Faced with increased workloads and time and budget constraints that often restrict external train-ing support, many chemical pro-

cess operators are forced to get the most out of their heat transfer system with less help. This article offers rec-ommendations for how to carry out proactive maintenance on heat-trans-fer fluids, to maximize their useful life and minimize problems associated with fluid degradation, such as exces-sive downtime for unplanned mainte-nance when the heat transfer system has become unsafe or is no longer able to carry heat in a reliable manner. It is useful for anyone developing or re-freshing asset-care-management pro-grams related to heat-transfer fluids and systems.

Discussed below are the most com-mon fluid-related problems encoun-tered by heat-transfer systems and a variety of potential solutions. While individual system designs and varia-tions in process and operating condi-tions make each application unique, all heat-transfer fluids share many common attributes, making these recommendations widely applicable.

Ultimately, our goal is to educate those involved with the operation and maintenance of liquid-phase heat-transfer systems, both large and

small, that use an organic-based heat-transfer fluid. The organics include chemical aromatics, fluids based on petroleum derivatives, silicone or gly-col, the polyalphaolefins (PAO; also referred to as API Group IV-based fluids) and more. A properly designed and operated heat-transfer system can be the biggest ally in maintain-ing (and even increasing) productivity while reducing overall maintenance and production costs.

It starts with smart selectionThe selection of the heat-transfer fluid — whether at the system design phase, or on an ongoing basis after commissioning — should not be taken lightly. Fluid selection should not be dictated solely by the purchase price or any single physical characteristic. Rather, a variety of factors should be considered: •Thepotential impactonworkersof

a given fluid, in terms of adequate training and protection that must be implemented to address hazards related to potential exposure to the fluid, in both its vapor form (inha-lation risk and mist concentration) and liquid form (skin contact). In ad-dition to direct exposure, the choice of the fluid could impact productiv-ity engendering additional handling

and paperwork protocols involving other internal resources within the company, such as the health and safety advisors, medical care per-sonnel, personnel in the receiving department and so forth

•Freight charges related to deliveryof fresh product

•Cost associated with the pickup,handling and disposal of the used oil and drums

•Proven fluid performance beyondfresh oil data (for instance, if vendor data is able to demonstrate the re-tention of fresh oil properties after some time in service, as demon-strated by extensive oxidation and thermal stability data)

•Can the current system accommo-date the fluid being considered (in terms of compatibility with sealing materials, existence of a properly sized expansion reservoir, suitable match between the fluid properties and the existing hardware, such as the pump and safety-relief valve)

•Miscibilitywithcurrentheat-trans-fer fluids if partial (rather than full) changeout is needed

•Documented success by the vendorin your type of application

•Level of liability coverage, serviceand expertise the fluid maker and distributor bring to the table

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32 ChemiCal engineering www.Che.Com DeCember 2009

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CC

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H

n-Hexocosane (C26H54)COC flash point : 215°C / 419°F

Molecular weight : 366.7 grams/mole

n-Dodecane (C12H26)COC Flash Point: 71°C / 160°F

Molecular weight: 170.34 grams/mole

Excess Heat

n-Tetradecane (C14H30)COC flash point : 99°C / 210°F

Molecular weight : 198.4 grams/mole

Heavy carbonaceous residues

Maximizing Heat-Transfer Fluid Longevity

Proper selection, monitoring and maintenance can protect fluids

and components from damage due to thermal degradation,

oxidation damage and contamination

FIGURE 1. In this example with heat-transfer fluid n-hexa-cosane, thermal degradation occurs when excess heat

drives the cracking of a straight-chain hydrocarbon (not shown is the formation of reactive free radicals,

which have been omitted for clarity)

Gaston ArseneaultPetro-Canada Lubricants, a Suncor Energy business

14_CHE_120109_SAS.indd 32 11/19/09 1:23:35 PM

Further discussion of initial fluid selection is beyond the scope of this article, but is covered in Ref. [1–7].

Over time, the most common threats to the life of heat-trans-fer fluids (and sometimes the en-tire system) include the following: • Thermal degradation • Oxidative degradation • Process contamination • Contamination by other materials Each threat is discussed below, along with findings from real case studies, and practical recommendations for how to deal with these challenges.

Thermal degradaTion Regardless of the chemistry of the heat-transfer media, thermal degra-dation can occur whenever the heat source provides more energy than the heat-transfer media can absorb and carry away at that particular time [8].

Figure 1 shows a simple example of the thermal degradation of a typi-cal petroleum-based heat-transfer fluid (n-hexacosane) with ISO viscos-ity grade 32. In this case, the fluid is a distribution of molecules of various lengths, averaging 26 carbons long.

As shown in Figure 1, when the en-ergy submitted to the fluid exceeds the threshold necessary to start breaking the stable covalent carbon-carbon bonds, the result is the formation of shorter hydrocarbons. The example in Figure 1 shows the scission (crack-ing) of a perfect straight, long-chain alkane into shorter molecules, such as dodecane (C12) and tetradecane (C14), each having a lower boiling and flashpoint and viscosity compared to the starting C26 hydrocarbon.

The systematic result of thermal degradation is a reduction in the overall fluid viscosity and increased volatility, which increases the risk of

leakage and loss through evaporation. Thermal cracking increases the vapor pressure, lowers the flashpoint and fire point, and sometimes, reduces au-toignition temperature (AIT). As the name implies, the AIT is the tempera-ture at which the fluid vapors are hot enough to ignite spontaneously in ab-sence of an ignition source [9, 10].

As shown in Figure 2, the problem worsens if left unaddressed. Reynolds discovered in 1883 [12, p. 86], that low-viscosity fluids offer the best heat transfer behavior in a forced-convec-tion situation such as a typical heat transfer system. Based on these find-ings, one may think thermal cracking is advantageous from a thermal con-ductivity point of view. However, the resulting drop in viscosity is not nec-essarily favorable.

Safety risksThe concern is that the associated po-tential reduction of the AIT of the de-graded fluid can make the operation of a closed system unsafe if the operat-ing temperature nears or exceeds the AIT. Moreover, shortened molecules are not the only species formed during thermal degradation of the fluid.

On the other hand, an open system — that is, one in which the heated fluid is constantly in contact with the atmosphere — is even less forgiving. Any drop in the heat-transfer fluid’s flashpoint and fire point (defined as the temperature at which the fluid sustains a fire for five seconds in the ASTM-D92 Cleveland Open Cup, or COC flashpoint test apparatus) could jeopardize the entire operation, considering that the fluid was likely chosen, in part, based on its fresh oil, open-cup flashpoint rating (to which a safety margin was likely added).

Efforts to determine a definitive re-

lationship between a drop in flashpoint and a drop in AIT have not proven suc-cessful. Fortunately for users, in many cases where a petroleum-based fluid exhibits a relatively low flashpoint, we have seen the AIT remained high, but this is not always the case.

The performance data shown in Table 1 demonstrate how progressive thermal degradation leads to steadily diminishing flashpoint and viscos-ity of the heat-transfer fluid. The gas chromatography distillation (GCD) test consists of a simulated distilla-tion of the fluid in the laboratory. In the cited example, the initial distilla-tion point (GCD 10%) drops over time, which again confirms the increased concentration of low-boiling compo-nents present in the fluid.

Performance problemsAnother major consequence of thermal cracking is the formation of carbona-ceous residues (Figure 2), which result from reactions of recombination. To a certain extent, these particles can be compared to soot that is produced dur-ing fuel combustion in a diesel engine, where it is documented that soot is harder than the metallic components of the engine [13].

Such unwanted carbon residues are not only abrasive toward the piping, but they also tend to stubbornly ad-here and harden onto the hot surface points, forming an insulation layer inside the pipe. This occurrence often forces the user to increase the heater set temperature (increasing energy consumption) to maintain the desired operating fluid temperature.

As a general rule of thumb, Wheeler [14] reports that the widely used heat-transfer fluids based on poly-alkylene glycols (PAGs) begin to ex-perience thermal degradation near 250°C (482°F). Meanwhile, Wheeler also reports that the thermal degrada-tion of uninhibited polyethylene glycol results in a mix of five organic acids [15]. The formation of these byproduct acids leads to increased corrosion over time in high-temperature systems.

Of similar importance is the fact that even systems running at tem-peratures that are considered to be relatively mild (for example, around 149–204°C or 300–400°F), are not ex-

ChemiCal engineering www.Che.Com DeCember 2009 33

FIGURE 2. Excessive thermal stress often results in a breakdown of the heat-transfer fluid, and the carbonaceous byproducts can build up on the inside surfaces of pipes

All photos: Petro-Canada Lubricants, a Suncor Energy business

14_CHE_120109_SAS.indd 33 11/19/09 1:24:59 PM

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34 ChemiCal engineering www.Che.Com DeCember 2009

empt from the ravages that elevated temperatures can bring, in terms of the thermal cracking of the heat-transfer fluid. For example, consider a system in which the fluid experienced a change in physical properties, com-bined with oil-flow issues (for instance, from a defective pump, a fluid contain-ing solids, or some piping restriction or pluggage) or a problem with the heater (for instance, the heater coil or electrical element has baked-on car-bon that acts as an insulation layer forcing a higher energy demand to maintain the target fluid outlet tem-perature). Such factors can cause a rise in the skin-film temperature (the temperature of the fluid immediately touching the heated surface).

Any combination of the conditions mentioned above can cause the skin-film temperature to be significantly higher than the temperature of the fluid circulating in the center of the heated pipe (which is called the bulk oil temperature). The larger the gap between skin film and bulk oil tem-perature, the more energy the fluid tries to distribute within itself through turbulence. At some point, the fluid at the heated surface will receive more energy than it can absorb (its heat ca-pacity), carry and release (its thermal conductivity), resulting in thermal degradation of the fluid.

Minimization strategiesDiscussed below are ways to minimize the thermal degradation of a heat-transfer fluid in open systems.Use the right fluid for the job. By choosing a fluid with a high thermal stability, Guyer and Brownell [16] suggest that most problems associ-ated with localized or temporary tem-perature excursion can be prevented. Ashman [17] also emphasizes the im-portance of using a heat-transfer fluid with a suitable thermal stability for the application. Hudson, Sahasrana-man [6, 7] and many others acknowl-edge that petroleum-based fluids of pharmaceutical quality produced by a severe hydrogenation and hydrocrack-ing process (also referred to as “white mineral oils”) tend to have greater thermal stability compared to petro-leum base oils that are produced from other refining methods [6, 7].

Use appropriate venting. Venting involves the periodic release (from the fluid and the system) of the light, more highly volatile hydrocarbons that form during thermal cracking. Venting is typically carried out by circulating some of the hot fluid to the expansion reservoir, so that those molecules with a relatively high vapor pressure can naturally migrate into the gas phase above the fluid. Then, depending on the system design, the vapors are re-leased directly into the atmosphere or sent to a collection drum or tank, al-though laws governing volatile organic compounds (VOCs) and other environ-mental trends cause most users to collect the condensed low-boilers and properly dispose of them.

Fresh fluid needs to be added pe-riodically, to maintain the desired fluid level (to prevent pump starva-tion and cavitation when the system charge contracts after a shutdown). As a precautionary note, users should re-member that fresh fluid must never be added directly into the hot oil stream; rather it should be added into the ex-pansion tank or other cool reservoirs connected to the system.

Venting continuously or for extended periods is not advised, because the re-sulting rise in the bulk fluid tempera-ture in the expansion tank will accel-erate oxidation (discussed below).

We recommend the use of an oil-analysis program to determine the rate of generation of low-boilers dur-

ing any operation. With proper vent-ing and analysis, users can establish how often, and for how long, the fluid must be periodically vented, in order to safely operate a high temperature system with a fluid that stays in good condition (maintaining characteristics that are similar to the fresh oil for as long as possible).Adopt proper startup and shut-down procedures. The successful startup of any heat-transfer system is important, since the faster the heat-transfer fluid reaches its desired op-erating temperature, the faster the facility can produce its products and begin to fulfill orders. This becomes even more important for systems that stop and start up regularly.

One may say that running the pump and the heater for a few extra hours to accommodate a slower, more-gentle startup is not cost-effective, but for many applications, such an approach pays its own dividends. For instance, by maintaining a more-gradual heat-ing profile at startup, the fluid will be able to effectively remove heat and reduce the risk of thermal degrada-tion, and minimizing the formation and buildup of baked-on residues. The net result will be extended planned-maintenance intervals and greater component life expectancy.

Shutdown procedures also impact system efficiency and fluid life. For instance, Stone [19] and others recom-mend maintaining oil circulation after

Table 1. AnAlysis DAtA showing thermAl DegrADAtion of the heAt-trAnsfer fluiD At A meAt-processing fAcility

sample date,

mm/dd/yy

flash-point, °c

(coc)*

watercontent, ppm

(Karl fisher)

Viscosityat 40 °c,

(centist-okes, cst)

gas chromatoraphy distillation (gcD)**

10% boiling, °c

90% boiling, °c

% boilingbelow335°c

04/04/00 154 660 27.0 327 512 10.49

08/10/01 155 580 23.2 307 507 14.40

06/11/02 175 313 22.7 317 490 12.80

09/09/02 171 51 21.2 201 481 31.90

12/09/02 161 220 20.5 304 489 16.20

03/12/03 175 42 19.8 294 490 19.00

After startup and shutdown procedure modification of April 2003

06/11/03 169 156 23.0 310 497 15.70

New fluid properties

209 — 35.6 382 498 0.80

* COC represents analysis via the ASTM-D92 Cleveland Open Cup (COC) flashpoint test apparatus.** GCD = gas chromatography distillation. The GCD test consists of a simulated distillation of the fluid in the laboratory. Comparison with the fresh-oil boiling curve allows for the detection of lighter and heavier molecules in the fluids.

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the heater is turned off until it’s been cooled to 65°C (150°F). The refrac-tory material in a furnace is designed to retain heat for as long as possible, so stopping the oil flow immediately after the heat source has been turned off provides an opportunity for the stagnant fluid to crack, forming low-boiling fractions and carbon residues. This negatively impacts the life of the fluid and the overall heater efficiency.

With regard to smaller systems such as temperature-controlled units (TCUs) or extruders, many designs have improved greatly in recent years and now maintain fluid circulation for some period of time following shut-down as a common approach.

An insufficient shutdown interval was the overall problem at the facil-ity whose degraded fluid was shown in Table 1. After a service call, it was de-termined that the 249°C (480°F) sys-tem was shut down on Friday evening with only a short circulation period following shutdown. It was fired up again at 7:00 a.m. on Monday, to allow for production to start at 9:00 a.m.

A full system shutdown and clean-ing was deemed impossible by the user at that time, so the fluid was left untouched, but better future prac-tices were implemented. The last set of results in Table 1 shows that two months after the initial analysis, the rate of generation of low-boilers had

diminished (as seen in the percentage boiled below 335°C). As a direct result, the facility did not add any new oil. The increase in kinematic viscosity and flashpoint, and the fact that the strainer no longer collected carbon residues in any appreciable amount, provided evidence of improvement.Consult your suppliers about proposed design or operational changes. Business is booming, more production is expected from the plant, more parts must be produced, and lines need to be added. Do you need to increase the operating temperature? What about the flowrate, is it ade-quate? What does your heater manu-facturer think of the proposed addi-tion? Operators should get as much input as possible from their system designer. manufacturers, and parts and fluid suppliers before any major changes are implemented. Stone [18] recommends that operators should maintain an updated list of contacts and keep it handy for questions or troubleshooting help.

It is relevant to document the skin-film temperature in the current sys-tem and in the proposed operating conditions. Make certain your fluid supplier confirms your current heat-transfer fluid’s ability to handle any new operating parameters.Maintain, inspect and perform preventative maintenance on sys-

tem components. Even though liq-uid-phase systems commonly operate above the flashpoint of the fluid (but below its auto-ignition temperature), the risk of fire should be very low in a normal, well-designed system, espe-cially one that is kept oil-tight, leak-free and subject to regular inspection and maintenance [19].

For any system where heat is pur-posely generated to raise the fluid temperature, ensuring proper opera-tion of the heat source is critical to achieve optimum performance. Daily inspections, using a consistent check-list of items to monitor are recom-mended [18, 20]. For instance, fired heaters should be inspected for flame impingement, especially if the burner is oversized or cycles frequently. In the case of flame impingement, the flame (whose temperature is typi-cally on the order of 1,093–1,650°C, or 2,000–3,000°F) subjects the oil tubes to excessive localized heat flux, which can cause tube deformation and cok-ing (resulting from thermal degrada-tion, as seen in Figure 2), and leakage with increased risk of fire [21].

In the case of systems equipped with immersed electrical heaters, excessive watt density, lack of fluid turbulence around the hot tubes, or insufficient flowrate often causes premature deg-radation of the fluid. Such degrada-tion can be offset in part by proper fluid selection and maintenance prac-tices [22, 23].

In any system, the oil-circulation pump can be compared to the heart, moving the fluid around. The pump should be well-maintained. Specifi-cally, drive bearings on the electric motor and pump seals should receive proper attention. Centrifugal pumps should ideally operate at or near their best efficiency point (BEP), with bearings well-maintained and seals working properly. Finally, the expan-sion reservoir, piping, connections and valves should be selected and maintained appropriately, as part of a world-class maintenance program.

Meanwhile, the life blood of the op-eration — the fluid itself — should be tested regularly. While further discussion of the types of tests, their significance and data interpretation is beyond the scope of this article, the

FIGURE 3. These illustrations shows the type of varnish (left) and sludge (center, right) that can result from oxidation-related degradation of a petroleum-based, chemi-cal aromatic and polyalkylene glycol (PAG) fluid

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36 ChemiCal engineering www.Che.Com DeCember 2009

American Society for Testing and Ma-terials (ASTM) Method D5372 should be followed to properly monitor the condition of heat-transfer fluids [24].

Oxidative degRadatiOnFor the purpose of this article, we de-fine fluid oxidation as the reaction of the heat-transfer fluid with oxygen from air. The oxidative degradation of organic compounds is extremely com-plex, as it involves a series of chemical reactions that result in the formation of high energy, unstable and reactive free-radicals and peroxides. One initial free-radical allows for the possibility of forming two radical species, which results in the formation of a variety of oxygen-containing species, mainly organic acids. These long-chained or-ganic acids may be weak on their own, but as their concentration grows in the fluid, the oil eventually becomes more corrosive [25].

These acids also polymerize — often to a level that is sufficient to modify the fluid properties, causing an in-crease in viscosity, discoloration and eventually, precipitation as lacquer, varnish and sludge [26] such as that shown in Figure 3. The varnish for-mation is seldom a concern in heat transfer applications because of rela-tively large pipe diameters and valves with high tolerances. However, further oxidation will lead to the formation of heavier acids and sludge. Oxidation-related sludge is not very soluble in heat-transfer fluids, so it tends to ad-here to metallic surfaces or settle in areas of low flow and low turbulence.

Such sludge also tends to settle at the bottom and the sides of the ex-pansion tank, and can also circulate throughout the system and make its way into control valves.

Fluids for a specific project are gen-erally chosen based on their proper-ties in a fresh state. Any alteration of the fluid physical properties (resulting from degradation or contamination) could negatively impact the heat ab-sorption and dissipation capabilities of the heat-transfer media.

Table 2 provides oil-analysis data for an uninhibited, chemical aromatic (synthetic), heat-transfer fluid that ex-perienced oxidation in a large 27,000-L (7,132-gal) system in Europe. (In this

context, the term “uninhibited” refers to the fact that the fluid does not con-tain additives such as anti-oxidants and rust-corrosion inhibitors to pre-vent degradation.) The acid number (AN) — as determined by ASTM D664 Method and used to quantify the level of acids in an oil sample — was in-creasing over time.

The distillation of the fluid, repre-sented by the GCD 10% boiling point, shows the initial boiling is at the same temperature as fresh oil, so thermal degradation does not seem to be an issue in this example. We notice the viscosity has risen by 30% over time and the end of the distillation curve (GCD 90%) is shifting toward higher temperatures, indicating the increas-ing presence of heavy compounds not found in the fresh oil.

An increasing amount of insoluble particles are forming, and the AN values are rising. By connecting the dots, we conclude that oil oxidation is causing an increased formation of heavy acidic polymers that will foul the low-flow areas of the system. This degraded oil, with its higher viscosity, cannot deliver the same performance capabilities as fresh oil, and in today’s context of high energy costs, any loss of efficiency is costly.

In the example discussed above, the company could not afford a shutdown to clean its system this year. Instead, operators opted for a partial fluid re-placement of 50% of the entire charge this year (incurring an expenditure of roughly $175,000, excluding waste oil disposal and labor) and are plan-ning a full drain, clean, flush and refill next year. In general, fluid oxidation imposes great cost penalties on any system; the selection of a fluid with better oxidation stability could have avoided this massive spending and of-fered many more years of useful life.

Minimization strategiesDiscussed below are several options that are available to avoid or minimize potential oxidative degradation.Inert gas blanketing. In closed sys-tems, the most effective way to elimi-nate the potential for oxidation is to install an inert gas blanket in the ex-pansion tank headspace. Hudson [29] provides details and recommenda-

tions on how to install such systems. The basic principle relies on substitut-ing air (which contains oxygen) with an inert gas (most often nitrogen, al-though carbon dioxide and argon may also be considered) in the only location where warm oil can come into contact with oxygen from air — the expansion tank headspace. Displacing oxygen that might react with the fluids virtu-ally eliminates oxidation.

The pressure of the inert gas is maintained slightly above atmospheric pressure. Gas-blanketing systems, in-cluding the safety-relief valve, require ongoing inspection and maintenance to prevent inert gas leaks and limit unnecessary, costly gas consumption.Choose a fluid formulated for the job. Oxidation-inhibitor additives are also available to enhance the perfor-mance of heat-transfer fluids. Most chemical aromatics sold today contain one or a few varieties of molecules and do not contain any performance enhancing additives such as antioxi-dants or rust and corrosion inhibitors.

The additives that are used in heat-transfer fluids are different from the ones found in other industrial lubri-cants that are not subjected to such elevated temperatures. Specifically, in the case of antioxidants, some tech-nologies combat oxidation by reacting with free radicals before they can lead to acid formation, while others attack intermediate peroxides [25].

Fluid selection is complicated by the fact that it is extremely difficult to determine the oxidation stability of a heat-transfer fluid by its techni-cal data sheet. Even though many of the heat-transfer fluids on the market today are unadditized, their respec-tive marketing materials often praise their fouling resistance and promote their outstanding oxidation stability. Thus, users should assess all product claims with a critical eye.

In general, systems with an enor-mous amount of oil tend to be more forgiving because it takes a longer time to oxidize a larger volume of fluid to a point where it raises concerns in terms of oil analysis results. In these cases, user experience, references, testimonials and competitive bench-marking studies should be evaluated in conjunction with vendor data, to

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assess the likely longevity of a fluid for the application at hand and avoid costly changeouts in large systems.

Compared to closed or blanketed systems, open systems allow the hot fluid to come in direct contact with air, making oxidative damage a harsh reality rather than a possibility. In these cases, the importance of choos-ing a robust product to maintain high productivity standards becomes even more important.

For example, an electronic company operating an open system at 175°C (350°F) was replacing its heat-trans-fer fluid every six months, after which time the fluid had become viscous and dark with a burnt odor. Switching to a fluid with better resistance to oxida-tion enabled longer service life. In fact, judging by the oil-analysis results, the oil properties still look like new after more than 24 months of service in these harsh conditions. This obviously saves the facility money in terms of time, labor and fluid purchases.

In closed systems with no inert gas blanketing, the key is to maintain the fluid temperature in the expansion tank below 65°C (150°F), if possible. The main reason is because there is a direct relationship between the tem-perature and the rate of oxidation. For instance, the rate of reaction between a petroleum-derived oil with oxygen (doubles for every 10°C (15°F) increase above 80°C (175°F) (with slight varia-tions depending on the author) [28], so the higher the temperature the more severe the degradation. And this does not take into account the fact that the oxidation reaction is exponential and is accelerated by contaminants such as copper or iron particles, water and other catalysts.

Oxidation could occur in systems with a design that allows the oil to circulate through the expansion res-ervoir with full flow, either directly after the heater or on the return from the heat users. Such design exposes the hot fluid directly to oxygen from

air, thereby acceleraing oxidation and greatly reducing fluid life.

Using the oil-analysis results, fluid oxidation can be monitored by paying close attention to acid number (AN) and gas chromatographic distillation (GCD) results.

MiniMizing process contaMinationProcess contamination can be ex-tremely damaging to the heat-transfer fluid and the system components. As is often the case, logic suggests that contamination is unlikely since the pressure is greater on the fluid side, but real life experience has shown on many occasions that process mate-rial can enter the heat-transfer fluid stream. The urgency required to fix a process leak really depends on the se-verity, the type of contaminant (chem-istry), and the heat transfer media it comes in contact with. The case of contamination by water is discussed in the next section, although water is sometimes part of the process.

For example, in the oil-and-gas in-dustry, a natural-gas-extraction fa-cility may experience an unintended leak of the process hydrocarbons into the heat-transfer fluid system. Being hydrocarbon-based, the heated gas-eous molecules will mix very well with heat-transfer fluids of a similar chem-istry, such as petroleum-based fluids, chemical aromatics and PAO Group IV synthetic fluids ([4] provides de-tails on competing fluid types). Within a short time, the viscosity of the entire fluid charge will be greatly reduced and its overall volatility increased.

In a situation such as this one, em-phasis must be put into venting the heat-transfer fluid to release those light hydrocarbons into the proper col-lection device in order to maintain a safe operation, and if at all safely pos-sible, to keep the unit running until the next shutdown opportunity to re-pair the leak.

Another example of process con-

tamination in the petroleum industry occurs frequently at asphalt termi-nals. Similar to the example discussed above, any unintended ingress of as-phalt in the heat-transfer fluid circuit will mix very well with most of the fluids, since the majority are based on long hydrocarbon chains. However, the highly viscous hydrocarbon asphalt will quickly thicken the fluid.

We have seen heat-transfer fluids in-crease to several hundred centistokes or even become too thick to measure at 40°C (104°F), thereby ruining the fluid’s ability to transfer heat effec-tively. The heavy asphalt components will also coat the system internals and plug small lines, meaning a full sys-tem cleaning and flushing will even-tually become necessary to restore the system to efficient operation.

In some cases, the contaminant it-self may be inert to the fluid but it may still react with traces of moisture to form acidic or insoluble compounds. These byproduct contaminants can ac-celerate rust and cause corrosion and fluid degradation.

Depending on the process contami-nants that are inadvertently leaking into the fluid system, it might be pos-sible to detect them (qualitatively) via oil analysis, using the common elemental analysis method like In-ductively Coupled Plasma – Atomic Emission Spectrometry (ICP-AES). Sometimes the contaminant can be detected indirectly after it has reacted with another compound in the fluid. In some cases regular oil analysis will not detect the process contaminant and specialized methodology and in-struments are needed, such as those found in specialized research-and-de-velopment facilities.

A quantitative evaluation to de-termine the type and extent of the contamination generally requires so-phisticated equipment (such as an electronic microscope, or gas chroma-tography coupled with mass spectrom-etry), as well as well-trained analysts

Table 2. OIl-aNalYSIS DaTa DeSCRIbING a FlUID THaT HaS eXPeRIeNCeD OXIDaTION (SOURCe : PeTRO-CaNaDa lUbRICaNTS, a SUNCOR eNeRGY COMPaNY)

Sample date, mm/dd/yy

Flash point (COC), °C

Water content, ppm (Karl Fisher)

Viscosity at 40°C, cSt

acid num-ber (aN*), mg/KOH/g

Solids (insolu-bles), wt.%

GCD

10% boiling, °C

90% boiling, °C

% boiling below 335°C

05/12/04 193 301 30.4 <0.1 0.1 333 423 10.5

04/25/06 179 382 29.6 0.11 0.24 324 426 11.0

04/15/08 201 138 39.4 0.23 0.48 336 431 9.4

*Acid Number (AN) is obtained using ASTM D664 titration method, which is used to quantify the levels of acid in an oil sample.

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38 ChemiCal engineering www.Che.Com DeCember 2009

who are knowledgeable about the product being tested and informed on what contaminant types to look for.

Whenever a process leak is sus-pected, it is advisable to reach out to your fluid supplier’s technical contact immediately and explain the situa-tion. A sample of the fluid should be analyzed right away.

OtheR sOuRces OF cOntaminatiOnIn addition to contamination that can arise from process materials (dis-cussed above), heat-tranfer fluids may also become contaminated by the envi-ronment (rain or snow), condensation, foreign liquids (such as the wrong fluid put in the system), or the ingress of air. For systems where the expansion reservoir is outside and vented to the atmosphere, it is critical to have — at a minimum — an enclosed tank with a 180-deg, goose-neck pipe on the top.

This may sound very basic, but we were once called to investigate un-usual noise coming from the hot oil piping at a saw mill. After assessing the noise, we climbed up to the top of the burner building to examine the expansion tank. The 12-by-12-in. steel cover normally bolted to the side of the 250-gal expansion tank was lay-ing on the catwalk, covered by a foot of dirt, wood dust and snow and no one could remember who had been up there last. Rainwater and snow falling directly into the expansion tank from the open hole was responsible for the high water content we later measured in the fluid and the knocking noise in the piping below.

New construction or recently cleaned systems or heat exchangers are not typically flushed before commission-ing. However, in systems where a full or partial cleaning was performed, traces of aggressive cleaning fluids or water-based solutions that are not re-moved could accelerate corrosion, foul-ing or create their own polymerization and insoluble residues [29]. In newly commissioned systems, aside from the typical wood debris, welding rods and rags, residual water from pressure testing is most often the culprit for startup problems. Unlike many indus-trial applications, water in the heat-transfer fluid is more easily detectable

by operators and unforgiving because it is heated above its boiling point dur-ing service in most applications.

Entrained water will affect various fluid chemistries in different ways. In lubricating and circulation fluids based on mineral and synthetic Group IV PAO oils, prolonged exposure to water may cause the following [30]: •Hydrolysis or precipitation of

oil additives (for those oils that have them)

•Accelerated rust and corrosion of system internals

•Acceleratedegradation(oxidation)•Causepumpcavitationandwear•Createagarglingnoiseintheexpan-

sion tank and knocking in the hot oil piping

Based on years of examining real-life oil-analysis results, we can say that in general, water does not appear to pose immediate productivity concerns at concentrations below 500 ppm (0.05 wt.%), although we have encountered certain, more-sensitive systems where lower concentrations did have a notice-able impact. However, residual water at concentrations above 1,000 ppm (0.1 wt.%) becomes alarming and calls for investigation and removal.

In the case of mineral oils, the best practical way to remove the water from a heat-transfer fluid while the system is running involves more of a two-step process. First, vent the fluid, allowing the water vapor to migrate into the expansion tank. Once inside the expansion tank, some of the steam will have sufficient vapor pressure to leave through the vent pipe or safety-relief valve when it opens.

In the case of PAG-based fluids, the numerous oxygen atoms in their structure produces strong hygroscopic behavior that is directly proportional to relative humidity in the environ-ment. Wheeler [15] reports that at 50% relative humidity, pure ethylene gly-col absorbs 20% water at equilibrium. This can cause serious concerns.

Lastly, operators must take steps to guard against potential contamination by airborne vapors or particles that could affect the fluid. Just think of a saw mill example, where entrained cellulose dust from the wood dust may not degrade the fluid itself, but will affect the fluid's ability to flow, which

will reduce the thermal efficiency and accelerate fouling in the system [29]. Such an occurrence is more likely to happen if the expansion tank is lo-cated in a very dusty environment.

Minimization strategiesDiscussed below are a variety of techniques for minimizing con-tamination that can threaten heat- transfer fluids.Investigate and fix. All cases of con-tamination should be investigated and fixed, and such incidents should also be reported to your fluid supplier, for advice on the potential impact on the fluid. As mentioned earlier, sometimes the contaminant can be evacuated, boiled off or it could ruin the fluid and foul the system in a short time.Flush new constructions or re-cently cleaned systems before startup. Operating companies and builders seldom factor in the cost of a system flush, since they often assume the blowing of the water will be done correctly and the contractors will not leave debris in the piping. Unfortu-nately, discovering such contaminants after the system is running can prove to be costly down the road. While no-body needs the extra costs of flushing a new system (especially when the fluid of choice is relatively expensive, like PAGs or silicone-based fluids), it is nonetheless a good practice. With systems filled with mineral oils, cir-culating a virgin base oil of the same viscosity as the heat-transfer fluid of choice is a cost-effective way to remove any potential contaminants. Keep an eye on filters and strain-ers. Solids collection in the oil filters or strainers should be noted in a log book and monitored closely, preferably with photos taken. The size, texture and color of the deposits all tell a story, and such residues can be sent periodi-cally to a laboratory with sophisticated analytical equipment for accurate identification.

Keep in mind that different solids may come from more than one source, and may become discolored, so don’t jump to conclusions.

Similarly solids from the previ-ous fluids may reside in the system for a long time before an event such as pipe work or partial fluid replace-

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ChemiCal engineering www.Che.Com DeCember 2009 39

ment creates enough disturbance to loosen them. We see this in cases where a used furnace is bought and commissioned without cleaning and flushing prior to the connection to the main system.

Often solids may have a familiar smell or texture that suggests an origin, but could well be something else. For example, a plant was using a heat-transfer fluid that caused valve malfunction because of deposits accu-mulating inside the valve spools. The black, abrasive deposits looked and felt like carbon particles (abrasive, gritty between the fingers). However, lab analysis identified the material as copper sulfide, formed by the localized chemical attack of sulfur present in the fluid’s base stock onto the copper from the brass valves.

The facility could have spent sev-eral thousands of dollars in parts and labor to upgrade all the valves to more expensive stainless steel. Instead it

switched to a properly formulated fluid based on highly refined API Group II base oils containing only traces of sul-fur. This replacement fluid has proven to be harmless to copper components after years of service, and has had the added benefit of extending oil changes considerably, based on oil-analysis results. ■

Edited by Suzanne Shelley

AuthorGaston Arseneault is a se-nior technical advisor with Petro-Canada Lubricants, a Suncor Energy business (1310 Lakeshore Road West, Missis-sauga, Ontario, Canada L5J 1K2; Phone: 973-673-3164; E-mail: garseneault@suncor.com), located in the Newark, N.J., area. With the company for more than ten years, Arseneault holds an M.S.

in analytical chemistry from the Université de Montréal in Canada and is a member of Society of Tribologists and Lubrication Engineers, from which he has obtained the Certified Lubrication Specialist (CLS) and Oil Monitoring Analyst (OMA I) certifications. He also holds the Ma-chinery Lubrication Technician I certification from the International Council for Machinery Lubrication.

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