This month’s Oil & Gas Measurement Podcast episode features Denis Rutherford discussing the differences between wired and wireless transmitters, the pros and cons for both, and which way the industry is heading. 

In this month’s episode, you will learn how wireless transmitters differ from wired, the installation cost difference, and how they are able to prolong the wireless battery’s lifespan.

Wireless Instrumentation on the Wellpad Show Notes, Links, and Insider Terms:

• Denis Rutherford is the District Sales Manager of the Gulf South District with Schneider Electric Target Accounts System Integrators. Connect with Denis on LinkedIn.
  • Schneider Electric‘s purpose is to empower all to make the most of our energy and resources, bridging progress and sustainability for all. Schneider drives digital transformation by integrating world-leading process and energy technologies, end-point to cloud connecting products, controls, software and services, across the entire lifecycle, enabling integrated company management, for homes, buildings, data centers, infrastructure and industries.
• RTUs (Remote Telemetry Units) are electronic devices placed in the field. RTUs enable remote automation by communicating data back to the facility and taking specific action after receiving input from the facility.
• Wellhead is an equipment installed at the surface of a completed oil or a gas well that provides a structural and pressure containing interface for the drilling and production equipment.
• 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.
• PLCs (Programmable Logic Controllers) are programmable devices placed in the field that take action when certain conditions are met in a pipeline program.
• Fracking is the process of injecting liquid and materials at high pressure to create small fractures within tight shale formations to stimulate the production and safely extract energy from an underground well after the drilling has ended and the rig and derrick are removed from the site.
• Flowback refers to process fluids that are collected at the surface after hydraulic fracturing operations are completed. 
• The Permian Basin is an oil-and-gas-producing area located in West Texas and the adjoining area of southeastern New Mexico. 
• ASGMT (American School of Gas Measurement Technology) is the largest gas measurement school in the United States that is devoted to natural gas measurement, pressure regulation, flow control, and other measurement-related arenas.
• ESD (Emergency Shut Down Systems) are high-powered control systems designed to protect people, pipelines, and the environment in the event of a pipeline operating beyond set control limits.

Wireless Instrumentation on the Wellpad Full Episode Transcript:

Weldon Wright:  Welcome to Episode 13 of the “Oil and Gas Measurement Podcast” sponsored by GCI, the Gas Certification Institute, who have 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.

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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:  Welcome to Episode 13 of the Oil and Gas Measurement Podcast. I’m here with Denis Rutherford of Schneider Electric. He is the district sales manager.

We’re going to be talking about wireless instrumentation and the advantages it brings to wellhead automation. Before we do that, Denis, tell us a little bit about yourself. What’s you do at Schneider, and how you got to be there?

Denis Rutherford:  I’ve been with Schneider now for 18 years. I’m a district sales manager. To get to this position, it started a long time ago. I started out in high school, and in the last two years of high school, being involved in a vocational program of electronics.

That got me into the Navy in the advanced electronics field where I worked on all types of communication, satellite communications, equipment, meteorological equipment, cryptographic equipment. That then took me, after six years, working for a company on analytical chemistry instrumentation, x-ray diffraction, x-ray spectrometry, where I was a field service engineer.

After six years of that, I went to work for an RTU company and that was at the time [inaudible 2:10] Automation that then became Flow Automation and now known as Thermo Fisher Scientific working on flow computers and communication systems. Working my way up from manufacturing technician up to a national accounts manager.

After 13 years there, I came to Schneider Electric, where I’m the district sales manager, working on programmable logic controllers, wireless instrumentation, and electronic flow meters or flow computers. Everything that I did along this whole route got me to the point where I’m at today, so it was a long training program.

Weldon:  Wow. You’ve seen the industry and measurement instrumentation evolve quite a lot since you got started in this, haven’t you?

Denis:  Yes, I have. I’ve been involved in a lot of different projects.

Weldon:  What we want to talk about today, folks, is we want to talk about utilizing wireless instrumentation, specifically in wellhead automation, but maybe a little more general than that.

The actual custody transfer of the wellhead, that’s still done by our classic higher power flow computers, possibly solar powered, maybe AC powered, with longer range wireless devices to that flow computer to that RTU. There’s a lot of other instrumentation and sensors used on the well side.

Those include casing head pressures, tank levels, pump controls. Sometimes that’s done in a flow computer. You may have a Fisher ROC or a larger footprint device like that capable of handling the whole wellhead. You may have a flow computer talking to an RTU. You have two different groups of people out there, two different companies, I should say.

You have companies where there’s a measurement group and there’s an I&E group. The measurement techs may not see that much of wireless instrumentation. The other side of that is there’s a lot of companies out there today that still the folks doing the measurement or the I&E techs, they’re handling all the devices at the pad or at the compressor station.

We’re going to talk about what that can bring to your operation specifically about wellhead automation. The same thing applies at the compressor stations or the other facilities.

Denis, let’s start off talking a little bit about the challenges that we see. The history has been a little long. I guess I dabbled with these devices in the late ’90s. They definitely weren’t where they were today. Talk to us about reliability and some of those challenges.

Denis:  I was just saying, in the beginning, really wireless instrumentation didn’t come out until basically in the middle to late ’90s. Then it was tough to get to market on that amid battery issues, there was just technology issues with radios, and so forth, and reliability. It took a while for it to evolve, but here we are today in 2022.

After a lot of advances in technology, it’s become a lot more reliable. As a matter of fact, the biggest piece of wireless instrumentation is around the battery. It’s a lithium battery. We know lithium batteries are utilized in cars and they’re actually utilized into a lot of different areas around our life. You’ll see it in aerospace. We see it in medicine.

There as far as monitoring of a heart, they’ll embed what looks like a USB stick into you and wire it to different places on the heart. It is wirelessly transmitting information on the heart where it’s monitoring for atrial fibrillation and then reports us back into a monitoring control room.

We’re trusting our lives with this now. It’s really become a lot more reliable. The radios that’s involved there, the spread spectrum radios. A lot of advances in that and becoming much more reliable.

Weldon:  Denis, when we talk about battery life, some folks out here are already going to be familiar with wireless instrumentation. Others may have decided they’re never going to use it because they heard something bad about it back 20 years ago.

Others are in the mode they’re going to learn about it. With the typical devices you’re putting out at the wellhead today, what’s the typical battery life, and what are the factors that determine that battery life?

Denis:  That’s a great question. It first started out with a battery lasting about a year. Now we have battery lives that are five years, some technologies and wireless instrumentation have 10 years of battery life.

It’s really about how often that you’re sampling and taking a measurement, and then how often you are transmitting that back to a base radio that has put it into the SCADA system or allowing a PLC to be able to do the control. Every time it transmits, it takes up a little bit more energy. The more often that you’re taking a reading, that takes a little bit more energy on the battery.

For example, on a tank level, the tank level really doesn’t change that fast. You don’t need to be doing custody transfer measurement once the second reading hits. You’re able to slow that down to maybe once every 30 seconds or once a minute, in some cases, even longer. That’s how you can get that extremely long battery life coupled with how often you transmit it back.

If the pressure is not changing, there’s no reason to update the SCADA system or the PLC with that reading because it’s exactly the same. Once it changes by enough, reaches over a certain threshold, then you’re going to transmit that information back. That’s how these manufacturers out here are pushing this such as with the Accu-Tech product line.

Weldon:  Denis, one of the important things you mentioned there that I’d like to dwell on just a little bit more, and I’m guilty of this also, is I think battery life is directly proportional to how often we get information back.

It’s much more complicated than that. Just like our flow computers are out there today, many of them are taking tenth of a second readings or doing second calculations, they’re adding up information, but we only call back to the mothership, some cases once an hour or some companies once a day.

With wireless instrumentation, we need to be careful not to confuse how often we report data back with how often we’re looking at the data because there’s a lot more intelligence in that from what I understand than there used to be.

My understanding is the meter is sitting there looking at the value and saying, “Such a small amount, I don’t need to report, I don’t need to report. Now I’ve reached the threshold, I need to report back.” Isn’t it more advanced than just time-based reporting?

Denis:  Yes. It’s all adjustable as far as how often you transmit it back and how often that you want to go and take a reading. The more critical the piece of the process that you’re looking at, for example, on a plunger lift, it’s knowing exactly when their plunger arrives so that takes a much faster cycle time. That’s all adjustable.

That’s up to the engineer and the technician to be able to set those timings accordingly as the applications need it.

Weldon:  OK, fair enough. Shifting gears just a little bit in our discussion. I want to get you to talk a little bit about the decision-making process of wireless versus wired technology. Old-school guys like me think the only advantage is I don’t have to dig a ditch.

The other side of the coin, we think, “Oh, wireless and batteries. That can’t be as reliable as having wires.” Talk to us a little bit about that process or the pros and cons between wireless and wired.

Denis:  There’s been a lot of advances in technology as we’ve gone through the years. Wireless instrumentation is becoming much more reliable. There’s just been tens of thousands of hours of research that has been put into it from all different types of markets that collectively has made it more reliable.

When we talk about wired versus wireless, there’s some things that’s happened in the oil and gas industry that have been game changers on looking and how one looks at wired versus wireless. For example, originally, we would just drill a well straight down. It might have a couple of zones, one or two zones, that are fracking.

Then horizontal drilling came in and then we had the multistage fracking on one well. Then the biggie is you have multiple wells up on one pad. For an example like in the Piceance Basin, there is a natural gas shale play that has 22 wells on it, and each well is horizontally drilled. When they’re drilling these wells, it’s doing a simultaneous drilling operation.

In a simultaneous drilling operation, you come up onto the first well. They’re drilling it. As that gets completed, the drilling rig slides over on a rail system and starts the second well. The first well goes into fracking. Then, once the second well is drilled, it slides over to the third well.

The first well goes into a flowback, the second well is in a fracking, so you’re just constantly moving this drilling rig over, and each of the wells is going to a stage of completion. Now 22 wells take a long time to be able to drill. A wired methodology because imagine with all the drilling support infrastructure that is on the pad, you have frac tanks, you have flow-back tanks, and cables run all over the ground.

The place is just completely covered up with truck trailers and cabling. There’s no way that you can bury a cable on the ground and run it over to the sales line. They want to come online immediately once that first well is done.

Here, on the well, these wells were plunger lift wells right from the beginning, so they put on a tubing pressure, a casing pressure, a Bradenhead pressure, and a plunger arrival sensor on these units. Basically, the time that it takes if you can imagine this.

As you’re walking from your tailgate of your truck, you’re wrapping the tape around the threads of the pressure transmitter. You press two buttons and three settings later, the unit is communicating back to the base radio.

Weldon:  Wow.

Denis:  They screw it onto the wellhead. In no time at all, in just a couple of minutes, you’ve completely instrumented the well. That well can now come online and start flowing and producing.

When you take things like that into consideration and also through years and years and hundreds of hours of technology and research, it has become more reliable. Now it starts making sense. Now it really starts making sense.

Weldon:  Exactly. That concept of, “Hey, I take it out of the box, and by the time I walk over to the place of installation, I’ve configured it, screwed it on, and it’s talking.” That is not the wireless that I think it was back in the late ’90s, I’ll just say.

Denis:  No.

Weldon:  The other thing, as I mentioned, so much of the conversation that we have, the debate that we have, is over the reliability of wireless for anything. I guess I missed saying this earlier. I should have mentioned this when we started up.

The reason we’re having this conversation today is that Denis had a great presentation at ASGMT, the American School of Gas Measurement Technology, earlier this week in Houston. One of the things he was talking about in there really made my gears shift in my head, not that they move very fast, mind you.

Talking about reliability, we really are in a place these days where that wireless sensor is generally much more reliable than the wired, especially in a heavy activity area. Lightning, you are more immune to lightning than wired.

As you were talking about, we can install that during trenching. Once our instrumentation is installed, trenching and backhoes and wet weather when the equipment’s digging ruts, those are all our enemies. When you install wireless, you’ve eliminated the worry about conduit and lines being cut. Wireless does a lot of things.

Denis:  It is. It takes a lot just to go and start digging a trench. You have to go through and do a pipe locator, figure out where everything is in the ground. Then you got to lay conduit down into the trenches. The trenches are going to tanks. The trenches are going back to the RTU. They’re going to a sales line valve by the flow computer, to each one of the wellheads. That’s a long distance.

These big well pads, especially at 22 well pad, this is all a 500 x 500-foot pad. That’s a lot of copper on the ground, and copper is really expensive. It not only costs a lot of money, but it gets stolen. That’s what they’re going for.

Then, of course, you’re talking about going in and out of zones, hazardous locations. You’re going to have seal-offs on a conduit that you’re going through. That’s added extra time when you run the wires to the transmitters all the way back to the PLC or controller or flow computer.

Somebody has to wring all that out and make sure you got the right wires going into the right terminal block. That takes a lot of time to be able to do that. It takes up a lot of room inside the cabinet. When you’re bringing in wires from over 150 instruments and coming into the terminal blocks onto their RTU. It means you have to have a much larger cabinet that’s on there.

A lot more terminal blocks and wiring inside that unit that increases costs that’s out there. Then wire requires maintenance. Sometimes you get corrosion, and so forth. There’s a lot of different pieces that gets to be a lot. When you add all that up to a wireless, you don’t have those troubles. It’s a lot different.

Weldon:  It makes a lot of sense there, Denis. It makes a lot of sense that some of those guys that are out there doing it forever and just falsely assumed copper is the best answer. That hadn’t been the case for quite a while.

I don’t want to get you off track of what we discussed that we were going to talk about today, but can you throw out some numbers, even if they’re order of magnitude numbers, what’s our installation cost difference? If you were doing full wellhead automation, are we talking it saves you 25 percent, are we talking it saves you 50 percent, or are we talking it saves you four times to install wireless?

Denis:  You want to keep something apples to apples. An example that I’m thinking up here of basically having three water tanks and maybe an oil tank that’s on there. Then you have a larger solar panel system to run everything wired, whereas a wireless has a battery self-contained system on each one of the instrumentation that’s out there.

A larger solar panel, and with that larger solar panel, you might have to have 450 instruments, several batteries. There’s a larger battery case taken into consideration. Certainly, wireless transmitters cost more than a wired pressure transmitter.

With all the conduit and copper wiring, in the time that it takes to be able to go and instrument a 22-well pad on that, or if we’ll just keep it simple to one well in this particular case, we’re looking at about a 20 percent to 30 percent savings out there on your wireless to wired. Probably closer to the 30 percent savings on that.

With just one well, a 30 percent savings, and if you had 25 wells out there, now we’re talking probably about a $250,000 savings over a wired solution.

Weldon:  Way more than you need for that cup of Starbucks cappuccino. That gets to be serious numbers there. Back on some of the other questions that are probably due to mainly older folks in the industry. The new guys in the industry probably don’t have that question. They just know intuitively.

When we get to talking about distance for devices, the number of devices, one of the old- school worries about putting wireless instrumentation on a pad was there’s a limit you could have of so many devices before you started having interference problems.

Early on, if you had a half a dozen devices on the pad, you began to worry. How many of the devices that you’re all putting out in the field today? How many of those can you have at a single pad?

Denis:  Each one of the transmitters goes back to a base radio. At that base radio, it’s capable of connecting to 100 devices. On a 22-well wireless pad, you could put two base radios out there and that would be connected to that one controller, that one PLC, that all the data goes to. That’s quite a bit out there as far as the quantities that you’re looking for.

Weldon:  What about distances? You mentioned earlier about not only having instrumentation at the wellhead, but you may have production tanks. Those production tanks might be right next to you, they might be far away, or as in one of your slides that I saw earlier this week, it could be up on top of a mountain. What’s the distance we’re talking about on these devices?

Denis:  Basically, you’re sending the information back from the wellhead or the tanks back to the RTU that’s on the corner of the pad. That’s where they are usually located off there to the side. Just with the built in antenna that is on the base radio and the built in antenna that’s on to the transmitter, you’re able to go to 1,500 feet.

Weldon:  Wow.

Denis:  A lot of times, these transmitters are located right on the ground, especially talking about a Bradenhead pressure or casing pressure. After all the drilling operations are gone and everybody’s gone, you still have trucks running around on the pad, 18 wheelers, picking up water loads, and so forth. Those trucks when they sit there, it can block the signal. There’s ways to get around that.

You can take the transmitters and you can remote mount the sensor away from the actual transmitter. You can go and take and add coax to the transmitter and put the antenna up higher. You can go to the base radio and instead of having the little cabinet-mounted antenna, put a higher gain antenna and coax and put it 20 feet up in the air and get around all these obstacles.

You can cover the whole production pads. Sometimes, the well is remotely off of the tank battery. It’s where you have a centralized tank battery in cases like in the Permian Basin. Here, the wells are located in the surrounding area with that.

It is possible to go, for example, with higher gain antennas and you have, for example, a high tank level, and I got to shut the well in on that. You would transmit information to the remote well and it would shut it in, utilizing a discrete output.

Turn the ESD pump off, shut the sales valve in. It shuts the well so that you don’t overflow the tank. We’re able to get some good distances with these radios now.

Weldon:  What I hear you saying there is where historically we would have to put in an instrument on the level gauge or a switch or where we may have had to put it in a pressure gauge before and then put it in a separate communication hop just to get back to our RTU, or flow computer.

I hear you saying now that we’ve eliminated three additional pieces of equipment. The transmitter itself now talks all the way back to that remote side.

Denis:  Yeah, it’s much more simpler now, and of course, that reduces costs.

Weldon:  I like simpler and I like reduced cost. That’s some great information, Denis. What else do you have as parting words for us here or what have we not talked about that you would like to?

Denis:  Basically, we came a long ways in the technology of wireless instrumentation. We have many installations out there across the country in the different oil and gas fields. They’re trusted. They’re working well. Every year, each one of the manufacturers, we’re all pushing the technology and improving it and getting them better.

We’re trusting wireless instrumentation in all parts of our lives now. It’s becoming more and more prevalent, even in automobiles and so forth. It’s here to stay. We’re not going to be able to kill it and shut it off. I think we’ll start seeing it more.

Weldon:  Thanks a lot, Denis. I certainly appreciate you taking a few minutes and appreciate the great presentation you did at ASGMT earlier this week. We will get Denis’s contact information on the show notes.

If you would like to get a hold of Denis and ask additional questions, or if you want to talk to Denis about how you find Schneider instrumentation to work at your facility, he’ll be able to direct you to the right rep or the right person to help you there. Denis, thanks again, sir, and great having you on our podcast.

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Denis:  Thank you.

Weldon:  Thanks for listening and we hope you found this episode interesting. If you did, please leave us a review on iTunes, Google, or wherever you get your podcast fixes from. We also encourage you to share this podcast for your co-workers, your boss, and others in the industry.

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