on June 9, 1994.

Ana Sol Gutierrez,

Acting Administrator, Research and Special Programs Administration.

[FR Doc. 94-15510 Filed 6-27-94; 8:45 am]

BILLING CODE 4910-60-P