Regulatory Review; Gas Pipeline Safety Standards

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 192

[Docket PS-124; Amdt. 192-76]

RIN 2137-AC25

Regulatory Review; Gas Pipeline Safety Standards

AGENCY: Research and Special Programs Administration (RSPA), DOT.

ACTION: Final rule.

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SUMMARY: This final rule changes miscellaneous gas pipeline safety

regulations to provide clarity, eliminate unnecessary or burdensome

requirements, and foster economic growth. The changes result from a

comprehensive review of the regulations RSPA has completed under

President Clinton's Regulatory Reinvention Initiative to reduce the

burden of government regulations. The changes are intended to reduce

the costs of compliance without compromising safety.

EFFECTIVE DATE: This final rule is effective July 8, 1996. The

incorporation by reference of certain publications listed in the

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

July 8, 1996.

FOR FURTHER INFORMATION CONTACT: A. C. Garnett, (202) 366-2036, or L.

M. Furrow, (202) 366-4559, regarding the subject matter of this

amendment, or the Dockets Unit, (202) 366-5046 regarding copies of this

amendment or other material in the docket.

SUPPLEMENTARY INFORMATION:

Background

Early in 1992, RSPA began an extensive review of the federal gas

pipeline safety regulations (49 CFR part 192) and invited the public to

participate (57 FR 4745, Feb. 7, 1992). The review was to see what

changes were necessary to provide clarity, eliminate unnecessary or

overly burdensome requirements, and foster economic growth. As a result

of the review, RSPA published a Notice of Proposed Rulemaking (NPRM),

proposing changes to 38 regulations in part 192 (Notice 1; 57 FR 39572,

Aug. 31, 1992).

Then the National Association of Pipeline Safety Representatives

(NAPSR) reported on a separate but related review of part 192. RSPA had

asked NAPSR to identify regulations in part 192 that may not assure

safety or

[[Page 28771]]

that may be hard to enforce. Because the NAPSR report concerned a few

of the regulations covered by the NPRM and had similar goals, we

published the report and requested public comment on its various

recommended rule changes (Notice 2; 58 FR 59431, Nov. 9, 1993). At the

same time, we announced that in developing final rules under the NPRM,

we would consider comments on any NAPSR recommendations that addressed

the same issues as the NPRM. The period for public comment on the NAPSR

recommendations was extended 90 days until April 11, 1994 (Notice 3; 58

FR 68382, Dec. 27, 1993).

Later on, President Clinton launched the Regulatory Reinvention

Initiative (memorandum for Heads of Departments and Agencies; March 4,

1995), which, among other things, directed DOT and other Federal

agencies to review and revise existing regulations to remove

unnecessary or burdensome requirements. Today's publication of this

Final Rule is a major step in carrying out that directive with respect

to DOT's pipeline safety regulations.

Advisory Committee

The Technical Pipeline Safety Standards Committee (TPSSC),

consisting of 15 members, was established by statute to consider the

feasibility, reasonableness, and practicability of proposed pipeline

safety regulations. In developing the final regulations, RSPA

considered all final TPSSC votes and comments on the NPRM, including

minority positions. A more detailed consideration of the TPSSC action

is contained in the following section-by-section discussion of

comments. A record of the TPSSC deliberation is available in the

docket.

Discussion of Comments

RSPA received comments on the NPRM from 36 pipeline operators, 9

pipeline-related associations, 1 state agency, and 8 other commenters.

More commenters submitted views on the NAPSR recommendations: 58

pipeline operators, 10 pipeline-related associations, 4 state agencies,

and 5 other commenters.

The following discussion on development of the final rules explains

how we treated TPSSC positions, comments on the NPRM, and comments on

NAPSR recommendations related to NPRM proposals (Secs. 192.3, 192.475,

192.485, and 192.607). We appreciate the comments on NAPSR

recommendations that were not related to NPRM proposals. They will help

us decide appropriate responses to those recommendations in an action

separate from this rulemaking.

Small Gas Systems. The NPRM invited comments on the idea of whether

RSPA should develop separate, more appropriate safety standards for

small gas distribution systems. Such systems include master meter

systems and petroleum gas systems serving mobile home or apartment

complexes.

Although TPSSC did not address this matter, RSPA received comments

from two pipeline operators, one state agency, and one mobile home

association. The state agency said that it is not clear that separate

regulations are required. This commenter suggested that a less

complicated remedy might be to excerpt those portions of the

regulations specifically applicable to small operators (deleting, for

example, sections applicable to transmission lines) and publish the

result as a guide or as instructional material.

Three commenters supported the need for more appropriate standards

for small gas distribution systems. A mobile home association endorsed

the idea of developing standards for small gas distribution systems,

such as master-meter systems serving mobile home parks, and publishing

the standards as a new part of title 49 of the Code of Federal

Regulations. The mobile home association commented that if it were not

for the Guidance Manual for Operators of Small Gas Systems published by

RSPA, the average mobile home park operator would have difficulty

determining which regulations in part 192 apply to master-meter

systems.

RSPA believes that each of the suggestions has merit and will be

useful in developing future pipeline safety agendas.

Section 192.1, Scope of Part

Section 192.1(b)(1) excepts from the scope of part 192 certain

gathering lines on the outer continental shelf (OCS), but does not

except similar gathering lines located in State offshore waters.

Section 192.1(b)(1) reads as follows: ``This part does not apply to * *

* (o)ffshore gathering of gas upstream from the outlet flange of each

facility on the outer continental shelf where hydrocarbons are produced

or where produced hydrocarbons are first separated, dehydrated, or

otherwise processed, whichever facility is farther downstream.''

Because RSPA treats OCS and State offshore gathering alike under part

192, we proposed to delete the phrase ``on the outer continental

shelf'' so the exception would cover offshore gathering no matter where

located. We also proposed to replace ``offshore gathering of gas'' with

``offshore pipelines,'' recognizing that the excepted pipelines may be

either production or gathering lines.

Twelve TPSSC members voted for the proposal, two supported it but

recommended a change, one member opposed it, and one abstained. The

recommended change was that ``gathering of gas'' should be retained in

Sec. 192.1(b)(1), since proposed Sec. 192.9 refers to gathering under

Sec. 192.1.

We did not adopt the TPSSC minority's recommended change because

the excepted pipelines located upstream from the referenced offshore

facilities may be either production lines or gathering lines. Also, the

term ``offshore pipelines'' was used in a similar revision of 49 CFR

195.1(b)(5) that we made to clarify the jurisdiction of the hazardous

liquid pipeline regulations over offshore pipelines (Docket PS-127; 59

FR 33388; June 28, 1994). As discussed below under the Sec. 192.9

heading, Sec. 192.9 has already been revised to cross-reference

Sec. 192.1. Since the cross- reference does not refer specifically to

gathering lines, deleting the words ``gathering of gas'' from

Sec. 192.1(b)(1) should not hinder the understanding of Sec. 192.9.

RSPA received 14 comments on the proposed rule change, nine from

operators, four from pipeline-related associations, and one from a

state agency. None of these comments opposed the proposal to change

Sec. 192.1(b)(1).

Section 192.3, Definitions

1. Petroleum Gas. A revised definition of ``petroleum gas'' is

discussed below under the Sec. 192.11 heading.

2. Secretary. The proposed revision of the definition of

``Secretary'' is no longer needed. Because the term ``Secretary'' is

not used in part 192, the definition of ``Secretary'' was removed from

Sec. 192.3 in an earlier rulemaking (59 FR 17281; April 12, 1994).

3. Transmission Line. A longstanding RSPA interpretation holds that

the definition of ``transmission line'' in Sec. 192.3 encompasses lines

that link gathering lines or transmission lines to large volume

customers, such as factories or power plants. This interpretation was

founded on the definition of ``transmission line'' in the 1968 edition

of the American Society of Mechanical Engineers [ASME] B31.8 Code. This

code, which was the cornerstone of part 192, defined transmission to

end at large volume customers. RSPA proposed to codify the

interpretation by restating the definition of ``transmission line''

under part 192 to

[[Page 28772]]

include a ``large volume customer'' as an end point of transmission.

Eleven TPSSC members voted for the proposal, three supported it

with a recommended change, and one abstained. The members who

recommended a change thought that RSPA should define ``large volume

customer.'' As discussed further below, the final definition includes

an explanation of this term.

Twenty-six entities commented on the NPRM proposal, including 19

pipeline operators, five pipeline-related associations, one state

agency, and one industrial consumer. Of these commenters, only eight

expressed unqualified support. Three commenters completely opposed the

proposal, saying it was not needed or would create confusion.

RSPA continues to believe that the proposed change is needed. The

present definition does not reflect RSPA's interpretation that the term

``transmission line'' includes pipelines that connect large volume

customers to gathering or transmission lines.

Nine commenters thought the proposed definition would reclassify as

transmission those pipelines that connect large volume customers to

high pressure distribution lines. RSPA did not intend for the proposed

change to alter the classification of distribution lines that supply

large volume customers. To avoid this unintended outcome, the

definition explicitly does not include lines serving large volume

customers downstream from a distribution center.

Four commenters said that the volume of gas transported is not an

appropriate indicator of transmission. This group suggested that

engineering characteristics, such as high pressure, stress level, or

connection to a pressure limiting station are more indicative of

transmission than the volume of gas transported. However, the purpose

of the transmission proposal was not to open discussion on whether

volume is an appropriate indicator of transmission. The purpose was to

recognize that, by interpretation of the present definition, volume

already is an established indicator of transmission, and that the

interpretation should be codified. None of the commenters challenged

the correctness of the interpretation. Moreover, before publishing the

proposed definition, we referred to the 1992 edition of the ASME B31.8

Code, a widely recognized code of voluntary standards for gas piping.

Section 803.21 of the ASME B31.8 Code (1992 edition) defined

``transmission line'' as ``pipe installed for the purpose of

transmitting gas from a source or sources of supply to one or more

distribution centers or to one or more large volume customers * * *''

(emphasis added). And this definition is the same in the current 1995

edition of the code. Given our longstanding interpretation and the ASME

B31.8 Code definition, we find it reasonable to add ``large volume

customer'' to the definition of transmission line as proposed.

Three commenters wanted RSPA to define ``large volume customer.''

We agree that an explanation of ``large volume customer'' would make

the final definition more precise. Thus, we added a statement to the

final definition to explain that ``large volume customer'' includes

factories, power plants, and institutional users of gas.

We did not specify a minimum volume of gas a pipeline must

transport to a customer to qualify as transmission. Volumes vary, and

setting an arbitrary threshold might unfairly reclassify some existing

lines. However, since ``large volume customer'' and ``distribution

center'' each mark the end of transmission under the definition,

operators may use the volume of gas supplied to distribution centers as

a guide to identifying large volume customers.

The NAPSR report recommended changing the part 192 definition of

``transmission line'' so that pipelines beginning at gathering or

transmission lines and ending at ``distribution systems and other load

centers'' would be classified as transmission lines. Under this

alternative wording, load centers conceivably would include large

volume customers.

Most of the persons who commented directly on this NAPSR

recommendation opposed it. A primary objection was that the recommended

definition would needlessly reclassify as transmission low stress

pipelines between communities or between distribution systems and high

pressure transmission lines. In this regard, many commenters felt

transmission should be limited to pipelines that operate at 20 percent

or more of specified minimum yield strength (SMYS) of pipe, one of the

characteristics under the present definition. The lack of definition of

the term ``load center'' was another frequently stated reason for

opposing the NAPSR recommendation. Commenters argued that introducing

this term into the definition would lead to more, not less, confusion.

Also several commenters thought the definition of transmission line

should remain unchanged until RSPA completes its project to redefine

the term ``gathering line,'' which appears in the transmission line

definition. After considering these concerns, we agree that the NAPSR

recommendation would not strengthen the present definition and could

cause reclassification of many lines. Therefore, we did not adopt the

recommendation in the final definition.

Section 192.5, Class Locations

RSPA proposed to clarify Sec. 192.5 to minimize the possibility

that a pipeline is classified higher than required. Inasmuch as part

192 regulations become more stringent as pipeline classification

increases, any over- classification results in needless expenditures.

Fourteen TPSSC members voted for the proposal and one abstained.

Eight operators and one pipeline-related association commented on the

proposed change. While these commenters generally supported the need to

clarify Sec. 192.5, two operators suggested alternative wording. Based

on one suggestion, RSPA has combined proposed Secs. 192.5 (c)(2) and

(c)(3) into final Sec. 192.5(c)(2).

One focus of the NPRM was the cluster exception in existing

Secs. 192.5(f)(2) and (f)(3). This exception provides that if a cluster

of buildings intended for human occupancy requires a Class 2 or 3

location, the classification ends 220 yards from the nearest building

in the cluster, rather than at the end of the 1-mile class location

unit that would otherwise be the basis for classification. In the NPRM

(at 39573), we stated that adding buildings outside a cluster to those

inside the cluster would result in over-classification of the class

location unit. However, this statement was incorrect. The history of

Sec. 192.5 (35 FR 13251, August 19, 1970) shows that the cluster

exception applies only when all buildings in a 1-mile class location

unit are in a single cluster. If a class location unit contains

buildings outside a cluster or more than one cluster of buildings, all

buildings in the unit must be counted to determine the classification

of the unit. The final rule clarifies this point.

The association that commented thought we should define the term

``cluster.'' However, the term is used in its ordinary dictionary

sense, and, in RSPA's experience, has not been a significant source of

misunderstanding.

Section 192.7, Incorporation by Reference

Section 192.7 describes the incorporation by reference in part 192

of documents or portions of documents relevant to gas pipeline safety.

RSPA proposed to revise Sec. 192.7(a) to clarify that when a regulation

in part 192

[[Page 28773]]

references a document, the entire document is not necessarily

incorporated by reference. Rather, only those portions of the document

that are specifically referenced in the regulation or are essential for

compliance with the regulation are incorporated by reference. Such

portions may or may not comprise the whole document, depending on the

scope of the reference.

Fourteen TPSSC members voted for the proposal and one abstained.

Commenters on the proposed change, seven operators and one pipeline-

related association, all favored the proposal. However, two of these

commenters wanted RSPA to change the rule in a manner not proposed.

They advised changing Sec. 192.7 to require operators to follow the

latest published editions of documents, instead of particular editions,

which can become obsolete before RSPA updates the references. RSPA

believes this recommended action is inappropriate because it would hand

over an established governmental function, rulemaking, to the private

organizations who produce the referenced documents. Each newly

published edition would automatically change a pipeline safety rule and

bypass the Federal rulemaking process, which ensures fair treatment of

all affected parties.

Section 192.9, Gathering Lines

When the NPRM was published, Sec. 192.9 required gathering lines to

comply with part 192 standards applicable to transmission lines without

indicating that certain gathering lines are excepted from part 192 by

Sec. 192.1. To highlight this exception and provide a clear

understanding of which gathering lines must meet transmission line

standards, we proposed to cross-reference Sec. 192.1 in Sec. 192.9.

Thirteen TPSSC members voted for the proposal and two abstained.

RSPA received seven comments on the proposed change, six from operators

and one from a pipeline-related association. Only one commenter opposed

the proposal, saying it did not see how the change would clarify the

present rule.

Then in 1994, in a separate, unrelated action concerning the

passage of pigs, RSPA revised Sec. 192.9 to include a cross-reference

to Sec. 192.1 (59 FR 17281, April 12, 1994). Thus, Sec. 192.9 has

already been changed consistent with the proposal in this proceeding,

and no further action is necessary.

Section 192.11, Petroleum Gas Systems (Including Changes to Secs. 192.1

and 192.3)

RSPA proposed several changes to the special rules in Sec. 192.11

for petroleum gas systems: First, we proposed to require that peak

shaving plants supplying petroleum gas by pipeline to a natural gas

distribution system as well as pipeline systems transporting only

petroleum gas or petroleum gas/air mixtures comply with part 192

standards and the National Fire Protection Association (NFPA) Standards

58 and 59. Downstream from the point where a peak shaving plant injects

petroleum gas into a natural gas distribution system, only part 192

would apply. Next, we proposed that the NFPA Standards prevail in the

event of a conflict between part 192 and NFPA Standards 58 or 59. At

the same time, we said that a conflict does not exist when NFPA

Standards 58 and 59 are silent or nonspecific on a subject (such as for

corrosion protection or leak detection). In this case, the operator

would have to comply with any applicable part 192 rule. Finally, we

proposed to add a definition of ``petroleum gas'' to Sec. 192.3, and to

clarify under Sec. 192.1(b)(4) which petroleum gas systems are excepted

from part 192.

Ten TPSSC members voted for the proposal, one member supported it

with a recommended change, three members opposed it, and one abstained.

Two TPSSC members disagreed with the proposal that NFPA standards

should prevail in the event of a conflict with part 192. One TPSSC

member voted yes, but recommended that in the event of conflict the

most stringent requirement should prevail.

We explained in the NPRM why we believe the NFPA standards should

have priority in direct conflict situations. The main reason is that in

contrast to part 192, the NFPA Standards specifically cover petroleum

gas transportation. Also, NFPA Standards 58 and 59 reflect current

petroleum gas technology and safety practices. Given this special

attention to petroleum gas, we do not think there is sufficient reason

to require operators to follow part 192 instead of the NFPA Standards

in the event of conflict, even if part 192 is more stringent.

RSPA received eight comments in favor and three comments in

opposition to the proposed changes to Sec. 192.11. Those commenters who

opposed the proposal were concerned that compliance with NFPA Standards

58 and 59 would involve significant capital expenditures. However,

Sec. 192.11 already requires petroleum gas systems to meet NFPA

Standards 58 and 59. And, in accordance with 49 U.S.C. Sec. 60104(b),

none of the design, installation, construction, initial testing, or

initial inspection requirements of NFPA Standards 58 and 59 would apply

under part 192 to peak shaving plants now in existence. So,

retrofitting existing plants would not be required. Although all plants

would have to comply with the operation and maintenance requirements of

NFPA Standards 58 and 59, overall compliance costs should be small

because, as NFPA stated in its petition, most, if not all, existing

plants already comply with NFPA Standards 58 and 59 to qualify for

insurance coverage. Thus, Sec. 192.11 is revised as proposed in the

NPRM.

Proposed Sec. 192.1(b)(4)(i) would exclude from part 192 pipeline

systems that transport only petroleum gas or petroleum gas/air mixtures

to fewer than 10 customers, if no portion of the system is located in a

public place. This exclusion is in the present Sec. 192.11(a), but in

proposing to relocate it to Sec. 192.1(b)(4)(i), we omitted the

parenthetical phrase ``(such as a highway).'' One commenter objected to

the omission, saying it would leave the meaning of ``public place''

open to interpretation. However, our experience has been that the

parenthetical phrase has hindered more than helped the understanding of

public place. We have consistently interpreted ``public place'' to mean

a place which is generally open to all persons in a community as

opposed to being restricted to specific persons. We consider churches,

schools, and commercial property as well as any publicly owned right-

of-way or property which is frequented by persons to be public places.

Although Sec. 192.11(a) refers to a highway as an example of a public

place, many operators have incorrectly considered the example to

restrict, rather than define, the coverage of petroleum gas systems

with fewer than 10 customers.

Proposed Sec. 192.1(b)(4)(ii) would clarify that part 192 does not

apply to single-tank, single-customer petroleum gas systems located

entirely on the customer's premises, but partially in a public place.

These systems exist, for example, at churches or restaurants, where the

gas is used for heating or cooking. The proposal was based on the

jurisdiction of part 192 over the distribution of gas. As indicated by

the definition of ``service line'' (Sec. 192.3), part 192 does not

apply to gas distribution beyond the point where metered gas enters

customer piping. For single-tank, single-customer systems on the

customer's premises, this point normally occurs at the tank.

Three commenters protested that part 192 would still apply to

single-customer, multi-tank systems on the customer's premises,

regardless of tank size. For example, the proposed rule

[[Page 28774]]

would not exclude a two-tank system partly in a public place, even if

the total quantity of stored gas is less than in a large single-tank

system. Because the proposed exclusion did not rest on the quantity of

gas delivered to the customer, we agree that the number of tanks should

not be a factor in the exclusion of single-customer systems on the

customer's premises. Therefore, final Sec. 192.1(b)(4)(ii) omits the

term ``single-tank.''

The proposed definition of ``petroleum gas'' drew no objections

from either the TPSSC or commenters. So the definition is adopted as

proposed.

Sections 192.14 and 192.553, Conversion and Uprating

If a steel pipeline to be converted to gas service under part 192

has not been designed and constructed to meet part 192 standards, it

must be converted according to Sec. 192.14 (Sec. 192.13(a)(2)). Section

192.14(a)(4) requires that each pipeline must be pressure tested under

subpart J of part 192 to substantiate the maximum allowable operating

pressure (MAOP) permitted by subpart L of part 192. Under subpart L, to

compute the MAOP of a pipeline being converted, an operator must

determine the design pressure of the weakest element of the pipeline

(Sec. 192.619(a)(1)).

Design pressure is also a factor under Sec. 192.553, which

establishes general requirements for increasing any pipeline's MAOP

(uprating). Under Sec. 192.553(d), an increased maximum allowable

operating pressure may not exceed the MAOP part 192 allows for a new

pipeline constructed of the same materials in the same location. Thus,

to uprate a pipeline within this MAOP limit, an operator must determine

the design pressure of the weakest element of the pipeline

(Sec. 192.619(a)(1)).

Because of the role of design pressure, a steel pipeline may not be

converted or uprated when any of the pipe characteristics needed to

calculate design pressure under Sec. 192.105 is unknown. Therefore,

RSPA proposed to amend Secs. 192.14(a)(1) and 192.553(d) to permit the

conversion or uprating of steel pipelines based on an approach found in

paragraph 845.214 and Appendix N of the ASME B31.8 Code. Under the

proposal, when design pressure is unknown, operators would have to

pressure test the pipeline under Appendix N until pipe yield occurs.

The first pressure that produces pipe yield, reduced by 20 percent and

the appropriate factor under Sec. 192.619(a)(2)(ii), would be used

instead of design pressure to calculate MAOP.

Twelve TPSSC members voted for the proposed revision of

Sec. 192.14, one member supported it with a recommended change, one

member opposed it but suggested changes, and one member abstained.

Eleven members voted for the proposal regarding Sec. 192.553, two

supported it with a recommended change, one opposed it, and one

abstained. The recommended changes were to make yield testing mandatory

instead of permissive, and to allow yield testing that is based on

other than the ``first pressure'' that produces yield, since Appendix N

does not use that term. The reasons against the proposal were that

yield testing appeared to be mandatory, and use of the Appendix N

method should be discretionary.

RSPA has adopted the recommended change regarding mandatory yield

testing. Although, in the proposed rules, yield testing may have

appeared permissive, RSPA clearly intended such testing to be the only

alternative when design pressure is unknown. Therefore, in the final

rule, if factors in the design formula are unknown, a pipeline to be

converted or uprated would have to be pressure tested under Appendix N

to determine pipe yield, except as discussed below for low-stress pipe.

The TPSSC member's recommendation to delete ``first pressure'' from

the proposed rule was not adopted. Although Appendix N does not refer

to the first pressure that produces yield, paragraph 845.214(a)(2) of

the ASME B31.8 Code, which applies to the establishment of MAOP when

design pressure is unknown, provides that only the first test to yield

can be used to determine MAOP. The proposed rules were consistent with

this B31.8 standard, which precludes the use of higher yield pressures

that can result from successive testing.

RSPA did not adopt the TPSSC member's comment that use of the

Appendix N method should be discretionary. When MAOP is determined

without knowing the pipeline's design pressure, conformity to a

standardized practice (Section N5.0 of Appendix N) assures additional

safety to offset the lack of knowledge about design pressure.

RSPA received comments on the proposed rules from 11 operators and

three pipeline-related associations. Four operators and one pipeline-

related association recommended removal of the proposed requirement to

use the ``first pressure'' that produces yield. Our position on this

subject is given above in response to a similar comment by a TPSSC

member.

One operator and one pipeline-related association suggested

locating the proposed amendments in Sec. 192.105 instead of

Secs. 192.14 and 192.553. RSPA did not adopt this suggestion because

Sec. 192.105 affects the design of new pipelines, a subject the

proposed rules did not address.

One operator and two pipeline-related associations argued that

pressure testing to yield is unnecessary to qualify low-stress

distribution lines (generally lines 12\3/4\ inches or less in nominal

outside diameter operating at pressures less than 200 psig) for

conversion or uprating. Part 192 recognizes that low- stress pipelines

present a much lower risk to public safety than high-stress lines, all

other factors being equal. For example, certain welding standards in

subpart E are less stringent for pipelines to be operated below 20

percent of SMYS. Because of the lower risk, the final rule provides

that pipelines 12\3/4\ inches or less in nominal outside diameter to be

operated at a pressure less than 200 psig may be converted or uprated

without testing to yield. The MAOP of such pipelines may be determined

under Sec. 192.619(a)(1) by using 200 psig as design pressure.

An operator argued that pressure testing to yield should be

discretionary, because sufficient safety would be provided by the

proposed pressure reduction factors regardless of the level of test

pressure. The commenter was also concerned that pressure testing to

yield for an extended time could cause the growth of defects that later

cause failure during operation. Two hours was suggested as the optimum

hold time for yield testing, based on ongoing studies.

RSPA did not adopt these comments. Pressure testing to yield

exposes more material and construction defects than does testing to a

lower pressure. With fewer defects remaining after testing to yield,

greater long-term protection against failures due to the growth of

unexposed defects results. RSPA intended this extra protection,

combined with the proposed pressure reduction factors, to offset the

absence of design pressure as a limit on MAOP. Pressure testing to

yield appears to be reasonable since many operators already strength

test their pipelines at or above yield for safety and efficiency

reasons. Also, none of the other commenters or TPSSC members objected

to pressure testing to yield, except as discussed above for low-stress

lines. As to the optimum hold period for yield testing, because the

matter is still being studied by industry and is not addressed by the

procedure for yield testing under Appendix N, it is too soon to

consider

[[Page 28775]]

establishing a special hold period for yield testing under part 192.

The final rules have been drafted to improve clarity, to show their

relation to design pressure and MAOP under Sec. 192.619, and to include

the changes discussed above. The proposed amendments to

Secs. 192.14(a)(1) and 192.553(d) are revised and published as an

amendment to Sec. 192.619(a)(1), because this section deals

specifically with design pressure and MAOP. Final Sec. 192.619(a)(1),

set forth below, provides that when design pressure is unknown for

steel pipelines being converted or uprated, a reduced value of first

yield hydrostatic test pressure, instead of design pressure, is used to

compute MAOP. As discussed below, final Sec. 192.619(a)(1) does not

include the reduction factors proposed for butt and lap welded pipe

under Sec. 192.14(a)(1)(ii). If the pipeline to be converted is 12\3/4\

inches or less in nominal outside diameter, 200 psig, instead of design

pressure, may be used if the line is not yield tested. Section

192.553(d) is also revised to refer to amended Sec. 192.619(a)(1).

Also, because the 1992 edition of the ASME B31.8 Code is now out-of-

print, the 1995 edition is referenced in Sec. 192.619(a)(1) as shown by

the revisions to Appendix A of part 192 (see below).

Section 192.107, Yield Strength (S) for Steel Pipe

For pipe made according to a specification not listed in part 192

or whose specification or tensile properties are unknown,

Sec. 192.107(b)(1) provides that yield strength may be established by

tensile testing in accordance with section II-D of appendix B to part

192. When yield strength is determined by such tensile testing,

paragraph (b)(1) requires that the yield strength used in the design

formula of Sec. 192.105 be the lower of either 80 percent of the

average yield strength determined by tensile testing or the lowest

yield strength determined by tensile testing, but not over 52,000 psi.

RSPA proposed to remove this 52,000 psi upper limit on yield strength,

because higher strength pipe has become available since this limitation

was adopted, and tensile testing is a generally accepted method of

determining material properties.

Twelve TPSSC members voted for the proposal, one member supported

it with a recommended change and two abstained. The member recommending

the change felt that the proposal would be better justified if we knew

the proportion of higher strength pipe that lacks tensile documentation

and why this information is unknown. RSPA believes this information is

not essential in deciding whether to adopt the proposal because the

proposed amendment has limited application. We expect operators would

use the proposed amendment to qualify stock pipe they have stored for

maintenance and emergencies and to qualify used pipe being reclaimed.

In either case, the amount of pipe that would be qualified under

proposed Sec. 192.107(b)(1)(ii) should be very small compared with all

pipe being qualified for use in gas pipeline systems.

RSPA received six comments on the proposed amendment. The comments

came from five operators and one pipeline-related association, and all

supported the proposal. In addition, one operator recommended that RSPA

further amend Sec. 192.107 to permit the use of recognized statistical

methods to determine yield strength from tensile tests. RSPA did not

adopt this comment because this concept was not addressed in the NPRM

and would require further public comment and study.

Accordingly, Sec. 192.107 is amended as proposed in the NPRM.

Section 192.121, Design of Plastic Pipe

RSPA proposed to add the following formula to Sec. 192.121, which

would allow use of the Standard Dimension Ratio (SDR) in determining

design pressure for plastic pipe:

[GRAPHIC] [TIFF OMITTED] TR06JN96.012

SDR is a commonly used plastic pipe characteristic in the gas

pipeline industry.

Thirteen TPSSC members voted for the proposal and two abstained.

RSPA received eight responses from the public, all in favor of the

proposed rule. Therefore, the final rule is issued as proposed in the

NPRM, except that the proposed definition is reworded to conform to

standard usage. The final definition agrees with the SDR definition

given in the voluntary standard referenced in part 192 for the

manufacture of thermoplastic pipe: American Society for Testing and

Materials (ASTM) Designation D 2513, ``Standard Specification for

Thermoplastic Gas Pressure Pipe, Tubing, and Fittings'' (1990c

edition).

Section 192.123, Design Limitations for Plastic Pipe

Under Sec. 192.123, plastic pipe may not be used where pipe

operating temperatures are below -20 deg.F. RSPA proposed to lower this

limit to -40 deg.F in light of improvements in pipe technology.

Additionally, RSPA proposed to clarify Sec. 192.123(b)(2), which sets

the maximum operating temperature for thermoplastic pipe and reinforced

thermosetting plastic pipe.

Thirteen TPSSC members voted for the proposal and two abstained.

RSPA received nine comments on the proposed rule changes: six from

operators, one from a pipeline-related association, and two from

manufacturers. The operators and the association supported the proposal

or did not object to it. However, the manufacturers opposed the

proposal stating that many components other than pipe that are made for

use in gas pipeline systems do not have a low temperature rating of

-40 deg.F, although they perform satisfactorily at -20 deg.F. One of

these commenters argued that unsafe operation could occur if pipeline

designers assumed that all components, such as repair and connection

devices, fittings, valves, meters, and regulators, may be used at

-40 deg.F.

RSPA shares the manufacturers' concern. Therefore, the final rule

allows the use of plastic pipe at temperatures between -20 deg.F and

-40 deg.F only if all pipe and pipeline components whose operating

temperature will be below -20 deg.F have a manufacturer's temperature

rating consistent with that operating temperature.

Section 192.179, Transmission Line Valves

Gas transmission lines must have sectionalizing block valves spaced

according to population density under Sec. 192.179(a). RSPA proposed to

revise this rule to allow the RSPA Administrator to approve alternative

spacing where the operator demonstrates an equivalent level of pipeline

safety.

Thirteen TPSSC members voted for the proposal, one against, and one

abstained.

RSPA received comments from 12 operators, two pipeline-related

associations, and a state agency. Thirteen commenters gave their full

or qualified approval, but one association and the state agency argued

against the proposal. Those commenters expressing qualified support

generally felt that the proposal offered some benefit to pipeline

operators. However, they urged that operators be permitted to determine

spacing based on criteria similar to those for hazardous liquid

pipelines in 49 CFR 195.260(c).

RSPA did not adopt the comment that transmission line valve spacing

should be governed by criteria similar to those in 49 CFR 195.260(c).

While those criteria may be appropriate for hazardous liquid pipelines,

we have no indication they are suitable for gas

[[Page 28776]]

transmission lines. In fact, the widely accepted voluntary standard for

valve spacing, paragraph 846.11 of the ASME B31.8 Code, differs little

from existing Sec. 192.179.

As for the comments opposing the proposal, RSPA has considered the

state agency's concern that the proposed rule would infringe on the

authority of state agencies to grant waivers from Sec. 192.179 for

intrastate transmission lines. (See 49 U.S.C 60118(d)). However, this

concern has been addressed by a procedural rule (49 CFR 190.9) that

RSPA adopted to handle petitions for finding or approval under the

federal pipeline safety regulations. Under this rule, which would apply

to petitions for alternative spacing under Sec. 192.179, operators of

intrastate pipelines subject to the safety regulatory jurisdiction of a

certified state agency must submit their petitions to that agency for

review and recommendation before final action by the Administrator.

RSPA does not agree with the pipeline-related association's

suggestion that since the underlying rule is not justified, the

proposed amendment is not needed. The basis for existing Sec. 192.179

was the 1968 edition of the ASME B31.8 Code. As noted above, the

current edition of that code continues to specify valve spacing similar

to Sec. 192.179.

Section 192.203, Instrument, Control, and Sampling Pipe and Components

Under Sec. 192.203(b)(2), each takeoff line must have a shutoff

valve as near as practicable to the point of takeoff. RSPA proposed an

exception for takeoff lines on pressure regulators when the lines can

be isolated by other valves from their source of pressure.

Eleven TPSSC members voted for the proposal, one voted against it,

two members supported it with a recommended change, and one abstained.

The two members recommended that we also except instrument control

lines that are capable of being isolated from their source of pressure.

Although the industry's use of isolatable regulators gave rise to

the proposed rule change, isolation of a takeoff line from its pressure

sources applies to any takeoff line capable of such isolation, not just

takeoff lines on regulators. Therefore, the final rule excepts any

takeoff line capable of being isolated from its sources of pressure.

Thus, the term ``takeoff line'' includes instrument control lines that

are designed as takeoff lines.

RSPA received 13 public comments, all in favor of changing the

regulation. One of these commenters offered a rewording intended to

broaden the regulation to include control lines at both measuring and

regulating stations. As explained above, such control lines will be

covered by the exception when they are takeoff lines capable of

isolation from their sources of pressure.

Section 192.227, Qualification of Welders, and Sec. 192.229,

Limitations on Welders

Welders qualified to weld on pipe to be operated at any hoop stress

(Sec. 192.227(a)) must requalify every 6 months (Sec. 192.229(c)).

However, welders qualified to weld only on pipe to be operated at low

hoop stress (less than 20 percent of SMYS) need only requalify once a

year (Sec. 192.227(b)), and the requalification requirements are less

comprehensive than those for other welders.

RSPA proposed to revise Secs. 192.227 and 192.229 to allow welders

initially qualified for any hoop stress level, but who weld only on

pipe to be operated at low hoop stress, to requalify under the low-

stress requirements. Such welders would then not be permitted to weld

on pipe to be operated at 20 percent or more of SMYS unless they again

qualify under Sec. 192.227(a).

Twelve TPSSC members voted for and one against the proposed

revision of Sec. 192.227, and two abstained. The TPSSC members' vote on

Sec. 192.229 was the same as on Sec. 192.227. Eight pipeline operators

and two pipeline-related associations also agreed with the proposal.

A commenter suggested that the final rule make clear that either

existing Sec. 192.229(c) or Sec. 192.227(b) can be used to requalify

welders to weld on pipe to be operated at less than 20 percent of SMYS.

RSPA adopted the substance of this comment by adding a sentence

concerning low stress requalification to the final Sec. 192.229(c).

The commenter who opposed the proposal claimed that qualification

under Secs. 192.227(a) and (b) is inadequate. However, RSPA finds no

justification for this claim. Section 192.227 became effective in

February 1970. Our accident data in the intervening 26 years have not

indicated that field welding of steel materials in pipelines presents a

significant safety problem.

In the final rules, proposed Sec. 192.227(c) is redesignated as

Sec. 192.229(d). Thus, all requalification requirements appear in one

section.

Section 192.241, Inspection and Test of Welds

Section 192.241 requires inspection and test of welds on steel

materials in pipelines, except welds made during the manufacture of

pipe and pipeline components. Under existing Sec. 192.241(c) and

appendix A to part 192, the acceptability of a weld that is

nondestructively tested or visually inspected is determined according

to the standards in section 6 of API Standard 1104 (17th edition).

The Appendix of API Standard 1104, which is based on fracture

mechanics principles, provides more detailed acceptance standards for

weld flaws than the criteria in section 6 of API Standard 1104. RSPA

proposed to amend Sec. 192.241(c) to permit use of the Appendix as an

alternative acceptance standard for girth weld flaws, except welds

unacceptable because of a crack.

Eleven TPSSC members voted for the proposal, three members

supported it with a recommended change and one abstained. The three

members suggested that the word ``flaw'' be changed to ``defect''.

In existing Sec. 192.241, neither the word ``flaw'' nor ``defect''

is used. The rule is written in terms of weld acceptability. Therefore,

in response to the comments of the TPSSC members, the final rule is

written without using either ``flaw'' or ``defect.''

Eleven pipeline operators and three pipeline-related associations

agreed with the proposed change. Only one commenter was opposed to

allowing use of the Appendix of API Standard 1104. This commenter was

concerned that industry inspection personnel may not be qualified to

apply the complicated engineering criteria found in the Appendix. On

the contrary, personnel who would use the Appendix must be able to

apply it correctly. 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.

The final rule indicates that use of the Appendix is restricted to

girth welds to which the Appendix applies. For example, as Section A.1

of the Appendix provides, welds used to connect fittings and valves are

not covered. Also, the Appendix applies only to girth welds between

pipe of equal nominal wall thickness.

Section 192.243, Nondestructive Testing

For pipelines subject to nondestructive testing under part 192,

Sec. 192.243(d)(4) requires such testing for all field butt welds at

pipeline tie-ins. RSPA proposed to amend Sec. 192.243(d)(4) to add the

phrase ``including tie-ins of replacement sections.'' This change was

meant to clarify that tie-ins occur in pipeline

[[Page 28777]]

replacement, as well as in new construction.

Fourteen TPSSC members voted for the proposal and one abstained.

Comments were received from five pipeline operators and one

pipeline-related association, and all favored the proposed rule change.

Section 192.243 is amended as proposed in the NPRM.

Section 192.281, Plastic Pipe

This rule establishes standards governing the joining of plastic

pipe. RSPA proposed to revise Sec. 192.281(c), which applies to heat-

fusion joints, to cover electrofusion, a method of heat-fusion joining.

The proposal was that electrofusion joints must be made with equipment

and techniques expressly prescribed by the fittings manufacturer.

Thirteen TPSSC members voted for the proposal, one member supported

it with a recommended change, and one abstained. The recommended change

was that ``or the equivalent'' be added so that operators could use

equipment and techniques equivalent to that prescribed by fittings

manufacturers.

RSPA received 15 comments on the proposed change to

Sec. 192.281(c). Eleven commenters fully or partially agreed with the

proposed rule, while four commenters objected. A commenter who

partially agreed recommended that electrofusion be specifically

addressed in Sec. 192.285. However, RSPA finds that step unnecessary

because electrofusion is a type of heat fusion, and heat fusion is

covered by Sec. 192.285(b)(2).

The objections focused on RSPA's proposal that operators must use

``equipment and techniques expressly prescribed by the fittings

manufacturer.'' One commenter said that electrofusion equipment is

expensive and that most electrofusion fittings can be installed only by

using the fittings manufacturer's equipment. As a result, most

operators have only a single source of electrofusion fittings. However,

the commenter stated that electrofusion equipment under development

will allow the installation of several different brands of

electrofusion fittings, and that those additional sources would

encourage competitive pricing. Other operators argued they should not

be denied the use of procedures and equipment not expressly prescribed

by the fittings manufacturer, as long as the procedures are qualified

for use under Sec. 192.283.

Since the proposal was intended to relax the current regulatory

requirement, RSPA accepts the recommendations that operators should

have latitude in choosing equipment and techniques for use in

electrofusion joining. We have adopted a slight revision of the wording

proposed by three pipeline operators and one pipeline-related

association. This wording meets the ``or the equivalent''

recommendation made by the TPSSC member. Additionally, this wording

responds to the commenter's concern that the proposed wording would

deter competitive pricing. The adopted wording requires that the joints

be joined using equipment and techniques of the fittings manufacturer

or equipment and techniques shown, by testing to certain criteria of

ASTM Designation F1055, ``Standard Specification for Electrofusion Type

Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe

and Tubing,'' to be at least equivalent to those of the fittings

manufacturer. The ASTM criteria are those adopted under the next

heading for qualifying electrofusion joining procedures.

Section 192.283, Plastic Pipe: Qualifying Joining Procedures

Section 192.283 prescribes criteria for qualifying procedures used

to join plastic pipe. RSPA proposed to amend this section by adding

more appropriate criteria for procedures used to join polyethylene

plastic pipe by electrofusion. The proposed criteria are contained in

certain sections of ASTM Designation F1055 (1987 edition).

Fourteen TPSSC members voted for the proposal and one member

abstained.

RSPA received eight comments on the proposal: seven from pipeline

operators and one from a pipeline-related association. Seven commenters

supported the proposal. But one opposed it, saying that the proposal

should be withdrawn or rewritten to accept any procedure that

demonstrates a suitable quality of joint. We believe, however, that

allowing operators to judge the quality of an electrofusion joint

without applying a recognized safety standard would be unacceptable.

Because of the failure risk of plastic pipe joints, the present rule

requires heat fusion joining methods to be qualified under generally

recognized voluntary standards, ASTM D2513 and ASTM D2517. In the

absence of safety data to the contrary, as a heat fusion method,

electrofusion procedures should likewise be qualified under an

appropriate recognized standard. Accordingly, proposed

Sec. 192.283(a)(iii) is adopted as final. However, the proposed

reference to the 1987 edition of ASTM Designation F1055 is updated to

the 1995 edition, as shown by the revisions to Appendix A of part 192

(see below). And the referenced title of paragraph 9.4 is corrected to

read ``Joint Integrity Tests.''

Sections 192.317(a), Protection From Hazards

This section requires that gas transmission lines and mains be

protected from washouts, floods, unstable soil, landslides, or other

hazards that may cause the pipeline to move or sustain abnormal loads.

Additionally, offshore pipelines must be protected from damage by mud

slides, water currents, hurricanes, ship anchors, and fishing

operations. RSPA recognized that in areas susceptible to these hazards,

such as offshore pipelines in areas where hurricanes usually pass,

complete protection against the hazards may not be feasible. We,

therefore, proposed to change the regulation to require that in

construction of transmission lines and mains, operators ``take all

practicable steps to protect'' the pipeline against the cited hazards.

Eleven TPSSC members voted for the proposal, one member supported

it with a recommended change, two members were opposed and one member

abstained. The two members who opposed it said that ``all practicable

steps to protect'' would be difficult to interpret.

Comments were received from seven pipeline operators and two

pipeline-related associations. All commenters gave their full or

qualified approval.

RSPA has issued the final rule as proposed in the NPRM. The ``all

practicable steps to protect'' wording was left in the rule to allow

operators flexibility in compliance; any tightening of this performance

wording would diminish that flexibility. RSPA will interpret or apply

the rule in light of customary pipeline design and construction

practices in the industry.

Secs. 192.319(c) and 192.327(e), Offshore Pipe in the Gulf of Mexico

and Its Inlets

Under Sec. 192.612, operators had to inspect gas pipelines in the

Gulf of Mexico and its inlets in waters up to 15 feet deep. If the

pipelines were found exposed or to be a hazard to navigation (i.e.,

buried less than 12 inches below the seabed), the operator had to bury

them to a depth of 36 inches in soil or 18 inches in rock.

The part 192 review disclosed that Secs. 192.319(c) and 192.327(e),

which govern the installation of pipe offshore, are incompatible with

the objectives of Sec. 192.612. In water between 12 and 200 feet deep,

Sec. 192.319(c) permits pipe to be installed at or above the natural

bottom. And in water less than 12 feet deep, in certain circumstances

Sec. 192.327(e) permits pipe to be buried less than 36 inches in soil

or 18 inches

[[Page 28778]]

in rock. RSPA proposed to amend Secs. 192.319(c) and 192.327(e) to

require that when pipe is installed offshore in the Gulf of Mexico and

its inlets, the pipe must be installed consistent with the burial

standards of Sec. 192.612.

Thirteen TPSSC members voted for the proposal, one member supported

it with a recommended change, and one abstained. One member supported

the proposal but recommended rewording and rearrangement for clarity,

and that Sec. 192.319(c) be moved to Sec. 192.327.

Seven operators and four pipeline-related associations supported

the proposed changes to Secs. 192.319(c) and 192.327(e). However, five

commenters recommended wording changes and rearrangement for clarity,

and five commenters suggested that Sec. 192.319(c) be moved to

Sec. 192.327. In light of the recommendations, RSPA has clarified the

final rule text, as set forth below.

One pipeline-related association opposed the proposal. It

maintained that pipe installed in water between 12 and 15 feet deep

with less than 12 inches of cover (now acceptable under Sec. 192.319(c)

but not Sec. 192.612) might not be an actual hazard to navigation. But

the proposal concerned the inconsistency of Sec. 192.612 with other

pipeline safety rules, a problem that can be resolved without reopening

the question of what is a ``hazard to navigation'' in the Gulf of

Mexico and its inlets. A ``hazard to navigation'' is defined in

Sec. 192.3 to mean ``a pipeline where the top of the pipe is less than

12 inches below the seabed in water less than 15 feet deep, as measured

from the mean low water.'' This definition was adopted in the

proceeding on Sec. 192.612 (Docket No. PS-120). Any remaining

controversy over the definition may be raised by submitting a petition

for rulemaking under 49 CFR part 106.

Section 192.321, Installation of Plastic Pipe; and Sec. 192.375,

Service Lines: Plastic

Section 192.321(a) requires that plastic pipe be installed below

ground level. RSPA proposed to allow the temporary use of uncased

(i.e., not encased) plastic pipe above ground level under certain

conditions. The proposed conditions limited the use to (1) 30 days; (2)

locations where the pipe is unlikely to be damaged (or is protected

from damage) by external forces; (3) pipe that is resistant to the

exposure to ultraviolet light and temperature extremes; and (4) pipe

that has not been previously used above ground level.

Nine TPSSC members voted for the proposal, one against, three

members supported it with a recommended change, and two abstained. The

recommended changes were similar to those made by the commenters as

discussed below.

RSPA received 18 comments on this proposal. Each commenter agreed

partially with the proposed rule. Some commenters said the current rule

should be amended to permit the permanent use of plastic above ground

when the pipe is encased in steel conduit. However, since the proposal

concerned only temporary usage, this comment was not adopted in the

final rule.

Many commenters argued that the 30-day period would be too brief.

They suggested a longer period, such as 60 or 90 days, in view of the

time it may take to complete a permanent installation. They cited the

time associated with planning, obtaining governmental permits,

acquiring easements, engaging contractors, competing work demands, and

other unforeseen events. Several commenters suggested that no specific

time limit be defined and that performance language be used.

Commenters also maintained that the proposed prohibition against

the subsequent reuse of plastic pipe above ground level is not

justified, since commercially available plastic pipe can be exposed to

ultraviolet light for at least 2 years with no degradation of its

properties. These commenters argued that the rule should permit reuse

of plastic pipe provided such use does not exceed the pipe

manufacturer's exposure limits.

RSPA agrees that in most cases 30 days may not be enough time for

operators to take full advantage of a temporary aboveground plastic

pipe installation. In a recent waiver of Sec. 192.321(a), we allowed

the applicant to install plastic pipe above ground for a time that does

not exceed the manufacturer's recommended maximum period of exposure

(60 FR 55752; Nov. 2, 1995). Although commenters indicated that

extending the limit to 2 years might not adversely affect pipeline

safety, we are not certain 2 years would be safe for all plastic

materials. Some pipe manufacturers may recommend less exposure time.

Therefore, we have chosen the manufacturer's recommended maximum period

of exposure but not longer than 2 years as the limit on the temporary

use of plastic pipe above ground. If a manufacturer has no recommended

maximum exposure period, then the limit would be 2 years. RSPA does not

believe a performance standard would provide a suitable time limit,

because the safe service life of plastic pipe exposed above ground is

too uncertain.

RSPA agrees that the final rule should not unduly hinder the use of

plastic pipe. Thus, the proposed ban on reusing plastic pipe above

ground level does not appear justified. The final rule permits

cumulative aboveground use for the manufacturer's recommended maximum

period of exposure but not longer than 2 years, provided the operator

can demonstrate the cumulative time of aboveground use. In monitoring

compliance, RSPA will consider credible evidence that demonstrates

cumulative time of use, such as business records, work orders, or

affidavits related to the pipe concerned.

RSPA recognized that the changes to Sec. 192.321 affected only

plastic mains and transmission lines. However, the need for these

changes applies as well to plastic service lines. As with transmission

lines and mains, in some situations operators may be able to save

material and construction costs of service lines located outside

buildings by temporarily installing the lines above ground. Thus,

Sec. 192.375(a), which requires that plastic service lines outside

buildings be installed below ground, is revised to allow temporary

aboveground installations in accordance with Sec. 192.321(g).

Section 192.455, External Corrosion Control: Buried or Submerged

Pipelines Installed After July 31, 1971

Under Sec. 192.455(a)(2), a pipeline must have a cathodic

protection system designed to protect the pipeline in its entirety.

RSPA proposed to remove the phrase ``in its entirety'' because it is

unnecessary to convey the meaning of the rule, and some operators have

incorrectly assumed that pipeline casings also must be protected.

In addition, Sec. 192.455(f)(1) exempts from corrosion control

requirements certain metal fittings in plastic pipelines if the fitting

is protected against corrosion by alloyage. RSPA recognized that the

word ``alloyage'' is not in common usage and proposed its replacement

with ``alloy composition'' to improve understanding.

Twelve TPSSC members voted for the proposal, two members supported

it with a recommended change and one abstained. The two members

recommended that in proposed paragraph (f)(1), the term ``corrosion

resistance'' be replaced by ``corrosion control,'' which is the term

used in the existing rule and throughout subpart I. RSPA has made this

replacement in the final rule.

Comments were received from six pipeline operators and one

pipeline-related association. Six commenters gave their full approval

and the seventh was noncommittal. Therefore, except for the previously

discussed wording

[[Page 28779]]

changes, Sec. 192.455 is adopted as proposed in the NPRM.

Section 192.475, Internal Corrosion Control: General.

Section 192.475(c) limits the hydrogen sulfide content of natural

gas stored in pipe-type or bottle-type holders to 0.1 grain per 100

standard cubic feet of gas. An operator proposed that this rule be

relaxed to allow a concentration of 0.25 grain per 100 standard cubic

feet of gas. Because the 0.25 limit is within customary industry

contract limits and is still lower than maximum allowable safe limits

set by other government agencies, RSPA proposed to increase the

allowable hydrogen sulfide limit in gas to be stored in pipe-type and

bottle-type holders to 0.25 grain per 100 standard cubic feet of gas.

This action would lower the cost of processing natural gas that

contains small quantities of hydrogen sulfide.

Thirteen TPSSC members voted for the proposal, one against, and one

member abstained.

Seven commenters supported the proposed change. No commenters

opposed the change. One state agency suggested that hydrogen sulfide

levels be expressed in parts per million in addition to grains per 100

standard cubic feet of gas. The NAPSR report also made this

recommendation, and all comments on the subject were supportive. RSPA

agrees the allowable level should be stated in parts per million and

has included this designation in the final rule.

Section 192.485, Remedial Measures: Transmission Lines

RSPA's review of Sec. 192.485, which prescribes remedial measures

for corroded transmission lines, disclosed that many operators need

guidance on how to determine the remaining strength of corroded pipe.

RSPA proposed to provide this guidance by referencing ASME B31G Manual

for Determining the Remaining Strength of Corroded Pipelines in a new

Sec. 192.485(c).

Fourteen TPSSC members voted for the proposal and one member

abstained.

Comments relevant to proposed Sec. 192.485(c) were received from 10

pipeline operators and two pipeline-related associations. Six

commenters gave their full or partial support. Another six said 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 the method in the American

Gas Association (AGA) report for Project PR 3-805, ``A Modified

Criterion for Evaluating the Remaining Strength of Corroded Pipe,''

(December 22, 1989; AGA catalog No. L51609). Project PR 3-805 was

undertaken to devise a criterion that, while still assuring adequate

pipeline integrity, would eliminate, as much as possible, the excess

conservatism embodied in the ASME B31G Manual. For a complex analysis,

the modified criterion can be applied by using a computer program

called RSTRENG, which is furnished with the report. The modified

criterion can also be applied with a long-hand equation, or if a

simplified analysis is preferred, with tables or curves.

Evaluating the strength of corroded pipe by procedures in ASME B31G

or the associated AGA report is subject to the limitations specified in

the procedures. For example, the procedures are not appropriate for

determining the ability of pipe to withstand stresses other than stress

from internal pressure. Thus, if corroded pipe is under significant

secondary stress (e.g., bending stress), an additional method must be

used to determine the pipe's remaining strength.

The NAPSR report recommended amending Sec. 192.483 to require the

use of appropriate guides, such as those published by ASME and the Gas

Piping Technology Committee, whenever the remaining strength of

corroded pipelines must be determined. The majority of commenters who

addressed this NAPSR recommendation opposed mandatory use of the

guides. They said operators should retain the flexibility to decide

when calculations under the guides are necessary. Even those commenters

who supported the recommendation thought the rule should permit the use

of other valid methods.

After considering the comments on proposed Sec. 192.485(c) and the

NAPSR recommendation, we believe the NAPSR recommendation would be

unduly restrictive. Operators are now free to use any valid method to

determine the remaining strength of corroded pipe, and we see no

compelling reason to restrain this flexibility. The NPRM simply

proposed to reference guidance documents that are generally available

for operators to use at their discretion. Moreover, the proposal was

written in a permissive sense to assist, but not restrict, operator

decision-making. So we have amended the regulation essentially as

proposed, but referenced both ASME B31G and the AGA report, with

RSTRENG, to expand the information provided.

Section 192.491, Corrosion Control Records

Under Sec. 192.491(a), operators must maintain records or maps

showing the location of cathodically protected piping, cathodic

protection facilities, other than unrecorded anodes installed before

August 1, 1971, and neighboring structures bonded to the cathodic

protection system. RSPA proposed to amend this requirement to relieve

operators of the burden of making precise field measurements and

preparing and maintaining records or maps showing the specific location

of millions of individual anodes.

The TPSSC members voted unanimously for the proposal.

Comments on proposed Sec. 192.491(a) were received from six

pipeline operators, two pipeline-related associations, and one state

agency. Eight commenters expressed their full or partial support with

one commenter opposed. RSPA has accepted the recommendation of two

operators that in the second sentence of proposed paragraph (a), the

phrase ``Records and maps * * *'' should, for consistency with the rest

of this section, be changed to ``Records or maps * * *.''

Section 192.491(b)(2) requires that operators retain records of

corrosion control tests, surveys, and inspections for ``as long as the

pipeline remains in service.'' RSPA proposed to reduce this retention

period to at least 5 years for many records, because 5 years was

thought to be adequate for compliance investigations and analysis of

possible corrosion problems.

The proposal did not, however, extend to records under

Secs. 192.465 (a) and (e) and 192.475(b). These records relate to tests

and inspections to determine the adequacy of, or need for, external and

internal protection on existing lines. RSPA felt strongly that these

records should continue to be kept for the service life of the

pipeline, because they provide a valuable database for use in assessing

corrosion problems.

The TPSSC unanimously supported the proposal.

Three pipeline-related associations, 10 operators, and one state

agency commented on the proposal. Four of these commenters agreed with

the proposal as written; the rest qualified their support by

recommending changes.

Five commenters, including two pipeline-related associations and a

state agency, were not persuaded of the importance of keeping records

of

[[Page 28780]]

corrosion monitoring under Sec. 192.465 for the life of the pipe. Most

of these commenters declared that 5 years would be adequate, but did

not explain why a longer period is excessive. Lacking any convincing

documentation to the contrary, RSPA believes the current rule should

stay in effect. In our experience, a history of corrosion monitoring

sheds light on the possible causes of a pipeline's condition. Such

history has proven to be a valuable resource in deciding the extent and

kind of remedial action needed when corrosion problems emerge on a

pipeline.

Regarding the proposed 5-year retention time for records other than

those required by Secs. 192.465 (a) and (e) and 192.475(b), two

commenters said the minimum time should be 3 years to coincide with the

longest interval between inspections. Two others suggested that instead

of a set time, we adopt a performance standard for record retention,

basing it on the time needed to observe trends, inquire into

compliance, or collect superseding data. All these comments provide a

reasonable basis for record retention. However, our main concern is

that operators keep records for a period that is compatible with the

occurrence of routine compliance investigations. Therefore, for

simplicity and uniformity, we have decided to adopt the proposed 5-year

minimum retention time.

The state agency that commented objected to the 5-year proposal on

grounds that it would sacrifice information about why external or

atmospheric corrosion control was not installed on pipelines under

Secs. 192.455, 192.457, and 192.479. RSPA believes the loss of this

information after 5 years would not be significant, because the

pipelines involved are covered by requirements for periodic inspections

or tests for corrosion under Secs. 192.465 and 192.481.

Section 192.553, General Requirements

(See previous discussion under Sec. 192.14).

Section 192.607, Determination of Class Location and Maximum Allowable

Operating Pressure

Because Sec. 192.607 has no continuing effect and the deadlines for

compliance have expired, RSPA proposed to remove Sec. 192.607 from part

192.

Fourteen TPSSC members voted for the proposal and one member

abstained.

Five operators, one pipeline-related association, and one state

agency commented on the proposed removal of Sec. 192.607. Four

operators and the association favored the idea. One operator and the

state agency disagreed with removal, believing the rule is needed to

tie a pipeline's maximum allowable operating pressure (MAOP) to its

class location. Similarly, the NAPSR report recommended that we only

remove the past compliance deadlines from Sec. 192.607, leaving the

rest of the rule in place to regulate the relation of class location to

stress level on high-stress pipelines.

Section 192.607 was a transitional requirement. Its purpose was to

establish plans under which operators initially determined class

locations and confirmed or revised the MAOPs of their high-stress

pipelines commensurate with their class locations. Section 192.607

provides that the plans had to be executed in accordance with

Sec. 192.611. This latter section together with Sec. 192.609 are

sufficient to require that operators have up-to-date class location

determinations for high-stress pipelines, and maintain the MAOPs of

those lines commensurate with their class locations.

Accordingly, Sec. 192.607 is removed from part 192.

Section 192.611, Change in Class Location

Section 192.611 requires confirmation or revision of a pipeline's

MAOP within 18 months after a change in class location. RSPA proposed

to reorganize Sec. 192.611 to clarify the requirement that the MAOP

resulting from confirmation or revision may not exceed the pipeline's

previous MAOP. This requirement is currently set forth in

Sec. 192.611(a)(3)(ii), suggesting that it applies only to

confirmations or revisions under paragraph (a)(3), which is not the

intent.

Fourteen TPSSC members voted for the proposal and one member

abstained.

Five operators and one pipeline-related association commented on

the proposal; each agreed with the proposal. Section 192.611 is,

therefore, adopted as proposed in the NPRM.

Section 192.614, Damage Prevention Program

To decrease excavation damage to pipelines, Sec. 192.614(b)(2)

requires operators to notify excavators and the public about the need

to locate buried pipelines before excavating. The NPRM proposed to

amend the rule to clarify that in contrast to the actual notification

required for excavators, only general notification is required for the

public. General notice can be given through newspapers, radio,

television, or other means of mass communication, as appropriate for

the public in the vicinity of the pipeline.

Fourteen TPSSC members voted for the proposal and one member

abstained.

Six pipeline operators and two pipeline-related organizations

commented. Seven commenters gave their full or qualified approval and

one commenter opposed the proposal. The qualified and negative comments

were that the rule should inform operators of the acceptable means of

notification. We do not feel it is necessary for the rule to do so,

however, because the available means of giving general public notice

are well known. The amendment to paragraph (b)(2) is adopted as

proposed.

Section 192.619, Maximum Allowable Operating Pressure: Steel or Plastic

Pipelines

Section 192.619(a) prescribes six pressure limits for use in

determining the MAOP of steel and plastic pipelines, the lowest of

which establishes the MAOP. Paragraph (a)(4) limits the MAOP of furnace

butt welded pipe to 60 percent of the mill test pressure. Paragraph

(a)(5) limits the MAOP of other steel pipe to 85 percent of the highest

test pressure to which the pipe has been subjected, whether by mill

test or by the post installation test.

RSPA proposed to repeal paragraphs (a)(4) and (a)(5), primarily

because mill tests are not an adequate MAOP consideration. However, to

assure consideration of longitudinal joint efficiency, RSPA also

proposed, in paragraph (a)(2)(iii), that the class location pressure

limit under existing paragraph (a)(2)(ii) be reduced for furnace butt

welded pipe and lap welded pipe.

Eleven TPSSC members voted for the proposal, one member supported

it with a recommended change, two members opposed it, and one

abstained. A member recommended that RSPA not adopt proposed paragraph

(a)(2)(iii) because design pressure (under paragraph (a)(1)) adequately

covers longitudinal joint concerns.

RSPA concurs with this view as explained below in response to

public comment.

Thirteen operators, four pipeline-related associations, and one

state agency commented on the proposed amendment. Two operators, one

pipeline-related association, and one state agency commented that

proposed paragraph (a)(2)(iii) could require operators to reduce the

operating pressure of some pipelines or test them to higher pressures

than they previously were tested, possibly damaging the pipelines. In

addition, some commenters stated that proposed paragraph (a)(2)(iii)

would duplicate use of longitudinal joint factors.

[[Page 28781]]

Upon further consideration of our joint efficiency concern, RSPA

concurs with these comments. Further, RSPA has no data showing that

pipelines covered by proposed paragraph (a)(2)(iii) pose a risk that

warrants pressure reduction or retesting. Therefore, although the final

rule repeals paragraphs (a)(4) and (a)(5) as proposed, proposed

paragraph (a)(2)(iii) is not adopted.

Section 192.625, Odorization of Gas

Section 192.619(f) requires operators to conduct periodic samplings

of gas to assure the proper concentration of odorant. Based on a

suggestion by the Oregon Public Utility Commission, the NPRM proposed

to allow operators of master meter systems to comply with this sampling

requirement by (1) receiving written verification from their gas

supplier that odorant meets the required concentration, and (2)

conducting periodic sniff tests at system extremities to confirm that

the gas contains odorant.

Thirteen TPSSC members voted for the proposal, one against, and one

member abstained.

Comments were received from eight pipeline operators, two pipeline-

related associations, a mobile home association, and a consultant. One

commenter favored the proposal and 11 commenters opposed it. Commenters

opposing the proposal argued that (1) gas from a transmission line may

be unodorized; (2) gas suppliers may be unwilling to provide written

verification of odorization levels because of potential legal liability

and the increased burden of providing the written verifications; (3)

the frequencies of sniff tests and written verifications are unclear;

and (4) the proposal would relax odorant monitoring requirements on gas

systems which, in general, have a relatively high leakage rate.

The purpose of the proposal was to ease the sampling requirement

for operators of master meter systems, who largely do not have the

training or resources to adequately carry out the requirement. The

alternative of getting written verifications and conducting sniff tests

should be much less burdensome than purchasing, maintaining, and using

an odorometer or contracting for odorant testing.

We do not feel this potential advantage is outweighed by any of the

negative considerations the commenters raised. First of all, most

master meter system operators purchase odorized gas from local

distribution companies. Although some operators may receive unodorized

gas from transmission lines and have to odorize the gas themselves,

this situation does not warrant rejecting the proposed alternative.

Those operators who receive unodorized gas simply would not be able to

take advantage of the alternative. Similarly, operators could not take

advantage of the alternative if their gas suppliers are unwilling to

provide requested verifications of odorant level. But again this

difficulty is no reason to deny the alternative to other operators.

Regarding the frequency of verifications and sniff tests, the proposal

called for an initial written verification from the gas supplier and

periodic sniff tests thereafter. As with periodic sampling, the

frequency of sniff tests would depend on the performance history of

odorization in the system: the longer the period of satisfactory

odorization, the longer the period between tests to assure proper

odorant levels. Testing details would be specified in the operator's

operations and maintenance manual under Sec. 192.605 and reviewed for

adequacy by government inspectors. Finally, the charge that master

meter systems have a high leakage rate was unsupported. In a 1984

report, ``Exercise of Jurisdiction Over Master Meter Gas Operators,''

RSPA concluded that master meter systems probably have a small leakage

rate in comparison to the leakage rate of utility distribution systems.

And more recent safety data continue to substantiate that conclusion.

Therefore, after weighing the comments and favorable TPSSC vote, we

have decided to amend Sec. 192.625(f) as proposed.

Section 192.705, Transmission Lines: Patrolling

Operators of transmission lines must patrol their rights-of-way for

indications of certain adverse conditions. Because of repeated

questions about whether patrols may be done from the air, RSPA proposed

to change Sec. 192.705 to include aerial patrols as an optional method

of compliance.

Fourteen TPSSC members voted for the proposal and one abstained.

Six operators and one pipeline-related association commented on the

proposal. All but two of these commenters agreed with the proposal. One

commenter that disagreed said a list of methods of compliance might be

considered exclusive, thus disallowing other appropriate methods. The

other commenter that disagreed thought the rule change unnecessary.

RSPA believes the phrase ``or other appropriate means of traversing

the right-of-way'' in the proposed and final rule eliminates any chance

the list of compliance methods might be considered exclusive. Also, the

need for the rule change is based on RSPA's experience in explaining

the meaning of ``patrol'' under Sec. 192.705. The change to

Sec. 192.705 is, therefore, adopted as proposed.

Section 192.709, Transmission Lines: Record Keeping

Section 192.709 requires operators to keep various records about

transmission lines for as long as the line remains in service. RSPA

proposed a shorter retention span that would not affect the usefulness

of records in determining an operator's level of compliance effort or

in constructing the history of an accident or safety problem. RSPA

proposed a minimum 5-year retention period for records of patrols,

surveys, inspections, and tests, and a 1-year retention period for

records of repairs on facilities other than pipe. We also proposed to

clarify the information to be recorded.

Ten TPSSC members voted for the proposal, three members supported

it with a recommended change, one member opposed it, and one abstained.

The recommended changes were that 5 years should be changed to 3-5

years or to 10 years, and that leaks and linebreaks should also be

recorded as the current Sec. 192.709 provides. The ``No'' vote was

predicated on an alleged need to keep records of repairs on valves,

compressors, and other non- pipe components for 3-5 years.

As with final Sec. 192.491(c), RSPA's main concern about non-pipe

records is that operators keep records for a minimum period that is

compatible with the occurrence of routine compliance investigations.

The suggested 3-5 years would not be long enough, and 10 years would be

excessive. Therefore, we have adopted the proposed 5-year minimum

period.

Repair records, as currently required, already provide information

about leaks and linebreaks. Thus, requirements to keep the records of

leaks and linebreaks were omitted from the proposed rule as unnecessary

in view of this existing requirement.

As for the ``No'' vote, RSPA has adopted this minority TPSSC

position as explained below in response to a comment by a state agency.

Eight operators, two pipeline-related associations, and one state

agency commented on the proposed changes to Sec. 192.709. Five of the

operators supported the proposal without suggesting any modification.

Two other operators suggested 3 years as an alternative to the

proposed 5-year minimum. But, as explained above, 3 years is

insufficient for compliance monitoring purposes.

[[Page 28782]]

One operator thought the words ``for the useful life of the pipe''

under proposed Sec. 192.709(a) could be misinterpreted. This commenter

suggested that instead we adopt the words used in Sec. 192.491(c):

``for as long as the pipeline remains in service.'' We agree that for

consistency the two sections should use similar wording to describe

similar record retention requirements. This comment was, therefore,

adopted in the final rule.

One pipeline-related association recommended that Sec. 192.709 be

like 49 CFR 195.404(c), which applies to hazardous liquid pipelines. We

did not adopt this comment because Sec. 195.404(c) specifies a 2-year

retention period for records of inspections and tests, a time we now

find to be insufficient for purposes of compliance investigations.

Otherwise the two sections are parallel. The other association

reiterated its previous comment, which we opposed as discussed above,

that record retention requirements should be performance based.

The state agency that commented objected to the proposed 1-year

retention time for non-pipe repairs, saying it was inconsistent with

the proposal to keep for at least 5 years records of inspections that

may show the need for repair. This commenter reasoned that an inspector

might not find any record showing the needed repair was made. RSPA

agrees that the two requirements should be congruent. Therefore, the

final rule requires that records of non-pipe repairs made as a result

of a required patrol, survey, inspection, or test be kept for the same

time required for records of such patrol, survey, inspection, or test.

Section 192.721, Distribution Systems: Patrolling

This section governs the frequency at which operators must patrol

mains in distribution systems. The regulation is written in performance

terms, except that mains located where anticipated movement or loading

could cause leakage must be patrolled at intervals not exceeding 4\1/2\

months, but at least four times a year. RSPA proposed a more moderate

patrol frequency of twice a year for such mains in Class 1 or 2

locations, in recognition of the lower risk in these less densely

populated locations.

Twelve TPSSC members voted for the proposal, one against, one

member supported it with a proposed change, and one abstained. The

member against the proposal said that separating requirements on the

basis of class locations is not always workable for distribution

systems. Our response to this minority view is given below following

similar comments by operators.

Four operators and two pipeline-related associations commented on

the proposal. Three of the operators and one association supported the

proposal, but the other operator and association thought class location

should not be used as a basis for patrol frequency in distribution

systems. One commenter suggested ``rural areas'' as an alternative to

Class 1 and 2 locations.

RSPA agrees that the class location concept is not easy to apply in

all distribution systems. Therefore, in the final rule, we have used

the term ``business district'' to represent areas of higher risk and

``outside business districts'' to represent areas of lower risk. A

similar classification method is already in place under Sec. 192.723

for leakage surveys in distribution systems. The new patrol requirement

matches that method. The term ``rural area'' was not adopted because it

lacks precedent in part 192.

Rulemaking Notices and Analyses

Paperwork Reduction Act

This Final Rule revises information collection requirements in part

192 that are subject to review by the Office of Management and Budget

(OMB) under the Paperwork Reduction Act of 1995 (Pub. L. 104-13). The

following revised regulations reduce the existing paperwork burden by

28,326 hours:

Secs. 192.491 (a) and (b), ``Corrosion Control Records,''

reduces the paperwork burden by 22,486 hours by reducing the number of

records, the precision of the measurements, and the amount of time the

records must be kept.

Sec. 192.709, ``Transmission Lines; Record keeping,''

reduces the paperwork burden by 5,840 hours by reducing the amount of

time the records must be kept.

Persons are not required to respond to a collection of information

unless it displays a currently valid OMB control number. OMB has

approved the revised information collection requirements of part 192

through May 31, 1999 (OMB No. 2137-0049).

Executive Order 12866 and DOT Regulatory Policies and Procedures

OMB considers this final rule to be a significant regulatory action

under section 3(f) of Executive Order 12866. Therefore, OMB has

reviewed the final rule. Also, DOT considers the final rule to be

significant under its regulatory policies and procedures (44 FR 11034,

February 26, 1979).

A final regulatory evaluation has been prepared and is available in

the Docket. RSPA estimates the changes to existing rules will result in

savings of $33,000,000 a year, without associated costs and with no

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

the use of new technology, greater flexibility in constructing,

maintaining, and operating pipelines, improved clarity, and the

elimination of burdensome requirements.

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

final rule, I certify under Section 605 of the Regulatory Flexibility

Act that this final rule will not have a significant economic impact on

a substantial number of small entities.

E. O. 12612

The final rule would not have substantial direct effects on states,

on the relationship between the Federal Government and the states, or

on the distribution of power and responsibilities among the various

levels of Government. Therefore, in accordance with Executive Order

12612 (52 FR 41685; October 30,1987), RSPA has determined that the

final rule does not have sufficient federalism implications to warrant

preparation of a Federalism Assessment.

List of Subjects in 49 CFR Part 192

Incorporation by reference, Natural gas, Pipeline safety, Reporting

and recordkeeping requirements.

In consideration of the foregoing, RSPA amends 49 CFR part 192 as

follows:

PART 192--[AMENDED]

1. The authority citation for part 192 continues to read as

follows:

Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110,

60113, and 60118; 49 CFR 1.53.

2. In Sec. 192.1, paragraph (b)(1) is revised and paragraph (b)(4)

is added to read as follows:

Sec. 192.1 Scope of part.

* * * * *

(b) This part does not apply to:

(1) Offshore pipelines upstream from the outlet flange of each

facility where hydrocarbons are produced or where

[[Page 28783]]

produced hydrocarbons are first separated, dehydrated, or otherwise

processed, whichever facility is farther downstream;

* * * * *

(4) Any pipeline system that transports only petroleum gas or

petroleum gas/air mixtures to--

(i) Fewer than 10 customers, if no portion of the system is located

in a public place; or

(ii) A single customer, if the system is located entirely on the

customer's premises (no matter if a portion of the system is located in

a public place).

3. In Sec. 192.3, a definition of ``Petroleum gas'' is added and

the definition of ``Transmission line'' is revised to read as follows:

Sec. 192.3 Definitions.

* * * * *

Petroleum gas means propane, propylene, butane, (normal butane or

isobutanes), and butylene (including isomers), or mixtures composed

predominantly of these gases, having a vapor pressure not exceeding

1434 kPa (208 psig) at 38 deg.C (100 deg.F).

* * * * *

Transmission line means a pipeline, other than a gathering line,

that:

(a) Transports gas from a gathering line or storage facility to a

distribution center, storage facility, or large volume customer that is

not downstream from a distribution center;

(b) Operates at a hoop stress of 20 percent or more of SMYS; or

(c) Transports gas within a storage field. A large volume customer

may receive similar volumes of gas as a distribution center, and

includes factories, power plants, and institutional users of gas.

* * * * *

4. Section 192.5 is revised to read as follows:

Sec. 192.5 Class locations.

(a) This section classifies pipeline locations for purposes of this

part. The following criteria apply to classifications under this

section.

(1) A ``class location unit'' is an onshore area that extends 220

yards on either side of the centerline of any continuous 1- mile length

of pipeline.

(2) Each separate dwelling unit in a multiple dwelling unit

building is counted as a separate building intended for human

occupancy.

(b) Except as provided in paragraph (c) of this section, pipeline

locations are classified as follows:

(1) A Class 1 location is:

(i) An offshore area; or

(ii) Any class location unit that has 10 or fewer buildings

intended for human occupancy.

(2) A Class 2 location is any class location unit that has more

than 10 but fewer than 46 buildings intended for human occupancy.

(3) A Class 3 location is:

(i) Any class location unit that has 46 or more buildings intended

for human occupancy; or

(ii) An area where the pipeline lies within 100 yards of either a

building or a small, well-defined outside area (such as a playground,

recreation area, outdoor theater, or other place of public assembly)

that is occupied by 20 or more persons on at least 5 days a week for 10

weeks in any 12-month period. (The days and weeks need not be

consecutive.)

(4) A Class 4 location is any class location unit where buildings

with four or more stories above ground are prevalent.

(c) The length of Class locations 2, 3, and 4 may be adjusted as

follows:

(1) A Class 4 location ends 220 yards from the nearest building

with four or more stories above ground.

(2) When all buildings intended for human occupancy within a Class

2 or 3 location are in a single cluster, the class location ends 220

yards from the nearest building in the cluster.

5. Section 192.7(a) is revised to read as follows:

Sec. 192.7 Incorporation by reference.

(a) Any documents or portions thereof incorporated by reference in

this part are included in this part as though set out in full. When

only a portion of a document is referenced, the remainder is not

incorporated in this part.

* * * * *

6. Section 192.11 is revised to read as follows:

Sec. 192.11 Petroleum gas systems.

(a) Each plant that supplies petroleum gas by pipeline to a natural

gas distribution system must meet the requirements of this part and

ANSI/NFPA 58 and 59.

(b) Each pipeline system subject to this part that transports only

petroleum gas or petroleum gas/air mixtures must meet the requirements

of this part and of ANSI/NFPA 58 and 59.

(c) In the event of a conflict between this part and ANSI/NFPA 58

and 59, ANSI/NFPA 58 and 59 prevail.

7. Section 192.107(b)(1)(ii) is revised to read as follows:

Sec. 192.107 Yield strength (S) for steel pipe.

* * * * *

(b) * * *

(1) * * *

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

* * * * *

8. Section 192.121 is revised to read as follows:

Sec. 192.121 Design of plastic pipe.

Subject to the limitations of Sec. 192.123, the design pressure for

plastic pipe is determined in accordance with either of the following

formulas:

[GRAPHIC] [TIFF OMITTED] TR06JN96.013

Where:

P=Design pressure, gauge, kPa (psig).

S=For thermoplastic pipe, the long-term hydrostatic strength determined

in accordance with the listed specification at a temperature equal to

23 deg.C (73 deg.F), 38 deg.C (100 deg.F), 49 deg.C (120 deg.F), or

60 deg.C (140 deg.F); for reinforced thermosetting plastic pipe, 75,842

kPa (11,000 psi).

t=Specified wall thickness, mm (in).

D=Specified outside diameter, mm (in).

SDR=Standard dimension ratio, the ratio of the average specified

outside diameter to the minimum specified wall thickness, corresponding

to a value from a common numbering system that was derived from the

American National Standards Institute preferred number series 10.

9. Section 192.123(b) is revised to read as follows:

Sec. 192.123 Design limitations for plastic pipe.

* * * * *

(b) * * *

(1) Below -29 deg.C (-20 deg.F), or -40 deg.C (-40 deg.F) if all

pipe and pipeline components whose operating temperature will be below

-29 deg.C (-20 deg.F) have a temperature rating by the manufacturer

consistent with that operating temperature; or

(2) Above the following applicable temperatures:

(i) For thermoplastic pipe, the temperature at which the long-term

hydrostatic strength used in the design formula under Sec. 192.121 is

determined. However, if the pipe was manufactured before May 18, 1978

and its long-term hydrostatic strength was determined at 23 deg.C

(73 deg.F), it may be used at temperatures up to 38 deg.C (100 deg.F).

(ii) For reinforced thermosetting plastic pipe, 66 deg.C

(150 deg.F).

* * * * *

[[Page 28784]]

10. The introductory text of Sec. 192.179(a) is revised to read as

follows:

Sec. 192.179 Transmission line valves.

(a) Each transmission line, other than offshore segments, must have

sectionalizing block valves spaced as follows, unless in a particular

case the Administrator finds that alternative spacing would provide an

equivalent level of safety:

* * * * *

11. Section 192.203(b)(2) is revised to read as follows:

Sec. 192.203 Instrument, control, and sampling pipe and components.

* * * * *

(b) * * *

(2) Except for takeoff lines that can be isolated from sources of

pressure by other valving, a shutoff valve must be installed in each

takeoff line as near as practicable to the point of takeoff. Blowdown

valves must be installed where necessary.

* * * * *

12. Section 192.227(b) is revised to read as follows:

Sec. 192.227 Qualification of welders.

* * * * *

(b) A welder may qualify to perform welding on pipe to be operated

at a pressure that produces a hoop stress of less than 20 percent of

SMYS by performing an acceptable test weld, for the process to be used,

under the test set forth in section I of Appendix C of this part. Each

welder who is to make a welded service line connection to a main must

first perform an acceptable test weld under section II of Appendix C of

this part as a requirement of the qualifying test.

13. In Sec. 192.229, paragraph (c) is revised and paragraph (d) is

added to read as follows:

Sec. 192.229 Limitations on welders.

* * * * *

(c) A welder qualified under Sec. 192.227(a)--

(1) May not weld on pipe to be operated at a pressure that produces

a hoop stress of 20 percent or more of SMYS unless within the preceding

6 calendar months the welder has had one weld tested and found

acceptable under section 3 or 6 of API Standard 1104, except that a

welder qualified under an earlier edition previously listed in Appendix

A of this part may weld but may not requalify under that earlier

edition; and

(2) May not weld on pipe to be operated at a pressure that produces

a hoop stress of less than 20 percent of SMYS unless the welder is

tested in accordance with paragraph (c)(1) of this section or

requalifies under paragraph (d)(1) or (d)(2) of this section.

(d) A welder qualified under Sec. 192.227(b) may not weld unless--

(1) Within the preceding 15 calendar months, but at least once each

calendar year, the welder has requalified under Sec. 192.227(b); or

(2) Within the preceding 7\1/2\ calendar months, but at least twice

each calendar year, the welder has had--

(i) A production weld cut out, tested, and found acceptable in

accordance with the qualifying test; or

(ii) For welders who work only on service lines 2 inches or smaller

in diameter, two sample welds tested and found acceptable in accordance

with the test in section III of Appendix C of this part.

14. Section 192.241(c) is revised to read as follows:

Sec. 192.241 Inspection and test of welds.

* * * * *

(c) The acceptability of a weld that is nondestructively tested or

visually inspected 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 further determined under that Appendix.

15. Section 192.243(d)(4) is revised to read as follows:

Sec. 192.243 Nondestructive testing.

* * * * *

(d) * * *

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

100 percent.

* * * * *

16. In Sec. 192.281, paragraph (c)(3) is redesignated as paragraph

(c)(4) and paragraph (c)(3) is added to read as follows:

Sec. 192.281 Plastic pipe.

* * * * *

(c) * * *

(3) An electrofusion joint must be joined utilizing the equipment

and techniques of the fittings manufacturer or equipment and techniques

shown, by testing joints to the requirements of

Sec. 192.283(a)(1)(iii), to be at least equivalent to those of the

fittings manufacturer.

* * * * *

17. In Sec. 192.283, the word ``or'' is removed from the end of

paragraph (a)(1)(i), paragraph (a)(1)(ii) is revised, and paragraph

(a)(1)(iii) is added to read as follows:

Sec. 192.283 Plastic pipe; qualifying joining procedures.

(a) * * *

(1) * * *

(ii) In the case of thermosetting plastic pipe, paragraph 8.5

(Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static

Pressure Test) of ASTM D2517; or

(iii) In the case of electrofusion fittings for polyethylene pipe

and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test),

paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile

Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM

Designation F1055.

* * * * *

18. Section 192.317(a) is revised to read as follows:

Sec. 192.317 Protection from hazards.

(a) The operator must take all practicable steps to protect each

transmission line or main from washouts, floods, unstable soil,

landslides, or other hazards that may cause the pipeline to move or to

sustain abnormal loads. In addition, the operator must take all

practicable steps to protect offshore pipelines from damage by mud

slides, water currents, hurricanes, ship anchors, and fishing

operations.

* * * * *

19. Section 192.319(c) is revised to read as follows:

Sec. 192.319 Installation of pipe in a ditch.

* * * * *

(c) All offshore pipe in water at least 12 feet deep but not more

than 200 feet deep, as measured from the mean low tide, except pipe in

the Gulf of Mexico and its inlets under 15 feet of water, 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. Pipe in

the Gulf of Mexico and its inlets under 15 feet of water must be

installed so that the top of the pipe is 36 inches below the seabed for

normal excavation or 18 inches for rock excavation.

20. In Sec. 192.321, paragraph (a) is revised and paragraph (g) is

added to read as follows:

Sec. 192.321 Installation of plastic pipe.

(a) Plastic pipe must be installed below ground level unless

otherwise permitted by paragraph (g) of this section.

* * * * *

(g) Uncased plastic pipe may be temporarily installed above ground

level under the following conditions:

[[Page 28785]]

(1) The operator must be able to demonstrate that the cumulative

aboveground exposure of the pipe does not exceed the manufacturer's

recommended maximum period of exposure or 2 years, whichever is less.

(2) The pipe either is located where damage by external forces is

unlikely or is otherwise protected against such damage.

(3) The pipe adequately resists exposure to ultraviolet light and

high and low temperatures.

21. In Sec. 192.327, the introductory text of paragraph (a) is

revised, paragraph (e) is revised, and paragraphs (f) and (g) are added

to read as follows:

Sec. 192.327 Cover.

* * * * *

(a) Except as provided in paragraphs (c), (e), (f), and (g) of this

section, each buried transmission line must be installed with a minimum

cover as follows:

* * * * *

(e) Except as provided in paragraph (c) of this section, all pipe

installed in a navigable river, stream, or harbor must be installed

with a minimum cover of 48 inches in soil or 24 inches in consolidated

rock between the top of the pipe and the natural bottom.

(f) All pipe installed offshore, except in the Gulf of Mexico and

its inlets, under water not more than 200 feet deep, as measured from

the mean low tide, must be installed as follows:

(1) Except as provided in paragraph (c) of this section, pipe under

water less than 12 feet deep, must be installed with a minimum cover of

36 inches in soil or 18 inches in consolidated rock between the top of

the pipe and the natural bottom.

(2) Pipe under water at least 12 feet deep 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.

(g) All pipelines installed under water in the Gulf of Mexico and

its inlets, as defined in Sec. 192.3, must be installed in accordance

with Sec. 192.612(b)(3).

22. Section 192.375(a) is revised to read as follows:

Sec. 192.375 Service lines: Plastic.

(a) Each plastic service line outside a building must be installed

below ground level, except that--

(1) It may be installed in accordance with Sec. 192.321(g); and

(2) It may terminate above ground level and outside the building,

if--

(i) The above ground level part of the plastic service line is

protected against deterioration and external damage; and

(ii) The plastic service line is not used to support external

loads.

* * * * *

23. In Sec. 192.455, paragraphs (a)(2) and (f)(1) are revised to

read as follows:

Sec. 192.455 External corrosion control: Buried or submerged pipelines

installed after July 31, 1971.

(a) * * *

(2) It must have a cathodic protection system designed to protect

the pipeline in accordance with this subpart, installed and placed in

operation within 1 year after completion of construction.

* * * * *

(f) * * *

(1) For the size fitting to be used, an operator can show by test,

investigation, or experience in the area of application that adequate

corrosion control is provided by the alloy composition; and

* * * * *

24. Section 192.475(c) is revised to read as follows:

Sec. 192.475 Internal corrosion control: General.

* * * * *

(c) Gas containing more than 0.25 grain of hydrogen sulfide per 100

standard cubic feet (4 parts per million) may not be stored in pipe-

type or bottle-type holders.

25. Section 192.485(c) is added to read as follows:

Sec. 192.485 Remedial measures: Transmission lines.

* * * * *

(c) Under paragraphs (a) and (b) of this section, the strength of

pipe based on actual remaining wall thickness may be determined by the

procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research

Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply

to corroded regions that do not penetrate the pipe wall, subject to the

limitations prescribed in the procedures.

26. Section 192.491 is revised to read as follows:

Sec. 192.491 Corrosion control records.

(a) Each operator shall maintain records or maps to show the

location of cathodically protected piping, cathodic protection

facilities, galvanic anodes, and neighboring structures bonded to the

cathodic protection system. Records or maps showing a stated number of

anodes, installed in a stated manner or spacing, need not show specific

distances to each buried anode.

(b) Each record or map required by paragraph (a) of this section

must be retained for as long as the pipeline remains in service.

(c) Each operator shall maintain a record of each test, survey, or

inspection required by this subpart in sufficient detail to demonstrate

the adequacy of corrosion control measures or that a corrosive

condition does not exist. These records must be retained for at least 5

years, except that records related to Secs. 192.465 (a) and (e) and

192.475(b) must be retained for as long as the pipeline remains in

service.

27. Section 192.553(d) is revised to read as follows:

Sec. 192.553 General requirements.

* * * * *

(d) Limitation on increase in maximum allowable operating pressure.

Except as provided in Sec. 192.555(c), a new maximum allowable

operating pressure established under this subpart may not exceed the

maximum that would be allowed under this part for a new segment of

pipeline constructed of the same materials in the same location.

However, when uprating a steel pipeline, if any variable necessary to

determine the design pressure under the design formula (Sec. 192.105)

is unknown, the MAOP may be increased as provided in

Sec. 192.619(a)(1).

Sec. 192.607 [Removed and reserved]

28. Section 192.607 is removed and reserved.

Sec. 192.611 [Amended]

29. In Sec. 192.611, paragraphs (b) and (c) are redesignated as (c)

and (d), respectively; paragraph (a)(3)(ii) is redesignated as

paragraph (b), and paragraph (a)(3)(iii) is redesignated as paragraph

(a)(3)(ii).

30. In Sec. 192.614, the introductory text of paragraph (b)(2) is

revised to read as follows:

Sec. 192.614 Damage prevention program.

* * * * *

(b) * * *

(2) Provide for general notification of the public in the vicinity

of the pipeline and actual notification of the persons identified in

paragraph (b)(1) of the following as often as needed to make them aware

of the damage prevention program:

* * * * *

31. In Sec. 192.619, paragraph (a)(1) is revised to read as

follows, paragraphs (a)(4) and (a)(5) are removed, paragraph (a)(6) is

redesignated as paragraph (a)(4), and paragraph (b) is amended by

removing ``(a)(6)'' and adding ``(a)(4)'' in its place:

Sec. 192.619 Maximum allowable operating pressure: Steel or plastic

pipelines.

(a) * * *

[[Page 28786]]

(1) The design pressure of the weakest element in the segment,

determined in accordance with subparts C and D of this part. However,

for steel pipe in pipelines being converted under Sec. 192.14 or

uprated under subpart K of this part, if any variable necessary to

determine the design pressure under the design formula (Sec. 192.105)

is 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 factor in paragraph (a)(2)(ii) of this section; or

(ii) If the pipe is 324 mm (12\3/4\ in) or less in outside diameter

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

* * * * *

32. Section 192.625 (f) is revised to read as follows:

Sec. 192.625 Odorization of gas.

* * * * *

(f) Each operator shall conduct periodic sampling of combustible

gases to assure the proper concentration of odorant in accordance with

this section. Operators of master meter systems may comply with this

requirement by--

(1) Receiving written verification from their gas source that the

gas has the proper concentration of odorant; and

(2) Conducting periodic ``sniff'' tests at the extremities of the

system to confirm that the gas contains odorant.

33. Section 192.705(c) is added to read as follows:

Sec. 192.705 Transmission lines: Patrolling.

* * * * *

(c) Methods of patrolling include walking, driving, flying or other

appropriate means of traversing the right-of-way.

34. Section 192.709 is revised to read as follows:

Sec. 192.709 Transmission lines: Record keeping.

Each operator shall maintain the following records for transmission

lines for the periods specified:

(a) The date, location, and description of each repair made to pipe

(including pipe-to-pipe connections) must be retained for as long as

the pipe remains in service.

(b) The date, location, and description of each repair made to

parts of the pipeline system other than pipe must be retained for at

least 5 years. However, repairs generated by patrols, surveys,

inspections, or tests required by subparts L and M of this part must be

retained in accordance with paragraph (c) of this section.

(c) A record of each patrol, survey, inspection, and test required

by subparts L and M of this part must be retained for at least 5 years

or until the next patrol, survey, inspection, or test is completed,

whichever is longer.

35. Section 192.721(b) is revised to read as follows:

Sec. 192.721 Distribution systems: Patrolling.

* * * * *

(b) Mains in places or on structures where anticipated physical

movement or external loading could cause failure or leakage must be

patrolled--

(1) In business districts, at intervals not exceeding 4\1/2\

months, but at least four times each calendar year; and

(2) Outside business districts, at intervals not exceeding 7\1/2\

months, but at least twice each calendar year.

36. In Appendix A, section I. is amended by redesignating

subsections A. through F. as subsections B. through G., respectively,

and by adding a new subsection A.; and section II. is amended by

redesignating subsections A. through E. as subsections B. through F.,

respectively, by adding a new subsection A. and a new subsection 12. to

newly designated C., by redesignating newly designated subsections D.3.

through D.5. as subsections D.5. through D.7., respectively, and by

adding new subsections D.3. and D.4. as follows:

Appendix A--Incorporated by Reference

I. * * *

A. American Gas Association (AGA), 1515 Wilson Boulevard,

Arlington, VA 22209.

* * * * *

II. * * *

A. American Gas Association (AGA):

1. AGA Pipeline Research Committee, Project PR-3-805, ``A

Modified Criterion for Evaluating the Remaining Strength of Corroded

Pipe'' (December 22, 1989).

* * * * *

C. * * *

12. ASTM Designation: F1055 ``Standard Specification for

Electrofusion Type Polyethylene Fittings for Outside Diameter

Controlled Polyethylene Pipe and Tubing'' (F1055-95).

D. * * *

3. ASME/ANSI B31G ``Manual for Determining the Remaining

Strength of Corroded Pipelines'' (1991).

4. ASME/ANSI B31.8 ``Gas Transmission and Distribution Piping

Systems'' (1995).

* * * * *

Issued in Washington, DC, on May 28, 1996.

D.K. Sharma,

Administrator.

[FR Doc. 96-13787 Filed 6-5-96; 8:45 am]

BILLING CODE 4910-60-P