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HODGES (Athlon Solutions)

Guidelines around the addition of desalter washwater were historically 3 to 5% on volume based on crude charge. Some years back, with a shift towards heavy Venezuelan and unconventional crudes, the trend pushed up towards the 7 to 10% range or higher. As an ancillary note, this has caused some more refiners to adopt a brine recycle strategy, as we just discussed. Common sources of the desalter washwater are stripped sour water, vacuum hot well, atmospheric, overhead accumulated water, and surface water. Ammonia levels should be monitored. Guidelines are unique and specific to the design, crude slate, and operational philosophy of the specific desalter. There is no one rule that fits all. Your process chemical suppliers should be able to design and carryout proper surveillance, testing, and ionic simulation to assist in bracketing the operational envelope for ammonia content in the washwater.

In general, ammonia guidelines are less than 50 ppm to avoid an emulsification impact on the desalter, or less than 20 ppm to avoid crude tower salting, fouling, and corrosion. Caustic can be added to the sour water stripper to improve ammonia stripping. Hot well water contains free and heavily emulsified oil. When setting your washwater rate, you should take into account the oil content of the hot well water that is coming into your desalter with makeup water; otherwise, it would be artificially low.

In newer, deep-cut vacuum units, we have noted a greater content of emulsifiers in the hot well water that must be addressed through either operational or chemical management techniques. Lastly, your process chemical supplier should run a full battery of lab testing on the washwater to check for the presence of known bad actor species such as tramp amines and others. These results should then be fed back into your overall washwater management and crude tower corrosion management practices.

PRIBNOW (CITGO Petroleum Corporation)

Improper control of washwater and brine will lead to emulsions, which will result in carryover and poor desalting. As I mentioned, when we start having carryover and upsets, our crude tower is going to become upset, which could result in the tower pressuring up.

Ways to Properly Control Washwater: Stephen mentioned many of them including 1) lacking enough fresh washwater, 2) excessive mixing of the water and oil at the mix valve, and 3) injecting the washwater further up in the pre-heat. If too much water is injected upstream, it will count as mixing. Tight emulsions may be created that are hard to break.

Vacuum Condensate: I think you called it ‘hot well water’. We all have our different lingo. If there is an emulsion or those bad actor components exist, there will be problems in our desalter, high solids in the washwater, and excessively high washwater pH. Our sulfur plants have sent the desalter high pH sour water. We will see that high pH in the desalter, which results in formation of a stable emulsion. Monitoring your incoming pH is important.

Finally, when we mud-wash, we do not take fresh water away from the water being injected for desalting. Every time fresh washwater is taken away, desalting stops. The level of chlorides will then increase going into the crude tower.

We just talked about brine recycle. Do not recirculate solids or emulsifying agents like oil. We have found that it will just create havoc with both desalters.

Poor Salt Removal: We start seeing a decrease in our overhead pH due to the concentration of the chlorides. If we see high pH in our desalter, our experience is that partitioning of the amines and ammonias into the oil phase enters our crude tower and then creates a higher or elevated overhead pH. Also, we have experienced salting of our top trays in the crude tower.

BILL CATES (Hunt Refining Company)

I will caution you about the use of the water off the sour water stripper, if you are putting in caustic. You have to watch to make sure that the operators are not getting overzealous with the caustic condition; because once you get sodium content in that water up to about 300 to 350 ppm, it will start to make sodium naphthenate. For folks that do not know, that is a very good tight agent for making the emulsion.

SHENKLE (Flint Hills Resources, Ltd.)

One data point from us with tight oil processing: We have seen a decrease in neutralizer usage in crude overheads. We do have units with brine acidification. We use vendor-supplied, inhibited acid for desalting and amine partitioning to the water.

VILAS LONAKADI (Foster Wheeler USA Corporation)

Steve, you mentioned the sources of the washwater, one of which was the surface water. Has anyone seen that the desired oxygen in this water has led to corrosion, or has anything been done to de-aerate that water being used, apart from the stripped water?

HODGES (Athlon Solutions)

That is a great question, and the answer is yes. The oxygen in surface water can and does contribute to problems in your atmospheric tower. For instance, crude units that run cold at the top generally have corrosion in their naphtha pumparound circuit which requires the use of a filming inhibitor in the pumparound return. If you are running sour crude and then add oxygen from your surface sourced washwater, you will make elemental sulfur in your tower. Further, if you have the presence of iron sulfide in your atmospheric tower, you will form a rubbery deposit in your tower. This has been happening as long as I have been in the industry since the 1980s. Think of it like a three-legged stool with the legs being elemental sulfur, iron sulfide, and filmer. If you take any one of those three away, you will not have a problem. If at all possible, try to avoid oxygenated water because of the problems that it can incur.

CHRISTINE SHOROKEY (Monroe Energy, LLC)

What is the panel’s experience with water injection points? If you are injecting 7 to 10% waterwash, is a portion of that in your pre-heat train?

HODGES (Athlon Solutions)

Good question. Our opinion and Best Practice are a bit contrarian. We like putting all of it ahead of the cold pre-heat train into the crude charge pump. We have case history after case history of the positive effects on this. We see tremendous benefits not only in elevated levels of desalting efficiency from a salt removal perspective, but also solids removal. Of course, you must have a demulsifier that is capable of handling the emulsion that this technique will create.

SLOLEY (CH2M Hill)

On the question of injection points, I am not aware of anyone using any special quills when injecting the water into the crude. It is really just an elbow connection. At the moment, the industry practice on water injection locations varies. It’s close to even numbers of plants putting all the water downstream of the cold train versus putting some of the water into the crude upstream of the cold train. When injected upstream of the cold train, water injection is typically downstream of the crude charge pump. Injection upstream of the crude charge pump is a minority position in the industry as a whole. Whether it is attractive or not is a different question. It is just an observation of what people do. There are a couple of issues with injecting the water early in the process. Of course, it increases the volume and the pressure drop to the unit. A lot of people have pushed for higher capacity. They find it the hydraulic constraints, so they want to avoid that.

The next issue is that depending on the water sources, sulfate, and carbonate content of the water, the technical risk there is really that the sulfates and carbonates become less soluble at higher temperatures. So there have been people who had deposits in their cold train equipment because of that. It is fairly easy to do the analysis on the water and make sure you do not have that problem, or do not do it if you do have carbonates. It is easy to avoid though.

RUSSELL “RUSTY” STRONG (Athlon Solutions)

Back to the question from the floor about oxygen, specifically about the corrosion issue: Back in 1988, Richard Horvath and Hans Schutt, with Shell Oil, presented a paper on one of their refineries where they identified the firewater (oxygen saturated) being used at the desalter was directly the cause of an ammonium bisulfite corrosion in the overhead line of their crude tower. What they found, demonstrated in the lab, and confirmed in the field was that the SO2 (sulfur dioxide) half-reacted with ammonia and formed a bisulfite salt that was actually quite corrosive in the overhead. Evidence is clear that it does happen, but not at every refinery.

PAUL FEARNSIDE (Nalco Champion Energy Services)

On the oxygenated water, do not assume that if you are using stripped sour water or good quality vacuum condensate water that it is oxygen-free. I had a number of cases where the seals were worn across the actual desalter water pump, or they had failed. The makeup water coming to the pump had less than 50 ppb oxygen. Leaving that pump, the water had as high as 2 ppm oxygen. The only way to catch that is to test for oxygen on your crude overhead water analysis. Do not just focus on chlorides. There are other acidic species; namely, SOx (sulfur oxide). So, to catch them, we monitored and analyzed for increased SOx and then went back and found that the pump seals had actually been failing.

VILAS LONAKADI (Foster Wheeler USA Corporation)

Is the corrosion deeply observed only in the crude tower overhead, in the desalter, and/or elsewhere because of this desired oxygen?

HODGES (Athlon Solutions)

Question 60 is about corrosion in the oxygenated water. I think our observation has been that generally, the negative impact of oxygen is limited to the crude tower and crude tower overhead. There are many other factors to consider where you may have, in fact, internal corrosion at the desalter and the brine water circuit. But in my observation, that has not generally been directly traced back to the use of oxygenated water.

GLENN SCATTERGOOD (Nalco Champion Energy Services)

High pH desalter washwater is typically caused by ammonia in the stripped sour water. This ammonia will exit the desalter along with the BS&W in desalted crude. The ammonia will distill into the crude tower overhead, promoting ammonium chloride salt deposition and leading to NH4Cl and HCl corrosion in the overhead, top pumparound, and top tray section of the distillation tower. This is the same mechanism observed with amines coming in either with the washwater (due to amine recycle of internal amine containing slops) or crude oils treated with H2S scavengers that generate amines.

DENNIS HAYNES (Nalco Champion Energy Services)

Desalter washwater mixing with the crude determines the effluent water pH. If the effluent water pH is low and a portion of this carries over with the crude, any acidic components in the basic water (BW) with the oil will carry through to the distillation column and increase potential for corrosion. Low pH of either desalter washwater or effluent can elevate corrosion rates in the desalter vessel and associated piping, requiring the addition of a corrosion inhibitor. If the resultant effluent water pH is high, it may stabilize the emulsion in the desalter causing water carryover and/or oil carryunder. Proper effluent water pH control (implied as washwater pH control) is important for reliable and stable desalter operations.

PHILIP THORNTHWAITE (Nalco Champion Energy Services)

The correct volume of washwater is critical to good desalting, and the use of low volumes can impact significantly on desalting and dehydration efficiencies. Increased salt in crude levels will result in elevated levels hydrolysable chlorides; and while these can be controlled to a degree with caustic, elevated levels of chlorides in the overheads will lead to low pH excursions and increased levels of aqueous corrosion. Although these low pH conditions can be mitigated with increased neutralizer dosing, the subsequent threat of salt formation is increased.

The quality of the desalter washwater is another important consideration; and if SWS (sour water stripper) bottoms are used as the washwater source, it is critical to ensure that ammonia content is minimized as this can significantly increase the risk of salt fouling in the top sections of the main fractionator and overhead condensing section. The high pH of the SWS bottoms will promote the partitioning of the ammonia into the oil phase where it will be passed into the main fractionator. Based on the partial pressures of ammonia and chlorides, there may be an elevated risk of salt formation and deposition on the top trays of the main fractionator, top pumparound, overhead line, and condensers. The deposition of ammonium chloride salts can lead to pitting corrosion and, in the worst case, fouling of equipment that begins to impinge of optimum performance of the unit.

Another consequence of using ammoniacal water as desalter washwater is that the ammonia will end up in the condensed water and increase the sour water pH. With elevated levels of ammonia, the pH of the overhead sour water can often be in excess of pH 6.5; and since May, refiners still dose neutralizer to achieve a pH in the range of 5.5 to 6.5, it is not uncommon to find that neutralizer dosing rates have been significantly reduced or even turned off. In these instances, it has been found that corrosion rates in the overheads condensers can increase significantly, even though the sour water pH is elevated. This is because ammonia is a very poor dew point neutralizer since it will not partition into the water phase until the bulk of the water has already condensed. Therefore, in these instances, it is recommended to continue to dose the neutralizer at a sufficient rate to neutralize the amount of chlorides present.

In order to mitigate against high ammonia levels in the washwater and also tramp amines present in the crude, some refiners choose to use desalter acidification programs to aid the partitioning of the ammonia and/or amine into the desalter effluent brine. Sufficient acid is injected into the washwater to maintain a desalter effluent pH in the region of 5.5 – 6.0 in order to maximize the removal efficiencies. When using acidification strategies, the choice of acid is critical. The most appropriate acid should be used to minimize the carryover into the crude unit overheads. Acids, such as acetic and glycolic acid, can end up in the overhead resulting in difficulties in controlling the overhead pH. This problem arises because the combination of these weak acids and the neutralizer, which is a weak base, results in overhead sour water that is highly buffered. Due to this buffering effect, a disproportionate amount of neutralizer is needed to achieve the desired pH. In such circumstances, careful control of neutralizer dosing is vital to ensure that both the risks of aqueous corrosion and salt formation are minimized.

SHENKLE (Flint Hills Resources, Ltd.)

Historically, we have not had corrosion problems in our brine circuit or desalters, so we do not do anything specific to address this question.

HODGES (Athlon Solutions)

Some refiners have used acids in the desalter washwater as a means to assist in emulsion resolution. We always look for other solutions as this practice may present other challenges including operator exposure, corrosion to the desalter internals/water circuit, and additional acid load to the atmospheric tower. When required, using weaker non-mineral acids usually makes the most sense and does not contribute as greatly to overhead corrosion.

Corrosion in the effluent brine/makeup water heat exchanger is overlooked in most every desalting system. We recommend the following Best Practices: First of all, many operators get tired of messing with this exchanger, so they bypass it: bad idea. You must run your effluent brine and makeup heat exchanger. Bypassing the system because it is difficult to keep online is not a good operating choice. Secondly, we have not seen any advantage with high metallurgy exchangers here. Carbon steel is cheap and allows you to keep a spare in the warehouse for replacement when it leaks. Lastly, have your specialty chemical supplier run a periodic chloride balance to make sure you are not leaking. Leaks often go undetected and can significantly degrade the desalting efficiency if you are leaking across your brine water exchanger.

SLOLEY (CH2M Hill)

If you look over the crude unit and find an abandoned exchanger, it is almost certainly the water/water exchanger for recovering heat from the brine to the fresh desalted water. This exchanger has major corrosion problems. Keeping this in service without leaks often requires either Inconel or Hastelloy materials. I think the panel is giving two approaches here. Build it cheap and replace it often or build it really expensive and make it work. Either way, you are both trying to address the problem of leaks. They are both legitimate approaches, but they do involve some level of commitment of capital or attention of the operation.

SAM LORDO (Nalco Champion Energy Services)

The use of specially designed corrosion inhibitors can successfully mitigate and control desalter washwater, desalter brine, and desalter vessel corrosion due to low pH excursions, either from crude contaminates or acidification programs.

DENNIS HAYNES (Nalco Champion Energy Services)

In cases where the corrosion is due to low pH washwater and low pH effluent, filming corrosion inhibitors have been successful in reducing corrosion. In cases where the desalter washwater is neutral or basic yet the effluent becomes low pH after washing the crude, there are rare applications where caustic is used to increase the washwater pH so that the resultant brine effluent pH can be control to acceptable levels. In cases where the corrosion is due to oxygen contamination of washwater sources, lining the desalter has been attempted; yet, the optimal solution is to eliminate the source of oxygen.

HODGES (Athlon Solutions)

High iron content on desalted crude manifests itself in two main areas. These are inability to make anode-grade coke and as a FCC catalyst poison. The iron can be in many forms. Three of the most common forms of iron we see are iron oxide, which is rust; iron sulfide, which is corrosion; and, siderite, which is essentially crystalline iron carbonate that we are seeing more and more of in certain tight oils. Historically, operators and process chemical suppliers have tried to address iron removal in three ways. The first way we have seen is acidifying the washwater with citric, acidic, or glycolic acids. A second way is applying a chelant to the washwater such as EDTA (ethylenediaminetetraacetic acid). The third way is running a continuous dirty rag draw from the desalter. We have not seen any of these mentioned methods meet with much success with respect to iron removal, and they have the unpleasant side effect of increasing desalter, crude tower, and downstream unit corrosion. The handling problems of the continuous dirty rag have diminished the popularity of that method as well.

We have seen a very successful alternative approach where caustic is added to the desalter washwater along with a unique demulsifier, which functions well at all pH levels. This transports the iron into the water phase, thus exiting with the brine. Check with your current chemical desalter supplier before trying this approach.

JIM PROROK (Husky Oil Operations Ltd.)

For years, we have been successfully running the dirty bleed pull on the rag draw, and we continue to do so. Yes, we are an anode coke business, and good iron removal is essential. Maybe the difference is that they were a light sweet refinery. Nowadays, the solids contents are coming up in the crudes, but we still manage them. You are right; we must have it. The oily bleed has to go to a free water knockout drum and then get as much free water out as possible. The resulting oil stream has to be centrifuged.

HODGES (Athlon Solutions)

It can be managed; it is just a bit cumbersome.

SLOLEY (CH2M Hill)

What pH do you run the desalter water down when you add caustic for the iron partitioning in order to promote iron partitioning into the water?

HODGES (Athlon Solutions)

The pH of the effluent brine must be 9 or higher. You could actually do some studies of pH elevation versus your iron removal to determine the specific best target for your particular desalter.

ROBERT AJILUNI (Athlon Solutions)

I want to add that if the source of your washwater is from a sour water stripper, you will need make sure that the stripper is working well because sometimes that water will have an elevated pH due to ammonia. So, if you are checking your washwater or brine as it comes off the desalter, you would think: Oh, the pH is good, and I have plenty of caustic. But in fact, you do have not enough caustic; so, you are not actually removing the iron the way you should. It is such a fine line on the color of that brine. You do not want crystal-clear brine, but you do not want oil; so that it is really incumbent on the operator, and Operations in general, to walk that fine line. But if you walk that line, you can get some really amazing results. 

JILL BROWN BURNS (Valero Energy Corporation)

We actually do this at one of our facilities and have not really seen the benefits on most of our critical KPIs (key performance indicator). It has actually caused some difficulties. If you go back to one of our previous slides talking about controlling the crude overhead pH, you will see that this is the KPI we are not able to meet. Mr. Sloley indicated controlling the brine pH. It does go up when you add caustic to it, and then you see a subsequent issue with controlling the crude overhead pH below the upper specification.

GLENN SCATTERGOOD (Nalco Champion Energy Services)

Some contaminant removal additives (CRAs) can be added to the desalter washwater to make the iron more water-soluble (such as acids) and move it from the oil phase into the water, leaving the desalter, along with the brine water, to the wastewater treatment plant in a water-soluble form. Other CRAs are non-acidic and can be used to move particulate iron from emulsion layers in the desalter into the water phase.

CHRIS CLAESEN (Nalco Champion Energy Services)

If the largest part of the Fe is contained in the solids, the solids removal can be improved with a specific Nalco Champion solids wetting additive. Removal of over 90% of the Fe and desalted crude Fe levels below 0.5 ppm have both been achieved with this additive.

DENNIS HAYNES (Nalco Champion Energy Services)

Mitigation of iron carryover from the desalter depends on the form of the iron; but where it is iron sulfide particulate, increased washwater, optimized mix valve setting, addition of solids removal chemistries, and adjusted interface level are the most certain methods.

PHILIP THORNTHWAITE (Nalco Champion Energy Services)

The key consideration here is the form of the Fe. In the majority of cases, iron is present as iron sulfide, a corrosion byproduct which is present in the crude due to corrosion upstream, tankage, or introduced via external streams such as slops. The particle size of the FeS (iron sulfide) in the crude is very small; and when coated in oil, these particles are very difficult to remove at the desalter. In order to effectively removed inorganic iron present as particulates, specialist solids removal chemistries have to be used in conjunction with the primary demulsifier. When the oil and washwater pass through the mix valve, the adjunct products help remove the oil coating from the particulate, allowing it to be water wetted. Once water-wet, the solids are removed with the effluent brine.

Iron can also be in the form of iron naphthenate and is present in particular naphthenic acid crudes. This organic form of iron is effectively removed through acidification of the washwater. The reduced pH causes the iron to dissociate from the naphthenate molecule, leaving the naphthenic acid and the iron salt of the particular acid that was used. This iron salt is typically water-soluble and removed with the effluent brine.

PRIBNOW (CITGO Petroleum Corporation)

It is essential to keep crude pre-heat exchangers clean. Cleaning benefits are hard to justify if they negatively affect crude rate. The criteria we use are crude hydraulic throughput, heater firing limits, fuel gas savings, desalter temperature efficiency, or crude or vacuum tower heat balance if you have needs in that area to remove heat. Each of these criteria at CITGO is periodically monitored by the process engineer or unit engineer and unit personnel to determine if action needs to get taken. If the fouling factors increase, we will increase monitoring of that exchanger and begin to make plans to take it offline in the near future or next opportunity.

The most common methods we use at CITGO are rather simple: pressure surveys and U-factor or duty calculations. For the crude hydraulic restrictions in your pre-heat, perform pressure surveys. Find out what bundle has the greatest impact, or which will give the crudest throughput recovery, and then clean it. The exchangers should be ranked in order of greatest to least impact. Compare the design conditions with the start-of-run conditions. If bypasses around exchangers are utilized to increase crude throughput, downstream relief capacities must be checked, and heater inlet temperatures monitored.

Perform U-factor or duty calculations for heater firing limits, desalter temperature, and fuel gas savings. Rank the exchangers by the most fuel gas saved at the heater. If you are cleaning an exchanger at the beginning of the preheat train, recovery factors need to be considered. A 20°F increase at the exchanger will not gain 20°F at the heater inlet. Consider this when performing economic evaluations. For the crude or vacuum tower heat balance or heat removal issues, then target that section of the tower and clean those bundles.

Another method for determining which exchangers to clean is a rigorous model. I have seen a couple programs that model crude pre-heat trains. These programs model heat integration within your crude towers and are able to predict the inlet temperature of your heater. We do not currently utilize that at CITGO. We prefer the simple go-out-in-the-field-and-look method.A couple of points to keep in mind: When exchangers are taken offline and bypassed, understand how this will affect the crude or vacuum tower heat balance. If parameters are not set properly beforehand, the crude or vacuum tower may become upset, which may result in product quality or pressuring of the tower. We experienced one event when we almost had to abort a cleaning because taking the exchanger offline resulted in an increase in crude tower pressure. We learned from that event. Now, we make sure to predict the heat balance change and adjust tower crude rate or heater firing as necessary prior to taking a preheat exchanger offline to clean.

HERLEVICH (Marathon Petroleum Corporation)

Just to add onto the cleaning piece: At our refinery, we recently made a procedure for evaluating whether it is actually acceptable to take bundles offline or bypass equipment. This has not typically been an issue in the crude pre-heat train because they were designed with online cleaning in mind. However, our practice is to review anyway because we have found several instances where downstream equipment was not rated for the bypassing scenario MAWT (maximum allowable working temperature) or sometimes the blocked-in case MAWP (maximum allowable working pressure).

We monitor the heat exchanger performance at Marathon, in most plants, by using a simple spreadsheet-based model as well. We have standardized on a corporate-supported, macro-driven, performance monitoring spreadsheet that was developed in-house. We used these on all units in the refinery, both for heat exchange and for basic catalyst performance. We monitor the heat exchanger performance in terms of actual heat transfer coefficient (UA) compared to start-of-run clean conditions. We also track heat exchanger pressure drop through field measurement. Once again, we often employ our college co-op workforce for these activities. Next, a simple economic analysis is conducted to compare rate reductions versus fuel gas savings. Most of our plants also do a ready-to-run analysis, which that typically results in spring heat exchanger cleaning programs.

A couple of points to keep in mind: When exchangers are taken offline and bypassed, understand how this will affect the crude or vacuum tower heat balance. If parameters are not set properly beforehand, the crude or vacuum tower may become upset, which may result in product quality or pressuring of the tower. We experienced one event when we almost had to abort a cleaning because taking the exchanger offline resulted in an increase in crude tower pressure. We learned from that event. Now, we make sure to predict the heat balance change and adjust tower crude rate or heater firing as necessary prior to taking a preheat exchanger offline to clean.

The next slide shows a graph from the performance monitor. This macro-driven, Excelbased software produces graphs that the tech service engineers include in their monthly reports. The results are analyzed to estimate fouling trends. You can see the UA and the duty for this particular set of exchangers in the graph.

The last slide lists the typical configurations for our crude units. In our bigger refineries, we have complete dual trains on the heat exchange side. During the spring exchanger cleanings, we will reduce the rate on those crude units to clean one heat exchange train at a time. In the medium-sized crude units, we tend to take off the individual exchangers or smaller batteries of exchangers. Finally, we have one small refinery that idles the entire unit for heat exchanger cleaning. This process is often conducted in sympathy with work on other refinery other units.

VICTOR TAILOR (Commonwealth Engineering & Construction)

The panel covered the entire pre-heat train potential problem well. I want to add that in a revamp case, you should consider the pressure drop through the heat exchanger when calculating the desalter charge pump to make sure that it has enough head, even at a slightly higher pressure drop. This pump needs to be very generously sized. In this way, you avoid reducing crude charge for a longer period of time.

TOM GERMANY (Calumet Specialty Products Partners, L.P.)

Has anyone on the panel used online thermal shocking of exchangers to clean in lieu of taking them off mechanically?

PRIBNOW (CITGO Petroleum Corporation)

Yes, we have heard of a couple of techniques in the cold pre-heat train.

SHENKLE (Flint Hills Resources, Ltd.)

We have not.

HERLEVICH (Marathon Petroleum Corporation)

No, I am not aware of our doing that.

HAROLD EGGERT (Athlon Solutions)

On units that are being monitored for crude pre-heat trains, we have noticed that when there is an upset, power failure, or shutdown, after the shutdown and startup, there is some significant heat gain recovery. It is, again, the thermal shock. The tube shrinks at a different rate than the fouling that is on there, resulting in some of the material breaking loose. I think some of that is being employed in a cold train, too.

HERLEVICH (Marathon Petroleum Corporation)

Just one more thought to add to that. We have seen times where we take down exchangers and prep them by conducting steamout and cleanup. Then where we have put them back online without any mechanical cleaning, they do still work much better. Once you discover that this process works, it may actually become routine. So take a look at that.

DENNIS HAYNES (Nalco Champion Energy Services)

The use of a heat exchanger rating program that can look at individual exchangers and how they relate to the overall system performance is the best method to rank the exchangers based on impact to the system due to fouling condition. Look at fouling rate, and then develop a cleaning schedule.

CHRIS CLAESEN (Nalco Champion Energy Services)

An intelligent way to look at this is by the determination of the total cost of operation (TCO) for each exchanger. The exchanger TCO consists of the additional fuel-burning cost required to generate the duty lost by fouling, cleaning costs (which are the additional furnace duty when offline), and fixed costs for chemicals, equipment, and manpower. More frequent cleaning reduces the additional fuel burning cost, but also increases the cost of cleaning. Clearly, there must be an optimum time to clean an exchanger, which will give the minimum cost, and this can be calculated. The exchanger network and individual exchanger fouling rate should be routinely calculated and tracked to maintain an optimum cleaning schedule using exchanger model software, such as NALCO’s Monitor™.

GARY HAWKINS (Emerson Process Management)

Emerson Process Management offers a heat exchanger health monitoring solution that calculates the duty on both the hot and cold sides (should be the same, alerts if too much deviation) and the current value of the heat exchanger coefficient. Changes in the heat exchanger coefficient are indicative of fouling. The rate of change of fouling is also calculated, and alerts can be generated to warn of potential crude instability leading to accelerated fouling of the exchangers.

PATRICK TRUESDALE (Emerson Process Management)

One problem facing refiners gathering all of the temperature measurements around each tube-and-shell bundle in the crude pre-heat train. Often, capped test thermowells are provided for periodic measurements taken manually. This option presents a refiner with the opportunity to take advantage of wireless temperature transmitters utilized to bring these missing temperature measurements into heat exchanger health monitoring solutions.