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.

Another pipeline incident anniversary – have things changed since 2009?

Question of the weekI think it was around this time in 2009 that a gas pipeline blew up in Palm City, Florida near a school. What really happened then, and have things gotten safer in the past 6 years?

On May 4, 2009, an 18-inch Florida Gas Transmission Company interstate pipeline ruptured about 6 miles south of Palm City, Florida, releasing about 36 million cubic feet of natural gas and causing three minor injuries in Martin County. The community was fortunate: the gas did not find a source of ignition and catch fire, nor did two other large gas lines buried parallel to the one that ruptured sustain any damage, though 106 feet (over 5,000 pounds) of buried pipeline was blown into the air and landed in the right-of-way between two major highways. The pipeline segment that failed was between two automatic shutoff valves, but only one closed in response to the pressure drop on the pipeline. A Supervisory Control and Data Acquisition (SCADA) system was in use by the pipeline operator at its control center in Houston, TX to remotely monitor and control the movement of gas through the pipeline. The SCADA system also failed to recognize the rupture or trigger any alarms.NTSB: Location next to I-95 and high school, in Rupture of Florida Gas Transmission Pipeline and Release of Natural Gas 20090504

The National Transportation Safety Board (NTSB) issued a pipeline accident brief on this incident, which found the cause of the accident to be the operator’s failure to detect cracking of the pipeline beneath protective coating. The NTSB also found that the operator failed to correctly identify the pipe as being within a high consequence area even though it was near a school.

As with most pipeline incidents, there were many contributing factors to this incident. The operator subsequently changed operations and procedures related to this pipeline in response to a PHMSA corrective action order as reported by the NTSB. But here, in response to the question about whether things have gotten safer in the past 6 years, we will focus on the issue of high consequence area (HCA) identification.

If the pipeline segment had been correctly identified as being within a high consequence area, then it would have been included in the pipeline operator’s integrity management program. There are specific rules in the federal regulations requiring the implementation of integrity management in high consequence areas, and these include specific inspection, analysis, maintenance and repair criteria designed to detect problems such as those that caused this 2009 incident.

As to whether these same mistakes could be happening today, the answer is yes. Are things safer? It’s hard to say. The same rules that allowed the identity and location of HCA’s to be kept secret from the public in 2009 are still in place. The public can’t know, until after an incident, whether an operator has accurately identified the HCAs along its route.  

A fundamental problem is that PHMSA essentially leaves the designation of high consequence area (HCA) boundaries up to the pipeline operators, and entrusts them to update the boundaries when any changes take place that would trigger a new inclusion in the HCA. There is no way for an average citizen to know about the details of these HCA boundaries, to know if PHMSA is enforcing the designation of those areas, and no way to help ensure operators encapsulate what needs to be included within those boundaries according to the regulations.

For example, on a gas transmission line like the one in Florida that ruptured in 2009, the presence of certain populated areas would trigger the HCA designation. There is a complicated way for gas pipeline operators to choose their method of designation and draw their boundaries (see 49 CFR §192.903). Put generally, any area near a pipeline with a high population (for gas pipelines, that means 20 or more homes), or with a populated activity center (e.g. school, office, assisted living, recreation area, campground, etc.; referred to as “designated sites” in the gas regulations), would be considered part of an HCA. Just how near to the gas pipeline these homes and activities need to be to trigger the HCA designation depends on how big the pipeline is, and the pressure inside it.

So what if a community is building a new school? Or what if a development goes in within a half-mile of an existing pipeline? In the case of a hazardous liquid (e.g. crude oil or petroleum) pipeline, nearby town water intakes or environmentally sensitive areas also trigger the HCA designation – what if a town changes their water intake or an agency recognizes a new critical habitat area? These types of changes and development happen all across the country, but only a very few communities have practices or rules in place that facilitate active dialogue between a pipeline operator and developer, or between an emergency management team and pipeline operator, to the degree that these types of changes are promptly reflected in a pipeline operator’s integrity management program.

In fact, PHMSA rules allow over 10 years – yes, TEN YEARS – from the time a natural gas pipeline operator identifies HCA changes to when that information must be part of a completed baseline assessment of the pipeline in the newly identified HCA. And PHMSA rules allow over 6 years from the time a hazardous liquid pipeline operator identifies an area of high population or sensitivity, to when that information must have been incorporated into its completed pipeline assessment. And the time between the actual on-the-ground change and the identification of that change by the pipeline operator adds even more time – a vague amount of time as this type of information analysis is only required by the operator ‘periodically.’

Contrary to some who think pipeline information needs to be less accessible, we think the secrecy surrounding pipeline operator’s designations of high consequence areas (HCAs) and other withheld information leads to more risky pipelines. If communities could access this type of information easily, it would be easy for planners, emergency responders, and concerned citizens to inform pipeline operators when a change is needed – thereby leading to SAFER pipelines, not more risky ones. Our experience is that those most impacted by pipelines – those who live in close proximity to them, are the ones with most at stake and most interested in keeping the pipelines and their community safe. Withholding information from these stakeholders disregards critical allies in our collective efforts toward safer pipelines.

Despite the lack of a transparent playing field in this area, there are some things you can do.

Communities with active Local Emergency Planning Committees (LEPC) often have regular open meetings, and the committee itself should include representation from community groups as well as emergency response professionals, elected officials, professional staff, and facility and pipeline operators. The emergency responders who participate in these meetings have the ability to access information from pipeline operators that the general public cannot access. Pipeline operators are required to share their emergency response plans with local first responders, and to maintain liaison with appropriate fire, police, and other public officials. Citizens can participate with the LEPC and request the committee work on accurate identification of HCAs in partnership with the pipeline operator. The LEPC topic is addressed in more detail in chapter 5 of our Local Government Guide to Pipelines.

PHMSA maintains a web-based National Pipeline Mapping System (NPMS), which is viewable on a county-level and depicts the location of hazardous liquid and natural gas pipelines, along with population areas and other information. While the population areas may give some indication of where a high consequence area is likely to be designated, there is not a direct link between the NPMS information and what the operators currently use to designate their HCAs. The PHMSA information is not up to date, and does not include the level of detail or environmental information needed to truly assess HCA boundaries. This is a problem. There are periodic opportunities for the public to comment on this issue, as the Trust did in December 2014 and October 2013 (comments of the Trust on a variety of pipeline safety topics are viewable here). The public needs to be able to view information and data gathered from pipeline companies on NPMS that depicts pipeline locations within an HCA with a high level of accuracy. There is in fact a statutory requirement that HCAs be incorporated as part of NPMS and updated biennially.[1]

Lastly, the Palm City, Florida incident was one of the incidents the NTSB highlighted in their recent safety study published earlier this year entitled “Integrity Management of Gas Transmission Pipelines in High Consequence Areas” and discussed in our January 30 Smart Pig blog post. This study included a number of additional changes needed to help make pipelines safer over time.

[1] Pipeline Safety Regulatory Certainty, and Job Creation Act of 2011; Section 6 made part of 49 USC 60132.

Oil Pipelines by the Real Numbers

Reporters ask us a lot about numbers, and we see both accurate and misleading figures being thrown around in the press and even on unnamed official websites, so we’re expanding here on our February 10 blog post that touched on numbers. That post mentioned both numbers from the Pipeline and Hazardous Materials Safety Administration (PHMSA) and industry numbers published recently by API/AOPL (American Petroleum Institute / Association of Oil Pipe Lines) in their Pipeline Safety Excellence (PSE) initiative “Pipelines by the Numbers.” A fundamental concern the Trust has with these industry numbers is the lack of transparency about where their numbers come from.

The federal government through DOT- Pipeline and Hazardous Materials Safety Administration (PHMSA) collects information from pipeline operators annually and on incidents that occur (annual data and incident data, respectively). This data is fairly comprehensive and publicly available. PSE uses data from their own secret Pipeline Performance Tracking System (PPTS) with no public access to this data. The “Pipelines by the Numbers” report does not tell the reader what filters are used to pull the numbers, or why they differ so from the PHMSA incident data.

The data used by the Trust is typically based on PHMSA 20-year pipeline significant incident trends. In this example, we filtered that for onshore hazardous liquid (HL) pipelines (accessed on Feb 25, 2014), as we’re comparing our numbers to those of the liquid pipeline industry (API/AOPL). The Trust relies on the ‘significant incident’ dataset (rather than ‘all incidents’ or ‘serious incidents’) because we think it provides the most honest and transparent reflection of the incidents that show shortcomings in pipeline safety regulations and in operator safety cultures. Serious incidents only capture information when a death or serious injury occurs, and many catastrophic incidents are left out because the environmental destruction or personal property damage incurred is not enough to warrant the ‘serious’ categorization. The significant incidents dataset includes all incidents with $50,000 or more in total costs, measured in 1984 dollars, and including the value of the lost product; it also includes all serious incidents, any hazardous liquid release of 50 barrels or more, any HVL release of 5 barrels or more, and any liquid release resulting in a fire or explosion. We do not generally use the ‘all incidents’ dataset that captures the smaller accidents that occur, because reporting criteria for what a reportable incident is has changed quite a bit over time and can result in seemingly odd fluctuations when looking at all incidents.

We’re going to use this space to compare what we see in the PHMSA numbers, to what the hazardous liquid pipeline industry has published through their API/AOPL PSE initiative “Pipelines by the Numbers.” For shorthand purposes, when we say the word “industry” below in this post, we are referring to the hazardous liquid pipeline industry and the numbers put forth by API/AOPL.

1    FACT: More than 5 million gallons of hazardous liquids spilled in 2013 (including crude oil, refined products like gasoline, highly volatile liquids and others).

Industry states 99.999% of all hazardous liquid products are delivered safely each year, equating to all but .001% of the 14.9 billion barrels delivered in 2013. That means 5,009,524 gallons (we use PHMSA numbers here, but using industry numbers it would be 6,258,000 gallons) were spilled in 2013 in hazardous liquid pipeline incidents. (This is the one time we do use the ‘all incidents’ dataset to portray the volume that does, in fact, NOT get delivered safely each year.) Even if we filter the data for only the significant incidents, that figure remains close to 5 million gallons (4,978,706 gallons) spilled that year. By way of comparison, that’s equivalent to five spills the size of Marshall Michigan just for the volume spilled in 2013.

2    FACT: Greater than 67% of incidents since 2002 were caused by things within the operator’s control.

PHMSA collects incident data from operators, including a designation of what caused the incident, and that information is posted on PHMSA’s website. Among the causes are several that are entirely within the operator’s control: Corrosion, Incorrect Operation, Material/Weld/Equipment Failure, and Excavation Damage by the operator or its contractor. Together, these incident cause categories account for an average of 75% of all incidents since 2002 being within the operator’s control (1,622 total significant incidents from 2002-2014; 1,214 of those caused by things within the operators control). And things are not improving over time: every other year since 2002, more than 2/3 of significant incidents have been caused by things within the operators’ control.

3    FACT: 315 million residents are at risk of pipeline failures.

Industry reports that 315 million US consumers and workers benefit from pipelines daily – roughly the US Census population. Both are hyperboles adding nothing to what should be an important discussion about pipeline safety.

4    FACT: Over 50% increase in significant onshore HL pipeline incidents between 2001-2013.

Industry states a 50% DROP in incidents from 1999-2013. Frankly, we have no idea where they got this number, unless they only considered incidents that occurred off company property on Sundays (we’re kidding, kind of). 1999 had the highest number of significant pipeline incidents between 1995-2012 (142), so it was a convenient year to begin if looking to find a drop, but even starting at that relatively high point, there has been a 13% increase in significant hazardous liquid pipeline incidents.

5    FACT: 119 people killed or injured by onshore HL pipeline incidents since 1999 and $2.4 billion in property damages from pipeline spills in the past 10 years.

These are numbers they’d rather you not think about, preferring instead some variation of “everything is awesome”.

6    FACT: $141 million spent by oil & gas industry to lobby Congress last year.

Again, industry points out how much money the industry spends on pipeline maintenance and safety initiatives; and yet the industry spends 14 times the amount on lobbying than HL operators spend on pipeline safety research and development in any given year. Is “getting to zero” as important as “influencing” politicians?

7    FACT: 1.5 regulators review spill response plans for 192,000 miles of pipelines    and                             0 unannounced spill response drills held by federal regulators.

Under the Oil Pollution Act of 1990, HL pipeline operators are required to produce an ‘oil spill response plan’ or ‘facility response plan’ that details their preparations for a spill and submit this plan to PHMSA every 5 years. Only 1.5 PHMSA staff members are assigned to review these plans that cover 192,000+ miles of pipelines, the lowest by far of any of the four agencies who review these types of plans. The low staffing level results in PHMSA failing to require unannounced drills, as is required.

8    FACT: Corrosion caused more incidents in each of the last 3 years than in any year since 1997.

Industry claims that corrosion-caused pipeline incidents are down 75% since 1999. What??! PHMSA tracks corrosion as a cause (out of 7 overall cause categories) of incidents. We simply don’t understand where the industry claim could have come from. See for yourself; we’ve included the PHMSA data below so you can see both the numbers and percentages of incidents caused by corrosion each year. It’s remained a fairly steady 25%, but of late the total number of corrosion-caused incidents has been higher, not lower, than in previous years.


  1995 1996 1997 1998 1999 2000 2001 2002 2003 2004
# onshore HL sig. incidents 154 171 153 131 142 128 107 129 122 125
# corrosion-caused subset 32 51 44 31 24 29 32 34 28 35
% corrosion-caused 20.8% 29.8% 28.8% 23.7% 16.9% 22.7% 29.9% 26.4% 23.0% 28.0%
  2005 2006 2007 2008 2009 2010 2011 2012 2013  
# onshore HL sig. incidents 120 104 107 119 107 119 137 126 160  
# corrosion-caused subset 27 32 26 31 26 27 38 36 38  
% corrosion-caused 22.5% 30.8% 24.3% 26.1% 24.3% 22.7% 27.7% 28.6% 23.8%  


NTSB’s recent study on systemic weaknesses in gas pipeline safety

News media recently reported that the National Transportation Safety Board (NTSB) found continuing systemic weaknesses in gas pipeline safety. What does the NTSB have to say about where improvements are needed?

The NTSB and the gas pipeline integrity management rules

The NTSB is a congressionally-mandated transportation agency that operates independently to conduct objective accident investigations and safety studies, and advocates for implementation of safety recommendations. The NTSB does not conduct investigations of all pipeline incidents; it investigates those in which there is a fatality, substantial property damage, or significant environmental impact. In the past five years, the NTSB investigated three major gas transmission pipeline accidents in which operator and PHMSA oversight deficiencies were identified as concerns, occurring in Palm City, FL (2009), San Bruno, CA (2010), and Sissonville, WV (2012). These three accidents resulted in 8 deaths, over 50 injuries, and 41 homes destroyed with many more damaged.

The five-member NTSB Board held a meeting on Tuesday and soon after released an abstract of their recommendations. [The full study is now available here.] The study focuses on gas transmission pipelines within High Consequence Areas – basically, areas with higher population – and therefore must have in place an integrity management program. Only about 7% of the nearly 300,000 miles of gas transmission pipelines nationwide are required to have an integrity management program, though the industry says many more miles are inspected under integrity management than what the rules require.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) gas pipeline integrity management program rules took effect in 2004. They require, among other things, that the pipeline operators inspect their gas pipelines at least every seven years, and have a program in place to assess risk and ensure their pipelines are safe and reliable. Integrity management rules are performance-based rather than prescriptive, and rely on the operator to have good and complete data that is continually evaluated. Pipeline operator integrity management programs are periodically inspected by PHMSA and/or state regulators to assess compliance. Theoretically, using integrity management, gas pipeline operators should be finding and addressing potential problems before they result in accidents. Clearly, that is not working as evidenced by the accidents mentioned, leading the NTSB to embark on their study.

The NTSB Study

The study highlights shortcomings of the gas transmission integrity management system, and underscores issues the Trust has been bringing up for years. [See our 2012 comments submitted to PHMSA on gas transmission line safety and our 2014 comments to PHMSA on improving the national pipeline mapping system.] The abstract from NTSB states, “there is no evidence that the overall occurrence of gas transmission pipeline incidents in HCA pipelines has declined.” The complexity of the integrity management programs require expertise in multiple technical disciplines from both operator personnel and pipeline inspectors, and PHMSA does not have the resources for guiding them. The thirty-three findings of the study are published in the abstract and are followed by twenty-eight recommendations.

In brief, many things need improvement, including much better geographic information so that inspectors and operators clearly know where pipelines and high consequence areas are, and all data is better integrated; better communication between state inspections lead by the National Association of Pipeline Safety Representatives and PHMSA; better use of in-line inspection tools and improved operation of the same; better threat identification and assessment methods, with PHMSA acting as a guide for pipeline operators and inspectors in this area; and generally stronger, clearer standards and criteria for both operator and inspector programs and personnel to raise the safety bar higher.

We sincerely hope that 2015 will be remembered not for more terrible pipeline accidents, but for safety improvements that are made in part when studies and recommendations like the NTSB’s are heeded.

New Natural Gas Pipelines and Proximity to Homes

We’ve had a couple inquires in the past few weeks from citizens who have property on or near which a new natural gas pipeline is being proposed. They have asked: 1) How close to homes can one of these pipelines be installed? and 2) What are the options to minimize the danger when developing pipelines in proximity to other structures if the pipeline were to rupture?

The answer to the first question is straightforward: There is no limitation on how close gas pipelines can be built to homes. The federal regulations say nothing about any minimum distance away from homes that pipeline installation must occur. There is language in the regulations that requires operators to generally protect the pipe from hazards, but often much is left up to the discretion of the operator. For example:

CFR §192.317(a), “The operator must take all practicable steps to protect each transmission line or main from washouts, floods, unstable soil, landslides, or other hazards that may cause the pipeline to move or to sustain abnormal loads….”


CFR §192.325(a), “Each transmission line must be installed with at least 12 inches (305 millimeters) of clearance from any other underground structure not associated with the transmission line. If this clearance cannot be attained, the transmission line must be protected from damage that might result from the proximity of the other structure.”

The second question leads to a longer answer. And one we cannot address without making mention of PIPA (the Pipelines and Informed Planning Alliance), a group made up of industry (including representatives from interstate natural gas pipeline operators), government, and public representatives that developed a set of recommended practices for development near existing pipelines. This group met for years to address the very real concerns of development and pipelines impacting one another and posing risks to one another. Recommended practices include things like: “Reduce Transmission Pipeline Risk in New Development for Residential, Mixed-Use, and Commercial Land Use,” which states in part:

“…it is prudent to design buildings and related facilities in a manner that mitigates the potential impacts on people and property from a transmission pipeline incident. Locating structures away from the pipeline right-of-way (ROW), incorporating more stringent building fire safety measures are examples of mitigation techniques that may improve public safety and limit damage to buildings or infrastructure in the event of a transmission pipeline incident.”

It is puzzling to us how the industry can see the importance of these types of recommendations, and not see the importance of turning them around to apply to the development of new pipelines near existing buildings. We have been pushing PIPA to be reinvigorated and tackle this issue, but as of yet it has not happened.

Risks in proximity to gas pipelines are relative to the size and pressure of the pipeline. “A Model for Sizing High Consequence Areas Associated with Natural Gas Pipelines” was published in 2000 by Mark Stephens of C-FER Technologies, and prepared for the Gas Research Institute [LINK]. This report gives detailed explanations and calculations that lead to a proposed hazard area radius as a function of line diameter and pressure (see Figure 2.4 in the report). The hazard area radius is basically the area in proximity to the pipeline within which there would be virtually no chance of survival if a pipeline rupture and fire were to happen, and it varies in size from about 100 feet to about 700 feet for a 6-inch to 42-inch pipeline, respectively. For example, A 26-inch, 600 psi natural gas pipeline would have an approximate 450 foot hazard area radius, according to the C-FER model. The model does not take into account things like wind, topography, and any protection such as berms or fire walls.

States and (if the state does not preempt them) local communities may adopt their own setbacks between pipelines and homes. No jurisdiction that we know of has adopted the C-FER hazard area as the basis of setbacks from natural gas pipelines, though it has often been discussed. For jurisdictions that have adopted some sort of setback or consultation ordinances, see this link.

A few of the ordinances accessed through our website link specifically discuss evacuation, and evacuation is also addressed in the PIPA recommendations. Language repeated in a number of recommendations is “…buildings should have a safe means of egress with exits located where they would not be made inaccessible by the impacts of a pipeline incident. Similarly, cul-de-sac streets should not be designed crossing a transmission pipeline as the only route of ingress or egress could be blocked during a pipeline incident.”

Some gas pipelines lie within High Consequence Areas – basically areas with higher population density – and operators of those pipelines are required to have an integrity management program that includes conducting risk management and regular assessment of the pipeline. Depending on the location, the pipeline may also be required to have thicker walls or more frequent valve spacing.

While we know of no instances where FERC has denied a new gas pipeline application, there are instances where the pipeline route has changed due to environmental, safety, or other concerns brought to light during the FERC proceedings.

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.