This week’s Pipeliners Podcast episode features David Slavin of Burns & McDonnell discussing the fundamental elements of designing pipeline gas metering and regulating stations.
In this episode, you will learn about the importance of metering and regulation in aiding the prevention of accidental ruptures, the key components of a metering and regulation station, and how metering and regulation varies between Transmission and Utilities.
Designing Metering & Regulation Stations: Show Notes, Links, and Insider Terms
- David Slavin is a Senior Project Engineer at Burns & McDonnell. Connect with David on LinkedIn.
- Burns & McDonnell is a family of companies bringing together an unmatched team of 7,600 engineers, construction professionals, architects, planners, technologists and scientists to help those who work in critical infrastructure sectors deliver on their imperative responsibilities.
- Access David’s SGA 2020 conference webinar, “Natural Gas Station Best Practices,” sponsored by Burns & McDonnell.
- Read a white paper from David Slavin on improving natural gas distribution systems to ease pressure risks.
- Read a blog by David Slavin on the benefits of a standardized approach to pipeline M&R station design.
- Read a blog by Evan Montz of Burns & McDonnell discussing the PHMSA’s Mega Rule Phase 1.
- Burns & McDonnell is a family of companies bringing together an unmatched team of 7,600 engineers, construction professionals, architects, planners, technologists and scientists to help those who work in critical infrastructure sectors deliver on their imperative responsibilities.
- Metering & Regulation (M&R) Stations provide the control with information needed for any custody transfer point, acting as the toll booths of a pipeline system.
- The Merrimack Valley gas explosion in Massachusetts in September 2018 was the result of excessive pressure build-up in a natural gas pipeline owned by Columbia Gas that led to a series of explosions and fires. [Read the preliminary NTSB Accident Report]
- PHMSA (Pipeline and Hazardous Materials Safety Administration) is responsible for providing pipeline safety oversight through regulatory rulemaking, NTSB recommendations, and other important functions to protect people and the environment through the safe transportation of energy and other hazardous materials.
- GPAC (Gas Pipeline Advisory Committee) is organized by PHMSA to review their proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness, and practicability of each proposal.
- The Mega Rule is a set of new pipeline safety standards issued by PHMSA in October 2019 that brings 500,000 miles of pipeline under federal jurisdiction to ensure the safe transport of gas product.
- 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.
- Access the AGA whitepaper, Skills and Experience for Effectively Designing Natural Gas Systems.
- CEESI (Colorado Engineering Experiment Station Inc.) performs NIST traceable primary and secondary calibration for numerous types of flow meters and fluids. In addition to quality calibrations, CEESI offers calibration-related engineering services, valve testing, and a wide range of flow measurement training services.
- SwRI (Southwest Research Institute) is one of the oldest and largest independent, nonprofit, applied research and development organizations in the United States.
- Coalescing Filter is a device used to separate vapors, liquids, soluble particles, or oil from some other fluid through a coalescing effect. The coalescing effect is the coming together of liquid aerosols to form a larger whole which is easier to filter out of the system due to increased weight.
- Marcellus Shale is a rock formation that covers multiple U.S. states in the Northeast and Midwest region. According to the USGS, Marcellus contains approximately 84 trillion cubic feet of undiscovered, technically recoverable natural gas and 3.4 billion barrels of undiscovered, technically recoverable natural gas liquids.
- DI system (Direct Injection) is a system where natural gas is directly injected into a line.
- Cryogenics is a system used to extract natural gas liquids (NGL) from natural gas.
- BTU (British Thermal Unit) is the amount of energy needed to raise 1 pound of water by 1 degree Fahrenheit while at sea level.
- Odorization is the process of injecting an odorant into a gas stream by an odorizer or odorant injection equipment. The purpose, of course, is to make the gas smell so that it can be detected, because, in its natural state, natural gas is odorless.
- Odorant Fade occurs when physical and/or chemical processes cause the level of odorant in gas to be reduced.
- Mercaptan is also known as methanethiol and is a harmless but pungent-smelling gas which has been described as having the stench of rotting cabbages or smelly socks.
- Hydraulic Actuators use pressurized gas from a pipeline as its power source.
- Meter proving is a method of physically testing the accuracy of a meter through the proving process of measuring temperature, pressure, flow rate, and density against a known prover.
- Ultrasonic Flow Meters measure the velocity of a fluid using ultrasound technology to calculate volume flow.
- Orifice Plate is a device used for measuring flow rate, for reducing pressure, or for restricting flow of product flowing through a system.
- Coriolis Meters measure mass flow of natural gas and liquid, as opposed to just volumetric flow. Either gas or liquid flows through a tube which is vibrated by a small actuator to create the measurement.
- Attenuation Tees are placed in meters to reduce noise effects that can alter the measurement of product flowing through a system.
- RTU (Remote Telemetry Units) are electronic devices placed in the field. RTUs enable remote automation by communicating data back to the facility and taking specific action after receiving input from the facility.
- ControlWave Micro is a highly programmable controller that combines the unique capabilities of a programmable logic controller (PLC) and a remote terminal unit (RTU) into a single hybrid controller.
- The ROC800 combines the ruggedness and low power consumption of a RTU, the scalability, speed, and control of a PLC, and the audit trails and historical data of a flow computer enabling the measurement, control, and optimization of oil and gas operations.
- EFM (Electronic Flow Meter) measures the amount of substance flowing in a pipeline and performs other calculations that are communicated back to the SCADA system.
- PLCs (Programmable Logic Controllers) are programmable devices placed in the field that take action when certain conditions are met in a pipeline program.
- Maximum Allowable Operating Pressure (MAOP) is a pressure limit set, usually by a government body, which applies to compressed gas pressure vessels, pipelines, and storage tanks.
Designing Metering & Regulation Stations: Full Episode Transcript
Russel Treat: Welcome to the Pipeliners Podcast, episode 146, sponsored by Burns & McDonnell, delivering pipeline projects with an integrated construction and design mindset, connecting all the project elements, design, procurement, sequencing at the site. Burns & McDonnell uses its vast knowledge and the latest technology with an ownership commitment to safely deliver innovative, quality projects. Learn how Burns & McDonnell is on-site through it all at burnsmcd.com.
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. To show that appreciation, we give away a customized YETI tumbler to one listener each episode.
This week, our winner is Danny Scott with Riviera Utilities. Congrats, Danny, your YETI is on its way. To learn how you can win this signature prize pack, stick around until the end of the episode.
This week, David Slavin, with Burns & McDonnell will be joining us. We’re going to have a conversation about designing metering and regulating stations, a subject near and dear to my heart. David, welcome to the Pipeliners Podcast.
David Slavin: Hey. Thanks for having me, Russel.
Russel: If you could, would you give us a bit of your background, a bit of introduction, how you go into pipelining?
David: Absolutely. David Slavin. Been with Burns & McDonnell since 2011. Since then I’ve worked with gas transmission and gas utility companies across the country, roughly about a dozen different companies. I’ve been responsible for the installation of around 40 to 50 different M&R stations, both at the transmission level but also at the utility level.
Russel: Let’s start with a fundamental question. What is metering and regulation, and why do I care?
David: Good question, Russel. Metering and regulation is just fundamental. Main purpose of an M&R station is to meter the gas. Typically, you’ll need these points of change between a transmission company and utility company but also to regulate the gas. Within a utility company, you have to step the pressure down to eventually provide the customer the gas that we’re supplying.
Russel: If people follow incidents, there was an incident in 2019 in Massachusetts where there was a problem with a regulator station when they were changing out old cast iron to newer plastic pipe. They had a failure in regulation, which caused higher pressure gas to get to the delivery point and caused a whole lot of problems. It’s a very critical piece of the gas infrastructure.
David: Yeah, absolutely. There’s been a lot of lessons learned that come out of that Merrimack Valley incident. It’s really driving our industry, what we know about overpressure protection, and where the industry is going in that regards.
Russel: I think that’d be a great place to land. In fact, I know that the Gas Pipeline Advisory Committee is meeting over the next couple of days as we record this to talk specifically about some new rulemaking around rupture detection and gas systems. I would say that’s an advanced topic in this domain, maybe, but it might be something else we talk a little bit about.
David: Definitely. One other thing that came out of there is the professional engineering license requirement. There’s a lot of push now that everything gets sealed, but that has a lot of implications for gas utilities, even these engineers within the industry.
Russel: Exactly. Where do you go to get a seal? Where do you get to go to get qualified, to have an engineering seal, to do metering and regulation? That’s a whole another interesting question, right?
David: Yeah, that’s a deep dive. If you look at the state of California and a lot of the civil engineers, they won’t give them a professional engineering license within the natural gas industry because they don’t see it as a civil type field. Pipeline engineers are civil, mechanical. We have all diverse backgrounds.
Russel: Pipeline engineering is a specialized function that really you learn and practice after you get out the door. That’s what we’re going to talk about, is what have you guys learned doing metering and regulation? I’ll ask this question next. Kind of walkout, what are the key components of a metering and regulation station?
David: That’s good. Maybe, we’ll start from where we interconnect with either the producer. First, we have to filter the gas. There’s a lot of discussion on filtration and what type of filtration it depends at the gas transmission level. We typically use coalescing filters. Also, it depends on the quality of gas.
For example, a lot of the gas we get from the Marcellus Shale, it’s a lot wetter, a lot richer. A lot of times, if you’re getting gas from maybe an older supplier, they can have issues with compressor oil.
It’s really important for the utility to want to protect the gas coming into their system. At that level, a lot of times, you will find these more two-stage, horizontal type filters, coalescing type elements.
From there, when you get to some of the lower pressure down in the distribution level, a lot of times, we’ll use simpler devices. We might use a basket strainer or a Y strainer. It just depends on what we’re protecting and what we’re trying to achieve at these facilities.
Russel: Probably a good idea to talk a little bit about the different classes because, typically, when you talk on the upstream side, when you talk about the gas coming off of the gas plant and the first place I get pipeline quality gas, generally, what I’m doing there is trying to get you the right concentration of methane. I’m stepping the pressure up.
On the other end, I’m taking that higher pressure gas that’s traveled through these pipelines, cleaning it up, and stepping the pressure down to make it appropriate to burn it at your cooktop.
David: Exactly. A lot of it depends on what type of gas plant. Are you downstream of a DI system or is it maybe a refrigerant system, like a cryogenic system? A lot of times, cryogenic gas is a lot drier. It’s not very wet. You expect the quality to be pretty good.
One of the things related to filtration is if you’re operating like a waver pipe, for example like the REX line, it has a 0.8 design factor. That’s called a waver pipe. That’s required by code that you take that gas through a coalescing filter.
It’s interesting, though, because you’re like, “Well, how did PHMSA come to the decision to make wavered pipe filtered through a coalescing filter?” Some of the engineering reasons behind it, maybe just to keep liquids out of the transmission line for you weren’t having internal corrosion. They were worried about the smaller wall thickness on your mainline pipe.
A lot of times, when you’re talking about coalescing filtration, you’ll see that much more at the transmission level, maybe at the city gate level, but less within the utility company’s distribution system.
Russel: The operating assumption is that the heavy-duty gas quality level filtration is at the inlet to the distribution system. From there, I don’t need to do that again.
David: Exactly. Just protect it right there at the beginning,
Russel: From there, it’s more about things that might get into the line that I got to keep from running further down the line.
David: Exactly. Some of the problems you get, though, some of the older systems, they didn’t put in that initial coalescing filter to protect their systems. Now, they’re up the creek because this is already within their system.
Now, we’re seeing a lot of problems within the gas utility system of just regulators that are gunking up. You’re seeing this white film, especially when we get higher-pressure cuts. It could be elemental sulfur that’s dropping out.
Russel: The other thing that people don’t realize is that gas quality changes over time. If you think about just gas in the Northeast, 20 years ago, most of that gas was coming off either production in the Gulf Coast being moved up Northeast or was off of old stripper wells on cold seam, which has got a lot of water in it, but it’s pretty lean gas.
David: It used to be a lot more bone dry gas. Now, with all the gas from the Marcellus, you get Btu levels of 1,100 pretty easily, pretty regularly now.
Russel: 1,300 and 1,400 in some cases, too.
Russel: It’s not just about Btu. This gets really interesting from a very technical measurement standpoint. When you start talking about, “Well, I’ve got a lower concentration of methane but I’m getting the Btu up by putting the heavies in with the methane,” that gas doesn’t behave the same as something that gets to the Btu content as pure methane.
David: A perfect example of that is odorization. When you have more ethane in your pipeline system, the half-life of your odorant is much higher. We’re seeing this phenomenon with odorant fade across the gas utility system, which is becoming a real issue in the industry.
Russel: That’s interesting. That’s a whole new one on me. I guess I’m not working close enough to that end of the pipeline system these days.
So, we talked about separators. Now, you’re teeing up odorization. That’s another big thing that’s typically done at the interconnect off the transmission line and then, again, other places throughout a system. For those that don’t know, what is odorization? Why is it important?
David: Odorization is some type of mercaptan, depending on which region you are in. England has their own version of the THT versus TbH that we use. The purpose is that at the local level, at the customer level, if there was a gas leak, they would be able to smell and then report that gas leak.
A lot of times, we’ve standardized around packages that we put in. We have our tanks, and we odorize at certain rates. One of the things going back to that odor and fade discussion — something we’ve been doing a lot more often — is installing what we call like odor analyzers where we analyze that sulfur content to make sure that that fade issue isn’t happening as much.
Russel: That’s very interesting. I think those that don’t work in the industry or maybe those that work on the liquid side may not know this, but natural gas is odorless and colorless.
It is not odorized until it gets near to the point of use. It’s not odorized in production. It’s not odorized in transmission. It’s only odorized once it starts hitting the place where humans are going to be using it.
David: In the Mega Rule, it changed so many times over the last five or six years. One of the things they were looking at is odorizing all transmission pipelines. That just has a lot of repercussions because, historically, we don’t odorize it at the transmission level. It’s typically when we bring it into that distribution that we start to odorize.
Russel: There’s reasons why that’s a problem. Particularly, if you’re taking gas and you’re moving that gas 1,500 miles.
David: Then who’s responsible for the odorant? The customer at the utility level says, “Well, they already odorize the gas. Why do I need to re-odorize, and who takes responsibility?”
Russel: Exactly. Everything else, it’s complex. We ought to talk about the other key components of metering and regulation, and that’s the valves. Why don’t you talk to us a little bit about what are the typical valves used in M&R stations and such?
David: Absolutely. All kinds. [laughs] Just to break it down, mostly ball valves, natural gas, transmission. Distribution typically uses ball valves. That’s because you get zero leakage when you shut off. When it comes to like venting gas, we typically use plug valves because they’re more rugged. They can take that giant pressure going out without tearing out the seats.
Then a lot of times those valves are actuated, depending on where that valve is. For example, every meter skid, if it has two runs, for example, one of the runs will be actuated. It’s called a run switcher. That’s where you can open those runs as the flow rate starts to increase. As the flow rate backs off, those runs will typically close.
It’s all automated. It’s within that flow computer, but it is part of the process. Typically, we’re using a beta style, low-pressure pneumatic actuator. Some of our bigger valves, maybe 16-inch and up, we use a gas or oil hydraulic actuator like a Shafer or maybe a direct gas actuator like a Biffi.
Russel: What about the meters themselves? Where were we 15, 20 years ago? Where are we now, and where are we headed?
David: That’s a fun discussion.
Russel: I’m challenging you because to cover that in two or three minutes is not easy. [laughs]
David: Historically, everything was orifice plate. We all did orifice plate. There’s thousands of orifice plates still out there in the industry. From there, the problem of orifice plates is you have a low turndown on an orifice plate, so you can’t really cover a good range.
Russel: Explain for those that don’t know. What is a turndown?
David: For example, an orifice plate, you get typically about a 1 to 10 turndown, which means that I can flow at 80 feet per second down to 8 feet per second. It’s a factor of 10. You’re anywhere from 1 to 5 to 1 to 10 on an orifice plate.
Now, if you look at an ultrasonic meter, you’re closer to 1 to 100 turndown or 1 to 1,000 turned down even. You can just cover a longer range of the flow. Orifice plates, you’d have to put in a lot of runs to cover that sequencing for you because your turndown rate was so low.
Russel: You also have to make orifice plate changes because any specific plate didn’t have that much of a turndown.
David: Exactly, because each have their own different beta ratio. You have to set your plates up separately. Where we went from orifice plate is we went to turbines, and there was a good five-year period where we said, “All the gate stations are installing turbine meters.”
The problem with turbine meters is they have those cartridges in them, better turndown, a little more accuracy in measurement, but they have these cartridges that you have to replace. They’re an operation nightmare. There’s a little blip there when we went to turbines.
About six or seven years ago, we really shifted in the industry. We pretty much doubled down on ultrasonic meters. The technology got a lot better. The accuracy got better. The noise attenuation, that was a much bigger issue. The technology is getting a lot better though there.
Russel: They started making smaller meters. I don’t think that the four-inch meters and the three-inch meters have been on the market very long.
David: I agreed. Even when you use ultrasonic now, you limit yourself to about a four-inch. Sometimes, we use a three-inch on the ultrasonic. After that, either you’re doing orifice plates because your flow rate’s small enough to do it, or you’re using some type of like Coriolis meter where you get a lot better turndown. It’s a true mass flow meter. Coriolis.
Russel: What drives my meter selection? When I’m looking at an M&R station, what meters I’m going to put in?
David: Obviously, flow rate. [laughs] When you look at it, you really have to look at, “How do I cover this turndown?” You might have a power plant, for example. The power plants, they come on really fast, and then they hit these high loads. You have to cover this wide range.
A lot of times, what you’ll do is you’ll have maybe a trim run meter. You might use a four-inch meter, or this might even be an example. We use a two-inch Coriolis. From there, you might have the main flow run, which would be a 12-inch run. That way, you conserve that entire load for the power plant, but you’re able to cover that startup in that range when it comes to measurement.
Russel: Then the other thing you’ve got to address is reliability. What happens if a meter goes out of pressure control or a flow control goes out? Do I still have the capacity to deliver?
David: Exactly. You look at like, “Do you size your system for maybe 2 by 50 percent where you have a redundant?” Flowmeter run, even just the servicing on an annual basis, that allows them to shut it out and maybe inspect the meter tube but run through the secondary run or the redundant run.
That’s got to be part of that overall design philosophy. How do we space those meter runs? Even then, when you’re using ultrasonic measurement, one of the big things you have to really understand is noise attenuation. For example, you can’t put a flow control valve right next to your meter. That noise can get up into your meter, and it can cause hysteria.
Another issue — I saw a great presentation at the AGA Conference a few years ago, and they were talking about this. What can happen is, if you don’t establish your attenuating tees correctly, you can almost get the spiraling effect when it goes through your meter that can cause really hysteria on your meter. You’re not getting good measurement, accuracy.
Russel: What is hysteria, other than it’s making the measurement got crazy? [laughs]
David: It just points all over the place, up and down. Because the one thing is, when we have meter tools, we got to send them out for calibration. There’s only a few companies that calibrate meters. There’s CEESI, and there’s a SwRI, but a lot of us use CEESI to calibrate our meters. That’s just part of that.
We’re trying to get that baseline accuracy so we’re picking a bunch of different points anywhere from 5 feet per second to 85 feet per second, and we’re trying to define those on a plot. That’s how we calibrate our meter.
Russel: Again, we could do a whole conversation, actually do multiple conversations just on meter calibration and all the various aspects of that. One of the big challenges with the city gates is that CEESI doesn’t calibrate at the lower pressures.
David: Exactly. Another issue is when you do, for example, when you need to recalibrate, you have no other choice but to take it off and send it into CEESI to get it recalibrated. There is some advancements in that. For example, there’s a company out there, they’ll actually do meter proving on-site. There is a lot of advancements in that way.
Russel: I know one utility that is using secondary reference meters to do meter proving for all of their ultrasonics. They’re basically running them similar to how you would run a liquid meter and they’ve got provers that they can travel around and use to prove.
David: That’s actually really cool, because that’s a fundamental of liquid measurement. Is having that prover system that they can add up.
Russel: There’s, again, a whole ‘nother conversation around…In fact, I did a whole episode on liquid proving. That’s probably been two years ago now, but that hadn’t changed much. Anyways, there’s a lot going on in that domain around deploying these ultrasonics at lower flow rates and lower pressures, and outside of what the calibration laboratories can support. It’s interesting, actually.
Russel: Let’s talk a little bit about the flow and pressure control. How often is flow control the issue and how often is pressure control the issue, and how often are both the issue?
David: You’re right. You hit it on the head. Sometimes we have both. A lot of times, flow control — this is what you’ll see typically from a transmission company — that’s because they have to nominate a certain flow rate every day. That allows them to just control that flow rate throughout the day.
Some cases, they also are doing a pressure cut. That’s when you get a type of pressure with maybe a flow override or flow control with pressure override, where there’s some sort of pressure set point that they’re also trying to achieve. That gets a little more complicated with the controls, but there’s different ways you can set that up on your valves.
At a distribution level, most of the time, it’s not a flow control scenario. It’s much more of a pressure control scenario because what they’re trying to do is they’re trying to get into the high-pressure distribution center so they’re really trying to balance the pressure within their loop, the city loop. That’s when you see much more pressure control type arrangements.
Russel: The analogy I always use for this is that a utility doesn’t really have any control over the demand, because that’s driven by weather, cooling load, heating load, electric load, industrial load, and all these other things.
They have all these fancy algorithms for predicting load, but they don’t have control over it. What they do is they maintain pressure at the regulator station in order to support the load.
It’s like they’re blowing into the balloon and a whole bunch of other people have little straws and they’re taking out of the balloon. I got to make sure that they keep blowing into the balloon and the balloon doesn’t go flat. Consequently, pressure control. I’ve got to keep the pressure up to support the load. Where the transmission world, it’s more about nominations and all that stuff.
David: Exactly. Utility is much more just about making sure, I love the way you said it, make sure the balloon doesn’t deflate.
Russel: Exactly. I like simple analogies, man. That helps me understand things. What’s interesting in this conversation is we’re kind of walking out the pieces and parts. We’re talking about all the physical equipment. We haven’t talked about pressure sensors and all of that, or temperature and chromatographs and that sort of thing.
What pulls this all together is the flow computer. What are you seeing going on with flow computers and where do you think we’re headed with flow computer technology?
David: It’s funny because sometimes we get into these older systems, especially on the utility side and M&R stations, and you can see all sorts of RTUs that are out there. Just a lot of legacy RTUs that have a lot less IO. They don’t typically have a flow computer. They typically have a separate flow computer.
What we’re seeing now as more of a trend is we’re standardizing around two type of RTU/flow computers. That would be the ControlWave Micro and the…What’s the one I’m thinking about, Russel? I know you’re a measurement guy.
Russel: I don’t want to start listing because I’ll probably…
David: The Fisher ROC.
Russel: Okay, the ROC.
David: The ROC. That’s right. Because those have the EFM calculations already pre-programmed and so that allows you to do all those calculations right there on-site and control your system as well.
Russel: They also are highly configurable to support all the other automation that you need to do.
David: Exactly. The ROC has all the pre-programmed loops already set up. They’re just a lot easier. More out of the box, I should say. Whereas the PLC, the ControlWave Micro, that allows you to actually do a little programming yourself.
Again, most companies now have a standard USB drive. They go out and their tech plugs it in and they’ve been using that same program to control their M&R stations for a decade now.
Russel: Well, I’m old enough to remember when it was all pneumatic.
David: Oh, wow.
Russel: Don’t say it that way. That’s not real polite.
David: I was like, “You just aged yourself, Russel.”
Russel: I know I did. I know I did.
David: It’s funny because we’ll go out and we’ll look at these old city gates and they’ll have those like pneumatic pressure charts and there’s all those pneumatic instruments.
Russel: There’s a lot of that out there, particularly in the smaller gas utilities that are very, very simple. They don’t like automation. They like things that mechanics can work on and there’s good reason for that.
David: Definitely. Speaking more on that, it is where the industry is going. We got to be able to report MAOP exceedances. There’s a lot changing now with the Mega Rule. It’s not uncommon now we see a lot of companies going through this kind of replacement to bring their technology in.
Russel: Let’s talk a little bit about overpressure protection because I think that’s another key aspect of what you do. We’ve been talking more about the business side, the ongoings inside of M&R. Overpressure is more where safety begins to meet operation. Let’s talk a little bit about overpressure protection. I’ll ask the question, what is it and how do you implement it?
David: That’s a good one. I actually spoke at the AGA conference about this in May, just best design practice for overpressure protection.
One of the things that came out as part of the Merrimack Valley incident is AGA released a whitepaper — and I actually sit on the engineering committee — but it was a white paper discussing, what are some of the best practices to prevent one of these accidental ruptures in the future?
One of those being making things more remote control. Adding transmitters, automated valves, was one of the best practices. Back to the fundamental question, what is overpressure protection?
Overpressure protection for us is defined as…There’s three ways to provide overpressure protection. There’s the worker monitor control valve setup. You’ll see this a lot at the utility level.
There’s the relief valve. People aren’t as big of fans as the relief valve providing overprotection because, for obvious reasons, it releases gas to the atmosphere, it’s loud, but it is a much cheaper solution when you need to check that box.
Then there’s the automatic shutoff valve. You see the automatic shutoff valve a lot more at the transmission level. Thinking about utilities is they’re terrified that you’re going to shut their gas system in. That has big implications because then you have to go and re-light all your customers.
Russel: We had this conversation a year ago at AGA and the gas control committee about how utilities were originally designed for reliability, meaning they never let the burners go out. They’re designed to keep the gas flowing. They’re not designed to shut the gas off.
There’s a whole lot of risk associated with relighting. Turning the gas back on. There’s more risks with that than there is with venting the gas, although there’s other kinds of risk there. It becomes quite complex.
David: For example, when we do a monitor worker setup at a transmission level, it’s typically the worker, the one that controls the pressure, controls the flow, that one typically is designed to either fail last or fail open.
Then the monitor, which just senses the downstream pressure of the worker, that one’s actually designed typically to fail close. But if you get into the utility sphere, that’s not always the case. In the utility sphere, they might design both of those to fail open.
You nailed it on the head there. They’re more worried about having to relight and the risk associated with that than they are about the risk associated with overpressure event.
One thing, though, that they are starting to invest in now is tertiary protection. We’re seeing a lot of utilities across the country now putting in a third level protection. That would be like a relief valve, for example.
Russel: They basically have three levels of protection so they can sustain deliverability until they get to some point where they say, “No, at this point, we should not be sustaining deliverability. We should be shutting it down.”
David: Exactly. Then there’s a lot of discussion as, what should those set points be? For example, the state of Texas won’t allow you to set that secondary device, your monitor, above your MAOP. Where a lot of times, the gas system, we need that pressure. To maintain that reliability, to keep that balloon from deflating, we really need to maintain as much pressure as we can.
But then it comes into question, where’s that third set point for that tertiary relief? If I’m setting that at 60 pounds and then my monitor is at 55, now my worker’s down at 50, I just took a 10-pound pressure release before I even started.
Russel: We mentioned Merrimack, we ought to talk about it in this context. The problem with Merrimack is that the downstream sensor stayed connected to a line that was pulled out of service as they were doing an upgrade. Consequently, it was sensing no pressure and caused the regulator to open wide open. What that did was it took pipeline pressure gas all the way to the pilots in these homes.
Basically, you’ve got a little pilot light that’s got a nice little pretty flame that all the sudden, when you add all this additional pressure, that little flame becomes a blowtorch.
It’s complicated because you need to keep the gas on, particularly if you have critical loads for things like power plants and such, you need to keep the gas on, but you need to make sure you don’t get too much gas going down the line. Anyways, it’s a very important subject, probably warrants a whole podcast conversation just on that subject by itself.
David: Absolutely. That was actually another one of the best practices. It’s when you have these buried sensing lines, a lot of times, if you’re the operator out there, it’s hard to track where that sensing line is going. This is when you add in the human error side of operations.
Russel: Exactly. One of the things we’ll do for the listeners that are interested, we’ll take this AGA whitepaper, we’ll get that linked up to the episode, and we’ll drop that in the resources section on the website. Dave, we’re coming to the end of our time. We’ve taken a rock and we’ve skipped it across the top of a very deep lake here.
David: [laughs] Absolutely.
Russel: What would you want to say? Here’s the key takeaway about M&R station design. Here’s the key thing y’all know about it.
David: I guess one of the big things, it varies. Depending on where you’re at in the country, there’s just a lot of different practices. I’ll give you an example. For example, when you’re in the Northeast…We’ll be talking about monitor worker regulators. In the Northeast, they put those in different buildings.
That’s how they interpret the code where a lot of times in the Midwest, we put those on the same sched. Not all applications or not all designs fit every application is what my biggest takeaway to be. It just takes understanding what’s important for that customer or that utility in this, how do you apply that, and what do they see as their best practices?
Russel: You have to basically take some general industry understanding and apply it to particular utility’s needs?
Russel: Cool. Hey, David, thanks so much for coming on the podcast.
This has been awesome. I hope I have the opportunity to run into you at one of these conferences because I’m sure we could have a cocktail and talk in great length about measurements and laboratories, should you be doing demography analysis, if you’re going to do that on the utility side, where and all kinds of other things that would probably bored many others to tears.
David: [laughs] This is true. Absolutely. I really enjoyed it.
Russel: I hope you enjoyed this week’s episode of the Pipeliners Podcast and our conversation with David Slavin. Just a reminder before you go, you should register to win our customized Pipeliners Podcast YETI tumbler. Simply 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 at the Contact Us page at pipelinepodcastnetwork.com or reach out to me on LinkedIn. Thanks for listening. I’ll talk to you next week.
Transcription by CastingWords