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.

Santa Barbara Oil Spill

Question of the dayI see a pipeline just spilled oil into the ocean near Santa Barbara, California. What can you tell me about the company that operates that pipeline and their safety record?

 

Thanks for the question. The cause and the size of the spill are still being determined, and the clean up will go on for weeks we are sure.  Here is a quick analysis of the company that operates that pipelines

Quick Analysis Plains Pipeline L.P pipeline that failed in California

With the spill yesterday into the Pacific Ocean from a pipeline operated by a subsidiary of Plains All American Pipeline L.P. we have received a lot of calls about why the pipeline failed and how Plains safety record compares to other companies operating similar pipelines. To date we have not seen any information about why the pipeline may have failed, so speculating on that would serve little purpose. The Plains All American Pipeline L.P. system that failed is referred to in the Pipeline and Hazardous Materials Safety Administration’s (PHMSA) database as Plains Pipeline L.P, and their operator identification number is 300. Plains Pipeline L.P. is only part of the entire Plains All American Pipeline system which according to their website includes 17,800 miles of pipeline.

According to PHMSA Plains Pipeline L.P operates 6437 miles of hazardous liquid pipelines in 16 states, with 480 miles of it in California.[1] In the past ten years they have reported 175 pipeline incidents,[2] which caused nearly $24 million of property damage. Of those 175 incidents only 11 were in California. There have been 20 enforcement actions initiated against this company resulting in $284,500 in fines.[3] Of those enforcement actions none of them were for issues specific to California.

Here is some information about the incidents this system has had in the past ten years. Plains

The Pipeline Safety Trust today took a look at the incident data from PHMSA for the past 5 years (2009 – 2013) and compared Plains All American’s incident rates to the national average. Here is what we learned.

Graph1

 

 

 

The number of Incidents reported to PHMSA for all hazardous liquid pipelines is increasing, but incidents for crude oil pipelines are increasing at a faster rate. The number of incidents on crude oil pipelines operated by Plains Pipeline L.P. follows this trend, and is increasing faster then the national average.

Graph2

 

 

 

Since the mileage of pipelines has changed over the past few years we also normalized this analysis by looking at the number of incidents per mile of pipeline. We found that the rate nationally for crude oil pipelines is twice that of other types of hazardous liquid pipelines, and that the rate of incidents/mile of pipe for crude oil pipelines operated by Plains Pipeline L.P. was about 14% higher than the national average for crude oil pipelines.

Graph3

 

 

[1] http://primis.phmsa.dot.gov/comm/reports/operator/OperatorIM_opid_300.html?nocache=3583#_OuterPanel_tab_1

[2] http://primis.phmsa.dot.gov/comm/reports/operator/OperatorIM_opid_300.html?nocache=3583#_Incidents_tab_3

[3] http://primis.phmsa.dot.gov/comm/reports/operator/OperatorIE_opid_300.html?nocache=9182#_OuterPanel_tab_2