Articles

Fig. 3A: Inlet coating of tubes Fig. 3B: Magnified view mon method is simply cleaning boxes, tube-sheets, and tube ends. In when plant operations are affected.

1990, both Japan and Germany This method is not enough to mini-offered shop-coated new copper tubmize the cost of fuel or electricitying; shop coating of petrochemical HX or loss of equipment life due to tubes was done in many countries, tube corrosion. Including the U.S.; and in Europe Pe r formance modeling is neces (Italy), in-situ coating of condenser sary to determine optimum times tubes was a common practice. for cleaning and efficiency mainte-Florida Power Corporation and nance. Heat Exchanger Institute EPRI conducted a six-year study cul(HEI) standards (Cleanliness minating in a final report, I n - S i t u Factor–CF), EPRI standards Coating of Condenser Tubes as an ( Taborek & Tsou Pe r fo r m a n c e Alternative to Retubing.

This extenFactor–PF), or Engineering sive report included heat transfer Sciences Data Unit (ESDU) guide studies and coatings applications in d a t a⁸ can be used, or you can three plant units and a side-by-side develop your own perfo r m a n c e test of two waterboxes, one with coat-models, which most companies tubes and one with uncoated tubes.

The simplest way to develop a model is to compare heat transfer just before and just after cleaning, then calculate the increase in efficiency due to the heat transfer gained. For example, if a 500MW condenser is not cleaned, the cost of fouling can amount to over $265,000 in one year. One cleaning will pay for itself seven fold in direct fuel costs. This example includes only the direct losses of fo u l i n g , not the costs of corrosion of materials due to fouling and the loss of equipment life due to corrosion. If we factor in the loss of one year of a 15-year tube life, the costs double and one cleaning saves twice as much.

Coatings Will Work to Break the Fouling Cycle

The Electric Power Research Institute (EPRI) published a study on tube coatings (RP-1689-18) in the 1980s. In 1989, John Monday suggested that full-length tube coatings were a possible s o l u t i o n⁹ because they had worked so well in preventing corrosion of water

-JPCL November 2005

The findings in the EPRI study supported the use of coatings. While the uncoated waterbox required regular maintenance and cleanings, the coated box did not. The uncoated tubes continued to deteriorate, doubling plugged percentage within five years, while the plug rate of the coated tubes remained low. Heat transfer results showed that coatings resistance typically compares with that of a slightly fouled tube, and, while sprayed on coatings do reduce the tube diameter (3-6 mils), this is compensated by an increase in the water flow rate in the tube.

Reduced cleaning requirements, little macro or micro fouling, few deposits, no heat transfer penalty, no flow reduction, no under-deposit corrosion or leaks to speak of, and a tube life extension of over five years—why haven’t we heard of this before? Quite simply, the law of supply and demand regarding coated tubes does not yet apply because too few people realize the value of coated t u b e s .

100% Solids Epoxy Coatings 100% solids epoxy coatings are used with great success on seawater cooling and other systems in almost every industry and country. With service lives of 20+ years, they minimize or prevent corrosion on circulating water pipe, waterboxes, channel heads, tubesheets, tube inlets, and other structures.

The coating of tube inlets to over 6–8 times their diameter has proven very beneficial. Unlike inserts, the endings are tapered, with each of the two or three coating layers shorter than the one b e fore. This provides a true taper transition that does not promote turbulence and further erosion-corrosion damage, a problem found with true metal or plastic inserts. Fig. 3 shows the coated inlet s y s t e m . Some 100% solids coatings are designed for fl e x i b i l i t y, erosion-corrosion resistance, impact, and wear. These products are safe to use in a confined space, have no volatile organic compounds (VOCs) or hazardous air pollutants (HAPs), and can be applied easily in a few coats to almost any thickness desired. A natural extension of using this type of epoxy system is to apply it in the tube. We know that 100% epoxy systems reduce galvanic corrosion of dissimilar materials and erosion-corrosion.

(Figs. 1 and 2). Adding an inert, non-corrosive coating does away with both the crystallization and corrosion fo u l i n g mechanisms. The metallic component is insulated from the cooling media by a layer of inert, non-metallic coating that is non-corrosive in the media. Insulating the metallic component eliminates the ionic

bonding in crystallization and disbonding in c o r r o s i o n . Also minimized is a large portion of the active fo u l i n g mechanisms. The question we would naturally ask is: “What happens to both biological and particulate fouling when coatings are present?”

We already can postulate a partial answer. With a slick surface and no oxides or corrosion byproducts to hinder flow and create boundary layer drag, these two mechanisms of fo u l i n g will decrease. As we do not have standard test data here, we will need to look at performance data to answer the question. However, first we need to answer the question “What happens to tube heat transfer when coatings are pres e n t ? ”

How Heat Transfer in a Condenser or HX Tube Wo r k s

The power plant system most oft e n examined is the condenser. Because the steam side conditions are almost exactly the same for condensers regardless of plant, they are easier to examine than heat exchangers, which have widely varying conditions.

Figure 4A shows that the heat trans-fer resistance (HTR) or losses in a 90/10 copper-nickel condenser tube are related to the tube material (2%), on the steam condensing side (26%), and on the water cooling side (72%). In a breakdown of these percentages (Fig. 4B), we see that steam side (SS) fouling consists of a black magnetite layer deposit and a condensing water layer on the outside of the tube. On the steam side, the deposit accounts for 31% of the HTR and the water film accounts for 69%. This is interesting information, but it is difficult to conceive of taking any maintenance actions to reduce these losses because the steam side of a condenser is very hot and has limited access; the outer tube surfaces are inaccessible; and the magnetite layer would quickly refo r m .

The more relevant side is the waterside, which accounts for 72% of the total

Heat transfer losses. Here, waterside deposits account for about 46% of the HTR and the boundary layer accounts for 54%. These are relative figures fo r testing on one tube. The percentages will s h i ft with changes in the fouling condition. However, minimizing these two waterside conditions of heat transfer loss will greatly affect the total HTR of the tube and the operating condenser, due to the 72% effect on total HTR. Condenser & HX Design Both HEI and the Tubular Exchanger M a n u facturers Association (TEMA) intentionally “over-design” heat exchangers and condensers to allow fo r corrosion and plugging of tubes during their design lives. A 15% over- t h e r m a l capacity design is typical. There are also allowances for fouling and cleanliness, and again, a typical HX or condenser will operate with associated fuel cost increases to perhaps a 65% cleanliness or performance fa c t o r.

Many of us have used the 15%

plugged limit as a guide to the end of condenser tube life. Also as a general rule for condensers, 20 years in seawater service is a long time. As such, seawater service condensers can require re-tubing two to three times during a p l a n t ’s life span.

Most industry studies on how and when to clean heat exchanger and condenser tubing demonstrate that cleaning with some established frequency or as a measure of performance pays for itself in reduced corporate operating expendit u r e s .^{1 1} Most of these studies do not economically account for the extended operating life of the tubing due to this maintenance cleaning.

Heat Transfer Test Data Results Without getting too much into the theor y, actual heat transfer resistance performance test data show the fo l l o w i n g .⁹

Based on the dataset in Fig. 5, a coated tube will perform similarly to a typically installed and fouled tube in service without adverse effects on the heat transfer capability of the tube itself. In fact, the total HTR of coated the tube is less than that of a tube with typical fo u l i n g deposits (tube # 4 vs. tube #8 in Fig. 5).

A number of factors account for this. The increase in flow rate and overall heat transfer for a coated tube is accounted for by the reduction of the waterside boundary layer thickness. Less drag means a thinner boundary layer and more heat transfer. Without a reactive metal surface, there are no ionic interactions, such as manganese deposits or oxide formations. The coating is a non-corrosive, inert ceramic or plastic. Less drag means higher flow and less biological and particulate fo u l i n g . Silts are not collected, and the smooth s u r face finish present will inhibit biological growth as well.

The reader should note that, although the tube diameter is reduced by a small percentage (by three mils of coating), the velocity or flow rate through the tube slightly increases to compensate fo r coating thickness (P₁V₁= P₂V₂), so the reduced tube diameter is not a fa c t o r. Essentially we have replaced a mud, silt, and blocky oxide deposit with a dense cross-linked epoxy that has an equivalent HTR.

While tube coatings can fail in spots from mechanical or other damage, the copper alloy tube in this area generally turns passive rather than active. An active copper alloy passivates quickly in seawater (a few hours). Pitting occurs without forced passivation in a new condenser because of the extent of the area of tubing and the fact that one area of the tube can be anodic to another. In a coated tube, when a small area of coating fails and the base metal is exposed to s e a w a t e r, it almost always quickly passivates. If coatings blister, lift, or are permeated by seawater, the area will still be passive and collect brine or salts (passive in copper alloy tubes). Fig. 6 shows two different coated copper alloy tubes removed from a seawater condenser after 7.5 years’ service. The tubes were cut in a band saw, creating chipping along the edges, but are otherwise “as found.” The right (white) tube was lightly wiped with a wet rag to show the extent of particulate and biological fouling and deposit (essentially none). You don’t go through a testing program without failures. Saltwater service, chlorides, and forgetting to reset the cathodic protection system voltage for coated conditions will blister coatings (Fig. 7).

So down-tube, full-length coatings work in all respects. This data has been gathered from 15 years of experience in coating copper alloy tubes in fossil fuel p l a n t s .

Blasting is done with special patented nozzles that set up a standing cyclone-generated sine-wave that insures the entire tube is cleaned and well profiled with wearing of the surface confined to no more than 1–3% (Fig. 8A). Coating is conducted with specially patented spray nozzles and procedures that ensure full coverage (Fig. 8B).

Coating Vs. Re-tubing Condensers and Heat Exchangers

Re-tubing larger condensers must be a planned project because it often cannot be accomplished in the time typically allotted for outages. The tubing must be ordered up to 18 months in advance and the work scheduled during a major turbine outage. Utilities are not the only industry with re-tubing schedule/outage duration restrictions. Refinery and chemical plants need to produce, and operating a large hospital, hotel, or sports complex without air conditioning is not feasible.

Typical costs in a fossil condenser re-tubing are in the range of $4,500/MW. As units decrease in size, the costs go up to $6,000/MW. So, for a 750 MW unit, it will cost at least $3.5M to re-tube the condenser ($2/L-ft tube) with any alloy, provided there are no problems and the $ 4 / L - ft). These are serious costs, and, coupled with the loss of operating revenues for added downtimes, an option such as coating tubes may be more v i a b l e .

Conclusion: Why Coat Tu b i n g ? While coatings on condenser or exchanger tubes will not last as long as retubing (5–10 years vs. 20 years), they have their place in the overall operations, maintenance schedule, and options portfolio, as described below.

First, the coating operations can be done in a typical outage turnaround cycle, and the costs run in the range of 20–35% of those of re-tubing (e.g., for a 750 MW unit, 40,000 40 ft tubes, lead time 45 days, implementation 3 weeks). If the tubing in your plant or unit does not have 20 more years of service life, the down tube coatings option becomes the most viable economically. If your unit needs and warrants a full re-tube but you need to buy time to budget, engineer, or make it to a turbine outage four years away, full or partial down tube coatings may be an option to avoid operation unavailability and leaks. If one waterbox of two or four is limiting your plant’s performance capabilities, the tubes in this box can be coated to extend life until you have the opportunity for full re-tubing. If tube fouling is a problem requiring large maintenance expenditures; then coating tubes should be considered a viable alternative to the continued high operating costs. O ften, we are driven by discharge permit limits. Copper has become a source of problems for many industries. Down tube coatings eliminate almost all copper discharge (about 6 lbs/yr/MW). The technology and services to apply full-length tube coatings are available n o w, both in Europe and the U.S.

S o u r c e b o o k, TR-103403, Puckorious & Associates, 12/93.

1. 2 . ASME Press, Steam Surface Condensers—Basic Principles, Pe r formance Monitoring, and Maintenance, Richard Putnam, 2 0 0 1 .
2. 3 . The Economics of Regular Condenser Maintenance—Return on Investment Analysis, White Pa p e r, Richard Putnam, Conco Systems, post 2000.
3. 4 . HEI, Standards for Steam Surface C o n d e n s e r s , Ninth Edition, 1995, Heat Exchanger Institute.
4. 5 . The NALCO Guide to Cooling Water Systems Failure Analysis, Harvey Herro and Robert Port, McGraw-Hill, 1993.
5. 6 . Corrosion Atlas, Evert During, E l s e v i e r, 1988, Association of Industries and Organizations for Energy and Environment.
6. 7 . Fouling during the use of Seawater as a Coolant—the Development of a User Guide, 2003 Conference on HX Fouling & Cleaning, Fundamentals & Applications, Santa Fe, NM, Pugh, Hewitt, & M u l l e r- S t e i n h a g e n .
7. 8 . Fouling in Cooling Systems Using S e a w a t e r, Item 03004, Engineering Sciences Data Unit, ESDU International Ltd, London, UK, 2 0 0 3 .
8. 9 . Extending the Life of Condensers and Heat Exchangers in Fossil Fired Electric Utility Generating Plants, John Monday, ASM International 8901-002, 1989.
9. 1 0 . EPRI, TR-107068, In-Situ Coating of Condenser Tubes as an Alternative to Retubing, R.O. Fraze & B. Woodruff, Florida Power Corporation, 9/1997.
10. 1 1 . Optimize Heat Exchanger Cleaning S c h e d u l e s , O’Donnell, Barna & Gosling, AICHE, CEP, June 2001.