63 FR 5918 - Risk-Based Alternative To Pressure Testing Older Hazardous Liquid and Carbon Dioxide Pipelines Rule | Regulus

Passage 1[Federal Register Volume 63, Number 24 (Thursday, February 5, 1998)] [Proposed Rules] [Pages 5918-5924] From the Federal Register Online via the Government Publishing Office [www.gpo.gov] [FR Doc No: 98-2860] ----------------------------------------------------------------------- Research and Special Programs Administration [Docket No. PS-144; Notice 2] [RIN 2137-AC 78] Risk-Based Alternative To Pressure Testing Older Hazardous Liquid and Carbon Dioxide Pipelines Rule AGENCY: Research and Special Programs Administration (RSPA), DOT. ----------------------------------------------------------------------- SUMMARY: This notice proposes to allow operators of older hazardous liquid and carbon dioxide pipelines to elect a risk-based alternative in lieu of the existing rule. The existing rule requires the hydrostatic pressure testing of certain older pipelines. The risk-based alternative would allow operators to elect an approach to evaluating the integrity of these lines that takes into account individual risk factors. This would allow operators to focus resources on higher risk pipelines and effect a greater reduction in the overall risk from pipeline accidents. DATES: Interested persons are invited to submit comments on this notice of proposed rulemaking (NPRM) by April 6, 1998. Late filed comments will be considered to the extent practicable. ADDRESSES: Written comments must be submitted in duplicate and mailed or hand-delivered to the Dockets Unit, Room 8421, U.S. Department of Transportation, 400 Seventh Street, SW., Washington, DC 20590-0001. Identify the docket and notice number stated in the heading of this notice. Comments will become part of this docket and will be available for inspection or copying in Room 8421 between 8:30 a.m. and 5 p.m. each business day. FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571, regarding the subject matter of this proposed rule, or Dockets Unit (202) 366- 4453, for copies of this final rule document or other material in the docket.#

Passage 2On June 7, 1994, RSPA published a final rule, ``Pressure Testing Older Hazardous Liquid and Carbon Dioxide Pipelines,'' (Amdt. 195-51; 59 FR 29379) to ensure that certain older pipelines have an adequate safety margin between their maximum operating pressure and test pressure. This safety margin is to be provided by pressure testing according to part 195 standards or operation at 80 percent or less of a qualified prior test or operating pressure. The pipelines covered by the rule are steel interstate pipelines constructed before January 8, 1971, steel interstate offshore gathering lines constructed before August 1, 1977, or steel intrastate pipelines constructed before October 21, 1985, that transport hazardous liquids subject to part 195. Also covered are steel carbon dioxide pipelines constructed before July 12, 1991, subject to part 195. On June 23, 1995, the American Petroleum Institute (API) filed a petition on behalf of many liquid pipeline operators that proposed a risk-based alternative to the required pressure testing rule. API indicated that its proposal would allow operators to focus resources on higher risk pipelines and to effect a greater reduction in the overall risk from pipeline accidents. In order to determine whether the API proposal had merit, RSPA held a public meeting on March 25, 1996. On May 8 and November 7, 1996, and on May 17, 1997, RSPA briefed the Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC) on the API proposal and steps taken by RSPA to develop a proposed rule. As discussed in more detail below, RSPA finds considerable merit in a risk-based approach to pressure testing of older hazardous liquid pipelines. It provides accelerated testing of electric resistance welded (ERW) pipe, incorporates the use of new technology, and provides for continuing internal inspection of older pipelines through a pigging program. RSPA has been working actively with the pipeline industry to develop a risk management framework for pipeline regulations. The API proposal is consistent with the risk assessment and management approach to safety. The API proposal provides an opportunity to pilot a risk-based approach in a rulemaking forum. Accordingly, this notice of proposed rulemaking proposes a risk-based alternative to the pressure testing rule that has been modeled after the API proposal. RSPA has extended time for complian#

Passage 3ce with the pressure testing rule in order to allow completion of this rulemaking on a risk-based alternative. The deadline for complying with Sec. 195.302 (c)(1) is extended to December 7, 1998. The deadline for complying with Sec. 195.302(c)(2)(i) is extended to December 7, 2000. The deadline for complying with Sec. 195.302(c)(2)(ii) is extended to December 7, 2003. [62 FR 54591; October 21, 1997]. RSPA seeks comment and information on how to measure the performance of this risk-based alternative to determine effectiveness, particularly in comparison with the pressure test rule. II. Major features of risk-based alternative The proposed risk-based alternative to the rule requiring the pressure testing of older pipelines has six main features: 1. Highest Priority is Given to the Highest Risk Facilities; Lowest Risk Facilities are Excepted From Additional Measures Pre-1970 electric resistance welded (ERW) and lapweld pipelines susceptible to longitudinal seam failures exhibit the highest potential risk because of their combination of probability of failure and potential for larger volume releases as evidenced by historical records. Pressure testing is the only available technology for verifying the integrity of pre-1970 ERW and lapweld pipelines, because it can detect the type of seam failures endemic to some ERW and all lapweld pipe. This risk-based alternative requires accelerated testing of pre-1970 ERW and lapweld pipe susceptible to longitudinal seam failure in certain locations (risk classification C and B) where people might be significantly affected. However, in rural areas (risk classification A), where consequences to the public are less significant, the risk-based alternative allows delayed testing for pre- 1970 ERW and lapweld pipe susceptible to longitudinal failure and allows the operator to determine the need for pressure testing of other types of pipe. 2. Consequence Factors Such as Location, Product Type, and Release Potential are Taken Into Consideration When Setting Testing Priorities#

Passage 4This risk-based alternative takes into account the most significant variables that may impact the severity of a release, i.e., location with respect to populated areas, the nature of the product transported, and the potential volume of product release. Historically, a very small percentage of releases adversely impacted public safety. By taking these potential consequences into consideration in the timing of tests, an operator's resources will be more effectively applied to reduce risks. 3. Best Available Technology is Applied To Verify Pipeline Integrity The risk-based alternative encourages the use of the most effective means to ensure pipeline integrity. This proposal utilizes the strength of two primary technologies--pressure testing and magnetic flux leakage/ultrasonic internal inspection devices. Each technology provides testing advantages in particular circumstances. This proposal allows the operator to evaluate the pipeline risk considerations and to choose the most appropriate technology. Considering the probability and consequence factors, the risk-based concept increases the priority of a limited amount of pre-1970 ERW and all lapweld pipelines and maintains the three-year timing for risk classification B and C lines which represent the highest risk to people. Pipelines with lower risks (risk classification A) are allowed a longer testing schedule or are eliminated (non high risk pre-1970 ERW pipelines) from a mandatory testing requirement. Nothing in this proposed alternative precludes an operator from accelerating these schedules based on their pipeline operating and maintenance history. This proposal would allow operators options that require less test water and generate less water requiring treatment. 6. Provides an Opportunity To Reduce Operating Costs and Maintain the Necessary Margins of Safety by Applying the Risk-based Concept Acceptance and implementation of this proposal provides an opportunity to pilot a risk-based approach to regulation. OPS anticipates increased use of risk-based approaches in future rulemakings. RSPA is proposing to add a new section to Part 195 entitled ``Risk- based alternative to pressure testing.'' Existing sections Sec. 195.303 ``Test pressure'', and Sec. 195.304 ``Testing of components'' will be renumbered as Sec. 195.304 and Sec. 195.305 respectively.#

Passage 5Proposed new section Sec. 195.303 ``Risk-based alternative to pressure testing'' would allow an operator of older hazardous liquid and carbon dioxide pipeline to elect an approach to evaluating the integrity of lines that takes into account individual risk factors. This alternative establishes test priorities based on the inherent risk of a given pipeline segment. Each pipeline is assigned a risk classification based on several indicators. In assigning a risk classification to a given pipeline segment, the first step is to determine whether or not the segment contains pre-1970 ERW and lap-weld pipe susceptible to longitudinal seam failures \1\. --------------------------------------------------------------------------- \1\ Certain pre-1970 ERW and lap-weld pipeline segments are susceptible to longitudinal seam failures. An Operator must consider the seam-related leak history of the pipe and pipe manufacturing information as available, which may include the pipe steel's mechanical properties, including fracture toughness; the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low- frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel-making process; and other factors pertinent to seam properties and quality. ---------------------------------------------------------------------------#

Passage 6The next step is to determine the pipeline segment's proximity to populated areas (Location). We are not now proposing to include environmentally sensitive locations within the risk factors for application of the alternative. This is consistent with the API proposal for a risk based alternative. Following public briefings on the progress of the rulemaking at the THLPSSC meetings in November 1996 and May 1997, API objected to inclusion of an environmental factor as premature in light of the ongoing rulemaking to define unusually sensitive areas (USAs). While we do not necessarily agree that a definition of USAs will provide the sole basis for inclusion of an environmental factor for a risk-based alternative to pressure testing, we recognize the difficulties in including such a factor before the USA definition is formulated. The difficulty in even articulating a factor at this time was made very apparent by THLPSSC members at the May 1997 meeting (while one member argued that the environmental factor under consideration for the proposed rule was inadequate, two other members challenged that argument) and discussions with the members and API following that meeting. Because this alternative takes into consideration other significant risk factors that may impact severity of a release, i.e., proximity to populated areas, potential volume of the product release, the nature of product transported, pipeline failure history and pipeline susceptible to longitudinal seam failures, it is unlikely that pipeline testing is being undermined by not considering the environmental factor in the interim. Therefore, we have decided to omit an environmental factor at this time and explore the issue further once we have defined ``unusually sensitive areas''. The risk classification of a segment is also adjusted based on the pipeline failure history, the product transported, and the volume potentially releasable in a failure. Additional guidance for use of the alternative is provided in a new proposed Appendix B. The pipeline failure history, denoted in the proposed rule as ``Probability of Failure Indicator,'' is an important factor. The history of past failures (types of failures, number of failures, sizes of releases, etc.) plays an important role in determining the chances of future occurrences for a particular pipeline system. Therefore, it has been included as risk factor in t#

Passage 7he matrix for determining the risk classification. In the proposed rule the probability of failure indicator is considered ``high risk'' if the pipeline segment has experienced more than three failures in last 10 years due to time- dependent defects (due to corrosion, gouges, or problems developed during manufacture, construction or operation, etc.). Pipeline operators should make an appropriate investigation of spills to determine whether they are due to time-dependent defects. An operator's determination should be based on sound engineering judgment and be documented. RSPA seeks comment on whether some failures are so minimal as to be appropriately excluded from the failure history risk factor. If so, how should the failure be quantified? Should it only be a reportable incident? In addition, the proposed rule provides compliance dates and recordkeeping requirements for those operators who elect the risk-based alternative to pressure testing of older hazardous liquid and carbon dioxide pipelines. RSPA believes the proposed rule will provide the pipeline industry with the flexibility to elect alternative technology for evaluating pipeline integrity without sacrificing safety. Executive Order 12866 and DOT Regulatory Policies and Procedures#

Passage 8This proposed rule is a significant regulatory action under Executive Order 12866. Therefore, this notice was reviewed by the Office of Management and Budget. In addition, this proposed rule is significant under DOT's regulatory policies and procedures (44 FR 11034; February 26, 1979) because it is the first explicitly risk-based approach to rulemaking proposed by the Office of Pipeline Safety. A copy of the draft regulatory evaluation to this proposal is also available in the docket office for review. This section summarizes the conclusions of the draft regulatory evaluation. RSPA's pressure testing final rule was published on June 7, 1994 (59 FR 29379) along with a regulatory evaluation which found that the rule had a positive net benefit to the public, i.e., the benefits of the rule exceeded the cost (Present value costs of the earlier proposal were estimated to be between $134-$179 million in 1997 dollars while the present value benefits were estimated as $230-$283 million). Since the risk-based alternative maintains the necessary margins of safety, the benefits of this alternative should be similar to the benefits of the earlier proposal. The present value costs for the risk- based alternative are estimated to be between $88.4-$98.4 million for reasons described below. The proposed rule allows the use of alternative technology (smart pigs) for evaluating pipeline integrity. On average smart pig testing is less expensive than pressure testing by $2,650/mile. In some cases smart pig technology provides more information about pipeline anomalies than pressure testing. The alternative would reduce the total amount of test water, which should lower the waste treatment costs and generate less hazardous waste. The alternative would allow operators to forgo testing where pipelines have low operating pressures, transport non-volatile product, operate in rural areas, and have good records on pipeline failure history. This risk-based approach is an ongoing process. RSPA believes that the risk-based alternative maintains the necessary margins of safety for the public. Moreover, RSPA concludes that this alternative has the potential for positive improvements for the environment while reducing operating costs by allowing operators to elect those test methods most appropriate to the circumstances of each pipeline. Regulatory Flexibility Act The regulatory flexibility a#

Passage 9nalysis of the earlier final rule concluded that it would not have a significant impact on a substantial number of small entities. RSPA believes that because this proposed regulation offers an alternative to operators that could reduce the impact of the earlier regulation, this#

Passage 10proposed rule does not have a significant impact on a substantial number of small entities. Based on the facts available about the anticipated impact of this rulemaking action, I certify pursuant to Section 605 of the Regulatory Flexibility Act (5 U.S.C. 605) that the action will not have a significant economic impact on a substantial number of small entities. However, RSPA does not currently have specific information about small entities which may elect to use this alternative to pressure testing. RSPA requests comments from small entities directed at the impacts of this proposed rule. Executive Order 12612 This rulemaking action will 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 E.O. 12612 (52 FR 41685; October 30, 1987), RSPA has determined that this final rule does not have sufficient federalism implications to warrant preparation of a Federalism Assessment. Paperwork Reduction Act This rule does not substantially modify the paperwork burden on pipeline operators. Under the current pressure testing regulations operators are required to have testing plans, schedules, and records. The risk-based alternative would require the same or equivalent plans, schedules, and records for either pressure testing or internal inspection. Therefore, there is no additional paperwork required. Operators who choose the risk-based alternative will be required to have records that the pipeline segment which is not being tested qualifies for the risk-based alternative. According to conversations between OPS and the pipeline industry some of this information is already available in the form of drawings or plans that can be found either in operators' Facility Response Plans required by the Oil Pollution Act of 1990 (OPA 90) or in emergency response plans required by RSPA. Operators will be required to periodically review the pipelines that qualify for the risk-based alternative to ensure that they still qualify. OPS believes that operators can conduct this review as part of their normal procedures. Because of the above analysis, OPS does not believe that operators will have any additional paperwork burden because of this alternative, and therefore no separate paperwork submission is required#

Passage 11. National Environmental Policy Act RSPA has analyzed this action for purposes of the National Environmental Policy Act (42 U.S.C. 4321 et seq.) and has determined that this action would not significantly affect the quality of the human environment. An Environmental Assessment and a Finding of No Significant Impact are in the docket. Anhydrous ammonia, Carbon dioxide, Petroleum, Pipeline safety, Reporting and recordkeeping requirements. In consideration of the foregoing, RSPA proposes to amend part 195 of title 49 of the Code of Federal Regulations as follows: 1. The authority citation for part 195 continues to read as follows: Authority: 49 U.S.C. 60102, 60104, 60108, and 60109; and 49 CFR 1.53. 2. Section 195.302 would be amended by adding a new paragraph (b)(4) to read as follows: * * * * * (b) * * * (4) Those portions of older hazardous liquid and carbon dioxide pipelines for which an operator has elected the risk-based alternative under Sec. 195.303 and which are not required to be tested based on the risk-based criteria. * * * * * 3. Section 195.302(a) is amended by removing cross-reference ``Sec. 195.304(b)'' and adding in its place cross-reference ``Sec. 195.305(b)''. 4. In paragraph (c) of Sec. 195.302, the introductory text would be revised to read as follows: * * * * * (c) Except for pipelines that transport HVL onshore, low-stress pipelines, and pipelines covered under Sec. 195.303, the following compliance deadlines apply to pipelines under paragraphs (b)(1) and (b)(2)(i) of this section that have not been pressure tested under this subpart: * * * * * 5. Section 195.303 ``Test pressure'' and Sec. 195.304 ``Testing of components'' are redesignated as Sec. 195.304 ``Test pressure'' and Sec. 195.305 ``Testing of components'' 6. Part 195 would be amended by adding a new Sec. 195.303 to read as follows: Sec. 195.303 Risk-based alternative to pressure testing older hazardous liquid and carbon dioxide pipelines.#

Passage 12(a) An operator may elect to follow a program for testing a pipeline on risk-based criteria as an alternative to the pressure testing in Sec. 195.302(b)(1)(i) through (iii) and Sec. 195.302(b)(2)(i) of this subpart. Appendix B provides guidance on how this program will work. An operator electing such a program shall assign a risk classification to each pipeline segment according to the indicators described in paragraph (b) of this section as follows: (1) Risk Classification A if the location indicator is ranked as low or medium risk, the product and volume indicators are ranked as low risk, and the probability of failure indicator is ranked as low risk; (2) Risk Classification C if the location indicator is ranked as high risk; or (3) Risk Classification B. (b) An operator shall evaluate each pipeline segment in the program according to the following indicators of risk: (1) The location indicator is-- (i) High risk if an area is non-rural \1\; or --------------------------------------------------------------------------- \1\ An environmental factor will be considered in a later rulemaking. --------------------------------------------------------------------------- (ii) Medium risk \2\; or --------------------------------------------------------------------------- \2\ Not currently applicable; it may be applicable with addition of environmental factor to the location indicator. --------------------------------------------------------------------------- (iii) Low risk if an area is not high or medium risk. (2) The product indicator is-- (i) High risk if the product transported is highly toxic or is both highly volatile and flammable; (ii) Medium risk if the product transported is flammable with a flashpoint of less than 100 deg. F, but not highly volatile; or (iii) Low risk if the product transported is not high or medium risk. (3) The volume indicator is-- (i) High risk if the line is at least 18 inches in nominal diameter; (ii) Medium risk if the line is at least 10 inches, but less than 18 inches, in nominal diameter; or (iii) Low risk if the line is not high or medium risk. (4) The probability of failure indicator is-- (i) High risk if the segment has experienced more than three failures in the last 10 years due to time-dependent defects (e.g., corrosion, gouges, or problems developed during manufacture, construction or operation, etc.); or#

Passage 13(ii) Low risk if the segment has experienced less than three failures in the last 10 years due to time-dependent defects. (c) The program under paragraph (a) of this section shall provide for pressure testing for a segment constructed of electric resistance- welded (ERW) pipe and lapweld pipe manufactured prior to 1970 susceptible to longitudinal seam failures as determined through paragraph (d) of this section. The timing of such pressure test may be determined based on risk classifications discussed under paragraph (b) of this section. For other segments, the program may provide for use of a magnetic flux leakage or ultrasonic internal inspection survey as an alternative to pressure testing and, in the case of such segments in Risk Classification A, may provide for no additional measures. (d) All pre-1970 ERW pipe and lapweld pipe is deemed susceptible to longitudinal seam failures unless an engineering analysis shows otherwise. In conducting an engineering analysis an operator must consider the seam-related leak history of the pipe and pipe manufacturing information as available, which may include the pipe steel's mechanical properties, including fracture toughness; the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel-making process; and other factors pertinent to seam properties and quality. (e) Pressure testing done under this section must be conducted in accordance with this subpart. Except for segments in Risk Classification B which are not constructed with pre-1970 ERW pipe, water must be the test medium. (f) An operator electing to follow a program under paragraph (a) of this section must develop plans that include the method of testing and a schedule for the testing by December 7, 1998. The compliance deadlines for completion of testing are as shown in the table below: Table: Sec. 195.303--Test deadlines#

Passage 14---------------------------------------------------------------------------------------------------------------- Pipeline segment Risk classification Test deadline ---------------------------------------------------------------------------------------------------------------- Pre-1970 Pipe susceptible to C or B 12/7/2000 longitudinal seam failures [defined A in Sec. 195.303(c) & (d)]. 12/7/2002 All Other Pipeline.................... C 12/7/2002 Segments.............................. B 12/7/2004 A Additional testing not required. ---------------------------------------------------------------------------------------------------------------- (g) An operator must review the risk classifications at intervals not to exceed 15 months. If the risk classification of a segment changes, an operator must take appropriate action within two years, or establish the maximum operating pressure under Sec. 195.406(a)(5). (h) An operator must maintain records establishing compliance with this section, including records verifying the risk classifications, the plans and schedule for testing, the conduct of the testing, and the review of the risk classifications. (i) An operator may discontinue a program under this section only after written notification to the Administrator and approval, if needed, of a schedule for pressure testing. 7. Section 195.406(a)(4) is amended by removing cross-reference ``Sec. 195.304'' and adding cross-reference ``Sec. 195.305'' in its place. 8. A new Appendix B would be added to Part 195 to read as follows: Appendix B to Part 195--Risk-Based Alternative to Pressure Testing Older Hazardous Liquid and Carbon Dioxide Pipelines#

Passage 15This Appendix provides guidance on how a risk-based alternative to pressure testing older hazardous liquid and carbon dioxide pipelines rule allowed by Sec. 195.303 will work. This risk-based alternative establishes test priorities for older pipelines, not previously pressure tested, based on the inherent risk of a given pipeline segment. The first step is to determine the classification based on the type of pipe or on the pipeline segment's proximity to populated. Secondly, the classifications must be adjusted based on the pipeline failure history, product transported, and the release volume potential. Tables 2 through 6 give definitions of risk classification A, B, and C facilities. For the purposes of this rule, pipeline segments containing high risk electric resistance-welded pipe (ERW pipe) and lapwelded pipe manufactured prior to 1970 and considered a risk classification C or B facility shall be treated as the top priority for testing because of the higher risk associated with the susceptibility of this pipe to longitudinal seam failures. In all cases, operators shall annually, at intervals not to exceed 15 months, review their facilities to reassess the classification and shall take appropriate action within two years or operate the pipeline system at a lower pressure. Pipeline failures, changes in the characteristics of the pipeline route, or changes in service should all trigger a reassessment of the originally classification. Table 1 explains different levels of test requirements depending on the inherent risk of a given pipeline segment. The overall risk classification is determined based on the type of pipe involved, the facility's location, the product transported, the relative volume of flow and pipeline failure history as determined from Tables 2 through 6.#

Passage 16Table 1.--Test Requirements--Mainline Segments Outside of Terminals, Stations, and Tank Farms ---------------------------------------------------------------------------------------------------------------- Pipeline segment Risk classification Test deadline \1\ Test medium ---------------------------------------------------------------------------------------------------------------- Pre-1970 Pipeline Segments C or B 12/7/2000 \3\ Water only. susceptible to longitudinal A 12/7/2002 \3\ Water only. seam failures \2\. All Other Pipeline Segments. C 12/7/2002 \4\ Water only. B 12/7/2004 \4\ Water/Liq.\5\#

Passage 17A Additional pressure testing not required. ---------------------------------------------------------------------------------------------------------------- \1\ If operational experience indicates a history of past failures for a particular pipeline system, failure causes (time-dependent defects due to corrosion, construction, manufacture, or transmission problems, etc.) shall be reviewed in determining risk classification (See Table 6) and the timing of the pressure test should be accelerated. \2\ All pre-1970 ERW pipeline segments may not require testing. In determining which ERW pipeline segments should be included in this category, an operator must consider the seam-related leak history of the pipe and pipe manufacturing information as available, which may include the pipe steel's mechanical properties, including fracture toughness; the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel- making process; and other factors pertinent to seam properties and quality. \3\ For those pipeline operators with extensive mileage of pre-1970 ERW pipe, any waiver requests for timing relief should be supported by an assessment of hazards in accordance with location, product, volume, and probability of failure considerations consistent with Tables 3, 4, 5, and 6. \4\ A magnetic flux leakage or ultrasonic internal inspection survey may be utilized as an alternative to pressure testing where leak history and operating experience do not indicate leaks caused by longitudinal cracks or seam failures. \5\ Pressure tests utilizing a hydrocarbon liquid may be conducted, but only with a liquid which does not vaporize rapidly. Using LOCATION, PRODUCT, VOLUME, and FAILURE HISTORY ``Indicators'' from Tables 3, 4, 5, and 6 respectively, the overall risk classification of a given pipeline or pipeline segment can be established from Table 2. The LOCATION Indicator is the primary factor which determines overall risk, with the PRODUCT, VOLUME, and PROBABILITY OF FAILURE Indicators used to adjust to a higher or lower overall risk classification per the following table.#

Passage 18Table 2.--Risk Classification ---------------------------------------------------------------------------------------------------------------- Probability of failure Risk classification Hazard location indicator Product/volume indicator indicator ---------------------------------------------------------------------------------------------------------------- A................................ L or M L/L L B................................ (2) Not A or C Risk Classification C................................ H Any Any. ---------------------------------------------------------------------------------------------------------------- H=High, M=Moderate, and L=Low. Note: For Location, Product, Volume, and Probability of Failure Indicators, see Tables 3, 4, 5, and 6. Table 3 is used to establish the LOCATION indicator used in Table 2. Based on the population (and environmental in the future) characteristics associated with a pipeline facility's location, a LOCATION Indicator of H, (M) or L is selected. Table 3.--Location Indicators--Pipeline Segments ------------------------------------------------------------------------ Indicator Population \1\ Environment \2\ ------------------------------------------------------------------------ H........................... Non-rural areas .................... M........................... .................... .................... L........................... Rural areas .................... ------------------------------------------------------------------------ \1\ The effects of potential vapor migration should be considered for pipeline segments transporting highly volatile or toxic products. \2\ An environmental factor has not been included at this time, but may be once a definition of ``unusually sensitive areas'' has been established. Tables 4, 5 AND 6 are used to establish the PRODUCT, VOLUME, and PROBABILITY OF FAILURE Indicators respectively, in Table 2. The PRODUCT Indicator is selected from Table 4 as H, M, or L based on the acute and chronic hazards associated with the product transported. The VOLUME Indicator is selected from Table 5 as H, M, or L based on the nominal diameter of the pipeline. The Probability of Failure Indicator is selected from Table 6.#

Passage 19Table 4.--Product Indicators ------------------------------------------------------------------------ Indicator Considerations Product examples ------------------------------------------------------------------------ H........................... (Highly volatile and (Propane, butane, flammable). Natural Gas Liquid (NGL), ammonia). .......................... Highly toxic........ (Benzene, high Hydrogen Sulfide content crude oils). M........................... Flammable--flashpoin (Gasoline, JP4, low t <100F. flashpoint crude oils). L........................... Non-flammable-- (Diesel, fuel oil, flashpoint 100+F. kerosene, JP5, most crude oils). .......................... Highly volatile and Carbon Dioxide. non-flammable/non- toxic. ------------------------------------------------------------------------ Considerations: The degree of acute and chronic toxicity to humans, wildlife, and aquatic life; reactivity; and, volatility, flammability, and water solubility determine the Product Indicator. Comprehensive Environmental Response, Compensation and Liability Act Reportable Quantity values can be used as an indication of chronic toxicity. National Fire Protection Association health factors can be used for rating acute hazards. Table 5.--Volume Indicators ------------------------------------------------------------------------ Indicator Line size ------------------------------------------------------------------------ H........................................ 18'' M........................................ 10''-16'' nominal diameters. L........................................ 8'' nominal diameter. ------------------------------------------------------------------------ H=High, M=Moderate, and L=Low. Table 6 is used to establish the PROBABILITY OF FAILURE Indicator used in Table 2. The ``Probability of Failure'' Indicator is selected from Table 6 as H or L.#

Passage 20Table 6.--Probability of Failure Indicators (in each haz. Location) ------------------------------------------------------------------------ Failure history (time- Indicator dependent defects) \2\ ------------------------------------------------------------------------ H \1\.................................... > Three spills in last 10 years. L........................................ Three spills in last 10 years. ------------------------------------------------------------------------ H=High and L=Low. \1\ Pipeline segments with greater than three product spills in the last 10 years should be reviewed for failure causes as described in subnote(\2\). The pipeline operator should make an appropriate investigation and reach a decision based on sound engineering judgment, and be able to demonstrate the basis of the decision. \2\ Time-Dependent Defects are defects that result in spills due to corrosion, gouges, or problems developed during manufacture, construction or operation, etc. Issued in Washington, D.C. on January 30, 1998. Richard B. Felder, Associate Administrator for Pipeline Safety. [FR Doc. 98-2860 Filed 2-4-98; 8:45 am] BILLING CODE 4910-60-P#