This month’s Oil & Gas Measurement Podcast episode features John Lansing discussing ways technology is improving in the industry, how new inventions are impacting workers, and different revisions of AGA, specifically AGA 9.

In this month’s episode, you will learn about the history behind the ultrasonic meter and its advancements, why the AGA revisions are necessary over time, and how ultrasonic meters are increasing in popularity,

Ultrasonic Measurement Show Notes, Links, and Insider Terms

• John Lansing is the Director at RMG Americas, Inc. He has over 25 years of experience in gas ultrasonic metering. He was also awarded the American Gas Association’s Lifetime Achievement Award at the 2021 Operations Conference in Kissimmee, Florida.
• RMG Americas, Inc. is part of RMG.
  • RMG gas meter products use the latest physical and chemical measurement methods, allowing accurate measurement and analysis of gas quantity and quality. The RMG portfolio includes a range of products that support energy-efficient and environmentally friendly energy supply.
• 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.
  • AGA REPORT 9, 2022 Edition, 2022 – MEASUREMENT OF GAS BY MULTIPATH ULTRASONIC METERS. This report is for multipath ultrasonic transit-time flow meters used for the measurement of natural gas. It may be used for the measurement of other gases in consultation with the meter manufacturer and a competent professional.
• 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.
• 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 Meter – a sophisticated device utilized to gauge the flow of liquids or gases within a pipe by employing ultrasonic waves. These waves traverse the pipe in both the direction of the flow and against it. By analyzing the interaction of these ultrasonic waves with the velocity of the flowing substance, the flow rate can be accurately determined.
• The PRCI (Pipeline Research Council International) is the preeminent global collaborative research development organization of, by, and for the energy pipeline industry.

• Single-path Ultrasonic Meter is a meter utilizing a single pair of ultrasonic transduces that fire sound pulses back and forth across the pipe on a single, diagonal line, with one sensor downstream in relationship to the other sensor of the pair. The difference in speed of the sound waves moving with the flow and against the flow is used to calculate the gas velocity in the pipe.
• Multi-path Ultrasonic Meter is a meter utilizing multiple pairs of ultrasonic transduces that fire sound pulses back and forth across the pipe on different lines (paths), each with a different geometric cross section of the pipe.  By comparing the speed of sound of the different paths, valuable information can be obtained about the quality of the measurement data.  Most ultrasonic meters approved for Custody Transfer use at least 4 pairs of sensors.
• Ultrasonic Meter Diagnostics refers to the capability of many multiple path ultrasonic meters to analyze high speed data from individual senor paths and provide valuable data, including an overall health score, for the meter. This includes the ability to detect flow profile changes, swirl, sensor fouling, and liquids in the meter, all of which impact meter accuracy.
• Flow Profile refers to how a liquid moves within a pipe. A “fully developed” flow profile is one where gas near the pipe walls moves in at a uniform, but slower, speed around the entire perimeter of the pipe. Gas in the center third of the pipe is moving slightly faster, with no swirling or eddies taking place. A fully developed and consistent flow profile is critical for many meter types.
• Installation Effect refers to the negative impact on measurement accuracy and repeatability because the gas Flow Profile has been disrupted by the piping arrangement upstream of the meter or intrusions into the gas flow. A classic Installation Effect problem that creates inaccurate measurement is swirl within the pipe caused by multiple bends or elbows. Such swirl can persist for many pipe diameters downstream of the disruption. 
• Flow Conditioner or Conditioner Plate refers to engineered obstructions that are intestinally installed upstream of a meter to correct for known or unknown installation effects. Most Flow Conditions work by partially obstructing the gas flow, creating a differential pressure. The gas gasses through carefully placed and sized holes in the condition, helping to rapidly restore a fully developed flow profile.
• ANIS 150, 300, 600 … refer to the design Pressure Class of flanges used in construction of pipeline fitting and devices (such as meter bodies). The ANSI numeric value does not translate into a psi pressure rating, but increasing ANSI ratings handle increasingly high pressures. 
• Ultrasonic Meter Calibration typically refers to sending a meter (and often its associated piping) to a commercial flow calibration lab with extremely accurate reference meters that are traceable to NIST standards. The meter under test is temporarily installed in-line with the reference meters and flow is varied and adjusted to multiple points across the meter’s expected operation flow range. The meter manufacturer then uses the data points gathered to program adjustments into the meter’s microprocessor, reducing the measured error.
• Upstream is the operation stage in the oil and gas industry that involves exploration and production. 
• Midstream is the processing, storing, transporting and marketing of oil, natural gas, and natural gas liquids.
• Downstream is the process involved in converting oil and gas into the finished product, including refining crude oil into gasoline, natural gas liquids, diesel, and a variety of other energy sources. The closer an oil and gas company is to the process of providing consumers with petroleum products, the further downstream the company is said to be.
• GPA or GPA Midstream Association is a voluntary industry organization composed of member companies that operate in the midstream sector of our industry.  GPA Midstream sets standards for natural gas liquids; develops simple and reproducible test methods to define the industry’s raw materials and products; manages a worldwide cooperative research program; provides a voice for our industry on Capitol Hill; and is the go-to resource for technical reports and publications.
• BTU (British Thermal Unit) is a measure of the heat content of fuels or energy sources. It is the quantity of heat required to raise the temperature of one pound of liquid water by 1 degree Fahrenheit at the temperature that water has its greatest density (approximately 39 degrees Fahrenheit).
• Renewable Natural Gas (RNG) is a pipeline-quality gas that is fully interchangeable with conventional natural gas. The quality of RNG is similar to fossil natural gas and has a methane concentration of 90% or greater.

Ultrasonic Measurement Full Episode Transcript

Weldon Wright: Welcome to Episode 22 of the “Oil & Gas Measurement Podcast,” sponsored by GCI, the Gas Certification Institute, which has been providing measurement training, standard operating procedures, and consulting services to the oil and gas industry for over 20 years.

GCI proudly partners with Muddy Boots Online, helping fuel measurement increase efficiency in meter testing, witnessing, and sample tracking, improve route planning, and better manage schedules while providing their management concise and timely metrics for their teams. Visit GasCertification.com to find out how Muddy Boots can streamline your field operations.

Announcer: Welcome to the Oil & Gas Measurement Podcast, where measurement professionals, bubba geeks and gurus share their knowledge, experience, and likely a tall tale or two on measurement topics for the oil and gas industry. Now your host, Weldon Wright.

Weldon: Hello and welcome to Episode 22 of the Oil & Gas Measurement Podcast. I’ve got the great and powerful John Lansing here with me today. We’re going to talk a little bit about all things ultrasonic. It may get a little rambling at times, but John is going to share some of the new directions and all with us.

Before we get into that, John, thanks for being on the podcast with me. Tell us a little bit about yourself and what you’re doing now.

John Lansing: Weldon, thanks for inviting me. Let me give you a little background on my history in the ultrasonic world. I was an electrical/mechanical engineer at Cal Poly in Pomona in the 1960s and ran out of money. Went out looking for a job so I could go back to school. Ended up taking the first opportunity for SoCal Gas.

For the first couple, three, years, I ended up just digging ditches and building meter sets. Finally I had an opportunity to get back in the garage to work swing shifts so I could go back to school.

When I went back to school, I realized that I didn’t have enough time, being married and in the National Guard, to go for a double major in electrical and mechanical, so I just focused on mechanical engineering.

In 1979, I had an opportunity to go to a system subsidiary called Dual Fuel. There, we did high pressure natural gas. Once I got my degree, engineering decided that they would like to hire me to design the new installations at all our facilities to convert vehicles to run on natural gas. That was my first introduction into engineering at SoCal Gas.

After two years, my boss wanted me to go over to field services staff and learn a little bit more about the customer’s perspective on designing meter stations so we could do a better job. That was the end of my engineering career because I ended up spending the rest of my career at the measurement department because I enjoyed the measurement aspect of natural gas.

Now, one of the fortunate things for me, in 1987, I had the opportunity to develop the first flow computer system for SoCal Gas. Rule 636 came into place. We had to start building our customers on electronics. I ended up building a flow computer system using a Daniel Micro 3000 as well as our GC.

We did seven sites, handbuilt those with a couple of my friends. 7 Bcf went through the installation. We were within .34 of the chart recorders. After that, we ended up building another 46 sites. I ended up supervising that group for a while. Then we decided to do some reorganization at SoCal.

Around that time is when I first started attending the AGA Transmission Measurement Committee meetings. In the early ’90s, when I saw ultrasonics come out in 1993 at an AGA Operations Conference, I really got intrigued with it. I bought one of the very first Instromet ultrasonic meters for SoCal Gas that they produced here in the United States.

Another reorganization came in ’95. I decided that maybe it was time to move on. I ended up going to work for Instromet in 1996. I worked there as a product manager or a technical services manager, or both. In ’99, I went to Daniel. I was a product manager there, working for Kevin Warner for about six years and I left.

In 2006, to go to work for SECC. Worked there and ran the US ultrasonic operation until 2012. At that point, I left SECC and went to work for CC to promote a new product called C Smart that automatically monitors your ultrasonic meter and enjoyed a career there for five years. Then I left in 2017 to start my own consulting business.

In 2018, I met the chairman of RNG. We agreed on me as a contractor working pretty much full time in January of 2019. My role has been working with ultrasonic meters basically full time since 1996 when I went to work for Instromet. I’m still doing much of the same thing with RNG here.

During that period of time, I’ve been through over 150 points with HGA. I did achieve the Lifetime Achievement Award at HGA about two three years ago, so I’ve been an AGA TMC, Transmission Measurement Committee member before AGA 9 was initially started in 1994. That’s a little background on me. 

Weldon: I thought I knew everything about you, at least a lot about you. I learned something new just then. I never knew you were in the National Guard. I bet there’s some stories that go along with that one.

John: 10 years truck mechanic, hands on guy.

Weldon: Fair enough. John, where I would like to get to, the place we want to land today is talking a little bit about all the current interest and all current work going on around ultrasonic meter devices, specifically the smaller, the simpler the battery powered single path devices rather.

Before we do that, can you talk a little bit about AGA 9 – you mentioned earlier – that’s our standard for custody transfer meters. It’s probably been revised more than most of the other standards given the length of time it’s been out, but that’s really because this has been an emerging technology, right? Something new for us.

John: Yes, I would agree. In 1994, when I was still at SoCal Gas, I saw the ultrasonic meter technology and so did a lot of other industry people and realized that this is probably the wave of the future, no pun intended.

As a consequence, we started developing the first part of AGA 9. We called it a tech note. We developed the tech note which summarizes how an ultrasonic meter works, some of the basics and diagnostics and whatnot.

After two years in developing the tech note, we embarked on developing AGA 9, the first edition, which came out in 1998. That was probably the fastest we’d ever developed any kind of a document in the transmission measurement committee.

It was really driven by the end users, the industry people. At that time, there were really only three ultrasonic companies participating in the TMC that had ultrasonic products. That was Daniel. There was some FMC but also instrument in Panametrics.

Within two years, we developed the first edition. Couple of key things about the first edition was there was no required flow calibration. We made the assumption that if we dimensionally measure like an orifice meter, then all the information from the meter is going to be accurate.

We certainly found out that wasn’t true. I ended up sending hundreds of meters literally to Europe for flow calibration for clients and developed a tremendous database as well as other manufacturers on the performance of the meter.

After that first release in 1998, we embarked on developing an upgrade of a new version of the second edition. It was released in 2007. It had many changes, including flow calibration is now required for fiscal measurement. We put in some information relative to the piping design and whatnot.

It took a long time to get that document done. We didn’t really do it in a nice, orderly fashion. In other words, we talked about flow calibrating the meter before we even talked about what kind of piping is recommended. We spent a lot of time developing the third edition which came out in July of 2017.

There, we made some changes to the piping. The 2007 edition had piping with recommended Ts on the end, but they were optional. Most everybody thought those Ts or elbows were required.

We found out through a lot of testing, through CC who did an awful lot of testing every year, they basically provided one week of testing. There was a lot of testing also done, Southwest Research under GRI. We learned that installation effects sometimes over power flow conditions.

We made some changes in 2017 to talk about recommended meter piping, which included three different options now, without any Ts in the pictures, just basically straight piping with 10 and 10 and a flow conditioner.

Then we did whatever the manufacturer of the flow condition, the ultrasonic meter field or upstream requirements are, that could be a five and five, a three and eight. Then, the third option was if you believe the meter does not have enough flow conditioner, then you can do it with just straight piping based on the manufacturer’s recommendations.

That took us through, say, July of 2017. After that document was released, we ended up having a really nice document. A very solid document at that time. It’d been through quite a few iterations because the technology was evolving and more and more test data was being released by not only Southwest research, but by CC doing these tests, one week basically every year for 15 years.

They had a group of folks called the North American Fluid Flow Measurement Council that would suggest testing and whatnot, installation effects testing, and then CC would donate a week to accomplish that. A lot of data went behind the latest release of 2017.

Weldon: Cumulatively, that is a massive amount of testing over the years, right?

John: Yeah.

Weldon: New meter technology usually, we get three or four days a couple of times, as we develop the products. That’s a massive amount of testing.

John: Yeah, I think when you take a look at over 15 years’ worth of testing that CC did on installation effects, virtually all of it was done at the CC Iowa facility because these were large meters. Typically, we did 10s and 8s and 12s for installation effects testing of all types.

This was all driven by several key people in the industry, many of which have already retired. CC has now rejoined the conference and reinitiated the conference after the pandemic. I think they’ll get back to doing more testing in the future.

The amount of testing that GRI did in the ’90s with installation effects testing, as well as all the stuff that CC did really played a major role in the ability to develop a great document. I think that’s what AGA, the 2017 edition of the third edition, I think is really well done.

There’s things we’re still learning today. That’s what we’ll get to when we talk about the next edition. That’s a little background on the AGA development through the third edition anyway.

Weldon: AGA 9 was a little shift in approach for transmission measurement documents. At least it wasn’t in my opinion. Prior to that, if we start talking about ultrasonic orifice measurement, which has been around for what, are we at 140 or 150 years with orifice measurement now?

John: Yes.

Weldon: AGA 3 really focused around, here is how you build a device that is going to achieve the stated accuracy or uncertainty. With AGA 9, there was very much a shift, wasn’t there? That was the first time we said, “The manufacturer really knows about their device. We’re going to listen to how the manufacturer says they have tested and reached these accuracies.”

John: That’s why in the 1998 edition, we didn’t require flow calibration because it was new to most everybody. There wasn’t a lot of data out there. Quite honestly, the major reason why we didn’t require flow calibration, there was not a facility in North America that could calibrate a meter to full capacity above six inch.

Steve Caldwell and TransCanada Pipeline back then, now TC Energy realized that there’s a need for a large volume calibration lab. Both labs opened up very close to each other, one in the late 1990s and TransCanada opened up in the early 2000s.

Customers were still calibrating meters, a lot of 10 through 20 inch meters. We were air freighting those over to Pixar for the smaller meters up to 12 inches, and then Westerbork for the larger meters. Customers, they wanted to believe the manufacturer, but they wanted to see the data.

The data basically supported flow calibration was required. Initially we thought just looking at the speed of sound based on AGA 10, which is now part of AGA 8. If the speed of sound agreed with the meter, then the meter was accurate.

That’s the furthest thing from the truth. The profile coming into the meter plays a major role in the performance of the meter. We didn’t really understand all of that, at least didn’t want to recognize it back in the ’90s.

Again, the first edition didn’t require flow calibration because we didn’t have enough data to support it. We thought, as an orifice meter, we can dimensionally measure everything and get the same answer. Of course, flow profiles coming into an orifice meter, as well as an ultrasonic meter, have an effect on the performance of the meter.

With an ultrasonic meter, you can see this through the use of diagnostics. All the industry people started learning about the diagnostics and realizing there’s installation effects here that are causing accuracy shifts.

We want a level of performance on an ultrasonic meter that’s far greater than a typical orifice meter today. Therein lies kind of the background on how we ended up requiring flow calibration in 2007.

Weldon: When you look at it, and there’s a lot of young folks in our industry today, not nearly enough, because our industry is starved for people that want to learn the industry, want to become part of the industry. So many of them there don’t realize how ultrasonic meters have really overlaid the entire electronic flow measurement world.

We were still in the infancy of electronic flow measurement, of hooking a 4 to 20 milliamp transmitter up to a computer in the field. We were in that infancy for RFIS measurement when we started working on ultrasonic meters, right?

In fact, you made the statement earlier. Your first testing, I think you said, involved using a chart recorder as the standard you compare the ultrasonic against. Folks don’t realize that the ultrasonic meters, we think of them as very new, they’re a new technology.

They’re new, but we’ve been at this stuff for quite a while. It’s orifice that’s old.

John: You’re right. The ultrasonic technology is relatively new and even flow computers, at SoCal, we didn’t really get into using any kind of single run flow computers until the mid ’80s. The technology obviously has evolved tremendously in the last 20, 30 years as well as ultrasonics.

I think the one thing that made it a lot more understandable for the average person in the field is they got used to using electronics with flow computers before ultrasonic technology came along. They were already used to using a computer or a handheld device to interface with a flow computer.

The transition over to using an ultrasonic meter became a little bit easier, I believe than if it would have been rolled out, say 10 or 20 years before flow computers. The process of the better technology and digital signal processing is what’s really made ultrasonic technology today so much better than what we had in the ’80s and ’90s when it was all analog.

We looked at analog ultrasonic meters back then, but they weren’t reliable and they didn’t have the performance and range ability anywhere near what we need today. Today’s products are vastly superior than 20 years ago. There’s just no doubt about it.

Weldon: John, that’s also great stuff there. Kind of what started this conversation out, though, is we’re going on a couple of years now of talking  – let’s scrap that, let’s not say talking – arguing in the Transmission Measurement Committee about, “Hey, what do we need to do with AGA 9? Does AGA 9 need to be revised? Does it need another section? Does it need to be three or eight where there’s two or three parts?”

In all of that conversation, arguments are really focused on the same thing. The industry didn’t find a need for a smaller, less expensive ultrasonic meter. Then a subset of that is a single path battery powered meter.

Can you talk to us a little about what that path has been like and what direction we’re heading, not just with the Transmission Measurement Committee or the standards, but also, what’s the technology out there doing right now?

John: Yeah, let me talk about our fourth edition, which I hadn’t covered yet. Then we’ll get into discussing the battery powered ultrasonic meters. There’s been a need in the past for customers to pull a meter out of the field after the 2017 edition came out. They found that changing transistors and/or electronics may incur some significant shifts in the meter.

Reese Platzer at Enterprise Products was able to convince management to run a test on three brands of eight inch meters using four surface roughness from 40 mico inches to 250 micro inches. He published a paper at the AGA Operations Conference in 2019. From that, it showed that there was no real significant shift on the meter with all these different surface roughnesses.

His thinking was, “Why can’t I just buy a meter and have it calibrated at the lab with the same basic piping link and the same brand of flow conditioner, take that meter, go to the field, and then replace a meter that may have had some issues with transitioner failures or electronics failures and not have to send the entire meter run in?”

From that, we started in the fall of 2019 at AGA to develop the fourth edition. We were getting ready to publish that. Then I was working at RMG at the time, so I went ahead and did the same testing on the RMG meter. We had four brands of meters now in eighth inch with test data.

Many of these members on the TMC are also PRCI members, Pipeline Research Council International. Everybody said, “Wouldn’t it be nice if we had another line size to test?” PRCI funded another test with a 16 inch meter. We had two pipes. To save some money we only used two surface roughness pipings. One was 86 microinch. Then one was 353.

One of the things we did in the 3rd Edition was allow for rougher than 250 microinch above 12 inch. We went to the 353, which was the upper limit for 16 inch meters. Three meters were tested. That data was only available to PRCI paid members. Each manufacturer got their own data. It showed virtually no shift at all.

From that, Rick Spann, who was at Dominion at the time, was the chair of AGA 9. Reese Platzer and I were co-chair. We modified AGA 9 to come out with a 4th Edition. It was released in January 2022.

What this allows the customer to do is to buy a meter and piping, if it’s new, and send the meter to the lab prior to even the piping being done and then marry the piping up in the field or at the manufacturer where the piping is being built or buy a loose meter to replace a meter in the field.

This is especially important for our Latin American friends that want to build the piping down there but couldn’t afford to send all the piping up to North America. It was a huge benefit for a lot of people. It’s been taken advantage of. It’s starting to catch on a little bit.

Having said all that, the 4th Edition, as I said, came out in January 2022. At that time, we had already seen significant use of battery powered multi-path, two path, meters for the distribution market, basically ANSI 150.

These are not to be confused with your residential single path ultrasonic meters that are out there. That was being developed. There is a document out there that was developed by the then DMC, Distribution Measurement Committee, which has been joined with another group right now.

About a year and a half, two years ago, I proposed that we have a second and maybe a third document, maybe an AGA 9 Part 1, Part 2, Part 3. Part 1 would be maybe the current version.

Part 2 might be, say, a distribution type of meter. It’s a two path, battery powered meter, typically two through eight inch ANSI 150. I call it the McDonald’s meter, the larger volume meters to go after the smaller turbine and rotary meter market.

Then the third proposal was to develop a meter for the upstream/midstream market because the use of ultrasonics there has gained a lot of attention over the last 10 years. That part is now being developed by GPA. They’re working on that document at the time.

What we’ve decided to do, I think – we’re still talking about it – we’re actually just going to take our current fourth edition, modify it to allow for the separate areas where we talk about relaxed tolerances for these battery powered meters, maybe some relaxed performance requirements, because we are running on a battery and we want to get five years out of a battery.

Weldon, as currently under discussion, we’ll have a meeting on September in Pittsburgh, and we’ll have probably about a day discussion on that and really get serious about working on it. That’s where we’re headed right now with the fourth edition of AGA 9.

Weldon: There’s a lot of folks in my part of the world that don’t even realize those types of battery powered readers exist, right?

John: Yeah. There’s really only one manufacturer out there. RMG is now going to release the second one, and I expect other manufacturers to do the same.

Weldon: I know the first time I saw one. I had to stop, back up. “What the heck is this? What are you doing with it?” There’s quite a few out there in service. The price point has changed so dramatically as opposed to the other equipment.

John: The technology continues to improve. If we just look at our iPhones over the last five years, they get faster and more affordable. Oh, iPhones aren’t more affordable, but they do get faster and better performance all the time.

With mass production, hundreds and hundreds of meters a year, you can reduce the costs and whatnot. That’s what’s driven the whole industry. I expect you’ll see other manufacturers doing more of the same in the future.

In fact, just a little short history on that, a friend of mine from SoCal Gas came to me when I was working in SIC and said, “John, I love your meter, but I just like to have a distribution powered and battery operated meter to go after the NT150 Turbo meters.”

That’s where it all started. SIC developed that product and then released it sometime around 2013 or ’14. Then, it really caught on quite well. The industry has driven manufacturers to develop this product more than the manufacturer came up with it on their own.

Weldon: John, here’s a question we didn’t talk about earlier. Don’t throw anything at me for asking it. What if you gaze into your lens and crystal ball and look down the road?

Now, first of all, given the fact that there’s 100,000 plus chart recorders, still in custody transfer service today, given that fact, do you see a point that we’ll see widespread replace or maybe not replacement, beginning to install new battery powered ultrasonic devices in that upstream market, maybe some of the midstream market, what time period do you think that could occur?

John: I think that time period is very close. New products are being announced all the time that are available up to the NT600 that are running on battery power.

The thing right now is that the upstream market is all about cost driven. Right now, if they’ve got a new well going in, that would be a three or four inch senior fitting. Most people feel it’s cheaper to buy than an ultrasonic meter.

Once you take a look at the range ability, the lack of maintenance requirements, the ultrasonic meter often will be cheaper in the long term if you want to look at the long term, O&M as well as the capital.

The whole concept actually came from the same individual, Enterprise Products, Reese Platzer. He called me up one day in about 2008. He said, “Lansing, I’ve just started changing plates on orifice meters.”

Then after a couple, three years, the four inch meter, and then I got to take it out, put a three inch meter. I just need a low cost ultrasonic meter. Therein lies the reason why a product was developed at six specifically for that upstream market but it was not battery powered.

I think in the near future, you’ll see a lot more battery powered meters that are not quite the accuracy of a custody transfer transmission meter. Again, these meters are being subjected to not just pure natural gas. We got liquids occasionally going through it.

They’re typically used in allocation applications. Weldon, I think you’ll be seeing these meters in the upstream market in the very near future.

Weldon: I’m ready for it. We sit around in the upstream and the gathering world, and we say ultrasonic is not the greatest thing for this job, but we just don’t have anything better. It’s a matter of that price point. If the price point can come down with more production. Of course, battery power, to begin with, drops the installation costs. We’ve got to get people to embrace understanding that full ownership costs.

John: That’s the whole thing, is they just look at that upfront capital cost, but they don’t realize all the maintenance of fugitive emissions from him. Even when you have a senior fitting up, you’ve got some gas vented to the atmosphere. Nevermind the person having to drive to the site.

The thing is sold ultrasonics over the years, the diagnostics, and now with remote capabilities, we can monitor the health of a meter and we know immediately when we have liquids. It doesn’t hurt the meter.

The meters are so robust these days. You can hydrostatically pressure these meters and you’re not going to damage them, so they can handle the liquids coming through a meter and continue operational. Yes, they’re going to over register just like an orifice, but the nice part about an ultrasonic, it tells you when there’s a problem. With an orifice, all you have is differential.

Weldon: It tells you there’s a problem. Not only it tells you a problem, as you say not damaged by it. The entire maintenance issues behind the fugitive emissions reporting issues around ultrasonic meters is going to make them a better choice than orifice meters. It’s just a matter of time, how long it takes to get there.

Right now, we already have companies that are capturing data for every time they pull a plate, just to report that tiny amount of emissions, which is probably where we need to be. Like I say, we’re an industry with 100,000 plus customer credit for chart recorders out there.

I don’t see it as pulling smaller orifice meters out, but I can definitely see the industry reaching a point where they’ll install new meters in that upstreaming and gathering world as ultrasonics as soon as that price block comes down.

John: We’re already seeing that a lot of clients are using an ultrasonic meter to path traditionally MC600 in the upstream market. RNG does have a three path version of that. These are gaining in popularity.

Yes, they are more expensive than your traditional orifice meter, but if you’ve got a location where the customer has to drive along ways to check out a well or you’ve got a wide range of flow rates or you’ve got occasional slugging liquids which can bend the plate, the ultrasound meters are far better choice there.

It’s gaining in popularity and therein lies the reason why GPA has decided to embark on a program to develop a document specifically targeting these upstream-midstream kind of applications, as I call them.

Weldon: John, what else would you like to share with us? What other words of wisdom do you have before we decide to wrap this up?

John: I think the ultrasonic technology, as we see it today, is getting a little more mature, but the industry is gaining a lot more knowledge about diagnostics. I predict in the future that the ultrasonic meter will be able to compensate to some degree for these applications where you’ve got occasional liquids coming through.

We know there’s a program right now. If you understand the liquid loading, you can correct your orifice meter, but the trick is to know how much liquid you’ve got to come into the thing with the test separator. I believe someday with use of diagnostics, the ultrasonic meter can more accurately predict the amount of liquids and those compensate for the over registration.

I’ve done some work on that. I published some papers on it to show the effect of the meter diagnostics, and I think the [inaudible 31:11] eventually to correcting for the over registration and thus gives you a much better product for the upstream-midstream market.

The downstream market, the transmission market, is going to continue to embrace using ultrasonic meters going forward. I don’t think any customers today are going to be buying any large orifice meters probably above six or eight.

With new technology and we’re always evolving with new products, I think the use of ultrasonics is only going to expand much more so than it has in the last say 20 years and it’s going to continue to grow and evolve.

Frankly, I don’t see anything coming along like optical to replace it because ultrasonic is pretty robust when it comes to contamination issues. That’s why people continue to use them today in greater numbers than ever before. I think the future is bright for ultrasonics, and I don’t see anything causing it to go away anytime soon.

Weldon: That’s the same sentiments that I feel. I’m ready for that transition to shift and hard gear. Before we quit, John, do you want to give us the elevator speech on your Bright Sensor or do you want to put that off for a different time?

John: Essentially, what Bright Sensor has developed is what I call a digital colorimeter. It’s a device that can measure with no consumables, no calibration gas, no helium, no carrier, runs on two watts of power. It gives you less than one percent from a range of 750 up to about 1,300 BTU.

In reality, I believe after looking at some of the preliminary data I got from Europe, that this is more a two tenths of a percent device. Back in the ’90s, I did a paper in SoCal Gas called, “Do You Really Need a Gas Chromatograph?”

The whole point of the talk was that compressibility is important. This device does give me a Z, but at lower pressures. compressibility is an insignificant component compared to the billing that we’re doing in energy and not volume.

This device has been developed over several years and we’ve reached an agreement with RMG to distribute this product and we’re just now bringing it to the United States in the form of a portable unit, the RGQ 3 as we call it, which is battery powered.

You can go out there and hook it up to your distribution system and immediately get updates within a few seconds, and it does one second updates once it’s operational. The RGQ 5 is going to be more for your transmission market.

It’ll come complete with regulation and filtration. There’s a tremendous need for this product for gas turbines, RNG for renewable natural gas. It can handle up to 30 percent CO2, 20 percent hydrogen with a couple of added molecules.

The future is very bright for this product because I think it’s going to end up replacing a lot of chromatograms for these lower volume applications where they don’t need the expense and the maintenance issues that come along with a traditional chromatograph.

That’s going to be my focus now going forward with RMG is to try to get this product out there and it’s new to the world. There’s really no competitive product to it. It’s a game changer, sort of how ultrasonic technology was in the early ’90s.

That’ll be my focus going forward and I’ll be working primarily on getting and learning the RNG market a little bit, the solar gas turbine market, and all the pig manure and cow manure places, where they’re taking into digesters and coming up with pure methane gas. These are just ripe for a new product like this.

Weldon: I look forward to learning more about that in the next few months, John.

John: Really good.

Weldon: Thanks again for being on the podcast. I certainly appreciate it.

John: Thank you.

Weldon: Thank you, sir. I’ll see you at a show or a conference or a committee meeting somewhere soon.

John: In the near future. Thank you for your time.

Weldon: I want to thank each of you for listening, and I hope you find the insight on ultrasonic meter development and the new directions for this part of the industry interesting and informative. Please share our podcast with your co-workers, your boss, and others in the industry.

We’ll have a full transcript of the episode along with John’s contact info in the show notes on our website at PipelinePodcastNetwork.com.

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Ultrasonic Measurement Full Episode Transcript

The full episode transcript will be uploaded later this week.