So much pipeline safety information!

Did you know we recently updated our briefing papers and added papers on three additional topics? These papers are a great source of ‘Pipeline Safety 101’ information – they are short and each focused on a single topic. They do not need to be read in order, though some basic understanding is helpful before reading about the more technical issues. Check them out if you haven’t already! Here is the full list:


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.



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.




Hope that helps answer your question.

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.





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.





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.







Another Spill into the Yellowstone – Are we learning anything?


Many rivers to cross
But I can’t seem to find my way over

                                                ~Jimmy Cliff


Dear Readers: An unfortunate deja-vu-all-over-again moment occurred recently: another pipeline ruptured at a crossing of the Yellowstone River in eastern Montana.

First, there was the Silvertip spill….

You may remember that after the ExxonMobil Co.’s Silvertip Pipeline ruptured and spilled 1,500 barrels of oil into the Yellowstone River in 2011, I got a letter from my friend King Fisher of Riparian Ranch asking about the rules that govern pipelines crossing rivers. It was clear by then that the Silvertip spill was caused by the pipeline being damaged by riverbed scour and debris and he was understandably confused about the existing rule requiring operators to bury their pipelines a minimum of only four feet when they construct pipelines across rivers of at least 100 feet in width. He wondered whether there were other rules, and what they might be. 

I answered that letter in the Trust’s newsletter in January of 2013 (at pages 4-6). Here are the highlights of that response:

  • The current rules require pipelines crossing rivers that are wider than 100 feet to be buried at least 4 feet at the time of construction. A separate rule requires lines that cross navigable rivers to be checked at least every 5 years “to determine the condition of the crossing”. There is no rule requiring any specific depth of cover to be maintained after installation, unless the pipeline is one where a spill could affect a “high consequence area,” say, for example, the drinking water supply of a small city that takes its water directly from, say, the Yellowstone River.
  • The 2011 amendments to the Pipeline Safety Act included a directive to PHMSA to undertake a study of liquid pipeline incidents at river crossings to determine if depth of cover was a factor, and to make recommendations for any legislative action to improve the safety of buried pipelines at river crossings. No regulatory action was required of PHMSA.
  • PHMSA produced its report describing its data management challenges (it doesn’t have a database, geographic or otherwise that shows the crossings that are subject to the 100 foot crossing/4 feet deep rule); and describing the pipeline failures at crossings in the last 20 or so years (well, at least some of them). In an NTSB document not cited in PHMSA’s report to Congress, a chart shows that 6 of Exxon’s pipelines in the San Jacinto floodplain ruptured or were undermined for up to 120 feet in the 1994 flood event; most of these were not included in the PHMSA analysis.

Then there was the Bridger spill – Another spill into the Yellowstone River last month

The Bridger pipeline failed at its crossing of the Yellowstone River, spilling approximately 1,000 barrels of crude into the river. Complicating response, investigation and recovery is that the river is entirely frozen over, but with ice of varying thickness from day to day, creating safety concerns for responders and physical limitations on recovery operations.

Initial reports were that the pipeline was buried at least 8 feet under the bed of the river. Then we learned that was an assessment from 2011. Then we learned that sonar showed much of the pipeline crossing the river was exposed on the riverbed, and some of it was suspended above the bed, entirely exposed. Although we do not yet know the reason for the pipe’s failure, clearly the lessons of the Silvertip (and a USGS study showing parts of the Missouri River scouring to depths of up to 40 feet) had not been learned – that rivers change all the time and quickly, that riverbeds move a lot of sediment, and quickly.

My 2013 reply to King Fisher was written before PHMSA had fulfilled its second obligation under the 2011 Act: to determine whether the depth of cover requirements are inadequate and if so, to make legislative recommendations. I suggested staying tuned to find out what PHMSA would do, and raised concerns about some of the options open to it:

The risk is that PHMSA either: a) decides to change the depth of cover at installation rule, creating a political sideshow that exhausts safety advocates’ energy arguing over the number of feet or inches it should be raised, completely ignoring the fact that the installation rule makes very little difference over time if there are no maintenance of cover rules or viable, enforceable integrity management rules to require operators to manage for the risk of riverbed scour; or b) decides to argue that the operator’s obligations under integrity management rules to identify and mitigate the risks of riverbed scouring are sufficient, regardless of the 4-foot depth of cover at installation requirement, and therefore the depth of cover rules don’t need to be changed. 

Unless PHMSA opts for: c) an enforceable and enforced maintenance of cover rule for all crossings that is based on a study of the specific location and characteristics of each crossing; and d) actually enforcing integrity management obligations of operators to design for and mitigate against the risk of riverbed scour before an incident occurs, this smart pig is not optimistic about improving the safety of crossings at rivers.

So, how did PHMSA do?

Well, to some extent it remains to be seen, but there is recent reason to hope for improvement.

When PHMSA reported to Congress with the second half of its homework assignment – do you have legislative recommendations? – PHMSA reported that it believed that its existing legislative authority was adequate to protect pipelines at river crossings. PHMSA has yet to publish ANY substantive proposed changes to its safety regulations since the 2011 reauthorization, and until those major proposed rulemakings are released, we won’t know whether PHMSA intends to change the depth-of-cover-at-construction rule or to propose any new rules requiring maintenance of cover to some depth.

But just last week, in the midst of the awful news about the Bridger spill into the Yellowstone, PHMSA released its Final Order on ExxonMobil’s appeal of the fine imposed for its Silvertip spill. In the order, PHMSA responded to the operator’s (EMPCo’s) arguments that they had complied with the regulations relating to adequate risk assessments and integrity management measures to manage the identified risks:

The fact that flooding had not previously caused an integrity issue for Respondent’s pipeline does not mean future flooding could never cause a failure. One of the purposes of the integrity management regulations is to anticipate the possible threats to the pipeline in the future. Given that flooding is a threat in general and that flooding had caused integrity issues for other pipelines at the same location, it was not reasonable for EMPCo to assume seasonal flooding would never impact its own pipeline. At a minimum, the Operator had a duty to evaluate the likelihood of a pipeline release occurring from flooding. [Order at page 9.]

The order continues by analyzing the documents in the record to determine if such a risk analysis had been made, notes that the 2010 Preventive and Mitigative Measures Analysis identified only three risks to the line — third-party damage, manufacturing, and external corrosion — in spite of the fact that the entire line had been identified as one which could affect a high consequence area, and further noting that the presence of the Yellowstone River or the risk of a failure at its crossing was never mentioned.

The good news

The Conclusion of the PHMSA order on this violation is this:

Given the history of flooding and impact to other pipelines at this location, the threat of flooding was relevant to the likelihood of a release occurring on Respondent’s pipeline. Respondent did not evaluate the likelihood of a release caused by flooding of the Yellowstone River and failed to consider risk factors relevant to flooding. Accordingly, PHMSA finds Respondent violated § 195.452(i)(2) by failing to conduct a risk analysis of the Silvertip Pipeline that considered all risk factors relevant to the likelihood of a release on the Silvertip Pipeline and potential consequences affecting the Yellowstone River. [Order at page 12.]

This suggests that PHMSA may, in fact, be choosing Option D from my response to my friend King Fisher: d) actually enforcing integrity management obligations of operators to design for and mitigate against the risk of riverbed scour before an incident occurs.

Well, okay, technically, they haven’t yet enforced those obligations before an incident occurs as far as we know, but this is at least a start. Most importantly, it should certainly put every other operator on notice, whether they’ve had a flooding/riverbed scour/earth movement failure or not, that PHMSA will enforce the operators’ obligation to adequately assess those risks and to integrate sufficient preventive and mitigative measures into their integrity management programs to protect against failures. Unfortunately, PHMSA didn’t do that when they inspected the Silvertip a year or so before the Yellowstone rupture. When regulators enforce those obligations in routine inspections of integrity management programs independent of (and hopefully before) any incidents, that will indeed be good news.

Natural Gas Transmission Pipeline Leaks & Repair Criteria

Smart Pig’s Question of the Week – 

A Texas farmer recently contacted us to ask how long could an operator allow a leak from a natural gas transmission line to go without being repaired? He indicated that a leak – identifiable by the soil being sprayed up in the air above the line – had reportedly been visible in a neighboring field for some time, and there had been no apparent effort by the operator to repair it.

Leaving aside all of the reasonable, predictable questions about how that could happen or what an operator’s representative might have said when notified of the leak, here’s what the regulations say about leaks in gas transmission lines. As we suggested in our last post, the regulations vary depending on whether the leak is in a “high consequence area” (HCA) – generally an area of higher population. If you need the details on how gas transmission line operators identify HCAs, you can find them here.

This leak is nowhere near a high consequence area. Not even close. So the leak repair criteria in the gas integrity management rules that would apply in HCAs don’t apply. That means the repair falls under the general gas transmission repair regulations, found at 49 CFR § 192.711, seen in the box below.


§ 192.711 Transmission lines: General requirements for repair procedures.

(a)Temporary repairs.Each operator must take immediate temporary measures to protect the public whenever:
(1)A leak, imperfection, or damage that impairs its serviceability is found in a segment of steel transmission line operating at or above 40 percent of the SMYS; and
(2) It is not feasible to make a permanent repair at the time of discovery.
(b)Permanent repairs.An operator must make permanent repairs on its pipeline system according to the following:
(1) Non integrity management repairs: The operator must make permanent repairs as soon as feasible.
(2) Integrity management repairs: When an operator discovers a condition on a pipeline covered under Subpart O-Gas Transmission Pipeline Integrity Management, the operator must remediate the condition as prescribed by § 192.933(d).
(c) Welded patch.Except as provided in § 192.717(b)(3), no operator may use a welded patch as a means of repair.


To paraphrase, an operator must make immediate temporary repairs to protect the public, but only when lots of qualifiers apply to the situation:

1) the leak/imperfection/damage impairs the serviceability of a pipeline;

2) the line is operating at or above 40% SMYS (specified minimum yield strength, defined in 49 CFR § 192.4); and

3) it is not feasible to make a permanent repair at the time of discovery.

For permanent repairs, none of those qualifiers are necessary: for non-integrity management repairs, meaning like the line in question it is not in a high consequence area, the operator must make permanent repairs “as soon as feasible”. So that begs the question, what does “as soon as feasible” mean? It doesn’t say “immediately,” (presumably because they’ve already made immediate temporary repairs where there is risk to the line or to the public) but it also doesn’t say “as soon as practicable,” or “in the course of ordinary business.” To an ordinary reader, I think “as soon as feasible” would mean “as soon as you can, even if that’s sooner than you want to.”

Unfortunately, the answer could get a bit muddier (or at least more expensive to determine) if one were to look to the rules for repairs on pipes subject to integrity management rules for guidance in determining how soon is “as soon as feasible.” That’s because, as noted in the text box above, repairs on pipes in high consequence areas are required to follow the criteria in 49 CFR 192.933 (d) in remediating a “condition.”  If we assume that a leak qualifies as a “condition,” (and I would argue it does, since “condition” is used in §192.711 interchangeably with “leak, imperfection or damage”) then an operator needs to determine, within 180 days, whether it poses a potential threat to the integrity of the line. Assuming it does pose such a threat, then the operator has to “complete remediation of the condition” within the timeframes included in an industry standard incorporated by reference into the PHMSA regs, but unavailable to mere members of the public unless you either buy them at considerable expense, or trek to the bowels of the Department of Transportation office or the National Archives, both in Washington DC in order to see a copy of them. Once there, you will want to see the schedule in ASMA/ANSI B31.8S, Section 7, figure 4. Unfortunately, this little piggy has not purchased the appropriate set of industry standards, nor am I able to travel to either of these offices, so I am not able to tell you how a leak large enough to blow soil into the air might be classified for repair. The remainder of subsection (d) of the regulation is not of much assistance, either: it names specific types of anomalous conditions on a pipe and indicates whether they are “immediate repair conditions”, “180 day repair conditions”, or a “monitored condition”, which need not be repaired until it gets worse. Leaks are not included in any of those lists.

Bottom line: Leaks on gas transmission lines outside of HCAs need to be repaired as soon as feasible. Leaks inside HCAs: it depends – but only somebody with the industry standards can tell you exactly on what it depends. And I expect there will be continuing conversations about whether it’s okay to make people who live with the consequences of a law pay a private industry organization for a copy of a standard that has been incorporated into that law.

Natural Gas Components, Transmission Line Leaks and Karst Topography

Smart Pig’s Question of the Week –

We were recently contacted by a resident of Virginia who wanted to know whether natural gas transmission lines leak, and particularly about how the methane and other constituents of transported gas might behave if a leak occurred in an aquifer associated with karst topography.

To best respond to his concerns, we’ve divided his questions up into smaller bits:

1) Do gas transmission lines leak?

2) How do we find out what else is in gas transmission lines in addition to methane?

3) How will gas behave when it is released by a leaking transmission line into an aquifer, specifically one in a karst landscape?

1. Do gas transmission lines leak?

Yes, gas transmission lines leak, but because of a variety of factors such as size of leak, weather conditions, how the gas might migrate and/or collect, and available ignition sources, leaks may or may not reach the right mixture with air to ignite. The natural gas in these types of pipelines is primarily methane which is lighter than air, so if there is a leak the gas rises in the atmosphere and dissipates, and is not typically a problem for groundwater contamination like other types of liquid pipelines and pipelines that carry liquid gases (ethane, propane, butane, etc.).

Emissions from all the different types of gas pipelines is a problem that has recently been recognized by the EPA and White House in relation to concerns over climate change. In general “leaks” from gas transmission lines are not the largest source of gas coming from such pipelines. Emissions from compressor stations, blow downs at valves, and releases associated with maintenance programs account for more gas released. If you are interested in the emission concerns that are starting to be highlighted nationally regarding climate change at our recent national conference we had representatives from a variety of groups talking about those issues. You can find video of some of those presentations here.

How long an operator can allow a leak to continue depends on its characteristics and whether it falls into a geographic area known as a “high consequence area” – usually a higher population area – where there are additional safety requirements with which operators must comply. See our next installation for a more detailed discussion of leak repair criteria.

2. How do we find out what else might be in natural gas transmission lines in addition to methane?

Interstate natural gas pipelines will typically only be transporting natural gas that is made up of a high percentage of methane. The specific ratio of gases will be set by the gas ‘quality’ tariffs that the company drafts. A maximum BTU/SCF (British Thermal Unit per standard cubic foot) quality tariff usually sets a maximum on the “richness” of heavier than methane gas components such as ethane, propane etc., that can be in the natural gas. The pipeline company wants to set quality standards for what is included in the natural gas so the end users can use it with the minimal amount of processing, and so it does not contain things that could damage the pipeline. As an example, here is a screenshot of the gas quality measurements from a Williams Transco pipeline that goes through Virginia.

Click for larger version

Click for larger version

You will see that at the Fredricksburg station, the “natural gas” was made up of about 95% methane, with a few other components (predominantly ethane and CO2) also included. You can find this info for the Transco pipeline at  There are buttons on the left hand side of the page that will take you to the “gas quality” section. There you can choose between various tabs to see daily gas quality values and the actual gas quality tariff provisions. Most companies post their tariffs on their websites.

3. How will natural gas behave when it is released by a leaking transmission line into an aquifer, specifically one in a karst landscape?

Karst topography and landforms are created by the action of water on soluble rock types like limestone and gypsum. Karst is typified by sinkholes and caves.  Aquifers in karst topography can transport pollutants much more quickly than other aquifers, simply because there are frequently large cracks and caves through which the water can travel, rather than having to pass through less porous, less permeable rock types. One additional risk incurred by pipelines in these areas is that they must be engineered and maintained accounting for the possibility of rapid changes in the geologic stability of the route, as sinkholes and caverns can collapse quite quickly placing abnormal loads that can cause a pipeline to fail. Another additional risk is that leaked gas could migrate to a pocket in the rock or a cave where it could become trapped and eventually become an explosion hazard if it were to find an ignition source.

The methane being transported in a transmission pipeline will, if released, dissipate as a gas into the atmosphere, making its way through whatever soil or rock type the pipe is buried in. At the low concentrations present in natural gas, the ethane in the gas mixture tends to travel as a gas and not a liquid. If there were to be a transmission line leak, the ethane would release into the atmosphere as a gas, although because it is heavier than air, it will not dissipate as quickly as the methane. If a natural gas line were to leak into groundwater, the small percentage of ethane will tend to be carried with the methane and dissipate as a gas.