The Pipeline and Hazardous Materials Safety Administration (PHMSA) published a final rule dictating the shape and content of new control room management programs for hazardous liquid, gas transmission and distribution pipelines.
The rules come into play where controllers use supervisory control and data acquisition (SCADA) systems. This is a final rule which the Interstate Natural Gas Association of America and the American Gas Association initially opposed, then suggested alternative language for. In the final rule, PHMSA does step away from some of the more objectionable language in the proposed rule it issued in September 2008.
Terry Boss, a senior vice president at INGAA, admits the rulemaking process was “contentious” but lauds PHMSA’s ultimate publication of a “good, consensus final rule.” INGAA has been participating in development of a “Common Gas Control Manual” under the auspices of the Southern Gas Association. That document is almost complete. It is expected to provide additional specificity beyond some of the general requirements in the PHMSA final rule. One change companies must make to come into compliance with that rule, for example, is revisions in the hours of service SCADA employees work. The PMHSA final rule provides some flexibility, there, Boss explains. The SGA manual will provide specifics which, if companies adhere to them, will essentially put them in good shape with regard to PHMSA’s expectations.
The new rule became effective on Feb. 1, 2010. Control room management programs must be written by Aug. 1, 2011 and implemented by Feb. 1, 2012.
The SCADA rule grows out of the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES) Act which required PHMSA to set standards for a new human factors management plan. The most controversial aspects of PHMSA’s proposed rule of 2008 were its definitions of “controller” and “control room” and the requirement to conduct a 100% baseline data point verification of SCADA systems. Pipeline operators generally commented that the first was too vague and the second would entail significant cost for very limited benefit.
In the final rule, PHMSA narrowed the definition of a controller to eliminate persons who only use SCADA data incidentally and thus cannot directly affect pipeline safety. The definition now includes only those persons who monitor SCADA data from a control room and have “operational authority and accountability for the remote operational functions of the pipeline facility as defined by the pipeline operator.” The definition of control room is also narrowed, but it would take too much space to explain the complexities of the new definition.
Small pipelines with fewer than 250,000 customers and transmission companies without compressor stations have a scaled-down set of requirements.
Controversial Elements Dumped From DIMP
The Distribution Integrity Management Program (DIMP) final rule the Pipeline and Hazardous Materials Safety Administration (PHMSA) published in December was shorn of a number of controversial elements. The agency ditched what some companies called “vague and unenforceable” human factor requirements in integrity management (IM) programs, a requirement to report plastic pipe failures to PHMSA instead of the existing Plastic Pipe Database Committee (PPDC), and a requirement to report any excavation damages (not just those resulting in gas leaks) to PHMSA as one of the IM performance reporting measures the agency established in this final rule.
In the final rule, the definition of excavation damage is brought more closely in line with the one used by the Common Ground Alliance’s (CGA) Damage Information Reporting Tool (DIRT) which defines damage based on whether repair or replacement of an underground facility is required.
The DIMP rule covers all one million-plus miles owned by intrastate gas companies but does not require internal inspection of pipeline (as the gas transmission IM program does), mostly because the smaller-diameter distribution pipes don’t take pigging devicess. Instead, distribution companies will have 18 months (by Aug. 2, 2011) to develop an IM plan using some general parameters suggested by PHMSA. These include four specific performance reporting measures, including one on leak management.
Probably the most consequential aspect of the final rule is that it pulls in an otherwise unconnected element that companies install excess flow valves (EFVs) on single-family lines when those lines are repaired or put in for the first time. The company has to pay for that construction. That mandate went into effect Feb. 10. Previously, companies only had to notify customers that EFVs were available and if the customer wanted an EFV the customer paid for its installation.
Once an IM plan is written, there has to be a plan to reduce the risks identified in the plan, including an effective leak management program. Once a risk reduction plan is in effect, its results have to be measured based on performance measures, many of which PHMSA spells out, including the number of hazardous leaks either eliminated or repaired. An annual report has to be sent in disclosing the company’s success on four of the specified performance measures. The threats and risks have to be re-evaluated every five years.
A separate annual report on failure of compression couplings resulting in only hazardous leaks is also required. The first report is due March 15, 2011. This information must include, at a minimum, location of the failure in the system, nominal pipe size, material type, nature of failure including any contribution of local pipeline environment, coupling manufacturer, lot number and date of manufacture, and other information that can be found in markings on the failed coupling.
While PHMSA ditched the controversial human resources component in the IM plan, as distribution companies requested, it did not grant another request: that it reclassify low-stress pipelines now classified as gas transmission lines – and thus under the much more onerous interstate IM program – as distribution lines if they operate below 30% specified minimum yield strength (SMYS). Laclede Gas Co., the major gas utility in Missouri, had said it was costing it $10,000 a mile to assess the 134 miles of its low-stress pipelines running through high-consequence areas. Of those 134 miles, 84% operate below 30% SMYS. The final rule says PHMSA may consider this change later though more research would be needed.
FERC “Approves” Second Of Three Oregon LNG/Pipeline Projects
The Federal Energy Regulatory Commission (FERC) “approved” the Jordan Cove-Pacific Connector LNG/pipeline project with Chairman Jon Wellinghoff again casting a lone dissent. Wellinghoff, as he did in September 2008 on the Bradwood Landing LNG project, argued that domestic gas supplies and hydroelectric potential were a better alternative for getting gas to northern California and northern Nevada than a new LNG terminal in Oregon. Commissioners Suedeen Kelly, Marc Spitzer and Philip Moeller disagreed and voted “yes” as they also did on Bradwood. Both projects would be located in Oregon.
The FERC “approval” is conditional on Jordan Cove meeting 128 conditions, some significant, some not so much. The project already has all local land-use permits approved. But U.S. Commerce Department approval under the Coastal Zone Management Act and separate approvals under other federal laws by the Corps of Engineers remain ahead. Robert L. Braddock, vice president, Jordan Cove Energy project L.P., says he is confident that the project will have all 128 conditions satisfied by the end of calendar year 2010, which would allow the project to break ground in June 2011.
However, only one of the three Oregon LNG/pipeline projects (Oregon LNG is the third; FERC has not approved it yet, as it has Bradwood and Jordan Cove) will be built, and the project that moves forward will be the one with shipper backing. Braddock explains that shippers are hesitant to sign on with any of the three prospective projects until they have all state and federal permits in hand. So there is no telling yet which of the three will ultimately win the shipper jackpot.
The Jordan Cove Project would consist of an LNG import terminal on Coos Bay in Coos County, OR, and 234-miles of natural gas pipeline extending from the outlet of the LNG terminal to Klamath County, OR on the Oregon-California border. It would have the capability of receiving and unloading 80 LNG tankers per year, with a proposed send-out capacity of 1 Bcf/d.