Troubleshooting Manual for Crude Oil Distillation Units

This short publication summarizes some of my responses related to some questions about practical and theoretical questions related to operating issues of crude oil distillation processing units.

The responses published here are based on my knowledge and experience and don’t have the pretention to be the unique and right argument in all the cases, in all business the diversity of point of view is welcome and this is not different in the downstream industry.

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 - For a desalter system with low performance, we made an RCA that revealed multiple issues to the desalter hardware, including that the equipment is undersized and electro-coalescne not happening, while grid is still ON. Could anybody advise equipment retrofitters to shift the existing desalter almost electrodynamic type to low velocity type ?

My Response -

Well, we have two types of electrostatic treaters which are known as low velocity type and high velocity type. The low velocity type is normally applied in platforms or in upstream assets aiming to promote the water separation from the produced crude oil, in this system the emulsion is fed in the top of the separation vessel along the length of the vessel and the emulsion is fed in the aqueous phase which due to the density gap presents an upward flow in direction to the electrodes which are normally positioned above of the centre line of the separating vessel. In these dessalters the crude oil is dispersed in the aqueous phase and suffers a kind of wash which remove salts and solid particles present in the oleous phase along of this upward flow in direction of the electrodes there is a small coalescence effect due to the low intensity electric field between the lower electrode and the water-oil interface. When the emulsion reaches the high intensity electric field occurs the remaining coalescence. These dessalters can suffer with poor performance along their lifecycle due to the raise in the water concentration in the crude oil along the time due to the depletion of the crude oil well and according to the strategy applied to improve the flowrate production of the well, and this can be one of the sources of the issue mentioned in the question.

In this case, the revamp of the desalting system for a high velocity desalter can be thought as a solution. In these dessalters, the emulsion is fed directly between the electrodes.

The limitation here is precisely the amount of water in the emulsion, for water concentration above 10 % the protection system can trip the desalting system due to the high electric current level and this limitation can be prohibitive to upstream assets due to the raise of water concentration in the crude oil along the time as explained above. For this reason, it's important to consider the service that you are planned to your desalting system, if the system is operating in an upstream asset, the revamp for a high velocity desalter can be a bad idea considering the trend of elevation in the water content in the crude oil along the time.

My suggestion would be to analyze the installation of a third electrode grid as well as consider the installation of a mud wash system in order to remove the sediments in the separating vessels bottom which can significantly reduce the residence time of the emulsion in the dessalter and lead to a poor performance of the whole system.

Question 9 - How can I know the water mole fraction in the overhead stream in the CDU? I need it to know the optimum temperature of the top refluxes.

My Response -

I believe that you can carry out a mass balance using the stripping steam flow rate and eventually another water injection to the atmospheric column to determine the water concentration in the overhead system indirectly, if you have a safe and adequate sample point you can make a chemical analysis to determine it. But it's important considering that the corrosion in the overhead system of the atmospheric tower is strictly related with the performance of the desalting system.

According to the characteristics of the processed crude, the performance of desalters needs to be optimized, especially considering the concentration of magnesium and calcium chloride salts which tends to suffer hydrolysis and generate HCl which will concentrates in the overhead system of the atmospheric column, this is a special concern to refiners processing heavy crudes, slop blendend with crude oil, and opportunity crudes. The adequate reflux temperature is fundamental to control the corrosion and fouling in the top plates of the atmospheric column which is caused by low reflux temperature and presence of NH3, HCl and amines which are absorbed by the water which vaporizes along the downward of the reflux leading to the salt fouling in the top plates which causes severe pressure drop leading to poor fractionating performance and can limit the the operating cycle of the processing unit.?

Some refiners adopt the amine injection in the overhead systems to control the salts precipitation, especially H2S scavengers but the side effect here is the trend of deposition of corrosive salts under low temperature.

The literature highlights that the design of overhead systems needs to consider the probability of the corrosion and fouling in the top section of the atmospheric column, if the probability is high a overhead system with two separating vessels needs to be considered once to avoid low reflux temperature which can cause water condensation inside the column. A very good reference about this topic is the article published by Mr. Tony Barletta and Mr. Steve White in the Q3 2007 issue of PTQ Magazine.

Question 10 - What are types of Corrosion Inhibitor (Filmer) and neutralizing amine used in crude distillation units. What is the philosophy of their work and the concentration of injection?

My Response -

According to the characteristics of the processed crude, the performance of desalters needs to be optimized, especially considering the concentration of magnesium and calcium chloride salts which tends to suffer hydrolysis and generate HCl which will concentrates in the overhead system of the atmospheric column, this is a special concern to refiners processing heavy crudes, slop blended with crude oil, and opportunity crudes.

Some refiners adopt an online injection of corrosion inhibitor in the overhead systems to control the salts precipitation. Normally, the corrosion inhibitor applied is a kind of filmic amine like alkylene polyamines (ethylene diamine - EDA, for example) which produces a protective film inside of the critical areas of the atmospheric column and neutralize the acid affect of decomposed salts from the crude oil.

Regarding the concentration of the corrosion inhibitor this vary case by case due to the characteristics of the processed crude, crude oils with high contaminants content and poor desalting performance like heavy and slop crudes tends to present higher concentration of NH3, HCl and amines in the desalted crude oil which raises the probability of corrosion and demands higher flow rates of corrosion inhibitor, it's recommended to look for specialized advice from a chemical treating company which will optimize the system to control de corrosion process under minimum flow rate of corrosion inhibitor as well as indicate what is the best corrosion inhibitor for your processed crude oil blend.

Dr. Marcio Wagner da Silva is Process Engineer and Stockpiling Manager on Crude Oil Refining Industry based in S?o José dos Campos, Brazil. Bachelor’s in chemical engineering from University of Maringa (UEM), Brazil and PhD. in Chemical Engineering from University of Campinas (UNICAMP), Brazil. Has extensive experience in research, design and construction to oil and gas industry including developing and coordinating projects to operational improvements and debottlenecking to bottom barrel units, moreover Dr. Marcio Wagner have MBA in Project Management from Federal University of Rio de Janeiro (UFRJ), in Digital Transformation at PUC/RS, and is certified in Business from Getulio Vargas Foundation (FGV).