May 2016, Vol. 243, No. 5
Features
New Pipeline Safety Proposal Contains Multiple New Requirements
Pipeline industry executives are pouring over the 500-plus page safety proposal from the Pipeline and Hazardous Materials Safety Administration (PHMSA), an effort that will take some time before informed comments can be made. The initial comment deadline is at the end of May. “The typical 60 days in which to submit comments will have to no doubt be expanded,” states Thomas Lael, formerly a state and federal pipeline inspector and now a consultant to transmission companies. “The last 100 pages of so of the document I downloaded from the PHMSA web site contained the proposed revisions to Part 192. That is massive.”
Cathy Landry, spokeswoman for the Interstate Natural Gas Association of American (INGAA), says, “At this point, we aren’t willing to talk on this yet. We really aren’t entirely sure what the rule says, and what it means for us.”
American Gas Association CEO and President Dave McCurdy says, “We appreciate PHMSA’s efforts and look forward to continuing to work with them to help ensure that the final rule is technically-based, reasonable and cost-effective.”
PHMSA believes that its proposed new transmission pipeline safety mandates essentially codify in federal law what most responsible pipeline companies are doing already. The proposal adds to some requirements in integrity management (IM) programs, expands IM responsibilities to a new classification of “moderate consequence areas,” and imposes new mandates on pipelines outside of high and moderate areas, for example, to gathering lines.
One controversial proposal eliminates the current exemption which allows pipelines to avoid verifying maximum allowable operating pressure (MAOP) in pre-1970 pipelines. The proposal mitigates the burden somewhat by only covering pre-1970 segments in HCAs and MCAs, and then only if certain conditions are met, such as there having been a reportable in-service incident since its most recent successful subpart J pressure test or where pressure test records necessary to establish MAOP are not “reliable, traceable, verifiable, and complete.” This requirement, responsive to a recommendation from the National Transportation Safety Board (NTSB), will be among the most expensive for the industry to implement.
INGAA and a number of pipeline operators opposed repeal of the pre-1970 exemption because hydrostatic testing–needed to establish MAOP–is very expensive and could require pipelines to take segments out of service for up to several weeks. INGAA suggested its Fitness for Service protocol be used to assure continued safety of old pipe. PHMSA rejected that approach.
The long delayed proposed rule answers some of the mandates in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and also responds to recommendations made by the NTSB based on an investigation of the San Bruno accident.
A major aspect of the proposal is its addition of IM responsibilities for pipelines in HCAs, and the extension of the full gamut of IM responsibilities beyond HCAs to MCAs. Here, PHMSA argues it is basically requiring what INGAA members are already doing based on the “Commitment to Pipeline Safety” it issued in 2012. That obligates members to extend IM programs in four stages to all their mileage by year 2030.
Currently, approximately seven percent of 297,814 miles of onshore gas transmission pipeline mileage is located in HCAs. So that is approximately 21,000 miles. The proposed criteria for determining MCA locations would use the same process and the same definitions as currently used to identify HCAs, except that the threshold for buildings intended for human occupancy and the threshold for persons that occupy other defined sites, that are located within the potential impact radius, would both be lowered from 20 to 5. PHMSA estimates that approximately 41,000 miles of pipe would require an assessment within 15 years under this new MCA provision.
In a key part of the proposed rule, PHMSA acknowledges, “If constant improvement and zero incidents are goals for pipeline operators, INGAA’s plan to extend and prioritize IM assessments and principles to all parts of their pipeline networks that are located near any concentrations of population is an effective way to achieve those goals.”
But the proposal goes on to raise a question about whether the INGAA program easily translates into “risk management standards that most accurately target the safety of communities…” It adds, “Addressing that question has been, and remains, an important part of this proposed rule, recognizing that the answer will remain fluid based on factors that continue to change.”
With that in mind, PHMSA makes changes to that current risk assessment process, adding both performance-based and prescriptive requirements. For example, with regard to guiding decisions about which preventive and mitigative measures to take within HCAs, the industry has pretty much relied on ASME/ANSI B31.8S. Companies would have to do more under the proposal. There would be prescriptive requirements related to checking for both internal and external corrosion. To address internal corrosion, operators will have to monitor gas quality and contaminants and to take actions to mitigate adverse conditions. They will have to monitor and confirm the effectiveness of external corrosion control through electrical interference surveys and indirect assessments, including cathodic protection surveys and coating surveys.
PHMSA also proposes some performance-based risk assessment check points which would have to be included in any risk model. These include: (1) identifying risk drivers; (2) evaluating interactive threats; (3) assuring the use of traceable and verifiable information and data; (4) accounting for uncertainties in the risk model and the data used; (5) incorporating a root cause analysis of past incidents; (6) validating the risk model in light of incident, leak and failure history and other historical information; (7) using the risk assessment to establish criteria for acceptable risk levels; and (8) determining what additional preventive and mitigative measures are needed to achieve risk reduction goals.
W. Kent Muhlbauer, Managing Partner, WKM Consultancy, LLC, says there has been lots of push back from industry groups on new risk assessment requirements. “But I think that’s mostly just a matter of education,” he explains. “Once operators and other stakeholders see that a risk assessment can actually help them better manage their business, that it is more than just window dressing, then good methods will be welcomed. Luckily, the better risk assessment is even cheaper than old methods, so no downside at all.”
Pipeline inspection options will be changing, too. For the past decade, operators have done baseline and periodic assessments of pipeline segments in HCAs using one of four methods:
(1) in-line inspection; (2) pressure test in accordance with subpart J; (3) direct assessment to address the threats of external and internal corrosion and SCC; or (4) other technology that an operator demonstrates can provide an equivalent understanding of the condition of line pipe. Direct assessment is generally the cheapest of the four, and its utility in some instances has been questioned. So PHMSA would allow its use going forward only if a line is not capable of inspection by internal inspection tools and add some new inspection options, including a “spike” hydrostatic test; excavation and in situ direct examination; and guided wave ultrasonic testing (GWUT).
PHMSA also proposes to require that all pipeline segments in class 3 and class 4 locations and moderate consequence areas to be periodically assessed if the pipe segment can accommodate inspection by means of instrumented inline inspection tools.
PHMSA is also proposing to extend existing requirements for Type B gathering lines to Type A gathering lines in Class 1 locations, if the nominal diameter is 8 inches or greater. Gas gathering lines are currently not regulated if they are in Class 1 locations. Current estimates indicate that there are approximately 132,500 miles of Type A gas gathering lines located in Class 1 areas of which approximately 61,000 miles are estimated to be 8-inch diameter or greater, and approximately 106,000 miles of Type B gas gathering lines located in Class 1 areas. Current requirements for type B gathering lines are: 1) if metallic, control corrosion; 2) carry out a damage prevention program; 3) establish a public education program; 4) establish MAOP; 5) install and maintain line markers.
PHMSA will probably raise some eyebrows with its contention that the benefits of the proposal outweigh costs to industry by about five to one. Using what is called a discount rate to come up with “present values” of both benefits and costs, the agency sees the value of benefits over 15 years amounting to approximately $3.2-$3.7 billion using a 7% discount rate or $4.0-$4.7 billion using a 3% discount rate. The present value of costs to would be $597 million at 7% and $711 at 3%. Discounting is a technique that translates future costs and benefits into present-day values to account for the time value of money. It does not take inflation into account.
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