Pipeliners Podcast

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In the third of a series of episodes, Pipeliners Podcast host Russel Treat welcomes Dan Sensel, Jason Dalton, and Kyle Miller from Marathon Pipe Line to discuss how relief valves work and best operate in liquid pipelining.

You will learn a lot of math in this episode. We hope that you can apply the calculations, processes, and real-world experience relayed by the Marathon trio directly in your role. Also, listen for unique insight on the relief valve technology used right now in the field.

Relief Valves in Liquid Pipelining: Show Notes, Links, and Insider Terms

  • Marathon Pipe Line (MPL) is a subsidiary of Marathon Petroleum Corporation that owns, operates, and develops midstream energy infrastructure assets. MPL operates pipelines, storage tanks, and barge dock facilities.
  • Relief Valves control or limit pressure build-up in a system. They are designed to open at a pre-set level and relieve the system when the system exceeds the pre-set level.
  • The Boiler and Pressure Vessel Code is set by and updated by ASME (American Society of Mechanical Engineers). The code establishes rules of safety related to pressure integrity.
  • API 520 is an industry standard that covers methods of installation for pressure relief devices on equipment that has a maximum allowable working pressure of 15 psig or greater.
  • DOT 195 is a PHMSA standard for the transportation of hazardous liquids by pipeline.
    • DOT 195, Section 406 identifies the maximum allowable pressure in a pipeline in normal operating conditions.
  • Conventional Spring Valves are spring-loaded pressure safety valves that are set to open at a predetermined pressure.
  • Bellows Spring Valves are typically used when relief valves are piped near a closed flare system and the back-pressure exceeds 10 percent of the set pressure. Conventional valves cannot be used because the back-pressure is too high.
  • FMCSA (Federal Motor Carrier Safety Administration) is an agency within the U.S. DOT that regulates the trucking industry.
  • Thermal Relief Valves are used in a liquid pipeline to avoid pressure build-up from the evaporation of the liquid.
    • Thermal Check Valves are used during relief for thermal and shock relief protection.
  • BLEVEs (Boiling Liquid Expanding Vapor Explosion) is caused by the rupture of a tank structure containing pressurized liquid that reaches beyond the boiling point at atmospheric pressure.
  • Water Hammer (the Joukowsky Spike) is an equation that captures the maximum pressure change in a pipeline due to sudden valve closure.
  • Nitrogen plenum is used in Surge Relief Valves to support relief of a pipeline during abnormal conditions. The goal is to keep the system operable. Nitrogen plenum acts as a buffer to maintain the stability of the system.
    • A Nitrogen-charged Valve provides protection from over-pressure to control the flow of liquid in the line.
  • The Bellingham Pipeline Incident (Olympic Pipeline explosion) occurred in 1999 when a pipeline ruptured near a creek in Bellingham, Wash., causing deaths and injuries. According to the NTSB report, the cause of the rupture and subsequent fire was a lack of employee training, a faulty SCADA system, and damaged pipeline equipment. [Read the NTSB Pipeline Accident Report]
  • Blowdown is the process of removing liquid from a pipeline using pressure in the line.
  • Cv is a method to calculate the flow in a pipeline to understand the pressure drop and the flow rate.
  • MOP (Maximum Operating Pressure) is the maximum pressure that a pipeline can withstand based on its design, function, and strength.
  • Relief Inlet Pressure is a calculation that identifies at what point an operator must catch pressure at a closed valve location before it moves upstream and exceeds 110 percent of MOP.
  • Leak Detection is the process of monitoring, diagnosing, and addressing a leak in a pipeline to mitigate risks.
    • The Real-Time Transient Model (RTTM) for leak detection simulates the behavior of a pipeline using computational algorithms. The model, which is driven by the field instrumentation, monitors discrepancy between the measured and calculated values potential caused by a leak. RTTM uses flow, pressure, temperature, and density among many other variables.
  • 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.
    • PSI is the measurement of pressure to determine the desired flow rate.
  • PSMs (Liquids Pipeline Safety Management Systems) is a series of workshops hosted by API that is designed to provide liquids pipeline companies with tools and knowledge to implement API RP 1173.

Relief Valves in Liquid Pipelining: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 61 sponsored by EnerSys Corporation, providers of POEMS, the Pipeline Operations Excellent Management System, compliance and operations software for the pipeline control center. Find out more about POEMS at enersyscorp.com/podcast.

[background music]

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. We appreciate you taking the time, and to show that appreciation, we are giving away a customized YETI tumbler to one listener each episode. This week, our winner is Jose Ortega with Plains All American Pipeline. Congratulations, Jose, your YETI is on its way.

We have returning Jason Dalton, Dan Sensel, and Kyle Miller of Marathon Pipe Line. They’re going to talk about relief valves in liquid pipelining.

Well, Marathon Pipe Line and the fabulous three, welcome back to the Pipeliners Podcast.

Kyle:  Always a pleasure, Russel.

Jason:  Good to be here, Russel.

Dan:  Thanks, Russel.

Russel:  Guys, we asked you to come on this time to talk about relief valves, and obviously, relief valves is a very important topic in pipeline operations of all types. Maybe we could just start with, what is a relief valve and why is it important?

Kyle:  Sure. A relief valve, and if you read the Boiler and Pressure Vessel Code, you read API 520, more generally, a relief device is anything to dump pressure from an unsafe to a safe situation.

For us, with having thousands of miles of high pressure liquid hydrocarbon lines all over the country, protection of our assets and the protection of the public is extremely important to us. Of course, we abide by all the typical regulations. A lot of our lines are DOT 195 regulated, so we’re looking at the DOT 195, Section 406.

We use API 520 to help us size our pressure relief valves. It’s something that we take very seriously here.

Russel:  Yeah, no doubt. Certainly, it’s something that the regulators and other authorities are very interested in — how you implement your pressure protection program. What are some of the codes and standards? You mentioned API 520. What are the other codes and standards that might be of interest that would govern relief devices or relief valves?

Kyle:  Sure. To go into a little bit more depth about API 520, API 520 has a Part 1 and a Part 2. Part 2 is all about the installation, and maintenance, and the strategy for inlet and outlet piping.

It specifically contains the famous three percent loss rule, which has been the subject of much hand-wringing over the years that you shouldn’t have more than three percent of your set pressure should be non-recoverable losses. That’s all in API 520, Part 2.

Part 1 is all about conventional and bellows spring valves. It talks about rupture discs, and buckling pin valves, and everything associated with that.

I also mentioned the Boiler and Pressure Vessel Code. ASME Section VIII, Div. 1 has a lot of the same information for unfired pressure vessels. I mentioned briefly DOT 195. That’s the one that we typically find ourselves limited to. We’ve got 110 percent ceiling without question there.

We calculate our max operating pressure, per Subpart Part E, and then we never want to go above 110 percent of that. If we were just looking at ASME, there are provisions to go up to 116 or 121 percent if you have multiple relief valves in parallel or if you have a fire case situation.

For us, we design to no higher than 110 all the time.

Russel:  Right. That’s because the FMCSA regulations, the whole bunch of things that you don’t want to have to deal with kick in if you exceed that.

Kyle:  Right. If you look ASME B31.3, you can get an exception to go up to 120 percent if you keep it below 50 hours at a time, 500 hours per year, or even up to 133 percent if it’s 10 hours at a time or 100 hours a year. For us, it’s 110 all the time.

Russel:  I think that’s pretty common for liquid pipeline operators. The standards are a little different on gas versus liquid, but that’s pretty common.

I think your whole tee-up was really on-target here. We want to keep that pressure in the pipe. Consequently, we’re going to be conservative in terms of design and operating standards in order to accomplish that.

I think, however, one of the things that a lot of people don’t understand about these requirements is that 110 percent is anywhere in the pipe, regardless of whether or not you have a transmitter there.

And, that means that you’ve got to measure it where you can measure it with a transmitter. Then, other calculations, when appropriate, to determine if you get to that 110 percent due to hydraulic gradients, or transient changes, or any of those kinds of things.

Kyle:  We can get into this, but we have some tools, some industry tools and some in-house tools that we have developed that will do just that. We put in our worst-case flow rates, our worst case fluid properties, and we’re looking at the entire 20, 50, 100, 500-mile profile of the line and making sure that we’re violating that anywhere.

Russel:  I think that’s important for people to know that in liquid pipelining, pressure management’s a big thing. Understand that you can’t always directly measure the pressure. Sometimes you have to measure plus calculate to get that whole profile.

What kind of things would cause a relief to actuate? From an operating standpoint, what would cause that to happen?

Jason:  There’s actually several events in the pipeline world, and actually in the oil and gas industry, and in the process plants. Probably, if you look across our enterprise the highest number of relief valves we have installed are thermal relief valves.

If you think about if you’ve left a hose in your yard on a really hot day and you think it’s nothing’s going to happen. It ends up rupturing. That’s thermal expansion. What’s basically happening, as the hydrocarbon is gaining heat from the environment, it’s expanding. It doesn’t expand a lot, talking in the order of hundredths of a percent. It’s almost incompressible.

As it expands, it exerts pressure on the pipe. The pressure rises. You can either try to build a pipe strong enough that it can maintain that, which isn’t really going to happen, or even put in a thermal relief valve, which you either have a small valve that relieves teaspoons of liquid at a time to a tank connected to your piping, or you can use a thermal check valve, which moves it to a lower pressure piece of piping.

On the low end of thermal relief, that’s it. Some people in the industry call that sun pressure. We just call that thermal.

Another big one that is very serious is the fire sizing. Those are pressure vessels that store pressures above atmospheric pressure. They’re in a process facility. You design a relief valve to protect the vessel should it be engulfed in flames or fire so that the vessel doesn’t rupture and create a BLEVE condition.

Those are some of the most serious relief valves you can put in just because of the fact that they are your last line of defense on how serious that event is and how accurately you need to work.

In the pipeline industry, we’ve got events that are a little different than what our friends in the refining and process industries deal with. We’ve got a lot of transient events, water hammer events.

Those are the type of events that are caused by somebody closing a valve when you don’t want them to close that valve, or when a pump shuts down, or when you turn a flowing pipeline into a closed flow path. What’s different about all of those events is that on a thermal relief valve or a typical pressure relief valve, your gain in pressure is very slow but it’s sustained.

You’re going to get to 100 PSI. Five minutes later, you’ll be at 105 PSI. Five minutes later, you’ll be at 110. Then you relieve, and there’s a chance that the pressure is going to stay elevated right after the release set point.

On a transient event, that pressure weight is moving at about 3,500 feet per second, or the speed of sound in that fluid. The relief valve has to open fast enough to capture that pressure wave before it can propagate up the line and find a lower pressure piece of pipe.

It’s a pretty detailed analysis to make sure that you find where your surge initiation point is at and how much accumulation of pressure you’re going to get by the time that you get to where your relief valve is at. You have the relief valve set at an adequate pressure to kill that wave before it propagates up the line.

Russel:  That actually brings up another really interesting subject here, is there’s different kinds of relief valves that are designed to deal with these different types of operating conditions. Maybe one of you guys could lead us through what are the types of relief valves? What are the uses of those relief valves?

Kyle:  Sure. As Jason alluded to a second ago, we’ve got thermal reliefs constituting the overwhelming majority of the relief valves we have. Those are either going to be conventional valves or bellows style valves.

Conventional valves are ones that are affected by superimposed back pressure. If you are discharging, if you have a set pressure of 350 degrees and it’s relieving into a 100 PSI relief header, that raises your set point by 100 pounds. It’s really at 450.

When back pressure is a concern, you can specify a bellows style valve for that. Either way, we’re talking about spring-loaded valves. There are some oddball valves that we don’t use very much. Of course, rupture discs have been around for a long time. Those are one shot items. You’ve got to bust bolts and replace it.

We have a handful of buckling pins valves, which are also called out in API 520. The pressure relief valves to catch a transient, those, for us, are typically nitrogen backed valves where the spring is somewhere between 10 to 30 PSI of the set point. The other hundreds of pounds, maybe between 200 to 800 pounds, is made up of a nitrogen plenum that allows for the fast action of the valve.

For the listeners, it may be helpful to think of a nitrogen backed valve as just a very, very long spring because if you think about a valve that’s only about a foot tall, that’s just a big, old, honking spring in there to hold back a thousand pounds, how much pressure would you need to get that valve 10 percent open? It would be an unbelievable amount of pressure.

What the nitrogen plenum allows is for you to simply compress that volume of gas. Sizing the plenum is another fun math opportunity for us. [laughter]

It allows that valve to hit that fully open, that 10 percent open condition, that allows for full flow through the relief. If it’s an application where we have to catch it right away, if we want to catch that water hammer spike. That’s the density of the fluid times the weight speed times the change in velocity. Then, we’re talking about, typically, a nitrogen charged valve.

Russel:  Interesting. I know that there have been situations where there’s been pipeline incidents. Bellingham is one that comes to mind, where the failure of a relief valve to operate as designed…In that particular case, in Bellingham, actually the valve was improperly designed.

These relief valves are really critical but they don’t get exercised very often. What are the standards and practices around making sure that these things are going to operate when they’re supposed to operate at the pressure they’re supposed to operate?

Kyle:  With regards to the sizing, just like any piece of pipeline equipment it can be too small or it can be too big. We’re looking at the wide-open CV, of course, which is a coefficient of flow that represents what your gallon per minute flow would be to lose 1 PSI.

We want to make sure that the maximum line rate in our worst possible fluid conditions…Typically, we’ll take the highest gravity that we move and give it the lowest viscosity. We’ll come up with what’s the maximum possible rate and make sure that it can make its way through the relief valve without excessive pressure drop through the valve that would continue to build pressure.

Now, if you oversize the valve, the peril in that direction is that if you don’t open it enough you don’t take advantage of the blowdown characteristics upon closing. Blowdown is the ability of the valve to control its speed of closure so you don’t shatter or smack and create follow on transient events.

If you had a three or a four-inch valve application and you put in a 16-inch valve, that thing could be, maybe, one percent open and handle full flow. It’s going to smack back shut.

We want to make sure not only can it handle the maximum worst-case flow rate. We want it to open up enough that it can close slowly and carefully. Maybe it’s going to modulate open and closed for a few seconds or minutes and perfectly handle that relief again for us.

Another thing that we do is we try to flush our relief lines about twice a year. Jason, can you confirm that?

Jason:  Yeah. Russel, one of the things that we do as a DOT operator, we’re required to test our release systems once a year at an interval not to exceed 15 months. That’s a DOT regulation. We’re required to ensure that the relief valve opens as intended and that we can get fluid through it.

When we do that, we take the opportunity to flush our relief lines. One of the things that we’ve done is — a relief valve is not a normally operated piece of equipment. I think that’s where you’re getting at.

Russel:  Right, that’s exactly right.

Jason:  In that scenario, these valves…You don’t know if it’s going to work because it’s been months since it’s been exercised. One of the things that we do around that is that every relief event is treated as a serious situation.

Now, what you have heard is a relief valve is like your safety in football. You’ve got 11 guys on the field. If you look at your defense and 90 percent of your tackles are being made by the safety, you’ve got some problems with your linebacking corps.

That’s how we treat relief events. We don’t want that relief valve going off consistently. When it does, we figure out why it went off and try to make sure that that doesn’t happen again.

The testing of those is something very serious.

Russel:  I think it’s a really good point. If you’re operating your reliefs, then there’s some other process, or procedure, or something else that’s not working as it should be.

Jason:  Right.

Russel:  And then, of course, the flipside of that is for anything that’s mechanical, if it’s not operated very often, if you go long enough and don’t operate this, it’s probably not going to operate when it needs to. That’s why the DOT has the requirement to go out and test these things.

The other thing this conversation illustrates, for me, is that this testing of these relief valves is more than just putting pressure on it and seeing if it opens. It’s making sure that it opens and closes the way you want it to open and close within the design parameters for that particular valve and that particular operating scenario.

Jason:  Absolutely.

Russel:  That makes that a little bit more complicated, for sure.

Kyle:  Part of the additional complication of a nitrogen-charged valve is that, just like everything else there’s temperature dependence. When you have the plenum of nitrogen gas that’s sitting against the valve, when the sun comes up, just like the product is heating up in your pipe, your nitrogen is heating up in your plenum. It wants to increase that pressure.

We need a regulation system to burp off pressure as the sun comes up. Then, as it cools during the night, we don’t want the nitrogen pressure to drop too low and have a nuisance relief. We need a nitrogen supply standing by to augment that pressure.

Not only do we have, what’s the maximum permissible pressure that we would want to see in order to catch the surge wave? Now, you look at, what’s the losses through the relief valve? What are the losses through your relief line into your facility piping? What’s the pressure held back by your spring?

The remainder of that is the nitrogen that has to be allowed to drift within safe limits due to that temperature dependence.

Russel:  Once again, we’re illustrating the idea that all this is easy unless you know enough about it.

Kyle:  Right. I just want everybody to know how much fun we have.

Russel:  You did mention there’s lots of opportunities here to do fun math. I’m all over that. That sounds interesting to me. Speaking of math, how do you go about calculating and sizing one of these valves? What’s involved in doing that?

Kyle:  As I alluded to a little bit earlier, we have some homemade tools that we’ve had in our group for quite a while. We also have some industry transient software packages. If possible, we will use multiple means and then, occasionally, get out a piece of graph paper and look at the CV, look at the flow rate, look at the gravity.

As I mentioned, it’s not just about having a valve big enough to catch that spike, but to make sure that it doesn’t slam shut right away. We will look at our tank farm. Where’s the relief tank? What product is in it? How far away is it? What’s the size of the pipe? How many elbows? How many tees? How many valves? What are all the elevation changes involved? What are the properties of the relief valves that we typically select?

Of course, over time, you develop a little bit of an intuition. You go with your first guess. You do some iteration until you get there. It is a fun blend of using multiple tools, multiple concepts. Then, your intuition gets better over time.

Russel:  That’s right. That’s exactly right. That engineering experience, what you’re calling intuition, which might more formally be called engineering judgment. That’s a big part of all of this. There’s a lot of variables that go into sizing and determining set point.

That’s probably where I ought to go next, is there’s this whole exercise around selecting and sizing the valve. Then, there’s the other issue of, now we’re going to deploy it. We’ve got to figure out what set point to put on the valve. Maybe we could talk about that a bit.

Kyle:  Sure. With the selection of a set point, that’s where we’ll look at what’s the slate of all of the products that we will move on a system. What’s the heaviest? What’s the lightest? Lowest viscosity, highest viscosity. What’s our highest vapor pressure? That will matter.

Then, we’ll figure out, what is the maximum possible rate? Once we know that, then that becomes our worst-case situation. Historically, we’ve done a lot of modeling of an instantaneous closure. That is, of course, your worst-case situation.

This is a whole ‘nother conversation, but a 30-second, or one-minute, or even a two-minute closure on a 400-mile pipeline is not much different than an instantaneous closure. Instantaneous is typically the assumption we make. Then, we will make sure that we can catch that worst-case possible spike.

If the rate of the line, if the max rate, is slow enough and if the MOP is high enough, we may be okay. We may determine that any valve closure, either going into the facility or in the manifold, if that is intrinsically safe then we will issue a study that says, based on all these conditions relief is not required.

Otherwise, we’ll issue a study saying, based on all these conditions here is the exact valve that we need to buy. Here are the exact settings. We have a pretty robust peer review process on the hydraulic screw so nothing is ever issued by accident. There’s at least two or three reviews that goes into everything.

We like to check for every possible stone. That has served us well for quite a while. I don’t know. Jason, can you remember when the last time is we’ve had a mainline over-pressure event?

Jason:  It’s been over 20 years.

Russel:  Wow, that’s impressive. Over 20 years since you’ve had a relief valve operate for an over-pressure relief?

Dan:  No, no.

Kyle:  Since we have exceeded 110 percent on the main line.

Russel:  Right. I probably phrased that incorrectly. I’m getting at that this goes to the level of engineering expertise and the way you’ve tuned in how you guys do all of this.

You mentioned the review process. I think the review process is critical. You want one person to do the design, and somebody else to do the review, and a third person to take those folks and ask them a bunch of questions. Everybody brings their own perspective and set of experiences to the process. Even if I might, on one project, be the designer on another project be a reviewer. It needs to be a different brain that’s doing it.

Jason:  Our studies typically go through three reviews here at Marathon. They’ll go through what we call a peer review, which is just another hydraulics engineer to look at it. Then, they’ll go through a pressure control review so that…Most of the time that’s Kyle as the pressure control process leader, reviewing the study to make sure that he agrees.

Then, it goes through a supervisor review for one final pass.

Russel:  Again, we work a lot with smaller operators. Sometimes that can be challenging but they’ll partner with an engineering company. They’ll figure out a process to do a multi-stage review, if you will.

I think that’s a really important part of any of this kind of activity, the peer process. Everybody has their own perspective. I know in situations where I’m looking at something, I really look for and am appreciative of somebody coming and questioning my work. I really value that. It makes me better.

There’s one other thing that you guys had given me in the tee up to talk about a little bit. I want to ask about that. This is the idea of calculating the relief inlet pressure. We have now gotten out of — I don’t know anything about a relief inlet pressure calculation. Maybe you can help me and explain what that is.

Dan:  When we use one of our tools to look at the entire line, we’re looking at if we could…at what moment do we have to perfectly catch the pressure at that closed valve location?

What is the exact point we have to catch it before the wave propagates all the way back upstream and exceeds 110 percent of MOP, either at the upstream pump station or at some low lying area somewhere in between? As you aptly noted, Russel, before, there’s a lot of places we don’t have transmitters. 99.99 percent of the places we’re using calculated pressures.

We may exceed 110 somewhere in the middle rather than on one of the ends. Once we figure out what is the maximum possible pressure that’s allowed at the delivery location, we work down from that, as I mentioned. That may be that your surge spike is, let’s say, 150 or 200 PSI.

Then, maybe, over the next 15 seconds to 45 seconds, maybe you build another 300 PSI. Maybe it’s 500 total PSI. You can’t go above that at the delivery, to exceed 110 up at your pump station.

We’ll figure out that maximum point and subtract out, what’s the tank head? What are my tank farm losses? What’s my spring in my relief valve? Then, figure out, what’s my allowable nitrogen drift. We want to set that relief pressure as high as we can to trap as much pressure on shutdown as possible.

Our previous podcast was all about slack lines. Of course, if you want to avoid having a relief event on shutdown, you leave all your valves open and let the whole line go slack. You’re not worried about pressuring up. We don’t want that. We want to trap as much pressure as possible. We model out shutdowns to be very aggressive. We want to trap as much pressure as possible without overpressuring the line.

It’s understanding, once you figure out that max rate, once you look at your entire pipeline system from tank flange to tank flange, it’s understanding all of the components that back down from that maximum permissible pressure.

If 500 PSI is the highest pressure I can see there, that doesn’t mean that my inlet pressure is 500 PSI. I have to back out everything else that’s going to be a pressure loss that would be built up back pressure. To use API 520 language, that’s flowing back pressure.

It’s understanding the system holistically.

Russel:  Again, I think it’s an important part that, if you weren’t familiar with liquid pipeline operations, you might not understand. Simply stated, if I’m putting 500 pounds into the inlet of a 100-mile-long pipe, even if that pipe were flat laying on the ground, I might drop depending on just the sheer losses in the pipe of friction. I might lose 200-300 PSI.

Then, you’ve got all the other things you’ve got to calculate like elevation changes, and fluid densities, and on, and on, and on, to understand that, yeah well, for this relief valve at this point, even though my MOP is 500 PSI, I’ve got to set my relief at 150 at this location because of all those other factors.

Kyle:  The other element to the relief inlet pressure is, what is the proximity of your valve to where the bad news is happening? Because our discussion so far has assumed that your relief valve is right there next to your closed delivery valve, but you may have a situation where you’re hundreds of feet, hundreds of yards, God forbid you’re a mile away.

We do a lot of peer review maybe on other Marathon components. Sometimes we’re looking at other third parties and their studies and they say, “Hey, we’ll have a valve closure, but it’s okay because we’ve got a relief valve that’s a half-mile away.”

What we try to educate people on is that it’s going to take a little time for that positive wave to get to the valve, and then when that valve opens — hopefully rapidly — you have that negative wave that has to travel back to the point of valve closure. You may have a perfectly fast-acting relief valve, but you have to lower your set point to allow for that travel time.

You’re going to have the worst-case build, which is going to be at your closed valve. If that’s in a facility, and your valve is on the mainline, then your mainline set point is going to be maybe 150, 175, 200 PSI to protect that ASME Class 150 piping. You may have an ASME 600 Class mainline, but that relief may be doing double duty, and it has to protect facility piping that’s a few hundred yards away.

So that inlet pressure matters. It’s not just what’s happening at the build. It’s “can your relief valve save the worst possible location from overpressure?”

Russel:  Like everything else, I end up with a strategy around this. It’s not as simple as, “Well, I need to pick a valve and put it here.” It may be that if I’m looking inside a facility and I’ve got multiple products that can go into that facility and I’ve got a header, then I may be using different relief valves based on the product that’s coming through that part of the header.

Kyle:  Yes.

Russel:  Those kinds of things. Then when I look at, well, what am I doing on my pipeline relief versus what am I doing at my facility relief? They might be different. Of course, that gets more complicated when I start talking about interconnect parties. Because I may not have control over what my interconnect partner’s going to do on their side, but they’re impacting me and I’m impacting them.

Kyle:  Yes. Our typical delivery location will have two surge capable relieves. We’ll have one that’s on the mainline, that’s to protect against a delivery valve closure. Typically, it’s our head gate valve or one of the pig receive valves. That set pressure may be between 400 to 1,000 PSI. And that’s to protect that high class mainline pipe.

Then we’ll have another surge capable valve inside the facility that’s set to typically 175 to 225 PSI, and that’s to protect the ASME 150 piping. We have engineered it to the point where there is just almost no way to screw it up with closing either the delivery valve or one of the facility valves.

When necessary, the facility valve may be also doing pump stop surge duty if we have maybe two or three mainline units in a series that are putting up 1,000 or 1,200 pounds. If that wave coming backward maybe 300 or 400 pounds, then we’ve got that surge relief there to catch that also.

That’s all part of the peer review process. We’re trying to engineer out every potential human mistake.

Russel:  Yeah, exactly. That is the goal. You want the system to be perfectly forgiving. It’s like a lot of other goals that we talk about on this podcast that we’re trying to achieve. It’s like having zero incidents from a safety standpoint. Some of these goals may be impossible to get to forever, but they’re the only goals that make sense.

As we move forward and we get more operating experience and this technology evolves, we come up with new ways of doing things, and we learn from our history, and we get better, but we’re never going to be perfect. There is always room to get better.

I actually have found this quite interesting. I know enough about relief valves myself. I’ve sat through enough PSMs and know enough about pipeline operations to kind of have a conceptual idea of what they are and what they do, but for me, this has really been helpful in terms of understanding some of the details and complexities of working with these relief valves and why it’s important.

A lot of times I do the whole, here is my three takeaways, I don’t think I could get it down to three for this particular episode. That’s awesome. We’ll just say there is lots of takeaways. If you need to hear what they are, just listen again.

Kyle:  [laughs] Here, I’ll give you one. This is something that people can think about. Is that if you have a 20, 50, 100, 200-mile pipeline, that is a freight train. You cannot just bring a freight train to a screeching halt. I think you mentioned on our slack line podcast episode, you can slam a cold water faucet shut in your kitchen sink and the consequences may not be dire.

With the amount of energy, you think about the momentum of bringing a million barrels to stop in 30 seconds, it’s just not going to work. Sizing for your worst-case scenario, that’s what it’s all about. That is the million dollar question. Understand, how dangerous is your freight train? That’s the first thing you’ve got to wrap your mind around and everything else is fun math.

Russel:  [laughs] That’s awesome. That’s a great takeaway. I think you did excellent there. That’s wonderful. Well, gentlemen, as always, I appreciate you taking the time to do this. Looking forward to having you back as we work through some of the many other operating considerations in pipelining. Thanks again.

Kyle:  Thanks, Russel. Always a pleasure.

Jason:  Thanks, Russel.

Russel:  I hope you enjoyed this week’s episode of the Pipeliners Podcast and our conversation with the three amigos from Marathon Pipe Line, Jason Dalton, Dan Sensel, and Kyle Miller. Just a reminder before you go. You should register to win our customized Pipeliners Podcast YETI tumbler. Simply visit pipelinerspodcast.com/win to enter yourself in the drawing.

If you’d like to support the podcast, please leave us a review on your podcast player on your smart device. You can find instructions at pipelinerspodcast.com.

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

Transcription by CastingWords

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