This month’s Oil & Gas Measurement Podcast episode features Irvin Schwartzenburg discussing field flare measurement and the related challenges faced by upstream and midstream operators.
Due to Regulatory and ESG initiatives, the demands for accurate flare measurement and reporting are increasing. Irvin discusses the challenges faced in low pressure flare measurement in the field difference, and how facility design impacts flare measurement.
Challenges with Flare Measurement Show Notes, Links, and Insider Terms:
- Irvin Schwartzenburg is a Senior Application Engineer at SICK Sensor Intelligence. Connect with Irvin on LinkedIn.
- SICK provides sensor intelligence and application solutions for industry. The Flow divisions of SICK’s Process group provides a variety of measurement solutions to the oil and gas industry.
- SCADA (Supervisory Control and Data Acquisition) is a system of software and technology that allows pipeliners to control processes locally or at remote locations. SCADA breaks down into two key functions: supervisory control and data acquisition. Included is managing the field, communication, and control room technology components that send and receive valuable data, allowing users to respond to the data.
- Gas flaring is the intentional and controlled combustion of waste products, or emergency pressure relief gas. Through controlled combustion, the environmental impact is less than the release of the unburned hydrocarbons and other gases into the atmosphere.
- VRTs (Vapor Recovery Tower) are tall, vertical separators used to recover flash gas emissions that would be generated in a crude oil storage tank. Flash gas results from natural gas coming out of solution when crude oil is transferred from higher pressure production separators (or other pressure vessels) into storage tanks.
- VRUs (Vapor Recovery Units) is a system that captures low pressure gass at a production site, that would otherwise need to be flared, (such as from a VRT) and compresses it to pipeline pressure. These units allow operators to safely comply with prevailing emission regulations while recovering valuable hydrocarbon gas.
- 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.
- Knockout Drum (KOD) is a part of the flare header system and is used to remove liquids and oil from flare gasses.
- Flow profile refers to the way that a liquid travels within a pipeline. Specifically, it relates to the velocity and turbulence in the pipe. For most technologies, a “Well developed flow profile” is required to achieve accurate measurement. This refers to a state where swirl is not present, the gas in the center of the pipe is moving faster than the gas at the walls, and the gas has not achieved a laminar flow state.
- AGA 3 Part 2 covers Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids – Concentric, Square-edged Orifice Meters, Specifications and Installation Requirements.
- British Thermal Unit (BTU) is a basic unit of energy used in the US. It is the amount of energy needed to raise 1 pound of water by 1 degree Fahrenheit while at sea level.
- Gain refers to the amount of power needed by an ultrasonic transducer to produce a reliable signal at the receiver. Meters use automatic gain control to ensure trouble free measurement. Changes in the required gain is a basic diagnostic tool for ultrasonic meters.
- Ultrasonic Flow Meters measure the velocity of a fluid using ultrasound technology to calculate volume flow.
- Gas Chromatograph (GC) is an analytical instrument that measures the content of various components in a sample. The analysis performed by a gas chromatograph is called gas chromatography.
- Custody Transfer Point is a metering point that is used as the “cash register” in a transaction transaction. Custody Transfer Meters must meet very specific standards and be routinely tested to for accuracy.
Challenges with Flare Measurement Full Episode Transcript:
Weldon Wright: Welcome to the Oil and Gas Measurement Podcast, sponsored by GCI, the Gas Certification Institute, who has for over 20 years provided measurement training, standard operating procedures, consulting, and now the Muddy Boots field operation software to the oil and gas industry.
Announcer: Welcome to the Oil and 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 12 of the Oil and Gas Measurement Podcast. I’m here with Irvin Schwartzenburg today from SICK, and we’re going to be talking a little bit about the challenges of flare measurement.
Before we do that, afternoon, Irvin, and tell us a little bit about yourself, and what you do over at SICK, and how you got there.
Irvin Schwartzenburg: Thanks, Weldon. Appreciate you inviting me in to do this with you today. My background is once upon a time, I was a systems engineer at an upstream production field in Wyoming. I covered a few states and that’s where I got into a lot of gas measurement as well as systems and pretty much everything else.
I had an electrical engineer background. They put me in SCADA, and measurement, and flow computers. Over time, I ended up having a couple of other jobs, but about 10 years ago, I ended up here with SICK as the application engineer.
My role as an application engineer is to help customers understand the technology and understand how to deploy the technology. Not only that, how to successfully deploy it and have a good measurement, and take advantage of all the rich diagnostics suite that ultrasonics can provide.
That’s where I came from and what I do with SICK.
Weldon: Great, Irvin. There’s something that I laughed a little bit about when we had a pre- recording discussion. It struck me just now that it might be worth talking about, because I’m sure there’s listeners out there that would like to start with a short story behind it.
We hear SICK. We hear ZICK. Do you want to tell people why?
Irvin: Yeah. SICK is not an acronym. SICK is actually a gentleman’s name from back in the ’40s, Dr. Erwin SICK. The translation between Ss and Zs, and Vs and Ws between German and English is a little bit different.
Over there, we would say ZICK is the proper way, but over here in the US, if we said ZICK, everybody would be trying to spell it with a Z and they couldn’t find it. That’s really the difference. Dr. Erwin Sick started the company back in the ’40s, a really, really inspirational type guy.
He started working with photoelectronics, and sensors, and optics, and moved on from that. He was very interested in other technologies that would help make the Earth a better place. One of his original ones dealt with emissions. He looked at the smoke coming out of stacks, and he said there’s got to be something we can do to help.
Over time, one of the divisions within SICK is what we call the Process Division. We are in the Flow Division underneath that, where we make products that measure gas, along with other products related to flow and analytical measurements. That’s where the ultrasonics and that’s where SICK or ZICK got the background from.
Weldon: Great. I’m going to stick with SICK here. Part of having you on here, there’s a lot of talk, a lot of concern in the measurement world, not just the measurement world but the entire hydrocarbon production, measurement, transportation, and use world, about all the changes that we’re seeing recently.
The SEG, the social economic governance, pressures on being greener, of reducing our emissions, of reporting what we’re doing better, I guess for years and years, we’ve had flare measurement, but flare measurement has been in the plant, in the refinery, in the big process plant, that 150-foot tower that you see burning from five miles away on a good day and 90 miles on a bad day.
What we’re seeing, though, is the push to decrease losses from an economic standpoint, to better capture emissions and to hopefully reduce emissions in the long run, that need for flare measurement is being pushed from that big plant, from that downstream world into the midstream and the upstream operations.
There’s a lot of challenges when you talk about the large plant flare versus the small station or the production pad. Can you talk to us a little bit about some of the challenges you face as we try to move flare measurement into these lower volume and lower pressure applications?
Irvin: Yeah, sure. That’s something I’ve been getting very, very intimately involved in these days. One of the things that came up – I think we had talked about this before – is people look at the refinery and petrochemicals. They say, “Well, we’ve been doing flare measurement for years. We’ll just stick it out here in the production world. Life is good.”
I guess I’d like to point out a few things that are different and lead to some of the challenges that we face. While we talk about the challenges, I do want to assure you that, done properly, we can get good measurement out in the upstream world, but there are some challenges.
If you think about where this came from, with the flaring in the refineries, generally, large flares, pipes, but they had access and almost all of them have access to what we’ll call a sweet gas or purge gas. When they run these lines out there to the flares in the refinery, they can be very large. They also have a certain amount of gas that is running through that pipe to give some forward direction to that flow.
Their types of flares are a little more complex than what we see out in the upstream. A lot of times, you’ll see different isolation. You’ll see water seals, molecular seals. You’ll see different flare technologies out there.
In their application, one of the things that’s very common is they have a certain amount of purge gas. They’ll have an inert gas, which is nitrogen. That nitrogen will keep a base flow rate going through there.
As you know in measurement, if things are repeatable and if things are steady, you can measure them very well. Once things are not repeatable and not steady, the uncertainty is going to go up.
In the world of refining, they always have a base minimum velocity through the pipe they try to maintain. That overcomes effects from the sun hitting it, thermal stratification, and stuff like that. In their applications, they do things just a little bit differently.
When we move this upstream, we have a couple of different types of flares that we have up here. It’s interesting when people talk about flares. Flares, to me, fall in two different categories.
One is “Life is good. Then life is, oh crap.” The speed goes from zero to a billion feet per second. That’s a safety flare. That’s where you’re trying to dissipate energy that can otherwise cause problems. In the upstream world, that’s very calmly called their high-pressure flare.
That high-pressure flare is effectively a vent. Very common would be on the pad or on the production facility, if sales can’t take the gas, they’ve got to do something with it rather than shutting everything down.
In that case right there, the flare is generally not doing anything until they have to divert this large volume at a high pressure. They’ve got to get rid of that gas. We want to send it up the flare and we’ll vent it. We’ll burn it at the flare tip.
The next type of flare we run into upstream is generally what I call the low pressure flare. In the old days they still did have things called combustors. Really, that’s just you’ve got the gas coming off of a tank or a VRT. It’s a very low volume, but they don’t have a good way to deal with it on pad. They just have to get rid of it.
That’s not the critical zero to a million feet per second. Generally, that’s a consistent, very, very low-velocity flare, smaller lines coming off tanks. Those are the two types of flares we generally see upstream. One will be considered a high pressure. One’s low pressure. Each one of these have their own challenges.
The challenges we see as we move up to there is you go up to the production world. You don’t have a lot of inert nitrogen gas to run a nice purge through this. Now what happens is they run these flare lines. Within the flare lines, you don’t have a lot of gas, at any given time, keeping a positive movement on the gas within the pipeline.
If you can imagine a long cavity of a pipe or enclosure sitting out in the sun, you’re going to have different thermal effects. The sun’s going to heat it up. The gas is going to move around in the pipe. It’s going to expand. It’s going to contract on a windy day. A lot of these flares that we see, in fact, some of them don’t have a flame arrestor.
Some, so if they’re open to the atmosphere on a windy day, you’ll see compression and decompression in the flare stack, which translates back into the header. There’s a lot of things that if there is no positive movement of gas, meaning I don’t have a defined sweep or purge, then what happens is that gas inside the pipe is subject to any number of things to make it, I’ll say, just wander around aimlessly in the pipe.
Maybe it’s going towards the flare tip. Maybe it’s not, but you’ll get these circulations. In the world of upstream, everybody’s trying to keep their emissions down, which is a good thing.
In order to accurately measure down to the low values they’re trying to do today, it can be a real challenge, especially when you don’t have any very well defined. Again, I’ll say that if something’s well defined and, or repeatable, you can measure it.
Weldon: That kind of sounds like you just defined how we try to do most of this flare measurement on the upstream and midstream side.
Irvin: Yep. Low-pressure flares are a little bit different. They have different challenges of their own. At least on the high pressure, generally there’s no flow. Then when it flows, it goes, man, they’re venting and they see a considerable amount of velocity and that’s an event.
The low-pressure flares, generally just in the way that they’re set up, the gasses coming off the tanks, or evolving out of the gas, are going to be heavy gasses, very low flow rates. This gas is just trying to make itself to the flare.
You get temperature swings. You get these heavy gasses hitting dew points and they’re condensing, maybe some of the fluid gets in the bottom and then during the day it evolves out. It’s a lot of other things that can happen in these low-pressure flares when you’re trying, on average, to measure something down around one, two feet a second.
A lot of these low-pressure flares are very low. That gas, the flow profile, as we’ll call it, just really, isn’t well defined.
Weldon: That really sticks it to the issues that we fight in the midstream, as in the process plant, and upstream to that, to the compressor station, and even some of the big well pads. In that regard I’m going to use a quote that you gave me when we talked earlier this week.
I’ve heard it said in different ways, but this is probably the best. Your quote was “You cannot fix bad process design with good measurement equipment.” That’s something that we all know intuitively, but we all want to deny it on the surface.
We need a quick fix where we could plug something in, add a new piece of equipment with 5 minutes to 15 minutes worth of installation time, and suddenly have better measurement or eliminate the losses. Many times the problems we see are not actually measurement related at all.
Can you talk to us a little bit about what you see when we talk about bad process design, especially in these low-pressure flares? Talk about some of the things you see out there. Some of the things that strike horror and you just know you’ll see it again next time.
Irvin: Yeah. Got a chuckle on that. I’m going to open a website with some shirts to sell to the measurement people that say exactly that, “Good measurement can’t fix a bad process.”
Weldon: I need ten.
Irvin: Okay! What the deal is with that is even moving away from flare, but measurement in general, it just gets to me sometimes because they spend all the money drilling wells and you get the product. At the point where you turn that product into dollars, or in this case into emissions, and which actually ties back into dollars, they don’t want to spend anything at all.
It’s almost a lot of times, and I’m sure everybody agrees in the measurement world that this ends up being an afterthought. I would really stress if the measurement groups can ever get in early and have some input into where these measurement points in the flare system occur, they’re going to save themselves a lot of headache.
While before I talked about all the different things that make this challenging, the good news is that if it’s done right, you can actually get some pretty good flare measurement. A lot of that stuff, again, deals with the measurement point and the design.
Often, as it comes out whether through a VRT or VRU, or off tanks, or even a high-pressure flare, they’ll have a knockout drum. Then, I’ve seen knockout drums where you have a football field between the knockout drum and the flare base.
I kid you not, what they’ll do is they’ll come right out of the knockout drum in the first elbow, and they’ll stick the measurement point, when you have a freeway of pipe before a nice straight pipe where you could put the flare measurement, the probes, in further away from the knockout.
What this does is if you were to locate the ultrasonic flares further from the knockout, it does a couple of things. One, it gives you a nice straight run of pipe. The gas tries to get more formed up as opposed to it having a better chance of fixing the flow profile as it comes out of the knockout.
But not only that, coming out of the knockout, that rich gas has more time to drop out into the flare header. As it drops out, if they build it with a little bit of slope back into the knockout, then that stuff will tend to drain back into the knockout.
If you can imagine this rich gas coming out of the knockout, off the tanks to the knockout, into the flare header. If it had a fair amount of distance, so anything happening, condensate and all stuff drop out, not only drop out, but flow back to the knockouts, by the time you hit the measurement point, you’re in a much better situation.
If you can influence it there, that would be good. Other things you can do to remediate that is we’ll see the use of heat blankets and heat traces. That will also help, especially in the northern climates, to where you have a real situation with gas, condensate, and heavys dropping out, and then moving back into the gas stream over temperature changes.
I know engineers a lot of times think bigger is better, but in the world of flare, especially for the low pressure, while you want to maintain a very low back pressure on the system, larger pipes means that gas velocity is going to go lower and lower. The lower the gas velocity, the more challenging it is to get a good number.
Because remember, we’re always trying to get good accountability on what the lowest flare emission rates are.
Weldon: Well put Irvin. As you mentioned earlier, so much of the time measurement is an afterthought. We will always have great measurement on that custody transfer point, that one point that the big check gets written off of.
As long as things are going well, that’s really all management cares about most of the time. It’s when things don’t go well when we have unexpected losses when we have discrepancies on check measurement. That’s when everybody gets excited.
They get to run around in circles and automatically point at measurement because we expect the same quality measurement of every meter that we have, even if we only spent a 10th of money on those “non-custody transfer grade,” meters that are used for things like flares.
I know even with ultrasonics, flow profile, flow profile, flow profile. If it’s not consistent, if it’s not well formed, if it’s not repeatable, I don’t know that there’s any meter out there that can make up for those things if they get too bad, right?
Irvin: Yeah. Definitely, with ultrasonic, it is flow profile related, but the truth is most all technologies. If you look at AGA 3 Part 2, there’s a big discussion on it on upstream piping links with and without flow conditioners, and pipe element changes.
While it’s often neglected in other technologies because other technologies will always give you a number, flare measurement, the benefits of the diagnostics that a flare measurement using ultrasonic gives you indication of the quality of the measurements.
You can see things you have never seen before. When you get into flare measurement, you’ll be able to see what’s basically going on to the pipe. When you get a number from us, you have a sense of the quality of the measurement.
Is a meter working good, does a meter believe its number or is a meter starting to show some contamination? All meter technologies eventually take the cross section of the pipe and use it to calculate a volume, or the quantity of fluid going through it.
Even with flares, you’re looking for a good number, but if that flare has a lot of non-gas in the cross-sectional area, that’s an immediate source of uncertainty. Today, when we’re trying to get down to the absolutely lowest number of reportable events, generally, when you have cross sectional areas full of stuff or consumed with stuff that is not gas, meter technologies are going to over report.
Being able to get good measurement – knowing what’s going on, taking action when you need to – in the long run is going to give you good measurement. Good measurement in context of the flare means more accurate reporting, which if it is just gas, chances are you’re going to actually have a better number, which is going to result in a lower reportable. It just all ties together.
People, like you said before, they want really good measurement. It’s doable. You just need to go in there and try to get the engineers to give you the best possible foundation to work on.
Weldon: The real key there is they want the best measurement possible for next to nothing, right?
Irvin: Oh, yeah. That’s right.
Weldon: Of course, the best measurement possible is something that we can’t afford in the industry. That’s NASA-level stuff. What we’re looking for is the right balance between reducing risk of accuracy, of uncertainty, and the cost involved in getting it, right?
Weldon: Let me wrap back around to something you said. I’d like to get you to expand a little bit on it. You mentioned that there’s technologies out there that you always get a number with. Many times, we don’t stop to think about what that really means.
We can take that entire 12-inch or 24-inch orifice meter run. We can load that up onto a truck. We can ship it to the cornfields and have it flow tested. We can have our orifice meter flow tested and flow profiled, and get some crazy accuracy out of that, right?
Weldon: We can load that truck up and take that truck back, and install it, and once it’s installed, we’ve got a good meter. We wave our hands, we slap ourselves on the back, and we don’t look at it again. Maybe if we’re really lucky, we look at the orifice plate once a month, but otherwise, it’s there.
We have no idea what’s going on inside of that meter tube. We have no idea if the flow condition has become partially obstructed, or something else is happening to the flow profile, if we built up an eighth-inch or a quarter-inch of black oxide on the inside of that pipe, or if the pipe has four inches of water in the bottom.
Our orifice meter doesn’t tell us those things. It’s just fat and happy. That’s the same with so many other technologies. The orifice meter regurgitates a number and doesn’t tell us anything, unless you’re using some of the advanced diagnostics or something. That is available. I just don’t see it installed anywhere except offshore.
You have a turbine meter? That turbine meter gives you a number for liquid spinning. I think the real difference in these technologies is that when we start talking ultrasonic or we start talking Coriolis, those meters can tell us they’re not happy again.
You want to elaborate a little bit more on why that information is important to us coming out of ultrasonic meters and what it can tell us?
Irvin: Yeah. You’re right. This is primarily about flares, but the concept of mass meters applies. It’s a good discussion to have about the orifice as well, though orifices typically are not used on flares. The point is that mass meters are fundamentally mass meters.
They’re not dependent upon the composition going through the meter. An easy illustration would be if you take an orifice and you run hydrogen. Whatever beta ratio, and run a certain amount of hydrogen, and what sort of transmitter to get to 50 inches. You’re going to be running a lot of that real light hydrogen through there.
On the other hand, you take something and you run, I don’t know, something really heavy, like oil, through it. Chances are you don’t have to move very much oil to get that same 50 inches.
That illustrates a mass meter. Whether it’s an orifice, or a thermal, or a vortex, any of these mass meters now end up having some tie to having to know what’s in the pipe in terms of composition to actually get the best uncertainty.
In the world of ultrasonics, it is a little bit different, because if we can get the sound wave across, we can calculate an actual volume. Then in the flow computer, they’ll convert that to standard. That’s where the gas analysis comes into play if you’re going to go back to standard.
Fundamentally, air can be introduced into differential or mass meters due to not having the composition. Then again, they’ll take that to the AGA calculations and wrong compositions will affect that as well too.
Where it comes into play about being able to get a number which with a traditional, a turbine with bearings that are dragging, or the orifice plate, or any number of factors like dirty plates, or edges, or bent plates, or non-sharp edges, you just won’t see anything in there, like you’d said before. I’ll give you 50 inches, whether I’m full of water or full of gas.
With an ultrasonic, there are certain things you can gain out of that technology to give you an idea of what’s going on in the pipe. For instance, an easy one is speed of sound. Flow computers will have the gas composition in it, and that’ll calculate a theoretical speed of sound.
We measure speed of sound so we can give you an idea if that seems plausible or not when you compare theoretical to measured speed of sound. Maybe that means you need to change or update your gas analysis there.
If you’re pushing gas of a higher BTU or content through there, you’re going to be over reporting in terms of what a standard volume might be.
We look in terms of gain. Gain is another metric. What gain allows you to do is determine if there are starting to be contamination or loading in that meter. Turbulence is another factor. There are several diagnostics that allow you to not only just say, here’s my number, but give you an indication of how good that number is, and what’s the quality of that number.
The deal with ultrasonics, and many people know this, is you always start with the baseline. You put it in, and an ultrasonic is just a straight piece of pipe with a couple of sensors on a wall. It’s just telling you what’s going on in the pipe.
You take that baseline and you look at those diagnostics, and you trend them over time. If they start to change, if they start to move in one direction, then chances are you might have to take some action to sort the meter out, to clean it or whatever.
The best thing about ultrasonics is that the diagnostics, the rich amount of information you can get, and just pulling it in and trending them gives you so much more information.
When it comes time to try to substantiate your numbers, whether it’s custody transfer, flare, or EPA, having not only the number, the quantity, but being able to say this quantity is either good or questionable due to these other things that we look at, the diagnostics is so important.
Weldon: Exactly. We talk quite a bit about the diagnostics available in ultrasonic meters. We talk quite a bit about watching the speed of sound, about doing gain comparisons, trending gain over time, looking for sudden changes in gain, as well as comparison of the different paths across the meter for a multipath meter.
We talk about all those things and we think about diagnostics of the flow computer of the meter itself. One thing that’s available to us that I don’t see used a lot is to continuously watch that calculated speed of sound from the ultrasonic meter, up against the data coming out of an online analyzer.
Obviously, when we go out and test, we want to go out and do our monthly check of the ultrasonic. We log onto it remotely. We look at the diagnostics for several periods of time. We’re worried about the meter in that case.
Or as you mentioned, maybe if we don’t have an online analyzer, do we need to update our analysis? A very powerful tool there would be to begin to use data from that ultrasonic meter as a diagnostic check against our online chromatograph.
Irvin: You’re exactly right. We are measuring the speed of sound and that’s very simple. It’s just straight math. Time A to B, B to A, you have a high-resolution clock, you do a little bit of math, and out pops the speed of sound. It’s a measured value.
I like to, when I’m teaching, give this analogy. I have a resistor, I give it to five people, and five people have their own Fluke. If everybody says the resistor is a hundred, 100.1, 99.9, chances are that resistor is a hundred.
If four other people say it’s pretty much a hundred, but one guy says, “Oh, the value is 200.” Chances are something’s up. When you start to verify the meter by looking at the speed of sound, you want to make sure that the meter itself agrees with itself.
If it does, then when you start comparing it to the speed of sound of the gas chromatograph, if you think about what the gas chromatograph is doing, its calculation is theoretical, and it’s going to be based on composition, pressure, and temperature.
Gas chromatographs have to be maintained. There’s certain cal gas. There’s issues with that if it’s not being…It can be stratified. There’s just issues with that. There’s people who know chromatographs much better than me, but also into the equation is pressure and temperature.
If you think about temperature measurement out there on the meter run, I’ll say it’s one of the lower quality measurements, because in terms of gas quantity, temperature, because it’s converted to Kelvin, has a much less effect on the quantity.
However, when you look at temperature with the speed of sound, there’s a great impact to change temperature to the calculated speed of sound. You’re exactly right. When we go out there and we verify more of a pipeline, or a custody transfer, we will look at speed of sound.
If the meter multi-passes agree with themselves, 99 percent of the time you’re going to find an error with the gas chromatograph or the pressure and temperature, and it’s usually the temperature. In the transmission world, you are right. People are very used to comparing the speed of sound with the meter as a verification.
As you move upstream, that is something that people are starting to do. I’m glad they’re doing it because not every upstream point, not everybody has a GC. I’m sure they would love it, but it’s not going to happen.
What they are able to do is put that fixed sample in their flow computer, whether it’s for the flare or whether it’s for a custody point. As they monitor the measured speed of sound, and of course the diagnostics in the meter saying, “I think the meter is working good.”
You can have high faith, high confidence in our measured speed of sound, then you can compare it to the other one, to the calculated. That will give you indication of things like, “Did the composition change? Maybe I’m getting some moisture. Maybe I’m getting some condensate misting through the meter.”
Because you will see that measured speed of sound change with very small effects to the composition. If you look at the theoretical, it’s not going to show that. Very good diagnostic as you put out there, that I would like to see everyone use is comparison of the theoretical from the flow computer with a measured speed of sound.
That’s one indication that definitely tells you something inside the pipe is changing.
Weldon: That’s some great stuff there, Irvin. I think, though, you run into the fact that many times out there in the pipeline world and downstream of the transportation pipeline world, there’s a lot more time to focus. The job is usually a little narrower and it’s not changing as fast.
When you get into the midstream and the upstream, the gatherers, the producers, a lot of times they’re hopping so fast that they have trouble just getting the basic meter installed. Many times, using these diagnostics and using these tools gets put on a back burner till next week or next month then they never happen. It’s something we should really look at.
You’ve provided us some great information and some great insight here today. One last thing before we go. A lot of the push we see of moving better measurement for these flares further toward the midstream and the downstream world.
As we mentioned earlier, that of course is driven by the socioeconomic governance push “be greener”. Many times with producers out in the field now, and the midstream companies, they need to document that they’re taking efforts, at least that they’re measuring.
As you look at the change between what you were seeing and what you had requested for flare measurement five years ago, and what you have today, would you be willing to venture any kind of guess at how the percentage of that changed?
Five years ago, how much of the time were you asked to look at low-volume, low-pressure flares versus the stuff in the refineries, the petrochemical complexes.
Irvin: I couldn’t even stand a guess.
Weldon: Fair enough.
Irvin: In terms of fair enough percentage, but it’s integer multipliers. It’s 10, 20. It’s huge because back then people would just, and in fact, a lot of times in upstream, they were allowed to just do a calculated value and not even measure.
Then some people would try to do measurement. I’ve seen some where they just put a temperature transmitter on the pipe, and then they try to correlate the pressure in the pipe to the flow in the pipe.
It goes from just calculated to very, very crude, to some people will try other technologies that would give a number. Now, what we’re seeing is, for all the reasons you mentioned – companies want to be green, companies want to be good stewards, the balancing, the carbon credits, the financing, everything comes into play – and so we’re seeing a lot, lot more interest in that right now.
Good thing about it is, while it’s very challenging, if it’s done right, with some forethought, you can come up with some good measurement data. As far as SICK, yeah, we’re seeing a lot of it. We’re very involved in that today. There are a few things that we can offer, not only from the experience, but how our meters perform.
I’d encourage anybody, if they have questions, to get in touch with us, and we’d love to discuss what we can offer in the future.
Weldon: Great. Thank you for sharing your knowledge and your time with us. We’ll have your contact information up in the show notes on the website. When you get those t-shirts done and get your website online, let me know. I need to put in my order for them.
Irvin: All right, then.
Weldon: Thanks again, sir, for being on our podcast.
Irvin: All right. Thank you very much.
Weldon: Thanks for listening, and we hope you found this episode informative. If you did, please take a moment and leave a comment on iTunes, Google, or wherever you get your podcast fixes from. We also encourage you to share our podcast with your coworkers and maybe even your boss.
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Thanks again for listening, folks. Join us next month.
Transcription by CastingWords