In this month’s edition of the Pipeline Technology Podcast sponsored by Pipeline & Gas Journal, Dr. Alasdair Murray and Jeff Williamson of OptaSense discuss their recent article, “Application of Distributed Fiber-optic Sensing for Pipeline Integrity and Security.”

Listen to this episode to learn more about how fiber optic technology has evolved over the past decade, the application of fiber optic sensing to support leak detection in pipelines, how fiber optic technology can support the delivery of real-time data for decision-making, how the cost has improved to implement fiber cables to reach a favorable price point, the opportunity to dramatically reduce the effects of a pipeline incident, and more valuable topics.

Fiber Optic Sensing Applied to Pipelines: Show Notes, Links, and Insider Terms

• Dr. Alasdair Murray is a Data Analyst Engineer for OptaSense. Connect with Dr. Murray on LinkedIn.
• Jeff Williamson is the Global Managing Director, Infrastructure and Security Monitoring, for OptaSense. Connect with Jeff on LinkedIn.
  • OptaSense is a leader in leading-edge fiber optic Distributed Acoustic Sensing (DAS) solutions that reduce the cost of asset ownership by optimizing operational efficiency, performance, and safety. OptaSense operates in 40+ countries with more than 30,000km of assets under contract. The company is actively monitoring and protecting some of the world’s most valuable assets.
• Pipeline & Gas Journal is the essential resource for technology, industry information, and analytical trends in the midstream oil and gas industry.  For more information on how to become a subscriber, visit pgjonline.com/subscribe.
  • Read Dr. Murray and Jeff Williamson’s article, “Application of Distributed Fiber-optic Sensing for Pipeline Integrity and Security,” in the March 2021 edition of Pipeline & Gas Journal.
• Distributed Acoustic Sensing (DAS) is a Rayleigh-based scattering system that enables users to acquire continuous, real-time measurements along the entire length of a fiber optic cable.
  • Interrogator Units convert a single-mode fiber into thousands of extremely sensitive acoustic and vibration sensors. A DAS sensor connected to one end of the fiber uses a laser to send short pulses of light along the fiber. A small proportion of the light travelling in a fiber is reflected back through Rayleigh scattering.
    • The OptaSense QuantX interrogator unit interrogates the fiber with a sequence of launch pulses that unwrap higher fidelity phase and amplitude locked information from the Rayleigh backscatter.
      • The OptaSense ODH4+ High Performance Distributed Acoustic Sensing Interrogator Unit For Enhanced Fibers delivers superior measurements in multiple applications with the flexibility of using high backscatter fiber cables.
• Scattering refers to the loss of signal caused by the diffusion of a light beam traveling through a fiber optic cable. This usually occurs when a light signal hits a defect or impurity in the fiber.
  • Rayleigh backscattering is the process of scattering light at scattering centers along a fiber line. This newer form of scattering is key for distributed fiber optic sensing.
  • Raman scattering is an inelastic scattering process that results from the interaction of light with the vibrational or rotational modes of molecules within a fiber line.
  • Brillouin scattering is a nonlinear scattering effect involving acoustic phonons to detect the presence of molecules.
• Gas Pipeline Block Valve Stations are constructed to divide up segments of a gas pipeline, enabling each section to be isolated for inspection, cleaning, and maintenance.
• Leak Detection is the process of monitoring, diagnosing, and addressing a leak in a pipeline to mitigate risks.
  • Leak Detection Systems (LDS) include external and internal methods of leak detection. External methods are based on observing external factors within the pipeline to see if any product is released outside the line. Internal methods are based on measuring parameters of the hydraulics of the pipeline such as flow rate, pressure, density, or temperature. The information is placed in a computational algorithm to determine whether there is a leak.

Fiber Optic Sensing Applied to Pipelines: Full Episode Transcript

Announcer:  The Pipeline Technology Podcast, brought to you by Pipeline & Gas Journal, the decision-making resource for pipeline and midstream professionals. Now your host, Russel Treat.

Russel Treat:  Welcome to the Pipeline Technology Podcast, Episode 10. On this episode, our guests are Alasdair Murray, Principal Data Analyst, and Jeff Williamson, Managing Director of Infrastructure and Security Monitoring, both with OptaSense.

We’re going to talk to Alasdair and Jeff about their article published in the March 2021 Pipeline & Gas Journal titled, “Application of Distributed Fiber-optic Sensing for Pipeline Integrity and Security.”

Jeff, Alasdair, welcome to the Pipeline Technology Podcast.

Jeff Williamson:  It’s good to be with you today, Russel.

Alasdair Murray:  Pleasure to be here. Thanks for having us.

Russel:  We’ve asked you guys to come on and talk about the use of fiber optics for pipeline integrity and security. Before we diversity in, I’d like to ask you guys to do a little introduction. Tell us a bit about your background.

Jeff, if you would, could you go first?

Jeff:  Sure. More than happy to. Jeff Williamson, I am the Global Managing Director for OptaSense’s infrastructure business, which is basically pipelines, borders, any long, linear asset that’s up on the surface of the earth. I’ve been with OptaSense for eight years now.

I was basically a graduate mechanical engineer, got into controls and instrumentation business early in my career. Ending up getting into oil and gas 15 years into my career. Spent time in the energy services business making people very energy efficient in power quality/power reliability applications and technology.

OptaSense basically recruited me away from the oil and gas industry to come and do a startup on the infrastructure business. I started that eight years ago. It’s been quite a fun ride. We’re doing business in 40 countries and have applied the technology to over 30,000 kilometers of assets. It’s been quite good and quite fun.

Russel:  Awesome. Alasdair, same question. How did you get into fiber optics and applications towards pipelining?

Alasdair:  Sure, Russel. Thanks for asking. My background is not in pipeline and gas or oil and gas like with Jeff. I actually started out in physics, where I obtained a doctorate in acoustic metamaterials, something that you probably don’t hear too often in the oil and gas industry.

From there, I then went to work for a company called QinetiQ, where I was involved in underwater acoustic stealth. Then, for a complete change of pace, I came over to OptaSense three years ago. We get involved in a wide range of things, but one of my key areas has been the analysis and development of our pipeline product.

Russel:  There’s a couple things you said there I’d like you to unpack a little bit, Alasdair. The first is you said your doctorate is in acoustic metadata? Did I say that correctly?

Alasdair:  Acoustic metamaterials.

Russel:  Meta. What does that mean?

Alasdair:  For the uninitiated, acoustic metamaterials are effectively…They’re man-made materials that are designed to have properties that wouldn’t occur naturally in nature.

The one example that everyone can get on board with, which is really out there in the realms of sci-fi, is the Harry Potter invisibility cloak. It would probably never happen, but that’s the type of thing that people were looking to do with metamaterials.

Russel:  Interesting. You said you did a term doing underwater acoustic stealth? What is that?

Alasdair:  Very similar to the Harry Potter invisibility cloak, we were looking to hide things from sound underwater.

Russel:  Interesting. That’s fascinating. I don’t know. There’s probably a whole podcast just getting to unpack that a little bit, Alasdair. Let me ask you guys this question to kick off the conversation. How is it you’re able to take a strand of glass and use it for pipeline integrity and security? What is actually happening to be able to do that?

Alasdair:  It’s a great question, Russel. The very simple answer is that we take a long section of fiber optic cable and place what we call an interrogator unit at one end of the fiber and send a pulse of laser light down the fiber.

What this does is it allows us to turn that fiber into a distributed array of thousands of sensors, which we can use to pick up lots of different effects, such as temperature, strain, and vibration.

What I’ve told you doesn’t really tell you how it works. If we go into a little bit more detail on that, as that pulse of laser light is traveling down the fiber, what it’s doing is interacting with lots of microscopic inhomogeneities within the fiber. As it interacts with these little particles, it scatters. A small fraction of that light gets sent back towards the interrogator unit.

This is a continuous phenomenon, but because of the speed of light and the fiber is finite, we’re able to use the time of flight to work out where that scatter has come from. By interrogating that scatter, we’re able to interpret events that are occurring along the length of the fiber.

Russel:  That immediately raises a question around you mentioned time of flight. We’re talking about light. So is time of flight the speed of light?

Alasdair:  I understand what you mean by the speed of light, Russel, and yes it is traveling at the speed of light, but the speed of light in the fiber is slightly lower than in a vacuum. We’re talking 200 million meters a second as opposed to the 300 million meters a second you’d get in a vacuum. It’s still incredibly quick and effectively allows us to sample the entire fiber in real-time almost instantaneously.

Jeff:  With very little latency.

Alasdair:  Yeah, very little latency.

Russel:  For all intents and purposes almost unmeasurable I would think.

Alasdair:  Correct. [laughs]

Russel:  For a guy who comes out of controls and, Jeff, I’m sure you’ll appreciate this, we’re used to thinking about milliseconds as really fast. I’m thinking you guys are dealing with micro microseconds to be able to do this kind of processing.

Jeff:  You’re right. Basically just to take that a step further from controls and instrumentation. You think of point sensors. They typically, historically, have been electrical mechanical devices.

Basically what we’re doing is instead of having to wire up a lot of electrical mechanical sensing devices, we’re using that fiber optic cable, which is about the size of a hair follicle, shooting a light down it, and just say at 26 miles we’re turning it into 5,000 unique sensors.

Think about that and the power of that. If you had to go and take a standard electromechanical SCADA system with RTUs and that number of point sensors, could you imagine what the cost would be over let’s say 1,000 mile pipeline to wire that up? It’s huge.

Therein lies the value, if you will, to distribute acoustical sensing. It allows you to end up going along a pipeline and you’re able to look at every 30 feet and turn that into a unique point sensor.

Russel:  That brings up another question. You used I guess what I would consider a buzzword in the fiber optic community. This idea of digital acoustic sensing.

Jeff:  Distributive acoustical sensing.

Russel:  Yeah, sorry. Thank you. The word I’m focused on here is acoustic, because we’re talking about light. Acoustic is sound. Help me make that connection.

Alasdair:  Let me expand on that a bit for you, Russel. When I was talking about the light being scattered in the fiber, there’s a few different scattering mechanisms that can take place. Different fiber optic sensing technologies make use of these different scattering mechanisms.

We have distributed temperature sensing which makes use of Raman scattering. Distributed strain sensing tends to make use of Brillouin scattering and the OptaSense product for distributed acoustic sensing makes use of Rayleigh typology.

One of the nice things that’s coming out in the future with really advanced technology is the ability to use Rayleigh-based sensing to perform temperature and strain measurements as well.

Russel:  Talk to me, if you would, Alasdair, about the three kinds of sensing. You’re a PhD physicist talking to a bachelor’s degree engineer, so you don’t need to dumb it all the way down, but you’ve got to dumb it quite a ways down. How’s that? [laughs]

Alasdair:  I’ll do my best.

Russel:  If you’re a fan of Big Bang Theory, it’s Sheldon talking to the engineer. [laughs]

Alasdair:  Most of these products do what they say on the tin. A distributed temperature sensor will detect temperature changes along the length of a fiber and be able to identify where along that fiber the temperature change is occurring. Similarly, a distributed strain sensor can tell you what strain is occurring and where along the fiber.

In the early days of distributed acoustic sensing, we were primarily looking at vibrations and impacts. We’re able to pick out things like someone walking along the surface next to a fiber or a vehicle driving along the fiber. Anything that generates a vibration, such as manual digging. Digging next to fiber is obviously quite a key area of interest for the pipeline industry. That’s where these technologies grew from.

As I said, the future holds lots of very exciting things, certainly for distributed acoustic sensing. Because we’re seeing that we’re able to roll in that temperature and strain sensing capability as well.

Russel:  Interesting. I’m still processing what you’re telling me about the three different kinds of scatter. I’m sure there’s a lot more to trying to unpack that and the different kinds of sensing you’re doing.

Fundamentally, I’m trying to get an analogy that makes sense in my mind. I’m thinking about a prism and how a prism will break light up into the various colors. Pretty simplistic, but I guess similarly there’s other kinds of effects that will cause scatter. Then you’re measuring that scatter based on the kind of effect?

Alasdair:  Correct.

Russel:  I’m probably doing to bore the listeners to tears if I try to fully understand what you’re talking about in that domain, so maybe it’s best we move on a little bit.

What is the cost of implementing fiber? Jeff talked about I’m getting 5,000 sensors in 26 miles, that kind of thing, and what the comparative value is of that. What are we typically talking about in terms of cost of implementing fiber?

Jeff:  Great question, Russel. It’s going to end up varying. If you’re talking on a pipeline and the trench is already open because you’ve laid the pipeline into it, you absolutely get the removal of the cost to slot or dig in the fiber, because that’s already taken place. You’ve got a set of pipe to get into the right-of-way.

But, typically, the cost of the fiber as well as the interrogator unit in the system — I’ll give it to you in a range because it depends on the type of fiber it is as well as if you have to dig the slack cut or put the slack cut in for the fiber — it’s going to range anywhere from $4.50/foot to upwards of $12/foot. That’s all based upon the geology of the terrain if you have to slack cut it yourself.

If it’s already open, the trench is open already, then it’s just the labor and the cost of the fiber to lay into there. That’s going to end up being a couple of dollars to $4/foot for the fiber. Then if you look at the cost of the interrogator unit on a per-foot basis, you’re looking at probably another $2 to $3. Once again, $5 to $12-15/foot.

Where we found a lot of success with this in the early adopters is that they already had fiber specified going into the right-of-way for telecommunications as well as for security applications up and down the right-of-way. The fiber was there. All we needed to do was pick up an unused fiber that was in the bundle, so it was very cost-effective.

Russel:  The other thing I want to ask about, too, and maybe my information is a little dated. There’s a couple of things that at least in my experience working with fiber that creates some limitations.

One is you have to have a sending unit every certain amount of distance. How frequently do you have to have a sending unit? In other words, how much fiber can you run before you need to put some other sending unit on the fiber?

Jeff:  Another great question. What we end up doing is we typically put in a single location two interrogator units. One looking 26 miles in one direction, the other looking at 26 miles in the other direction. Basically, you can cover from a single point of power 52 plus miles.

In some applications, we can take up beyond 26 miles. It depends on what we’re looking for and what we’re trying to do with it. The fiber range is actually based on technology changing and what we’re doing with cleaner glass and cleaner fiber as well as some modifications to the interrogator units. We are increasing beyond that 52 miles per single location.

Russel:  Interesting.

Alasdair:  Just to add a bit to that, Russel. As Jeff was saying that existing technology is typically around 26 miles in each direction. But there are developments going on that are looking at extending those ranges.

Of course, as our laser pulse is traveling along the fiber, it’s constantly getting weaker. At some point, the scatter we’re receiving back is getting weaker. There is eventually a point where we’re not really detecting anything.

Some of the changes that can be looked at to extend these ranges are putting in specialist cables such as ultra-low loss cables, which allow that pulse to travel further. Or high backscatter cables, which can be added at the end of an existing range in order to boost the scatter coming back.

Of course, implementing specialist fibers is an expensive business compared to putting in standard technology and retrofitting interrogator units to standard single-mode fiber.

Russel:  There’s certainly a lot of applications where if you can do 10 miles there’s a lot of applications just there for sure.

Alasdair:  Yeah, a big part of our business out in the United States is in oil field services where we have fibers going down lines and fracture lines monitoring for fractures.

Russel:  Right. I’m familiar with that technology from experience quite a number of years ago. The other thing I wanted to ask you about this was maintainability. We all know if you’ve got a copper wire and you break it, then you’ve just got to connect that copper wire back up and there’s not a lot to maintaining quality of signal. What happens if you get a fiber broken?

Alasdair:  If a fiber breaks, obviously the laser pulse can’t get past that break, but you can cut out the broken section and splice in new fiber. There can be a bit of additional work to manage that because the geo-referencing of the system. Actually, mapping that fiber to the pipeline may end up being shifted by however much fiber is being spliced back in. But it’s a relatively simple repair.

Jeff:  Let me add another point, Russel, if I might. If you think about it, in landing copper wires, it typically takes time to make that particular repair if it’s broken as well. It’s tried and proven methods. Fiber optic cable and splicing has been around for a pretty good time now. There’s a very good, strong industry that people understand how to splice it and put it back together.

Alasdair is absolutely on point in saying that once you have a break, you just need to come in and test your geo-referencing points because you’re basically looking at time of flight. Time that you posted and what time the arrival coming back of the backscatter.

You’ve got to make sure you know where it is along the pipeline or you’re just going to end up getting a signal and your reference will not be correct where it is. You will have to do a little bit of geo-referencing, but that’s pretty simple to do as well.

Russel:  That’s kind of a calibration activity.

Jeff:  Exactly.

Russel:  I guess the point I’m driving at in asking these questions, guys, is that my experience with fiber is probably at this point 15 years old or more since I was actually implementing a system using fiber.

There were a lot of challenges at that time with fiber that I would think the industry has overcome and evolved beyond. That’s the point I was trying to make with asking these questions. “Where are we now versus when I had experience with it quite a number of years ago.”

Let’s transition again. What’s the value of fiber once you have it in? What are the things I’m able to do?

Alasdair:  I think we’ve touched on a few of these things already, about how that fiber optic cable can be turned into thousands of sensors along the monitored asset, which provides real-time sensing of what we’re looking for.

Typically, on a 26-mile system, we’ll be sampling at 2.0-2.5 kilohertz. It’s very much real-time. There’s minimal power requirements because fiber optic cable itself doesn’t require anything, so it’s just powering the block valve stations where the hardware is located. We can cover a pretty long range from a single location.

I think what you’re angling towards is what can we actually detect using these systems.

Russel:  Right, exactly.

Alasdair:  Three of the key areas that we look at with respect to pipelines is third-party intrusion, which is where the bulk of the early uptakers were. By third-party intrusion, we’re talking about people walking along the right-of-way, or vehicles appearing along the right-of-way. We were searching for hopped-up events, digging located next to the pipeline trying to prevent damage to the structure.

More recently, we’re talking 10 years ago now that our first leak detection product was released, and that’s been growing and developing since then. One of the main areas of use is also in the detection of leaks. What we’re discovering is that fiber optic leak detection is incredibly sensitive and quick.

We have four different modes of detection that we look for. These are a negative pressure pulse. This occurs at the instant the pipeline ruptures and there’s a sudden loss of pressure in the pipeline. What this generates is a pressure pulse that propagates in both directions from the leak location.

Obviously, there’s no imagery here but what it generates on the system is a beautiful V shape that points directly to where the leak occurred. Because it happens at the instant that the leak occurs, the detection is within seconds.

Three of the modes that we look for are orifice noise. This is product being forced out of the pipeline and generating vibrations in the ground or however it’s propagating to the fiber. Any strain that can occur.

This is particularly prevalent with gas pipelines because you’ve got pressurized gas expanding out of the pipe and rapidly expanding and with distributed temperature changes. If there is a temperature difference between the product and the fiber, then that will eventually cause detectable changes in the fiber.

One of the questions we’re always asked about this is what sort of sensitivity are we looking at? With the negative pressure pulse, as I said, we can detect within seconds and currently have evidence of detection down to one and a half liters a minute. Sorry, I’m talking in European measures there. If I convert it, that’s around six barrels an hour. That is the smallest leak that we’ve detected with the negative pressure pulse.

The orifice noise strain and temperature change detectors are less sensitive than that, but we’re still talking around 60 barrels an hour as a sensitivity with a detection time of a few minutes.

Russel:  I think a lot of people that don’t work in the domain of leak detection don’t really understand that this basic idea of there’s three factors that you’re trying to take care of if you have a leak. One is speed of detection. The other is how small of a leak can I detect. The last is location. Because all of those things go to response.

We’re pretty good at finding big leaks quickly. We’re not very good as an industry at finding little leaks quickly.

Alasdair:  It’s understandable.

Russel:  Yeah. A “little leak” is relative. It’s relative to the flow rate in most cases, but in this case, it’s really more relative to your ability to pick up the noise or temperature change, which is not necessarily related to the size of pipe, which is also different than other methods of detection. I should frame that as a question. Am I on track with that?

Alasdair:  I think broadly speaking, you’re on track, yeah. For temperature change, there has to be a temperature difference and enough product being leaked to enact enough of a change. These systems are sensitive to fractions of a degree changes.

Similarly, for orifice noise, the flow rate has to be high enough to generate significant vibrations. As I say, we specify that at around 60 barrels an hour as a flow rate.

I think just to try and give some numbers to that, when we undertook some full-scale leak testing out in Brazil, to get flow rates of that order, we were looking at a 10-inch diameter pipeline at 10 bar pressure with a 10 millimeter orifice. It was sizeable that you could see it with your eye, but it was still a relatively small hole.

Russel:  Yeah. You ran all that in the imperial units and I’m trying to get that back to our units. [laughs]

Alasdair:  Sorry. Jeff’s on the conversion for me.

Jeff:  Yeah, we’re trying to do the conversion. I thought you were going to ask that, Russel. You’ve got to be in the plus 200 PSI gauge.

Russel:  10 millimeters, what is that in inches?

Alasdair:  That’s about half an inch.

Russel:  About half an inch, right.

Alasdair:  A bit less than half an inch diameter.

Russel:  That’s still a fairly good size hole. It’s not a micro leak.

Alasdair:  To contrast that. That’s for the orifice noise strain and temperature detectors, but with the negative pressure pulse, then you’re then talking a 1 millimeter diameter hole.

Russel:  Wow, that’s starting to get tiny.

Jeff:  That’s getting tiny. It’s a 10 order of magnitude difference in that. You’ve got to put that into perspective.

Russel:  Exactly right. I want to ask you a couple more questions just about how you implement fiber to detect these things. Typically, if I’m putting fiber in, I’m not just running a single strand. I’m running a number of strands in a single pool, or a single drop I guess is a better way to say that.

Am I doing all this sensing on a single strand of fiber or do I use a different strand of fiber for each type of sensing I’m doing?

Jeff:  On our particular product for the Rayleigh backscatter, we basically, in essence, are using one fiber across the entire pipeline for sensing. That’s a single core. One single core. We typically use another core to run the data on, which we don’t have to. We can run it on the same one using some techniques. The point being we use one dark fiber.

Typically, what happens, though, in a bundle of fibers, especially what’s going into pipelines today, is there’s a bundle in there for their telecoms, their security packages, video backhaul, those types of things as well as their network.

A lot of pipelines across the globe are putting in much larger bundles. We’re talking 256 cores where they’re actually taking broadband to rural areas, which in essence is creating a revenue stream for that particular asset because they’re selling bandwidth.

I know in Texas, one of our particular clients, that’s what they ended up doing to create another revenue stream. Not only providing leak protection and third-party intrusion across the asset, but they also are able to get revenue streams for providing data access to rural West Texas. It’s quite a very lucrative deal for that particular asset owner, because it ended up giving them a much better rate of return.

Russel:  Yeah, that’s really interesting. That’s one of those things where you never know how that’s going to play out. You might find that the telecom revenue is more valuable than the pipeline revenue. Who knows, right?

Jeff:  It might be, but if you think about it from a leaks standpoint, the sooner you realize that the leak is there and the faster you’re able to turn the valves, what ends up happening is you minimize the environmental impact.

If you think about that, and really what’s a bad day for a pipeline operator? It’s probably getting a leak, because all of a sudden, your valuation of your company just went down on the bad news. That’s gone down.

Now I’ve got to go out there and I’ve got to clean this mess up. I normally get paid on the transportation cost. How many barrels a day am I passing through the pipeline? Then all of a sudden, you’ve got that loss of revenue.

It’s a huge impact if a pipeline operator gets a leak. It’s just not the loss of product and those revenues, but the cleanup is very astronomical depending on what is carried in the pipe.

Russel:  That’s absolutely true. I say this all the time, but being a pipeliner is like being an offensive lineman. You get your number calls when you screw up. You get press, you get airplay when you make a mistake. Those consequences of those mistakes are big.

Certainly, this is a technology that provides a lot of value. I think at least in my experience it’s not well understood.

Jeff:  Surprisingly enough though, Russel, compared to where it was eight years ago, when I got into the industry, everybody thought it was magic was what we’re doing. Now, more and more as the industry is getting educated on the value of what this brings as well as the asset owners, what it’s enabled them to do from a preventative or mitigation standpoint, people have taken a marked interest in this. We’re seeing more and more, as time moves forward, adoption.

I think the future is going to be bright for this sensing because as I said you can’t afford to wire up 5,000 sensors across 26 miles. It’s very cost-prohibitive in comparison with what you get here.

Russel:  I think also to your point, Jeff, that what we’re going to see in the future is we’re going to be able to get more distance, more data, more sensitivity as the instrumentation continues to improve. I expect that we’re going to see an order of magnitude improvement in performance in these technologies in the next 10 years.

Alasdair:  Certainly. You’ve got to think in the grand scheme of things this technology is still relatively young compared to a lot of other things that are out there.

Russel:  Right, exactly, Alasdair. I think that’s really true.

Jeff:  This one proof point on that is that the next generation of fiber sensing as we see it today we were talking earlier being able to cover 52 plus miles from a single location. What we’re seeing now with our next generation device from that same location we’re going about 125 miles.

Russel:  Yeah, and that’s a game-changer, too, because you just don’t find runs longer than that where you don’t have power.

Jeff:  Exactly.

Russel:  What do you think pipeliners should know about this technology? What would you want the entire industry to know and understand about fiber and summarizing what the value of all this is?

Alasdair:  So many things. We very briefly touched on it earlier that we’ve gone out over the past few years and undertaken several large-scale trials on full-scale pipelines in order to verify that the system does what we want it to do.

The numbers that we’ve been putting out there, we like to think that those are proven solutions that provide leak detection. We have a long history with the third-party intrusion product, which has provided a great many examples of positive use cases.

I think at the moment, we have around over 20,000 miles of asset under monitoring over the history of OptaSense.

Jeff:  If I could add, too, a bit, Russel. I think that, importantly, is that we as OptaSense sell proven technology and we apply proven technology. We spend the time, the effort, and the money to prove out what we say in our spec.

I would tell you anything people take away is for pipelines, there’s a proven technology that will end up providing help with third-party intrusion, perimeter protection around the block valve stations, as well as leak detection as well as scrape or pig tracking. We do that very well. It’s there. It’s done. You’ve got decision-ready data so that you can make decisions once it comes in. And it’s affordable. It is very much affordable today.

10 years ago, it probably wasn’t affordable, but as new technology goes over time, what happens is the price point goes down and it’s coming down now in these markets where it truly is affordable for a decision-ready information system while managing the asset.

Russel:  Awesome. Gentlemen, thank you for coming on and talking about fiber optics and pipelining. I’ve certainly learned a lot. I feel like I’ve got updated a little bit. I think my information was a bit dated. Again, thank you very much. This has been awesome.

Jeff:  Thank you.

Alasdair:  Yeah, it’s been a pleasure being here, Russel. Thank you for having us.

Russel:  I hope you enjoyed this month’s episode of the Pipeline Technology Podcast and our conversation with Alasdair and Jeff. If you would like to support this podcast, the best thing to do is to leave us a review on Apple Podcast, Google Play, or on your smart device podcast app. You could find instructions at pipelinepodcastnetwork.com.

If there is a Pipeline & Gas Journal article where you’d like to hear from the author, please let me know either on the Contact Us page of pipelinepodcastnetwork.com or reach out to me on LinkedIn. Thanks for listening. I’ll talk to you next month.

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Transcription by CastingWords