Troubleshooting and Optimization Guide for Crude Oil Distillation Units

Question 1 - What is the basis for maintaining minimum wetting rates in vacuum column (whether based on vacuum charge or design condition?) What will happen if minimum wetting rates are not adhering to?

My Response -

The response for this question depends on a several parameters like the characteristics of the column internals as well as the mixture which will be separated.

Considering that we are dealing with a vacuum column, there is a great chance that the equipment is operating with packing internals which presents lower pressure drop than the perforated plates. There is a several correlations in the literature capable to give an estimative for the minimum wetting rate of a separation column which relies on the characteristics of the fluids like viscosity, density, and temperature and the characteristics of the packing like applied material, if is stacked or random, geometric form, atc.

An wetting rate below of the minimum will not conduct adequate mass and heat transfer rates, leading to poor performance of the separation column. In services with high temperature with hydrocarbons the low wetting rate can lead to premature coking deposition in the separation section leading a poor fractionating performance, high pressure drop and shorter operating lifecycle.

Question 2 - What is the impact in the product quality if circulating refluxes return temperatures are not maintaining at design temperatures? Is it wise to reduce heat recovery in pre heat network for maintaining design pump around return temp at the expense of pre-heat?

My Response -

The temperature profile of a separation column is a key parameter for an adequate fractionating, for this reason it's expected deleterious effects over the final quality of the products or side streams if the temperature profile is below or above the parameters recommend by design.

Reduce the heat recovery to maintain an adequate temperature profile in the distillation column can be interesting in some cases, bute reveals that you have a problem with your energy balance and recovery of the processing unit. Crude oil distillation units are the major energy consumer is a crude oil refinery and the energy is responsible for higher then 60 % of the operating costs of a crude oil refinery, furthermore the CO2 emissions is raised in an unefficient energy system, based on these data it's not recommended to deoptimize the energy balance of the processing unit even to improve the fractionating quality. In other words, if this is happened it's necessary a energy integration study (maybe through pinch technique) to identify bottlenecks and then propose alternatives to eliminate then.

Question 3 - We have a black sludge formation at the interphase of naphtha and water in OVHD accumulator. But all the OVHD paramters like pH, Iron  and Chloride are normal. The crude unit has a partail condensation ovhd system and the black sludge is observed in the second boot (Cold reflux boot). There is a CI dosing in the accumulator upstream. What could be the reason for this sludge?

My Response -

This is a relatively common condition in overhead systems of crude oil distillation units. The black sludge observed in the overhead vessel is probably pickering emulsion stabilized by iron particles which is accumulated in the interface between sour water and naphtha, despite the information that the pH, Iron and Chloride content is controlled in the overhead system it's possible that this system and the atmospheric tower can operate under corrosion situation in the past. When the emulsion is formed in the vessel, this residue cant be removed without the shutdown of the processing unit or through draining the overhead vessel totally which requires a special procedure aiming to minimize the safety risks as well as the damage to the pumps of the overhead drum.

Regarding the corrosion control in the overhead systems it's important to analyze that the corrosion control parameters is under an adequate range, especially the operating temperature of the overhead system. There are some correlations in the literature which relates the ammonia and chloride concentration in the sour water to determine salt deposition temperature in the top of the tower and this needs to be considered to define the operating temperature of the system.

Question 4 - Our desalter is facing a rag layer issue when we process cabinda crude. The brine turns black. It seems like our current emulsion breaker can not solve this problem. Is there any ideas or recommendations?

My Response -

According to the datasheet of the Cabinda crude oil, this is a light  and sweet crude oil which probably contains high amounts of paraffinic hydrocarbons. To realize an adequate analysis it's important to know if the refinery is processing only the Cabinda crude or under blending with heavier crudes, in this case we can saw chemical instability between the crudes leading to asphaltenes precipitation which stabilize emulsions reducing the separation efficiency in  the desalter vessels and provoke the change in the brine colour. In this case, it's possible to solve the problem by applying a crude stabiliser agent which is dosed independently of the emulsion breaker agent.

Another approach is analyze the incompatibility between the Cabinda crude with the another crude oils processed by the refinery and take anticipatory actions like reduce the processed flow rate in the crude oil distillation unit to ensure a higher residence time in the dessalters when processing a crude blending with high incompatibility potential, or avoid to process crude oils chemical incompatible with the Cabinda crude.

Question 5 - We have low PH (3 to 4) in the CDU overhead but in same time we have low chloride values ( 3 to 10 ) and already we injected high values of neutralizing amine and corrosion inhibiter. What is the reason that causes this drop in PH value?

My Response -

It's important analyze the content of chloride salts (MgCl2 and CaCl2) in the processed crude, these salts can suffer hydrolysis and generate hydrogen chloride (HCl) which can cause drastic reduction in the pH. According to the concentration of chloride salts in the crude oil it's possible to minimize this problem injection sodium hydroxide (NaOH) upstream of the dessalting vessels aiming to neutralize the hydrochlorides compounds.

Question 6 - We have a problem in our Desalter.  When we turn on the electric transformers, the electricity feeder trips off immediately several times. One of the transformers is damaged. The desalter contains only Crude Oil (Not mixed with water) What are the causes?

My Response -

Firstly, you need to check that the BSW of the Crude Oil is according to the design parameter of the desalting system as well as the interface level is adequate to avoid the risk of grounding the desalter leading to the trip of the power electric systems.

It's important to analyze if the desalting system suffered some instability event which caused internal damages to desalters like the electrodes breaking, for this it's necessary open the desalters and access the internals of the equipment. I suggest to start by the desalter that have a failed transformer. Furthermore, it's important to check the isolation of the electrode responsible for the electric alimentation of the desalter internals from the transformers, a failure in the electric insulation can cause the trip of the electric system. This can be caused by internal damages to desalting systems which can led to contact between shell of the desalter and the electrodes.

It's important to analyze if the desalting system suffered some instability event which caused internal damages to desalters like the electrodes breaking, for this it's necessary open the desalters and access the internals of the equipment. I suggest to start by the desalter that have a failed transformer.

Another important point is to check the isolators integrity of the transformers which are responsible to conduct the electricity to the desalters internals.

Question 7 - What's the philosophy of desalting system in Crude Distillation Unit, with respect to High Voltage & Demulsifier?

My Response -

The desalting of crude oil is one of the most important processes in a refinery to ensure the reliability and the operational availability of the refining hardware. During the crude oil extraction processes the petroleum drag sediments and water beyond inorganic salts (carbonates, calcium, chlorides, etc.) which are responsible for fouling heat exchangers leading to efficiency reduction, raise in energy consumption and reduce the operation campaign of the process units.

The presence of the dissolved salts in the crude oil is still responsible for catalysts deactivation in conversion process units (FCC and Hydrotreating), furthermore, these compounds can accumulate in the top of atmospheric crude distillation columns leading to corrosion and loss in separation efficiency. The desalting process involves the mixture of crude oil with water aiming at the dissolution of the salts considering the higher solubility of these compounds in the aqueous phase.

The crude oil is pumped from the storage tanks through the heating battery where it is heated and mixed with dilution water, the mixture is made by a mixing valve that promotes an intense mixture through pressure drop. The major part of water is under the free form and is removed by decantation due to the difference of density between the aqueous and oil phases, however, part of the water is emulsified in the oil phase and are required actions to broke the emulsion and allow the decantation of this water and the dissolved salts.

The emulsion breaking is carried out with the application of high-intensity electric field (close to 3,0 kV/cm) that provokes the polarization of water droplets, his agglutination and consequently his decantation. Desalting heavy crude oils is a greater challenge to refiners once the lower difference of density between the aqueous and oil phases makes the separation hard, beyond the higher content of compounds which stabilize the emulsions in heavier crudes (asphaltenes), in these cases the refiners operate under higher desalting temperatures and are used demulsifiers to facilitate the emulsion breaking.

Demulsifiers are normally a combination of surfactants with hydrophilic and hydrophobic bands in the same molecule which normally have their formulation protected by patents and his dosage needs to be accompanied by a specialist (chemical vendor). Regarding the electrical field, higher electrical intensity tends to improve the desalting efficiency considering the other variables fixed once improve the mixing effect and intensity of water droplets, collision with consequent coalescence and decantation, but it's necessary to consider that there is an optimal point for achieve this effect, once mixing in excess can promote collisions but without adequate conditions of coalescence.

It's important to consider the whole desalting process and all operating variables and not only the demulsifier and electrical field. The desalting temperature is a key parameter of the process once impact the viscosity of the crude and consequently the sedimentation velocity, it's important to realize an study including all operating variables like content of dilution water, pressure drop in the mixture valve, electrical field and desalting temperature. It's important to take into account the compatibility of the crude oils processed, which can lead to asphaltenes precipitation in some cases, especially in blends of high paraffinic crudes with heavier crudes.

Question 8 - We have a problem in one of the main towers (capacity = 150.000 bbl/day) in the company I'm working for. There is an inclination in the tower which may affect the efficiency of separation. So, what's the maximum allowable inclination so that no effect in the separation efficiency may occur?

Response - It's important to consider that distillation columns with industrial applications with high capacity like described in your question normally have an inclination grade. The fractionating efficiency will be affected according to the diameter of the distillation column, once higher diameters will lead to a most severe disequilibrium in the liquid holdup in the fractionating stages which will produce an accumulation of liquid in the inclined section of the fractionating stage with higher pressure drop, preferential flowing of the vapor phase and then a reduction in the fractionating efficiency. This phenomenon is called vapor-liquid channeling by specialized literature and a good reference about this topic is the book "Working Guide to Process Equipment" by Norman P. Lieberman and Elizabeth T. Lieberman (Fourth edition, 2014). Based on this reference, it's possible to conclude that is not rare to identify a 1 ft out of level in a distillation column with 14 ft diameter ( I believe that 3 % of inclination (based on the column diameter) would be acceptable) and this out of level can be compensated through raising the pressure drop of the liquid flowing through the orifice holes which demand the shutdown of the distillation processing unit. It's important to quote that any inclination will affect the fractionating performance due to the mechanism mentioned above, it's possible to find a tolerated point of performance reduction, but the inclination should be solved as soon as possible to return the processing unit to their optimized point. Despite this, I believe that the most important concern should be the stability of the structure considering all efforts and wind load to ensure the process safety requirements.

Question 9 - In our CDU we have stabilizer and splitter columns, stabilizer for separating LPG from Naphtha, after the annual maintenance, we have a problem in the boot of the overhead drum of stabilizer column we have a Black water and high iron number so what's the problem that makes this black water?

Response - The black sludge and water observed in the overhead vessel is probably pickering emulsion stabilized by iron particles which is accumulated in the interface between sour water and naphtha. It's important to check the pH, Iron and Chloride content in the overhead system, a lack of control of these parameters can lead to a severe corrosion process in this system as well as in the atmospheric tower. When the emulsion is formed in the vessel, this residue can’t be removed without the shutdown of the processing unit or through draining the overhead vessel totally which requires a special procedure aiming to minimize the safety risks as well as the damage to the pumps of the overhead drum. Regarding the corrosion control in the overhead systems it's important to analyze that the corrosion control parameters is under an adequate range, especially the operating temperature of the overhead system. There are some correlations in the literature which relates the ammonia and chloride concentration in the sour water to determine salt deposition temperature in the top of the tower and this needs to be considered to define the operating temperature of the system.

Question 10 - Our water maker is facing a problem while processing the crude oil mixture. The electrostatic plates are reversed because it is not possible to break the emulsion present.

Composition of the crude mixture: - Mars blend 58% - Basrah Medium 20% - Bouri 8% - Lokele 7% - Frade 2% - WTI 2%

Wash water Desalter 4.5%, brine desalter not present. - DeltaMix valve 0.35 kg/cm2. - Raw density 845 kg/m3 - watermaker inlet temperature 120°C - Water OUT desalter pH 8 - IN water sample not present - Head water pH 8

Response - Well, checking the datasheet of the crude oils involving the processing blend informed in the question it's possible to note that the feed stream to the desalting system is a mixture of light and sweet crudes with heavy crudes. The light crudes tends to present high paraffins concentration which can lead to chemical instability in mixtures with heavy crudes and then causing asphaltenes precipitation which stabilize emulsions reducing the separation efficiency in  the desalter vessels and provoke the change in the brine colour (the question do not provide information regard this). In this case, it's possible to solve the problem applying a crude stabiliser agent which is dosed independently of the emulsion breaker agent which needs to be applied in this case.

It's also important to check if there is no internal damage to desalting systems which can lead to contact between the shell of the desalter and the electrodes. It's important to analyze if the desalting system suffered some instability event which caused internal damages to desalters like the electrodes breaking, for this it's necessary to open the desalters and access the internals of the equipment.

There are very good references about this topic available in the technical literature and a good example is the article published on PTQ Magazine by Mr. Brian Benoit and Mr. Jeffrey Zurlo in 2014 regarding the impacts of North American shale oil processing in the refining chain.

Question 11 - In a crude processing unit, we have two stages of separation (gas, oil & water) and two stages of desalter. I need to know if we should heat the crude between two separators or before the first desalter? and why?

Response – Well, this is a very interesting question, an increase in the process temperature has two antagonic effects which need to be balanced aiming to maximize the separation and desalting efficiency. The crude oil heating will reduce the density and viscosity which will settling rates of the water droplets in the oil phase allowing a higher processing capacity of the water-oil separating system. On the other hand, the temperature increase will raise the conductivity of the crude oil, demanding a higher power consumption to promote an adequate desalting. Some studies point out that the adequate temperature for desalting is above 140 oC but it can be optimized according to the characteristics of processed crude oil once heavier crudes tend to present hard separation and desalting characteristics due to the lower density gap between water and crude oil. I believe that you can carry out an economic and energetic integration study aiming to heat the crude upstream the water-oil separating system to a intermediate temperature to improve the water-oil separation and   promote another heating to a higher temperature aiming to maximize the performance of desalting process considering the limitation effect over the conductivity of the crude oil. Based on the information in your question, I believe that the best location for the heat exchanger is between the separators aiming to maximize the performance of the water-oil separating system and avoid an eventual overload of the desalting system.

Question 12 - In our Vacuum Unit we have 2 Identical Trains, Train -1 constructed in 1984 and 2 constructed in 1989. Our Vacuum system is Wet Vacuum with 2 Pre- Condensers in parallel and 3 Stage Ejector system, each having 3 no. of Vacuum Ejectors, with Condenser, with the cooling medium being Sea Water and the Sea Water entry is to the Pre-Condensers and it's return going to the other 3 Stage condensers simultaneously and also provided with a By-Pass to increase the flow to those condensers if and when required. Actually in the middle of May 2023, we experienced sudden break in vacuum in only Train - 1 and this phenomenon was continuing on & off, with this phenomenon occurring every 7-10 days and would resolve by switching the Ejectors and /or hammering the Pre-Condensers leg lines, till our Scheduled Biennial Turnaround in October 2023. And after Start-up of the unit on October 31, 2023, till December 30/31 2023 for about a couple of months the unit was running very smoothly, before the vacuum issue started cropping up again and this time the frequency of the drop/break in Vacuum was about 10-15 days, continuing upto March 2024. But, our Operation personnel thought this is due to the Pre-condensers leg line getting blocked due to Metal rust & corrosion and instructed to externally Hammer those leg lines twice in every shift from February upto Middle of March 2024., and by that that issue also resolved. And for a period of more than 6 months upto 2024 October first week, we did not face any issue except little increase in Vacuum twice or thrice when sea water flow was getting dropped, or more lighter in feed from Tankfarm. Also, as compared to the other Train, we were having 2 ejectors more online i.e.., 6 Ejectors with 2 each in all the 3 stages. But again we faced sudden break in Vacuum itself on October 5th at around 04:00 hrs, even with unit running on extremely low Throughput. So, I kindly request you to help with this issue. Note:- As per my observation, I have noticed 2 separate phenomenon happening with none being related to each other or happening together even once. 1. Pre-Condensers leg line temperatures getting low 2. 3rd Stage Condenser outlet temperature getting high which in turn increases the pressure of the non-condensible from the Hotwell increasing the back-pressure of the system irrespective of burning in our Heater or flaring it.

Response - This is a very interesting practice case study. The use of sea water for the cooling system put under suspicion the fouling formation in the cooling water system. Despite the issues being observed only in one of the two crude distillation trains, it's possible to occur preferential deposition according to the alignment arrangement of the cooling water tubulations that feed the heat exchangers. Under this context it's important to check through external ultrasonic meters, if the cooling water is adequately distributed to the heat exchangers. Another key question to be verified is the quality of the steam applied in the ejectors. Again, according to the supply tubulation arrangement the steam can be fed under a saturated condition to the ejectors, leading to subsonic flow in the ejectors and consequently poor performance. Another question which can be considered is the feed quality to the crude oil distillation train. Some paraffinic crudes can suffer thermal cracking in the fired heaters and overload the top of the vacuum tower leading to high operating pressure, this can occur in some time intervals considering the changes in the crude oil slate processed by the refinery. Another question is related with the performance and gasoil and vacuum residue yields in the problematic distillation train during the vacuum break. If there is a corresponding change in the yields (lower gas oil production and higher vacuum residue production), the pressure transmitter of the vacuum tower is calibrated? The intermittent characteristic of the phenomena is intriguing, but a possibility is the occurence of self-sealing failures in the heat exchangers tubes, especially considering the use of sea water as cooling water (high fouling rates). This possibility is reinforced by the information of material deposition in the barometric leg lines. Following through a root cause failures tree, it's important to verify the performance of side withdrawal pumps. Poor performance of these machines can lead to high pressure drop in the fractionating sections and impact the tower pressure. The same verification it's necessary to sour water draining pumps of the top vessel. How is the temperature of the cooling water system? Is it possible to identify the coincidence of vacuum broken events with the moments where the cooling water temperature is high? As previously quoted, the cooling water circulation rate to the problematic train is in compliance with the design? The performance of the atmospheric tower is another verification point, its occurring light degradation (like heavy diesel) to the atmospheric residue overloading the condensation system of the vacuum tower due to the dragging of light compounds, this can occur according to the characteristics of the processed crude slate. This effect can also occur due to a failure in the pre-heating exchanger battery of the crude oil distillation unit, mainly those that exchange heat between vacuum gas oil with crude oil. It's also important to verify the possibility of air entry in the cooling system and the vacuum system, I believe that this verification was already carried out, but it's an important verification in a root cause analysis. Considering the case description, the operating issue seems to be related to poor performance of the condensation system of the vacuum tower top section. A good strategy is to make a frequent flushing and backwash of the cooling water supply alignments to the condensers aiming to help to remove fouling under operation. If there are no necessary alignments to promote this operation, it can be a good change to be installed in both crude oil distillation trains in the next maintenance shutdown.

Question 13 - How can I calculate the salt point in an atmospheric crude distillation tower to avoid the precipitation of salts, what literature recommends.

Response - The salt point of crude oil distillation units it's a critical variable and is strictly related to the salt concentration in the control point. Higher salt concentrations (NH4Cl and NH4HS) will lead to lower salt point, by this reason, the efficiency of the crude oil desalting step is critical to controlling the corrosion process in the crude oil distillation unit and downstream processing units like FCC and Delayed Coking. A good reference about this topic is the article published in the Q3 2012 edition of PTQ Magazine by Mr. Brandon Payne which details the strategy to avoid deposition of salts keeping the operating temperature above the salt point, avoiding under deposit corrosion in top condensers and process lines.

Question 14 - In our vacuum distillation unit, in HVGO section temperature difference between vapors entering into the bed from below and temperature in the bed has come down to less than 10 degc from almost 50 degc after unit emergency shutdown. This has lead to high temperature across bed 1-3. What could be possible reason for this and what are potential impact of this column yield pattern? And what are the remedial measures for controlling this without going for any shutdown?

Response - Considering the information in the question, it's possible that after the emergency shutdown, the bottom liquid reached the feed nozzle which expanded with feed energy and produced damages in the fractionation beds (sudden expansion). A good way to verify this condition is monitoring the pressure drop in the fractionating bed. If the pressure drop is raised, it's possible the coke formation in the bed. Otherwise, if is observed lower pressure drop in fractionating bed after the emergency shutdown, probably occurred preferential channelling or the total destruction of the bed. A good way to confirm this is to open the suction filters of the side stream pumps to identify the presence of pieces of internals of the fractionating bed. Unfortunately, in this case the best solution is shutdown the vacuum distillation column and correct the damages in the affected beds once operate under this conditions will lead to a poor performance of the processing unit impacting the downstream units like hydrotreaters and residue upgrading units and may lead to the worsening of the internal damages of the vacuum tower which can cause another emergency shutdown with even more serious consequences.

Dr. Marcio Wagner da Silva is Process Engineering Manager at a Crude Oil Refinery based in São José dos Campos, Brazil. He earned a bachelor’s in chemical engineering from the University of Maringa (UEM), Brazil and a PhD. in Chemical Engineering from the University of Campinas (UNICAMP), Brazil. He has extensive experience in research, design and construction in the oil and gas industry, including developing and coordinating projects for operational improvements and debottlenecking to bottom barrel units, moreover Dr. Marcio Wagner earned an MBA in Project Management from the Federal University of Rio de Janeiro (UFRJ), and in Digital Transformation at Pontifical Catholic University of Rio Grande do Sul (PUC/RS), in Production and Operations Management at University of Sao Paulo (USP), and is certified in Business from Getulio Vargas Foundation (FGV).