What’s up with the differences in fines?

What’s up with the differences in fines?Money-tips-scale-of-justice

I just saw that along with the big fine ($1.6 billion) the California PUC levied against PG&E for violations relating to the pipeline failure in San Bruno, they also levied (and a court just upheld) a smaller, but still substantial $14.35 million dollar fine against PG&E for recordkeeping and notification violations relating to a pipeline segment running through San Carlos.

 

Here’s part of the story I saw, as reported by Sarah Smith in SNL:

 

Although the utility lowered the lines’ MAOPs after making the discovery in the field, the company did not notify the commission until roughly eight months later in an errata filing.

 

The CPUC in December 2013 voted to fine PG&E $14.35 million not only because of the lengthy reporting delay but also because PG&E informed the commission in an errata document — a type of filing the CPUC asserted is usually used for noting minor corrections. The CPUC said these actions had misled the commission, in violation of CPUC rules.

 

The fine included $50,000 for each day between when the company discovered its records were wrong and when the utility told the commission, along with $50,000 per day for the time during which PG&E’s misleading records correction document was on file.

 

My question is this: Why is there such a big difference between the size of these fines and the relatively small penalties levied by PHMSA for other big failures, like the Enbridge spill in Michigan, or the ExxonMobil Silvertip spill in Montana?

 

Answer:

There are two answers to this question. The easy one is that California has no maximum amount for a series of continuing or related violations; as long as a violation continues, that $50,000 per day can keep adding up. PHMSA is subject to a $2 million dollar limit for a “related series of violations.” (And the two spills you mention occurred before Congress in 2011 increased PHMSA’s penalty authority from 1 to 2 million dollars for a “related series of violations.”)

 

And that leads to the second answer, which is: PHMSA is anything but transparent about how it calculates penalties, how it chooses to compromise penalties during, or as a result of, closed enforcement hearings, what will be considered a “related series of violations”, and what will not, what kind of violation will result in the full $200,000 for each violation for each day it occurs, and what will not. While PHMSA has a limitation for related violations imposed by statute, it has not adopted a policy or rule defining what “related series of violations” means, nor do its enforcement decisions make it very clear. For example, is a recordkeeping or reporting violation that is discovered in the course of an incident investigation “related” to other violations for an insufficient risk assessment or emergency plan simply because the shortcomings were identified during the investigation of a single incident? Or what about two independent violations discovered during an inspection, for vastly different subject matters? Are they related? Hard to say. Actually, it’s impossible to say, because PHMSA doesn’t tell anyone.

 

What’s more, not even the industry is happy with the cloak of mystery surrounding penalty calculations. In a very enlightening document entitled “STATUS OF EVOLVING PHMSA PENALTY POLICY” prepared by two attorneys from Hunton and Williams for an AOPL Business Conference in 2013, they described their concerns with these same two issues: the difficulty in anticipating how PHMSA will calculate a penalty and how PHMSA will decide whether violations are in a related series.

 

This document also introduced us to the “Pipeline Safety Violation Report (PSVR) used by PHMSA: “PSVRs are prepared as part of the Agency’s enforcement process. They are considered ‘confidential enforcement information’ and protected from disclosure to third parties under FOIA. PSVRs are only provided to an operator in the event an operator challenges an enforcement action by requesting a hearing (and even then only upon an express request for the PSVR by the operator). In our experience, the amount of information included in a PSVR regarding the alleged violations and proposed penalties vary widely, and some do not even contain information regarding penalties at all. The information that is provided rarely (if ever) includes any sort of rationale as to the basis for a proposed penalty.”  Status of Evolving PHMSA Penalty Policy at page 2.

 

Until PHMSA decides to establish a penalty calculation policy and makes it available to the public, all of this will remain completely hidden from public view, just like everything else that happens in enforcement hearings kept closed from the public view.

 

 

 

Ignition of Natural Gas Transmission Pipelines

Question of the week:

A fairly large, 24 inch I believe, natural gas transmission pipeline recently failed here in Pennsylvania, and I was surprised that it did not ignite. I thought when natural gas pipelines ruptured they normally catch fire. Can you tell me why this one didn’t?

 

I think you are referring to the recent William’s Transco failure in Lycoming County, Pennsylvania that is described in a newspaper account here. We can’t really tell you why that one did not ignite, because few specifics are known about that failure at this time, but it is not unusual for gas transmission pipeline to rupture or leak without igniting. It all really depends whether the gas coming out finds an ignition source, which normally in an open area such as where this rupture occurred would be from sparks from the pipeline and rocks flying around due to the pressure of the escaping gas, or even static caused by the rapidly escaping gas.

 

We took a quick look at all the significant natural gas transmission pipeline incidents in the past 5 years and came up with this graph that shows for the various types of pipeline incidents whether they ignited or not. As you can see more often than not pipelines do not ignite when there are incidents, even when the lines completely rupture. We suspect that part of the reason people think they ignite more often is that when they do the incidents are quite spectacular and tend to make the news, whereas when they don’t ignite people hear much less about them.

ignitions

 

It is not unusual for these types of gas transmission pipelines to be operating at 800-1000 psi or more. Compare that to your car tires that operate at 30-35 psi and you get a sense of how much pressure is in these pipelines. Even just the pressure of the gas escaping can cause some impressive damage as the picture below shows. This picture shows a similar pipeline rupture in Washington State where there was no ignition. The crater is just from the force of the gas escaping. Notice the piece of pipe in the upper right hand corner of the picture. That is how far the force of the escaping gas threw that piece of heavy pipe.

 

WilliamsSouthofSeattle

 

Hope that helps answer your question.

Coming Back to Bellingham

June 10, 2015

We’ve just come back from a four day trip to California to participate in a couple of community forums  in Contra Costa County, visit with our friends in the city of San Bruno, meet some staffers in the Gas Safety Division at the CPUC, and research a report we’re writing for the community of Alamo about the liquid products line in their midst and how to improve safety around it.

Our trip fell just a couple of weeks after the oil spill in Santa Barbara, and between meetings, we spent more time on the phone with reporters and legislators and their staffers talking about how to improve pipeline safety in California.

With every public meeting, every conversation with a legislative staffer who has found our website, and every reporter wondering how it is the Trust came to exist, we tell and retell the story of June 10, 1999, the lives lost, the community reaction, the insistence that the story not be forgotten once the forest in Whatcom Falls Park recovered and the salmon returned to Whatcom Creek.

The Bellingham explosion was completely preventable. Just like the more than 74% of significant incidents on hazardous liquid pipelines in the past 10 years, it was caused by things within the operator’s control. (More than 57% of the past 10 years’ significant incidents on the gas transmission system fall into these same categories.) Causes like corrosion, incorrect operation, and material or valve failure – those are things the operators can anticipate, prevent and mitigate. But for whatever reason, they don’t, or won’t, or choose not to. And so, the Bambi vs. Godzilla story continues.

Last year, on the 15th anniversary of the Bellingham tragedy, Carl wrote a remarkable description of the impact of the Bellingham story.  It is a powerful reminder of Why the Bellingham Story Must Continue to Be Told. We urge you to revisit it.

dontforget-originalposter-edit

Bellingham on June 10, 1999

 

 

“I hope that everyone in Bellingham and around the country will join us today to remember the story again, and to show others that while we are tired of the story it is still important.”

 

 

 

Valves: Block, remote, automatic – which is best?

Our question this time comes from a resident of Santa Barbara and relates to the oil spill last month from an onshore pipeline that failed, allowing crude oil to reach the ocean.

Question of the week:

It would be very helpful for us here in Santa Barbara if you could answer some of our questions. 
One of the issues in our recent pipeline spill near Santa Barbara is whether there should have been an automatic shut off valve, as there is in most of the pipelines here. Industry spokesmen insist that the automatic shutoffs can cause unintended consequences, including over-pressurization elsewhere in the pipeline, and that it’s safer to shut down the pipeline manually. Other pipelines here have automatic shutoffs and haven’t had any incidents with them. Can you clear up this muddle?

I think there continues to be a good deal of confusion regarding this spill, which is too bad because either PHMSA or the company could clear it up with a little more communication.

For instance, I still do not know what type of valve was on that pipeline. Some reports say the valve was “manually” closed which would make someone believe that it was like the valve in San Bruno where someone had to actually drive to the site and turn the valve off by turning a large wheel/handle lots and lots of times. Other reports say the valve was turned off “manually” from the control room, as in an operator there pushed a button to remotely close the valve electronically. Those are two very different scenarios.

There are basically three types of valves in such locations:

Manual valves that need to be physically turned off at the valve site

Remotely controlled valves (RCVs) that can be turned off from the control room hundreds or thousands of miles away

Automatic shutoff valves (ASVs) that detect a problem on the pipeline themselves and then shut down without any needed human assistance.

Clearly the valve at issue on the Plains All American line was not an automatic valve, but from what I can decipher from the news stories I suspect it was a remotely controlled valve. After the San Bruno tragedy the NTSB recommended installation of automated valves on natural gas pipelines, and they left it up to PHMSA and the industry to decide which was better, remotely actuated or automatic valves. PHMSA did a large and expensive study on those types of valves for both natural gas and hazardous liquid pipelines, which can be found here. The bottom line was:

“Feasibility evaluations conducted as part of this study show that under certain conditions installing ASVs and RCVs in newly constructed and fully replaced natural gas and hazardous liquid pipelines is technically, operationally, and economically feasible with a positive cost benefit. However, these results may not apply to all newly constructed and fully replaced pipelines because site-specific parameters that influence risk analyses and feasibility evaluations often vary significantly from one pipeline segment to another, and may not be consistent with those considered in this study. Consequently, the technical, operational, and economic feasibility and potential cost benefits of installing ASVs and RCVs in newly constructed or fully replaced pipelines need to be evaluated on a case-by-case basis.”

 It is true that if an automatic valve decided to close incorrectly, it could cause pressure problems on other parts of the pipeline. In the Bellingham tragedy it was an incorrectly installed valve that decided to close on its own causing a pressure surge to flow back towards Bellingham and the damaged pipeline to burst at a weak spot. Smart engineers seem to believe that while clearly that is a risk, the technology has gotten better, not all automatic valves are installed incorrectly, and that the entire system can be engineered and programmed to do other things when an automatic valve sends a signal it is closing, such as change the speed with which it closes, or direct other components, such as other valves and pump stations, to adjust to the valve closure to overcome that risk.

It is also true that human errors by operators in the control room can delay closure of remotely controlled valves, allowing more oil to spill, as in the ExxonMobil Silvertip Pipeline spill into the Yellowstone, or cause things to be done in the wrong order so the closure of that type of valve may damage other parts of the system. 

So the bottom line is there is a good deal of grey area between exactly the benefits of an ASV over a RCV, and a good deal of it depends on the pipeline system, operator training and the topography. 

The current regulations applying to all hazardous liquid lines require that “a valve must be installed at each of the following locations: ….(c) On each mainline at locations along the pipeline system that will minimize damage or pollution from accidental hazardous liquid discharge, as appropriate for the terrain in open country, for offshore areas, or for populated areas.” 49 CFR §195.260.

For lines to which the integrity management rules apply – that is, that less than half of the liquid lines where a failure could affect a high consequence area – there are additional considerations relating to automatic or remote control valves, or EFRDs, in the regulations words, standing for Emergency Flow Restricting Devices.

First: “An operator must take measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area.” 49 CFR 195.452(i). The operator must undertake a risk analysis “to identify additional actions to enhance public safety or environmental protection”….including “installing EFRDs on the pipeline segment.”

Speaking specifically about EFRDs: “If an operator determines that an EFRD is needed on a pipeline segment to protect a high consequence area in the event of a hazardous liquid pipeline release, and operator must install the EFRD.” 49 CFR 195. 452(i)(4). This sentence is followed by a long list of factors that must be considered in determining whether an EFRD is needed.

Unfortunately, like most risk/performance based regulations, these do not help eliminate any of the gray area on this issue. And they leave the consideration and determination to each operator in the context of an integrity management plan the public will never see.

There is a good deal of speculation that a proposed change in the rules governing hazardous liquid lines may include changes to regulations about the installation of different kinds of valves, but no one knows for sure. An Advanced Notice of Proposed Rulemaking was issued in October of 2010, indicating that valves might be included in the proposed rule. The proposed rule has yet to emerge from PHMSA and the review by the White House Office of Management and Budget. To get notifications of progress in this area, go to www.regulations.gov, search for PHMSA-2010-0229, and sign up to receive email notifications when new information is posted.