Transcript (edited for clarity)

Welcome to Chemical Processing's Distilled podcast. This podcast and its transcript can be found at chemicalprocessing.com. You can also download this podcast on your favorite player. I'm Traci Purdum, editor in chief of CP, and joining me today is Brad Buecker, senior technical consultant with Samco Technologies. He has many years of experience supporting the power industry, much of it in steam generation chemistry, water treatment and air quality control. Brad has a degree in chemistry from Iowa State University, with additional coursework in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. Brad has written several articles for us, many about water and wastewater. We've turned those written words into podcast episodes to dig deeper into some of the case studies Brad has experienced. Last episode, we discussed sodium softening, the workhorse of industrial boiler makeup water treatment. Today, we're tackling condensate recovery. Thanks for joining me again, Brad.

Brad: Thank you, Traci, for having me on.

Traci: Well, I enjoy talking with you — you have great stories, so I'm looking forward to today's episode.

Brad: Oh, I'll probably get the adrenaline flowing again once I start telling these stories.

Benefits Of Recovering Condensate

Traci: Let's set the baseline here. What are the primary benefits of recovering condensate?

Brad: Many industrial plants produce a large quantity of steam for various processes. Producing that steam takes a good deal of effort — preparing the high-purity makeup water for the steam generators — plus the fuel and energy costs that go into it. If that steam, after it's done its job and converted back to condensate, is simply discarded, that represents a significant loss to the plant: energy, makeup water, capital and O&M costs. Recovering that condensate as best as possible can save a plant a lot of money and reduce the size of the treatment equipment needed.

But I regularly see posts on LinkedIn that make those points — which are valid — without saying anything about the chemistry of condensate return. I am seeing a bit of a change now, though: more comments pointing out that we really need to pay attention to chemistry, too. Just recovering condensate without regard to what it might do in the steam generator can be very problematic. That's something people need to think about when they're looking at condensate return — what can I recover easily, what might require extra treatment, and what streams might just have to be discarded, whether periodically or permanently.

Drawbacks To Condensate Recovery

Traci: If there's a cost savings involved, why isn't every plant maximizing condensate return? Is there a catch? Are there drawbacks to condensate recovery? You mentioned the chemistry and making sure everything's OK there.

Brad: It involves extra effort. Large plants have numerous heat exchangers and many miles of piping. You need the steam to drive the processes, but there are costs involved in installing all the condensate return piping and dealing with it afterward — manpower, for one. Who's going to watch over this? That's a big issue in some of the cases I've seen: who's going to track what's happening, and do they have the experience and education to understand what's going on? Large plants may also have literally hundreds, or even thousands, of steam traps. When condensate first forms in steam lines, it needs to be extracted to keep the steam flowing properly through the rest of the line. With that many steam traps spread across a large plant, keeping track of them is yet another issue plant personnel have to deal with.

Traci: You mentioned you had a case history in mind from years ago at an organic chemicals plant. Do you want to talk about what you saw there?

Brad: That was a very interesting case history, and it goes back to a theme I've used in Chemical Processing and elsewhere: the mindset that "water is water." At this particular plant — this was a number of years ago — they started to realize they had problems, but I'll explain at the end of this case history what they were actually looking for at the time.

This was an organic chemicals plant. A colleague and I were contacted and went out to the plant. They had four package boilers, 550-psi boilers with superheaters. They called us out because they were replacing each superheater in these boilers about every one and a half to two years due to solids accumulation. That's not good.

So we got out there, and they had one of the superheater bundles sitting in a laydown yard. We inspected it, and sure enough — by my estimate and a colleague's — the tubes had anywhere from an eighth of an inch to a quarter of an inch of deposits in them. In a boiler superheater, that's the highest-temperature part of the entire system, so these superheaters were failing due to loss of heat transfer and metal overheating.

Then we looked at the units in operation, and every saturated steam sample line had foam coming out of it. That's another indicator of problems. We were only there for a day, but we eventually learned that this plant manufactured five phenol derivatives — a relatively small organic compound.

Standard boiler water guidelines recommend that for boilers of that pressure, total organic carbon, or TOC — a blanket measurement of the organic carbon in a stream — should be less than 0.5 parts per million. Some analyses performed by a water treatment vendor at this plant showed that the condensate return, most of which they recovered and sent back to the boilers, sometimes had TOC levels up to 200 parts per million — more than 400 times the recommended limit.

It was easy to see, without running any further chemical analyses, what was going on. All these organics were returning to the boilers, causing a great deal of foam, which carried over into the steam and into the superheaters and caused these problems.

We had a follow-up meeting at the end of the day, before we left, and tried to explain some potential solutions — which I'll get to in a bit — that would require some effort, testing and evaluation. We quickly learned in that meeting that management, at least at the time, was looking for a magic-pixie-dust solution: throw something in the water and all the problems would be solved. We tried to explain that they'd have to put more effort into it than that. We weren't invited back.

I really would have loved to run more tests on that water and bring in some other colleagues, but that never happened.

Traci: So there's no magic pixie dust, is what you're saying.

Brad: No, no — you have to invest some effort and some money to solve problems like this.

Dealing With Condensate Return Impurties

Traci: Well, you alluded to solutions. What are the solutions for dealing with condensate return impurity ingress?

Brad: One of the first solutions — and this applies to so many water treatment applications — is obtaining comprehensive analyses of what's in the water. You can't just say, "We'll slap this piece of equipment on here and it'll work fine." You really have to analyze and find out what's in the water. Like in the case history I just mentioned, the plant manufactured five phenol derivatives. The "lab," so to speak, was just a rudimentary little shed, and the plant personnel who analyzed the condensate and other water samples were just operators. They had a test that indicated only one of the five products that could have been in the condensate return — it was supposed to turn orange if that particular product was present. It was a colorimetric test. I distinctly remember one of the operators telling me, "We run this test, and very often it turns pink. We don't know what that is." It was obvious they weren't trained, or didn't have the equipment, to properly analyze what was in the water.

If you look at a refinery, or another plant of that nature, there could be any number of products in different condensate streams. It all needs to be analyzed up front before you start looking for solutions.

A particular problem — one that affects the power industry, where I spend a lot of time, but also cogeneration and industrial steam generators — is that oxygen and carbon dioxide are frequent impurities that get into condensate streams and feedwater. With all those miles of piping and many heat exchanger connections, it's almost impossible to seal off everything. It's great if you can stop the leaks, but that can be very difficult with so many potential sources.

So it's very common — typical, even — for the feedwater system to the boiler to have a mechanical deaerator for removing dissolved oxygen, along with chemical treatment using oxygen scavengers, which are reducing agents, to bring dissolved oxygen content down to zero, and neutralizing amines — or, as they're now termed in the power industry, alkalizing amines — for pH control. That combination — and again, you have to look at the chemistry — can remove dissolved oxygen and carbon dioxide from the boiler feedwater and help with downstream effects, particularly with carbon dioxide. If alkalinity isn't removed during makeup water treatment, a lot of CO2 can carry over with the steam and convert to carbonic acid in the condensate return lines, causing general corrosion.

That's one avenue for treatment. There are several alkalizing amine products, and a blend can be selected so some stays in the boiler water for protection while some carries over with the steam and comes out in the condensate.

I want to offer a caveat here: I know this podcast reaches a number of industrial steam generation personnel, but in the power industry there are some big issues around dissolved oxygen removal and chemical treatment programs — they get into the topic of flow-accelerated corrosion, which I won't cover today. For any high-pressure boilers with high-purity makeup, it's important to study the guidelines and learn about the potential for flow-accelerated corrosion. That's all I'll say about that for now.

Another possibility is injecting alkalizing amines directly into some condensate return lines — again, a potential approach, perhaps even using a reducing agent. Reducing agents typically work better at higher temperatures, but some will passivate metals even at condensate return temperatures. Again, proper research is needed to determine what will be most effective.

I'll also point out that a number of industries, including power, have started doing direct iron analyses — and sometimes iron and copper analyses — of these water streams, because that data is valuable in showing plant personnel how well a treatment program is working. The instrumentation costs a bit, but in my view, having that data is well worth it for evaluating and adjusting a treatment program.

Something that's re-emerged in recent years — the last 10 or 20 years — is film-forming products. These were developed back in the last century. The late Paul Pecorius, a cooling water expert, had a saying — call it a motto — for metallic pipe surfaces, carbon steel (as in boilers) and copper alloys: protect the metal surface. Film-forming products, many of which are amine-based, do exactly that. Some early versions had problems — they could accumulate, if not fed or controlled properly, into what were commonly known as "gunk balls," gelatinous masses that would form in condensate lines.

But newer products have been developed. What they do is form roughly an 18- to 20-carbon-chain molecule. One end has active sites, and the rest of the molecule is just the carbon chain. The active sites attach to the metal, and the carbon chain extends into the liquid, helping protect the metal surface. If you get a good coating on the metal, you can effectively protect it that way. I'm seeing more and more successful applications of these products with the newer chemistry — though not universally; some places have still had problems. Again, that goes back to testing and evaluation. You don't just pour a Pepsi bottle full of filming amine in and see how that works. You have to evaluate it. That's an area being researched extensively, because analyzing the concentration of these compounds hasn't been easy.

But researchers at various laboratories are working on that diligently. I'll also point out that one of the experts in this field gave a presentation on film-forming amines at this year's PowerGen conference, at the Electric Utility and Cogeneration Chemistry Workshop. He'll be giving another presentation at PowerGen 2027 in January, so if anyone's interested, that would be well worth attending. And, Traci, this might also make a good subject for Echem Expo the next time that comes around — just an idea.

Now, for systems where dissolved ions might be a problem — calcium and magnesium, the hardness ions, or other dissolved ions — ion exchange, or basic condensate polishing, can be the answer. A friend of mine, now retired, formerly oversaw the steam generation and chiller systems at a major college campus, which had two hospitals as well, and an extensive condensate return system. They installed an ion exchange condensate polisher to pull dissolved ions out of the water before it went back to the boilers. In the power industry, especially with supercritical units, ion exchange condensate polishers are an absolute requirement — you cannot have impurities going back to the steam generator.

In the case history I mentioned with the organic compounds, activated carbon filtration can potentially be effective. I don't have a vast knowledge in that area, but I know activated carbon, or ACF, works well for large organic molecules. For smaller molecules, that would require testing — lab testing, maybe even pilot testing. ACF products are made from a variety of materials — coal, wood and others. If I were dealing with organic compounds coming back in the condensate return, I would certainly look at ACF as a way to remove them, rather than having to dump the condensate, like in the case history I mentioned. If they couldn't remove those organic compounds, they might have had to dump the condensate — but that would have increased makeup water requirements tremendously and probably required a new makeup water treatment system. It probably also would have affected the wastewater treatment system, which might have needed to be enlarged. So there are a number of factors that go into what's done with condensate return, and if you can save it, it's probably going to save the plant a lot of money.

Some processes generate many solid particulates, and solids that go into a steam generator typically deposit on the boiler tubes, causing overheating and under-deposit corrosion. So it's very important to filter those solids out. In the power industry, an approach that's becoming more common for condensing steam coming out of the turbine is an air-cooled condenser, which can generate a lot of iron oxide particulates. At a power plant where I worked, we didn't have an air-cooled condenser, but during outages it would generate a lot of iron oxide particulates that had to be filtered out before the boiler could even be started up. We ended up installing a direct filtration device with replaceable filters that captured all the particulates, which proved very cost-effective.

At that same plant — this was actually a makeup water application — we installed, and later my successor installed, a microfiltration unit, a membrane-based process. That's becoming extremely common, too: microfiltration and ultrafiltration for particulate removal. Again, care is needed in selecting systems — you don't want to just put one in, because surges in particulates can overload them — but it's definitely worth considering for particulate filtration.

I was also at a petrochemical plant in Texas once where the condensate return coming back was extremely dark-colored, due largely to iron oxide and other particulates. We looked at particulate filtration for that stream, too, just to remove that, because the chemistry otherwise was reasonable to return to the boilers — we just needed to get the particulates out. So those are some examples of how to address impurities in condensate return and boiler feedwater — some ideas for listeners to look at, and to contact good firms that can provide detailed information on those processes.

Traci: Lots of great examples there, and it's obvious that condensate recovery isn't a set-it-and-forget-it kind of thing — you need a robust management program in place. Do you have any final advice or thoughts before we wrap up for the day?

Brad: Just to beat a dead horse: know what's in the water. That's the big thing. I've seen projects before — one was a makeup water project — where they based the makeup water treatment system on a sketchy snapshot analysis. When the equipment was put into service, the water quality was nowhere close to what that snapshot analysis showed, and they basically had to replace the makeup water system. That's a huge cost, not only in equipment but also in downtime. So — know what's in there.

Traci: That's sound advice: know what's in the water, for sure. Brad, thank you for giving us a glimpse into your world and these great case histories and solutions to the problems we cover here. Listeners who want to stay on top of best practices in the chemical industry can subscribe to this free podcast on their favorite platform. You can also visit us at chemicalprocessing.com for more tools and resources to help you succeed. On behalf of Brad, I'm Traci, and this is Chemical Processing's Distilled Podcast. Thanks for listening — and thanks again, Brad.

Brad: Thank you, Traci.