pH Field Screening in Hydrocarbon Operations (Webinar Recording)

Good morning, everybody. Thank you so much for taking the time to join us. My name’s Ryan Sikes with Chemi-Sense Systems, and I’m joined here with Rick Sugden, our president and CEO of Chemi-Sense Systems, as well as the legendary Tom Pickthall of EnhanceCo. We’re gonna talk a little bit today about pH in hydrocarbon operations, some of the challenges that are associated with that, as well as what we’re developing here at Chemi-Sense Systems. So with that, maybe we’ll just kind of dive right in. We’ve only got 30 minutes.

Maybe some quick introductions. We’ll start with you, Rick, your background and your credentials. Yeah, Rick Sugden here. I’ve spent about 20 years in the oil and gas industry working in instrumentation, pipeline integrity, corrosion control, and regulatory compliance. Now, I’m leading Chemi-Sense Systems that’s bringing practical technology to help with some of the difficult challenges I’ve experienced in this industry. Yeah.

And Tom, really appreciate you joining us. You bring in such a wealth of knowledge. Maybe give the folks watching here a little bit of the breadth of your background and the perspective you bring. Thanks for having me. First of all, thank you both. So I’ve been doing internal corrosion for just under 40 years.

Run a company called EnhanceCo. We do third-party internal corrosion equipment and services pretty much amongst all the way from downhole till the time you make cheese out of the product. Do some data storage, do some building water, lots of different things that we do, but primarily where we find water. Yeah, that’s pretty much what we’re doing. Awesome. And so today we’re really talking about pH and hydrocarbon operations, right?

There’s cheese and there’s all kinds of other things. You know, when we talk about hydrocarbons predominantly, we’re talking about crude oil, right? Rick, whenever somebody asks about pH and crude oil, what are they really trying to understand? Yeah, so conventional pH is a measurement of the hydrogen ions that’s in the aqueous phase. Crude oil itself does not have a conventional pH in the same sense that water does. That oil phase acidity is typically measured by a total acid number or TAN, which is typically a measurement of the organic acids that are in the crude oil.

But when we start talking about pipelining and process corrosion, we really care about the water phase that can contact the steel. That water may be in crude containing samples, produced water, or processed stream. Free water entrained water and emulsions pose different sampling and contact challenges when you’re trying to measure that pH. Yeah, so we’re really talking about the water that’s associated with the crude, so that that’s within the crude. Tom, where does that distinction really matter in practice? Well, when you’re trying to get a pH, for instance, almost all of your equipment is designed for water.

So if you can’t get free water, you have a hard time getting a pH to begin with. And then once you’ve gotten that water, one of the things the pH of the oil is usually driven by an organic acid. The pH of the water is usually driven by inorganics, although it can be driven by organics. So it’s a combination of what goes on. So the big thing is trying to get a good, reasonable pH number that’s relatively accurate in the field. And pH is a useful signal, but it doesn’t directly correlate to a corrosion rate reading, right Tom?

Dissolved ferrous iron may supply another signal. And of course, inhibitor residual chemistry is part of that larger monitoring picture, and it’s one of the things that we’re also working on at our company. Operating conditions and other corrosion evidence that we’re looking for still determine the interpretation of what’s going on with our corrosion levels. Yeah. And so that’s a pretty good point, right? So in crude oil and in samples, there’s actually all kinds of different things that you can look for, but there’s also all kinds of things that could potentially cause interferences and challenges and things like that.

So Tom, you were kind of alluding to that. What’s the hardest part of getting that sample that you can actually trust? Getting the sample that you can actually use. So depending on what you’re working on, you may not have a place to get a sample. You may have some HS&E problems getting the sample. And then once you’ve got the sample, if you’ve got to do, for instance, a pH in a crude oil or pH in a hydrocarbon of any sort, often you’ve got to take that sample and you’ve got to get it to a lab.

And that takes time. And the whole time, the pH is changing. So trying to get a good, accurate field sample is difficult, particularly, again, if you don’t have free water. If you’ve got free water, you can use standard equipment. But if you’ve got an emulsion or you’ve got straight hydrocarbons, it’s a lot tougher to do that. And that’s the intended benefit of the technology that we’ve developed is really to have a simpler, near-sample point screening for conditions where getting that result is much more difficult.

Collecting that data right at the point helps because we don’t see that temperature shift, gas exchange, ongoing reactions that are changing that chemistry from the sample point until it gets to the lab. Yeah, so Rick, that kind of brings us into really what we’re building here at Chemi-Sense with our pH sensor. So kind of in the simplest sense, what we’re enabling is being able to do it more often, right? So that’s kind of what you were alluding to. How does that work, right? What about what we’re doing enables more rapid decisions?

Yeah, so what Chemi-Sense systems did was we immobilized a colorimetric indicator chemistry inside a solid polymer, plastic matrix. When that film contacts the sample phase, the indicator responds to the hydrogen ion activity through a visible color change. Our current observations as shown on the screen show that neutral, it’s a teal color, and it shifts towards a pale yellow under more acidic conditions and towards a cyan or darker blue under more alkaline conditions. The design was intended to make field handling practical in complicated samples. We’ve also shown that we want to have resistance to interference. We don’t have the fouling issues that you have with a pH meter in particular fluids and under certain conditions.

Yeah, and we’ve got them actually, they’re up here on the screen, but I’ve actually got some of the sensors here with me to kind of give a representation. It might be hard to see on the camera, but it’s a dip test, right? So the sensor that you’re seeing on the screen there is actually connected to the little plastic holder. And the intent is you actually just dip this directly into the sample. Little to no prep, you can pull the sample directly out, dip it straight in. I believe on the pH, it’s a two minute wait time.

I think it actually responds quicker to that. Tom, in your experience, where could you really use a simple dip test like that? I mean, we’ve talked about kind of that rapid points and those things, but how does this differ versus what you’ve seen in existing applications? Well, first biggest thing is that you can do it in oil. You can do it in a hydrocarbon. The second thing is, let’s take a pH meter, for instance.

If I stick my pH meter in oil, the frit is ruined. We’re done. And we’re done for the rest of the day. So even a colorimetric, just a plain old dip test, a dip strip for straight, the design for water, for pH, is not everybody can see the same colors the same way. Some of those pH papers are not as accurate as maybe they should be. So this makes it nice and simple.

It makes it so that you can get a good quick answer and it makes it so you can repeat that location over and over again to be able to get an average over a period of time without breaking the bank. You haven’t sent 30 samples to the lab. You’re just taking a dip strip and going out and testing it. And anybody can do it. And so that’s also, you kind of brought up a great point, colorimetric test. Our test is colorimetric as well.

A big limitation is human eye. Rick, he’s heard me say this plenty of times, I’m color blind. I have challenges seeing some of the colors. So that’s actually why we’ve developed an actual camera app that uses your smartphone. You can take a picture. It uses a grayscale reference to match that up.

And then it gives you kind of that reading straight out through the app. You know, Rick, what are your thoughts on kind of the deployment? Tom hit very well on being able to rapidly use it across multiple applications. You know, one of the things that we see is gathering systems. We see a lot of pull on not only the pH, but our amine residual and our ferrous iron testing kits within the gathering space. So where does this really fit?

And how do you see some of those challenges presented in the gathering space that we’re solving? Yeah, so we’ve actually thought of three different scenarios that we’ll discuss here. Gathering systems are very dynamic. New laterals are constantly being tied in. New wells are coming online as those wells come online. Their conditions and what they’re bringing into the pipeline system are changing almost daily.

A team that’s managing an inhibitor program may need to narrow down where is the pH shift originating, which well is causing the problems. Being able to frequently test measurements at different points could help focus their investigation. While pH alone can’t establish inhibitor efficiency or the corrosion mechanism, it does assist the team in investigating what’s going on in the pipeline system for gathering. Yeah, that team would be somebody like Tom that’s out there chasing kind of this problem for the customer. And so, Tom, maybe walk us through, you’ve got a gathering system, multiple wells, you’re chasing kind of an upset in the inhibitor or corrosion rate. What are your first kind of actions?

And if you had a test like this, where would you be using it? Sure. So, you know, the first thing that you do is, OK, where am I having a problem? Or where do I think I might be having a problem if you’re being kind of forward looking? And then you go to the known areas and you test and then you start maybe going upstream from there. Once you’ve found in a branch system, once you’re on the trunk, you may have to go upstream into the branches to look for a problem child or, you know, an area that maybe is giving you more corrosive fluids than the rest of the system.

And that’s pretty typical with almost all gathering systems. You’ll have good wells and bad wells and you’ll have, you know, good areas, areas where the separator is working really well and where the separator is maybe not working so good. Yeah. And so maybe what I’m hearing is this is a really good investigative tool, right? So you’re you’re out there and you’re starting your investigation on the site, you know, forensically, per se. And you get out there and you’re able to test and backtrace.

Absolutely. Well, and you got to remember, this is only one tool in your toolbox. Right. But it is a tool in your toolbox and it does something that most of your other tools don’t because they’re designed for water. Correct. Right.

And as you guys are going through that investigation, if pH is moving and you’re also seeing dissolved ferrous iron rising, that combination leads you down the path of this is actively corroding. And we need to determine what that mechanism is or whether there’s a chemical change. Is this something that’s transient? Is it something that’s occurring on a regular basis? And these tools in those toolbox, like you said, Tom, can really help the investigator figure out what’s going on. Yeah.

So gathering systems are one kind of initial pool and application just because there’s so many different things coming in. But if we can think of kind of similar applications across the oil and hydrocarbon ecosystem is tank storage. Similarly, you’ve got big tank storage facilities that take in products from all kinds of different locations and they’re storing them. They’ve got mixed and emulsified water. Sampling becomes very hard in tank scenarios. So maybe, Rick, you’ve got some experience around dealing with that.

How do you kind of deal with that? Yeah. So I ran into this problem in one of my prior works where we had tanks that we could get free water off the bottom of the tank and we could test it. However, there’s other tanks that use mixers and they’re running all the time and it’s dispersing that water throughout the crude. And so it was extremely difficult to actually extract any water to do traditional testing. And again, our intended use case for this is this technology allows for screening that oil and understanding what’s going on with the pH.

And repeated sampling at a particular point could help you learn what’s going on, what’s coming into the tank, what conditions are happening inside that tank, and allow you to, again, do further investigation. Yeah. And so maybe kind of to pair off that, Tom, whenever you go into a facility that’s got a really big tank farming and they’ve got a challenge that, you know, they know that challenges are presenting with a certain set of tanks. Of course, you start there, but then you’re going to start working yourselves backwards. So could you give some perspective on what you would do in that scenario? Sure.

Well, let’s just take a tank farm in Cushing. You might have two or three hundred tanks. And let’s say you’ve got an east and a west side. So you might start at where those two come together. And then you might work your way up the header system into the east side and into the west side and find out that the east side is pretty benign. And maybe you don’t have to work on that.

So now you’re down to 50 tanks. And then you might work your way up into the tanks and find out what kind of crudes they’re in. And now maybe you’re down to 20 tanks of which five are the bad actors. So you’ve got to do something. You can’t test them all, particularly if you thoroughly test them. But you can decide using this technology in combination with some other things.

You can kind of get an idea of where you should be testing, where you should spend your time and your money. Yeah, so we’ve got, you know, we talked a little about in the gathering system where you’re investigating using them to investigate. Now you’re using it similarly to investigate, but really, you’re trying to figure out exactly which tank deserves that attention. Where are you going to spend that time, that money, that resource, right? So you’re answering that question. Exactly.

Yeah, and then that might lead you again into the kind of a third scenario where we’re talking about transport. Those tanks might be taking crude from a particular source point, such as rail car unloading or from multiple pipelines and then being able to work your way up those pipeline systems. And kind of like you said, Tom, you can’t send 200 samples off to the lab to understand what’s going on. And so you’re kind of picking random tanks or maybe suspected tanks. Whereas this technology allows you to then begin moving much quicker and evaluating those tanks and working your way up into the transport system. And maybe that points you to a particular producer, a particular supplier that’s causing these issues even in your tank farm.

Yeah. And I will tell you, you can send 200 samples out one dime, but you will probably be visiting with your boss after that. Exactly. You’re going to be dealing with the people that are spending that are cost control. Exactly. They’re going to wonder whose boat you’ve been on.

Yeah, exactly. So, you know, that kind of opens up that third approach where, you know, now we’ve investigated, now we figured out where we’re spending the money. But also now we’re enabling the ability to trace backwards where things are coming from, right? Rapidly testing kind of throughout these different points, you’re able to trace that back, find the bad actor, find that, I think, in a call yesterday, Tom, you called it the problem child, right? And so you’re able to identify that rather quickly. Yeah, exactly.

And that’s just a standard investigative method, but that’s what you have to do. And, you know, if you’re lucky enough to be ahead of the game, great. But often you get called in when the ID and the OD of the pipe is met. Yeah. So you kind of know where the problem has occurred the worst. But now you’ve got to go find out why it occurred and what caused it.

And that’s where you’ll use something like this. And where else is it occurring? And okay, so we got this one. What’s the next, where’s the next opportunity going to be? Yeah. And maybe, you know, Tom, you know, without just kind of directly selling it for us, maybe that summarizes kind of the value proposition.

And maybe you could kind of reiterate that in your words. Where do you see, you know, the real practical value? We’ve hit on kind of these things of enabling the ability to rapidly deploy it, to do kind of the high fidelity inspections. If you’re able to investigate rather quickly, kind of summarize those in your words, if you could. I think it just is. You’ve got a method that’s, I’m not going to say it’s absolutely foolproof.

We can mess up anything. But it’s pretty close to foolproof. You’ve got a method where you’re looking at a color, but to take out some of the opportunities for messing up, you’ve got a software that’s going to be able to look at that and give you a color, a consistent reading. You’ve got a simple method that will, it’s not going to tell you that it’s by gosh, corrosion. It’s going to tell you you have an indicator and you should look this direction. Yeah.

And then it’s able to point you to where you can do more advanced testing and learn more. But it’s a good first step. And again, it’s where I think it really advantages is that you’re not going to spend nearly as much time and effort at the lab on things that are not necessary. You can spend your time and money and effort at the lab on things that you know are a problem. Yeah. It’s helping you prioritize what you send off to the lab and that spend that you’re spending for those advanced chemical analyses versus sending samples that you don’t necessarily need to send out.

Exactly. So we’re right on time. We’re right on schedule. I want to make sure we’ve got a couple of questions that have come in throughout the registration process. I don’t know if we have any live right now, but the first one that pops up is, and I think we’ve kind of covered it. Rick, you can hit on this.

Why not just a regular pH meter? I think, Tom, you were alluding to that as well, but maybe Rick can reinforce that. Yeah. So the typical pH test meter, you’re not going to stick that thing down in crude, like Tom said. You’re done for the day. Even when you get into some of the produced water, if that’s a fairly dirty sample, it’s also going to give you problems.

Typically, this is also something you’re going to do in the lab, although there are some field methods for this. But again, you’re going to struggle with that same matrix and interference issues whenever you try to use a pH meter on some of these samples that we’ve talked about. Yeah, and actually, there’s another question that’s here. I’ll summarize this, but what if crude has other things that interfere in it? How do you not get all the other things from the crude? So that’s the beauty of the polymer matrix that we’ve been able to develop.

It actually blocks out all of those interfering matrices and allows just the hydrogen ion to traverse that polymer matrix and actually interact with the indicator that’s embedded inside of it. That sounds fancy. That’s the engineering coming out. So Tom, we’ve actually got one that you could probably answer. Does low pH mean corrosion? Like, does that correlate directly?

No, it’s just one more indicator. But just because you have a low pH does not mean that’s what’s causing the corrosion. What’s causing corrosion may be causing the low pH, but it doesn’t mean that you’re actively corroding. It just means you have a low pH. It means that you have the potential to actively corrode. I think that wraps up all the questions that we have here.

I don’t see any other ones on the list. I want to extend a big thank you to Tom for joining us today, taking time to join and share your expertise with us. Rick, as always, your expertise is appreciated. And everybody that took the time to join, as well as watch here at home, really appreciate all the time. Thank you for now. Our next webinar will be next month on ferrous iron and look for material coming out on that.

Thanks. Thank you. Thanks for having us. Bye.