Question 62: What are causes of foaming in crude pre-flash drums and towers, and what options are available to mitigate foaming?
SHELTON (KBC Advanced Technologies, Inc.)
Surfactants cause foaming. Mike will discuss surfactants and amines that should not be in the crude. Sodium naphthenate is a common surfactant produced by the reaction of caustic injected at the desalter effluent and naphthenic hydrocarbons.
A simple solution is to move the injection downstream of the pre-flash or pre-fractionator to the bottom pumps. If the injection point is at the desalter effluent, solids and corrosion products can cause foaming.
Improving desalter solids removal will mitigate foaming. Precipitated asphaltenes that frequently occur with bitumens and asphaltic crudes can also cause foaming, so we would evaluate crude compatibility in that case.
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The question includes pre-flash drums and towers, which I assume is a pre-fractionator. These applications are quite different in design and operation. In our pre-fractionator designs, we consider C factors, internals, tray design, and tower loadings.
We have used pre-flash drums in our latest grassroots designs because the hot trains have been so efficient that crude heater inlet temperatures are 600ºF to 610ºF. A flash drum removes water and requires lower pressure to suppress vaporization at the end of the hot train. The flash drum design avoids elevated pressures in the hot train and 900-pound flanges. Obviously, we specify vertical versus horizontal. We consider height versus diameter and liquid superficial velocity versus vapor velocity to optimize the ratio. We also consider disengaging height and the feed distributor inlet design. Of course, temperature and pressure have a major impact.
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The pre-flash drum performs two functions: flashing water and suppressing vaporization. Many pre-flash drums are operated to remove light hydrocarbons. However, water causes vaporization, and operating pressure and temperature determine the vapor rate and composition. It is important to model the optimum pressure. Operate at the pressure required to remove water and not generate excessive hydrocarbon vapor load, which can result in carryover of bottoms.
In our designs, flashed vapors are sent to the flash zone. Designs where the flashed vapors are introduced in higher sections of the column can create problems. For any design, in the event of a foamover, temporarily increase pressure. With the flash drum, increase pressure until there is no vaporization. That will stop the foamover. It is important to have a pressure controller on that vapor line to the flash drum.
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Pre-fractionator foaming is less likely because it is a refluxed column with an overhead product. The trays mitigate foaming, and the liquid loading should tend to knock down the foam. Again, in the event of a foamover, you could temporarily increase pressure. This may not be obvious, but we try to design for higher temperatures to reduce surface tension, which also mitigates foaming. In a new design, the pre-flash drum operating temperature is determined by the location in the hot train. Finally, improving desalter operation will mitigate foaming in the downstream columns.
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BASHAM (Marathon Petroleum Corporation)
I want to reinforce some of Al’s points here. As he already mentioned, pre-flash tower or vessel foaming is a function of crude type salt or water carryover, temperature, and caustic addition. You are always going to have foaming occurring in a pre-flash drum or tower. The key here is to manage the foam and keep it in the tower. You must have sufficient vessel height and diameter necessary to disengage the foam. As Al also mentioned, the liquid superficial velocity is the key design parameter. It is important to keep in mind that the smaller the diameter of the vessel, the larger the foam height; so in narrow vessels, the liquid superficial velocity will need to be low in order to keep the foam height low. It is possible to add silicone-based antifoam to the pre-flash drum or tower, but consideration needs to be given to the downstream, gasoline, and distillate hydrotreater reactor catalyst.
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DION (GE Water & Process Technologies)
Al and Kevin covered operational and mechanical issues regarding foam. Part of the question asked about the causes of foaming. There are surfactants in crude oil. Surfactants can be any organic molecule that has an atom that is not carbon or hydrogen, such as organic acids, organic amines, mercaptans, and other molecules with a polar group associated with them.
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RUSSELL STRONG (Champion Technologies)
I have heard several comments that silicone antifoams in crude are problematic. There have been recent events offshore in the Gulf where so much antifoam was being used upstream that it was actually poisoning hydrotreater catalyst in the refinery from the upstream application. Other causes of silicone contamination can come from the crude while trying to control foaming in a flash drum or in a crude tower. To control those, silicone antifoams are sometimes used with occasional success. Several years ago, at a refinery down in the Houston, Texas area, I encountered severe foaming in a crude tower that would not go away. Standard silicone antifoams did nothing to solve the problem, but a fluorosilicone antifoam worked well. It was far more efficient and actually worked where the polysiloxane was deficient. It also offered less risk of downstream silicon contamination. So, keep this in mind as an option if you have crude unit foaming.
STEVEN FISCHER (Delek Refining)
At a previous refinery, we reintroduced the vapors to the flash zone with the result being quench to the flash drum that resulted in poor cutpoints. When we introduced the flash vapors from the flash drum to the flash zone, we saw that that the flash drum had actually acted like a quench, which could result in a poor cutpoint at the bottom of the crude tower.
SHELTON (KBC Advanced Technologies, Inc.)
Simulations do not indicate flash zone quenching if, as previously mentioned, the flash drum operating pressure is optimized to flash-only water. We have evaluated the flow schemes in models with the two streams mixed outside of the column and combined in the flash zone, but we get the same overflash.
STEVEN FISCHER (Delek Refining)
That was our assumption when we designed it that way, but our performance did not show that result. Our performance improved when we introduced it higher up.
ANDREW SLOLEY (CH2MHILL)
Addressing that last comment, I think what you are seeing there, when you see the poor performance, is the mixing of transfer line liquid with the vapor coming in, which is an issue with the equipment and not having the vapor segregated from the transfer line.
SHELTON (KBC Advanced Technologies, Inc.)
Our designs do have a separate flash drum vapor nozzle in the flash zone. It is important to have a pressure controller on the flashed vapor line, so the drum is not riding on the lower flash zone pressure. I do not know if that is your case or not. Do you have pressure control on the pre-flash drum? If not, a large pressure drop will produce a very high vapor rate, and then hydrocarbons will be flashed. In that case, there could be some quenching. We try to just flash the water and no hydrocarbons. When you think about it, if there were substantial light hydrocarbons, the desalter would overpressure. So, there are not a lot of light hydrocarbons in the crude because the only difference in the flash drum versus desalter operation is the desalter pressure, which is also low compared to the elevated hot train pressure.
STEVEN FISCHER (Delek Refining) We had some light hydrocarbons going overhead in addition to water.
SHELTON (KBC Advanced Technologies, Inc.)
There may also be recycle streams quenching the flash zone.
ROBERTSON (AFPM) Al, could you comment on the superficial velocity?
SHELTON (KBC Advanced Technologies, Inc.)
Liquid superficial velocity is a function of the vessel height versus diameter and design of the drum, which differs for vertical versus horizontal vessels. It is specific to each design and not a variable for an existing drum. Pressure is the important operating variable. If there is no pressure controller on the vapor from the flash drum, then that deficiency can be remedied online because there is usually a block valve at the column. In that case, the back pressure controller can be installed online.
VILAS LONAKADI (Foster Wheeler USA Corporation)
Is there any experience with the use of any internals in the pre-flash drums?
SHELTON (KBC Advanced Technologies, Inc.)
There are several types of feed distributors, including vortex tube clusters (VTC) and tangential nozzles. There are many effective feed distributors that will improve disengaging.
VILAS LONAKADI (Foster Wheeler USA Corporation)
Not about just the feed entry, but in the drum itself.
SHELTON (KBC Advanced Technologies, Inc.)
We do not recommend demisters on vapor outlets, and flash drums do not typically have any internals.
VILAS LONAKADI (Foster Wheeler USA Corporation)
Some vendors offer vortex tube clusters. I want to know if anyone has used them.
SHELTON (KBC Advanced Technologies, Inc.)
Yes, we mentioned vortex tube clusters (VTC), which have been used successfully in drums that operate at high velocities. We have also seen VTC distributors used for revamps to increase throughput at higher drum velocities. They have been very effective.
VILAS LONAKADI (Foster Wheeler USA Corporation)
Did it reduce foaming?
SHELTON (KBC Advanced Technologies, Inc.) Yes, VTC distributors have been used to solve foaming problems for existing vessels.
SHELTON (KBC Advanced Technologies, Inc.)
Foaming in flash drums and pre-fractionators is often caused by crude contaminants. Inorganic fines (sand, corrosion products, etc.), precipitated asphaltenes and sodium naphthenates formed from the reaction of caustic and naphthenic hydrocarbons have been identified as precursors. If caustic is injected at the desalter effluent, a simple solution is to move the caustic injection downstream of the flash drum to the pre-flash bottoms or hot train pumps.
The immediate solution to a foaming problem is to increase pressure to decrease vaporization. In a prefractionator, in addition to increasing pressure, higher reflux or wash rates will tend to knock down the foam front. Increasing temperature will reduce surface tension and mitigate foaming. Long term solutions include improving desalter operation (particularly solids removal) and improved selection of treating chemicals for the preheat train and desalters.
The design and operation of pre-flash drums and refluxed pre-fractionator columns are different. Vessel design (vertical versus horizontal) and disengaging height affect foaming. KBC design guidelines for pre-flash drums include height versus diameter, liquid superficial velocity versus vapor velocity, disengaging parameters, feed distributors and pressure. For any design, increasing operating pressure will reduce foaming.
Pre-flash drums are located in the hot crude train downstream of the desalters to flash water and suppress vaporization at the end of the hot train. Flash drum vapors on pressure control are routed to the crude column flash zone. Flash drum pressure sets the vapor rate and composition. Simulations show that water causes vaporization in heat exchanger services at the end of the hot train, not light hydrocarbons. Very light hydrocarbons would overpressure the desalters, if present. Simulations will determine the flash drum pressure required to remove dissolved water from the desalter effluent. The flash drum should be operated at the pressure required to remove water and no lower to reduce carryover of flashed crude. In the event of a foamover, the foam can be broken by temporarily increasing drum pressure to reduce vaporization. Good desalter operation with no water carryover to the flash drum will minimize foaming. Desalters should be operated with less than 0.5% BS&W in the effluent. Prefractionators are typically refluxed distillation columns with an overhead product such as light naphtha and may also have sidecuts. Foaming is less prevalent in a refluxed column. In the event of a foamover the foam front can be broken by first increasing reflux rate and if necessary, temporarily increasing overhead pressure.
BASHAM (Marathon Petroleum Corporation)
Foaming is always present in pre-flash drums and towers. It can be a function of several parameters including crude type, desalter performance (water carryover), drum or tower temperature, and caustic addition. Depending on its feed location in the atmospheric crude tower, pre-flash drum vapor can cause black distillate, black atmospheric gas oil, and increased atmospheric tower bottoms if the foam contains flashed crude. Similarly, in pre-flash towers foam with entrained flashed crude can cause black naphtha. The key to managing foam is keeping it in the pre-flash drum or tower.
A properly designed vessel (drum or tower) will allow sufficient height to disengage the vapor from the liquid. The most important design parameter is the superficial velocity of the flashed crude. The foam height is directly proportional to the liquid superficial velocity. The liquid superficial velocity must be sufficiently low enough to keep the foam height below the vapor outlet of the drum or tower. The foam height is also a function of the tower or drum diameter (cross-sectional area.): the smaller the diameter, the larger the foam height. This means that foaming will be a bigger concern in narrow vessels, so the liquid superficial velocity will need to be low in order to keep the foam height low.
It is possible to add silicone-based antifoam to the pre-flash drum or tower, but consideration must be given to downstream gasoline and distillate hydrotreater catalyst silicon loading.
LEE (BP Products North America)
A potential cause is water carryover out of the desalter that is vaporized in the flash drum. If there is water carryover and high shear stresses associated with a letdown valve with high pressure drop, this situation can generate small droplets which would contribute to foam generation. Foaming is often associated with high vapor rates, so a crude with a significant amount of vaporization at the flash drum conditions may have high potential for foaming. Antifoam use, and additional enhanced separations hardware, such as vortex cluster internals, can be considered.
DION (GE Water & Process Technologies)
Any organic molecules with atoms other than hydrogen or carbon are potential surfactants. Examples of such molecules are; alkyl phenols, organic amines, organic acids, and mercaptans. Foaming can be mitigated through the use of a defoamer or antifoam chemistry.Defoamers function by reducing the interfacial surface tension and viscosity. Antifoams function by modifying the interfacial surface elasticity. Most products commercially available from specialty chemical suppliers, such as GE Water & Process Technologies, function in both manners due to the behavior of their surfactant structure. The most effective defoamers in hydrocarbon environments are typically silicone based. If silicone poisoning is a concern, non-silicone-based defoamers, such as glycolic materials, are available.
BRUCE WRIGHT (Baker Hughes) Pre-flash tower foaming is most often caused by high solids loading coupled with high gas flows. Foam control with Baker Hughes Si-based antifoams has proven to be effective.
DENNIS HAYNES (Nalco Energy Services)
Crude viscosity, hydrocarbon polarity, solids content, caustic use, and vapor disengaging in flash sections and tower bottoms are discussed as causes for foaming. Antifoams have been around for quite a while that may be utilized in this area; however, the first step in corrective action is to determine that it is actually a stabilized foam layer and not tower flooding. There are instances where pre-flash towers are operated above design or have had some internal damage that causes flooding which is mistaken for foaming.
ANDREW SLOLEY (CH2M HILL)
One major cause of foam formation in these units is surface-active agents stabilizing the foam film on the liquid-vapor interface. Some of these agents are inherent components of specific crudes. However, many of them have been added to crude as well stimulation, drag-reducing, anticorrosion, or hydrogen sulfide scavenging additives. With continued production of heavier crudes and more aggressive well stimulation operations, foaming problems should be expected to get worse.
Solutions to foam formation include; antifoaming additives; foam-breaking inertial separators; and modifying operating conditions.
Silicone-based antifoaming additives can be effectively used. Their downside is that they vaporize and end up in the lighter products, particularly naphtha. This puts the antifoam into the downstream naphtha hydrotreater feed. Few hydrotreaters can tolerate this. Antifoams are rarely used.
Foam-breaking inertial separators have been used in a number of plants. They are derived from equipment design for oil production operations. In the oil fields they are proven technology. Experience in refineries, while limited, has been mostly successful. For certain plants and feeds they may be a choice worth serious consideration.
The most common method of avoiding foam-created problems has been to modify the plant operating conditions. This may include changes in feed rate, pressure, or temperature. Feed rate reduction increases effective residence time in equipment. It also reduces total vapor rate formation. While expensive, some plants are constrained to do this. Increasing pressure reduces vapor formation and increases vapor density. Both reduce the volume of vapor. Increasing operating pressure reduces foam problems. Temperature changes are more complex. Higher temperatures (at the same pressure) create more vapor volume, they also decrease liquid viscosity. These are competing changes. More vapor volume increases foam make. Lower viscosity speeds foam decay. In a plant with a foam problem, small temperature changes, in either direction, may help solve the problem. Experience has shown an operating temperature change as little as 10°F may change the vapor volume, or the viscosity, enough allow the flash drum or tower work, or be catastrophically worse.
Proper pre-flash installation includes balancing many factors including equipment size, expected operating conditions, and how to connect the pre-flash system to the existing unit. Revamps to add, or improve, pre-flash drums or towers need to be carefully evaluated.
Question 43: What are your best practices when shipping ecat, fines, feed, and slurry to suppliers for testing? Please also comment on some best practices for sampling equilibrium catalyst.
TODD HOCHHEISER (Johnson Matthey)
When shipping ecat or fines, an appropriate sample container should be used. Catalyst suppliers will typically provide refiners with sample containers if needed. Catalyst shipping containers should be made of plastic or metal. Glass containers are not recommended due to potential breakage but can be used with appropriate packaging. A screw top lid is preferred over a snap on lid sometimes found on metal containers. Prying opening a snap on lid can result in personnel dust exposure. Catalyst samples should not be shipped in plastic sandwich bags or other containers not designed for catalyst service.
JM has found that metal sample containers with a screw top lid are best when shipping low vapor pressure hydrocarbon samples. A best practice is to place the sample container in a plastic bag containing adsorbent pads. These pads should minimize the chance of hydrocarbons leaking out of the box if the sample container leaks.
For hazardous catalyst and hydrocarbon samples, a GHS complaint label must be placed on the sample container. The safety data sheet must also be included with the shipment. Most catalyst suppliers prefer for a safety data sheet to be included even if the sample isn’t considered hazardous. Other regulations and requirements may apply especially for sample shipments between countries.
Common sense precautions are also recommended. Some examples are shipping only the quantity of sample that is required, packaging in strong boxes, and using labels with high quality adhesive. Our lab has received sample boxes containing multiple ecat samples and multiple labels that are no longer attached to the sample containers. Clearly identifying the date of the ecat samples is critical for unit monitoring.
For any sample that is shipped, it is recommended that a company representative certified under DOT or applicable regulations be involved in the packaging and shipping process. Carriers also have specific requirements for shipping hazardous material.
KEN BRYDEN AND LUIS BOUGRAT (W. R. Grace & Co.)
For all samples, it is important to provide a safety data sheet (SDS) when shipping the sample and to follow appropriate Department of Transportation (DOT) and International Air Transport Association (IATA) rules when packaging and sending the sample. Samples should not be sent by U.S. Mail or any service that transfers to U.S. Mail. Based on our experience receiving and testing thousands of customers Ecat and hydrocarbon samples each year, Grace has the following suggestions on best shipping practices.
Ecat and Fines Samples
For Equilibrium catalyst (Ecat) and fines samples, we have found that for routine testing a 500 mL screw top plastic container is an ideal size. Grace provides complimentary Ecat Express containers for this purpose. Screw-top metal containers are another packaging option for Ecat. Glass containers are unsuitable for Ecat since they tend to break in shipment. Containers with paint can lids are unsuitable since the lids tend to come off during shipment and spill catalyst. Bags are also unsuitable containers since they tend to leak. For any container, do not put any tag, string or wire between the cap and the container lid since they will compromise the seal and cause leaking. For large quantities of Ecat, we have found that five-gallon (or 20 liter) plastic screw top buckets are good containers.
For Ecat and fines samples, proper labeling is important in making sure the desired tests are done and reported. At a minimum, samples should be labeled with the following information:
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Refinery or company name.
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Refinery location. For example, city and state.
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Unit Name: Especially important if there is more than one FCC unit at the refinery location.
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Sample Date: The date that the sample was collected.
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Sample ID: (Optional) A sample number or name, for your reference.
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Sample Type: for example, Ecat, fines, purchased Ecat, non-routine, etc.
As part of the complimentary Ecat Express kits, Grace provides container labels that already have the refinery name and unit written and barcoded on the label.
Feed and Oil Slurry Samples
For routine analytical testing to measure the properties of feed or oil slurry samples, a 16-ounce (or 500 mL) sample size is preferred. In shipping hazardous materials, proper packaging and labeling is essential to ensure compliance with the appropriate regulations. This will prevent fines from the carrier and delays in your shipment. In addition, poorly packaged samples can leak, which results in the sample being compromised and thus unsuitable for analysis. There are many good packaging systems available from suppliers that may be chosen to meet the packaging requirements of IATA and CFR49. Which system to use has to be determined by each individual shipper for their samples. The most common system that we see customers use is a 4GV shipper where the hydrocarbon sample is packaged in a metal can, which is then placed inside a plastic bag with an absorbent sleeve. The entire assembly is then placed in a certified cardboard box. It is important to make sure that the lid is screwed on securely. We occasionally receive leaking samples where the container lid vibrated loose in shipment. In preparing containers, make sure tags and wires from labels are not in the thread area of a cap. A string or wire from a label tag put into the sample container, with the cap sealed over it, will act as a wick. This will always cause leaking. Container types that we have noted problems within the past are a) paint cans- the lids often pop off during shipment, and b) glass bottles- they have a tendency to break during shipment.
As with Ecat samples, labeling of feed and slurry oil samples is important. The container should be labeled with the material identity and the appropriate Global Harmonized System (GHS) hazard symbols. Additionally, the sample should be labeled with the following information:
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Refinery or company name
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Refinery location: for example, city and state
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Unit Name: especially important if there is more than one FCC unit at the location
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Sample Date: the date that the sample was collected
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Sample ID: (Optional) a sample number or name, for your reference
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Sample Type: for example, feed, oil slurry, etc.
Process Ecat Sampling
Routine and representative sampling of the circulating Ecat inventory represents a critical part of FCC performance monitoring and optimization. Samples of the circulating inventory should be collected from a fluidized and accessible section of the unit to enable representative sampling of the catalyst system. From a safety standpoint, regenerated catalyst represents an inherently safer sampling source than spent catalyst due to the lack of entrained hydrocarbons and the lower coke concentration along the surface of the catalyst. However, the process temperatures associated with regenerated catalyst are significantly higher than those of spent catalyst and should be mitigated accordingly.
The regenerated catalyst standpipe represents the most common sampling location due to the continuous catalyst flow and accessibility associated with this standpipe. Although the flowing catalyst is well fluidized within this type of standpipe, it is important to properly fluidize the sampling manifold as well when obtaining a catalyst sample. Plant or instrument air are the most common fluidization media for regenerated catalyst sampling stations, which can also be equipped with steam connections to serve as blast points for line plugging troubleshooting. An air or steam purge into the process should be maintained at all times across the standpipe sampling nozzle to prevent catalyst ingress and nozzle plugging. The fluidization medium should correspond to a reliably dry source to prevent potential catalyst agglomeration issues throughout long-term operation. The sampling outlet nozzle should be purged prior to lining up the sampling line to the process to ensure that the manifold is clear of fouling and to confirm that the sample fluidization medium is available and properly dry. The key considerations and best practices for the Ecat sampling process, among others, are as follow:
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Field personnel should be equipped with all necessary PPE prior to collecting the Ecat sample. Contact your catalyst vendor if any additional feedback or specific PPE guidelines are required.
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Any potential impacts on instrument readings or safety interlocks by the Ecat sampling process should be thoroughly identified. Ecat sampling activities should be communicated to the board operators prior to starting the sampling process to help ensure that instrument and safety interlock functions are not compromised while sampling.
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Ensure that the sampling container or recipient is adequately rated for the normal process temperatures associated with the circulating Ecat inventory. The sample containers used for shipping are not typically rated for these elevated temperatures. Metallic containers are typically required to accommodate Ecat sampling.
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The sampling valve and the sampling outlet nozzle configuration should, ideally, enable sample collection without exposing field personnel to catalyst and entrained flue gas at the high process temperatures. A remote point where the operator can operate a HIC (Hand Indicate Controller) valve to take the sample in line of sight of the sample station but a safe distance away is practiced by several refiners. The sampling recipient can be attached to a long metallic or high-temperature-resistant handle to help mitigate personnel exposure to high temperatures throughout the sampling procedure.
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Sufficient sample flow should be established to enable collection of a representative Ecat sample. Insufficient purging of the sampling manifold with the flowing Ecat can lead to non-representative or compromised results due to the presence of stagnant Ecat from previous sampling rounds, or other similar contamination sources. Collection of a slip stream during continuous Ecat flow through the sampling line tends to yield a more representative sample than collecting a vial sample from a drum or (large container) of Ecat sample inventory.
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Excessive superficial velocities through the sampling manifold should be prevented while sampling to help mitigate potential erosion and attrition issues. Excessive catalyst attrition through the sampling line can lead to false PSD profiles for the circulating catalyst inventory that can prompt unnecessary troubleshooting activities. Adequate velocities through the sampling nozzle also help reduce turbulence and dust as the flowing Ecat reaches the sampling container, thus preserving as much of the fines content present in the circulating inventory as possible.
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A pint of Ecat sample is usually sufficient volume to accommodate routine lab testing for process monitoring purposes. Excess Ecat sampling volume should be properly handled and discarded via spent catalyst drums or disposal lines routed to the spent catalyst hopper, if available.
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Ecat samples should be allowed to properly cool before filling the corresponding shipping containers. Windy or wet environments should be avoided for the cooling period to avoid altering the physical properties of the Ecat sample.
The guidelines and best practices previously referenced should be followed when shipping the Ecat sample containers. Board operators, unit engineers and other supporting staff for the FCC complex should visually inspect Ecat samples before the sample is shipped to the catalyst vendor. Visual inspection can help qualitatively gauge the health of the circulating catalyst inventory – especially with respect to coke on regenerated catalyst (CRC), drastic PSD shifts, and/or potential Fe poisoning contamination – well before the corresponding lab results become available.