Department of Transportation
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines; Final Rule
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
[Docket No. PHMSA-2005-23447]
Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT).
ACTION: Final rule.
SUMMARY: PHMSA is amending the pipeline safety regulations to prescribe safety requirements for the operation of certain gas transmission pipelines at pressures based on higher operating stress levels. The result is an increase of maximum allowable operating pressure (MAOP) over that currently allowed in the regulations. Improvements in pipeline technology assessment methodology, maintenance practices, and management processes over the past twenty-five years have significantly reduced the risk of failure in pipelines and necessitate updating the standards that govern the MAOP. This rule will generate significant public benefits by reducing the number and consequences of potential incidents and boosting the potential capacity and efficiency of pipeline infrastructure, while promoting rigorous life-cycle maintenance and investment in improved pipe technology.
DATES: Effective Date: This final rule takes effect November 17, 2008.
Incorporation by Reference Date: The incorporation by reference of a certain publication listed in this rule is approved by the Director of the Federal Register as of November 17, 2008.
FOR FURTHER INFORMATION CONTACT: Alan Mayberry by phone at (202) 366-5124, or by e-mail at firstname.lastname@example.org.
Table of Contents
A. Purpose of the Rulemaking
B.1. Current Regulations
B.2. Evolution in Views on Pressure
B.3. History of PHMSA Consideration
B.4. Safety Conditions in Special Permits
B.5. Codifying the Special Permit Standards
B.6. How to Handle Special Permits and Requests for Special Permits
B.7. Statutory Considerations
C. Comments on the NPRM
C.1. General Comments
C.2. Comments on Specific Provisions in the Proposed Rule
C.2.1. Section 192.7, Incorporation by Reference
C.2.2. Design Requirements
C.2.3. Construction Requirements
C.2.4. Eligibility for and Implementing Alternative MAOP
C.2.5. Operation and Maintenance Requirements
C.3. Comments on Regulatory Analysis
D. Consideration by the Technical Pipeline Safety Standards Committee
E. The Final Rule
E.1. In General
E.2. Amendment to §192.7–Incorporation by Reference
E.3. New §192.112–Additional Design Requirements
E.4. New §192.328–Additional Construction Requirements
E.5. Amendment to §192.611–Change in Class Location: Confirmation or Revision of Maximum Operating Pressure
E.6. Amendment to §192.619–Maximum Allowable Operating Pressure
E.7. New §192.620–Operation at an Alternative MAOP
E.7.1. §192.620(a)–Calculating the Alternative MAOP
E.7.2. §192.620(b)–Which Pipelines Qualify
E.7.3. Sec. §192.620(c)(1), (2), and (3)–How an Operator Selects Operation Under This Section
E.7.4. §192.620(c)(4)–Initial Strength Testing
E.7.5. §192.620(c)(5)–Operation and Maintenance
E.7.6. §192.620(c)(6)–New Construction and Maintenance Tasks
E.7.8. §192.620(c)(8)–Class Upgrades
E.8. §192.620(d)–Additional Operation and Maintenance Requirements
E.8.1. §192.620(d)(1)–Threat Assessments
E.8.2. §192.620(d)(1)–Public Awareness
E.8.3. §192.620(d)(2)–Emergency Response
E.8.4. §192.620(d)(3)–Damage Prevention
E.8.5. §192.620(d)(4)–Internal Corrosion Control
E.8.6. Sec. §192.620(d)(5), (6), and (7)–External Corrosion Control
E.8.7. Sec. §192.620(d)(8) and (9)–Integrity Assessments
E.8.8. §192.620(d)(10)–Repair Criteria
E.9. §192.620(e)–Overpressure Protection–Proposed §192.620(e)
F. Regulatory Analyses and Notices
F.1. Privacy Act Statement
F.2. Executive Order 12866 and DOT Policies and Procedures
F.3. Regulatory Flexibility Act
F.4. Executive Order 13175
F.5. Paperwork Reduction Act
F.6. Unfunded Mandates Reform Act of 1995
F.7. National Environmental Policy Act
F.8. Executive Order 13132
F.9. Executive Order 13211
A. Purpose of the Rulemaking
PHMSA published a Notice of Proposed Rulemaking (NPRM) on March 12, 2008 (73 FR 13167), to establish standards under which certain natural or other gas (gas) transmission pipelines would be allowed to operate at higher maximum allowable operating pressure (MAOP). The proposed changes were made possible by dramatic improvements in pipeline technology and risk controls over the past 25 years. The current standards for calculating MAOP on gas transmission pipelines were adopted in 1970, in the original pipeline safety regulations promulgated under Federal law. Almost all risk controls on gas transmission pipelines have been strengthened in the intervening years, beginning with the introduction of improved manufacturing, metallurgy, testing, and assessment tools and standards. Pipe manufactured and tested to modern standards is far less likely to contain defects that can grow to failure over time than pipe manufactured and installed a generation ago. Likewise, modern maintenance practices, if consistently followed, significantly reduce the risk that corrosion, or other defects affecting pipeline integrity, will develop in installed pipelines. Most recently, operators' development and implementation of integrity management programs have increased understanding about the condition of pipelines and how to reduce pipeline risks. In view of these developments, PHMSA concludes that certain gas transmission pipelines can be safely and reliably operated at pressures above current Federal pipeline safety design limits. With appropriate conditions and controls, permitting operation at higher pressures will increase energy capacity and efficiency without diminishing system safety.
Currently, PHMSA has granted special permits on a case-by-case basis to allow operation of particular pipeline segments at a higher MAOP than currently allowed under the existing design requirements. These special permits, that have been granted, have been limited to operation in Class 1, 2, and 3 locations and conditioned on demonstrated rigor in the pipeline's design and construction and the operator's performance of additional safety measures. Building on the record of success developed in the special permit proceedings, PHMSA is codifying the conditions and limitations of the special permits into standards of general applicability.
B.1. Current Regulations
The design factor specified in §192.105 restricts the MAOP of a steel gas transmission pipeline based on stress levels and class location. For most steel pipelines, the MAOP is defined in §192.619 based on design pressure calculated using a formula, found at §192.111, which includes the design factor. The regulations establish four classifications based on population density, ranging from Class 1 (undeveloped, rural land) through Class 4 (densely populated urban areas). In sparsely populated Class 1 locations, the design factor specified in §192.105 restricts the stress level at which a pipeline can be operated to 72 percent of the specified minimum yield strength (SMYS) of the steel. The operating pressures in more populated Class 2 and Class 3 locations are limited to 60 and 50 percent of SMYS, respectively. Paragraph (c) of §192.619 provides an exception to this calculation of MAOP for pipelines built before the issuance of the Federal pipeline safety standards. A pipeline that is ``grandfathered'' under this section may be operated at a stress level exceeding 72 percent of SMYS if it was operated at that pressure for five years prior to July 1, 1970.
Part 192 also prescribes safety standards for designing, constructing, operating, and maintaining steel pipelines used to transport gas. Although these standards have always included several requirements for initial and periodic testing and inspection, prior to 2003, part 192 contained no Federal requirements for internal inspection of existing pipelines. Internal inspection is performed using a tool known as an ``instrumented pig'' (or ``smart pig''). Many pipelines constructed before the advent of this technology cannot accommodate an instrumented pig and, accordingly, cannot be inspected internally. Beginning in 1994, PHMSA required operators to design new pipelines so that they could accommodate instrumented pigs, paving the way for internal inspection (59 FR 17281; Apr. 12, 1994).
In December 2003, PHMSA adopted its gas transmission integrity management rule, requiring operators to develop and implement plans to extend additional protections, including internal inspection, to pipelines located in ``high consequence areas'' (HCAs) (68 FR 69816). Integrity management programs, as required by subpart O of part 192, include threat assessments, both baseline and periodic internal inspection, pressure testing, or direct assessment (DA), and additional measures designed to prevent and mitigate pipeline failures and their consequences. AN HCA, as defined in §192.903, is a geographic territory in which, by virtue of its population density and proximity to a pipeline, a pipeline failure would pose a higher risk to people. In addition to class location, one of the criteria for identifying an HCA is a potential impact circle surrounding a pipeline. The calculation of the circle includes a factor for the MAOP, with the result that a higher MAOP results in a larger impact circle.
B.2. Evolution in Views on Pressure
Absent any defects, and with proper maintenance and management practices, steel pipe can last for many decades in gas service. However, the manufacture of the steel or rolling of the pipe can introduce flaws. In addition, during construction, improper backfilling can damage the pipe and pipe coating. Over time, damaged coating unchecked can allow corrosion to continue and cause leaks. Excavation-related damage can produce an immediate pipeline failure or leave a dent or coating damage that could grow to failure over time.
The regulations on MAOP in part 192 have their origin in engineering standards developed in the 1950s, when industry had relatively limited information about the material properties of pipe and limited ability to evaluate a pipeline's integrity during its operating lifetime. Early pipeline codes allowed maximum operating pressures to be set at a fixed amount under the pressure of the initial strength test without regard to SMYS. Pipeline engineers developing consensus standards looked for ways to lengthen the time before defects initiated during manufacture, construction, or operation could grow to failure. Their solutions focused on tests done at the mill to evaluate the ability of the pipe to contain pressure during operation. They added an additional factor to the hydrostatic test pressure of the mill test. At the time during the 1950's, the consensus standard, known as the B31.8 Code, used this conservative margin of safety for gas pipe design. A 25 percent margin of safety translated into a design factor limiting stress level to 72 percent of SMYS in rural areas. Specifically, the MAOP of 72 percent of SMYS comes from dividing the typical maximum mill test pressure of 90 percent of SMYS by 1.25. When issuing the first Federal pipeline safety regulations in 1970, regulators incorporated this design factor, as found in the 1968 edition of the B31.8 Code, into the requirements for determining the MAOP.
Even as the Federal regulations were being developed, some technical support existed for operation at a higher stress level, provided initial strength testing resulted in operators removing defects. In 1968, the American Gas Association published Report No. L30050 entitled Study of Feasibility of Basing Natural Gas Pipeline Operating Pressure on Hydrostatic Test Pressure prepared by the Battelle Memorial Institute. The research study concluded that:
It is inherently safer to base the MAOP on the test pressure, which demonstrates the actual in-place yield strength of the pipeline, than to base it on SMYS alone.
High pressure hydrostatic testing is able to remove defects that may fail in service.
Hydrostatic testing to actual yield, as determined with a pressure-volume plot, does not damage a pipeline.
The report specifically recommended setting the MAOP as a percentage of the field test pressure. In particular, it recommended setting the MAOP at 80 percent of the test pressure when the minimum test pressure was 90 percent of SMYS or higher. Although the committee responsible for the B31.8 Code received the report, the committee deferred consideration of its findings at that time because the Federal regulators had already begun the process to incorporate the 1968 edition of the B31.8 Code into the Federal pipeline safety standards.
More than a decade later, the committee responsible for development of the B31.8 Code, now under the auspices of the American Society of Mechanical Engineers (ASME), revisited the question of the design factor it had deferred in the late 1960s. The committee determined pipelines could operate safely at stress levels up to 80 percent of SMYS. ASME updated the design factors in a 1990 addendum to the 1989 edition of the B31.8 Code, and they remain in the current edition. Although part 192 incorporates parts of the B31.8 Code by reference, it does not incorporate the updated design factors. With the benefit of operating experience with pipelines, it seems clear that operating pressure plays a less critical role in pipeline integrity and failure consequence than other factors within the operator's control.
By any measure, new technologies and risk controls have had a far greater impact on pipeline safety and integrity. A great deal of progress has occurred in the manufacture of steel pipe and in its initial inspection and testing. Technological advances in metallurgy and pipe manufacture decrease the risk of incipient flaws occurring and going undetected during manufacture. The detailed standards now followed in steel and pipe manufacturing provide engineers considerable information about their material properties. Toughness standards make new steel pipe more likely to resist fracture and to survive mechanical damage. Knowledge about the material properties allows engineers to predict how quickly flaws, whether inherent or introduced during construction or operation, will grow to failure under known operating conditions.
Initial inspection and hydrostatic testing of pipelines allow operators to discover flaws that have occurred prior to operation, such as during transportation or construction. They also serve to validate the integrity of the pipeline before operation. Initial pressure testing causes longitudinal and some other flaws introduced during manufacture, transportation, or construction to grow to the point of failure. Initial pressure testing detects all but one type of manufacturing or construction defect that could cause failure in the near-term. The sole type of defect that pressure testing may not identify, a flaw in a girth weld, is detectable through pre-operational non-destructive testing, which is required in this rule.
The most common defects initiated during operation are caused by mechanical damage or corrosion. Improvements in technology have resulted in internal inspection techniques that provide operators a significant amount of information about defects. Although there is significant variance in the capability of the tools used for internal inspections, each provides the operator information about flaws in the pipeline that an operator would not otherwise have. An operator can then examine these flaws to determine whether they are defects requiring repair. In addition, internal inspections with in-line inspection (ILI) devices, unlike pressure testing, are not destructive and can be done while the pipeline is in operation. Initial internal inspection establishes a baseline. Operators can use subsequent internal inspections at appropriate intervals to monitor for changes in flaws already discovered or to find new flaws requiring repair or monitoring. Internal inspections, and other improved life-cycle management practices, increase the likelihood operators will detect any flaws that remain in the pipe after initial inspection and testing, or that develop after construction, well before the flaws grow to failure.
B.3. History of PHMSA Consideration
Although the agency had never formally revisited its part 192 MAOP standards, prior to this rulemaking, developments in related arenas have increasingly set the stage for changes to those standards. Grandfathered pipelines have operated successfully at higher stress levels in the United States during more than 35 years of Federal safety regulation. Many of these grandfathered pipelines have operated at higher stress levels for more than 50 years without a higher rate of failure. We have also been aware of pipelines outside the United States operating successfully at the higher stress levels permitted under the ASME standard. A technical study published in December 2000 by R.J. Eiber, M. McLamb, and W.B. McGehee, Quantifying Pipeline Design at 72% SMYS as a Precursor to Increasing the Design Stress Level, GRI-00/0233, further raised interest in the issue.
In connection with our issuance of the 2003 gas transmission integrity management regulations, PHMSA announced a policy to grant ``class location'' waivers (now called special permits) to operators demonstrating an alternative integrity management program for the affected pipeline. A ``class location'' waiver allows an operator to maintain current operating pressure on a pipeline following an increase in population that changes the class location. Absent a waiver, the operator would have to reduce pressure or replace the pipe with thicker walled pipe. PHMSA held a meeting on April 14-15, 2004, to discuss the criteria for the waivers. In a notice seeking public involvement in the process (69 FR 22116; Apr. 23, 2004), PHMSA announced:
Waivers will only be granted when pipe condition and active integrity management provides a level of safety greater than or equal to a pipe replacement or pressure reduction.
A second notice (69 FR 38948; June 29, 2004) announced the criteria. The criteria included the use of high quality manufacturing and construction processes, effective coating, and a lack of systemic problems identified in internal inspections Although the class location special permits/waivers do not address increases in stress levels per se, the risk management approach developed in those cases takes account of operating pressure and addresses many of the same concerns. The same risk management approach, and many of the specific criteria applied in the class location waivers, guided PHMSA's handling of the special permits discussed below and, ultimately, this rule.
Beginning in 2005, operators began addressing the issue of stress level directly with requests that PHMSA allow operation at the MAOP levels that the ASME B31.8 Code would allow. With the increasing interest, PHMSA held a public meeting on March 21, 2006, to discuss whether to allow increased MAOP consistent with the updated ASME standards. PHMSA also solicited technical papers on the issue. Papers filed in response, as well as the transcript of the public meeting, are in the docket for this rulemaking. Later in 2006, PHMSA again sought public comment at a meeting of its advisory committee, the Technical Pipeline Safety Standards Committee (TPSSC). The transcript and briefing materials for the June 28, 2006, meeting are in the docket for the advisory committee, Docket ID PHMSA-RSPA-1998-4470-204, 220. This docket can be found at http://www.regulations.gov. Comments and papers written during the period these efforts were undertaken overwhelmingly supported examining increased MAOP as a way to increase energy efficiency and capacity while maintaining safety.
B.4. Safety Conditions in Special Permits
In 2005, operators began requesting waivers, now called special permits, to allow operation at the MAOP levels that the ASME B31.8 Code would allow. In some cases, operators filed these requests at the same time they were seeking approval from the Federal Energy Regulatory Commission (FERC) to build new gas transmission pipelines. In other cases, operators sought relief from current MAOP limits for existing pipelines that had been built to more rigorous design and construction standards.
In developing an approach to the requests, PHMSA examined the operating history of lines already operated at higher stress levels. Canadian and British standards have allowed operation at the higher stress levels for some time. The Canadian pipeline authority, which has allowed higher stress levels since 1973, reports the following regarding pipelines operating at stress levels higher than 72 percent of SMYS:
About 6,000 miles of pipelines on the Alberta system, ranging from six to 42 inches in diameter, were installed or upgraded between the early 1970s and 2005;
About 4,500 miles of pipelines on the Mainline system east of the Alberta-Saskatchewan border, ranging from 20 to 42 inches in diameter, were installed or upgraded between the early 1970s and 2005; and,
More than 600 miles in the Foothills Pipe Line system, ranging from 36 to 40 inches in diameter, were installed between 1979 and 1998.
In the United Kingdom, about 1,140 miles of the Northern pipeline system have been uprated to operate at higher stress level in the past ten years. Accident rates for pipelines in these countries have not indicated a measurable increased risk from operation at these higher operating stress levels.
In the United States, some 5,000 miles of gas transmission lines have MAOPs that were grandfathered under §192.619(c), when the Federal pipeline safety regulations were adopted in the early 1970s, continue to operate at stress levels higher than 72 percent of SMYS. After some accidents caused by corrosion on grandfathered pipelines, PHMSA considered whether to remove the exception in §192.619(c). In 1992, PHMSA decided to continue to allow operation at the grandfathered pressures (57 FR 41119; Sept. 9, 1992). PHMSA based its decision on the operating history of two of the operators whose pipelines contained most of the mileage operated at the grandfathered pressures. PHMSA noted the incident rate on these pipelines, operated at stress levels above 72 percent of SMYS, was between 10 percent and 50 percent of the incident rate of pipelines operated at the lower pressure. Texas Eastern Gas Pipeline Company (now Spectra Energy), the operator of many of the grandfathered pipelines, attributed the lower incident rate to aggressive inspection and maintenance. This included initial hydrostatic testing to 100 percent of SMYS, internal inspection, visual examination of anomalies found during internal inspection, repair of defects, and selective pressure testing to validate the results of the internal inspection. Internal inspection was not in common use in the industry prior to the 1980s. PHMSA's statistics show these pipelines continue to have an equivalent safety record when compared with pipelines operating according to the design factors in the pipeline safety regulations.
PHMSA also considered technical studies and required companies seeking special permits to provide information about the pipelines' design and construction and to specify the additional inspection and testing to be used. PHMSA also considered how to handle findings that could compromise the long-term serviceability of the pipe. PHMSA concluded that pipelines can operate safely and reliably at stress levels up to 80 percent of SMYS if the pipeline has well-established metallurgical properties and can be managed to protect it against known threats, such as corrosion and mechanical damage.
Early and vigilant corrosion protection reduces the possibility of corrosion occurring. At the earliest stage, this includes care in applying a protective coating before transporting the pipe to the right-of-way. With the newer coating materials and careful application, coating provides considerable protection against external corrosion and facilitates the application of induced current, commonly called cathodic protection, to prevent corrosion from developing at any breaks that may occur in the coating. Regularly monitoring the level of protection and addressing any low readings will detect and correct conditions that can cause corrosion at an early stage. Vigilant corrosion protection includes close attention to operating conditions that lead to internal corrosion, such as poor gas quality. In addition, for new pipelines, operators' compliance with a rule issued last year requiring greater attention to internal corrosion protection during design and construction (72 FR 20059; Apr. 23, 2007) will prevent internal corrosion. Finally, corrosion protection includes internal inspection and other assessment techniques for early detection of both internal and external corrosion.
One of the major causes of serious pipeline failure is mechanical damage caused by outside forces, such as an equipment strike during excavation activities. Burying the pipeline deeper, increased patrolling, and additional line marking help prevent the risk that excavation will cause mechanical damage. Further, enhanced pipe properties increase the pipe's resistance to immediate puncture from a single equipment strike. Improved toughness increases the ability of the pipe to withstand mechanical damage from an outside force and may also limit any failure consequences to leaks rather than ruptures. This toughness usually allows time for the operator to detect the damage during internal inspection well before the pipe fails.
To evaluate each request for a special permit, PHMSA established a docket and sought public comment on the request. We received several public comments, most in response to the first special permits considered. Many of the comments supported granting the special permits. Those who were not supportive may have underestimated the significance of the safety upgrades required for the special permits. A few commenters raised technical concerns. Among these were questions about the impact of rail crossings and blasting activities in the vicinity of the pipeline. The special permits did not change the current requirements where road crossings exist and added a requirement to monitor activities, such as blasting, that could impact earth movement. Some commenters expressed concern about the impact radius of the pipeline operating at a higher stress level. PHMSA included supplemental safety criteria to address the increased radius. The remainder of the comments addressed concerns, such as compensation or aesthetics, which were outside the scope of the special permits. PHMSA special permits do not address issues on siting, which are governed by the FERC.
PHMSA expects to issue seven special permits, and possibly more, in response to these requests. In each case, PHMSA has provided oversight to confirm the line pipe is, or will be (for pipe yet to be constructed), as free of inherent flaws as possible, that construction and operation do not introduce flaws, and that any flaws are detected before they can fail. PHMSA accomplishes this by imposing a series of conditions on the grant of special permits. The conditions imposed as part of the special permits are designed to address the potential additional risk involved in operating the pipeline at a higher stress level. A proposed pipeline must be built to rigorous design and construction standards, and the operator requesting a special permit for an existing pipeline must demonstrate that the pipeline was built to rigorous design and construction standards. These additional design and construction standards focused on producing a high quality pipeline that is free from inherent defects that could grow more rapidly under operation at a higher stress level and is more resistant to expected operational risks. In addition, PHMSA requires the operator of a pipeline receiving a special permit to comply with operation and maintenance (O&M) requirements that exceed current pipeline safety regulations. These additional O&M and integrity management requirements focused on the potential for corrosion and mechanical damage and on detecting defects before the defects can grow to failure.
B.5. Codifying the Special Permit Standards
This rule puts in place a process for managing the life-cycle of a pipeline operating at a higher stress level based on our experience with the special permits. Integrity management focuses on managing and extending the service life of the pipeline. Life-cycle management goes beyond the operations and maintenance practices, including integrity management, to address steel production, pipeline manufacture, pipeline design, and installation.
Industry experience with integrity management demonstrates the value of life-cycle management. Through baseline assessments in integrity management programs, gas transmission operators identified and repaired 2,883 defects in the first three years of the program (2004, 2005, and 2006). More than 2,000 of these were discovered in the first two years as operators assessed their highest risk, generally older, pipelines. In a September 2006 report, GAO-09-946, the Government Accountability Office noted this data as an early indication of improvement in pipeline safety. In order to qualify for operation at higher stress levels under this rule, pipelines will be designed and constructed under more rigorous standards. Baseline assessment of these lines will likely uncover few defects, but removing those few defects will result in safer pipelines. In addition, the results of the baseline assessment will aid in evaluating anomalies discovered during future assessments.
This rule, based on the terms and conditions of the special permits allowing operation at higher stress levels, imposes similar terms and conditions and limitations on operators seeking to apply the new rule. The terms and conditions, which include meeting design standards that go beyond current regulation, address the safety concerns related to operating the pipeline at a higher stress level. PHMSA will step up inspection and oversight of pipeline design and construction, in addition to review and inspection of enhanced life-cycle management requirements for these pipelines.
With special permits, PHMSA individually examined the design, construction, and O&M plans for a particular pipeline before allowing operation at a higher pressure than currently authorized. In each case, PHMSA conditioned approval on compliance with a series of rigorous design, construction, O&M, and management standards, including enhanced damage prevention practices. PHMSA's experience with these requests for special permits led to the conclusion that a rule of general applicability is appropriate. With a rule of general applicability, the conditions for approval are established for all without need to craft the conditions based on individual evaluation. Thus, this rule sets rigorous safety standards. In place of individual examination, the rule requires senior executive certification of an operator's adherence to the more rigorous safety standards. An operator seeking to operate at a higher pressure than allowed by current regulation must certify that a pipeline is built according to rigorous design and construction standards and must agree to operate under stringent O&M standards. After PHMSA or state pipeline safety authority (when the pipeline is located in a state where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that state) receives an operator's certification indicating its intention to operate at a higher operating stress level, PHMSA or the state would then follow up with the operator to verify compliance. As with the special permits, this rule would allow an operator to qualify both new and existing segments of pipeline for operation at the higher MAOP, provided the operator meets the conditions for the pipeline segment.
Several types of pipeline segments will not qualify under this rule. These include the following:
Pipeline segments in densely populated Class 4 locations. In addition to the increased consequences of failure in a Class 4 location, the level of activity in such a location increases the risk of excavation damage.
Pipeline segments of grandfathered pipeline already operating at a higher stress level but not constructed in accordance with modern standards. Although grandfathered pipeline has been operated successfully at the higher stress level, PHMSA or the state would examine any further increases individually through the special permit process.
Bare or ineffectively coated pipe. This pipe lacks the coating needed to prevent corrosion and to make cathodic protection effective.
Pipelines with wrinkle bends. Section 192.315(a) currently prohibits wrinkle bends in pipeline operating at hoop stress exceeding 30 percent of SMYS.
Pipelines experiencing failures indicative of a systemic problem, such as seam flaws, during initial hydrostatic testing. Such pipe is more likely to have inherent defects that can grow to failure more rapidly at higher stress levels.
Pipe manufactured by certain processes, such as low frequency electric welding process.
Pipeline segments which cannot accommodate internal inspection devices.
We are establishing slightly different requirements for segments that have already been operating and those which are to be newly built. Some variation is necessary or appropriate for an existing pipeline. For example, the requirement for cathodically protecting pipeline within 12 months of construction is an existing requirement for all pipelines. A requirement for the operator of an existing pipeline segment to prove that the segment was in fact cathodically protected within 12 months of construction provides greater confidence in the condition of the existing segment. Allowing proof of five percent fewer nondestructive tests done on an existing segment at the time of construction recognizes the possibility that some welds may not be tested when 100 percent nondestructive testing is not required. The overriding principle in the variation is to allow qualification of a quality pipeline with minimal distinction. Based on our review of requests for special permits on existing pipelines, PHMSA does not believe the more rigorous standards we are requiring are too high for existing segments of modern design and construction. Setting the qualification standards lower for existing pipeline segments could encourage operators to construct a pipeline at the lower standards and seek to raise the operating pressure at some future date.
PHMSA acknowledges this rule may not cover all conditions encountered by a pipeline operator. Further, operators may have innovative alternative methods to the guidelines contained in this rule. To that end, operators may apply to PHMSA or state pipeline safety authority (when the pipeline is located in a state where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that state) for a special permit requesting to implement the alternative methods.
B.6. How To Handle Special Permits and Requests for Special Permits
A number of pipeline operators have submitted requests for special permits seeking relief from the current design requirements to allow operation at higher stress levels. For the most part, this rule addresses the relief requested. PHMSA has already granted many of these under terms and conditions that may vary slightly from those in this final rule. In some cases, the relief granted is specific to the relief requested by the operator and extends beyond the scope of this rulemaking. PHMSA has continued review of pending special permit applications while working on this rulemaking, in recognition that a final rule may not be issued by the time an operator intended to operate its pipeline at a higher operating stress level. With the publication of this final rule, this case-by-case approach to approving operation under a special permit at higher operating stress levels is no longer needed.
PHMSA will terminate its review of any pending applications for special permits associated with operation at higher operating stress levels once this final rule is issued. Operators of those pipelines must comply with this final rule in order to operate their pipelines at a higher alternative MAOP. PHMSA will examine special permits that have already been granted, as appropriate, to determine if any modifications are needed in light of safety decisions made in preparing this rule.
B.7. Statutory Considerations
Under 49 U.S.C. 60102(a), PHMSA has broad authority to issue safety standards for the design, construction, O&M of gas transmission pipelines. Under 49 U.S.C. 60104(b), PHMSA may not require an operator to modify or replace existing pipelines to meet a new design or construction standard. Although this rule includes design and construction standards, these standards simply add more rigorous, non-mandatory requirements. This rule does not require an operator to modify or replace existing pipelines or to design and construct new pipeline in accordance with these non-mandatory standards. If, however, a new or existing pipeline meets these more rigorous standards, the rule allows an operator to elect to calculate the MAOP for the pipeline based on a higher stress level. This would allow operation at an increased pressure over that otherwise allowed for pipeline built since the Federal regulations were issued in the 1970s. To operate at the higher pressure, the operator would have to comply with more rigorous O&M, and management requirements.
Under 49 U.S.C. 60102(b), a gas pipeline safety standard must be practicable and designed to meet the need for gas pipeline safety and for protection of the environment. PHMSA must consider several factors in issuing a safety standard. These factors include the relevant available pipeline safety and environmental information, the appropriateness of the standard for the type of pipeline, the reasonableness of the standard, and reasonably identifiable or estimated costs and benefits. PHMSA has considered these factors in developing this rule and provides its analysis in the preamble.
PHMSA must also consider any comments received from the public and any comments and recommendations of the TPSSC. These are discussed below.