Pipeline Safety: Safety of Hazardous Liquid Pipelines
Federal RegisterOct 1, 2019
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 195
[Docket No. PHMSA-2010-0229; Amdt. No. 195-102]
RIN 2137-AE66
Pipeline Safety: Safety of Hazardous Liquid Pipelines
AGENCY:
Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT).
ACTION:
Final rule.
SUMMARY:
In response to congressional mandates, NTSB and GAO recommendations, lessons learned, and public input, PHMSA is amending the Pipeline Safety Regulations to improve the safety of pipelines transporting hazardous liquids. Specifically, PHMSA is extending reporting requirements to certain hazardous liquid gravity and rural gathering lines; requiring the inspection of pipelines in areas affected by extreme weather and natural disasters; requiring integrity assessments at least once every 10 years of onshore hazardous liquid pipeline segments located outside of high consequence areas and that are “piggable” (
i.e.,
can accommodate in-line inspection devices); extending the required use of leak detection systems beyond high consequence areas to all regulated, non-gathering hazardous liquid pipelines; and requiring that all pipelines in or affecting high consequence areas be capable of accommodating in-line inspection tools within 20 years, unless the basic construction of a pipeline cannot be modified to permit that accommodation. Additionally, PHMSA is clarifying other regulations and is incorporating Sections 14 and 25 of the PIPES Act of 2016 to improve regulatory certainty and compliance.
DATES:
The effective date of this final rule is July 1, 2020. The incorporation by reference of certain publications listed in the rule was approved by the Director of the Federal Register as of March 24, 2017 and March 6, 2015.
FOR FURTHER INFORMATION CONTACT:
Technical questions:
Steve Nanney, Project Manager, by telephone at 713-272-2855.
General information:
Robert Jagger, Senior Transportation Specialist, by telephone at 202-366-4361.
SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of the Regulatory Action in Question
C. Costs and Benefits
II. Background
A. Detailed Overview
B. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011
C. National Transportation Safety Board Recommendations
D. Summary of Each Topic
III. Pipeline Advisory Committee
IV. Analysis of Comments and PHMSA Response
A. Reporting Requirements for Gravity Lines
B. Reporting Requirements for Gathering Lines
C. Pipelines Affected by Extreme Weather and Natural Disasters
D. Periodic Assessment of Pipelines Not Subject to IM
E. IM and Non-IM Repair Criteria
F. Leak Detection Requirements
G. Increased Use of ILI Tools in HCAs
H. Clarifying Other Requirements
V. PIPES Act of 2016
VI. Section-by-Section Analysis
VII. Regulatory Notices
I. Executive Summary
A. Purpose of the Regulatory Action
In recent years, there have been significant hazardous liquid pipeline accidents, most notably the 2010 crude oil spill near Marshall, MI, during which at least 843,000 gallons of crude oil were released, significantly affecting the Kalamazoo River. In response to accident investigation findings, incident report data and trends, and stakeholder input, the Pipeline and Hazardous Materials Safety Administration (PHMSA) is amending the hazardous liquid pipeline safety regulations to improve protection of the public, property, and the environment by closing regulatory gaps where appropriate and ensuring that operators are increasing the detection and remediation of pipeline integrity threats, and mitigating the adverse effects of pipeline failures. On October 18, 2010, PHMSA published an Advanced Notice of Proposed Rulemaking (ANPRM) in the
Federal Register
(75 FR 63774). The ANPRM solicited stakeholder and public input and comments on several aspects of the hazardous liquid pipeline regulations being considered for revision or updating to address various pipeline safety issues.
Subsequently, Congress enacted the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (2011 Pipeline Safety Act). That legislation included several provisions that are relevant to the regulation of hazardous liquid pipelines. The 2011 Pipeline Safety Act included mandates for PHMSA to complete studies on topics including existing Federal and State regulations for gathering lines, on automatic shutdown and remote control valves, expanding integrity management requirements beyond high-consequence areas, and on the leak detection systems used by hazardous liquid operators. PHMSA completed these studies and submitted the valve and leak detection studies to Congress on December 27, 2012; the gathering line study to Congress on May 8, 2015; and the integrity management (IM) study in April of 2016. These studies are available in the docket for this rulemaking.
Shortly after the 2011 Pipeline Safety Act was passed, the National Transportation Safety Board (NTSB) issued its accident investigation report on the Marshall, MI, accident on July 10, 2012. In it, the NTSB made recommendations regarding the need to revise and update hazardous liquid pipeline regulations. Specifically, the NTSB issued recommendations P-12-03 and P-12-04, which addressed detection of pipeline cracks and “discovery of condition,” respectively. The “discovery of condition” recommendation would require, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, that pipeline operators notify PHMSA and provide an expected date when adequate information will become available.
The Government Accounting Office (GAO) also issued a recommendation in 2012 concerning hazardous liquid and gas gathering pipelines. Recommendation GAO-12-388, dated March 22, 2012, states, “To enhance the safety of unregulated onshore hazardous liquid and gas gathering pipelines, the Secretary of Transportation should direct the PHMSA Administrator to collect data from operators of federally unregulated onshore hazardous liquid and gas gathering pipelines, subsequent to an analysis of the benefits and industry burdens associated with such data collection.”
On October 13, 2015, PHMSA published a NPRM to seek public comments on proposed changes to the hazardous liquid pipeline safety regulations (80 FR 61609). A summary of those proposed changes is provided later in this document.
Between the publication of the NPRM and this final rule, the President signed the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” (PIPES Act of 2016), Public Law 114-183, on June 22, 2016. While the PIPES Act of 2016 contained several mandates that must be addressed
through rulemaking, certain provisions are self-executing standards that can be incorporated into this final rule rulemaking without a prior NPRM and opportunity to comment. Those changes are outlined in Section V of this document.
B. Summary of the Major Provisions of the Regulatory Action
In response to these mandates, recommendations, lessons learned, and public input, PHMSA is making certain amendments to the Pipeline Safety Regulations affecting hazardous liquid pipelines. The first and second amendments extend reporting requirements to certain hazardous liquid gravity and rural gathering lines not currently regulated by PHMSA. The collection of information about these lines, including those that are not currently regulated, is authorized under the Pipeline Safety Laws, and the resulting data will assist in determining whether the existing Federal and State regulations for these lines and the scope of their applicability are adequate.
The third amendment requires inspections of pipelines in areas affected by extreme weather or natural disasters that could impose unexpected longitudinal or circumferential pipe loads, or other risks to the pipeline's integrity and continued safe operation. This provision affects all covered lines under § 195.1, whether they be onshore or offshore, and in a high consequence area (HCA) or outside an HCA.
1
Such inspections will help to ensure that operators can safely operate pipelines after these events.
1
High Consequence Areas are defined in 49 CFR 195.450.
The fourth amendment requires integrity assessments at least once every 10 years, using inline inspection tools or other technology, as appropriate for the threat being assessed, of onshore, piggable, hazardous liquid pipeline segments located outside of HCAs. Existing regulations require operators to assess hazardous liquid pipeline segments located inside HCAs at least once every 5 years. These assessments will provide important information to operators about the condition of these pipelines, including the existence of internal and external corrosion and deformation anomalies.
The fifth amendment extends the required use of leak detection systems beyond HCAs to all regulated hazardous liquid pipelines, except for offshore gathering and regulated rural gathering pipelines. The use of such systems will help to mitigate the effects of hazardous liquid pipeline failures that occur outside of HCAs.
The sixth amendment requires that all pipelines in or affecting HCAs be capable of accommodating in-line inspection tools within 20 years, unless the basic construction of a pipeline cannot be modified to permit that accommodation. In-line inspection tools are an effective means of assessing the integrity of a pipeline and broadening their use will improve the detection of anomalies and prevent or mitigate future accidents in high-risk areas. Finally, PHMSA is clarifying other regulations and is incorporating Sections 14 and 25 of the PIPES Act of 2016 to improve regulatory certainty and compliance.
C. Cost and Benefits
Consistent with Executive Orders 12866 and 13563, PHMSA has prepared an assessment of the benefits and costs of the rule as well as reasonably feasible alternatives. PHMSA estimates that up to 502 hazardous liquid operators may incur costs to comply with the NPRM. The estimated annual costs for individual components of the requirements in this rulemaking range between approximately $5,000 and $10.5 million, with aggregate costs of approximately $19.5 million to $21.4 million for all requirements.
2
2
Estimated costs are annualized using a 7 percent discount rate.
This final rule is primarily designed to mitigate or prevent hazardous liquid pipeline incidents, and is expected to reduce pipeline incident damages, including injuries and fatalities, cleanup and response costs, property damage, product loss, and ecosystem impacts. The rule's information reporting requirements are designed to provide PHMSA information to inform regulatory decision-making. The Regulatory Impact Analysis (RIA) for this final rule is available in the docket. The table below provides a summary of the estimated costs and benefits for each of the eight major provisions and in total (see the RIA for the details of these estimates).
Annualized Costs and Benefits by Requirement Area (2017$)
3
Final rule requirement area
Annual costs
1
3% discount rate
7% discount rate
Benefits
1. Reporting requirements for gravity lines
$5,000
$5,000
Better risk understanding and management.
2
2. Reporting requirements for gathering lines
$75,000
$76,000
Better risk understanding and management.
3
3. Inspections of pipelines in areas affected by extreme weather events or natural disasters
4
Minimal
Minimal
Additional clarity and certainty for pipeline operators.
4. Assessments of onshore pipelines that are not already covered under the IM program using ILI every 10 years
5 6
$6,467,000
$6,467,000
Avoided incidents and damages through detection of safety conditions.
7
5. IM repair criteria
8
$0
$0
$0.
6. LDSs on pipelines located outside HCAs
6
$8,652,000
$10,508,000
Reduced damages through earlier detection and response.
9
7. Increased use of ILI tools
10
Minimal
Minimal
Improved detection of pipeline flaws.
10
8. Clarify certain IM plan requirements
$4,269,000
$4,343,000
Reduced damages through prevention and earlier detection and response.
11
Total
$19,468,000
$21,399,000
Reduced damages from avoiding and/or mitigating hazardous liquid releases.
1
Costs in this table are rounded to the nearest thousand dollars and may differ from costs presented in individual sections of the document. One-time costs are annualized over a 10-year period using discount rates of 3 percent and 7 percent.
2
Gravity lines can present safety and environmental risks. Depending on the elevation change, a gravity flow pipeline could have more pressure than a pipeline with pump stations to boost the pressure. The benefits of this requirement are not quantified, but based on social costs of $51 per gallon for releases from regulated gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of 101 gallons per year to generate benefits that equal the costs.
3
The benefits are not quantified, but based on social costs of $51 per gallon for releases from regulated gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of 1,493 gallons per year to generate benefits that equal the costs.
4
To the extent that the 72-hour timeline required in the final rule results in higher costs for conducting inspections following a disaster (e.g., due to staff overtime), the final rule could result in costs not reflected in this analysis.
5
PHMSA also conducted a sensitivity analysis that uses alternative baseline assumptions for pipelines not currently covered under the IM program. Specifically, PHMSA estimated the costs for two alternative scenarios: (1) A scenario that assumes that 100 percent of mileage outside HCAs is assessed in the baseline; and (2) a scenario that assumes that 83 percent of the mileage is assessed in the baseline. Costs for these two scenarios are $0 and $12.9 million, respectively.
6
Excludes gathering lines.
7
Given a cost per incident of $536,800, incremental assessment of pipelines outside of HCAs would need to prevent 12 incidents for benefits to equate costs.
8
PHMSA is not finalizing any changes to the repair criteria and as such expects no incremental costs or benefits.
9
As discussed in Section 2.6.2, 1,918 incidents involved pipelines outside HCAs between 2010 and 2017, or an average of 240 incidents per year. Transmission pipeline incidents outside HCAs had average costs of approximately $382,179, not including additional damages and costs that are excluded or underreported in the incident data. The annual cost estimate is equivalent to the average damages of 28 to 32 such incidents.
10
Costs (to retrofit pipes to accommodate ILI) and benefits (from avoided damages) would accrue only to the extent that existing practices deviate from industry standards; PHMSA expects costs and benefits will be minimal due to baseline prevalence of ILI-capable pipelines in all areas.
11
The benefits of reduced costs associated with the prevention or reduction of released hazardous liquids cannot be quantified but could vary in frequency and size depending on the types of failures that are averted. Including additional pipelines in the IM plan, integrating data, and conducting spatial analyses is expected to enhance an operator's ability to identify and address risk. The societal costs associated with incidents involving pipelines in HCAs average $1.7 million per incident (see Section 2.6.2). The annual cost estimates for this requirement are equivalent to the average damages from less than three such incidents. This is relative to an annual average of 161 incidents in HCAs between 2010 and 2017.
II. Background
3
Numbers in this table may not sum due to rounding.
A. Detailed Overview
This final rule addresses the requirements established by Congress in the 2011 Pipeline Safety Act, which are consistent with the emerging needs of the Nation's hazardous liquid pipeline system. This final rule also advances an important safety need to adapt and expand risk-based safety practices considering changing markets and a growing national population whose location choices are in ever-closer proximity to existing pipelines.
This final rule strengthens protocols for IM, including protocols for inspections, and improves and streamlines information collection to help drive risk-based identification of the areas with the greatest safety deficiencies.
Hazardous Liquid Infrastructure Overview
There are two major types of pipelines along the petroleum transportation route: Gathering pipeline systems, and crude oil and refined products pipeline systems. The location, construction and operation of these systems are generally regulated by Federal and State requirements.
Gathering lines are typically smaller pipelines no more than 8
5/8
inches in diameter that transport petroleum from onshore and offshore production facilities. Hazardous liquid pipelines transport the crude oil from the gathering systems to refineries and from refineries to distribution centers. Hazardous liquid lines transport both crude and refined products, and can be hundreds of miles long. These lines may cross State and continental borders, and range in size from 2 to 48 inches in diameter. Hazardous liquid pipeline networks also include pump stations, which move the product through the pipelines, and storage terminals. Changes in product demand has also led to efforts by operators to increase pipeline capacity through flow-direction reversals or converting natural gas pipelines into hazardous liquid pipelines.
Per PHMSA's database, 43 percent of all hazardous liquid pipelines were installed prior to 1970.
4
However, pipeline manufacturing, construction, and operational and maintenance practices have been improving steadily in recent decades, and some older pipes are susceptible to certain manufacturing or construction defects. For example, low-frequency electric resistance welded (ERW) pipe used from the early 1900s through the post-World War II construction boom that lasted well into the 1970s is vulnerable to seam-quality issues. Since the early 1970s, many improvements in pipe manufacturing and materials have been made, and steel and seam properties of pipe have improved with the increased use of high-frequency electric welded (HF-ERW), submerged arc welded (SAW), and seamless pipe (SMLS).
5
In addition, smart pigs, which are tools that record information about the internal conditions of a pipeline, were not developed until the 1960s and 1970s prior to the adoption of the part 195 regulations.
4
PHMSA's Annual Report Mileage for Hazardous Liquid or Carbon Dioxide Systems;
https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
5
HF-ERW steel pipe has a welded pipe seam made using a high frequency welding current. SMLS steel pipe has no longitudinal weld seam. SAW steel pipe has a weld seam made using a submerged welding arc in a bed of powdered flux to shield it from impurities.
Since 2012, U.S. oil production has increased about 70 percent from approximately 2.4 to 3.4 Billion barrels annually
6
resulting in the United States becoming the world's largest producer of liquid fuels in early 2014. Much of the recent increases in production have been in tight oil plays. Tight oil shale formations are heterogeneous and vary widely over relatively short distances and are subjected to fracking. Examples of tight oil formations include the Bakken Shale, the Niobrara Formation, Barnett Shale, and the Eagle Ford Shale in the United States. Per data from the U.S. Energy Information Administration (EIA), in 2017, tight oil plays accounted for approximately half of the U.S. production, balancing declining production in older plays. While tight oil from shale plays has historically been more difficult to extract, improvements in drilling and production methods, such as horizontal drilling and hydraulic fracturing, have made it economically recoverable. These tight oil plays are located both in regions that have had an oil extraction industry for decades and new regions, such as the Bakken region in North Dakota and Montana, that were not previously oil-producing areas. This has expanded U.S. refiners' access to domestically produced crudes, and U.S. crude oil imports dropped by 7 percent since 2012.
7
Additionally, exports have risen from minimal amounts in 2012 to
over a million barrels per day in 2017.
8
These supply increases and spatial changes in production patterns are creating wide-ranging impacts on liquid fuels transportation infrastructure.
6
U.S. Energy Information Administration, Crude Oil Production. Producers extracted 2.4 billion barrels of crude oil from U.S. fields in 2012 and 3.4 billion barrels of crude oil in 2017.
https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm.
7
EIA, U.S. Imports of Crude Oil (Thousands of Barrels per Day).
https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_epc0_im0_mbblpd_a.htm.
8
EIA, U.S. Exports of Crude Oil (Thousand Barrels per Day).
https://www.eia.gov/dnav/pet/pet_move_exp_dc_NUS-Z00_mbblpd_a.htm.
Regulatory History
Congress established the current framework for regulating the safety of hazardous liquid pipelines in the Hazardous Liquid Pipeline Safety Act (HLPSA) of 1979 (Pub. L. 96-129). The HLPSA provides the Secretary of Transportation (the Secretary) with the authority to prescribe minimum Federal safety standards for hazardous liquid pipeline facilities. That authority, as amended in subsequent reauthorizations, is currently codified in the Pipeline Safety Laws (49 U.S.C. 60101,
et seq.
).
PHMSA is the agency within DOT that administers the Pipeline Safety Laws. PHMSA has issued a set of comprehensive safety standards for the design, construction, testing, operation, and maintenance of hazardous liquid pipelines. Those standards are codified in the Hazardous Liquid Pipeline Safety Regulations (49 CFR part 195).
Part 195 applies broadly to the transportation of hazardous liquids or carbon dioxide by pipeline, including on the Outer Continental Shelf, with certain exceptions set forth by statute or regulation. A combination of prescriptive and management-based safety standards is used (
i.e.,
an objective is specified, but the method of achieving that objective is not). Risk management principles play a key role in the IM requirements.
PHMSA exercises primary regulatory authority over interstate hazardous liquid pipelines, and the owners and operators of those facilities must comply with safety standards in part 195. States may apply to PHMSA for a certification to conduct inspections of intrastate hazardous liquid pipelines. Public utility commissions administer most State pipeline safety programs. These State authorities must adopt the Pipeline Safety Regulations as part of a certification or agreement with PHMSA, but may establish more stringent safety standards for intrastate pipeline facilities within their State regulatory authorities. PHMSA is precluded from regulating the safety standards or practices for an intrastate pipeline facility if a State is currently certified to regulate that facility. States certified to regulate their intrastate lines can also enter into agreements with PHMSA to serve as an agent for inspecting interstate facilities, and they can receive Federal monetary grants to off-set the costs of those State inspections.
In 2000 and 2002, the Office of Pipeline Safety (OPS) published regulations requiring IM programs for hazardous liquid pipeline operators in response to a hazardous liquid incident in Bellingham, WA, in 1999 that killed three people.
9
The regulations were broad-reaching and supplemented PHMSA's prescriptive safety requirements with performance and process-oriented requirements. The approach aimed to set expectations for operators while giving them a degree of flexibility in how they complied with those expectations. The objectives of the IM regulations were to accelerate and improve the quality of integrity assessments conducted on pipelines in areas with the highest potential for adverse consequences; promote a more rigorous, integrated, and systematic management of pipeline integrity and risk by operators; strengthen the government's role in the oversight of pipeline operator integrity plans and programs; and increase the public's confidence in the safe operation of the Nation's pipeline network.
9
65 FR 75378; December 1, 2000; Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators With 500 or More Miles of Pipeline). 67 FR 1650; January 14, 2002; Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Repair Criteria). 67 FR 2136; January 16, 2002; Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators With Less Than 500 Miles of Pipelines).
In January 2011, PHMSA published the Hazardous Liquid Integrity Management Progress Report,
10
which reported on PHMSA's progress in achieving the program objectives and examined accident trends. The report found that the IM rule and PHMSA's rigorous oversight of operator compliance with the rule are contributing to improved safety performance, including a reduction in the frequency of significant accidents and a decrease in volume spilled in significant accidents.
10
http://primis.phmsa.dot.gov/iim/IM_Jan2011_StatusReport_01_23_11.pdf
.
PHMSA's Progress on Integrity Management
The original part 195 Pipeline Safety Regulations were not designed with risk management in mind. In the mid-1990s, following models from other industries such as nuclear power, PHMSA started to explore whether a risk-based approach to regulation could improve safety of the public and the environment. During this time, PHMSA found that many operators were performing forms of IM that varied in scope and sophistication but there were not consistent minimum standards or requirements.
Since the implementation of the IM regulations more than 15 years ago, many factors have changed. Most importantly, there have been sweeping changes in the oil industry, and the Nation's relatively safe but aging pipeline network faces increased pressures from these changes. Long-identified pipeline safety issues, some of which IM set out to address, remain problems. Infrequent but severe accidents indicate that some pipelines continue to be vulnerable to failures stemming from, among other things, outdated construction methods or materials. Some severe pipeline accidents have occurred in areas outside HCAs where the application of IM principles is not required.
11
11
Per PHMSA annual report data accessed May 14, 2019, 1677 non-HCA accidents have occurred since 2010. Of these accidents, 908 resulted in a “large” spill, which for reporting purposes is defined as those spills where there was a fatality, injury, fire, explosion, water contamination, property damage of greater than $50,000, or an unintentional loss of product greater than 210 gallons (5 bbls).
The current IM program is both a set of regulations and an overall regulatory approach to improve pipeline operators' ability to identify and mitigate the risks to their pipeline systems. On the operator level, an IM program includes adopting procedures and processes to identify HCAs, which are areas with the greatest population density and environmental sensitivity; determining likely threats to the pipeline within the HCA; evaluating the physical integrity of the pipe within the HCA; and repairing or remediating any pipeline defects found. Because these procedures and processes are complex and interconnected, effective implementation of an IM program relies on continual evaluation and data integration.
Operators have made great progress towards achieving the IM objectives. Operators have an improved understanding of the precise locations of their HCAs—those areas where integrity assessments and other protective measures spelled out in the IM rule must be taken to assure public safety and environmental protection. During an incident, petroleum can spread over large areas and cause environmental damage. The IM protections for HCAs are designed to account for the potential environmental and community risks from oil releases. Per PHMSA's hazardous liquid annual
data, 42 percent of the Nation's hazardous liquid pipelines
12
can potentially affect HCAs and thus receive the enhanced level of integrity assessment and protection mandated by the IM rule. As required by the IM rule, operators have also conducted baseline integrity assessments on all pipelines that could affect HCAs and have begun conducting reassessments of these same pipeline segments. Through this requirement to assess their pipelines, operators now have an improved understanding of the condition of pipelines in these safety-sensitive areas.
12
http://phmsa.dot.gov/portal/site/PHMSA/menuitem.6f23687cf7b00b0f22e4c6962d9c8789/?vgnextoid=a872dfa122a1d110VgnVCM1000009ed07898RCRD&vgnextchannel=3430fb649a2dc110VgnVCM1000009ed07898RCRD&vgnextfmt=print.
According to PHMSA's January 2011 Hazardous Liquid Integrity Management Progress Report, which tracked the progress and effectiveness of the IM program in its first decade, as a result of these initial baseline assessments, operators have made more than 7,600 repairs of anomalies that required immediate attention, remediated over 28,000 other conditions on a scheduled basis, and addressed an additional 79,000 anomalies that were not required to be addressed by the IM rule, thus significantly improving the condition of the Nation's pipelines.
However, based on recent accidents and mandates from the 2011 Pipeline Safety Act, improvement is still needed in the areas of data integration and their use in risk modelling, risk analysis, and to identify and implement additional preventive and mitigative measures to reduce risk. Improving data integration is critical, as the integrity assessment provisions of the rule only address some of the causes of pipeline failures.
Inadequate Leak Detection, Exposure to Weather, Increased Use, and Age Can Increase the Risk of Pipeline Incidents
Risk factors for pipeline safety issues stem from many sources, including manufacturing issues, external weather and environmental factors, land-use activities near pipelines, other operational issues, and age-related integrity issues.
On July 25, 2010, a segment of a 30-inch-diameter pipeline called Line 6B, owned and operated by Enbridge Incorporated, ruptured in a wetland area in Marshall, MI. Per §§ 195.450 and 195.6, this area was identified by the operator as an “other populated area,” which meant it was within an HCA. Per the NTSB's Pipeline Accident Report on the incident, the rupture occurred during the last stages of a planned shutdown and was not discovered or addressed for over 17 hours. During the time lapse, Enbridge twice pumped additional oil (81 percent of the total release) into Line 6B during two startups; the total release was estimated by Enbridge to be 843,444 gallons of crude oil.
13
The oil saturated the surrounding wetlands and flowed into the Talmadge Creek and the Kalamazoo River. In all, 4,632 acres of land were impacted, 346 animals were killed, 4,208 animals were oiled, and fish and benthic invertebrate communities were impacted. Further, approximately 100,000 recreational user-days were lost, including activities like fishing and boating, and general shoreline park and trail use. The incident also resulted in losses of tribal use, as the Kalamazoo River is used by two tribes for water travel; subsistence; and medicinal, economic, educational, and ceremonial services.
14
This incident motivated a reexamination of hazardous liquid pipeline safety. The NTSB made recommendations to PHMSA and the regulated industry regarding the need to improve hazardous liquid pipeline safety. Congress also directed PHMSA to reexamine many of its safety requirements, including the expansion of IM regulations to more hazardous liquid pipelines. Other recent accidents, including a pair of related failures that occurred in 2010 on a crude oil pipeline in Salt Lake City, UT, corroborated the significance of having an adequate means for identifying and responding to leaks in all locations.
13
National Transportation Safety Board: “Enbridge Incorporated Hazardous Liquid Pipeline Rupture and Release, Marshall, Michigan, July 25, 2010,” Accident Report NTSB/PAR-12/01, adopted 2012;
http://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf.
14
U.S. Fish and Wildlife Service: “Final Damage Assessment and Restoration Plan/Environmental Assessment for the July 25-26, 2010 Enbridge Line 6B Oil Discharges near Marshall, MI;” Sections 1.4—Summary of Natural Resource Injuries and 3.0—Injury Assessment and Quantification. October 2015.
https://www.fws.gov/midwest/es/ec/nrda/MichiganEnbridge/pdf/FinalDARP_EA_EnbridgeOct2015.pdf.
The Nation's pipeline system also faces significant risk from failure due to extreme weather events and natural disasters, such as hurricanes, floods, mudslides, tornadoes, and earthquakes. On January 17, 2015, a breach in the Bridger Pipeline Company's Poplar system resulted in a spill into the Yellowstone River near the town of Glendive, MT, releasing 31,835 gallons (758 barrels)
15
of crude oil into the river and affecting local water supplies. Information indicated over 100 feet of pipeline was exposed on the river bottom, and the release point was near a girth weld. A depth of cover survey indicated sufficient cover in late 2011,
16
but the area experienced localized flooding in early 2014. A previous crude oil spill into the Yellowstone River in 2011 near Laurel, MT, was caused by channel migration and river bottom scour, leaving a large span of the pipeline exposed to prolonged current forces and debris washing downstream in the river. Those external forces damaged the exposed pipeline.
15
PHMSA Database: “Operator Information: Incident and Mileage Data: Bridger Pipeline LLC,”
http://primis.phmsa.dot.gov/comm/reports/operator/OperatorIM_opid_31878.html?nocache=4851%20-%20_Incidents_tab_3#_OuterPanel_tab_2.
16
PHMSA, Corrective Action Order, CPF No. 5-2015-5003H, page 4, January 23, 2015;
http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Pipeline/520155003H_Corrective%20Action%20Order_01232015.pdf.
In October 1994, flooding along the San Jacinto River led to the failure of eight hazardous liquid pipelines and undermined a number of other pipelines. The escaping products were ignited, leading to 547 people in the area suffering extensive smoke inhalation or burn injuries.
17
According to PHMSA's Accident and Incident Data for hazardous liquid pipelines, from 2010 to 2017, there were 145 reportable incidents
18
in which storms or other severe natural force conditions damaged pipelines and resulted in their failure. Operators reported total damages of over $232 million from these incidents.
19
PHMSA has issued several Advisory Bulletins to operators warning about extreme weather events and the consequences of flooding events, including river scour and river channel migration. Further, in December 2017, the American Petroleum Institute issued a Recommended Practice 1133 that provided guidance to operators on how to identify at-risk river crossings and take measures to reduce such risks before, during, and after flooding- and river-scour events.
17
NTSB, Pipeline Special Investigation Report, “Evaluation of Pipeline Failures During Flooding and of Spill Response Actions, San Jacinto River Near Houston, Texas, October 1994;” NTSB/SIR-96/04, Adopted September 6, 1996.
18
Reporting thresholds for hazardous liquid pipelines are established at § 195.50. Operators must report any failures of a hazardous liquid pipeline resulting in any of the following: (1) An explosion or fire not intentionally set by the operator, (2) A release of 5 gallons or more of hazardous liquid or carbon dioxide, (3) The death of an individual, (4) Personal injury requiring hospitalization, (5) Estimated property damage exceeding $50,000.
19
PHMSA Hazardous Liquid Accident Reports.
https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
In addition to external weather and environmental threats, changing production and shipment patterns are increasing stress on the Nation's
pipeline system. Shifting production to tight oil production like shale plays have changed U.S. oil production locations, as well as the types of crude transported in the Nation's pipelines. The U.S. pipeline system has previously moved crude oil from interior production regions to the Gulf of Mexico refineries, and petroleum products from Gulf Coast refineries to the interior of the country. However, increased tight oil production requires significant infrastructure expansion in new areas, and shifting production areas are changing the patterns of oil transport. Many operators are adapting their systems to move crude oil to markets formerly dependent on imports by modifying existing pipelines. These modifications can be made by reversing flow directions and repurposing natural gas pipelines; in some cases pipeline expansion projects can also increase pumping capability with minimal alterations of the pipeline itself.
Reversing a pipeline's flow, modifying pump station placement and operation, changing commodities, or making other changes to a pipeline's historical hydraulic gradient can impose new stresses on the system due to altered pressure gradients, cycling, and flow rates. Furthermore, certain commodities and low flow rates may create new risks of internal corrosion. Occasional failures on hazardous liquid pipelines have occurred after operational changes that include flow reversals and product changes. PHMSA has noticed several recent or proposed flow reversals and product changes on a number of hazardous liquid and gas transmission lines. In response to this phenomenon, on September 18, 2014, PHMSA issued an Advisory Bulletin
20
notifying operators of the potentially significant impacts such changes may have on the integrity of a pipeline.
20
PHMSA: “Pipeline Safety: Guidance for Pipeline Flow Reversals, Product Changes and Conversion to Service”
Advisory Bulletin,
79 FR 56121, September 18, 2014;
http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Advisory%20Notices/ADB-2014-04_Flow_Reversal.pdf.
Data indicate that some pipelines also continue to be vulnerable to issues stemming from outdated construction methods or materials. Much of the older pipe in the Nation's pipeline infrastructure was made before the 1970s using techniques that have proven to contain latent defects due to the manufacturing process.
21
Such defects cause the pipe to be susceptible to developing hook cracks or other anomalies that may, over time, lead to failures if they are not timely repaired. For example, line pipe manufactured using low-frequency electric resistance welding is susceptible to seam failure. A substantial amount of this type of pipe is still in service; per PHMSA's “Miles by Decade of Installation Inventory Reports” for hazardous liquid lines, there were 92,271 miles of pre-1970s pipe still in service in 2017.
22
The IM regulations include specific requirements for evaluating such pipe if located in HCAs, but infrequent-yet-severe failures that are attributed to longitudinal seam defects continue to occur. Per PHMSA's Accident and Incident database, between 2010 and 2017, 84 reportable incidents were attributed to seam failures, resulting in over $220 million of property damage.
23 24
21
See
https://primis.phmsa.dot.gov/comm/FactSheets/FSPipeManufacturingProcess.htm
for more information about pipe manufacturing processes and known latent defects.
22
PHMSA's Annual Report Mileage for Hazardous Liquid or Carbon Dioxide Systems;
https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
23
PHMSA Hazardous Liquid Accident Reports.
https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
24
The data can be narrowed down by selecting the “hl2010toPresent” Excel spreadsheet. Cell “CR” indicates the identified location of the failure and whether the failure was in the pipe body or in the pipe seam. If it was identified as a pipe seam failure, Cells “CW” and “CX” provide additional information on pipe seam type and pipe seam details, respectively.
In the final rule, PHMSA strengthens the IM requirements to identify and respond to the increased pipeline risks resulting from operational changes, weather and associated geotechnical hazards, and increased use and age of a pipe.
Enhanced Collection of Data
To keep the public safe and to protect the Nation's energy security and reliability, operators and regulators must have an intimate understanding of their entire pipeline system, including threats and operations. However, with operators who are not required to report certain information on certain currently unregulated pipelines, and with aging pipelines that are not modernized for internal inspection, there continue to be data gaps that make it hard to fully understand the extent of the potential safety risks to the integrity of the Nation's pipeline system.
PHMSA's regulations exempt rural gathering pipelines and gravity pipelines. Gravity pipelines carry product by means of gravity, and many gravity lines are short and within tank farms or other pipeline facilities. However, some gravity lines are longer and can build up high pressures. PHMSA is aware of gravity lines that traverse long distances with significant elevation changes, which could have significant consequences in the event of a release. Both gravity and gathering lines are currently excluded from reporting requirements, leaving large gaps in PHMSA's knowledge of these unregulated pipeline systems. This is especially true because much of operators' and PHMSA's data is obtained through testing and inspection under IM requirements, which are not currently required for gathering and gravity lines.
To assess a pipeline's integrity, operators generally choose between three methods of testing a pipeline: In-line inspection (ILI), pressure testing, and direct assessment (DA). In 2017, PHMSA estimates that slightly over 90 percent of the hazardous liquid line mileage in HCAs is already piggable and almost 90 percent of these lines were being inspected with ILI tools.
Operators perform ILIs by using special tools, sometimes referred to as “smart pigs,” which are usually pushed through a pipeline by the pressure and flow rate of the product being transported. As the tool travels through the pipeline, it identifies and records potential pipe defects or anomalies. Because these tests can be performed with product in the pipeline, the pipeline does not have to be taken out of service for testing to occur, which can reduce cost to the operator and possible service disruptions to consumers. Further, ILI is a non-destructive testing technique, and it can be less costly on a per-unit basis to perform than other assessment methods. However, a very small portion of hazardous liquid pipe segments cannot be inspected through ILI because they are too short in length, which makes getting accurate ILI tool results impractical due to tool speed variations. Other hazardous liquid pipelines might not be inspected through ILI because they do not have enough operating pressure or flow rate to run the tool.
Pipeline operators typically use pressure tests to determine the integrity (or strength) of the pipeline immediately after construction and before placing the pipeline in service. In a pressure test, a test medium (typically water) inside the pipeline is pressurized to a level greater than the normal operating pressure of the pipeline. This test pressure is held for a number of hours to ensure there are no leaks in the pipeline.
Direct assessment is the evaluation of various locations on a pipeline for corrosion threats. Operators will review operational records and indirectly inspect the pipeline with coating surveys, such as close interval, direct
current voltage gradient, and alternating current voltage gradient surveys, to detect areas where the protective, anti-corrosion coating applied to a pipeline may be faulty, as corrosion may be more likely in these locations. Operators subsequently excavate and examine areas that are likely to have suffered from corrosion. DA can be costly to use without targeting specific locations. A limited number of specific locations, however, may not give an accurate representation of the condition of lengths of entire pipeline segments.
Ongoing research appears to indicate that ILI and hydrostatic pressure “spike” testing are more effective than DA for identifying pipe conditions related to cracking defects such as dents with stress cracks, stress corrosion cracking (SCC), selective seam weld corrosion (SSWC), and other seam-type cracking.
25
Hydrostatic testing of hazardous liquid pipelines requires testing to at least 125 percent of the maximum operating pressure (MOP) for at least 4 continuous hours and an additional 4 hours at a pressure of at least 110 percent of MOP if the pipe is not visible. If there is concern about pipe cracks that might grow due to pressure cycling, operating stress levels, environmental conditions, and fatigue, then a spike test at a pressure of up to or over 139 percent of MOP for a short period (up to a 30-minute hold time or longer) may be conducted. A spike test detects pipe body and seam cracks by causing any cracks that would later grow to failure to fail during the hydrostatic test. Both regulators and operators have expressed interest in improving ILI methods as an alternative to hydrostatic testing for better risk evaluation and management of pipeline safety. Hydrostatic pressure testing can result in substantial costs and occasional disruptions in service, whereas ILI testing can obtain data that is not otherwise obtainable via other assessment methods, such as pipe wall loss, dents, and cracking.
25
See: Comprehensive Study to Understand Longitudinal ERW Seam Research & Development study task reports: Battelle Final Reports (“Battelle's Experience with ERW and Flash Weld Seam Failures: Causes and Implications”—Task 1.4), Report No. 13-002 (“Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams”—Subtask 2.4), Report No. 13-021 (“Predicting Times to Failure for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue”—Subtask 2.5), and “Final Summary Report and Recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1”—Task 4.5), which can be found online at:
https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
In this final rule, PHMSA is addressing data gaps and increasing the quality of data collected by expanding the reporting requirements to cover both gathering and gravity lines and requiring that all lines in HCAs be piggable for a better understanding of pipeline characteristics. The final rule will also require operators to fully integrate their pipeline data across all data sources to close any remaining gaps.
Looking at Risk Beyond HCAs
In addition to improving IM programs for the pipe that they already cover, PHMSA understands the importance of carefully reconsidering the scope of the areas covered by IM requirements. While PHMSA's hazardous liquid IM program manages risks primarily by focusing oversight on areas with the greatest population density and environmental sensitivity, it is imperative to protect the safety of environmental resources and communities throughout the country. The changing landscape of production, consumption, and product movement merits a fresh look at the current scope of IM coverage.
The current definition of an HCA uses Census Bureau definitions of urbanized areas or areas with a concentrated population.
26
The HCA definition also encompasses “unusually sensitive areas,” including drinking water or ecological resource areas and commercially navigable waterways. However, liquid spills, even outside HCAs, can result in environmental damage necessitating clean up, restoration costs, and lost use and non-use values. If operators do not periodically assess and repair their pipelines, liquid spills are more likely to occur. In fact, devastating incidents have occurred outside of HCAs in rural areas where populations are sparse, and operators have not been required to assess their lines as frequently as lines covered by IM. Per PHMSA's databases, between 2010 and 2017, significant incidents at hazardous liquid facilities accounted for over 993,097 barrels spilled, 24 injuries, and 10 fatalities. Out of those, over 702,091 barrels spilled, 10 injuries, and four fatalities occurred in non-HCA areas.
27
These data show that ruptures with the potential to affect populations, the environment, or commerce, can occur anywhere on the Nation's pipeline system.
26
Specifically, § 195.450 states that a
high population area
is an urban area, as defined and delineated by the Census Bureau, that contains 50,000 or more people and has a population density of at least 1,000 people per square mile, and an
other populated area
is a place, as defined and delineated by the Census Bureau, that contains a concentrated population, such as an incorporated or unincorporated city, town, village, or other designated residential or commercial area.
27
PHMSA Hazardous Liquid Accident Reports.
https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
If constant improvement and zero incidents are goals for pipeline operators,
28
extending and prioritizing IM assessments and principles to all parts of pipeline networks is an effective way to achieve those goals. Extending IM assessments and principles to non-HCAs will help clarify vulnerabilities and prioritize improvements, and this final rule takes important steps towards developing that approach and will lead operators to gather valuable information they may not have collected if regulations were not in place.
28
Major trade associations, including API and INGAA, have publicly committed to a goal of zero incidents. See:
https://www.api.org/oil-and-natural-gas/wells-to-consumer/transporting-oil-natural-gas/pipeline/pipeline-safety
and
https://www.ingaa.org/File.aspx?id=20463 for more details.
In this final rule, PHMSA is requiring operators to assess onshore, piggable pipelines outside of HCAs periodically using ILI or other technology, if appropriate, to detect (and remediate) anomalies in all locations within their pipeline systems. PHMSA is providing operators with deadlines to verify their segment analyses to identify any new HCAs and implement the appropriate actions. These changes would ensure the remediation of anomalous conditions that could potentially impact people, property, or the environment, while at the same time allowing operators to allocate their resources based on pipeline risks and the vulnerability of surrounding areas.
Recent Developments in Hazardous Liquid Pipeline Safety Regulation
On October 18, 2010, PHMSA posed a series of questions to the public in the context of an ANPRM titled “Pipeline Safety: Safety of On-Shore Hazardous Liquid Pipelines” (75 FR 63774). In that document, PHMSA sought comments on several proposed changes to part 195, including: (1) The scope of part 195 and existing regulatory exceptions, (2) Criteria for designation of HCAs, (3) Leak detection and emergency flow restricting devices, (4) Valve spacing, (5) Repair criteria outside of HCAs, and (6) Stress corrosion cracking. The questions in this ANPRM considered topics relating to the statutory mandates; the post-Marshall, MI, NTSB and GAO recommendations; and other pipeline safety mandates. Twenty-one organizations and individuals submitted comments in response to the ANPRM.
PHMSA reviewed the received comments, the 2011 Pipeline Safety Act,
and the NTSB and GAO recommendations, and responded in the subsequent NPRM published on October 13, 2015, (80 FR 61609). In summary, the NPRM addressed the following areas: (1) Reporting requirements for gravity lines, (2) Reporting requirements for gathering lines, (3) Inspections of pipelines following extreme weather events and natural disasters, (4) Periodic assessments of pipelines not subject to IM, (5) Repair criteria, (6) Expanded use of leak detection systems, (7) Increased use of in-line inspection tools, and (8) Clarifying other requirements. A summary of comments and responses to those comments are provided later in the document. The ANPRM and NPRM may be viewed at
http://www.regulations.gov
by searching for Docket No. PHMSA-2010-0229.
B. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011
After the issuance of the ANPRM on October 18, 2010, the 2011 Pipeline Safety Act included several statutory requirements related directly to the topics being considered in the ANPRM. The related topics and statutory citations that PHMSA considered within the context of this rulemaking include, but are not limited to:
• Section 5(f)—Requires, if appropriate, regulations issued by the Secretary to expand integrity management system requirements, or elements thereof, beyond high-consequence areas. These regulations are to be dependent on an evaluation and report of whether integrity management system requirements, or elements thereof, should be expanded beyond high-consequence areas;
• Section 8—Requires, if appropriate, regulations regarding leak detection on hazardous liquid pipelines and establishing leak detection standards. These regulations are to be dependent on a report on the analysis of the technical limitations of current leak detection systems, including the ability of the systems to detect ruptures and small leaks that are ongoing or intermittent, and what can be done to foster development of better technologies, and an analysis of the practicability of establishing technically, operationally, and economically feasible standards for the capability of such systems to detect leaks, and the safety benefits and adverse consequences of requiring operators to use leak detection systems;
• Section 14—Permits PHMSA to issue regulations for pipelines transporting non-petroleum fuels, such as biofuels;
• Section 21—Requires a review on the regulation of Gas (and Hazardous Liquid) Gathering Lines and the issuance of further regulations, if appropriate; and
• Section 29—Requires that operators consider seismicity when evaluating pipeline threats.
C. National Transportation Safety Board Recommendation
On July 10, 2012, shortly after the 2011 Pipeline Safety Act was passed, the NTSB issued its accident investigation report on the Marshall, MI, accident. In it, the NTSB made additional recommendations to update the hazardous liquid pipeline regulations. Pertaining directly to this rule, the NTSB issued recommendation P-12-04, which addressed the “discovery of condition” as follows:
• NTSB Recommendation P-12-4:
“Revise Title 49 Code of Federal Regulations 195.452(h)(2), the `discovery of condition,' to require, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, that pipeline operators notify the Pipeline and Hazardous Materials Safety Administration and provide an expected date when adequate information will become available.”
D. Summary of Each Topic
This final rule amends the Federal Pipeline Safety Regulations to address the following topics. Details of the changes in this rule are discussed in this document in Section IV, “Analysis of Comments and PHMSA Response,” and Section V, “Section-by-Section Analysis.”
(1) Extend Certain Reporting Requirements to Certain Gravity and Rural Hazardous Liquid Gathering Lines
Gravity lines are pipelines that carry product by means of gravity and are currently exempt from PHMSA regulations. Many gravity lines are short and within tank farms or other pipeline facilities; however, some gravity lines are longer and can build up large amounts of pressure. Further, certain gravity lines may have significant elevation changes, which can lead to serious consequences in the event of a release.
For PHMSA to effectively analyze the safety performance and risk of gravity lines, PHMSA needs basic data about those pipelines. The agency has the statutory authority to gather data for all gravity lines (49 U.S.C. 60117(b)). Accordingly, PHMSA is amending the Pipeline Safety Regulations (PSR) to require that the operators of certain gravity lines comply with requirements for submitting annual, safety-related condition, and incident reports. PHMSA estimates that, at most, five hazardous liquid pipeline operators will be affected. Based on comments to the ANPRM from the American Petroleum Institute and the Association of Oil Pipelines (API-AOPL), 3 operators have approximately 17 miles of gravity-fed pipelines. PHMSA estimated that proportionally 5 operators would have 28 miles of gravity-fed pipelines.
PHMSA is also amending the PSR to extend the annual, accident, and safety-related condition reporting requirements of part 195 to all hazardous liquid gathering lines. The Hazardous Liquid Pipeline Safety Act of 1979 (Pub. L. 96-129) did not mandate the regulation of rural gathering lines because at that time they were not thought to present a significant enough risk to public safety to justify Federal regulation based on the data available at that time. However, the Pipeline Safety Act of 1992 (Pub. L. 102-508) authorized the issuance of safety standards for regulated rural gathering lines based on a consideration of certain factors and subject to certain exclusions. When PHMSA adopted the current requirements for regulated rural gathering lines, the agency made judgments in implementing those statutory provisions based on the information available at that time.
Recent data indicates, however, that PHMSA regulates less than 4,000 miles of the approximately 30,000 to 40,000 miles of onshore hazardous liquid gathering lines in the United States.
29
That means that about 90 percent of the onshore gathering line mileage is not currently subject to any minimum Federal pipeline safety standards. The NTSB has also raised concerns about the safety of hazardous liquid gathering lines in the Gulf of Mexico and its inlets,
30
which are only subject to certain inspection and reburial requirements.
29
PHMSA, “Hazardous Liquid Pipeline Miles and Tanks,”
https://hip.phmsa.dot.gov/analyticsSOAP/saw.dll?Portalpages&NQUser=PDM_WEB_USER&NQPassword=Public_Web_User1&PortalPath=%2Fshared%2FPDM%20Public%20website%2F_portal%2FPublic%20Reports&Page=Infrastructure&Action=Navigate&col1=%22PHP%20-%20Geo%20Location%22.%22State%20Name%22&val1=%22%22,
retrieved 11/20/2018.
30
Deborah Hersman, Testimony before the Subcommittee on Surface Transportation and Merchant Marine Infrastructure, Safety, and Security Committee on Commerce, Science, and Transportation, United States Senate Hearing on Ensuring the Safety of our Nation's Pipelines, Washington DC, 6/24/2010.
https://www.ntsb.gov/news/speeches/DHersman/Pages/Testimony_before_the_Subcommittee_on_Surface_Transportation_and_Merchant_Marine_Infrastructure_Safety_and_Security_Committ.aspx.
In the ANPRM, PHMSA asked whether the agency should repeal or modify any of the exceptions for hazardous liquid gathering lines. Section 195.1(a)(4)(ii) states that part 195 applies to a “regulated rural gathering line as provided in § 195.11.” PHMSA published a final rule on June 3, 2008 (73 FR 31634), that prescribed certain safety requirements for regulated rural gathering lines (
i.e.,
the filing of accident, safety-related condition, and annual reports; establishing the MOP in accordance with § 195.406; installing line markers; and establishing programs for public awareness, damage prevention, corrosion control, and operator qualification of personnel).
The June 2008 final rule did not establish safety standards for all rural hazardous liquid gathering lines. Some of those lines cannot be regulated by statute (
i.e.,
49 U.S.C. 60101(b)(2)(B) states that “the definition of “regulated gathering line” for hazardous liquid may not include a crude oil gathering line that has a nominal diameter of not more than 6 inches, is operated at low pressure, and is in a rural area that is not unusually sensitive to environmental damage”), and Congress did not remove this exemption in the 2011 Pipeline Safety Act.
PHMSA is currently statutorily limited to regulating gathering lines in HCAs and “regulated rural gathering lines,” which are defined in § 195.11 to mean onshore gathering lines in a rural area that meet certain criteria (
i.e.,
has a nominal diameter from 6
5/8
in. (168 mm) to 8
5/8
in. (219.1 mm), is in or within
1/4
mile of an unusually sensitive area as defined in § 195.6, and operates at a maximum pressure established under § 195.406). This limitation leaves gaps in the regulation of rural gathering lines not classified as regulated rural gathering lines.
Further, PHMSA currently collects no data on unregulated gathering lines. This lack of data prevents PHMSA from being able to determine whether current regulations should be applied to currently unregulated gathering lines. Therefore, in this final rule, PHMSA is requiring reporting on all hazardous liquid gathering lines and will consider, based on the nature of the data gathered, the appropriateness of additional regulatory requirements, if any, for hazardous liquid gathering lines in the future.
The final rule, however, does not address or require data collection for transportation-related flow lines until further study and cost analyses can be conducted. PHMSA notes that, per Section 12 of the 2011 Pipeline Safety Act, Congress has provided PHMSA with the authority to collect data on pipelines transporting oil off the grounds of the well where it originated and across areas not owned by the producer, regardless of the extent to which the oil has been processed, if at all. Aside from this rulemaking, PHMSA may consider collecting these data in the future. As discussed above, any decision PHMSA makes to expand its oversight of gathering lines beyond what is currently regulated will be driven by risk assessment and analysis based on evaluations of incident and accident data, data related to infrastructure, and further technological advancements such as the unconventional production practices used in shale formations.
(2) Require Inspections of Pipelines in Areas Affected by Extreme Weather and Natural Disasters
Extreme weather has been a contributing factor in several pipeline failures. For example, in 1994, flooding in Texas led to river scour and ground movement that caused the failure of eight pipelines and the release of more than 35,000 barrels of hazardous liquids into the San Jacinto River. Some of that released product also ignited, causing minor burns and other injuries to nearly 550 people according to the NTSB. In July 2011, a pipeline failure associated with river bottom scour occurred near Laurel, MT, causing the release of an estimated 1,000 barrels of crude oil into the Yellowstone River. That area had experienced extensive flooding due to warm weather causing the rapid melting of large snowpack levels in the weeks leading up to the failure. The operator estimated the cleanup costs at approximately $135 million. In January 2015, another pipeline failure caused by river bottom scour again occurred on the Yellowstone River, spilling approximately 758 barrels of crude oil into the river, causing the shutdown of nearby drinking-water intakes.
31
Additionally, on October 21, 2016, extreme localized flooding, soil erosion, and ground movement caused a release of over 1,238 barrels of gasoline into the Loyalsock Creek in Lycoming County, PA. Further, on March 20, 2018, heavy rain caused a pipeline to rupture and release 1,400 barrels of diesel fuel into Big Creek at Solitude, IN. Specifically, a girth weld on the pipeline ruptured due to land slippage caused by the saturated soil.
31
http://deq.mt.gov/Portals/112/DEQAdmin/DIR/Documents/Bridger%20Consent%20Order/Final%20Bridger%20Consent%20Order.pdf?ver=2017-02-09-121902-843.
Weather events and natural disasters that can cause river scour, soil subsidence or ground movement may subject pipelines to additional external loads, which could cause a pipeline to fail. These conditions can pose a threat to the integrity of pipeline facilities if those threats are not promptly identified and mitigated. While the existing regulations provide for design standards that consider the load that may be imposed by geological forces, events like the ones described above can quickly impact the safe operation of a pipeline and have severe consequences if not mitigated and remediated as quickly as possible.
PHMSA issued Advisory Bulletins in 2015, 2016, and 2019 to communicate the potential for damage to pipeline facilities caused by severe flooding, including actions that operators should consider taking to ensure the integrity of pipelines in the event of flooding, river scour, river channel migration, and earth movement.
32
As PHMSA has noted in a series of Advisory Bulletins, hurricanes are also capable of causing extensive damage to both offshore and inland pipelines (
e.g.,
Hurricane Ivan, September 23, 2004 (69 FR 57135); Hurricane Katrina, September 7, 2005
(70 FR 53272); Hurricane Rita, September 1, 2011 (76 FR 54531)).
32
“Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding, River Scour, and River Channel Migration,” April 9, 2015, 80 FR 19114; and January 19, 2016, 81 FR 2943. See also “Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Earth Movement and Other Geological Hazards,” May 2, 2019, 84 FR 18919.
These events demonstrate the importance of working to ensure that our Nation's waterways and the public are adequately protected from pipeline risks in the event of a natural disaster or extreme weather. PHMSA is aware that many operators perform inspections following such events; however, because it is not a requirement, some operators do not. Therefore, PHMSA is amending the PSR to require that operators commence inspection of their potentially affected assets within 72 hours after the cessation of an extreme weather event such as a hurricane, flood, landslide, earthquake, or other natural disaster that has the likelihood to damage infrastructure. PHMSA would not expect operators to comply with these provisions for weather events when, considering the physical characteristics, operating conditions, location, and prior history of the affected system, the event would not have a likelihood of damage to the pipeline. For example, extreme weather events would not include rain events that do not exceed the high-water banks of the rivers, streams or beaches in proximity to the pipeline; rain events that do not result in a landslide in the area of the pipeline; storms that do not produce winds at tropical storm or hurricane level velocities; or earthquakes that do not cause soil movement in the area of the pipeline.
Under this requirement, an operator must inspect all potentially affected pipeline facilities following these types of events to detect conditions that could adversely affect the safe operation of the pipeline. The operator must consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining whether the event necessitates an inspection as well as the appropriate method for performing the inspection. If the event creates a likelihood that there is damage to pipeline infrastructure, the operator must commence an inspection within 72 hours after the cessation of the event, defined as the point in time when the area can be safely accessed by personnel and equipment, including availability of personnel and equipment, required to perform the inspection. PHMSA has found that 72 hours is reasonable and achievable in most cases based on prior observations of extreme events. If an operator finds an adverse condition, the operator must take appropriate remedial action to ensure the safe operation of a pipeline based on the information obtained from the inspection. Such actions might include, but are not limited to:
• Reducing the operating pressure or shutting down the pipeline;
• Isolating pipelines in affected areas and performing “stand up” leak tests;
• Modifying, repairing, or replacing any damaged pipeline facilities;
• Preventing, mitigating, or eliminating any unsafe conditions in the pipeline rights-of-way;
• Performing additional patrols, depth of cover surveys, ILI or hydrostatic tests, or other inspections to confirm the condition of the pipeline and identify any imminent threats to the pipeline;
• Implementing emergency response activities with Federal, State, or local personnel; and
• Notifying affected communities of the steps that can be taken to ensure public safety.
This requirement is based on the experience of PHMSA and is expected to increase the likelihood that operators will find and respond to safety conditions more quickly.
(3) Require Assessments of Pipelines That Are Not Already Covered Under the IM Program Requirements at Least Once Every 10 Years
PHMSA is requiring that operators periodically assess onshore, piggable, hazardous liquid pipeline segments in non-HCAs. PHMSA has determined that expanding assessment requirements to these non-HCA pipeline segments will provide operators with valuable information they may not have collected if regulations were not in place. Such a requirement works to ensure prompt detection and remediation of corrosion and other deformation anomalies across the Nation, not just in populated or environmentally sensitive areas as defined by Federal regulations. There is still considerable consequence risk—regarding personal safety, environmental damage, and economic impact—of a spill in less-populated areas, into waterways not designated as “commercially navigable,” recreational areas, commercial fishing areas, and agriculturally productive areas that do not meet the definition of an HCA.
In this rulemaking, § 195.416 requires operators to assess onshore, piggable, non-HCA, hazardous liquid pipeline segments at least once every 10 years, which allows operators to prioritize assessments in HCAs over assessments in non-HCAs (the assessment period is 5 years for hazardous liquid pipeline segments that are in or can otherwise affect an HCA). The individuals who review the results of these assessments will need to be qualified by knowledge, training, and experience and will be required to consider any uncertainty in the results obtained, including ILI tool tolerance, when determining whether any conditions could adversely affect the safe operation of a pipeline. Such determinations will have to be made promptly, but no later than 180 days after an inspection, unless the operator demonstrates that the 180-day deadline is impracticable.
Operators are required to comply with the other provisions in part 195 in implementing the requirements in § 195.416. That includes having appropriate provisions for performing these periodic assessments and any resulting repairs in an operator's procedural manual (see § 195.402); adhering to the recordkeeping provisions for inspections, tests, and repairs (see § 195.404); and taking appropriate remedial action under § 195.401(b)(1), as discussed below.
Such requirements will help ensure operators obtain information necessary for the detection and remediation of corrosion and other deformation anomalies in all locations, not just HCAs. Of the many assessment methods, PHMSA has found that ILI in many cases is the most efficient and effective. Operators can perform ILIs while pipelines are in service without any interruption of product flow. Further, ILIs are non-destructive and can provide information beyond direct assessments, which can only tell whether there is exterior coating damage or corrosion, and hydrotests, which are essentially “pass” or “fail.” ILI tools, which are constantly improving, can provide accurate information on internal corrosion, external corrosion, cracks, and gouges. Additionally, there is robust guidance and documentation for the use of ILI; API and the National Association of Corrosion Engineers (NACE) have developed standards for ILIs that provide guidelines on appropriate tool selection, assessment procedures, and the qualification of personnel conducting assessments.
Currently, operators said they are performing ILI assessments on a large portion of both HCA and non-HCA pipeline mileage, even though no regulation requires them to assess mileage outside of HCAs. Reported repairs in non-HCA segments reflect this indication. PHMSA wants to best ensure that current assessment rates continue and expand to those areas not voluntarily assessed. PHMSA has determined that by adopting these amendments to the existing pipeline safety regulations, data collection will continue to improve across the entire pipeline system, and anomalies that
may have previously gone undetected in non-HCAs will be detected and repaired in a more consistent manner.
(4) Expand the Use of Leak Detection Systems for Certain Hazardous Liquid Pipelines
With respect to new hazardous liquid pipelines, PHMSA is amending § 195.134 to require that all new covered pipelines, in both HCAs and non-HCAs, have leak detection systems within 1 year after this final rule is published in the
Federal Register
, and all covered pipelines constructed prior to the rule's publication have leak detection systems within 5 years after this rule is published. Recent pipeline accidents, including related failures that occurred in 2010 on a crude oil pipeline in Salt Lake City, UT; a failure of another crude oil pipeline in Santa Barbara, CA, in 2015; a crude oil release in Belfield, ND, in 2016; and the failure of refined products lines in Dono Ana County, NM, in 2018, corroborate the significance of having an adequate means for identifying leaks in all locations along the pipeline right-of-way. PHMSA, aware of the significance of leak detection, held a 2-day workshop in Rockville, MD, on March 27-28 of 2012.
33
These workshops sought comment from the public concerning many of the issues raised in the 2010 ANPRM, including leak detection expansion. Both workshops were well attended, and PHMSA received valuable input from stakeholders on the technical gaps and challenges for future research and ways to leverage resources to achieve common objectives and reduce duplication of research programs. Participants also discussed the development of leak detection for all pipeline types and the capabilities and limitations of current leak detection technologies.
33
https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=75.
With respect to existing pipelines, part 195 currently contains mandatory leak detection requirements for only those hazardous liquid pipelines that could affect an HCA. Congress included additional requirements for leak detection systems in section 8 of the 2011 Pipeline Safety Act. That legislation requires the Secretary to submit a report to Congress, within 1 year of the enactment date, on the use of leak detection systems, including an analysis of the technical limitations and the practicability, safety benefits, and adverse consequences of establishing additional standards for the use of those systems. Congress authorized the issuance of regulations for leak detection if warranted by the findings of the report.
PHMSA publicly provided the results of the 2012 Kiefner and Associates study on leak detection systems in the pipeline industry, including the current state of technology. The study found that most leak detection technologies can be retrofitted to existing pipelines, though many operators “fear investing in leak detection systems, with potentially little benefit to show from them and no way to truly measure success in a standardized way,” resulting in leak detection being implemented “cautiously, and incrementally, on measurement and other systems that are already in place.”
34
34
Kiefner and Associates, Inc., “Final Report on Leak Detection Study-DTPH56-11-D-000001,” December 10, 2012;
http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Press%20Release%20Files/Leak%20Detection%20Study.pdf.
Based on information available to PHMSA, including post-accident reviews and the Kiefner Report, the need to expand the use of leak detection systems and strengthen the current leak detection requirements is clear. A robust leak detection system is extremely important to hazardous liquid operators because it triggers all other impact mitigation measures that an operator should plan for, including safe flow shutdown, spill containment, cleanup, and remediation. In this final rule, PHMSA is modifying § 195.444 to require a means for detecting leaks on all portions of a hazardous liquid pipeline system, including non-HCA lines, and to require that operators perform an evaluation to determine what kinds of systems must be installed to adequately protect the public, property, and the environment. The factors that must be considered during that evaluation include (but are not limited to) the characteristics and history of the affected pipeline, the capabilities of available leak detection systems, and the location of emergency response personnel. PHMSA is retaining the requirements in §§ 195.134 and 195.444 that each new computational leak detection system comply with the applicable requirements in API Recommended Practice 1130.
35
35
API RP 1130 focuses on the design, implementation, testing and operation of Computational Pipeline Monitoring (CPM) systems that use an algorithmic approach to detect hydraulic anomalies in pipeline operating parameters for hazardous liquid pipelines.
Given the difficulties identified in the Kiefner study related to leak detection performance standards, PHMSA is not making any additional changes to the regulations concerning specific leak detection system performance criteria requirements at this time. PHMSA will be studying this issue further and may make proposals concerning this topic in a later rulemaking.
(5) Increase Accommodation of In-Line Inspection Tools
In this final rule, PHMSA is amending the part 195 regulations to require that all hazardous liquid pipelines in HCAs and areas that could affect an HCA be made capable of accommodating ILI tools within 20 years, unless subject to PHMSA approval, the basic construction of a pipeline will not accommodate the passage of such a device or the operator determines it would abandon the pipeline because of the cost of complying with the amendment. Per the petition process at § 190.9, operators would be required to document these determinations and submit the documentation to PHMSA for approval.
Modern ILI tools can provide a relatively complete examination of the entire length of a pipeline, including information about threats that other assessment methods cannot always identify. ILI tools also provide superior information about incipient flaws (
i.e.,
flaws that are not yet a threat to pipeline integrity, but that could become so in the future), thereby allowing these conditions to be monitored over consecutive inspections and remediated before a pipeline failure occurs. Hydrostatic pressure testing, another well-recognized method, reveals flaws (such as wall loss and cracking flaws) that cause pipe failures at pressures that exceed actual operating conditions, but only allows operators to determine whether a required safety margin is met (
i.e.,
pass/fail) and does not provide information about the existence of anomalies that could deteriorate over time between tests. Similarly, external corrosion direct assessment (ECDA) is a form of direct assessment that can identify instances where coating damage or ineffective coatings may be affecting pipeline integrity, but operators must perform additional activities, including follow-up excavations and direct examinations, to verify the extent of that threat. ECDA also does not provide information about the internal condition of a pipe to the extent an ILI tool would.
The current regulations for the passage of ILI devices in hazardous liquid pipelines are prescribed in § 195.120, which require that new and replaced pipelines are designed to accommodate ILI tools. The basis for these requirements is a 1988 law that addressed the Secretary's authority with regard to requiring the accommodation
of ILI tools. This law required the Secretary to establish minimum Federal safety standards for the use of ILI tools, but only in newly constructed and replaced hazardous liquid pipelines (Pub. L. 100-561).
As the Research and Special Programs Administration (RSPA; a predecessor agency of PHMSA), explained in the final rule published on April 12, 1994 (59 FR 17275), that promulgated § 195.120, “the clear intent of th[at] congressional mandate [wa]s to improve an existing pipeline's piggability,” and to “require the gradual elimination of restrictions in existing hazardous liquid and carbon dioxide lines in a manner that will eventually make the lines piggable.” RSPA also noted that Congress amended the 1988 law in the Pipeline Safety Act of 1992 (Pub. L. 102-508) to require the periodic internal inspection of hazardous liquid pipelines, including with ILI tools in appropriate circumstances. In 1996, Congress passed another law further expanding the Secretary's authority to require pipeline operators to have systems that can accommodate ILI tools. In particular, Congress provided additional authority for the Secretary to require the modification of existing pipelines whose basic construction would accommodate an ILI tool to accommodate such a tool and permit internal inspection (Pub. L. 104-304). RSPA established requirements for the use of ILI tools in pipelines that could affect HCAs in a final rule published on December 1, 2000 (65 FR 75378).
Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the requirements for the passage of ILI tools to be extended to existing hazardous liquid pipeline facilities, provided the basic construction of those facilities can be modified to permit the use of smart pigs. The current requirements apply only to new hazardous liquid pipelines and to line sections where the line pipe, valves, fittings, or other components are replaced. Exceptions are also provided for certain kinds of pipeline facilities, including manifolds, piping at stations and storage facilities, piping of a size that cannot be inspected with a commercially available ILI tool, and smaller-diameter offshore pipelines.
In this final rule, PHMSA is taking steps to further facilitate the gradual elimination of pipelines that are not capable of accommodating smart pigs in accordance with the authority provided in section 60102(f)(1)(B). PHMSA is limiting the circumstances where a pipeline can be constructed without being able to accommodate a smart pig. Under the current regulation, an operator can petition the PHMSA Administrator for such an allowance for reasons of impracticability, emergencies, construction time constraints, costs, and other unforeseen construction problems. PHMSA believes that an exception should still be available for emergencies and where the basic existing construction of a pipeline makes that accommodation impracticable.
Regulations already require that new and replaced pipelines accommodate ILI tools, and many of the pipelines covered by this new rule will need to be replaced and therefore will accommodate ILI tools before the end of the 20-year implementation period. Providing industry with sufficient time to implement this provision allows the industry to prioritize retrofits and replacements based on age or other factors; it also reduces the mileage of pipeline potentially needing to be replaced before it has reached the limit of its operational life. PHMSA determined that the 20-year timeline strikes the appropriate balance between the need for upgrades with the operational challenges of making these changes.
(6) Clarify Other Requirements
In this final rule, PHMSA is also making several other clarifying changes to the regulations that are intended to improve compliance and enforcement. First, PHMSA is proposing to revise paragraph (b)(1) of § 195.452 to better harmonize this section with other parts of the current regulations. Currently, § 195.452(b)(2) requires that segments of new pipelines that could affect HCAs be identified before the pipeline begins operations, and § 195.452(d)(1) requires that baseline assessments for covered segments of new pipelines be completed by the date the pipeline begins operation. However, § 195.452(b)(1) does not require an operator to draft its IM program for a new pipeline until 1 year after the pipeline begins operation. These provisions are inconsistent, as the identification of could-affect segments and performance of baseline assessments are elements of the written IM program. PHMSA is amending the table in (b)(1) to resolve this issue by eliminating the 1-year compliance deadline for Category 3 pipelines. An operator of a new pipeline is required to develop its written IM program before the pipeline begins operation—there is no burden associated with this amendment because operators already were required to report to DOT prior to construction.
Second, as mentioned in the non-HCA assessment section, operators of both HCA lines and non-HCA lines will have equal requirements for the “discovery” of conditions, which occurs when an operator has adequate information about a condition to determine that it presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate that the 180-day period is impracticable. This could include demonstrating why such information would not be available prior to that date. If an operator believes that unique circumstances exist in a particular case that make the 180-day period impracticable, the operator must submit a notification to PHMSA and provide an expected date when adequate information will become available. The submission of such a notification, by itself, will not affect compliance determinations on whether the 180-day requirement was met. PHMSA is thereby amending the existing “discovery of condition” language at § 195.452(h)(2) in the pipeline safety regulations to reflect these changes.
A decade's worth of IM inspection experience has shown that many operators are performing inadequate information analyses (
i.e.,
they are collecting information but are not affording it sufficient consideration, or they are not promptly evaluating the information they have gathered following events that have increased risk, such as historic weather events). Ongoing data integration is one of the most important aspects of the IM program, and operators must account for interactions between threats or conditions affecting the pipeline when setting priorities for dealing with identified issues. For example, evidence of potential corrosion in an area with foreign pipeline crossings,
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nearby current interference from power lines and electrically powered transport systems, evidence of land movement or waterway channel changes that may impact pipeline integrity, and recent aerial patrol indications of excavation activity could indicate a priority for operators to reassess risk and make timely changes to their IM program to reduce that risk. Consideration of each of these factors individually would not necessarily reveal any need for priority attention. PHMSA is concerned that a major benefit to pipeline safety intended in the IM rule is not being realized
because of inadequate information analyses.
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Foreign pipelines can include other hazardous liquid, natural gas, water, sewer, or drainage pipelines.
For this reason, PHMSA is adding specificity to paragraph (g) by establishing several pipeline attributes that must be included in these analyses and requiring explicitly that operators integrate analyzed information. PHMSA is also requiring operators to consider explicitly any spatial relationships among anomalous information. PHMSA supports the use of computer-based geographic information systems (GIS) to record this information. GIS systems can be beneficial in identifying spatial relationships, but analysis is required to identify where these relationships could result in situations adverse to pipeline integrity.
Second, PHMSA is requiring operators to verify their pipeline segment identification (as HCAs or otherwise) annually by determining whether factors considered in their analysis have changed. Section 195.452(b) currently requires that operators identify each segment of their pipeline that could affect an HCA in the event of a release, but there is no explicit requirement that operators assure that their identification of covered segments remains current. As time goes by, the likelihood increases that factors considered in the original identification of covered segments may have changed. Construction activities or erosion near the pipeline could change local topography in a way that could cause product released in an accident to travel farther than initially analyzed. Changes in agricultural land use could also affect an operator's analysis of the distance released product could be expected to travel. Changes in the deployment of emergency response personnel could increase the time required to respond to a release and result in a release affecting a larger area if the original segment identification relied on emergency response in limiting the transport of released product. Therefore, PHMSA has determined that operators should periodically re-visit their initial analyses to determine whether they need updating; operators might identify new HCAs in subsequent analyses.
The change that PHMSA is adopting does not automatically require operators to re-perform their segment analyses. Rather, it requires operators to first identify the factors considered in their original analyses, determine whether those factors have changed, and consider whether any such change would likely affect the results of the original segment identification. If so, the operator is required to perform a new segment analysis to validate or change the endpoints of the segments affected by the change.
Further, Section 29 of the 2011 Pipeline Safety Act states that “[i]n identifying and evaluating all potential threats to each pipeline segment pursuant to parts 192 and 195 of title 49, Code of Federal Regulations, an operator of a pipeline facility shall consider the seismicity of the area.” While seismicity is already mentioned at several points in the IM program guidance provided in Appendix C of 49 CFR part 195, PHMSA is amending the PSR to further comply with Congress's directive by including an explicit reference to seismicity in the list of risk factors that must be considered in establishing assessment schedules (§ 195.452(e)), performing information analyses (§ 195.452(g)), and implementing preventive and mitigative measures (§ 195.452(i)) under the IM requirements.
Finally, the PIPES Act of 2016 contained two sections PHMSA identified as self-executing and that PHMSA could incorporate into the PSR without notice of public comment or previous proposed rulemaking. Section 14 of the PIPES Act of 2016 requires operators of hazardous liquid pipeline facilities to provide safety data sheets to the designated Federal On-Scene Coordinator and appropriate State and local emergency responders within 6 hours of a telephonic or electronic notice of the accident to the National Response Center. Section 25 of the PIPES Act of 2016 requires operators of underwater hazardous liquid pipeline facilities in HCAs that are not offshore pipeline facilities and that any portion of which are located at depths greater than 150 feet below the surface of the water to complete ILI assessments appropriate to the integrity threats specific to those pipelines no less frequently than once every 12 months. Furthermore, section 25 of the PIPES Act of 2016 requires that operators use pipeline route surveys, depth of cover surveys, pressure tests, ECDAs, or other technology that the operator demonstrates can further the understanding of the condition of the pipeline facility, as necessary to assess the integrity of those pipelines on a schedule based on the risk that the pipeline facility poses to the HCA in which the facility is located. PHMSA is amending the PSR by codifying the statutory language of these provisions.
III. Liquid Pipeline Advisory Committee Recommendations
The Liquid Pipeline Advisory Committee (LPAC) is a statutorily mandated advisory committee that advises PHMSA on proposed safety standards, risk assessments, and safety policies for hazardous liquid pipelines. The Pipeline Advisory Committees (PAC) were established under the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C. App. 1-16) and the Federal Pipeline Safety Statutes (49 U.S.C. Chap. 601). Each committee consists of 15 members, with membership divided among the Federal and State agencies, the regulated industry, and the public.
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The PACs advise PHMSA on the technical feasibility, practicability, and cost-effectiveness of each proposed pipeline safety standard.
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Members from the general public include two members who have education, background, or experience in environmental protection or public safety. At least one of the five members must have education, background, or experience in risk assessment and cost-benefit analysis. No public member can have a significant interest in the pipeline, petroleum, or gas industry. At least one of the public members must have no financial interests in the pipeline, petroleum, or natural gas industries. See section 12(d), “Liquid Pipeline Advisory Committee Charter—October 2018 to October 2020,”
https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/standards-rulemaking/pipeline/4396/lpac-charter-final-102418.pdf
.
On February 1, 2016, the LPAC met at the Hilton Arlington in Arlington, VA, to discuss this rulemaking. During the meeting, the LPAC considered the specific regulatory proposals of the NPRM and discussed various comments to the NPRM proposed by the pipeline industry, public interest groups, and government entities. To assist the LPAC in their deliberations, PHMSA presented a description and summary of the eight major issues in the NPRM and the comments received on those issues, as well as some sample regulatory text changes to foster discussion.
During the meeting, eight votes were taken: One vote on each major topic of the NPRM. For each major topic of the rule, the LPAC came to a consensus decision that the provisions of the rulemaking would be technically feasible, reasonable, cost-effective, and practicable, provided PHMSA made certain changes. The order the topics were discussed in, the changes the committee agreed upon, and the corresponding vote counts were as follows:
Gravity lines: In the NPRM, PHMSA proposed to subject gravity lines to reporting requirements for data gathering purposes, as there are currently no regulatory requirements for these lines and little data for potential regulatory decision-making purposes. The LPAC voted 9-1 that the NPRM, with respect to gravity lines, as published in the
Federal Register
, and the draft regulatory evaluation were technically feasible, reasonable, cost-
effective, and practicable, if PHMSA made the following changes: Modify (shorten) the reporting form, require no National Pipeline Mapping System (NPMS) submissions, provide reporting exceptions for lower-risk pipelines (for example, intra-plant lines), allow a1-year implementation period for annual reporting, and allow a 6-month implementation period for accident reporting.
The LPAC agreed that PHMSA should modify the reporting forms to gather only the data necessary for PHMSA to determine whether these lines need to be regulated in the future. LPAC members representing the pipeline industry requested that PHMSA consider reporting exceptions for lower-risk pipelines, such as intra-plant gravity lines. The same members also requested that any reporting requirements for gravity lines not include NPMS submissions, asserting that incorporating that data into a mapping system would be costly compared to the amount of risk these lines pose. LPAC members representing the public did not support these recommendations. They noted that as gravity line mileage is already limited, and the reporting requirement is only being used to gather data, excepting a subset of this limited mileage from reporting requirements would be counter-productive. Further, the public members strongly suggested that NPMS submissions be included for gravity lines, as location could be an important data point PHMSA could collect.
Gathering lines: In the NPRM, PHMSA proposed to collect information on all gathering lines and subject regulated gathering lines to periodic assessment and leak detection requirements. Much of the LPAC's discussion for gathering lines mirrored the topics discussed regarding gravity lines. During the discussion, PHMSA noted that under 49 U.S.C. 60132, only transmission-pipeline operators are required to submit mapping data for use in the NPMS. As a result, the LPAC removed language concerning NPMS submissions by gathering line operators. Ultimately, the committee voted 10-0 that the NPRM regarding gathering lines, as published in the
Federal Register
, and the draft regulatory evaluation are technically feasible, reasonable, cost effective, and practicable if PHMSA made the following changes: modify (shorten) the reporting form, allow a 1-year implementation period for annual reporting, and allow a 6-month implementation period for accident reporting.
Leak detection: In the NPRM, PHMSA proposed that all hazardous liquid pipelines transporting liquid in single phase (without gas in the liquid) include a leak detection system and have it operate and maintained per specified standards. Many commenters noted that there was no implementation period for PHMSA's proposed leak detection requirements. The LPAC proposed a 5-year implementation period for leak detection systems on existing lines and a 1-year implementation period for leak detection systems on new lines. The LPAC also recommended PHMSA not apply leak detection requirements to offshore gathering lines due to various technical challenges associated with flow monitoring and leak detecting. The LPAC voted unanimously that the NPRM, regarding leak detection, as published in the
Federal Register
, and the draft regulatory evaluation are technically feasible, reasonable, cost effective, and practicable if PHMSA made the following changes: Allow a5-year implementation period for existing pipelines, allow a 1-year implementation period for new pipelines, and exempt offshore gathering lines from the leak detection requirements.
Clarifying other requirements: In the NPRM, PHMSA proposed to revise the IM requirements to specify additional pipeline attributes for operators to analyze when evaluating the integrity of pipelines in HCAs; to require the integration of all sources of information, including spatial relationships, when determining pipeline integrity; to require operators have a written IM plan prior to a specific pipeline's operation; and to require annual HCA segment identification and verification. During the meeting, the LPAC primarily discussed whether there should be a timeframe for implementing the specific data attributes and integrating all sources of information when determining pipeline integrity. Committee members representing the public argued that, because these provisions were clarifications of existing requirements, operators should have already been performing many of these actions, and an extended implementation period would not make sense. Several members who represented the public pushed for a1-year implementation period. LPAC members representing the industry noted that developing data integration systems to a level that PHMSA would like could be expensive and time-consuming, possibly taking several years. Further, LPAC members representing industry noted that while a lot of data integration is already occurring in operators' IM programs, it could take some operators an extended period to adjust their software to incorporate all the items in PHMSA's proposed list. LPAC members representing industry proposed PHMSA allow operators a 3-year deadline from the rule's issuance to fully implement the proposed list of attributes. Ultimately, the LPAC voted 7-3 that the NPRM, regarding the data integration requirements, as published in the
Federal Register
, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable if operators begin implementing the requirements upon the rule's issuance with a deadline of 3 years for full implementation.
Inspections following extreme weather events: In the NPRM, PHMSA proposed requiring operators to perform inspections of pipelines that may have been affected by natural disasters or extreme weather events within 72 hours after the cessation of the event to better ensure that no conditions exist that could adversely affect the safe operation of that pipeline. The LPAC voted unanimously that the NPRM, as it relates to inspections following extreme weather events, as published in the
Federal Register
, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable, if PHMSA included the term “landslide” as a specific extreme weather event and qualify the term “other similar events” as it pertains to triggering the requirements of performing an inspection by tying the term to those events “that the operator determines to have a significant likelihood of damage to infrastructure.” Further, the LPAC recommended PHMSA clarify that the purpose of the inspection is to “detect conditions that could adversely affect the safe operation of the pipeline” and not “ensure that no conditions exist that could adversely affect the safe operation of the pipeline.” The LPAC also recommended PHMSA clarify that the inspection per these requirements would be an initial inspection, conducted within 72 hours of the area being safely accessible by personnel and equipment, to determine if any damage has occurred and whether additional assessments are necessary.
Periodic assessments in non-HCAs: In the NPRM, PHMSA proposed to require operators to assess non-HCA pipelines at least once every 10 years using ILI or other equivalent methods. The LPAC agreed on this requirement and wanted to ensure it was not more restrictive than the requirement for assessing lines
in HCAs. The LPAC voted unanimously that, regarding the provisions of the NPRM related to periodic assessments, the NPRM, as published in the
Federal Register
, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable if PHMSA ensured that the periodic assessment requirement applies to regulated pipelines that are not currently subject to the IM requirements at § 195.452, and made the methods operators use to assess non-HCA pipelines consistent with the methods operators use to assess HCA pipelines and allow operators to choose the appropriate tool for the appropriate threat.
Making all pipelines in HCAs able to accommodate ILI tools: In the NPRM, PHMSA proposed to require all pipelines in HCAs be capable of accommodating ILI tools within 20 years. The LPAC voted 9-1 that, regarding the provision of the rule requiring the use of ILI tools in all HCAs, the NPRM, as published in the
Federal Register
, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable provided PHMSA insert a phrase stating that an operator can also file a petition if it determines it would abandon or otherwise shut down a pipeline because of the compliance cost of the provision.
Repair criteria: In the NPRM, PHMSA proposed to make various changes to the existing repair criteria to reflect an improved prioritization of repairing abnormal pipeline conditions. The LPAC voted unanimously that, with regard to repair criteria for both HCA and non-HCA pipeline segments, the NPRM, as published in the
Federal Register
, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable if PHMSA considers allowing recognized engineering analyses to determine whether applicable dents and cracks are non-injurious and need no further investigation, and gives “full and equal consideration to the industry comments that were discussed [at the meeting].”
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Those hazardous liquid industry comments provided at the LPAC meeting for PHMSA to consider were as follows:
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At the Advisory Committee meeting, member Craig Pierson, representing the pipeline industry, submitted for the members' consideration a written recommendation regarding repair criteria anomalies.
Repair Criteria for both HCA and non-HCA pipeline segments:
1. Regarding “Immediate” conditions:
a. Include crack anomalies greater than 70 percent of wall thickness or the tool's maximum measurable depth if it is less than 70 percent;
b. Remove specific references to “any indication” of significant stress corrosion cracking (SCC) and selective seam weld corrosion (SSWC).
c. Allow for an industry recognized engineering analysis to determine those dents that are non-injurious and require no further investigation; and
d. Instead of addressing cracks and SSWC specifically, expand the various accepted failure models that identify an anomaly that does not have the remaining strength to exceed 1.1 times the MOP at the location of the anomaly, which should also include injurious cracks and SSWC.
2. Regarding 270-day conditions for HCAs and 18-month conditions for non-HCAs:
a. Revise the existing reference to cracks and include crack anomalies greater than 50 percent of wall thickness or the tool's maximum measurable depth if it is less than 50 percent;
b. Allow for an industry recognized engineering analysis to determine those dents that are non-injurious and require no further investigation; and
c. To address cracks and SSWC, expand the various accepted failure models that identify an anomaly that does not have the remaining strength to exceed 1.25 times the MOP at the location of the anomaly.
3. Add a “Scheduled condition:”
a. Anomalies that do not meet the 270-day or the 18-month repair criteria but have the possibility to grow before the next segment inspection are subject to predictive modeling of remaining strength; and
b. Investigate in the years prior to the next inspection if the predicted burst pressure is less than 1.1 times the MOP at the location of the anomaly.
In this final rule, PHMSA considered the recommendations of the LPAC and adopted them as PHMSA deemed appropriate. To summarize, the major changes PHMSA has made in this rule that deviate from the LPAC recommendations are as follows: (1) PHMSA has added an additional requirement that operators notify the appropriate PHMSA Region Director when they are unable to inspect infrastructure impacted by extreme weather within 72 hours; (2) PHMSA has removed the phrase “other similar event” from the extreme weather inspection requirements; (3) PHMSA has changed a word in the regulatory text for non-HCA assessments, to provide that operators must assess “line pipe” (instead of “pipelines defined under § 195.1”) not subject to the IM requirements at § 195.452; (4) PHMSA has restricted the non-HCA periodic assessment requirement to onshore, piggable, line pipe only, which removed the proposed assessment requirement for covered offshore lines and for regulated rural gathering lines; (5) PHMSA has removed the leak detection requirement for rural regulated gathering lines at § 195.11; and (6) PHMSA declined to move forward with the repair criteria and timelines as proposed for both HCAs and non-HCAs and has, instead, reverted to the existing non-IM repair language in § 195.401(b)(1) and the existing IM repair language at § 195.452(h). In the comments section, for each major topic of this final rule, PHMSA broadly discusses specific amendments proposed during the meeting and the corresponding discussion. PHMSA also discusses the instances where PHMSA did not adopt the specific recommendations of the LPAC.
IV. Analysis of Comments and PHMSA Response
On October 13, 2015, PHMSA published an NPRM (80 FR 61609) proposing several amendments to 49 CFR part 195. The NPRM proposed amendments addressing the following areas:
(1) Reporting requirements for gravity lines.
(2) Reporting requirements for gathering lines.
(3) Inspections of pipelines following extreme weather events.
(4) Periodic assessments of pipelines not subject to IM.
(5) Repair criteria.
(6) Expanded use of leak detection systems.
(7) Increased use of in-line inspection tools.
(8) Clarifying other requirements.
Seventy organizations and individuals submitted comments in response to the NPRM, including public representatives, private citizens, industry service providers, individual pipeline operators, and trade associations representing pipeline operators. Some of the comments PHMSA received in response to the NPRM were comments beyond the scope or authority of the proposed regulations. The absence of amendments in this proceeding involving other pipeline safety issues (including several topics listed in the ANPRM) does not mean that PHMSA determined additional rules or amendments on other issues are not needed. Such issues may be the subject of other existing
rulemaking proceedings or future rulemaking proceedings.
The remaining comments reflect a wide variety of views on the merits of particular sections of the NPRM. The substantive comments received on the NPRM are organized by topic below and are discussed in the appropriate section with PHMSA's response and resolution to those comments.
A. Reporting Requirements for Gravity Lines
1. PHMSA's Proposal
Gravity lines, pipelines that carry product by means of gravity, are currently exempt from PHMSA regulations. Many gravity lines are short and within tank farms or other pipeline facilities; however, some gravity lines are longer and can build up large amounts of pressure because they traverse areas with significant elevation changes, which could have significant consequences in the event of a release.
For PHMSA to effectively analyze gravity line safety performance and risk, PHMSA needs basic data about those pipelines. PHMSA has the statutory authority to gather data for all pipelines (49 U.S.C. 60117(b)), and that authority was not affected by any of the provisions in the 2011 Pipeline Safety Act. Accordingly, PHMSA proposed to add § 195.1(a)(5) to require that the operators of all gravity lines comply with requirements for submitting annual, safety-related condition, and incident reports.
2. Summary of Public Comment
PHMSA received comments from trade organizations, citizen groups, and individuals on the scope and format of the reporting requirements. To reduce the reporting burden, industry representatives (API-AOPL, the GPA Midstream Association (GPA) and Energy Transfer Partners (ETP)) recommended that PHMSA create a new abbreviated annual report with input from operators to separate the reporting of pipeline data for regulated pipelines and those not currently subject to 49 CFR part 195. Specifically, API noted that pipelines not currently covered under part 195 (gravity lines) are not subject to operator qualification, control room management, leak detection, and HCA requirements, and therefore those areas should be excluded from reporting. The Texas Pipeline Association requested that reporting be limited to annual and incident reports, a suggestion also supported by the ETP. API-AOPL commented that industry experience indicates that the cost and time burdens associated with the reporting requirements for gravity lines exceeded the cost estimate cited by PHMSA in the NPRM.
The Environmental Defense Center requested that the reporting requirements include the location, operation, condition, and history of the pipelines, and multiple citizen groups requested that GIS mapping be required for pipelines. In addition to GIS mapping information, the Western Organization of Resource Councils and the Alliance for Great Lakes et al. recommended that PHMSA also require pipeline operators to meet minimum safety standards for all pipelines, a comment echoed by numerous other citizen groups and individuals. These commenters also requested that inspection reports, notices of violation, and similar documents be made readily available to the public.
Trade organizations made additional comments regarding the applicability and implementation timeline for the reporting requirements. API-AOPL and other industry representatives requested that the data collection be narrowed, such that it would apply only to those gravity lines that could present a risk to the public, which: (1) Travel outside of facility boundaries for at least 1 mile, (2) operate at a specified minimum yield strength level of twenty percent or greater, and (3) are not otherwise exempted in § 195.1(b). On this same basis, Denbury Resources added a request to exempt CO
2
pipelines. Finally, API-AOPL requested that PHMSA extend the proposed implementation period to 1 year after the effective date of the final rule.
During the February 1, 2016, meeting, the LPAC recommended that PHMSA modify the NPRM to (1) require reporting from gravity pipeline operators using streamlined forms, (2) not require integration of gravity lines into NPMS, (3) provide exceptions for lower-risk pipelines (
e.g.,
intra-plant lines), and (4) set a 1-year implementation period for the annual reporting requirement and a 6-month implementation period for the accident reporting requirement.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters regarding the scope and timing of the requirements for gravity lines. After considering these comments and LPAC input, PHMSA is modifying the exception for gravity lines at § 195.1 as it pertains to reporting requirements. This change will allow PHMSA to require operators of gravity lines to report information annually, starting 1 year from the rule's effective date, and to report accidents and safety-related conditions starting 6 months from the rule's effective date. PHMSA considers these deadlines practicable in view of the limited scope of the information requested for these lines.
PHMSA focused collection on those data elements that will enable the agency to assess the risk posed by these lines and determine whether requirements that are more stringent are warranted in the future. To facilitate reporting and address commenters' concerns about providing clear instructions on data elements that operators must fill out for gravity lines, PHMSA has modified its existing reporting form to provide clear instructions, including skip patterns, for relevant sections. In response to API's specific suggestions regarding operator qualification, control room management, leak detection, and HCA reporting, these revisions exempted gravity lines from any fields that involve “Could Affect HCA” data. This targeting of the information collection request will reduce the burden associated with providing the information, as was requested by commenters. PHMSA recognizes that operators who are not currently submitting data will have to register with PHMSA to obtain an Operator Identification Number (OPID) under § 195.64, but the associated burden is minimal; PHMSA estimates that fewer than 10 operators would need to submit information for gravity lines. PHMSA estimates the total reporting burden at 66 hours per year, on average.
During the LPAC meeting, the committee reached consensus on requiring gravity line operators to report safety-related conditions. These conditions could lead to significant consequences and are important data points for PHMSA to determine whether additional gravity line regulations may be necessary in the future.
As explained previously, the purpose of the information collection is to support evaluation of the risk posed by gravity lines on the public. With this goal in mind, PHMSA is receptive to commenters who noted that pipelines located within the confines of a facility or in close proximity (within 1 mile) to a facility and do not cross a waterway currently used for commercial navigation pose a lower risk to the public and the environment. PHMSA has decided to exempt these lines from the reporting requirements. The language for this exception is similar to the language of an existing exception for low-stress pipelines at § 195.1.
Further safety-related condition reporting exceptions at § 195.55(b) will help minimize the reporting burdens for
operators. In the NPRM, PHMSA did not intend to propose requiring mapping of gravity lines at this time and therefore is finalizing the rule without this requirement. PHMSA understands commenters' concerns that gravity line NPMS data submissions could be costly and burdensome. However, as PHMSA is not requiring these submissions as a part of this final rule's reporting requirements, the cost and burden of these submissions were not and should not be considered as a part of the cost-benefit analysis. If PHMSA determines, following analysis of the data received on gravity lines, that mapping of these lines or expanding reporting applicability to lines exempted in this final rule would be beneficial to improve public safety or protect the environment, it may consider additional requirements in a future rulemaking.
Similarly, PHMSA is not requiring telephonic reporting of accidents involving gravity lines at this time but may reassess this requirement in a future rulemaking if analyses of the data suggest that doing so would enhance prevention, preparedness, and response to hazardous liquid releases from gravity lines.
Comments relating to public reporting and the reporting of specific pipeline attributes discussed issues that PHMSA did not propose in the NPRM and are therefore out-of-scope and could not be considered for this rulemaking. Similarly, comments discussing minimum safety standards be applied to gravity lines were also out-of-scope because they requested more stringent requirements than what PHMSA proposed in the NPRM.
B. Reporting Requirements for Gathering Lines
1. PHMSA's Proposal
In the NPRM, PHMSA also proposed to extend the reporting requirements of 49 CFR part 195 to all hazardous liquid gathering lines. Recent data indicates that PHMSA regulates less than 4,000 miles of the approximately 30,000 to 40,000 miles of onshore hazardous liquid gathering lines in the United States.
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That means that about 90 percent of the onshore gathering line mileage is not currently subject to any minimum Federal pipeline safety standards. Congress also ordered the review of existing State and Federal regulations for hazardous liquid gathering lines in the Pipeline Safety Act of 2011, to prepare a report on whether any of the existing exceptions for these lines should be modified or repealed, and to determine whether hazardous liquid gathering lines located offshore or in the inlets of the Gulf of Mexico should be subjected to the same safety standards as all other hazardous liquid gathering lines. Based on the study titled “Review of Existing Federal and State Regulations for Gas and Hazardous Liquid Gathering Lines”
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that was performed by the Oak Ridge National Laboratory and published on May 8, 2015, PHMSA proposed additional regulations to help ensure the safety of hazardous liquid gathering lines.
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GAO-12-388: “Pipeline Safety: Collecting Data and Sharing Information on Federally Unregulated Gathering Pipelines Could Help Enhance Safety,” March 2012, pg. 7;
http://www.gao.gov/assets/590/589514.pdf
.
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http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/report_to_congress_on_gathering_lines.pdf
.
For PHMSA to effectively analyze safety performance and risk of gathering lines, we need basic data about those pipelines. PHMSA has statutory authority to gather data for all gathering lines (49 U.S.C. 60117(b)). Accordingly, PHMSA proposed to add § 195.1(a)(5) to require that the operators of all gathering lines (whether onshore, offshore, regulated, or unregulated) comply with requirements for submitting annual, safety-related condition, and incident reports.
2. Summary of Public Comment
PHMSA received comments on hazardous liquid gathering lines that echoed those for gravity lines. Citizen groups and individuals again requested that the requirements for these lines include GIS mapping and minimum safety standards; that the reporting include location, operation, condition, and history; and that inspection reports, notices of violation, and similar documents be made available to the public. Trade organizations again commented on compliance costs and recommended that the reporting requirement be limited to annual and incident reports with an abbreviated form, have a phase-in implementation over 1 year, and exempt lower-risk pipelines. Specifically, API noted again that, as rural gathering lines are not subject to operator qualification, control room management, leak detection, and HCA requirements, those areas should be excluded from reporting.
Trade organizations also made several additional recommendations related to the scope of applicability, the scope of requirements, and implementation. The Independent Petroleum Association of America (IPAA) commented that PHMSA exceeds its authority in requiring operators of gathering lines to submit annual, safety-related condition, and incident reports. The GPA and other organizations noted that PHMSA did not fully account for the burden increase and cost of the reporting requirements for gathering lines in the preliminary RIA. The GPA recommended that information requested under § 195.61 and § 195.64 be excluded from data collection. Numerous trade organizations identified accident reporting for these lines as costly and duplicative. The Louisiana Mid-Continent Oil and Gas Association (LMOGA) commented that most, if not all accident information requested for gathering lines is already required to be reported under other existing Federal and State regulations, and the GPA recommended that information collected through an abbreviated Annual Report could be paired with Accident Reporting on Form F 7000-1 (rev 7-2014). LMOGA also recommended that mapping of gathering lines not be required because of incidental environmental impacts on wetlands, permitting, and resource costs for teams to enter wetlands and track these lines.
The Offshore Operators Committee (OOC) requested that PHMSA make clear in the final rule that the agency's intent is not to have the proposed reporting requirements apply to gathering lines offshore within State waters that are currently not regulated by PHMSA or the Bureau of Safety and Environmental Enforcement (BSEE) or to other gathering lines that are regulated by BSEE.
Finally, commenters asked for implementation periods that ranged from 1 year (API-AOPL) to 10 years (Enterprise Products Partners) after the effective date of the rule.
During the meeting on February 1, 2016, the LPAC recommended that PHMSA modify the NPRM to (1) require reporting from gathering pipeline operators using streamlined forms and (2) set a 1-year implementation period for the annual reporting requirement and a 6-month implementation period for the accident reporting requirement.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters regarding the scope and timing of the requirements for gathering lines. Regarding the comment that the proposed reporting requirement of § 195.1(a)(5) exceeds PHMSA's statutory authority, PHMSA notes that the Federal Pipeline Safety Statutes state, in relevant part, “[t]he Secretary may require owners and operators of gathering lines to provide the Secretary
information pertinent to the Secretary's ability to make a determination as to whether and to what extent to regulate gathering lines.” 49 U.S.C. 60117(b). PHMSA has determined that, in order to decide whether and to what extent to regulate gathering lines, as permitted by Congress, PHMSA requires pertinent information about those pipelines, including elements of the data contained in annual, safety-related condition, and incident reports. With this reporting requirement, PHMSA is not encroaching on the States' regulatory authority, nor creating new jurisdiction. Rather, PHMSA is collecting pertinent information to determine if future regulation is necessary for the statutory purpose of promoting pipeline safety.
More specifically, PHMSA is collecting items in the annual report that primarily include the mileage count for those gathering lines currently unregulated, the diameters of those lines, and whether they are operating at greater or less than 20 percent SMYS. The goal of collecting this specific information is to provide PHMSA with a better understanding of the scope of the Nation's gathering pipeline infrastructure. As previously stated, recent data indicates PHMSA regulates only approximately 4,000 miles of the estimated 30,000 to 40,000 miles of onshore hazardous liquid gathering lines in the United States. That means that as much as 90 percent of the onshore gathering line mileage is not currently subject to any minimum Federal pipeline safety standards, and little is known about that mileage.
In requiring accident reports for otherwise unregulated gathering lines, PHMSA is collecting data that includes the underlying cause for the accident, where the accident was located and how it was reported to the operator, and a value for any property damage caused. This data will be essential to understanding and managing risk. PHMSA uses information reported by pipeline operators to identify trends, provide performance measures, and understand the causes and consequences of pipeline incidents. Reporting requirements are in place for all pipelines except for the gravity and gathering pipelines addressed by this final rule. Each year, the U.S. Coast Guard's National Response Center receives several notifications of hazardous liquid releases involving “gathering lines,” but details on these releases are not sufficient to understand the factors that contributed to the releases and the damages, or to evaluate whether the lines involved are gathering lines over which PHMSA has jurisdiction.
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The reporting requirements for gathering lines will help PHMSA have a more complete understanding of the risks these lines may pose.
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NRC data for 2010 through 2014 show 116 incidents categorized as “pipeline” incidents and that specifically include the term “gathering” in the incident description. Many more pipeline incidents could also be from gathering lines.
PHMSA notes that one of its challenges is to understand and target risk, which requires a systematic approach to risk management, including a “comprehensive understanding of the factors contributing to risk and the ability to focus resources in those areas that pose the greatest risk.” One of PHMSA's strategies for dealing with this challenge is to improve data collection and analysis, collect the right data to evaluate risks from unregulated entities, and improve the transparency of information and public awareness of pipeline and hazardous materials safety issues. The long-term benefits of having better information may include reducing incidents, enhancing incident response, and increasing public confidence.
As such, PHMSA is finalizing the requirement for operators of gathering lines to report information annually, starting 1 year from the rule's effective date, and to report accidents and safety-related conditions starting 6 months from the final rule's effective date. PHMSA considers these deadlines practicable in view of the scope of the information requested. To facilitate reporting and address commenters' concerns about providing clear instructions on data elements that must be filled out for gathering lines, PHMSA has modified its existing reporting form to provide clear instructions, including skip patterns, on the relevant sections that gathering line operators must fill out. In response to API's specific suggestions regarding operator qualification, control room management, leak detection, and HCA reporting, these revisions exempted rural gathering lines from any fields that involve “Could Affect HCA” data. PHMSA recognizes that operators who are not currently submitting data will have to register for an identifier, but PHMSA expects the burden on operators to do this is small. In its analysis, PHMSA assumed that a majority of the reporting of currently unregulated gathering lines would be done by operators who already have OPIDs. PHMSA estimates that, at a minimum, approximately 20 operators will need to submit information for gathering lines for the first time, and another 56 operators will add information about gathering lines to their existing annual reports. PHMSA estimates the total reporting burden at 402 hours per year, on average. See the revised RIA accompanying the final rule for additional detail.
Some commenters requested that PHMSA clarify whether these reporting requirements applied to offshore gathering lines in State waters. As the purpose of the information collection is to evaluate the public risk posed by gathering lines, PHMSA found it appropriate to extend the reporting requirements to certain offshore gathering lines in State waters.
In its proposal, PHMSA did not intend to require mapping or NPMS submissions for gathering lines. Under 49 U.S.C. 60132, only transmission line operators are required to submit mapping data for use in the NPMS; PHMSA does not have the explicit authority to collect NPMS data for gathering lines. PHMSA is therefore finalizing the rule without imposing this requirement on operators of gathering lines.
Similar to requirements for gravity lines, PHMSA is not requiring telephonic reporting of accidents involving gathering lines to PHMSA at this time since such a requirement would not support the purpose of this data collection effort, which is to enable PHMSA to evaluate risk over time for potential future action. PHMSA notes that operators must still report spills to the National Response Center and other relevant authorities. PHMSA will reassess the utility of requiring notification for incidents involving gathering lines in a future rulemaking if the analyses suggest that such notifications would enhance prevention, preparedness, and response to hazardous liquid releases from gathering lines.
Certain commenters also stated their belief that PHMSA neglected to account for the costs and burden associated with the initial compiling of the data needed to complete the forms. In many cases, the commenters suggested, information may not have been recorded or may not have been provided during mergers or acquisitions. PHMSA noted in the RIA that it expects operators to have the requested information readily available, as it is essential for pipeline operation and safety. PHMSA allows operators to enter “unknown” when values cannot be determined for certain data fields. In the burden estimate, PHMSA allotted time for operators to compile the proper data and organize it into the requested format. See the RIA for further details. PHMSA did not impose minimum safety standards on currently unregulated gathering lines, as some
commenters suggested, because the agency currently does not have data to analyze what risk, if any, those lines may pose to surrounding communities and environments. However, under these provisions, PHMSA will gather data on unregulated gathering lines and will use that data to determine whether additional safety regulations may be necessary.
C. Pipelines Affected by Extreme Weather and Natural Disasters
1. PHMSA's Proposal
Recent events demonstrate the importance of ensuring that our Nation's waterways are adequately protected in the event of a natural disaster or extreme weather. PHMSA is aware that responsible operators might do such inspections; however, because it is not a requirement, some operators do not. Therefore, PHMSA proposed to require that operators perform an additional inspection within 72 hours after the cessation of an extreme weather event such as a hurricane or flood, an earthquake, a natural disaster, or other similar event.
Specifically, PHMSA proposed that an operator must inspect all potentially affected pipeline facilities after an extreme weather event to help ensure that no conditions exist that could adversely affect the safe operation of that pipeline. The operator would be required to consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining the appropriate method for performing the inspection required. The initial inspection must occur within 72 hours after the cessation of the event, defined as the point in time when the affected area can be safely accessed by available personnel and equipment required to perform the inspection. Based on PHMSA's experience and coordination with operators following natural disasters, PHMSA has found that 72 hours is reasonable and achievable in most cases. If an operator finds an adverse condition, the operator must take appropriate remedial action to best ensure the safe operation of a pipeline based on the information obtained as a result of performing the inspection. PHMSA specifically asked for comments on how operators currently respond to these events, what type of events are encountered, and if a 72-hour response time is reasonable.
2. Summary of Public Comment
Some trade organizations recommended that certain requirements be eliminated altogether or consolidated to reduce what they considered to be duplicative of existing emergency planning requirements in § 195.402(e)(4).
Commenters were nearly unanimous in requesting that PHMSA clarify the definition of extreme weather event, the 72-hour timeline, and the timeline for mitigating or repairing anomalies. The GPA recommended that PHMSA either define exactly which events require response and inspection or establish performance expectations without partially defining the criteria, while the County of Santa Barbara recommended that the proposed regulations specify a threshold at which action would be required. Congresswoman Lois Capps (California) recommended that PHMSA include definitions and/or citations of existing definitions for qualifying events and the responsible party for such a determination. Congresswoman Capps also recommended that PHMSA clarify the terminology for an “appropriate method for performing the inspection” after the event.
In addition to clarification of the definition of extreme weather event, trade groups also requested clarification of the 72-hour timeline following an extreme weather event, including how they would determine the cessation of the event, what appropriate action they would need to take following an event, and how to address the possibility of continued danger facing personnel or issues with availability of personnel and resources following an event.
API-AOPL recommended that PHMSA define cessation as the point in time when no further threats to personnel safety or equipment exist in the affected area, allowing for safe access by pipeline personnel and equipment. They also recommended that the 72-hour window commence only once personnel and equipment could safely access the affected area.
Citizen groups and individuals requested that operators be required to proactively address known risks and vulnerabilities in advance of an extreme weather event. For example, one organization recommended additional requirements to identify areas that are particularly vulnerable to extreme weather events or natural disasters, (
e.g.,
stream crossings, and to develop proactive preventive measures.) The Alaska Wilderness League et al. recommended mandatory prevention measures that include shutting down pipeline operations in case of an imminent flood to prevent spills such as the 2011 Exxon Mobil Yellowstone River spill. Citizen groups also requested immediate reporting to PHMSA when remedial action is required and that this information be made publicly available. The Environmental Defense Center requested that PHMSA provide specific, enforceable requirements for shutdown or other remedial action should an inspection reveal damage or anomalies, and that PHMSA clarify the type of events covered and the inspection methodology required.
Finally, the OOC recommended that PHMSA coordinate with BSEE and the U.S. Coast Guard for activities that occur after hurricanes.
During the meeting on February 1, 2016, the LPAC recommended that PHMSA modify the NPRM to (1) include landslides as an extreme weather event, (2) clarify that other similar events are those likely to damage infrastructure, and (3) require operators to inspect all potentially affected pipeline facilities to detect conditions that could adversely affect the safe operation of the pipeline. The LPAC also recommended that PHMSA modify the language regarding the inspection method to require operators to consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining the appropriate method for performing the initial inspection to determine damage and the need for additional assessments. Finally, the LPAC recommended that PHMSA clarify that the inspection must commence within 72 hours after the cessation of the event, which is defined as the point in time when the affected area can be safely accessed by the personnel and equipment, accounting for personnel and equipment availability.
3. PHMSA Response
PHMSA disagrees with the comments stating the provisions at § 195.414 are unnecessary and duplicate operation and maintenance (O&M) manual requirements already contained in the response plan requirements under § 195.402. While § 195.402 does require that operators include certain ongoing monitoring measures in their O&M manuals, the proposed § 195.414 is much more specific in requiring that operators take appropriate remedial action to best ensure the safe operation of a pipeline based on the information obtained as a result of performing the post-event inspection required under paragraph (a) of this section. This will ensure that operators take the prescribed actions; having measures described in an operator's O&M manual, as previously required, is not equivalent to action. PHMSA maintains that separate and more specific requirements are
warranted to best ensure public safety and environmental protection following extreme events. Additionally, PHMSA notes that reporting is coordinated with BSEE, the U.S. Coast Guard, and other agencies under existing notification procedures if the assessment determines there was a release involving their areas of responsibility. Both 49 CFR parts 194 and 195 require operators to report spills to the National Response Center.
PHMSA appreciates the feedback provided by the commenters regarding the need for greater clarity in the definition of extreme events and natural disasters and expectations on the timing and scope of post-event inspections. In developing the requirements, PHMSA sought to balance being explicit regarding the types of events that could increase the risk of a release and therefore require inspections, with providing sufficient flexibility to account for diverse geographical and pipeline design factors. PHMSA recognizes that the language recommended by the LPAC is useful in striking this balance and adopted most its revisions in the final rule under §§ 195.414(a), (b), and (c). PHMSA is removing the language “other similar event” as PHMSA found the phrase to be vague and unnecessary to accomplish the goals of the provision but is maintaining the LPAC's recommended language regarding the “likelihood to damage infrastructure.” Per the finalized requirement, operators must inspect all potentially affected pipeline facilities following extreme weather events or natural disasters with the likelihood of damaging infrastructure, such as named hurricanes or tropical storms; floods that exceed the high-water banks of rivers, shorelines or creeks; and landslides or earthquakes occurring within the area of a pipeline, in order to detect conditions that could adversely affect the safe operation of that pipeline. As discussed earlier in this document, the conditions that trigger this requirement are those that have the potential to cause river scour, soil subsidence, or earth movement, all of which can subject a pipeline to additional external loads and forces and cause the pipeline to fail. Pipeline operators are already required to understand and analyze the impact such weather events and natural disasters may have on their systems based the physical characteristics, operating conditions, location, and prior history of susceptible pipelines.
PHMSA retained the remedial actions unchanged from the proposal. While PHMSA intends for operators to inspect pipelines as soon as possible after an event ends, PHMSA also agrees with commenters that personnel safety is paramount. Accordingly, PHMSA clarified that the cessation of the event occurs as soon as it is safe for personnel and equipment to access the area. Operators are responsible for determining when each site is safe enough for entry.
In response to commenters who sought greater flexibility in the timing of the inspections by leaving it up to the operators, PHMSA disagrees and maintains that setting clear and consistent timelines is essential to ensuring that all operators detect and address any issues promptly. The final rule does provide a fallback to operators who must delay the start of actions beyond this time due to availability of equipment, but these operators must notify the Regional Director. This addition to the LPAC-approved language allows operators to retain flexibility due to unavailable equipment, while ensuring accountability and prompt action. PHMSA considers 72 hours to be a reasonable period for mobilizing personnel and equipment following an event.
In response to commenters who expressed concerns that inspections cannot be reasonably be completed within the 72-hour window, PHMSA notes that the proposal did not require completion of the inspections within 72 hours, and neither does the final rule; PHMSA recognizes that this needed to be clarified in the rule text and has done so in the final rule. The final rule accordingly describes the actions it expects operators to perform, starting within 72 hours after the cessation of the event. Recognizing that some actions will need to be site-specific, PHMSA provides flexibility to operators to determine the measures that are appropriate to the event, pipeline design, and circumstances.
PHMSA is receptive to the recommendation that operators should take precautionary measures to minimize exposure in advance of and during an extreme event (
e.g.,
reducing operating pressure or shutting down a pipeline), and notes that the current IM regulations require operators to know and understand risks to their system, which includes the threat of extreme events such as flooding or wind damage. To execute their IM programs and assessments on non-HCA lines as per this final rule, operators will need to have pipeline system information to address risks to their systems. Operators will use the information they have gathered on their entire pipeline system to monitor conditions and determine any anticipated risks to their pipelines, including extreme weather events. Given that the existing IM regulations require preventive and mitigative measures for HCAs, which often include river crossings, it is appropriate for this section to address post-natural disaster inspections for damage specifically.
D. Periodic Assessment of Pipelines Not Subject to IM
1. PHMSA's Proposal
PHMSA proposed to require integrity assessments for pipeline segments in non-HCAs. PHMSA believes that expanded assessment of non-HCA pipeline segments areas will provide operators with valuable information they may not have collected if regulations were not in place; such a requirement would help ensure prompt detection and remediation of corrosion and other deformation anomalies in all locations, not just HCAs. Specifically, the proposed § 195.416 would require operators to assess non-HCA (non-IM) pipeline segments with an ILI tool at least once every 10 years, which allows operators to prioritize HCA assessments. PHMSA proposed to allow other assessment methods if an operator provides OPS with prior written notice that a pipeline is not capable of accommodating an ILI tool. Such alternative technologies would include hydrostatic pressure testing or appropriate forms of direct assessment.
Although imposing the full set of IM requirements in § 195.452 on non-HCA pipeline segments was not proposed, operators would be required to comply with the other provisions in 49 CFR part 195 in implementing the requirements in § 195.416. That includes having appropriate provisions for performing periodic assessments and any resulting repairs in an operator's procedural manual (see § 195.402); adhering to the recordkeeping provisions for inspections, tests, and repairs (see § 195.404); and taking appropriate remedial action under proposed § 195.422, which, based on the existing IM repair criteria at § 195.452(h), identified specific types of anomalies and the timeframes by which they must be remediated. Operators would also follow the requirements for “discovery of condition,” where the discovery of a condition occurs when an operator has adequate information to determine that a condition exists. The operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition to determine whether the condition could adversely affect the safe operation of the pipeline, unless 180 days is impracticable as determined by
PHMSA. PHMSA sought public comment on the alternatives it considered under this specific proposal and on quantifying these alternatives in the regulatory impact analysis.
2. Summary of Public Comment
Trade organizations offered comments and language revisions on the methods and requirements included in the periodic assessments, implementation period, inspection intervals, and exemptions for lower risk pipelines. Enterprise Products Partners requested that operators be afforded the latitude they have under current IM regulations to determine the actual threats to pipeline integrity present on a given segment and to tailor their integrity assessment program accordingly. For instance, Enterprise suggested that PHMSA revise the proposal to clarify that a crack tool is not required for every ILI assessment, stating specifically that “an additional ILI crack tool is beneficial only when there is an identified threat to the pipeline segment that could result in cracks, such as cyclic fatigue. Yet PHMSA proposes to require a [crack tool] in all circumstances and on every pipeline segment.” Other trade organizations echoed this and requested that PHMSA incorporate alternatives to ILI tools for periodic assessments into the rule. Trade organizations also recommended that PHMSA ensure the rule is consistent with existing IM rules, including the reassessment intervals and implementation period. The Texas Pipeline Association requested that reassessment intervals be based on sound engineering judgement and industry consensus standards. Finally, trade organizations recommend that PHMSA limit and specify the type of pipelines to which the requirement would apply, with some commenters requesting specific exemptions for short lines and CO
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pipelines. API-AOPL requested that PHMSA clarify that operators would not need to run assessments on idle or out-of-service pipelines. API-AOPL also requested that PHMSA clarify that it intends for the requirements to include transmission lines only. Finally, the GPA requested that PHMSA rely on American Society of Nondestructive Testing (ASNT) ILI PQ as the standard for data analysis rather than the current language “qualified by knowledge, training, and experience.” The GPA submitted additional comments to PHMSA on March 24, 2016, expressing concerns that PHMSA misrepresented aspects of this proposal during the LPAC meeting. In the LPAC meeting the GPA claimed that PHMSA asserted that currently regulated gathering lines are subject to assessments; the GPA believes that this statement was inaccurate and led to a vote by the committee that was not based on accurate facts. Further, the GPA suggested that “it is possible there are gathering lines in non-rural areas which do not meet the Census Bureau definitions for high or other population areas. Thus, when properly applying the regulations as currently written, there are gathering lines, which are regulated by PHMSA and its state partners for safety purposes that are not subject to periodic assessments.”
Trade organizations also commented on the cost of expanding requirements for pipelines located outside of HCAs. The Texas Pipeline Association commented that raising the level of regulation on facilities outside of HCAs will redirect resources from high-risk areas to lower-risk areas. They requested that PHMSA consider the costs to operators of the proposed changes related to facilities outside of HCAs. The OOC also commented that offshore lines present unique challenges that make them ill-fitted for ILI technology and hydrotests.
Other groups and individuals commented on the methods and requirements included in the periodic assessments, inspection intervals, and additional requirements. A 5-year inspection interval was generally favored by citizen groups and individuals, including the Alliance for Great Lakes Et al. Congresswoman Capps highlighted that a 3-year interval between inspections had proven to be inadequate to detect corrosion that caused the Plains All American oil pipeline rupture in May 2015. These commenters also requested clarification that alternative methods of assessment must account for inspection along the entire pipeline both inside and outside HCAs and expressed concern with waivers for ILI tools or the use of direct assessment.
The NTSB requested that PHMSA harmonize the gas and liquid regulations to the maximum extent practicable and cautioned that direct assessment is an ineffective alternative technology for IM when applying the 10-year assessment requirement for the integrity of an entire pipeline. They recommended that the IM program encompass a broad range of available IM technologies including, but not limited to, ILI, magnetic flux leakage, ultrasonic testing, and tests directed at determining the integrity of the pipe coating.
Finally, some citizen groups and individuals requested that inspection reports be made publicly available and that operators be required to submit primary inspection results and data to PHMSA. The Environmental Defense Center recommended third-party verification of inspection reports based on corrosion underreporting. These groups also requested risk assessment on non-IM pipelines and annual inspections for all federally regulated hazardous liquid pipelines.
During the February 1, 2016, meeting, the LPAC recommended PHMSA modify the NPRM to clarify its application to pipelines regulated under § 195.1 that are not subject to the IM requirements in § 195.452. The LPAC also made additional language recommendations to clarify the method of the assessment when ILI tools are impracticable, including pressure tests, external corrosion direct assessment, or other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters. PHMSA notes that the LPAC, with minor tweaks, found the provision for requiring operators to perform these periodic assessments on all covered pipelines not subject to the integrity management requirements under § 195.452 to be a cost-effective, practicable, and technically feasible provision.
However, several commenters noted challenges and cost-benefit concerns with assessing offshore lines and regulated rural gathering lines as a part of this proposal. In this final rule, PHMSA is limiting the assessment requirement to onshore, non-HCA, non-gathering lines that can accommodate inline inspection tools.
Under the current regulations, PHMSA notes that approximately 45 percent of hazardous liquid pipelines are required to be assessed per the IM requirements by being located within an HCA or because they can affect an HCA. PHMSA has determined that, through this provision, most onshore non-HCA mileage will be assessed at a consistent rate. Further, as pipeline operators continue to replace pipe through modernization projects and repairs, PHMSA assumes that virtually all the Nation's pipeline mileage will be piggable within the next few decades.
In the NPRM, PHMSA did not intend for the requirements applicable to lines outside of HCAs to be more stringent than those applicable to lines in HCAs. PHMSA agreed with the commenters and the LPAC that it is appropriate to provide the same flexibility for the assessment of lines outside of HCAs as
lines within HCAs, but PHMSA notes that many of these concerns appeared to be in response to PHMSA's requirement to assess all non-HCA lines, even ones that were not readily piggable. As discussed above, this final rule's non-HCA assessment requirement now applies to piggable, onshore transmission line only. This final rule does allow operators to use pressure testing, direct assessment, or other technology in cases when in-line inspections are impracticable. PHMSA has determined that ILI tools may not be available for all pipe diameters and threats being assessed, and providing operators the ability to use these other assessment methods on piggable lines is appropriate at this time.
Further, per the comments received from commenters, including API and Enterprise, related to the use of crack tools, PHMSA has revised the final rule, at both §§ 195.416 and 195.452, to require crack tools only when there is an identified or probable risk or threat supporting their use. For example, if operators have identified a pipeline segment with identified or probable risks or threats related to corrosion and deformation anomalies, including dents, gouges, or grooves, then the operator must assess that segment with a tool capable of detecting those anomalies. Similarly, operators should assess pipeline segments with an identified or probable risk or threat related to cracks using a tool capable of detecting crack anomalies. Essentially, operators should always be selecting an appropriate assessment tool based on the pertinent threats to a given pipeline segment that have been identified by an operator's risk assessment. An operator's risk assessment should always be driving its integrity assessments and the integrity management program. An operator cannot properly maintain its pipeline if it does not know what threats to which the pipeline is susceptible to and which tools the company should be selecting to assess those threats. These threats can include, but are not limited to, pipe that may have manufacturing defects or have otherwise experienced in-service incidents.
Under the existing requirements of § 195.452(c)(1) (after which PHMSA modeled the new assessment requirements in § 195.416), operators must select an assessment method capable of assessing seam integrity and of detecting corrosion and deformation anomalies if the applicable pipe is low-frequency ERW pipe or lap-welded pipe susceptible to longitudinal seam failure. PHMSA has interpreted and intended the phrase “susceptible to seam failure” to apply to both low-frequency ERW pipe and lap-welded pipe. In this final rule, PHMSA has expanded the assessment provisions to require operators to use a tool or tools capable of assessing seam integrity, cracking, and of detecting corrosion and deformation anomalies on low-frequency ERW pipe, pipe with a seam factor less than 1.0 (as defined in § 195.106(e))
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)), or lap-welded pipe susceptible to longitudinal seam failure. Certain stakeholders may interpret this requirement to mean that these tools will need to be run on every segment of low-frequency ERW pipe, pipe with a seam factor of less than 1.0, or lap-welded pipe. However, PHMSA only explicitly requires the use of these tools for segments of low-frequency ERW pipe, pipe with a seam factor less than 1.0, or lap-welded pipe when these types of pipe are determined by an operator to be susceptible to longitudinal seam failure based on excavation findings, examinations, leaks, failures, pressure tests, inline inspections, other operating history, and the manufacturing history of the pipe vintage and its history of seam leaks and failures.
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49 CFR 195.106(e) has seam factors for pip
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