Many refineries and oil terminals are located beside major stretches of water, either sea or river, to provide a cost-effective transportation route for incoming crude oil and feedstock, and for outing finished products.
If left undetected, a hydrocarbon leak resulting from corrosion in a jetty line will go straight into the local water sources causing serious environmental damage to the local ecosystem and to company reputation.
Using continuous corrosion monitoring to proactively collect data on pipe integrity over time, operators can avoid environmental incidents, as well as increase operational performance, reduce unplanned outages, limit personnel in hazardous locations, and reduce the need for reactive maintenance.
In this storage terminal safety podcast, we are joined by Emerson’s Jake Davies to talk ways we’re helping industry leaders keep an eye on corrosion and erosion with innovative continuous and remote corrosion monitoring technologies
Visit the Storage Terminal Safety and the Corrosion & Erosion Monitoring sections on Emerson.com for more on the technologies and solutions to help you drive safer, more reliable, and more efficient terminal operations.
Jim: Hello, everybody. I’m Jim Cahill with the Emerson Automation Experts blog. And as part of our continuing podcast series on enabling storage terminals safety, I’m joined today by Jake Davies. And Jake is a director of Global Product Marketing for Emerson’s Corrosion and Erosion Solutions business. We’ll be discussing ways to monitor for corrosion in storage, terminal, jetty pipelines, and other spots. Welcome, Jake.
Jake: Thanks for having me, Jim. Great to be here.
Jim: Well, it’s great to be doing this. Let’s begin by having you share with our listeners your educational background and path to your current role.
Jake: Sure. Okay. It’s a long path, but it started with, I guess, a formal university education in engineering. I had a little time in industry, not the process industry, but more electronics. And then I went back to university and did a Ph.D. in ultrasonic engineering. And then after that, and in fact, while I was doing my Ph.D., a Ph.D. colleague of mine was researching some corrosion monitoring opportunities. And that actually led, just as I finished my Ph.D., to the formation of a startup company which was called Permasense. So, I joined that after my Ph.D. And really, at that time, we were two people. So, I did a lot of different roles ranging from customer support, design, engineering, supply chain management, production. I used to make some of the equipment myself. So, I really did a lot of roles in that startup as you can imagine.
And that startup became very successful. The technology was well adopted by the oil and gas industry. And in fact, that company was acquired by Emerson in 2016. So, that’s when I came into Emerson. And since then, we have joined that acquisition with Emerson’s wider Corrosion and Erosion monitoring portfolio. And effectively, I look after that portfolio in Emerson and now. Oh, and on the way, I did an MBA as well. I forgot to mention that in terms of educational background. So, yeah. I guess quite well-educated, but a lot more experience in, I would say, hands-on getting the job done. I learn more that way I think.
Jim: Yeah, it sounds like you’re a full-fledged entrepreneur to, you know, a startup company with two. I can imagine everything from helping drive some sales and supporting the customers and everything probably to pushing a broom at the end of the day to clean the dust down around there.
Jake: Yeah. Yeah. I think that sums up the range pretty well, yeah.
Jim: Yeah. That’s a tremendous background. So, let’s get into it a little bit. I know one of the things that terminals would be concerned about are hydrocarbon leaks caused by equipment failure and some other things. So, what are some of these types of issues, and what can be done to help mitigate some of these risks?
Jake: Yeah, exactly. I mean, most of the time, storage tanks and terminals, in general, are obviously holding and moving dangerous substances ultimately, fluids which, you know, aren’t nice to be in contact with for humans, aren’t nice to release into the environment. And so, clearly, all of the equipment in that terminal fundamentally is there to contain that nasty stuff and prevent it from getting out into the environment and making a mess and damaging things or potentially, some hydrocarbons as an example, extremely flammable. So, we need to do everything in the terminal to contain those fluids. So, we talk a lot about, in the process industry, hydrocarbon containment, but clearly, there are other fluids that may be in tanks and terminals which aren’t necessarily hydrocarbons, but they might still be not particularly nice to get out into the environment.
So, those thin bits of metal that make up that equipment, whether that’s piping, vessels, storage tanks, you know, generally, they’re made of metal. And one of the major concerns is if that metal is corroding, it’s getting thinner over time, and eventually, it might get so thin that the fluid contained within leaks to the environment outside. And then, of course, you have huge environmental problems. You’re going to have environmental fines most likely because of the nature of these substances, these fluids. They may be very harmful to personnel or indeed people living in the local community. And so, really containing these fluids is the key. And as I say, the metalwork that make up the equipment of these assets is what is preventing that fluid escaping.
And so, we need to be, as operators of these plants, these assets, we need to care about the condition of that infrastructure and corrosion from the inside and indeed, potentially from the outside, from the atmosphere side can, in some cases, under certain conditions, quite quickly damage that infrastructure. And so, what we’re talking about today is how do we actually monitor, how do we understand the health of that equipment such that we can avoid or, at least, detect quickly and early when corrosion is damaging it such that we can prevent such major incidents like loss of hydrocarbon containment?
Jim: So, it sounds like there’s obviously safety concerns because highly flammable fluids and all this that environmental leak any of it could subject you to fines, you know, issues in the community, damage to your brand, your company name, and everything from the, you know, negative in all kinds of bad things. So, yeah, it sounds like we definitely want to spot the problems and avoid them. What is it around the jetty pipelines that is a particular area of concern for the storage terminals that have jetties as a way to move product?
Jake: Yeah, I think it’s two-fold, one in terms of the environmental impact. Obviously, the jetty tends to, or nearly always is consists of pipework or piping, which is going from the storage tanks on land and linking them with the tanker ships that are coming in and either offloading a product or taking it away again from the terminal. And by definition, those are above water. And so, any leaks that occur in those lines tend to go straight into the water and that makes any subsequent cleanup or, kind of, environmental impact significantly worse than if it happened on land, where typically, you can build raised earthworks, you know, to prevent the fluid leaking. Even if the tank fails, you can still catch the fluid in the locale. And that makes cleanup whilst still involving…and that would still count as a major incident, obviously, if that happened, but if it happens above water, then that escaped fluid, that leaked fluid is, kind of, almost instantly going to start destroying that habitat. So, the impact of the incident tends to be more severe in terms of cleanup and costs.
Jim: I’m just thinking about it. What would be the traditional way versus a different approach for monitoring for it to avoid what would be a very bad situation of leaking into open water?
Jake: Yeah. A good question. So, in general, for these applications and indeed many others throughout the process industry, we have a 50, 60-year-old approach to trying to understand the equipment health and the equipment integrity when that equipment is faced with this potential to corrode from the inside and that is called manual inspection. So, typically, what happens under that approach is that you send out, kind of, an expert crew of so-called non-disruptive testing or NDT technicians, and they carry with them handheld devices, and they actually access the pipe itself. They may remove any installation to get to the outside of that pipe and they use, typically, an ultrasonic device, which is, sort of, pressed against the outside of that pipe, and that will read the thickness of the pipe in that location. And typically, you’re sending this crew around into the different areas to measure the health or the remaining fitness of the plant or the piping in lots of different high-risk locations.
But because you’re sending someone around, you obviously, you know, have to fund that. You have to get access to the pipe, you have to build a staging, you have to hire expert people and service providers and that clearly incurs costs. And what that means is you are likely to only get to the same location every couple of years. If you think about maybe a jetty and a terminal, it probably has maybe 100 locations typically that you would want to send someone to gather this data, but because of cost constraints, generally, they’re only going to get to each one of those locations maybe every couple of years. And there’s lots of regulation around this, around how frequently this manual inspection needs to happen in any given facility, terminals included, and jetty lines in terminals included. But the real challenge with this approach is that it is only giving you this snapshot measurement in time. And then you effectively have to run blind for, let’s say, another five years until you get that next measurement from the same location.
So, clearly, a lot, kind of, happened to the health of that asset, in this case, jetty piping or pipework. That means you have a very, almost instantly out-of-date understanding of the health of your plant. It’s too sparse in time. And so, whilst that measurement can be very reliable and very accurate, it is very sparse in time. And clearly, when we have corrosion events which maybe, in very extreme circumstances, could eat through piping in days or weeks and cause that leak, the risk is, of course, that that event happens and you don’t see it because you are only measuring it every few years. So, that fundamentally is the challenge with that manual inspection process in this application and ultimately across all process industries where internal corrosion is a problem.
Jim: And I’m trying to visualize, especially as pipelines going out over the water too, you know, that must be challenging just to physically get to them and perform this.
Jake: That is the other reason why jetty pipelines become a focus for monitoring tools, which we’ll start to talk about in a second because getting that technician to that jetty pipework is challenging. Typically, you’re talking about either building dedicated staging, which, kind of, you know, hangs down off the jetty so that someone can go down, maybe a rope access technician can go down, remove the insulation, take the measurement of the pipe, replace the insulation, you know, and then shimmy on along the pipe to get to the next location. Or you’re talking about trying to do this from a small boat or a rib or something underneath the jetty, which again, clearly, poses plenty of challenges for trying to take these measurements by hand. So, yeah, the cost of accessing the location to take the inspection by hand is, in this application, probably significantly more expensive than the act of taking the measurement itself.
Jim: Well, thankfully, technology’s been just rapidly advancing for all of us. So, now that we’ve heard a bit about the traditional way and the challenges involved in that, what’s a better approach in helping solve these kinds of issues?
Jake: Well, we believe, and indeed, many of our customers are discovering the value of moving from this, sort of, traditional, as I say, 50, 60-year-old method of taking measurements by hand very infrequently and beginning to migrate towards a continuous monitoring approach. And in order to do that, you effectively leave the measurement device in place on the equipment, in this case, the jetty pipeline. And we’re talking about very small, compact, wireless, battery-powered devices. So, no cabling. So, instead of going to take the measurement by hand every few years, you install a device once in that location, and then you leverage technology advances like wireless to get that data to desk.
And then not only are you removing the subsequent cost of having to go to that location by hand, but you’re also then able to get practically continuous data directly to your desk. So, you’re removing the difficulty, cost, safety risk of having to access that location, but also significantly increasing the quality and the frequency of data that you retrieve. And clearly, that frequency of data moving to continuous effectively would be almost impossible from a manpower resourcing cost base if you were trying to send someone maybe twice a day to that location to try and gather that same frequency of data. It simply isn’t cost-effective, unless you are going to automate that process with these more modern monitoring devices.
Jim: And it’s not like the data that’s coming from these devices is being used in control in any way. So, I got to imagine with whatever the sampling rate is on that, that as battery-powered devices, they’d last a long time.
Jake: Yeah, exactly. I mean, in my field, we talk about continuous monitoring of corrosion, but corrosion is relative to things like pressure and temperature and process monitoring going to vary significantly less fast than those process variables. So, whereas you may be interested in taking that kind of data maybe once a second or potentially even more frequent. You know, our devices by default will send a measurement every 12 hours or twice per day. I mean, the beauty of modern wireless technology like WirelessHART is that we have a two-way communication. So, not only is the data being automatically retrieved every 12 hours directly to desk, but also from desk, you can control that device and increase that measurement frequency if you want.
So, perhaps not this particular application, but for example, sand production on an offshore gas production well, sand production in that could maybe destroy that piping in less than 24 hours. In which case, for that particular application, you would want to achieve up the measurement frequency a little bit, but typically, you’re still only talking maybe once an hour, once every 15 minutes, something like that. So, absolutely, these devices, the battery will last seven years plus, no problem.
Jim: Well, that sounds really good. So, for those terminals there with, you know, existing systems in place for controlling or giving the operators around visibility into what’s happening around the terminal, how does this corrosion and erosion monitoring system integrate with those type of systems?
Jake: Well, again, that’s another fantastic feature of a WirelessHART technology because the mesh, the wireless mesh, if you imagine, the communication channels that exist between the devices to retrieve that data is so-called self-forming and self-healing. And what that means is if you already have some of this wireless data retrieval for other things…and clearly, we haven’t got time to talk about all of those other wireless measurement devices available from Emerson, the catalog is enormous. But if you’re already using that kind of thing and you already have this so-called gateway installed, then the beauty is you just come along with another device such as this thickness monitoring percent sensor, and you simply install it. And that device will immediately hook-in to that existing infrastructure and start communicating and retrieving its data. So, it’s extremely straightforward to drop in additional devices into that existing infrastructure.
That said, the self-forming element, if you don’t have that existing infrastructure, we are talking about one device, which is called a gateway, and that is the interface between the wired IT infrastructure that already exists somewhere in the plant and the devices. So, you’re just talking about having to make that one thing, which is the interface between the wireless world and the existing cable infrastructure that the customer will already have in that plant. So, it’s basically very easy to get going, and it’s also very easy to add once you have got going.
Jim: Yeah. It sounds like with that gateway is the device connected one way or another into the PLC, or DCS system, or whatever that they have in the facility. Yeah. You’re adding a device and it hops on and joins the network. You had mentioned a little earlier that there are other corrosion monitoring solutions. How does a user assess and select the best corrosion or erosion monitoring technology to use for their application?
Jake: That’s a great question. And actually, one in my current role, I feel, actually, Emerson is one of the only people that can genuinely answer that question for you. And that’s because we really do have a very, very complete range of corrosion and erosion measurement technologies. And that allows us to help a customer choose the right technologies. And I say technologies plural because most of the time, anyone with a corrosion or erosion challenge such as the one we’re talking about today with the jetty pipelines are interested in both early warning of risk and an understanding of all those…is that high-risk condition, is that corrosive condition that I have in my plant? How is that impacting the health of my plant? So, we frequently talk about in any given application for any given, sort of, corrosion challenge that we come across in any application, we talk about the desire and indeed the need to monitor both the risk and the impact.
And typically, I’m not going to say for every application, but typically, to monitor the risk, we use an intrusive probe or a so-called inline probe, and that’s actually a sacrificial device that we actually put inside the process fluid so that has a process penetration, it goes inside the process fluid, it’s in contact with the process fluid, and is super responsive to changes in that corrosive fluid. So, that tells you about the corrosion or the erosion risk of the fluid in the pipe. And then we use typically non-intrusive wall thickness monitoring devices to monitor the health of the asset itself. And clearly, that is what is changing if you have corrosion events that are eating away the plant. If the plant is being eaten away, if corrosion is happening, that will impact the thickness of the metal and we detect it that way. So, we’re looking at both the risk and the impact.
Clearly, we want to make sure we leverage such technologies that we’ve already talked about like wireless, software, visualization, and analytics, because one of the main things about moving from an inspection to a monitoring continuously, is that you’re going to be gathering a whole lot more data. So, you also need tools to help you make sense and get value of all this data. You don’t just want, you know, you don’t want an email coming up every time you get a measurement twice a day. You want to be able to look at trends, you want to be able to correlate with other process variables. And that’s where I’m bringing all the data together and using some sort of cutting-edge visualization and analytics tools. We can really add value to the data, or at least make sure that the customer is able to extract that value from this data.
Jim: That’s interesting, those different approaches and what you’re trying to do with it. Let me ask you one more before we wrap things up here. Do you have any example, like economics of, if somebody’s doing something the traditional way and moving to more of continuous monitoring approach, you know, that you’ve seen from places where we’ve implemented these technologies?
Jake: I think the cost comparison, if you will, between the traditional approach and the, sort of, modern monitoring approach will depend on how difficult the asset is to access. You know, so, we discussed for the jetty pipelines, if you’re building staging, if you’re having to, like, you know, secure a ship and trying to take the measurements, you’ve got to secure…clearly, you have to have a crew. You know, there’s all the safety concerns around that. So, there’s a lot more cost associated with getting those technicians to those locations. So, it’s quite variable, but for the most part over, let’s say, five years, the cost of monitoring is likely to be comparable with the cost of inspection. But really, the value add is whilst the cost might be comparable, under the monitoring scenario, you have gathered continuous data. So, every single day you know the health of your plant, whereas under the traditional inspection regime, you are up to five years old with your understanding of how your plant, of the health of your plant, and the understanding of how it’s coping with the corrosion burden or the corrosion demand being placed on it from within.
So, where we find the most valuable or where our customers find the most value is not necessarily in looking at reducing the cost base, although there is a reason to do that, as I say, in such difficult to access locations as jetty pipelines. But the mega value for these systems comes when, for example, the corrosion risk is varying frequently over time. And if you only are gathering, kind of, the average corrosion rate by looking at the difference between two measurements, one five years ago, and one yesterday, then clearly, at best, you’re going to get, kind of, a generic average corrosion rate for that asset. But it’s not going to tell you anything about when that metal loss actually occurred. And the flip side is if you do know when that metal loss actually occurred because you are monitoring, you can clearly do very reliable root cause analysis because you can say, you know, “On the 1st of October, my corrosion rate went from 0 to 50 mils per year. You know, it went from basically nothing. I was tracking no metal loss, then all of a sudden, you know, on a certain date, the corrosion rate went really, really high.”
So, if you’re monitoring, you detect that almost instantly, and then you say, “Well, it started on this day. You know, what in my other recorded process variables happened on that day?” And that’s how you begin to correlate the impact. So, we’re monitoring the impact with the Permasense devices, you know, the health of the equipment, the impact of corrosion on that equipment. But as a plant operator, you are already monitoring loads of other things and those loads of other things are likely to be some of the causes of corrosion. So, for example, in a jetty pipeline, you may be offloading a certain batch of crude, you know, from a ship and maybe that is a really corrosive batch and that’s what, you know, eats away your metal and maybe it only happens over a day, but clearly, unless you’re monitoring, you can’t see those events.
And it’s those seeing of those events in, you know, near real-time that allow you to take the preventative actions to avoid the loss of containment because clearly, if you know the pipe is already in a state that it’s about to go pop and leak, then you will not use that equipment. You know, that’s emergency shut downtime and your…well, not emergency shut downtime, but it’s, “Okay, we need to plan the maintenance. We need to replace this bit of equipment.” If you’re not monitoring, you’re just not going to see that. And the first you know about that corrosion, which has been happening, you know, inside the pipe from the process side out, is that you’re leaking hydrocarbon into the river. Clearly, depending on how quickly you spot that greatly affects your ability to clean it up and the economic impact of that leak, but if you’re monitoring, you can avoid that altogether.
Jim: Yeah. So, it sounds like you shouldn’t necessarily do the evaluation based on, you know, operation, no costs to manually inspect versus putting those continuous monitoring, “Oh, in the long-term, that’ll payout.” It’s more risk avoidance in so many areas and knowing the state better and maybe saying, “You know, we’ve got to do something with this pipeline before we take that high acid crude in here that could really cause some damage in there.” Well, Jake, I know I’ve learned a ton and I’m hoping our listeners have gotten quite a bit out of this. Where can they go to learn more?
Jake: In terms of finding more about this very particular initiative in terms of terminal safety, you can go to emerson.com/terminal-safety. And probably the easiest way to get hold of me, and I’m very willing to continue the conversation, is on LinkedIn, very active on LinkedIn. And then if you want to look for more general information about some of the corrosion monitoring solutions or erosion monitoring solutions we’ve talked about today, perhaps outside of the terminal application, I suggest to search for Emerson corrosion monitoring and you will find our portfolio on Emerson.com.
Jim: Well, that’s great. A couple of places for our listeners to go and I’ll make sure to include links in the transcript of our conversation here. So, thank you so much for joining us today, Jake.
Jake: Thanks for having me, Jim. I really appreciate it.
End of transcript.