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Doug Meyne (Champion)

Phosphorus-based naphthenic acid corrosion inhibitors have been successfully used in the refining industry since the early 1980’s. Phosphorus provides its protection to steel by corroding it and forming a passive layer that, under SEM/EDS, proves to be an Iron/Phosphorus/Sulfur blend. With rare exception, the protection comes from high TAN liquid attack of the affected metal, which is a good match for non-volatile filmers in pump-arounds like an HVGO. However, when there are zones being attacked by condensing naphthenic acids, the opportunity for contact, and hence mitigation by the inhibitor, is impaired. The P-S-Fe bond is pretty tenacious, with a bonding energy higher than the activation energy for naphthenic acid corrosion. In addition, this bonding is also effective at dispersing existing FeS in a dirty system which can result in downstream fouling issues and/or pluggage of HDS reactor beds. Naphthenic acid corrosion occurs from ~500F to ~650F. non-phosphorus inhibitors can work, but those in commercial use have temperature limitations. Their bonding energy is much lower than the phosphorus-based products, and at elevated temperatures (> 500F) they are simply inefficient at adsorption. Non-phosphorus inhibitors have been successful at the lower end of the temperature range in atmospheric columns. Products that also have a sulfur component are largely dependent on their sulfidation capability for resistance. The controlled application of a reactive sulfur causing sulfidation can be helpful in the sweeter acidic crudes, such as some of those coming out of western Africa with less than 0.5% sulfur. However, their effectiveness is substantially reduced when the crude already has sufficient H2S to create and maintain a thin sulfide layer, and they are ineffective in crudes that produce enough H2S to cause sulfidic corrosion.

Jim Johnson (Marathon Petroleum)

We use phosphorous based inhibitor at one of our refineries and have phosphorous based inhibitor on hand at another, but not using. We have no experience with a non-phosphorous inhibitor.

Sam Lordo (Nalco Company)

Nalco has successfully applied sulfur based high temperature corrosion inhibitors to mitigate naphthenic acid corrosion in all streams affected by naph acid, sidestreams, tower bottoms and in a few cases furnace transfer lines since 1992 using patented chemistries. The protective barrier formed by a sulfur-based inhibitor is not as persistent as the phosphorous based product so the use in these is recommend in high shear areas such as vacuum furnace transfer lines.

Nalco routinely uses this product when there is concern, valid or not, of downstream phosphorous impacts if a phosphorous inhibitor is used. The sulfur-based products are also used when the circuit to be protected contains fuels such as diesel or jet.

Jim Johnson (Marathon Petroleum)

In line with industry rules of thumb, Marathon considers a crude to be high acid with a whole crude Total Acid Number (TAN) above 0.5% or a side stream above 1.5%. With low sulfur crude slates the maximum TAN may be reduced, as one of our refineries that runs a predominantly sweet slate experienced naphthenic acid corrosion resulting in the TAN limit being reduced to 0.3%. Crudes are blended to the refinery TAN limit with sulfur, metallurgy and specific stream temperatures taken into account.

We recognize that TAN by itself is not necessarily a good indicator of corrosion potential, however, is readily available for each crude. The naphthenic acid content and type is the true concern in determining the corrosion potential in the higher boiling range sections of the crude and vacuum tower. From a corrosion standpoint, the TAN of the liquid hydrocarbon stream being evaluated rather than the TAN of the whole crude is the more important parameter in determining susceptibility to naphthenic acid corrosion.

We do not determine the content and type in-house; rather utilize the expertise of a third party or our vendors with their proprietary techniques. For one of our crude units that is designed for high TAN crudes with extensive utilization of 317SS in the hot circuits we have utilized third party involvement to evaluate the analytical properties and associated corrosivity of the one distillate circuit where 317SS is not utilized.

Side streams that are considered the most vulnerable to corrosion based on the metallurgy, temperature, and flow characteristics are monitored for corrosion using standard techniques. We also rely on input from our chemical vendors to assess our corrosion potential. Marathon is also a sponsor in an industry JIP to better understand the corrosion potential of naphthenic acids. While more is being learned about the corrosivity of specific naphthenic acids, we depend on unit corrosion monitoring and detailed inspection to assure reliable operation.

Eric Thraen (Flint Hills Resources)

The TAN of whole crude and crude fractions is included in our crude assay test protocol. The TAN of the crude fractions is a far better indicator of crude corrosivity than is the TAN of the whole crude.

Sam Lordo (Nalco Company)

The only way to truly define the corrosivity of a stream due to particular high acid crudes are thru processing of the crude and monitoring for corrosion or by using laboratory testing on streams distilled from the crude oil. Nalco uses a spinning autoclave that can test several metal samples under high temperature and moderate shear conditions.

Jim Johnson (Marathon Petroleum)

Marathon utilizes three methods of corrosion monitoring in the crude/vacuum units: multipoint resistance measurement (iicorr, FSM, GEBetz RCM) systems for naphthenic acid corrosion, ER probes, and corrosion coupons. While the use of coupons may not be considered an ‘advanced method’ for monitoring corrosion, we do continue to utilize them in our refining system.

Two of our refineries have installed multipoint resistance measurement technology in areas that previously experienced naphthenic acid corrosion. One refinery utilizes iicorr’s Field Signature Method (FSM) system, while the other location utilizes GEBetz’ Resistance Corrosion Monitoring (RCM) system. Neither of these systems is monitored continuously. Rather, spot readings are taken on a routine basis with the calculated corrosion rate reported to the refinery. A mix of ER probes and coupons are utilized in our refineries. Either is used depending on the corrosion history of the particular circuit and how frequent corrosion data is required. One of our refineries utilizes a data logger on the ER probe signal to capture data on a near continuous basis, whereas at all other locations the probes are typically monitored on a weekly basis. We have no examples where data is sent to the DCS. Corrosion coupons are still widely used, mainly for general corrosion monitoring. At one refinery that is designed for high TAN crudes, corrosion coupons of various less corrosion resistant metallurgies are placed in select circuits to provide data on the relative corrosivity of certain crudes and cuts. This data will be used in an effort to better optimize metallurgy requirements in the future and provide pertinent corrosion data if a common crude is processed at another location.

Doug Meyne (Champion)

Traditionally, standard corrosion coupons and ER probes are used to monitor corrosion in operating units. The main limitation of these types of corrosion monitoring devices is the limited amount of data that they generate, usually 1 to 2 corrosion rates a week if not less. Corrosion in operating units tends to be episodic in nature and can be attributed to many changes in operating conditions. Under normal conditions a system may see 1-5 mpy corrosion rates; however, the rates can spike up to hundreds of mpy during one of these corrosion episodes. It is critical to identify these corrosion spikes while they occur so that changes in operations or chemical additions can be made immediately to resolve the issue. By reducing the time duration of these spikes, the overall corrosion rate is minimized.

In order to “see” these corrosion spikes and overcome the limited data acquiring capabilities of traditional coupons and ER probes, Champion utilizes data loggers to obtain multiple corrosion rates per day. Standard ER probes are hooked up to the data loggers which have the ability to store several days of corrosion rates. Typically, the rates are uploaded to a handheld unit out in the field and then downloaded to a PC. The data loggers can also be tied directly into a DCS system via cables or wireless buses to yield true “real time” corrosion rates. These data loggers our part of our standard corrosion monitoring package and can be set to read corrosion rates on any given time interval.

Eberhard Lucke (Commonwealth E&C) I haven’t seen any operation yet that would show corrosion monitoring in the DCS. The most advanced I have seen (and I may be outdated on that) was installed corrosion probes with easy connections to a data logger (handheld, PDA like device). A dedicated maintenance person would walk the unit in certain intervals and collect all the data from the corrosion probes via data logger. The data would then be transferred electronically into spreadsheets and used in an offline unit monitoring system. I assume that with new wireless technologies and internet connections, automatic data transfer into databases and even the DCS should be no problem, if required.

Doug Meyne (Champion)

Since there are only isolated instances of fouling in the “cold train” exchangers prior to the desalter(s), we will assume this question is directed more towards the “hot train” exchangers.

First, it needs to be understood that inorganics can provide a “substrate” for organic material to bind to and accelerate agglomeration. At higher temperatures, inorganics can also add a mild catalytic effect to condensation, i.e., dehydrogenation. If deposits show >10% ash, it’s an indication that inorganics may be playing more than a simple passive role. Better removal of solids at the desalter can have a strong impact on preheat fouling, to the extent of virtually eliminating it all together. That being said, an otherwise compatible blend could still foul the preheat train if the desalter isn’t doing a good enough job removing solids.

For the most part, preheat fouling is caused by asphaltene precipitation. At lower temperatures the asphaltene isn’t prone to stick (adsorb) onto equipment surfaces as long as sufficient velocity (>~5 fps) is maintained. A significant amount of literature and research suggests that asphaltene precipitation increases with temperature up to a limit, and then the asphaltene precipitation decreases. Although this temperature varies from unit to unit and with different crude blends, it usually happens in the 400 Deg F range. As the oil heats up, asphaltenes that have fallen out of solution can be resolubilized, but the time it takes them to go back into solution is longer than the preheat time. When encountering hot tubes, the asphaltenes become tacky and will adsorb onto them.

Some crudes can be considered to be “self-incompatible” in a crude unit if they can precipitate asphaltenes by themselves. This situation is rare but can happen. One of the concerns coming out of Canada today is the lack of a good standard for the diluents used in a DilBit. Lighter aliphatic diluents (C7-) at % levels are known to precipitate asphaltenes, but as the weight of the aliphatic increases, so does solubility of the asphaltene. However, in the preheat train as the temperature rises and the density of the diluent decreases, there could be some non-linear effect that could aggravate precipitation. Under this circumstance, this would be a “self-incompatible” crude. Diluent variability can make this hard to diagnose.

The “Dead” oils used in refining, those that have had oilfield gases removed, aren’t as susceptible to pressure variation as “live oils” that will “flash” oilfield gases at a pressure drop. This reduction in pressure and increase in gas is known to cause asphaltene precipitation in production. With insufficient backpressure on a hot oil in a crude preheat, an otherwise stable oil could experience a similar effect in the hotter exchangers. This would then also be a considered a “self-incompatible” crude.

One indication of the precipitation potential of asphaltenes is to run standard SARA (Saturates, Aromatics, Resins, and Asphaltenes) testing on each crude slate. As a rule of thumb, higher aromatics and resins decrease asphaltene precipitation and higher saturates and asphaltenes increase asphaltene precipitation.

There is not agreement in the industry as to the effect of temperature on asphaltene solubility. Some data suggests the solubility is improved with higher temperature, whereas other data suggests higher temperature causes the stabilizing resins to be pulled away from the asphaltenes. Regardless, if an asphaltene precipitates at some lower temperature but doesn’t adsorb onto a tube surface, and if it could resolubilize into the oil, the time necessary to go back into solution is longer than the residence time available in a preheat. Inevitably the insoluble asphaltenes will adsorb (stick) onto hot tubes. Once that happens, at the higher temperatures, the asphaltenes and any still-associated resins will begin the process of dehydrogenating to coke, which cannot be resolubilized.

Different types of flocculation tests can be done, using varying ratios of heptane/toluene to provide a relative scale for the precipitation potential for any given sample of crude oil or crude oil blend. Similarly, the same tests can be used on blends of various crude oils. Since one crude oil may have a low asphaltene and resin content, and another may be rich in resins but with a different asphaltene structure, size and morphology, interpolating their values to determine the potential for fouling can’t be done linearly. However, Irwin Wiehe with Soluble Solutions out of Gladstone, NJ, has published, with some authority, a procedure for testing individual crudes and predicting the precipitation potential of their blends.

Jim Johnson (Marathon Petroleum)

One of our refineries has experienced serious problems with oil and solids undercarry while processing bitumen crudes along with some asphalt destabilization due to mixing lighter paraffinic crudes with very heavy crudes. Increased fouling was observed in the pre-heat circuit during these episodes, however due to the effect on the wastewater treatment plant we were not able to assess the contribution of crude compatibility to the observed fouling. Efforts were concentrated on attacking the effect on the desalter operation. Marathon is a member of the Canadian Crude Quality Technical Association and through that group we understand that there are no correlations currently available that reliably predict fouling. The CCQTA is currently embarking on a project to better assess crude compatibility and one of the deliverables is to develop a fouling correlation.