In this month’s edition of the Pipeline Technology Podcast sponsored by Pipeline & Gas Journal, Stephen Rawlinson and Wes Gardner of STATS Group discuss using isolation plugs in remote area pipeline rerouting from their November 2021 article in Pipeline & Gas Journal.
In this episode, you will learn about the STATS project featured in P&GJ, including pigging and the pigging methods utilized for the project, the purpose of isolation certificates, and what every pipeliner should know about pipeline isolation and rerouting, especially in remote areas.
Remote Area Pipeline Rerouting: Show Notes, Links, and Insider Terms
- Stephen Rawlinson is Regional Director of North America for STATS Group. Connect with Stephen on LinkedIn.
- Wes Gardner is a Design Engineer (E.I.T) at STATS Group. Connect with Wes on LinkedIn.
- STATS Group (STATSGroup.com) are market leaders in the supply of pressurised pipeline isolation, hot tapping, and plugging services to the global oil, gas, and petrochemical industries.
- Read Stephen and Wes’ article in the November 2021 edition of Pipeline & Gas Journal, “Using Isolation Plugs in Remote Area Pipeline Rerouting.”
- Access the referenced STATS brochures on pipeline isolation and intervention on their website.
- Remote Tecno Plug® from STATS features a fail-safe double block and bleed pipeline isolation of pressurised systems while they remain live and at operating pressure. The isolation plugs provide dual seals with a zero-energy zone to enable maintenance work on pressurised systems to be carried out safely and efficiently.
- Download the brochure, “Non-Intrusive Inline Isolation: Tecno Plug®.”
- Association of Professional Engineers and Geoscientists of Alberta (APEGA) regulates the practices of engineering and geoscience in Alberta on behalf of the Government of Alberta through the Engineering and Geoscience Professions Act.
- The Principles and Practice of Engineering (PE) exam tests for a minimum level of competency in a particular engineering discipline. It is designed for engineers who have gained a minimum of four years’ post-college work experience in their chosen engineering discipline.
- Pipe fittings are components used to join pipe sections together with other fluid control products like valves and pumps to create pipelines.
- Hot Tap is a procedure involving attaching a branch connection and valve on the outside of an operating pipeline, and then cutting out the pipe-line wall within the branch and removing the wall section through the valve. Hot tapping avoids product loss, methane emissions, and disruption of service to customers.
- Muskeg is part of the landscape in Canada characterized by a wet environment, vegetation, and peat deposits.
- Pigging refers to using devices known as “pigs” to perform maintenance operations. This tool associated with inline pipeline inspection has now become known as a Pipeline Inspection Gauge (PIG).
- Piggability/Piggable refers to the ability for a pig to successfully traverse the pipeline from launch to receipt.
- Purge Pig a pig utilized to conduct a pipeline purge. The practice involves inserting a pig into an isolated section of pipeline, pumping inert gas is then behind the pig to push natural gas through to the product line. At the appropriate shutoff point, the pig is caught in a pig trap and the pipeline blocked off. Once the pipeline is “gas free” the inert gas is vented to the atmosphere.
- Geometry Pig is defined as a configuration pig designed to record conditions, such as dents, wrinkles, ovality, bend radius and angel, and occasionally indication of a significant internal corrosion, by making measurements of the inside surface of the pipe.
- Bidirectional pigs are used in pipeline construction for hydrostatic testing or water displacement, as well as removal of debris and product separation. These pigs have excellent sealing qualities, and their bi-directional design allows the pig to run in either direction in the pipeline.
- Inline Inspection (ILI) is a method to assess the integrity and condition of a pipe by determining the existence of cracks, deformities, or other structural issues that could cause a leak.
- Magnetic Flux Leakage (MFL) is a magnetic method of nondestructive testing that is used to detect corrosion and pitting in pipelines.
- Line fill is the total quantity of product, including the volume of oil required by the carrier for the efficient operation of the pipeline needed to occupy the physical space within the pipeline and any applicable facilities.
- Line stops are used to temporarily shut down a pipeline system to complete modifications or repairs. They allow a system to operate as usual without any interruption of service.
- HNBR (Hydrogentated Butadiene) is a type of rubber seal used to support pressure resistance in extreme environments.
- Annulus (Annulus Ring) is defined as the space between two concentric objects, such as between the wellbore and casing or between casing and tubing, where fluid can flow. Pipe may consist of drill collars, drillpipe, casing, or tubing.
- Upstream pressure can be related to pressure drop through a flow device, such as a valve, strainer, flow meter, elbow, straight pipe section, etc. The region with the higher pressure is upstream while the region with the lower pressure is downstream.
Remote Area Pipeline Rerouting: 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. On this episode, our guests are Stephen Rawlinson, Regional Director, and Wes Gardner, Engineering Training with the STATS Group.
We’re going to talk to Steve and Wes about their article published in the November 2021 Pipeline & Gas Journal entitled, “Using Isolation Plug in Remote Area Pipeline Rerouting Project.” Steve and Wes, welcome to the Pipeline Technology Podcast.
Stephen Rawlinson: Thanks, Russel.
Wes Gardner: Thanks for having us.
Russel: Really glad to have you guys here, and I’m very interested in talking about this project you did. Before we get into that, let me ask you guys, tell me a little bit about yourself, what you do, and how you got into pipelining and found yourself in your current role. Stephen, you could go first.
Stephen: Sure. Thanks, Russel. I’ve been in my current role here with STATS Group for about ten years or so. That’s primarily focused on helping us grow our business and supporting our guys from a commercial perspective. I’ve been in the oil and gas and pipeline business for about 20 years.
How I got into it, it’s like many growing up or being part of the Alberta market here. You tend to be pretty focused in this space. Once you’re in oil and gas, and once you’re in the pipeline business, it draws you pretty hard in, and it’s hard to get out.
It’s one of those industries that’s challenging. Technically, there’s a lot of elements there that keep it interesting every day. Certainly, when you’re making a living isolating pipelines or plugging them, it tends to be a high-risk, high reward kind of business. It’s near and dear to my heart if you will.
Russel: I don’t know, Stephen, that this business is that hard to get out of other than once you find it, and you find out how much fun it is and how good the people are. You just don’t want to leave it.
Stephen: Fair point.
Russel: At least that’d be my story.
Stephen: [laughs] That’s a fair point. I’m sticking to it. [laughs]
Russel: Wes, same question. Could you tell us a little bit about yourself and how you got into what you’re doing now?
Wes: For sure. My name’s Wes Gardner. I’m an engineer in training with STATS Group. I got with STATS when I was in school. I took engineering and started my coops with STATS, and I’ve now been with STATS for about five years. I started early in a coop position in the shop working hands-on with the tools, and now I’m graduating up to doing some design work and project management for STATS Group.
Russel: You mentioned, Wes, you’re an engineer in training. This is a sideline off other than what we’re here to talk about, but it’s important, particularly for the U.S. listeners, to understand that the process you guys go through in Canada to get your professional engineering certification’s quite different than what we do in the U.S.
Wes: You’re meant to do basically 48 months of work experience after you graduate with an engineering degree, and then you apply to the regulatory body within your province. For me, I work in Alberta, and I’m registered with what’s called APEGA.
Basically, I tell them all my work experience. I meet certain criteria that they deem competent for me to work, and then they’ll approve my application, and then I graduate to become a professional engineer. That’s why I say I’m an engineer in training because, for one, I am, but secondly, it’s a legal obligation for me to do so.
I’m getting quite close. I have about five years of work experience now, so I’m close to being able to apply. I just crossed my discipline. I did school as a chemical, working as more of a mechanical engineer.
Russel: In the U.S., if you say engineer in training, you think about somebody who’s in their first couple of years. We actually certify an EIT, and then you can call yourself an engineer even if you’re not a professional engineer. It’s a little bit different.
I ought to put this as an Easter egg in the show notes or something, but talk about the whole ring you get when you get your engineering PE in Canada because it’s pretty cool.
Stephen: Lot’s of symbolism there for sure.
Russel: A constant reminder of what we do actually matters.
Stephen: It does. It very much so, very much so. To Wes’ point there, we’ve condensed five years in one year for him in terms of how he started off there. We certainly don’t lack for challenges and opportunities. That’s one thing, Wes, is we’ve certainly thrown everything, including the kitchen sink, at him, and he’s been pretty adept at tackling it so far.
Russel: The whole thing about getting your engineering degree is just getting your bona fides to get out into the world and actually learn engineering.
Stephen: For sure.
Russel: Most of those work in disciplines that are so narrow, they don’t teach them in school. The last thing I would say about this whole conversation is I’ve been doing engineering for 40 years, and I’m still an engineer in training, so there you go.
Stephen: Good point.
Russel: [laughs] Tell me a little bit about the project that you guys did. This whole thing’s pretty fascinating to me. You guys gave me some great materials to read before we got on the podcast here. Talk a little bit about the project and what this article that’s in Pipeline & Gas Journal is all about.
Stephen: For sure. Maybe I’ll kick it off and give the bit of the overview first, and you can slot in with some of the technical details there, Wes, and certainly correct me if I’m misrepresenting.
At a high level, here’s the scenario. Client has a crude oil pipeline. Due to some slope stability issues on one segment of the pipeline, they need to reroute, need to replace, and need to abandon.
The conventional approach to that would be to either take the line down, so basically close two mainline valves. In this case, drain a lot of product. Manage all that product. Do the work you got to do on that, on the line. Reconnect it back in. Fill it back up with product and re-run the line again. There’s some time, and that is a conventional approach to it.
Other approaches, you could throw a fitting on the line, hot tap it, isolate it, things like that to be able to facilitate the work that needs to be done. Great approach.
In this context, really challenging to be able to do that given in this particular area of the world, there’s a lot of wet soil, lots of muskegs, really difficult to access these locations. Because of all the slope stability, it would be advantageous not to leave anything on the line. That’s the scenario of the project.
Client needed to temporarily isolate the pipeline to be able to basically connect a new segment to it and then abandon an old line. Where we came in with our solution to this problem was to provide a piggable isolation tool, so essentially launch the tool through their trap system, pig it to where it needed to be, set it, confirm we’ve got a good double block and bleed isolation. Client does the repair work. They reconnect a new line to it, abandon the old, and then we move along with unsetting the tool and pigging it out to the destination trap or the receiver trap.
That’s it in a nutshell in terms of what the project was and what the challenge was. Wes, can you fill us in with any other subtle details on that?
Wes: Yeah. A couple of the additional subtle details is the way they were able to purge the pipeline of the crude oil product is when we installed our — what we call our Remote Tecno Plug — at the launcher site. We had two purge pigs installed downstream of our tool, and we put about 90 meters of product between the first two purge pigs and then our plug.
We pigged that as a plug chain, and they also did two line fill pigs behind our tool. We pigged those, that whole pigging arrangement — it’s a five-pig pigging arrangement — to that set location where they wanted to do their tie-in work.
At that location, they just had a couple of nitrogen injection points. We landed our plug upstream of the injection point and then the two purge pigs downstream. We were able to set our tool, so isolate upstream towards the launcher, and then they started injecting nitrogen to be able to purge the pipeline that they wanted to abandon.
That’s one of the additional subtle details of how we were able to basically reroute the pipeline without dealing with a ton of product.
The advantage there was we were roughly 150 meters upstream of the purge point, whereas the next closest mainline valve was approximately 40 kilometers upstream. You have another 10 kilometers to the receiver valve, so you’re dealing with 50 kilometers of product if you’re going the conventional approach versus us being right at the tie-in location where you need to be.
Russel: When we talked about this before, guys, I didn’t really even think about the whole product management conversation because that’s pretty material when you talk about isolating 100 meters versus 50 kilometers. That’s a real big deal…
Stephen: Some fluid management challenges.
Wes: I could jump in there as well. When they started injecting nitrogen, you still had 13 kilometers of product between, say, the lead purge pig and your receiver valve. They started injecting nitrogen. They basically recovered all of that product upstream of the first purge pig, until about 200 meters or so upstream of the receiver.
That’s where they started tying into storage tanks. Because we were using nitrogen to displace the product, if any of that nitrogen got past and into the crude, they started recovering and separating out.
The vast majority of that product between that lead purge pig and the receiver was actually just pushed into storage. You’re talking dealing with maybe 200 meters of product versus…
Russel: It’s just a big difference. Let’s just leave it there.
Wes: It is. [laughs]
Russel: It’s a big difference, right?
Stephen: Yeah. Truth be told, back in the day, even with non-liquid lines, even looking at gas lines, back in the day, venting and purging that volume, particularly with gas prices being relatively low, wasn’t a big deal. More and more, that’s a regulatory concern in terms of all this natural gas being emitted and control around that. That’s a changing space, for sure.
The notion, again, of closing mainline valves and then venting and purging or draining down, whether that’s 10 miles, 10 kilometers, it just doesn’t fit the realm of an easy alternative now. If you think about that in the context of what we’re offering and what the solution is, the notion of a piggable valve, that’s a handy thing to have in your back pocket.
Russel: That’s a really good way to say it, Stephen. As pipeliners, we have a pretty extensive toolbox. The question, the challenge, often is do you know everything that’s available to you and how to use it, when it makes sense to use it. Right?
Stephen: That’s exactly it. It’s a tool in the arsenal. It’s not necessarily appropriate for every application out there, but it certainly has its application for these types of activities. We’re certainly seeing that, particularly with this application, where there are multiple lines with the same problem.
This was the first of many runs of this tool to facilitate the same outcome, basically replacing taking the line out, abandoning that line, and putting a new line back into service, and on the pig goes.
Russel: I want to talk to you about how you locate these pigs. Pretty interesting to me that there’s one thing that you’re doing that’s simple for me to understand. That is that you have an above-ground device that you can use to communicate with the pig.
That’s pretty cool. That’s pretty easy to understand. It helps you know exactly where it is and to cause it to do the things it does to isolate. That’s a very different thing than putting the pig where you want it. That’s never simple, in my experience.
Stephen: The elements, in terms of deploying the tool, are pretty consistent with deploying any type of pig in the system. Whether it’s a cleaning pig or whether it’s an ILI tool, your different levels of sophistication, it’s really no different. You’re loading the tool up. It goes through the trap infrastructure. You’re pigging it down the line.
How do you know where the tool is? Wes can get into some of the details here. Ultimately, the tool is sending out, basically, a beacon saying, “Hey, here I am. Here I am.” You’re picking up that beacon, or you’re picking up that message above ground. That gives you a context in terms of where the tool is.
That’s not unique to our tooling per se, but what Wes can describe is some of the work that we do that is different. What we’re determining is not only where the tool is but coming up with a plan for how we’re going to slow down the tool so the tool can land in the right location.
Our work in that, if you want to talk about the magic, that’s the magic that happens, in terms of the analysis that we go through to ensure that we’ve got a good program with the operator such that they’re either killing pumps or they’re slowing down the progress of the tool.
We’re tracking it as it’s getting close to the location. Then we’re stopping pumping so that it lands at the right location.
Russel: Do you run a geometry pig, typically, in advance of doing one of these piggable valve operations? I would assume that if you’ve got out around pipe, that that could be a real problem for moving the pig to where you want it to go.
Wes: We certainly rely fairly heavily on client’s ILI data to review prior to us even saying if it’s a feasible option or not. That’s something we’ll look at, is geometry or MFL tool data, to see if the line is piggable, if it’s a good option.
Wes: If we’re still concerned about that, what we’ll also typically do is we’ll run a gauge pig. We’ll put three plates on a pig that mimic the geometry of our plug. We’ll send that through the pipeline just to confirm that it won’t get hung up on any unknown maybe restrictions in that line you may have.
Stephen: Keep in mind, most operators have good quality ILI information anyway, whether that’s a company requirement or a regulatory requirement.
Russel: Geometry is easy. It’s often gathered with any other tool run.
Stephen: Exactly. The things that Wes and Wes’ team will look at are, “What’s the age of that information, is it a recent run, has something changed in terms of infrastructure, have they added new infrastructure since the last run?”
That forms the basis of the engineering team’s review of saying, “Okay, here’s the piggability of the line; what does it look like?” Maybe, Wes, you can describe a little bit about some of the work you guys do to examine the piggability and then assess how we’re going to land the tools at the right location.
Wes: As you mentioned, we’re really concerned about the geometry. Are there any major restrictions in the line that would probably prevent that tool from getting through?
The other types of features we’ll look at are things like tight bends, or just bends in general, to ensure the tool can pass, like combinations of T-s, so back-to-back features. Say you have, for instance, at a launcher valve site, you’ve got a couple off-takes on either side of the valve. Then you also have a valve to go through. So, ensuring that you’re continually sealing past all those features and this big tool that you’re trying to get through the pipeline is still going to chug its way along. That’s some of the stuff that we look for — from a piggability perspective.
When it comes to getting the tool at the right location, we definitely look at flows, how fast the tool is moving, and the product. If it’s either a liquid or a gas product, that potentially changes how we would stop the tool.
It is pretty simplistic in the fact where the tool — it doesn’t have brakes on it. You can’t just say, “Hey, we’re at this location. Stop. Stop. Stop.” You’re actually using flow to slow down the tool and stop it at the right location.
In this instance, this job we did, we actually ran a cleaning tool with a tracker in it prior to us doing the isolation, and we mimicked the shutdown. We knew we had to be really close to this nitrogen injection location at the tie-in spot, so we did a practice run with the cleaning tool, and we mimicked basically how we would stop the line when our plug got to the location.
Russel: You did, in effect, do a practice run with a cleaning tool.
Russel: That way, any of the things that cause you to have acceleration or deceleration that are related to features or anything else, you have an advanced understanding of all that before you run the isolating pig.
Wes: Exactly. In this instance, where the tie-in is, there’s a large slope. That’s the reason this pipeline in this particular area was starting to strain and buckle was the slope was sliding away. Basically, leading up to the location, mostly gradually uphill, and then right after where we wanted to set the tool, it just heads downhill towards the receiver site.
We wanted to be sure how the hydraulics in that line are going to behave when we want the tool to stop. It was very simple, and it was only an hour’s exercise of us at the isolation location, shutting down the line and making sure the tools are going to stop when we want them to stop.
Stephen: As usual, with any kind of testing scenario like that, it went well, and the feedback was, boy, that was a lot simpler than we thought. It wasn’t as hard, because, again, part of that process isn’t necessarily just driven by STATS.
That is the interaction of our tooling with the operator. It was more the operator just confirming, “Okay, how does the line behave?” That isn’t a metric that’s often really well understood, because traditionally you’re not trying to park a tool midstream in your pipeline.
Russel: You’re absolutely trying not to park a tool is what you’re doing.
Stephen: Exactly. Understanding those dynamics was a bit of discovery from the client’s perspective, and it was a good interaction with the client to go, “We’re not sure how it’s going to behave. This is our historical information that would help us understand.”
They went through a couple of assimilations themselves internally without stopping the line, without actually running anything in the line. The test was a good result at the end of the day. Wouldn’t you think, Wes?
Wes: Yeah. Yeah, it was great. It really helped us.
Russel: There’s another question I want to ask along this vein because, again, I’m not an ILI guy, but I know enough about this to be dangerous, and I’m a curious engineer. I can see. I can visualize how you get the first pig in the position you want it to be in, but how do you get the second pig into the position you want to be in without causing the first pig to move.
Stephen: Will you want to describe that a bit?
Wes: We loaded and launched each of the tools with about 90 meters of separation, so we gave ourselves a little buffer room there if any of the particular tools were going to bypass. If you think about where we had to land those tools, you had 90 meters of separation to work with, but you wanted to park that so it was two purge pigs in front of our tool, and then our isolation tool.
You wanted that second purge pig just downstream of that nitrogen injection so that if any of the tools or the pig arrangement continues to creep on, you still have some separation there.
That’s why the test was so critical for us is the goal of that test was to land the cleaning pig that we installed in this line. We wanted to land it just downstream of the nitrogen injection point, which we were successful in doing so, and then made us comfortable doing the actual installation.
During the pigging run, it’s not like it’s just at the isolation location right away. We were tracking these things for 103 kilometers. We were continuously tracking the separation of the tools.
Russel: You’re actually not landing an individual pig. You’re actually landing a train.
Wes: You’re landing five.
Stephen: You are. Wes, there was a strategic decision we made, too, during the project planning to mimic the pigging configuration for all the tools that were in the line.
The cleaning tools, we mimicked that same type of pig disc on our tooling, which we wouldn’t typically run, but to mimic it, then facilitated that the tools would travel consistently through the line. Typically for our normal configurations, we would do discs that are bidirectional. That gives us some flexibility to shuttle the tool back and forth if we needed to at the isolation location. Not always a requirement, but it’s just a general premise that we’re able to shuttle it back and forth.
In this context, we went with unidirectional that matched the tools that we were running upstream and downstream, and that gave us a bit more consistency. The end result is we didn’t see a lot of bypass on the tooling, and they stayed fairly consistent, Wes, in terms of how they traveled through the line.
Wes: We tracked them. We basically had the same separation throughout the entire line when we pigged them.
Russel: Again, this question may be goofy, but I have to ask it because if I don’t it’ll keep me up tonight because I didn’t ask it. Do you have the ability to lock one pig in place and move the other pig?
Wes: We do have that ability. It’s not the standard design of this particular plug, but we can do arrangements where, so with our tool, the sealing arrangement and the locks that keep it locked in place are all on one body, and they work together. They don’t work independently, so you can’t just lock and not seal. You lock and seal at the same time.
What we can do is we can separate out those locks from the seals and activate them independently. If you need to, you can pig it to the location, temporarily stop the line, set those locks, and then open up bypass valves and continue to run the line so that you can get your upstream tools into position.
That is something that we can do and I believe we’ve done in the past. We’ve done it on other scopes, but that’s not the standard design. It’s a little bit more complicated.
Russel: Cool. Let’s talk about how the pig actually works, how it actually isolates. I think people would be interested to understand what’s going on there. In looking at the brochures, to me, that appears to be fairly straightforward, but that’s probably because I don’t know enough about it.
Stephen: At a high level, it’s a downhole packing tool. Nothing unique in the context of applying a force on a set of seals so seals will readily expand and contact the pipe wall. The differences there are the subtleties with the design of hydraulic activation mixed with a little bit of self-energization. You can talk about that in a bit more detail, Wes.
Wes: Sure. The tool design is a large cylinder, essentially, that has two HNBR seals, so rubber seals, and a set of metal locks that grip the pipe wall. The locks are on a tapered lock bowl, and the seals are separated by what we call an annulus ring. The tool is hydraulically activated when you want it to set.
When we set the tool, the tool compresses itself longitudinally, which causes those seals to readily expand and grip the pipe wall. So, it squeezes the seals. They expand out, contact the pipe wall, and those locks — the angle of the lock bowl as the tool compresses itself — those rise up, and they contact pipe wall.
In a set position, you have your locks gripping the pipe wall, and then you have two rubber seals separated by an annulus space, which we can monitor for pressure.
Russel: The purpose of the annulus is so you can see are you getting any pass by to basically verify the seal.
Wes: Exactly. Our approach there is when we set the tool, depending if it’s a liquid or gas product, you trap that product between the seals as they continually expand and start to seal the pipe wall. The more you compress the tool, the more those seals expand out, and your volume decreases in that annular space as you’re sealing, which jacks up the pressure.
That’s our first indication that we’re getting a good seal on the pipe wall. We have control of that annular space, so we can vent off the product in that annular space to behind the tool after you’ve vented down behind the tool. That’s our check to check what we call our primary and secondary seals. We go through a sequence there. When we first set the tool, we get a higher annular space, a higher pressure in your annular space. That gives you an indication that you’re set.
You then vent off downstream of the tool or whatever your orientation. You vent off the isolated portion, the side you want to isolate, and then you have full pipeline product in front of your tool, greater than pipeline pressure in the annular space, and then essentially your ambient behind the tool so that you can test your secondary seal in that situation by greater than pipeline pressure. If your annular space stays higher than your pipeline pressure, you don’t lose any pressure there. You’re happy that your secondary seal is holding and isolating.
We then vent off that pressure to that isolated portion of the pipeline, so you now have no pressure in the annulus, no pressure behind the tool, full pipeline pressure in front of your primary seal. That tests that you now have a proven primary and secondary seal with essentially an annular space that you can vent off between the seals with double block and bleed isolation.
Stephen: You’ve got full monitoring capability of that annular space over the course of the work, so ultimately, it’s an area that can be managed.
Functionally, that annular space is that prove-up sequence that Wes just talked about. Testing that secondary seal over pipeline pressure gives you confidence that it’s holding well. Bringing that pressure down, letting that hold for a period of time to validate the confidence of the primary seal — those are two really important tests.
What gives you confidence that you’re sealing? What gives you confidence is that you’ve done those tests. They’ve passed. It’s very finite…it’s going to see any pressure changes during those tests.
The benefit there is you’ve validated your double block and are in a really good position before you break containment. Before you’re cutting down or adding any other additional infrastructure downstream, you’re in a really good position.
Wes also talked about the sequence there. We hydraulically set the tool, so the mechanism of the hydraulic set is that’s driven by another module that’s connected to the Tecno Plug. That module has your communications, your control, and basically your hydraulic pumps that basically facilitate the tool setting. We can communicate with the tool above ground, tell the tool to set. It drives that hydraulic pump, starts that set process.
The other neat aspect to it — and this is really the pedigree of the tool coming from an offshore world — is the fail-safe built into it. Hydraulics are used to set the tool. Once the tool is isolating, really that differential pressure acting on the tool adds an additional loading to the tool, and that facilitates an additional force to keep the tool in place. Those two forces are independent. The hydraulics are there, and the differential pressure is there. If I lost one, I’m still able to keep the tool in place.
For example, if we added some catastrophic hydraulic loss in the system, the tool is still going to be held into place. It wouldn’t be a great day. We don’t have that fail-safe anymore, but we still, the tool would be held into place.
Conversely, if I lost differential pressure, I’ve got hydraulics holding the tool in place. Those mechanisms and independence offer another level of protection that, to be fair, you don’t often even get with a valve. To have that with a piggable valve or a piggable Tecno Plug is a really good position to be.
Russel: I noticed in reading the article that y’all have provided me that there’s a place in there where you talk about in the project you delivered the operator an isolation certificate, I think is what it was called.
Tell me a little bit about that process. Is that basically STATS saying the tool’s in place, seal’s good, you can start your work?
Stephen: It comes on a parchment. It’s very fancy you know? [laughs] What it is is an attestation or a confirmation that we followed the process and the procedure, which obviously the client has, and we’re marking through — our technicians are marking through — that procedure as the job is underway. It’s validation of the steps of the secondary seal test, the primary seal test, and validation of the performance of those that meets the acceptance criteria.
Effectively, it’s a sign-off to say, yes, we’ve run through these steps. We’ve run through the steps that we all agreed to. We’re comfortable with breaking containment. Here’s the isolation certificate issued.
From a permitting perspective, that then holds for the period of time that those conditions are valid. So, if something changes, we may revoke the isolation certificate because the situation has changed. That’s how we treat that…
Russel: That’s your job safety process.
Stephen: It is.
Russel: You go through your process. You issue your certificate. You monitor things to see if the certificate needs to be revoked. Once you return to normal operations, you revoke the certificate.
Stephen: It’s probably one of the most critical activities a client will do. It’s an activity that the client wants to keep minimized. They want to keep that isolation for as limited a time as possible because the only thing holding back pipeline pressure is our tool. We’re very confident in how the tool works and how it’s designed and deployed.
The isolation certificate is confirmation of those steps, but it’s still a risky endeavor, and it’s important that that risk is managed. Time is one of the components of managing that.
Russel: Any time you do something that’s risky, regardless of how many safety barriers you have in place, you still want to get through that process and finish as quickly as you can.
Stephen: For sure.
Russel: If I’m the guy down in the ditch and I’m doing whatever remediation or modification needs to be done, and I know that there are pigs down there holding back pipeline pressure, I don’t care how confident I am, I’m going to be nervous, and I want that process to be done as quick as you can.
Stephen: What we find, because typically it’s the welders that want to have a confirmation of the quality of the isolation, so it’s bringing the welders on board with respect to understanding here’s our prove-up sequence. This is how we’re comfortable that we’re isolating.
Once there’s an understanding of the process, there’s quite a lot of buy-in from those doing the downstream activity. There’s quite a lot of buy-in in terms of understanding what’s the annulus pressure at today. What does that look like?
Russel: Has it changed? What’s the upstream pipeline pressure? Has it changed?
Stephen: That tangible record and that tangible monitoring information is a pretty important element versus the traditional approach might be I’ve got a port on the line, and I’m sniffing for gas, or I’m sniffing for crude. It’s an indirect mechanism there. This is giving you a pretty high quality. Not only are we validating the performance of those seals, but then, we’re checking for the performance of how the annulus is behaving over time.
Again, it’s a risk endeavor, for sure, but it does minimize that risk by understanding, “Okay, my annulus is looking pretty good here. I’m not getting any pressure increase. It’s been stable. It’s been stable overnight. It continues to hold really well. It gives me confidence I’m proceeding with my hot work in the safest way possible.”
Russel: Exactly. Guys, let me ask this wrap-up question. What do you think every operator ought to know about this approach for doing pipeline isolation?
Stephen: From my perspective, the takeaway in this circumstance is the client’s got another tool in the arsenal for being able to temporarily isolate the pipeline to facilitate the work that needs to be done.
What it talks about is in the development or the implementation of any new approach requires a different way of doing something. The ask in this situation is different than conventional. Conventionally, if you’re looking like doing a line stop activity, you want information about the pipeline at the line stop location. That’s all you’re really worried about from a delivery perspective.
In the context here, what’s important is that we understand what does the line information look like for our tool to get to the location and then our tool to get out of the location. What that means is the ask is different, the information shared is different. It doesn’t make it less complicated or more complicated. It’s just a different ask.
With that, and when operators are looking at the feasibility of this type of technology for their application, from a high level, if the line is piggable, we’ve got an opportunity to use the tools. The subtleties are about sharing some of that line information that helps us determine feasibility. It’s in the sweet spot for the application of the tool, application of the technology.
It’s definitely another tool in the arsenal that’s available. It can be really attractive. Particularly if a client’s got lots of these repairs to do on their system, the same tool could be deployed numerous times, even on the same run. The economics of that look good. The safety-wise aspects of it look good. It can be a pretty potent tool from that perspective.
Russel: Wes, anything to add to all that?
Wes: No, Steve nailed it there, especially on that last point. The actual isolation and the way that the tool operates, that’s easy for us. It’s the initial analysis is confirming, maybe you have a 300-kilometer pipeline. You got to make sure it goes from A to B. That initial analysis is the tricky part. The easy part is getting the isolation there or isolating with that technology.
Russel: I think that’s a really good point, Wes. That is pretty thematic in a lot of the things I end up talking about on this podcast. The preplanning and analysis are more important than the actual operation. It’s never the thing that you look at and don’t get right. It’s the thing you didn’t look at that you needed to look at that really causes you a problem, right?
The things you looked at and didn’t get right, you’ll catch it in your process and correct it. The ones you didn’t look at — those are the ones that get you in trouble.
Wes: That’s the restricted part that isn’t piggable that gets you into trouble.
Russel: Exactly. Listen, guys, this has been great. I really appreciate your time. I’m going to take the brochures that you sent me. We’ll link those up to the show notes in the episode so that if people are interested, they can download that information. Great job, really interesting. I appreciate it.
Stephen: Great, Russel. Thanks for the opportunity.
Russel: I hope you enjoyed this month’s episode of the Pipeline Technology Podcast and our conversation with Wes and Stephen. 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 pipelinerspodcast.com.
Transcription by CastingWords