Problem Solving Manual for Crude Oil Refining Processes

Introduction and Context

??????? This short publication summarizes some of my responses related to questions about practical and theoretical questions related to crude oil refining issues.

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 28 - I would like to learn about the usage of Pyrolysis oil produced from Ethylene Cracker in the Delayed Coker Unit. I would like to use this pyrolysis oil which is around 2.5 wt % of total feed as a feed in the Delayed Coker Unit. Do you know any applications like this? If it is, have you encountered any issue to process pyrolysis oil to the coker unit? In addition, what if I use this pyrolysis oil as wash oil stream in the coker fractionator column instead of using as a feed? Do you know any applications or example?

Response - The pyrolysis oil from steam cracking units can be an attractive feed for delayed coking units, especially for those dedicated to producing high quality needle coke due to the high aromaticity of the pyrolysis oil. Despite this advantage, the participation of this stream in the feed can be limited due to the high potential of coking lay down in the fired heaters which will reduce the operational campaign of the processing unit like quoted in the que question.

Despite being a relatively common feed for delayed coking units, unfortunately I don't have experience in operating delayed coking units with this feed stream, but the main side effect can be the acceleration of the coke deposition in the fired heaters which demands sensibility analysis to determine the maximum participation of the pyrolysis oil in the feed in order to balance the economic return between the pyrolysis oil advantages (needle coke production, for example) with the shorter operational life cycle of the processing unit. About the use of pyrolysis oil as wash oil stream in the main fractionator, my point of view is that the pyrolysis oil is much heavy to this service and tends to raise the coking rates in the fractionating and thermal exchanges beds which will reduce the operational life cycle of the delayed coking unit or, at least, reduce the performance of the processing unit.

Question 29 - Is CCR value directly linked with asphaltene content? In hyrocracker feed specification why limit is fixed for both CCR and Asphaltene content? Why both parameters are measured separately?

Response - The CCR analysis is directly related with asphaltenes content which are responsible of the most part of coke laydown tendency from the residue, but another components like resins, aromatics and saturated hydrocarbons can contribute with the stability of the residue and influence over the feed quality of residue hydrotreating or hydrocracking unit as well as with the expected yields of distillates. Normally, it's carried out complimentary analysis to CCR like SARA (Saturate, Aromatics, Resins, and Asphaltenes) and H/C ratio to allow a most adequate analysis of the stability of the feedstock and the coke laydown tendency which will determine fundamental operating parameters like hydrogen partial pressure necessary to ensure an adequate and economic life cycle for the processing unit.

Question 30 - We have a black sludge formation at the interphase of naphtha and water in OVHD accumulator. But all the OVHD parameters like pH, Iron and Chloride are normal. The crude unit has a partial condensation overhead 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?

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 31 - Can high-grade needle coke (such as P66 or Seadrift) be used for synthetic graphite in EV battery anode materials? If the quality exceeds specifications and needs to be downgraded, is it easy to modify the needle coke manufacturing process? Or is it easy to source lower grade decant oil??

Response - It's possible to produce high qulity needle coke in delayed processing units capable to meet restrict quality requirements, but the production route of needle coke demands some specific operating conditions and feed stream quality to be processed in delayed coking units. The decanted oil from FCC is one of the best alternatives to produce high quality needle coke, to produce a lower-grade needle coke you can blend the decanted oil with vacuum residue with lower content of aromatics or, in refineries relying on solvent deasphalting processing units, add asphaltic residue to the feed stream. It's necessary to carry out some operating tests with different feed stream compositions aiming to determine what is the best composition to reach your desired quality of needle coke.

Question 32 - 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?

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 desalting vessels aiming to neutralize the hydrochlorides compounds.

Question 33 - 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?

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 34 - 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?

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 35 - What are the optimal unit configurations and combinations (e.g., FCC/hydrocracking) for increasing high-margins products, while reducing low-value streams (e.g., HSFO & LSFO)?

Response - The response depends on the characteristics of the processed crude, especially the sulphur content and API grade.

Regulations like IMO 2020 imposed severe restrictions over the refining hardware to process high sulphur crudes and the refiners capable of adding value to heavier and sour crudes reached significant competitive advantage. The synergy between FCC and hydrocracking units gives high flexibility and maximizes the refining margins, especially considering the growing market of petrochemicals but is a capital intensive solution and can be prohibitive for low capital power players.

Refiners processing medium and low sulphur crudes can apply the combination of FCC and solvent deasphalting or delayed coking units and reach significant added value to the processed crude with less capital expense, here it's necessary to consider that the refiner will need to rely with adequate hydroprocessing capacity to treat the intermediate streams and this needs to be considered in the investment analysis.

Another point to be considered is if the refiner needs to meet the market of bottom derivatives like asphalt or fuel oil. For these players it's necessary to consider that a deep conversion refining hardware like reached with the combination of FCC and hydrocracking can led to a lack of bottom barrel streams to produce these derivatives, with consequent opportunity lose (in some cases the refining margin is attractive for bottom derivatives like asphalt) and supply shortage in the market.

Question 36 - In building the petrochemical value chain, how much further can we see the FCC unit being used to increase olefins production with the wide range of feedstocks currently available, including waste plastics-derived pyrolysis oil?

Response - Considering the growing demand by petrochemicals and the operational flexibility of the FCC units is expected than the FCC technologies will be in the core of petrochemical integration efforts from the refiners.

Beyond the traditional actions to maximize the olefins yield in conventional FCC units like higher operating temperature, higher Cat/Oil ratios, and catalyst additives (ZSM-5), is expected growing investments in high severity and petrochemical FCC units. There is some trends that will demand research and development involving FCC units like the renewables co-processing and the use of pyrolysis oil from plastics recycling plants as feed of FCC units which requires a deep analysis regarding the effect on the production profile of the processing unit as well as the catalyst deactivation rate. Regarding the renewables co-processing, the use of ethanol as feed to FCC units aiming to improve the yield of ethylene is one of the most interesting trends which will demand analysis by refiners and technology developers in the next years, in my point of view.

Question 37 - Under what conditions do you see opportunities with the upgradation of distressed refinery products (such as vacuum residue) to higher value outlets? Are these opportunities primarily outside the fuels market?

?Response - I believe that the response relies on the market that the refiner is inserted and the crude oil blend which is processed by the refinery. In developing economies still present high demand by transportation fuels like gasoline and diesel and, for these players can be attractive adopt refining routes based on residue upgrading technologies with less capital spending like the combination of delayed coking and hydrotreating to maximize the diesel and gasoline production ensuring high added value to the bottom barrel streams.

Refiners processing low sulphur crudes can still produce low sulfur fuel oil or Bunker (VLSFO) in compliance with IMO 2020 with just dilution of atmospheric residue once this derivative presents high demand due to the environmental regulations in ECA (Environmental Control Areas), but this can be economically attractive just for refiners processing crude blending capable to produce an atmospheric residue with maximum sulphur content close to 0,5 % wt.

Considering the recent forecasts, the developing economies are facing deep changes in the downstream market with growing demand by petrochemicals and hostile scenario for fossil fuels, for these markets closer integration between refining and petrochemical assets is the trend and this is strictly related with the capacity to add value to the bottom barrel streams. In these markets can be attractive the capital investments in deep residue upgrading technologies like hydrocracking and his synergies with FCC units.

Another attractive alternative is the lubricant market once these derivatives present growing demand and high added value, again it's necessary to consider an adequate refining hardware once the Group I lubricants present in contraction market. Refiners which intend to be competitive in the lubricant market need to make capital investments in hydrocracking units capable of producing Group II and III base oils.

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Question 38 - Is it possible that refiners could be overlooking some practical solutions to increasing FCC olefins yields, such as in the gas plant/recovery section?

Response - No doubt, there are some relatively easy solutions to improve the yield of petrochemical intermediates in FCC units which can be overlooked by some refiners.

Considering the current market demand, the FCC units can be optimized to produce higher added value derivatives like light olefins, refiners facing gasoline surplus markets can operate the processing unit in maximum olefins operation mode, to minimize the production of cracked naphtha.

In this operation mode the FCC unit operates under high severity translated to high operation temperature (TRX), high catalyst/oil ratio. The catalyst formulation considers higher catalyst activity through addition of ZSM-5 zeolite. There is the possibility of a reduction in the total processing capacity due to the limitations in blowers and cold area capacity.

It’s observed an improvement in the octane number of cracked naphtha despite a lower yield, due to the higher aromatics concentration in the cracked naphtha. In some cases, the refiner can use the cracked naphtha recycle to improve the LPG yield.

In the maximum LPG operation mode, the main restrictions are the cold area processing capacity, metallurgic limits in the hot section of the unit, treating section processing capacity as well as the top systems of the main fractionating column. In markets with falling demand by transportation fuels, this is the most common FCC operation mode.

Through changing the reaction severity, it is possible to maximize the production of petrochemical intermediates, mainly propylene in conventional FCC units.

The use of FCC catalyst additives such as ZSM-5 can increase unit propylene production by up to 9,0%. Despite the higher operating costs, the higher revenues from the higher added value of derivatives should lead to a positive financial result for the refiner, according to current market projections. A relatively common strategy also applied to improve the yield of LPG and propylene in FCC units is the recycling of cracked naphtha leading to an over cracking of the gasoline range molecules.

Nowadays, the falling demand by transportation fuels has made the refiners optimize the FCC units aiming to maximize the propylene yield following the trend of a closer integration with the petrochemical sector. Among the alternatives to maximize the propylene yield in FCC units is the use of ZSM-5 as additive to the FCC catalyst as well as the adjustment of the process variables to most severe conditions including higher temperatures and catalyst circulation rates. Another interesting alternative is to recycle the cracked naphtha to the process unit aiming to improve the LPG and consequently the propylene yield.

The installation of propylene separation units can present a significant capital investment to refiners but considering the last forecasts that reinforces the trend of reduction in the demand by transportation fuels, this investment can be a strategic decision to all players of the downstream industry in the middle term both to ensure higher added value to the processed crude oil and market share. Another possible capital investment aiming to improve the yield of light olefins recovery from FCC units is the use of cryogenic processes in the gas recovery section against the conventional configuration with separation columns, in this case the recovery of ethylene is highly improved.

Question 39 - Do you see growing investor interest in processing plastic waste-derived pyrolysis oil through refinery assets, such as hydrocrackers? Against this backdrop, how prepared are refiners to invest in contaminants removal systems (for pretreatment of the pyrolysis oils)?

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Response - We are facing a continuous growth of petrochemicals demand and a great part of these crude oil derivatives have been applied to produce common use plastics. Despite the higher added value and significant economic advantages in comparison with transportation fuels, the main side effect of the growth of plastics consumption is the growth of plastic waste.?? ?

Despite the efforts related to the mechanic recycling of plastics, the increasing volumes of plastics waste demand most effective recycling routes to ensure the sustainability of the petrochemical industry through the regeneration of the raw material, in this sense, some technology developers have been dedicated investments and efforts to develop competitive and efficient chemical recycling technologies of plastics. ?

One of the most applied technologies for plastics recycling is the thermal pyrolysis where the long chain polymeric is converted into smaller hydrocarbon molecules which can be fed to steam cracking units to reach a real circular petrochemical industry. Unfortunately, the thermal process produces chemically unstable feedstock to steam cracking units which raise the coking deposition rates and drastically reduces the operational life cycle of the cracking units. An alternative to the thermal process is the catalytic pyrolysis which is more selective and can produce molecules more stable than the thermal process, but these technologies are still under development.

Another promising chemical recycling route for plastics in the hydrocracking of plastics waste, in this case the chemical principle involves the cracking of carbon-carbon bonds of the polymer under high hydrogen pressure which lead to the production of stable low boiling point hydrocarbons. The hydrocracking route present some advantages in comparison with thermal or catalytic pyrolysis, once the number of aromatics or unsaturated molecules is lower than the achieved in the pyrolysis processes, leading to a most stable feedstock to steam cracking or another downstream processes as well as is more selective, producing gasoline range hydrocarbons which can be easily applied in the highly integrated refining hardware. ?

The chemical recycling of plastics is a great opportunity to technology developers and scientists, especially related to the development of effective catalysts to promote depolymerization reactions which can ensure the recovery of high added value molecules like BTX. More than that, the chemical recycling of plastics is an urgent necessity to close the sustainability cycle of an essential industry to our society. In my point of view, despite the necessity of better development of the available plastics recycling routes, the capital investment in these technologies is essential to any player which intends to be competitive in the petrochemical market, mainly in the Asian market which is more developed in this sense.

Question 40 - Projected diesel shortages could become a crisis if winter conditions are severe, potentially knocking out already strained power grids. What strategies should refiners rely on to increase distillate-range material?

Response - The response relies deeply of the available refining hardware as well as the processed crude oil.

Generally, it's possible to optimize the crude oil distillation unit to maximize middle distillates as well as gas oils capable to be converted into diesel after post processing in residue upgrading units like hydrocracking or deep hydroprocessing. Another interesting alternative is optimize the blending operations in stockpiling assets aiming to maximize the yield of middle distillates respecting the derivatives specifications, a common operations in some refineries is blending straight run heavy nafta with diesel aiming to improve the produced volume in the diesel pool.

The cracked heavy nafta can also be added to the feed of diesel hydrotreating units to improve the produced volume of diesel, of course, if the processing unit is able for this as well as there is hydrogen availability. Another cracked feed with is sent for diesel pool after adequate hydrotreating is the Light Cycle Oil (LCO) from FCC units, despite the high aromatics concentration of LCO, this stream can help to improve the diesel production through high severity hydrotreatement.

Question 41 - How can the refining industry supply the aviation industry’s growing demand for sustainable aviation fuel (SAF)? What are the most efficient pathways?

Response - This is one of the hot points of the downstream industry nowadays. The biofuels and renewables co-processing have a fundamental role in the energy transition and decarbonisation of refining industry and we are seeing attractive processing routes capable to reduce the carbon intensity of the fossil fuels like the co-processing of renewable raw materials in hydrotreating units to produce less carbon intensive diesel and jet fuel, for example. In the petrochemical industry, the ethanol to olefins route is another promising route which already presents commercial production plants.

The use of total renewable feedstock can be attractive under specific scenarios, but it's always important to consider the source of the renewable raw materials in order to avoid the competition with food industry as well as the pressure over the agribusiness especially in regions with restrictions of available arable lands. These restrictions can be also related to the biofuels production through esterification which are normally blended with the fossil fuels before commercialization.

Another interesting processing route is the Gas to Liquid (GTL) hydrocarbons production route applying biomass as feedstock, again it's necessary to consider the availability of the renewable raw material and the politician and social impact of this alternative. In the technical point of view, this alternative can produce high quality and low contaminants liquid hydrocarbons.

Lastly, but not less important, any effort to energy transition of the downstream industry needs to consider the hydrogen source applied to the process. We are seeing an increasing pressure in the last decades to reduce the environmental footprint of the fossil fuels and great part of the obtained results was achieved through the hydrorefining, leading to a growing dependence of hydrogen which, until this moment, is industrially produced through natural gas reforming process that produce great amount of carbon dioxide (CO2) emissions. The processing of renewable raw material requires even more hydrogen to achieve the goal of high quality and less contaminant fuels production, in other words, the sustainability cycle only will be closed if the hydrogen applied to the process is renewable or there is efficient carbon capture technologies which are still incipient in the market.

In summary, there are available processing routes and technologies capable of supplying the market of renewable fuels, but it's necessary to consider all impacts of the production chain as well as if the sustainability cycle is really closed.

Question 42 - What are water partial pressure & chloride partial pressure in the fixed bed catalyst of Naphtha Reforming Unit ? And how can be controlled ?

Response - The management of water/chloride relation is a key parameter for catalytic reforming units aiming to ensure an adequate balance between the acidic and metal functions of the catalyst. Normally, fresh catalytic reforming catalysts presents close to 1,0 %? wt of chloride, to maintain this chloride concentration it's necessary to control the water concentration aiming to allow an effective interaction between the alumina (catalyst support) and the chloride, reaching then a good performance of acidic sites of the catalyst which is responsible by the cracking reactions.

According to the literature, several factors impact the chlorides concentration in catalytic reforming catalysts. The reactor temperature and surface area of the support can directly affect the chloride concentration in the catalyst and are the most relevant factors. Still according to the literature, fixed bed catalytic reforming reactors should operate keeping the water to chloride molar ratio between 15 to 25 in the recycle gas aiming the keep the activity of the catalyst, to control this parameter it's necessary to install sample facilities or online monitoring systems in adequate points aiming to keep this parameter according to the licensor specifications. It's possible to find in the specialized literature chlorides equilibrium curves capable of helping the refiners to control the water to chloride ratio in the catalyst under the specifications defined by the licensors.

Question 43 - What is the best MOC (Material of Construction) for the NMP recovery and Dehydration portions of a Solvent Extraction System? We are finding that acid in the feed oil concentrates in the recirculating NMP and that this is degrading the 304 SS process vessels. Is 316 SS a good choice or will we need to go to more exotic alloys? The recirculating NMP can hit a pH of 4.0 and sometimes down to 3.7

Response - Unfortunately, the concentration of acidic compounds in NMP (N-Methyl Pyrrolidone) is a relatively common issue in lube oil dearomatization units.

Before considering changing the material of construction of the process equipment, please verify the possibility to raise the frequency of purge and make up the NMP aiming to reduce the concentration of acidic compounds in the solvent. Additionally, some references describe the use of sacrificial metals like magnesium and zinc installed in the critical of solvent recovery and dehydration sections of dearomatization units as an effective way to deal with corrosion issues in these processing units, I believe that this can be most economically attractive face to change the MOC (Material of Construction) of the processing unit.

The use of stainless steel like AISI 316 can be interesting, but it's expensive and can led to other issues once these materials are very sensitive to stress corrosion due chlorides and it's very difficult to ensure the absence of these compounds in a processing unit (a simple cooling water leakage can contaminate the system with chlorides). I believe that it can be interesting to make an economic analysis comparing the cost of replacing the construction material of the processing unit face to raise the frequency of solvent change or make up flow rate in order to reduce the acid concentration in the recirculating solvent (NMP).

Question 44 - Are there any DCU units that processes more than 50%wt of SDA in fresh feed? If so, do you have any problems with increased foaming or fouling?

Response - Unfortunately, I don't know a Delayed Coking unit that processes this perceptual of SDA residue, but please consider these factors about the foam formation in delayed coking reactors:

1 - Feedstock's characteristics: The paraffinic feeds tends to present high foam level in the reactor than aromatic feeds once the paraffinic compounds cracking faster than aromatics compounds, creating a flow of gas through the liquids in the reactor. Another parameters of the feedstock's which can cause foam production is the presence of high sodium and solids concentration in the feed;

2 - Sudden depressurization of the reactors: This disturb can cause an excessive velocity in the reactor, favouring the foam formation;

3 - Inadequate heating of the feed: Some refiners can try to reduce the temperature to minimize the coking issues in the fired heaters and reduces excessively the feedstock temperature leading to the increasing of the foam in the reactors. It's necessary to make a balance between the coking of the fired heaters and foaming formation in the reactors;

4 - Excessive velocity in the reactors: The high velocity in the delayed coking reactors can be caused by an excessive flow rate of the feed as well as reduced pressure of the reactors;

As described above, acting in the temperature and pressure of the reactors it's possible to minimize the foaming formation. Higher temperature and pressure tends to reduce the foaming production in delayed coking reactors, but it's necessary to consider the another aspects once the increasing of pressure and temperature affects directly the quality of the produced coke.

Question 45 - What's the philosophy of desalting system in Crude Distillation Unit, with respect to High Voltage & Demulsifier?

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. A 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 break 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 a 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 consider 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 46 - What are the other methods to reduce feed foaming in DCU reactor,?apart from the use of anti-foaming agents, increasing pressure and temperature??

Response - The foam formation in the delayed coking reactors can be caused by a series of factors like:

1 - Feedstocks characteristics: The paraffinic feeds tends to present high foam level in the reactor than aromatic feeds once the paraffinic compounds cracking faster than aromatics compounds, creating a flow of gas through the liquids in the reactor. Another parameters of the feedstocks which can cause foam production is the presence of high sodium and solids concentration in the feed;

2 - Sudden depressurization of the reactors: This disturb can cause an excessive velocity in the reactor, favouring the foam formation;

3 - Inadequate heating of the feed: Some refiners can try to reduce the temperature to minimize the coking issues in the fired heaters and reduces excessively the feedstock temperature leading to the increasing of the foam in the reactors. It's necessary to make a balance between the coking of the fired heaters and foaming formation in the reactors;

4 - Excessive velocity in the reactors: The high velocity in the delayed coking reactors can be caused by an excessive flowrate of the feed as well as reduced pressure of the reactors;

As described above, acting in the temperature and pressure of the reactors it's possible to minimize the foaming formation. Higher temperature and pressure tend to reduce the foaming production in delayed coking reactors, but it's necessary to consider another aspects once the increasing of pressure and temperature affects directly the quality of the produced coke.

Question 47 - 1) Increasing of the water content (H2O) of the Heavy Naphtha in the Storage Tanks … and the moisture in the Recycle Gas. What are the causes?

2) If the required concentration of chlorine (Cl) in the feed is (2 ppm). Provided that: Unit capacity (Reforming Unit) = 40 m3/hr (Density of Heavy Naphtha= 0.742 gm/cc ; Density of PDC (Propylene Dichloride C3H5Cl2) added = 1.15 gm/cc)

So, what's the amount of PDC to be added so that we obtain the above concentration (2 ppm)?

Response - I'm understanding that the heavy naphtha is fed to a catalytic reforming unit and was observed higher water content in the feedstock tank of the unit recently. About this issue it's recommended to check the separation quality in the top vessels of the crude distillation unit, especially the straight run naphtha split column in order to ensure that water is not being dragged to the heavy naphtha and accumulating in the storage tank. The water excess in the naphtha feed can be raising the moisture in the recycle gas.

Regarding the second question, based on informed data it's necessary to feed close to 95 ml/h of PDC (Propylene Dichloride) to ensure the desired chloride concentration in the feedstock of the catalytic reforming unit.

Question 48 - We have a problem in the specifications of the feed of the Reforming Unit (Heavy Naphtha: Sulfur content = 2.6 must be <1; Dr. test = Slightly H2S must be negative)

Knowing that the operating conditions of the Hydrodesulfurization unit are normal.

Any solutions welcome.

Response - Considering your information that the Hydrodesulfurisation is OK, we need to check the characteristics of the feed. Some relevant questions need to be answered like if your catalytic reforming is operating with only straight run naphtha, in some refineries it's common to apply hydrotreated coker naphtha as feed for catalytic reforming units.

I will consider that your processing unit is operating wit only straight run naphtha, in this case, it's necessary to check the sulphur content of the straight run naphtha to check that this is respecting the maximum hydrodesulfurisation capacity of the hydroprocessing unit. Maybe the change of processed crude to heavier or sourer crudes can be affected the sulphur content of the straight run naphtha.

Another point to check is the fractionating quality int he atmospheric column of the crude distillation unit, in some cases the salt formation in the tower internals can led to the poor fractionating quality in some sections and kerosene can be dragged to the naphtha, raising the sulphur content of this stream. My suggestion is to carry out a characterisation of the naphtha fed to hydrodesulfurisation with analysis of total sulphur and boiling range to identify possible contamination with heavy hydrocarbons.

Question 49 - We are having problems with the volatile material in the carbon of the DCU. To lower the MV we have increased the temperature of the furnace, and increased the steam flow during the vaporization of the bed; any other recommendations for this?

Response - The unit is using a motorized ball valve as switch valve? In this case, it's common to use many steam purge lines to avoid coke deposition over the seal faces of the valve and then it's necessary to evaluate and monitor the steam purges procedure to avoid an excessive decrease in the feed stream temperature to the reactors which can lead a high volatile matter in the produced green coke.

Question 50 - Currently we are facing problem of higher CO (Carbon Monoxide) and CO2 contents in the Net Gas (Net Gas is H2, produced in CCR Platforming Unit). This CO is affecting UOP's Penex Unit Catalyst. Please help finding out the source of CO & CO2 and guide how to reduce both in the Net Gas (our main focus is on reduction of Carbon Monoxide as it is a permanent poison for Penex Catalyst).

Response - It's important to understand better the refining scheme adopted in your refining asset, from the question it seems that the Net gas from CCR Platforming is directly fed to the Isomerization Unit (PENEX Process). If the net gas is not fed previously to a PSA unit or another hydrogen purification unit, it's expected a high concentration of CO and CO2 which are poison to isomerization catalyst. In this case, it’s necessary to study the economic viability to install a PSA or MEA treating unit aiming to reduce the CO and CO2 concentration in the Net Gas sent to the Isomerization unit.

Question 51 - How can we control the undesirable reactions in catalytic naphtha reforming (SRR Unit) (fixed bed reactors) in order to enhance the Octane Number and Hydrogen Purity?

Response - The most common side reactions in Catalytic Reforming Units is the hydrocracking which are favored by lower temperature (the hydrocracking reactions are exothermic), higher hydrogen pressure and lower space velocities. In this sense, a good way to minimize the risk of hydrocracking occurrence is to operate under higher temperature, lower hydrogen pressure and high space velocities. In other words, it's important to avoid the operation of the catalytic reforming with low feed flow rate and under low severity.

Question 52 - Crude Tank (Floating Double Deck Pontoon) is preparing to take crude oil (API 29) for the first time. Is it safe to put crude directly into the tank without Oxygen freeing? If water is first taken into the tank up to the floating level and then charge the crude, is it safer?

Response - It's possible to ensure a safety operation controlling the speed in the feed nozzle of the tank, there is some references which presents the maximum flow rate to ensure the filling the tank with controlled speed in order to minimize the vapour formation in the tank, of course, this flow rate depends on the diameter of the feed nozzle of the tank.

Question 53 - We faced problem in the particulate contamination specification of jet fuel product in the two tanks , and from our survey the specification from the unit of hydrobon unit is ok ,on the other hand in the refinery we refine sweet crude with API 42 and we got this problem for first time, in your view can you advice me?

Response -It's important consider in the analysis the information of the last cleaning of the internals of the storage tanks. It's important keep a routine of cleaning the storage tanks each five years in order to avoid the contamination of derivatives with water, sludge and corrosion products, this is specially true for jet fuel tanks.

Question 54 - 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?

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.

Dr. Marcio Wagner da Silva is Process Engineer and Stockpiling Manager at Crude Oil Refinery 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).