This week’s Pipeliners Podcast episode features Faye Cradit discussing the new Rupture Mitigation and Valve rule and the different challenges the oil and gas industry will face getting it implemented.

In this episode, you will learn how the new valve rule affects multiple sections of code, the distinctions between a gas and a liquid, and how the rule leaves it up to the operators to define a rupture.

Rupture Mitigation and Valve Rule: Show Notes, Links and Insider Terms

• Faye Cradit is a senior pipeline engineer at Burns & McDonnell. Connect with Faye on LinkedIn.
  • Burns & McDonnell is a family of companies bringing together an unmatched team of 10,000+ engineers, construction professionals, architects, planners, technologists, and scientists to help those who work in critical infrastructure sectors deliver on their imperative responsibilities. With an integrated construction and design mindset, the company offers full-service capabilities with more than 60 offices, globally. With a mission unchanged since 1898 — make clients successful — Burns & McDonnell partners with companies on the toughest challenges, constantly working to make the world an amazing place. Learn more at burnsmcd.com.
• Valve and Rupture Rule is a newly updated PHMSA regulation. This rule establishes requirements for rupture-mitigation valves, such as spacing, maintenance and inspection, and risk analysis. The final rule also requires operators of gas and hazardous liquid pipelines to contact 9-1-1 emergency call centers immediately upon notification of a potential rupture and conduct post-rupture investigations and reviews.
• SCADA (Supervisory Control and Data Acquisition) is a system of software and technology that allows pipeliners to control processes locally or at remote locations. SCADA breaks down into two key functions: supervisory control and data acquisition. Included is managing the field, communication, and control room technology components that send and receive valuable data, allowing users to respond to the data.
• GIS (Geographic Information System) is a system designed to capture, store, manipulate, analyze, manage, and present spatial or geographic data.
• PIR (Potential Impact Radius) is defined by PHMSA (49 CFR subpart 192.903) as the radius of a circle within which the potential failure of a pipeline could have significant impact on people or property.
  • PIR Calculation: PIR is determined by the formula r = 0.69* (square root of (p*d 2)), where ‘r’ is the radius of a circular area in feet surrounding the point of failure, ‘p’ is the maximum allowable operating pressure (MAOP) in the pipeline segment in pounds per square inch, ‘d’ is the nominal diameter of the pipeline in inches, and 0.69 is the number for natural gas (the number will vary for other gases depending upon their heat of combustion).
    • The formula that an operator must use in calculating the potential impact radius and potential impact circle for a pipeline is explained in the definitions provided in 49 CFR 192.903.
      • A diagram displaying how a potential impact circle looks can be found in Appendix E to Part 192, Title 49 (Guidance on Determining High Consequence Areas and on Carrying out Requirements in the Integrity Management Rule). This guidance is for the integrity management rules for gas transmission lines, but the diagram displays the same basic concept as the potential impact circle for a regulated gathering line.
• Gathering Lines transport gases and liquids from the commodity’s source – like rock formations located far below the drilling site – to a processing facility, refinery, or a transmission line. Types include Type A and Type B.
  • Type A: Metallic and the MAOP is more than 20% of SYMS, or non-metallic and MAOP is more than 125 psig.
• Slack line is a condition when both liquid and vapor exist in a liquid pipeline at the same time. A similar term is column separation.
• LPAC (Liquid Pipeline Advisory Committee) and GPAC (Gas Pipeline Advisory Committee) are statutorily mandated advisory committees that advise PHMSA on proposed gas pipeline and hazardous liquid pipeline safety standards, respectively, and their associated risk assessments. The committees consist of 15 members with membership evenly divided among Federal and State governments, the regulated industry, and the general public. The committees advise PHMSA on the technical feasibility, reasonableness, cost-effectiveness, and practicability of each proposed pipeline safety standard.
• PHMSA (Pipeline and Hazardous Materials Safety Administration) ensures the safe transportation of energy and hazardous materials.
• The Marshall Incident refers to the Enbridge Incorporated Hazardous Liquid Rupture and Release, which occurred on July 25, 2010, in Marshall, Michigan. Read the full NTSB Accident Report.
• The San Bruno or PG&E Incident in September 2010 refers to a ruptured pipeline operated by the Pacific Gas & Electric Company. The rupture created a crater near San Bruno, California, caused an explosion after natural gas was released and ignited, and resulted in fires causing loss to life and property.
• AGA (American Gas Association) represents companies delivering natural gas safely, reliably, and in an environmentally responsible way to help improve the quality of life for their customers every day. AGA’s mission is to provide clear value to its membership and serve as the indispensable, leading voice and facilitator on its behalf in promoting the safe, reliable, and efficient delivery of natural gas to homes and businesses across the nation.
  • The annual AGA Operations Conference is the natural gas industry’s largest gathering of natural gas utility and transmission company operations management from across North America and the world. During the conference, participants share technical knowledge, ideas, and practices to promote the safe, reliable, and cost-effective delivery of natural gas to the end-user.
• API (American Petroleum Institute) has developed more than 700 standards to enhance industry operations. Today, it is the global leader in convening subject matter experts to establish, maintain, and distribute consensus standards for the oil and natural gas industry.
  • API 1130 defines the requirements for leak detection in pipeline operations. API 1130 is incorporated by reference into the U.S. pipeline regulations in 49 CFR 195.134 and 49 CFR 195.444 for how pipeline operators should design, operate, and maintain their computational pipeline monitoring (CPM) systems.
  • API 1175 establishes a framework for Leak Detection Program Management for hazardous liquid pipelines within the jurisdiction of the U.S. DOT (specifically, 49 CFR Part 195). API RP 1175 is specifically designed to provide pipeline operators with a description of industry practices in risk-based pipeline LDP management and to provide the framework to develop sound program management practices within a pipeline operator’s individual companies.
• HMI (Human Machine Interface) is the user interface that connects an operator to the controller in pipeline operations.
• Operator Qualification Training (OQ Training) refers to a process of training control room decision-makers who have the authority to act in normal, abnormal, and emergency situations. Read the Operator Qualification Overview published by PHMSA.
• HCA (High-Consequence Areas) are defined by PHMSA as a potential impact zone that contains 20 or more structures intended for human occupancy or an identified site. PHMSA identifies how pipeline operators must identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines that could, in the event of a leak or failure, affect HCAs.
• HVL (Highly Volatile Liquids) are a specifically defined subset of hazardous liquids subject to special regulatory requirements and means a hazardous liquid which will form a vapor cloud when released to the atmosphere and which has a vapor pressure exceeding 276 kPa (40 psia) at 37.8 °C (100 °F).
• O&M (Operations & Maintenance) is a comprehensive approach to performing pipeline tasks related to the operation and maintenance of gas and liquid pipeline systems. A robust O&M program provides personnel with the knowledge and understanding of each situation to enable them to correctly assess the situation and take corrective action.
• Listen to the Pipeliners Podcast episode Russel mentions featuring Jason Dalton discussing API 1130 and 1175 here.

Rupture Mitigation and Valve Rule: Full Episode Transcript

Russel Treat:  Welcome to the “Pipeliners Podcast,” episode 246, sponsored by Burns & McDonnell, delivering pipeline projects with an integrated construction and design mindset. Connecting all the elements, design, procurement, and sequencing at the site.

Burns & McDonnell uses its fast knowledge, the latest technology, and an ownership commitment to safely deliver innovative, quality projects. Burns & McDonnell is designed to build, and keep it all connected. Learn more at burnsmcd.com.

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Announcer:  The Pipeliners Podcast, where professionals, Bubba geeks, and industry insiders share their knowledge and experience about technology, projects, and pipeline operations. Now, your host, Russel Treat.

Russel:  Thanks for listening to the Pipeliners Podcast. I appreciate you taking the time, and to show our appreciation, we give away a customized YETI tumbler to one listener every episode. This week, our winner is Stephen Lamson with Hilcorp Energy. Congrats, Stephen. Your YETI is on its way. To learn how you can win this signature prize, stick around until the end of the episode.

This week, Faye Cradit with Burns & McDonnell joins us to talk about the new Rupture Mitigation and Valve Rule and the challenges associated with getting it implemented. Faye, welcome to the Pipeliners Podcast.

Faye Cradit:  Hey, Russel. Thanks for having me.

Russel:  Before we get going, I’d like to ask you to tell us a little bit about who you are, your background, and how you became a pipeline engineer.

Faye:  I am a senior pipeline engineer at Burns & McDonnell. I’ve been there about 10 months now, but my overall experience in the pipeline industry spans 18 years. Overall, integrity management program support to both gas and hazardous liquids operators.

Russel:  I’ve asked you to come on and talk about the Valve Rule and the Rupture Rule, Valve and Rupture Rule, I guess, is what people are referring to it as. This is a little new to you, is it not?

Faye:  I think it’s very new to everybody, really, just released in April. [laughs]

Russel:  You’ve done a lot of work around SCADA and automation, and that sort of thing?

Faye:  Not too much with SCADA directly. Really, just helping those integrity engineers at the operators focus on their programs, but not specifically into the details of SCADA.

Russel:  This ought to be fun, then, because one of the things that I understand about the Valve Rule is that it’s not like in one place. It’s spread all throughout all the sections of the code. It’s in integrity management. It’s in control room management. It’s all over the place.

Faye:  Right. I think this encompasses a lot of different groups within those operators, GIS, engineering, integrity, SCADA, gas control.

Russel:  Operations.

Faye:  Right. They’ll have to work together, and figure out how they’re going to tackle this rule.

Russel:  Yeah, that’s what I understand about the rule. It’s very broad in its implications.

Faye:  Yes, definitely.

Russel:  My experience has always been that these rules that require multi-discipline, multi-department collaboration, they’re the ones that are the toughest to get done.

Faye:  Yes, because you have to get all these different groups on the same page, collaborating, providing information to one another. That can be a difficult thing in itself, for sure.

Russel:  No doubt. At a high level, can you walk me through what the rule requires of the operators?

Faye:  This applies to both natural gas and hazardous liquids. It’s for new construction or entirely replaced, six-inch or over diameter pipeline segments, when you’re replacing two miles or more within a five-mile stretch over 24 months. It’s a mouthful.

Russel:  Yeah, that is a mouthful. Just take that right there, Faye, and just think about what an operator would have to do to identify when that occurs. Just that in itself operationally, and within the organization, and the project planning group, that by itself is a whole tangled mess.

Faye:  Sure. That planning group has to think about two full years of, “Well, if we do two miles here or one mile here and there, it affects these other miles that we’re replacing,” yeah, it might fall under the rule. You’re having to track over 24 months what you’re doing with your construction group, and your integrity groups. It can be a lot to plan.

Russel:  Placement is one. What are some of the others?

Faye:  Another thing, it does not apply to class one and two locations with a PIR of 150 feet or less. These are your lower-pressure, lower-populated areas for the gas lines. Another caveat was it does not apply to when you have a class location change replacements that are 1,000 feet or less for a continuous mile over 24 months. [laughs]

Russel:  We’re just getting started, and you’re already making my head hurt.

Faye:  They add a lot of words in there. [laughs]

Russel:  There’s a lot of analysis that’s new for pipeline operators coming out of this, just in terms of all of that. What else? Let’s keep going. Keep making my head hurt.

Faye:  Natural gas transmission and type A gas gathering, it applies to those, and then hazardous liquids and your carbon dioxide pipelines. I also think certain regulated gathering lines. Those are the ones that cross water crossings over 100 feet or more wide. Those are the applicabilities.

Russel:  There’s placement. There’s applicability. What next?

Faye:  I think the big one is the valve closure time, so your isolation time, is limited to 30 minutes. That is the big one. I think a lot of operators may not be able to meet that criteria, as of today. That’s something that’s going to definitely affect a lot of valves and systems.

Russel:  We should unpack that a little bit because that is from receipt of an alarm indicating the possibility of a rupture until shutdown and isolation is complete.

Faye:  Right. They did go further to define what notification of potential rupture is versus rupture identification. It’s from rupture identification when that 30 minutes starts. Notification of potential rupture could be the general public notifying the operator that they see something, or emergency response, or even, I guess, that first alarm on your SCADA.

Then identification is confirming that you have sufficient information to determine that it is a rupture, and not a false alarm.

Russel:  You have 30 minutes from the time you determine it’s a verified rupture to shut down.

Faye:  That’s correct.

Russel:  I’ve read this thing, but I’ll be honest, I don’t recall. Does it give a time frame for how long you have for determination whether or not you have a rupture?

Faye:  They don’t. Initially, they said 10 minutes, but I think every operator was different. They were like, “That may be too short to make that determination.”

Russel:  I actually went to the GPAC and LPAC meetings in DC when they were discussing all of this. Day one, they had all the gas guys. The gas guys, I don’t remember the exact, so anybody listening, don’t quote this. Go look it up. It was like, “If I see a pressure drop of 10 percent in 10 minutes, then I’m going to call that a rupture, or an indication of a rupture.”

In a gas system, that makes a lot of sense. Like everything else, it’s never that straightforward because it depends on where I am in the pipeline, and a whole bunch of other hydraulic details. Then the next day, the liquid guys did it, and the PHMSA guy said, “Well, what about 10 percent in 10 minutes?”

They were like, “No way.” You get 10 percent pressure changes in a liquid system all the time as just routine operations because hydraulically, gas is compressible, and liquids aren’t.

Faye:  You would get a bunch of false alarms.

Russel:  Ultimately, I think the way the rule landed is everybody gets to define it for themselves, but I think the expectation is your SCADA system is going to indicate possibility of a rupture, and it’s going to pick it up pretty quick. We’re talking minutes, not hours.

Faye:  Yeah, I agree with that. I think the intention is also, we’re not looking for your field guys to run out there, and verify it in the field that you have a rupture. You should be able to see that with your system from those alarms. They are requiring it to put written procedures down of how you’re determining this rupture.

In that procedure, you have to define what it is, how you are proving that, and then that you don’t need personnel to be in the field to do that.

Russel:  Right. I think that’s exactly right. This comes out of Marshall and San Bruno in particular, where one of the after analyses was how long it took them to isolate those ruptures once they knew they had them. Then the part about identifying a rupture through the system is in addition to the findings coming out of those two incidents.

I am pretty active with AGA’s Gas Control Committee. They have a thread going around right now about, “Hey, what are you doing to define what a rupture is?” I’ve commented on that thread, but it’s interesting, it’s not as simple as you might think it should be.

Faye:  Yeah, I think with everybody’s systems being different, and everyone operates differently, I’m curious what those responses are, for sure.

Russel:  They’re, “I’m looking for a pressure drop of this much in this time frame unless these other things are occurring.” I would frame it generally that way, and then the questions start becoming how big of a pressure drop, over what period of time, at what location.

What these guys ideally want to do is they want to make that common across the entirety of their system, and not have it be specific to every site because that becomes a lot of overhead to manage. It’s a lot of conversation going on. I would say that the ship has not come into port yet.

Faye:  I wonder, once these valves start, these RMVs start getting installed or replaced or retrofitted to existing valves, adding more points to the SCADA systems, how much that will help them determine, and actually define what that rupture is.

Russel:  Being a guy who works in this domain, what I will tell you is the challenge is not getting the alarm. The challenge is determining if the alarm is valid. If you look at the liquid guys and what they do with their leak detection systems, they’ll get an alarm, but they don’t get very many.

When they get them, most of what they get are false, meaning some kind of hydraulic change occurred that caused the alarm system to throw a line. Like, they inadvertently caused a slack line. That can throw a leak detection alarm. The bigger operators, the more sophisticated, mature operators, they have whole, very elaborate and streamlined procedure for walking through to determine if I have a rupture or not.

Most of those guys will do drills unannounced, where they actually get out on the pipeline and pull fluid off the pipeline to see if the leak detection system picks it up and the control room properly responds.

If you look at the Marshall incident, one of the things they did is they had leak alarms and then restarted, and leak alarms, and restarted. They did that, because they thought they had – or they did have – a slack line condition.

The challenge, to my mind, in this rule is not in how do I throw an alarm up? The challenge is, once I get that alarm, how much time do I give myself to say whether or not I shut down?

If you’re asking me, my advice would be that the time should be 10 to 20 minutes, and if you can’t rule it out in 10 to 20 minutes, you should shut down. Then there’s a whole nother conversation that’s not part of the rule about what do you need to do before you restart so you don’t restart into a rupture that you’ve been unable to identify where it is, or verify?

All of that is really quite complex. Everything’s easy if you talk quickly. I think, anyway. I hope I’m not stealing your thunder.

Faye:  Oh, no.

Russel:  That whole process is in the sweet spot of my expertise. We probably ought to talk about the distinctions between liquid and gas, and how they would define a rupture. What would be your take on what people are doing in the domain?

Faye:  In talking to a couple operators, I think they’ve followed that 10 percent drop within 15-minute standard rule. As you said earlier, that’s pretty safe for the gas guys to follow. Liquids was, yeah, I think it’s very different. I think it’s going to take a lot of hydraulic modeling, and they’ll have to take the extra step to actually fine tune what they’re doing, and get into a leak detection program.

I’m not too familiar with it, so I might lean on you more for this answer. [laughs]

Russel:  That’s fine. That’s great. I just did a podcast with Jason, who works with Marathon. He chaired the API 1130/1175 committee that recently revived those two leak detection standards. 1130 is about the computerized pipeline monitoring approaches, and 1175 is more the programmatic approaches, things like cameras, aerial surveys, people calling in, that sort of thing.

What I would say – and we talk about this in that podcast – is it’s pretty easy to catch a big rupture. It’s the small leaks that are a challenge. A big rupture in a pipeline system is going to have a very distinct pressure signature, just like a big rupture in a gas pipeline will.

The challenge can be, depending on where the rupture is located, and the way your control is set up, and the size of the rupture, I can actually have my control algorithms, if they’re on flow control, they’ll just move more fluid and hold the pressure.

The challenge, I think, for the liquids guys is getting clear about, “Well, if I see a pressure change of this amount in this time frame at this location,” typically at the discharge of a pump station, and maybe at the inlet. Anyways, it’s a bit more complicated than in the gas.

I think, again, you can get pretty clear about, I’m looking for a pressure change within this range and this time frame. Usually, you can go back and do analysis of results and operations of your SCADA system, take a hydraulic model, and you can determine that pretty easily.

Say, “If I see a pressure swing of more than 20 percent in this time frame, then I’m calling that a rupture.” They can get there. It’s much like the gas guys, they’ve got to do the hydraulic analysis, and get comfortable with it.

It gets really when you start getting into the smaller leaks. Then, that gets to, “What is a rupture?” How does the rule define a rupture?

Faye:  How they define it is that 10 percent within 15 minutes.

Russel:  Right.

Faye:  Now, they’re saying you can…They’ve left it open. As long as you have it in your written procedures, and can define what it is, and how…prove that you can identify in an event, that is a rupture.

Russel:  We’re leaving the definition of a rupture up to the operator with some guidance that’s provided in the rule.

Faye:  Yeah. They provide that baseline, and then it’s up to the operator to decide.

Russel:  Really, that makes sense because there’s a lot of different kind of operators, and ruptures will show up in different ways because that’s all an indication of the…Actually, you have a background in integrity. I have a friend of mine who’s an integrity engineer with lots of years of experience.

We got into this conversation about the definition of a rupture. Integrity management has a definition of a rupture as well, and it’s something completely different from how we look at a rupture from an operations perspective. They define a rupture – I’m not going to say this exactly correctly, but he defined a rupture – as once it occurs, it continues to enlarge.

For example, if I have a pinhole leak, I can maintain flow, and that leak will have a constant amount of leak. If I get a rupture, I’ve lost containment, and that amount of flow is just going to go until the entirety of what the pipe can do is just going straight out the pipe, just like it broke in two.

Faye:  Like a guillotine cut.

Russel:  Yeah. If you think about a seam weld failure, you can get there pretty quick. That’s an entirely different definition. That’s not useful at all in this context.

Faye:  It’s almost starting as a leak, and then propagating out to a larger hole.

Russel:  Yeah, exactly, exactly. It’s interesting. What guidance would you give operators around working to get their definition of a rupture put together?

Faye:  I think reviewing API 1175 for guidance on the proper procedures and steps to take to get your leak detection system up to standards, and then going through the process of hydraulic modeling and seeing, “Does this meet our spec, the industry spec?”

I think those are the main steps to take, an overview of your entire system, and see if you can apply that to your, or update your, own processes to meet those.

Russel:  I would agree with that. I think the other thing that the operators need to look at with a fair amount of deliberateness is the HMI and the data that they’re providing to the guy on the console that they’re relying on to determine whether or not a notification indicating the possibility of a rupture is actually a rupture.

Getting very clear about their OQ, and their training, and what modifications they need to make, and screens. Really, people are going to need to see very good pressure flow trends for segments of line, and they’re going to need to be able to find them quickly. They’re going to need to know what to look for.

Faye:  Yeah. I think a lot of it is going to come down to training. Control room, your controllers, what kind of training, how often. With this rule comes a lot of updates to those, as well as authority to shut down the line. I think there’s some that still require upper management or senior authority to actually shut down a pipeline.

Maybe adjusting those responsibilities might be part of this as well.

Russel:  That’s a very interesting comment, Faye. If you look at the control room management rule, and roles and responsibilities, generally, that authority exists with the controller. Certainly, I think your point is very well made, that if there’s any ambiguity there at all who has that authority, you need to drive that ambiguity out.

Faye:  Yeah.

Russel:  What our philosophy is in that domain is, if I can rule out a rupture, then I can clear the alarm and move on, but if I’m unable to rule out a rupture, I shut down. The way we frame that is, as long as I understand what’s going on, I can continue to operate.

The minute I don’t have understanding that explains what I’m seeing, I have a fiduciary responsibility to shut down. That responsibility resides solely with the controller. Then restart authority is where you move it up the chain.

Faye:  Yeah.

Russel:  I am sure there are still people out there that are running pipelines that are not operating that way.

Faye:  Oh, yeah, I’m sure there are. [laughs]

Russel:  I couldn’t name any, but I’m sure there still are. There’s one other thing I want to talk about just around SCADA is you may have to look at your communications, particularly for the gathering operators and some of the gas guys that don’t have…

Liquid guys typically have quite high poll rates and pretty reliable communications because they’re required to run their leak detection systems. This is going to require the gas guys to take a similar look. They’re going to need to look at their communications, and can they physically get the data in quick enough to see what they’re looking for?

That may require them to rethink communications at some critical sites where they’re monitoring for rupture.

Faye:  Yeah, definitely, there’s a lot of upgrades that may need to happen to these gas systems, for sure.

Russel:  What do you think, for anybody who’s a pipeliner that’s listening to this, what do you think they ought to take away from this conversation?

Faye:  I think this Valve Rule, I guess Rupture Mitigation Valve Rule, it encompasses a lot more than I think is on the surface, incorporating different groups within the pipeline companies, trying to coordinate with everybody that way, and then looking at, deep down, what is that definition of a rupture?

I think what’s interesting also is, on the liquid side, that valve spacing has changed quite a bit.

Russel:  Talk me through those details, if you would.

Faye:  The valve spacing, the valve locations for hazardous liquids pipelines weren’t very prescriptive before. They were, location, put one here, put one here, either side of the water crossing, protect populated areas, that kind of thing.

Run an HCA analysis, and determine where you might want to protect those HCAs, but there was no maximum, minimum valve spacing of 25 miles or 20 miles. Now, they’ve changed it so that there is a minimum, or, I guess, yeah, maximum spacing.

Fifteen miles for HCAs and then 20 miles for non-HCAs. Then for HVLs, it went down to 7.5 miles for valve spacing. It’s very prescriptive now on those, on that spacing for liquids.

Russel:  To me, again, this is an interesting point because I hear the operators’ pain associated with the cost of implementing that, and particularly the O&M cost of maintaining it, but on the flip side, what I also hear is the public’s expectation about when a pipeline has an incident, how quickly they should be able to isolate it, and how much they should be able to constrain the impact.

I can hear both sides of that argument, and it’s a tough one, which I think is why this came out prescriptive. It’s interesting, the conversation in the GPAC and the LPAC was not too much about the spacing, and the other stuff about coverage, and stuff that you talked about.

There wasn’t a lot of conversation about that. That was pretty quickly ratified, but there was a lot of conversation about what is a rupture, and how do I respond?

Faye:  Yeah, I think that this is a big thing. Spacing wise, I think, for the gas side, it didn’t really change that much. It still follows 179. Liquids, I felt was interesting just to see them actually put numbers to that spacing, instead of just up to the operator.

Russel:  Liquids is a very different problem because once I have the rupture, I have no way to not drain the pipeline. If I have a gas rupture, that vents to the atmosphere, or it creates a really impressive fireball on the porch, basically, but that’s relatively constrained.

When I have a liquid leak, it goes everywhere. It’s like pouring water out of a hose. It’s going to go where it goes.

Faye:  Yeah, if it hits a water crossing, it’s going to carry it, it could be, miles away.

Russel:  Exactly. The decision makes sense, and I think the liquid operators understand why the decision got made the way it got made. I think the thing for me that I take away is there’s a lot of complexity in this rule, and there’s a lot of departments within a pipeline that are going to be impacted.

For that to run smoothly, and to actually get the results you’re looking for, it’s going to require some fairly senior leadership in the pipeline companies to make sure that all gets put in place in a way that it’s orthogonal, understood, and working well.

Faye:  I agree. I think it’ll take some leadership to drive the initiative, and make sure everybody’s on the same page, and agrees on all those definitions, and what they’re going to do, and how to progress.

Russel:  I absolutely agree with you. I absolutely agree with you. Listen, this has been awesome. Anything else you want to say about the Rupture Mitigation and Valve Rule?

Faye:  I think generally, at Burns & Mac, we’ve been talking about it, and thinking on how to tackle it with our clients here. We’ve discussed doing phased approaches. Breaking it up into steps, I think it’s easier to handle that way, instead of just jumping right in. I think that’s something for operators to think about.

Russel:  I think that’s a really good point, Faye. I think this is one of the places where an outside third party can add a lot of value, particularly if they understand holistically what needs to happen because they can facilitate, and coordinate, and validate that everything’s occurring.

It doesn’t eliminate the need for the operator to build the capability and competencies, but having a third party that can see it from end to end can be very helpful.

Faye:  Just follow a road map, follow it step by step, and don’t jump right in, and get overwhelmed with it. That’s the way to go.

Russel:  Yeah, exactly. I couldn’t agree more. Listen, this has been fun. I’d love to have you back sometime. We’ll talk about integrity management.

Faye:  Yeah, thanks for having me.

Russel:  Then I can go to school.

Faye:  [laughs] Yeah.

Russel:  Thanks so much.

Faye:  Thank you.

Russel:  I hope you enjoyed this week’s episode of the Pipeliners Podcast, and our conversation with Faye. Just a reminder before you go. You should register to win our customized Pipeliners Podcast YETI tumbler. Just visit PipelinePodcastNetwork.com/Win and enter yourself in the drawing.

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Russel:  If you have ideas, questions, or topics you’d be interested in, please let me know, either on the Contact Us page at PipelinePodcastNetwork.com or reach out to me on LinkedIn. Thanks for listening. I’ll talk to you next week.

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