In this month’s episode of the Oil & Gas Measurement Podcast, host Weldon Wright is joined by David Bell, president of Bell Technologies, to discuss the challenges and innovations in the field of oil and gas measurement.
They explore the limitations of the traditional orifice plate, which has been in use for over a century, and how new technologies are emerging to address these limitations.
They emphasize the importance of reevaluating traditional measurement methods and considering more efficient and accurate alternatives in the oil and gas sector.
Beyond the 100 Year Old Orifice Plate Show Notes, Links, and Insider Terms:
- David Bell is President and Founder of Bell Technologies LLC. Connect with David on LinkedIn.
- Bell Technologies LLC, based in Katy TX, is a global leader in helping businesses create and utilize innovative advancements in differential pressure flow measurement. The company combines technology and innovative engineering together to provide solutions to customers in industrial, commercial and consumer markets.
- Orifice Plate is a restrictive device installed in a pipeline for measuring the flow rate of liquids or gases by measuring the differential pressure created by across the restriction.
- Gas Chromatographs are analytical instruments used to separate, identify, and quantify components in gas mixtures.
- Liquid Samplers are devices used to collect representative samples of liquids in pipelines.
- Reynolds Number is a dimensionless number used to predict the behavior of a flowing fluid.
- DP Cell is the wetted element at the heart of a Differential Pressure Transmitter, where the net of the opposing pressures is converted into an output signal.
- E&P (Exploration and Production) also referred to as the “Upstream” portion of oil and gas industry, encompasses the search for oil and gas reserves, drilling, and production operations.
- Produced Water is water that comes up during oil and gas production, often mixed with hydrocarbons and other substances.
- CO2 Capture are the technologies and processes used to capture and store carbon dioxide emissions from various sources.
- TORUS Fitting is patented differential pressure element design device developed by Bell Technologies for measuring fluid flow.
- MAG Meter is an electromagnetic flow meter used to measure the flow rate of conductive liquids.
- Coriolis Meter is a mass flow meter that measures the mass flow rate of liquids and gases based on the Coriolis effect.
- Densitometer is an instrument used to measure the density of a fluid.
- API 22.2 Standard (American Petroleum Institute – Manual of Petroleum Measurement Standards, Chapter 22 Section 2) defines testing and reporting protocol for the evaluation of differential pressure flow measurement devices.
- Flow Profilers are devices designed for insertion into a pipeline to mitigate fluid swirl and facilitate the creation of a fully developed velocity profile prior to entering a flow meter.
- Linear Profile is a consistent flow pattern achieved with the TORUS fitting, ensuring accuracy.
Beyond the 100 Year Old Orifice Plate Full Episode Transcript:
Weldon Wright: Hello and welcome to Episode 25 of the “Oil & Gas Measurement Podcast,” sponsored by GCI, Gas Certification Institute. For more than 20 years, GCI has been providing measurement fundamentals training and measurement standard operating procedures to the oil and gas industry and now proudly offer the Muddy Boots Online field operations platform.
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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 another episode of the “Oil and Gas Measurement” podcast. I’m your host, Weldon Wright, with FPV Prime Measurement Consulting. I’m here today with David Bell, president of Bell Technologies. We’re going to talk about what I’m calling beyond the 100 year old orifice plate.
Hello, David. Thanks for being here, and tell us a little bit about yourself.
David Bell: Hello, Weldon. How are you? Thanks for the invite. I appreciate it. The opportunity is great. I’m of the old vintage. Came out of college in ’67 out of Indiana State University, Tarot, Indiana, thinking I would become a teacher.
I had spent four years in the oil patch in the summer paying for my school, and the company that paid me said they wanted me to return some of the money they’d put into me for the service. I went to work for Marathon Pipeline.
Weldon: You’re the classic example of, “You’ve got here from the ground up then.”
David: Yeah, I started out with a totally different degree in college than what I’m doing now. Even though what I learned in college about trying to educate people has been easy for me to help me to make presentations, talk to people.
What I’m doing is trying to enlighten the mental capacity of people to understand there are better ways of doing things. My educational background fits into what I’ve done, which I’ve been involved in multiple things, and currently, I hold 14 US patents on measurement equipment.
I’ve been really involved in developing hand valves manifolds, and built the first large bore manifold that went to the gas marketplace many years ago. I have done a lot in the development of what we’re doing now, as far as trying to solve a problem, not putting a Ban-Aid on it but to solve the problem.
The problem basically is mismanagement in the world of fluid, liquid, and gas measurement. A lot of people say, “Well, we don’t have problems,” but yes, we do. Need creates necessity which creates innovations, and basically, that’s where it’s pushed me.
About 2015, a young gentleman by the name of Zakir Hussain, a well known PhD in fluid dynamics, joined with me and said, “Hey, we developed some technology way back in ’83 at Daniels that never was used, so let’s see if it fits your technology,” that I had developed at that time and selling in the drilling industry, the slurry industry, the limestone coal burning power plants and places like that.
In that process, we made some, sent them to CC, got them calibrated, brought them back, and it proved his technology that they had developed at Daniels, that to tap the center throat of the orifice, you obtain the best differential pressure you can get.
You obtain a very stable differential pressure measurement, and then also you are not worried about what happens downstream of the device when you get into gas chromatographs, or liquid samplers, or whatnot. It can’t be injected into the system for four and a half diameters downstream.
Weldon: Basically, what you all dug into is how do we fix all the things that scares that 100 year old orifice plate?
David: That’s right. What are the things that scare the orifice plate, is what we were trying to fix.
Weldon: We say a 100 year old orifice plate, that’s only because I’ve been in measurement too long. It’s 120, 130 years now, for gas measurement.
David: Actually, the first orifice plate came into play in 1900 and was utilized. Then, of course, it really all works on Bernoulli’s theorem that was developed back in…I believe it was 1574 where he developed the technology of physics today that we measure fluid, liquid, gases, slurries, everything with.
Weldon: We talk about measuring natural gas with orifice plates, but the measurement of gas with orifice plates predates the natural word by quite a bit. Before we had natural gas, we had town gas or manufactured gas. We were using it back then.
What I’d like to get you to talk about for just a couple minutes is, in our previous discussions, you were talking about some of the other things y’all are doing with orifices, with your new TORUS fitting – I shouldn’t say, “New” – with your TORUS fitting.
One of the things that really struck me is two things are becoming very…They’re becoming closer to the top of the discussion list. Let’s put it that way. That is both water measurement and CO2 measurement, with all the CO2 capture ventures coming up, with their new emphasis on produced water and measuring it.
Talk to us a little bit about what you’re doing in those fields and why your technology is so great about that.
David: Let’s take water for example. Many years ago, we didn’t have produced water because we didn’t drill like we do today. With the hydro-fracking systems that we use today, we use a lot of water. The wells that have water are still producing a lot more water because of what they were being injected with.
In our process with this, we’re able to take and measure water. With what we call the CENTER TAP TORUS and an energy correlation calculation, we’re able to eliminate the major problems of the orifice plate and simply make it a linear profile result output on DP. We do that by following API 22.2 standard to get a unit calibrated in the old viscosity Reynolds number coefficient discharge curves.
Then we take all of the data that we get and put it into an Excel spreadsheet. That spreadsheet gives us a linear profile for a slope and an intercept point. That intercept point, along with density and Delta P gives us the actual accurate measurement less than a quarter percent.
By doing that in the water market, we’re able to take produced water. We eliminate viscosity, the viscosity that is caused by mud shaving, some oils, earth, everything that comes out with the water that impacts the viscosity, which is the major factor for a turbine meter or a DP cell type head device like an orifice plate.
You have to know that with a big blow and flow computer to be able to integrate all of the requirements to get an average flow output. This flow output has problems. Orifice plates have a half percent error, basically, to begin with. It was an error built into the calculations so that you could have one calculation for all sizes of orifice plates.
In our case, we don’t have but three sizes. We’re simplifying the number required. Typically, we now make the transmitter do its work as to what it transmits DP to us so that we can run through an electronic flow computer or a DP cell and into a PLC.
The stations of the future are getting simpler, less expensive. A lot of different things that go into why we went this route to solve the base problem of an orifice plate. A sharp edge is not needed. Bowing of the plate doesn’t happen.
Anything liquid wise, or gas wise, we need the density of the stream. The density comes from the gas chromatograph, or through a densitometer, or through a hydrostatic head differential for density on the weight of the fluids.
We’ve been drilling muds. We spent a year drilling muds with a company here in town. We were in through about 9.5 pounds per gallon density weight all the way through 18.9 pounds density weight and our…
Weldon: Hey, back up a minute here.
Weldon: We’re not talking water with a little bit of solids in it. We’re talking solids that you may pump down the pipeline. I don’t know that I can imagine a much worse environment for something to try to measure. Unless maybe you threw some rocks in. You may have some of those too.
David: Yeah, there’s been a lot of rocks run through it and whatnot. It’s just the geometry design of the device. We’re able to do all of these things that you would be scratching your head out in the field to solve the problem. They’re already solved before they get out there.
We’ve been very successful on the water side. We’re doing crude oil and loading tankers out in West Texas where they’re picking up tank bottoms and taking them in to the water guys. We’re measuring it very accurately. They looked for a long time. They tried all types of meters.
They just wouldn’t stand up to the severity of the service of these tankers, because they would unload pieces of wood, rocks, or whatnot. It would impact the type of measurement device they had in the system.
We’ve done that, and it’s really been good as far as solving the initial problem. The initial problem was, how do you get rid of problems that cause you problems? Viscosity, Reynolds numbers, and this type of calculation causes the problem.
That was developed by Zaki. Dr. Hussain came up with an energy correlation calculation that only uses potential and kinetic energy. It’s never been used before. We’ve turned it over to all of the instrumentation measurement gurus of the world, it’s known that we know of. Nobody has ever been able to pick a hole in it.
Everybody has looked at it. They come back with the same question. Why didn’t we use this 20 years ago? It was the issue. We didn’t have enough pain to cause that to happen.
Weldon: We also don’t like new things, let’s be honest with that.
David: That’s true, yes.
Weldon: I still consider ultrasonic new, but it’s good for some applications. It’s not nearly the silver bullet they tried to sell us, when they started pedaling it.
David: There’s a couple of them that have done that, and you’re exactly right.
Weldon: Now, as you mentioned, your device is not worried about changes in viscosity or knowing viscosity. That’s got to help a lot in CO2 measurement, because when we start talking about CO2 and wondering whether it’s really a gas or whether it’s a supercritical fluid, viscosity becomes an issue. What happens with you and CO2?
David: In CO2, basically, if you know the pressure and you take the natural losses, and what they are, physics of CO2, you can take the pressure and the temperature and figure the density. Because CO2 density doesn’t change, the viscosity changes on it.
Some densities will change. I shouldn’t lead people to believe that it never changes, because it does change. The issue is that most CO2 systems that are in pipelines today, the guys that make the CO2 know what it is when they put it in the line and report it to you, so you have a halfway chance of hitting it right to start with.
In our case, we like to take the density and by the density of it and with the natural laws that we work on today, we could actually go in and calculate the CO2 capabilities to know where the viscosity doesn’t impact us. We found that the higher we operate the pressure, the less impact viscosity has on the system.
Basically we have negated viscosity influences, because we run a smaller bore at a higher pressure with a higher DP, and we do not have density problem changes at the throat of the orifice like when you run a high pressure and a very low DP.
You can reach points where you have low inlet pressure and then you create higher DP and you get a change in density at the throat. As an example, a gas pipeline company in West Texas at an eight inch pipeline with a four inch Coriolis meter in it, developed 150 pounds a drop across the Coriolis meter.
They asked us simply because of their cost of compression, could we give them a meter that would relieve some of that pressure? We did. Now the meter runs at about 13 pounds a drop. When they did that, it made a much difference in their cost of compression. A lot of that went to the bottom line to their back pocket, which is great. That’s what we’re all in here for. In that process, though, we found that when they lowered the pressure to 13 pounds, they increased the volume throughput.
They’re sitting there running at about 900 pounds of pressure. The pressure drop is 13 to 15 pounds, and all of a sudden as they’re increasing their rates, the density is changing at the throat because of the drop in units, in pressure.
In that, we have asked that they increase the bore size to relieve the DP or back off on their throughput. I think they’re in the process of deciding what they want to do there to make it accurate. One of the things that we know from history is that this device overreads an orifice plate. I say that by clarifying it that orifice plates have always underread.
Those that are selling on orifice plates are losing about a half percent accuracy just because of what is developed into the calculation. It gets worse as it gets bigger in size from three inch, four inch, six .
When you get up into the 12s and 16s, you’re starting to have more inaccuracies and uncertainties just in the calculation than you do on a device like what we’re doing with the taking the pressure upstream and in the throat.
For water, it’s an ideal application. I don’t get the electrodes on a magnetic flow meter dirty. I don’t have that problem. I don’t get dirty in the throat because of the way the geometry of the ramps were done. The calculation that we use to eliminate viscosity in Reynolds numbers now makes it a linear profile.
It’s just all the best in the fact that it saves money. For example, in the natural gas market, we’ve got to the point where we don’t have to go and inspect the orifice plate because we’re now able to monitor differential pressure both at the throat, and the standard upstream downstream connections that are on the fittings today.
With a solid carrier and a center tap carrier plate, you can actually provide monitoring like all the other devices, Coriolis, ultrasonics, other turbometers, other types that have monitoring on it so that you can sit in your desk on your computer and dial it up, and pull the data historian down and determine do I have a problem with my unit or not?
Should I send somebody out to have it inspected? If they don’t, that’s a savings of manpower, insurance costs, monies, and also emissions of natural gas to the atmosphere or CO2 to the atmosphere.
Weldon: Because you’re not opening the meter up to test the plant.
David: Exactly. The meter is not open.
Weldon: You said something there. Let me back up here, rewind just about 30 seconds. You said something that I could turn into a whole episode here. There aren’t a lot of folks out there, especially our younger generation in the industry, that have any idea of the diagnostics that are available even with your conventional, square edged orifice plate.
If you’re willing to add a couple more pressure transmitters, a lot of amazing stuff can be done. When you take a device that’s already better off than that square edged plate and then provide some diagnostics on that, you get a wealth of information.
Like I said, that could be a whole episode all of its own, I believe. Talk to us a little bit, David, about what are the comparisons you see trying to use this out in the E&P and the midstream gathering world as opposed to a conventional orifice plate or a Coriolis meter, which is now being pushed by people that I don’t think have thought through it very far.
Talk to us a little bit about that in the natural gas world. Related to that or maybe to start that conversation, talk to us about how we can use your TORUS CENTER TAP in line with our current industry standards.
David: Let’s go to the production side. After the well has been drilled with the drilling muds…It’s got tubing in it for production. We’re producing gas out of the drill stem and liquid out the annulus or vice versa, which are where they elect to do it. Now we come into a location where we have a bunch of two and three phase separators.
The separators are basically designed to separate gas, liquid, water, and crude. In that process, you run into a lot of separators not large enough to handle the flow or too big to handle because it’s too slow. You create problems.
You have an active dump valve on the water system that’s popping up and down. They’re running turbine meters on the water. It is a surge on the turbine meter and the viscosity impact because the water is typically not totally clean. It’s going to have an impact viscosity wise.
Those turbine meters, a lot of times, which are now being replaced by Coriolis meters, those turbine meters are not calibrated in the liquid they run on, so the viscosity is their dying factor. You get into the crude oil side, sometimes they’ll put orifice plates, but mainly it’s some type of either PD meter, turbine meter, or Coriolis meter in the liquid side.
They’re looking, all of those devices today still have to use viscosity. They have an impact by viscosity. They need to know the Reynolds number and coefficients because that’s all calculated within all the electronics of the meters.
When you eliminate that requirement, that’s where R comes in to give you a better accuracy on what’s being produced out of the well. If we can get a good density, our accuracy runs with the ability to determine the density.
Density’s not too hard to do on a crude stream at all. You get into natural gas, and if it’s a large enough production well, there will be some type of gas fitting on the three phase separator that is trying to measure the output of the gas, but the gas is typically wet.
The big push in the gas marketplace today is, can we determine how wet, wet is? That’s the hardest thing right now for whether you try to put a BandAid on it and fix it one way versus another. That’s where we’re at right now.
We do have people that are doing development in probes that can determine the percentages of wetness in natural gas.
Weldon: That’s one of those things again with advances in technology. For many decades, we’ve just said it’s two phases. It’s either gas and liquid. It’s crude with water. Either way, when you start mixing things in there we just can’t measure it. We threw up our hands at one’s home and said we can’t do it.
Now with better technologies, with improved equipment, now we’re starting to ask those hard questions and saying we can’t measure it’s no longer the right answer, right? The answer is how do we measure it? Don’t tell us we can’t.
David: You know the production marketplace onshore and offshore are two different animals from day and night. The offshore industry suffers issues that a lot of the platforms out there are older platforms. They are restricted in space available to do new work because the wells are servicing, or dying or they’re going to add more to it.
The world of measurement to me is “if you can’t measure it, you can’t manage it.” That is my slogan. If you’re not measuring it coming on the platform, but you’re measuring it going off the platform, how do you create an unknown to a balanced knowledge?
Those are some of the things that we’re impacting in today’s world with this meter that we have and the system that we have, where we can eliminate a problem for an offshore platform that doesn’t have measurement coming from all of the wells.
They have wet meters, or subsea meters that they say, and the question of accuracy is up for grabs still, even though some are claimed to be relatively accurate, but are very expensive, but they still have to be calibrated every so often.
When they have to calibrate them, it’s a million dollars a trip to go get one, to have it brought back to surface, to get it calibrated on the stream. It’s a dollar savings. We’re in the savings and money making business for the client with the way we’ve done this.
In the field of production, we look to have a major impact because of what we can do with our viscosity, illumination, differential pressure, and density and the way we can do them, so in that pack. Then we move on to the shore.
You have the same basic problems, but you have a lot of water issues and separation in crudes that are going to the water guys that are reclaiming the tank bottoms, cleaning and water up, reinjecting it in the aquifer so we can reuse it again, and pull from aquifers to continue on our development.
We have done a lot of work with and are continuing to do work in different types of industries. I would say that simpler is better.
David: The KISS syndrome applies there.
David: The KISS syndrome with this newer developed technology is a money saver. It’s a money developer for the bottom line. It increases their ROICs for any company. If you just take a look at it, and really look at it, instead of saying, “Oh, well, we’ve already got what you’re doing, and we’re satisfied with it.”
I don’t know of anybody that wouldn’t take a half percent of their bottom line and be happy to increase it by a half percent, because you get some bottom lines there.
Weldon: I would definitely agree.
David: Pretty good size, yep.
Weldon: Let’s loop back around right quick.
David: Yes, sir.
Weldon: If we thought right now the pushout in the EMP and the gathering system processing world, the vendors are out there convincing us we need to start throwing Coriolis meters at all these applications. In the produced water, we’re using a lot of MAG meters. In the CO2 world, we’re starting to put in Coriolis meters.
Can you give us a Cliff notes version of price differences between those devices and your equipment as far as installed cost, and then some kind of relative comparison about operating costs?
David: In the MAG meter marketplace, water wise, they run everything from an ANSI 150 standard operating pressure in the industry up through ANSI 1,500 and 2,500 pounds due to the injection well pressures. You take a MAG meter and you get it above about a four or a six inch, and all of a sudden, it begins to run out of pressure zone.
What I mean by “pressure zone” is cost wise, you get an eight inch meter. An eight inch 1,500 pound meter is somewhere – and this is, I would say, a guess, but I’ve been confirmed a couple of times – that an eight inch 1,500 pound meter can be 16 to 20 week delivery, and it can also cost you about 20 to 30 thousand dollars.
In that process, we’ll provide you a device at 1,500, 2,500, will take you all the way up to 20,000 API if you need to, and those prices will be in the range of about 12 12.5 instead of 20 24.
You talk about Coriolis meters, a four inch 600 pound 1484 operating Coriolis meter runs somewhere in today’s world around 55 to 60,000 dollars. A unit that we would supply through eight inch or ten inch would be somewhere in the range of about 14 , 18,000.
Does the same thing you can get with a densitometer. I can now do volume or mass just like a Coriolis does mass or volume with it, because it’s looking at the vibrations. One of the things that we’re finding out in the industry today is that Coriolis meters, ultrasonic meters, orifice plates all have to have pre-runs with flow profilers installed.
The flow profilers are designed to straighten the stream out before it gets to all of these devices so that you have a straight pattern, typically, through the throat of the meter. We’re finding Coriolis meters have that flow profile problem when they reach the splitter in the inlet.
The impact is unbalanced on each one of the tubes if it’s a dual tube, or the unbalanced energy if it’s a single tube. We’re seeing people having to put installations in with these devices, and they’ve done nothing but continue on the old gas meter station where you came in through the inlet, through the valve.
Ten diameters, you put a profiler. Ten diameters, you put a meter. Four and a half diameters downstream, you are able to now insert your temperature, density, gas chromatograph, or a composite sample probe to determine what the product you were handling was.
In that process basically we do not need the flow profilers. We only, with this device, have a short footprint. The tested information dates from everywhere, from liquids, gasses, and all – muds and all – show that we can, without any problem, have the best thing going at five diameters up and three diameters down. We can do mass…
Weldon: That’s a lot different.
David: If you look at systems sizes, I beam schedules, piping, bolt, nuts, gaskets, and the whole bit, and all of a sudden you look at a device that now you can pull down to five diameters up and three diameters down, and that’s your meter station.
When you get into that, and the thing that you brought up while ago was the monitoring, you’re right exactly. In current days, we don’t monitor orifice plates because we have no way of determining when the orifice plate goes bad.
In our case, we do the monitoring and show you what standard is – P1 and P2 – and what our center tap pressure is at P1 and center tap, and these two different transmitters run in parallel with each other. Once they deviate from…I call it parallelism. Once they deviate from that point, you set off an alarm that either the station or the measurement coordinator sets as a standard.
Let’s let it last three minutes. If it lasts three minutes, then we go look at it. If it’s not lasting three minutes we ignore it. Something outlier happened and we went on from that point. Price wise, we are tremendously cheaper than MAG meters in the bigger sizes.
We get closer in the smaller sizes because everybody cheapens the MAG meter for water service for small end sizes. They don’t get as much profitability for the manufacturer as they do in the big ones.
Weldon: What I’m hearing from you, David, is that it’d be worth people taking a little bit of time to step back and have another look at differential pressure measurement within the technologies that are available with your…as far as center tap.
I think we went a little bit longer than anyone anticipated here, but that’s all right. There’s a lot of good stuff here. David, we’ll have your contact information on our website. We’ll have how to get ahold of you on LinkedIn. Folks can go to your website. Your website is?
David: Www.belltechnologiesllc.com. That’s a plural on the technologies, LLC, dot com.
Weldon: David and his partner have a wealth of information out there, folks. They will have more stuff than you can definitely take in one sitting for reading up on it, I guarantee you that.
For those of you that wonder about the actual science and the math involved in that, he has plenty of documentation that will take you down that rabbit hole till you can’t see light again.
David: That’s true. Doctor Hussein is good at that. We have the legs for this technology to stand on, and the technology basically is, as one guy here in Houston says, “As Mattress Max says, ‘It saves you money.'”
Weldon: David, thanks a lot for your time, sir. I appreciate you taking the time to talk to us and glad to have you on the podcast.
David: Thanks, Weldon. I appreciate the time.
Weldon: I want to thank each and every one of you for listening, and I hope that you found this episode entertaining and informative. If you did, please share our podcast with your coworkers, your boss, and other folks in the industry.
We will have a full transcript of this episode, along with David’s contact information, in the show notes on our website, PipelinePodcastNetwork.com.
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Transcription by CastingWords