{"operation":"document","citation":"85 FR 65142","title":"Pipeline Safety: Class Location Change Requirements","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"proposed","official":true,"published_on":"2020-10-14","effective_on":null,"summary":"In response to public input received as part of the rulemaking process, PHMSA is proposing to revise the Federal Pipeline Safety Regulations to amend the requirements for gas transmission pipeline segments that experience a change in class location. Under the existing regulations, pipeline segments located in areas where the population density has significantly increased must perform one of the following actions: Reduce the pressure of the pipeline segment, pressure test the pipeline segment to higher standards, or replace the pipeline segment. This proposed rule would add an alternative set of requirements operators could use, based on implementing integrity management principles and pipe eligibility criteria, to manage certain pipeline segments where the class location has changed from a Class 1 location to a Class 3 location. Through required periodic assessments, repair criteria, and other extra preventive and mitigative measures, PHMSA expects this alternative approach would provide long-term safety benefits consistent with the current natural gas pipeline safety rules while also providing cost savings for pipeline operators.","machine_formats":{"json":"https://regulus.evalyn.ai/document/federal-register-2020-19872.json","markdown":"https://regulus.evalyn.ai/document/federal-register-2020-19872.md"},"app_url":"https://regulus.evalyn.ai/document/federal-register-2020-19872","source_url":"https://www.federalregister.gov/documents/2020/10/14/2020-19872/pipeline-safety-class-location-change-requirements","body":"Federal Register, Volume 85 Issue 199 (Wednesday, October 14, 2020) [Federal Register Volume 85, Number 199 (Wednesday, October 14, 2020)] [Proposed Rules] [Pages 65142-65178] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 2020-19872] [[Page 65141]] Vol. 85 Wednesday, No. 199 October 14, 2020 Part II Department of Transportation ----------------------------------------------------------------------- Pipeline and Hazardous Materials Safety Administration ----------------------------------------------------------------------- 49 CFR Parts 191 and 192 Pipeline Safety: Class Location Change Requirements; Proposed Rule Federal Register / Vol. 85 , No. 199 / Wednesday, October 14, 2020 / Proposed Rules [[Page 65142]] ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 191 and 192 [Docket No. PHMSA-2017-0151] RIN 2137-AF29 Pipeline Safety: Class Location Change Requirements AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA); DOT. ACTION: Notice of proposed rulemaking (NPRM). ----------------------------------------------------------------------- SUMMARY: In response to public input received as part of the rulemaking process, PHMSA is proposing to revise the Federal Pipeline Safety Regulations to amend the requirements for gas transmission pipeline segments that experience a change in class location. Under the existing regulations, pipeline segments located in areas where the population density has significantly increased must perform one of the following actions: Reduce the pressure of the pipeline segment, pressure test the pipeline segment to higher standards, or replace the pipeline segment. This proposed rule would add an alternative set of requirements operators could use, based on implementing integrity management principles and pipe eligibility criteria, to manage certain pipeline segments where the class location has changed from a Class 1 location to a Class 3 location. Through required periodic assessments, repair criteria, and other extra preventive and mitigative measures, PHMSA expects this alternative approach would provide long-term safety benefits consistent with the current natural gas pipeline safety rules while also providing cost savings for pipeline operators. DATES: Persons interested in submitting written comments on this proposed rule must do so by December 14, 2020. Late-filed comments will be considered to the extent practicable. ADDRESSES: You may submit comments identified by the docket number PHMSA-2017-0151 by any of the following methods: Federal eRulemaking Portal: https://www.regulations.gov . This site allows the public to enter comments on any Federal Register notice issued by any agency. Follow the online instructions for submitting comments. Mail: Hand Delivery: U.S. DOT Docket Management System, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC 20590-0001 between 9:00 a.m. and 5:00 p.m., Monday through Friday, except Federal holidays. Fax: 1-202-493-2251. Instructions: Identify the docket number PHMSA-2017-0151 at the beginning of your comments. If you submit your comments by mail, submit two copies. If you wish to receive confirmation that PHMSA has received your comments, include a self-addressed stamped postcard. Internet users may submit comments at https://www.regulations.gov/ . Note: Comments are posted without changes or edits to https://www.regulations.gov , including any personal information provided. There is a privacy statement published on https://www.regulations.gov . Confidential Business Information Confidential Business Information (CBI) is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this notice contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this notice, it is important that you clearly designate the submitted comments as CBI. Pursuant to 49 CFR 190.343, you may ask PHMSA to give confidential treatment to information you give to the agency by taking the following steps: (1) Mark each page of the original document submission containing CBI as ``Confidential''; (2) send PHMSA, along with the original document, a second copy of the original document with the CBI deleted; and (3) explain why the information you are submitting is CBI. Unless you are notified otherwise, PHMSA will treat such marked submissions as confidential under the FOIA, and they will not be placed in the public docket of this notice. Submissions containing CBI should be sent to Robert Jagger, Office of Pipeline Safety (PHP-30), Pipeline and Hazardous Materials Safety Administration (PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, or by email at [email protected] . Any commentary PHMSA receives that is not specifically designated as CBI will be placed in the public docket. FOR FURTHER INFORMATION CONTACT: Robert Jagger, Senior Transportation Specialist, by telephone at 202-366-4361. For technical questions: Steve Nanney, Project Manager, by telephone at 713-272-2855. SUPPLEMENTARY INFORMATION: I. Executive Summary A. Purpose of Regulatory Action B. Summary of the Major Regulatory Provisions C. Costs and Benefits II. Background A. Class Location History and Purpose B. Changes in Class Location Due to Population Growth C. Class Location Change Special Permits D. Class Location Studies, Public Workshop, Report, and Stakeholder Input E. Class Location ANPRM F. 2019 Gas Transmission Final Rule III. Analysis of ANPRM Comments and PHMSA's Response A. Comments Related to the 2016 Proposed Gas Transmission Rule B. Requiring Pipe Integrity Upgrades and Allowing Other Options for Class Location Changes C. Integrity Upgrades and Integrity Management Options for Clustered Areas D. Using an Integrity Management Option To Manage Safety When Class Locations Change From a Class 1 to a Class 3 E. General Eligibility for Managing Class Location Changes With Integrity Management F. Eligibility for Pipe Operated in Accordance With Sec. 192.619(c) G. Eligibility for Pipe With Specific Conditions and Attributes H. Eligibility for Pipe With Significant Corrosion I. Eligibility for Damaged Pipe, Dented Pipe, or Pipe That Has Lost Ground Cover J. Eligibility Factors Based on Diameter, Operating Pressure, or Potential Impact Radius Size K. Codifying Current Special Permit Conditions L. Additional Preventive and Mitigative Measures Needed for an Integrity Management Option for Class Location Change Management M. Traceable, Verifiable, and Complete Records for Supporting Class Location Change Integrity Management Measures N. Data on Class Location Pipe Replacement and Route Planning O. Other Topics--General Comments IV. Section-by-Section Analysis V. Regulatory Analyses and Notices I. Executive Summary A. Purpose of Regulatory Action Class locations are used in the natural gas Federal Pipeline Safety Regulations (PSR) in a graded approach to provide conservative safety margins \\1\\ and safety standards commensurate with the potential consequences of pipeline [[Page 65143]] incidents, and are based on the population density near a pipeline.\\2\\ As class locations are defined with relation to the number of dwellings for human occupancy in the area, an onshore gas transmission pipeline's class location can change as the population living or working near a pipeline changes. An increase in population that results in a change in class location requires operators to confirm design factors and to recalculate the maximum allowable operating pressure (MAOP) of the pipeline.\\3\\ If a class location changes and the hoop stress \\4\\ corresponding to the established MAOP of a segment of pipeline is not commensurate with the MAOP of the newly determined class location, Sec. 192.611 currently requires that the pipeline operator (1) lower the pipeline's MAOP to reduce stress levels in the pipe, (2) replace the existing pipe with pipe that has thicker walls or higher yield strength to yield a lower operating stress at the same MAOP, or (3) pressure test the pipeline at a higher test pressure. --------------------------------------------------------------------------- \\1\\ Pipelines are designed with a safety margin between the design operating pressure and the pressure at which failure would occur. Safety margins are necessary because pipelines can be subject to emergency situations, unexpected loads, operator error, and material degradation. \\2\\ Class locations are defined at Sec. 192.5. A ``class location unit'' is defined at Sec. 192.5 as an onshore area that extends 220 yards on either side of the centerline of any continuous 1-mile length of pipeline. This distance is more colloquially known as the ``sliding mile'' and is explained in more detail later in this document. A Class 1 location is an offshore area or any class location unit with 10 or fewer buildings intended for human occupancy within the class location unit. A Class 2 location is any class location unit with more than 10 but fewer than 46 buildings intended for human occupancy within the class location unit. A Class 3 location is any class location unit with 46 or more buildings intended for human occupancy or an area where the pipeline lies within 100 yards of either a building or a small, well-defined outside area that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period within the class location unit, and a Class 4 location is any class location unit where buildings with 4 or more stories above ground are prevalent. \\3\\ Maximum allowable operating pressure is the maximum internal pressure at which a natural gas pipeline or pipeline segment may be operated. \\4\\ Hoop stress is stress that acts around the circumference of a pipe (i.e., perpendicular to the pipe length) and is caused by the internal pressure pushing outward against the pipe wall. As pressure within the pipe increases, the stress in the pipe wall must be capable of acting against that pressure to contain it. --------------------------------------------------------------------------- Some operators have applied for special permits to manage class location changes that would normally require replacing pipe, reducing the operating pressure, or pressure testing the pipe. Under the special permit process, PHMSA waives or otherwise modifies compliance with regulatory requirements if the operator requesting the special permit demonstrates a need and PHMSA determines that granting the special permit would be consistent with pipeline safety.\\5\\ PHMSA performs extensive technical analysis on special permit applications and has granted special permits on the condition that operators will perform alternative measures to retain a consistent level of pipeline safety for the new class location throughout the life cycle of the pipeline. In 2004, PHMSA published guidance in the Federal Register that addressed the common conditions for granting class location change special permit requests. This guidance clarified PHMSA's process for granting a class location waiver that would allow operators to perform alternative risk-control activities based on integrity management (IM) concepts, rather than pipe replacement, pressure testing, or pressure reductions.\\6\\ --------------------------------------------------------------------------- \\5\\ The special permit process is outlined in Sec. 190.341 and is no different for waiving the class location regulations than for waiving any other requirements in the PSR. \\6\\ Public notices were published in Federal Register: ``Pipeline Safety: Development of Class Location Change Waiver Guidelines,'' 69 FR 22115 (Apr. 23, 2004); and ``Pipeline Safety: Development of Class Location Change Waiver Criteria,'' 69 FR 38948 (June 29, 2004). Additional guidance is provided online at: http://primis.phmsa.dot.gov/classloc/index.htm . --------------------------------------------------------------------------- On January 3, 2012, Congress adopted the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act).\\7\\ Section 5 of that act required that PHMSA evaluate whether applying IM principles to areas outside of high consequence areas (HCA), with respect to gas transmission pipeline facilities, could possibly mitigate or eliminate the need for class location requirements.\\8\\ As stated in the resulting class location report titled ``Evaluation of Expanding Pipeline Integrity Management Beyond High-Consequence Areas and Whether Such Expansion Would Mitigate the Need for Gas Pipeline Class Location Requirements'' that was issued in 2016 (2016 Class Location Report), the application of IM requirements to gas transmission pipelines outside of HCAs would not warrant the total elimination of class locations.\\9\\ However, PHMSA stated that it intended to consider whether adjustments were needed in the way that operators were required to implement certain requirements when class locations did change. --------------------------------------------------------------------------- \\7\\ Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011; signed January 3, 2012; Public Law 112-90. \\8\\ Id. at sec. 5(a). \\9\\ See https://www.regulations.gov/document?D=PHMSA-2011-0023-0153 . --------------------------------------------------------------------------- On July 31, 2018, PHMSA published an advance notice of proposed rulemaking (ANPRM) in the Federal Register to seek feedback regarding the revision of the PSR applicable to the management of gas transmission pipeline segments where the class location has changed.\\10\\ Specifically, PHMSA requested comments regarding whether operators should have the option of performing certain risk-based IM activities in lieu of the current required activities (i.e., pipe replacement, pressure test, or pressure reduction) and whether those modifications could mitigate the public safety need for the existing class location requirements in this context. This ANPRM was initiated to honor the commitment made at the conclusion of the 2016 Class Location Report that PHMSA would study alternatives to the regulatory requirement for pipe replacement when class locations change and was also responsive to comments made to a 2017 DOT notice regarding regulatory review actions.\\11\\ --------------------------------------------------------------------------- \\10\\ ``Pipeline Safety: Class Location Change Requirements,'' 83 FR 36861 (July 31, 2018). \\11\\ ``Notification of Regulatory Review,'' 82 FR 45750 (Oct. 2, 2017). --------------------------------------------------------------------------- Based on input in previous public meetings and workshops,\\12\\ the comments received on the ANPRM, the 2016 Class Location report, and a review of PHMSA's active special permits for Class 1 to Class 3 location changes,\\13\\ PHMSA proposes to amend the class location change regulations for certain in-service gas transmission segments where the class location has changed from a Class 1 to a Class 3 to add an IM- based alternative to the existing requirements. PHMSA is requesting input from the public on all aspects of this proposal, including whether the modification or elimination of the proposed pipe eligibility attributes or additional preventative and mitigative measures would provide an equivalent level of safety and maximize net benefits to society. --------------------------------------------------------------------------- \\12\\ See Section II, D of this document titled, ``Class Location Studies, Public Workshop, Report, and Stakeholder Input.'' \\13\\ As of May 1, 2019, PHMSA's 12 special permits for Class 1 to Class 3 location changes apply to segments of pipe in the States of Alabama, Arizona, Colorado, Georgia, Kentucky, Louisiana, Michigan, Mississippi, New Jersey, New Mexico, New York, Ohio, Pennsylvania, Tennessee, Texas, West Virginia, and Wyoming. --------------------------------------------------------------------------- B. Summary of the Major Regulatory Provisions PHMSA is proposing an IM-based alternative to the existing class- location-change requirements. The NPRM addresses two main topics pertaining to the IM alternative: (1) The criteria that pipe must meet to be eligible for the alternative, and (2) the additional, IM-based safety requirements necessary for using the alternative. Both aspects serve to protect public safety when pipeline operators apply the alternative approach. [[Page 65144]] The NPRM addresses segments that change from a Class 1 to a Class 3 location after the publication of a final rule based on this proposed rulemaking and operate at 72 percent of specified minimum yield strength (SMYS) \\14\\ or less. PHMSA proposes that for segments that are eligible based on pipe attributes, operators choosing the IM alternative would adhere to documentation requirements, operations and maintenance (O&M) requirements, and other additional safety measures proposed in this rulemaking. Operators who do not meet the requirements of the proposed rule would need to follow the current regulatory requirements for class location changes or apply for a special permit. --------------------------------------------------------------------------- \\14\\ SMYS is an indication of the minimum stress that a pipe may experience that will cause plastic, or permanent, deformation of the steel pipe. --------------------------------------------------------------------------- Specifically, pipeline segments meeting the following conditions or having the following attributes would be ineligible for the IM alternative for managing class location changes: Bare pipe; Wrinkle bends; Missing material properties records; Certain historically problematic seam types; \\15\\ --------------------------------------------------------------------------- \\15\\ Problematic seam types include direct current (DC), low- frequency electric resistance welded pipe (LF-ERW), electric flash- welded (EFW) pipe, lap-welded pipe, and pipe seams with a longitudinal joint factor below 1.0 as defined in Sec. 192.113. --------------------------------------------------------------------------- Body, seam, or girth-weld cracking; \\16\\ --------------------------------------------------------------------------- \\16\\ This cracking can include stress corrosion cracking and selective seam weld corrosion, which are cracking defects in the pipe body or weld seam. Cracks are undesired openings or separations in a normally rigid material, such as a pipe wall, and are detrimental to the capability of a pipeline to restrain pressure. Often, cracks are found only on the surface and do not penetrate the pipe wall. However, cracks that don't fully penetrate the pipe wall, if left unchecked, can propagate into a failure or a rupture and must be promptly repaired. --------------------------------------------------------------------------- Pipe with poor external coating or with tape wraps or shrink sleeves; A leak or failure history within 5 miles of the segment; \\17\\ --------------------------------------------------------------------------- \\17\\ These would be leaks or failures reported to PHMSA via an incident report per part 191. --------------------------------------------------------------------------- Pipe transporting gas that is not of suitable composition and quality for sale to gas distribution customers; and Pipe operated in accordance with Sec. 192.619 (c) or (d). PHMSA also proposes that a pipeline segment would be ineligible if it did not have a documented successful \\18\\ 8-hour, part 192, subpart J, pressure test to a minimum of 1.25 times MAOP. Pipeline segments that were previously ``uprated'' \\19\\ without a documented pressure test would also not be eligible unless the operator conducts a new pressure test. --------------------------------------------------------------------------- \\18\\ A ``successful'' pressure test is one where the pipe does not rupture or leak because of the test. Part 192, subpart J, prescribes the minimum leak-test and strength-test requirements for pipelines. \\19\\ An ``uprate'' is where an operator increases the MAOP of its pipeline. To increase the pressure on its pipeline, an operator must comply with the minimum requirements prescribed in subpart K of part 192. An operator would still be subject to the leak-test and strength test requirements, including recordkeeping requirements, under part 192, subpart J. --------------------------------------------------------------------------- These applicability criteria would help protect public safety by assuring that pipeline segments with known elevated risks that are changing from a Class 1 to a Class 3 location are pressure-tested, de- rated to a lower MAOP, or replaced with new and stronger pipe, as required by the current regulations in Sec. 192.611. In most cases, this eligibility criteria prevents pipe that would be more susceptible to corrosion or cracking from using this NPRM alternative, and it also helps to ensure that operators can use the proper assessment and mitigation methods on pipeline segments that could cause great harm to the public based on their risk. PHMSA is concerned that, with the additional risk for corrosion and cracking many of these segments would have, anomalies might be able to grow to a failure size before the next assessment. Therefore, PHMSA has proposed these eligibility criteria as a matter of ensuring that pipe integrity can be maintained in Class 3 locations where pipe designed to Class 1 standards remains in service. PHMSA discusses this in more detail later in this document and seeks comment on whether there is an alternative approach that would maximize net benefits to society while maintaining safety. Pipeline segments changing to a Class 4 location would not be eligible for the IM alternative under this proposal, but would rather be accommodated through PHMSA's current class location special permit process.\\20\\ --------------------------------------------------------------------------- \\20\\ PHMSA has neither included Class 4 locations in this proposed rule nor would it include such locations in any other NPRM without having first developed a unique set of conditions to maintain safety for multi-story buildings and applying them through the issuance of several special permits. --------------------------------------------------------------------------- If a pipeline segment meets all eligibility criteria and the operator opts to follow the IM alternative, PHMSA proposes to require that the operator notify PHMSA of details of each segment that experienced a Class 1 to Class 3 location change 60 days prior to implementing the IM alternative. PHMSA is also proposing to modify the definition of an HCA to include these Class 1 to Class 3 location segments, which would then make these specific segments subject to all the requirements in subpart O, in addition to the more stringent requirements discussed in more detail below. When subpart O was developed and promulgated in 2003,\\21\\ PHMSA did not anticipate that operators would be able to demonstrate adequate pipeline integrity for pipe that was not designed for the class location in which it was located. Therefore, the regulations address any potential risk that would be involved when a class location changes by requiring that the pipeline operate at a lower pressure if an operator does not replace the pipeline segment or pressure test the segment. The proposal would allow operators to choose to follow IM requirements in subpart O and additional requirements for applicable segments, which include required in-line inspections (ILI), external pipeline coating, cathodic protection (CP),\\22\\ pipeline repair criteria to maintain MAOP with a Class 1 location 39 percent safety factor, usage of remote-controlled or automatic shutoff valves, and other additional preventive and mitigative (P&M) measures. PHMSA expects these measures to provide for an equivalent level of safety for the life of the pipeline when compared to pipe replacement. --------------------------------------------------------------------------- \\21\\ ``Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),'' 68 FR 69778 (Dec. 15, 2003). \\22\\ CP is a technique used to control or limit the corrosion of a pipeline's external metal surface by making it the cathode of an electrochemical cell. This treatment can be achieved with a special coating on the external surface of the pipeline along with an electrical system and anodes buried in the ground, or with a ``sacrificial'' or galvanic metal acting as an anode. In those types of systems, the anode will corrode before the protected metal will. --------------------------------------------------------------------------- More specifically, PHMSA is proposing that operators perform an initial integrity assessment using ILI tools within 24 months of the class location change, which would align with the current timeframe to either confirm or change the MAOP after a class location change. PHMSA would require operators to perform this ILI assessment on the entire pipeline segment that has experienced the change in class location, including from the nearest upstream ILI tool launcher to the nearest downstream ILI tool receiver. With respect to additional P&M measures beyond what are included in subpart O, PHMSA is proposing to require operators to do the following: Perform additional coating, interference, and corrosion surveys; remediate defined anomalies; install line-of-sight markers; install remote-control or automatic shutoff mainline valves; perform depth of cover surveys and [[Page 65145]] remediation; clear shorted casings; perform additional right-of-way patrols and leakage surveys; and use a supervisory control and data acquisition (SCADA) system. These additional requirements would address aspects of pipeline integrity and public safety for which ILI assessments alone do not address, such as reducing the likelihood of third-party damage, detecting and mitigating conditions that can accelerate corrosion growth, and terminating gas flow from ruptures faster than would be required under existing regulations. Operators would also be required to keep documentation for all assessments, surveys, and any other required actions they perform in meeting the proposed requirements. PHMSA intends for this class location management option, when performed in conjunction with the requirements of subpart O, to provide a consistent-or-higher level of safety for the life of the pipeline if the operator chooses not to replace the pipe. C. Costs and Benefits Consistent with Executive Order 12866, PHMSA has prepared an assessment of the benefits and costs of this proposed rule, as well as reasonable alternatives. The estimated cost savings of this proposal are due to avoided pipe replacement of segments for which operators employ the proposed IM alternative. In the Preliminary Regulatory Impact Analysis (PRIA) posted on the public docket, PHMSA presented two estimates of the number of miles that may change from a Class 1 to a Class 3 location each year from 2019 to 2039 and analyzed them as two separate scenarios. Scenario 1 is based on an estimate of 78 miles per year, which is the average result from PHMSA's annual estimates based on historical annual report data from 2010 to 2017. Scenario 2 is based on the median of PHMSA's annual estimates, which is 118 miles. PHMSA estimated the cost savings of the proposed rule by estimating the rate and unit cost for the currently available class location change compliance methods, the unit costs of complying with the special permit program, and the mix of consequence classifications among the affected segments. PHMSA assumes that this proposed rule would cause operators to replace pipe less often when a class location changes from Class 1 to Class 3, as they would choose to use the IM alternative of this method where feasible. PHMSA estimated the costs of the IM alternative compared to the costs of pipe replacement against the estimated mileage changing from a Class 1 location to a Class 3 location per year. As such, PHMSA estimates the annual cost savings of the rule to be approximately $55 million for scenario 1, and $86 million for scenario 2, both calculated at a 7 percent discount rate. II. Background A. Class Location History and Purpose The concept of class locations pre-dates the Federal regulation of gas transmission pipelines and was an early method of differentiating areas along natural gas transmission pipelines based on the potential consequence of a hypothetical pipeline accident. The first class location definitions were incorporated into the PSR on August 19, 1970, and were derived from the American Society of Mechanical Engineers (ASME) B31.8 designations that were included in the American Standards Association B31.8-1968 version of the ``Gas Transmission and Distribution Pipeline Systems'' standard, which eventually became ASME B31.8, ``Gas Transmission and Distribution Pipeline Systems.'' The definitions for class locations that PHMSA codified maintained the original ASME B31.8 characterizations for Class 1 through Class 3 locations and added a new Class 4 location definition. These original class location definitions, with some slight modifications, are still applied today. PHMSA uses class locations to provide safety margins and standards that are commensurate with the potential consequence of a pipeline failure based on the surrounding population. A pipeline's class location is based on the number of buildings or dwellings for human occupancy in the surrounding area. Pipeline class locations for onshore gas pipelines are determined using the concept of a ``sliding mile,'' which is a unit of measurement that is 1 mile in length, extending 220 yards on either side of the centerline of a pipeline, and moves along the pipeline. The number of buildings within this sliding mile at any point during the mile's movement determines the class location for the entire mile of pipeline that the sliding mile moves along.\\23\\ --------------------------------------------------------------------------- \\23\\ For the purposes of this rulemaking, a ``building'' may be interchangeably referred to as a ``home,'' a ``house,'' or a ``dwelling,'' all of which refer to a structure intended for human occupancy, whether it is used as a residence, for business, or for another purpose. --------------------------------------------------------------------------- A Class 1 location is a class location unit along a continuous mile containing 10 or fewer buildings intended for human occupancy or is an offshore area; a Class 2 location is a class location unit along a continuous mile containing 11 to 45 buildings intended for human occupancy; and a Class 3 location is a class location unit along a continuous mile containing 46 or more buildings intended for human occupancy, or is within 100 yards of a building or place of public assembly.\\24\\ Class 4 locations exist where buildings with four or more stories above ground are prevalent. Whenever a pipeline segment has multiple class locations, the higher-numbered class location applies to the entire segment. --------------------------------------------------------------------------- \\24\\ Under Sec. 192.5, a location is Class 3 if it has a building or a small, well-defined outside area (including playgrounds, recreation areas, and outdoor theaters) that is occupied by 20 or more persons at least 5 days a week for 10 weeks in any 12-month period. The days and weeks need not be consecutive. --------------------------------------------------------------------------- Potential consequences of personal injury and property damage resulting from incidents such as a leak- or rupture-type failure, increase in a more densely populated area. In addition, an increasing population around a pipeline amplifies the probability of an incident occurring due to additional external force stresses, corrosion, interference currents, loss of pipeline soil cover, damage from third parties, and other factors. Design factors \\25\\ are used along with pipe attributes in engineering calculations to determine the required design pressure and MAOP of each steel pipeline segment. To decrease operational hoop stresses \\26\\ in areas of higher consequence, these class location- based design factors (i.e., MAOP derating factors) \\27\\ provide a safety margin and help ensure the pipeline is operated below 100 percent of SMYS. As specified in Sec. 192.105, a pipeline's design pressure is determined using Barlow's Formula: P = (2St/D) x F x E x T, where P is the design pressure, S is the pipe's yield strength, t is the wall thickness of the pipe, D is the outside diameter of the pipe, F is the design factor specific to the class location, E is the longitudinal joint factor,\\28\\ and T is the temperature [[Page 65146]] derating factor.\\29\\ To illustrate how class location design factors influence the MAOP of a pipeline, consider a 1000 psig pipeline (1.0 design factor) with the same operating parameters (diameter, wall thickness, yield strength, seam type, and temperature) but in different class locations. The pipeline MAOPs would be as follows: --------------------------------------------------------------------------- \\25\\ Design factors, which are used to calculate the design pressure for steel pipe in Sec. 192.105(a), are listed in Sec. 192.111. Class 1 locations have a 0.72 design factor, Class 2 locations have a 0.60 factor, Class 3 locations have a 0.50 factor, and Class 4 locations have a 0.40 design factor. \\26\\ ``Hoop stress'' is the stress in a pipe wall, acting circumferentially in a plane perpendicular to the longitudinal axis of the pipe, that is produced by the pressure of the product in the pipe. Hoop stress is calculated using Barlow's Formula, which is at Sec. 192.105. Hoop stresses are the same as design pressure, unless an outside force is acting on it. If hoop stress has the same safety factor as MAOP, then they are equal. \\27\\ MAOP determination and the required design factors for the class location can be found in Sec. Sec. 192.105, 192.111, and 192.619. \\28\\ The longitudinal joint factor, based on the weld seam type of a pipeline, per this formula, has a limiting effect on the MAOP of the pipeline. While it is typically ``1.00'' and would not affect the calculation, certain types of furnace butt-welded pipe or pipe not manufactured to certain 49 CFR part 192-approved industry standards will have factors of 0.60 or 0.80, which will necessitate a reduction in design pressure. The longitudinal joint factors for steel pipe are listed at Sec. 192.113. \\29\\ The temperature derating factor ranges from 1.000 to 0.867 depending on the operating temperature of the pipeline. Pipelines designed to operate at 250 degrees Fahrenheit and lower have a factor of 1.000, which does not affect the design pressure calculation. Pipelines designed to operate at higher temperatures, including up to 450 degrees Fahrenheit, have derating factors less than one, which lowers the design pressure of the pipeline. Steel pipe temperature derating factors are listed at Sec. 192.115. Class 1--design factor = 0.72, MAOP = 720 psig Class 2--design factor = 0.60, MAOP = 600 psig Class 3--design factor = 0.50, MAOP = 500 psig Class 4--design factor = 0.40, MAOP = 400 psig As natural gas transmission pipeline standards and regulations have evolved, the class location concept was incorporated into many other regulatory areas, including test pressures, mainline block valve spacing, pipeline design and construction requirements, and on-going O&M requirements. In all, the class location concept is incorporated throughout part 192.\\30\\ --------------------------------------------------------------------------- \\30\\ Specifically, Sec. Sec. 192.5, 192.8, 192.9, 192.65, 192.105, 192.111, 192.150, 192.175, 192.179, 192.243, 192.327, 192.485, 192.503, 192.505, 192.609, 192.611, 192.613, 192.619, 192.620, 192.625, 192.705, 192.706, 192.707, 192.713, 192.903, 192.933, and 192.935. --------------------------------------------------------------------------- Modern pipeline inspection technology includes ILI and above-ground coating surveys. ILI technology uses devices that flow with the product in the pipeline and are colloquially known as ``smart pigs,'' which can measure and record irregularities in the pipe body and welds, including pipe wall loss (such as corrosion metal loss, gouges, scrapes, etc.), cracking, deformations, and dents. There are various types of ILI tools using different technologies that have distinct capabilities for detecting specific types of pipeline anomalies. However, in selecting the most suitable ILI tool, a pipeline operator must know the type of threats that are applicable to the pipeline segment. For example, a high-resolution magnetic flux leakage (HR-MFL) ILI tool can detect internal and external corrosion metal loss reliably but cannot accurately determine whether the pipeline has dents, deformations, or tight crack indications such as stress corrosion cracking \\31\\ or seam-weld cracks. A high-resolution deformation tool would be most appropriate for dents, whereas an electro-magnetic acoustic transducer (EMAT) tool would be the most appropriate for cracking. --------------------------------------------------------------------------- \\31\\ A ``tight crack'' is a crack that is below 0.008 inches in width. Stress corrosion cracking is a form of corrosion that produces a marked loss of pipeline strength with little metal loss. The combined influence of pipeline stress and a corrosive medium can result in the formation of interlinking crack clusters that can grow until the pipe fails. --------------------------------------------------------------------------- PHMSA first issued its IM regulations for gas transmission pipelines on December 15, 2003,\\32\\ in response to tragic gas pipeline incidents near Carlsbad, NM, in 2000,\\33\\ where 12 people were killed; and in Edison, NJ, in 1994, where 8 buildings were destroyed and approximately 1,500 residents were evacuated.\\34\\ The IM regulations provided a definition for HCA and required operators to assess the condition of pipelines periodically in these areas and make any necessary repairs within defined timeframes. --------------------------------------------------------------------------- \\32\\ 68 FR at 69778. \\33\\ NTSB, Pipeline Accident Report: Natural Gas Pipeline Rupture and Fire Near Carlsbad, New Mexico August 19, 2000, PAR-03- 01, adopted on February 11, 2003. \\34\\ NTSB, Pipeline Accident Report: Texas Eastern Transmission Corporation Natural Gas Pipeline Explosion and Fire, Edison, New Jersey; March 23, 1994; PAR-95-01, adopted on January 18, 1995. --------------------------------------------------------------------------- Prior to the recent publication of the ``Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments'' final rule on October 1, 2019 (2019 Gas Transmission Final Rule),\\35\\ operators were not required to assess or perform IM functions on pipeline segments outside of HCAs. With the publication of that rule, operators of onshore steel transmission pipeline segments with an MAOP of greater than or equal to 30 percent of SMYS and that are located in a Class 3 locations, a Class 4 locations, or a ``moderate consequence area'' as defined in Sec. 192.3 where the segment can accommod","truncated":true,"body_characters":284388}