Feb-2021

Our desalting rate drops away quickly when we use heavier feeds. What is the problem here?

Responses to a question in the Q1 2021 issues Q&A Feature

Various from Axens, Sulzer, Kurita,CHIMEC and SUEZ WTS,

Article Summary

Nabil Bouden, Equipment Sales Manager, Axens - nabil.bouden@axens.net

To understand this phenomenon, it is required to remind how a desalter is designed.

The water gravity separation is driven by the Hadamard—Rybczynski equation that gives the terminal velocity of a slowly moving spherical bubble through a fluid. Assuming that the coalescence process is not affected by the type of crude and that the droplet size remains the same whatever the crude, this formula shows that the settling velocity is proportional to both oil density and viscosity. As a result, in order to compensate this modification of crude properties, the flow rate should be reduced or the desalter volume should be increased, depending on whether the refinery wants to occasionally take advantage of opportunity crudes or if the refinery wants to implement a long term strategy of treating heavier crudes.

Another phenomenon that exacerbates this situation is due to the dipolar attractive force between droplets. This force, which produces coalescence on an AC field, depends on crude oil conductivity. Heavy crudes are usually more conductive, leading to a reduction in the voltage gradient within the desalter and thus affecting the coalescence process.

All these aspects should be taken into account during the desalter design phase to ensure that performances are maintained with all the specified crudes.

Some solutions can be tested to partly compensate the use of heavier feed and to help the desalting process. Desalter transformers are usually equipped with a tap changer that permits easy modification of the transformer voltage. Another action to be tested is to increase the wash water injection ratio in order to increase the water population distribution. This might improve the coalescence process by reducing the distance between water droplets and then increasing the attraction between charged water particles, even if it will not compensate a properly designed desalter.

To conclude on this question, it is important to keep in mind that a desalter is designed to perform for a specific range of crude feed and operational conditions. Hence, any changes in those conditions need to be addressed in coordination with the desalter supplier which can support the end user to tune its unit and assess specifically the impact on downstream equipment.

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Mark Pilling, Head Refinery System Business Group, Sulzer - mark.pilling@sulzer.com and Celso Pajaro, Head Refinery System Business AME, Sulzer - celso.pujaro@sulzer.com

Desalting is a two-stage process:
1. Mass transfer where salts move from the crude oil to the wash water; this process happens in the mixing valve.
2. Separation of the salty water from the crude oil; this process happens in the electrostatic separator.

If the desalting rate drops when processing heavy feeds, this could likely be related to the separation step. A lab analysis of crude leaving the desalter should indicate an increase in water content. If affirmative, these steps should be followed:
- Increase the temperature of the crude going to the desalter
   ν  Increasing the crude temperature reduces viscosity and increases the settling velocity of the water.
   ν  Note that the temperature increase should be limited by the desalter internals’ maximum operating temperature.
   ν  Some units allow switching of the heat exchangers before or after the desalter to increase or decrease crude temperature.
- Check the emulsion inside the desalter. You should involve the desalter chemical vendor to help determine if there is an emulsion present and what type of chemical is required to break it.
- Adjust the mixing valve pressure drop. Reducing the pressure drop increases the water droplet size, improving separation. However, increasing water droplet size reduces mass transfer. The net effect depends on the system.

If water content in the crude leaving the desalter is the same as with lighter feed, the problem is insufficient mass transfer. In this case:
- Increasing the mixing valve pressure drop will increase mass transfer. However, re-verify the water content in the crude leaving the desalter. If the water content increases after a mixing valve change, you should revert back to the previous pressure drop.
- Increase water wash quantity; typical values oscillate between 6 to 8%LV. More water produces a higher number of water droplets, which increases mass transfer area.
- Switch a portion (around 30%) of the wash water to the crude feed pump suction; water will achieve better mixing and allow higher salt removal.
- Install a static mixer, such as Sulzer SMV, downstream of the mixing valve. It will provide better mixing while reducing the pressure drop at the mixing valve.

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Berthold Otzisk, Senior Product Manager Process Chemicals, Kurita Europe - berthold.otzisk@kurita-water.com

Processing low-cost heavy crude oils can create many problems during desalting and downstream operation. Such heavy crudes often have a high viscosity, high salt content, high concentrations of solids or unstable asphaltenes, high sulphur levels, high naphthenic acid or high metals content. This causes significant problems such as low desalting efficiency because of uncontrollable emulsions, water and salt carry-over or oil carry-under into the desalter effluent water.

Drawbacks are reduced throughput, increased fouling and corrosion, wastewater treatment problems and higher energy costs. The function of a demulsifier is to break the oil/water emulsion, that the oil can be separated easily from the water. During oil production often higher amounts of such emulsion breakers are pumped into heavy crude oils. They are surface active agents and have a tendency to act as emulsifiers in higher concentrations. So instead of breaking the emulsion they form a more stable emulsion with oil.

Before processing crude oil in the electric desalter it could help to reduce the viscosity of the crude oil. Blending the heavy crude oil with lighter crudes will reduce the viscosity. A high viscosity is able to maintain larger droplets of dispersed water, while smaller dispersed droplets will show a higher resistance to settling. A higher water content increases the stability of the emulsion and reduces the desalting efficiency.

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Marco Roncato, Senior Product Manager, Process Development & Marketing, CHIMEC - mroncato@chimec.it

Crude oil is a mixture of thousands of organic compounds, together with variable amounts of inorganics (mainly salts, silica, limestone and few other types of silts).
Between the organic ones, the most dangerous in terms of emulsion stabilisation are asphaltenes (mainly) and naphthenates; they both — being polar molecules — work as surfactants when not in solution, stabilising water droplets in the hydrocarbon phase.

By definition, asphaltenes are a class of compounds of high molecular weight, soluble in toluene and insoluble in heptane; they are dispersed in the oil by resins.

The asphaltenes-resins complex is soluble in the aromatics of the oil matrix, while the paraffins are non-solvent.

Asphaltenes are tensioactive compounds that accumulate at the water-oil interface, reducing the surface tension of the water. This reduction increases the elasticity of the water droplets, resulting in emulsion stabilisation.

The resins, increasing the asphaltenes’ solubility in the oil matrix, are able to minimise their interaction with water droplets, so they can coalesce during the desalting operation.
Asphaltenes reside in the heavy fraction and this is the reason why usually heavier crude oils — containing a higher percentage of them — can be more difficult to treat at the desalter stage.

After asphaltenes, naphthenic acids and their soaps are surface active: they accumulate at the water/oil interface and stabilise colloidal structures.

Naphthenic acids can affect emulsion stability either directly or through interactions with other crude oil components (such as metallic ions, mainly Ca2+ and Na+).

Anyhow, in any desalter, to get good crude washing (hence good desalting efficiency) it is necessary to achieve the most intimate contact between salt crystals dispersed in the oil and the wash water. This is done through the mixing valve, where water is emulsified in the hydrocarbon phase. But immediately after this step, the emulsion must be broken and at this point the amount and characteristics of natural surfactants (mostly asphaltenes, naphthenates and inorganics) have to be considered.

As mentioned earlier, resins’ task is to increase asphaltenes’ solubility in the oil matrix, reducing their interaction with water droplets. When this phenomenon is not sufficient, the formed emulsion is stable and the oil/water interface in the desalter becomes thicker and more difficult to break, unavoidably leading to poorer washing of the oil; this means salts carry over after the desalter and because of this efficiency drops.

In such a situation, reducing the mixing valve ∆P — in order to reduce emulsification — is not a solution, because water/oil contact is reduced, therefore washing is less efficient and again desalter efficiency drops; it is a vicious circle.

To exit the loop, restoring desalting efficiency, for more than four decades Chimec has developed a complete programme — based on demulsifiers together with analytical and software tools — aimed at helping refineries in improving the desalter’s performance.

The first step is the choice of a specific demulsifier for the type of crudes processed.

The efficiency of a demulsifier is evaluated on the following points:
- Solid wetting capacity: in most crude oils, solids such as iron sulphide, silt, clay, drilling mud, paraffin, and so on, tend to collect at the interface, and can contribute significantly to emulsion stability; for removal from the interface, these solids can be water wetted and removed with water
- Capacity to improve the coalescence of the water droplets in order to speed the separation of oil and water
- Capacity to reduce the hydrocarbon content in discharged water
- Capacity to adapt the contact time of oil and water to the residence time of the desalter
Keeping in mind these four points, demulsifier selection always involves:
- Characterisation of the oil mixtures and related contaminants
- Evaluation of plant data (residence time, amperage, temperature, pressure, and so on)
- Finding the best equilibrium of the various components tailored on the characteristics of the crude diets processed by the refinery:
  ν wetting agents, for solids
  ν artificial resins, to increase the asphaltenes’ solubility in the oil matrix
  ν tensioactives, to replace the natural surfactants thus helping water droplets coalescence
- Simulating the real desalter’s conditions: special care is needed in applying an electric field to the emulsions in order to replicate the effect of electrical grids; the efficiency improvement due to electrostatic fields is well known in the industrial practice and applying this concept also at laboratory scale helps to optimise both the demulsifier components balance and the required dosage.

The second step — together with the best demulsifier — is the application of dedicated software: Descon is a software developed by Chimec and used for the optimisation of desalting systems.

Descon builds the mass balance of the desalting system and, depending on the process conditions, it allows the determination of:
- Desalter efficiency (salt, water, sediments)
- The optimal water quantity necessary for good desalting efficiency
- The parameters for optimal desalting (∆P of mixing valve, and so on)

Descon is a good tool for the management of anticorrosive treatments of the overhead system (by optimising the efficiency of the desalting process) and of antifouling treatment of the hot preheat train exchangers (optimising the washing of the crudes and caustic dosage).

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Mike Dion, Process Separations Center of Excellence Leader, SUEZ WTS - Mike.Dion@suez.com

The following assumes ‘desalting rate’ means crude charge rate. Crude charge rate can be hindered due to hydraulic limitations. These limitations can be simply due to pump capacity or higher water in the desalted crude which may increase head pressure the pump must overcome for the same crude throughput.

Pump curves are extremely useful to troubleshoot potential hydraulic limitations. They will provide, for a given pump impeller diameter, a curve depicting the relationship between flow rate and head pressure. The impeller diameter is usually sized per fluid specific gravity and/or viscosity.

Water in the desalted crude is a combination of soluble and insoluble water. The solubility of water in crude will depend on temperature and polarity of the crude oil. Insoluble water is entrained water droplets from the desalter. Higher water in the desalted crude can reduce crude throughput for plants with hydraulic limitations. A general rule of thumb commonly employed is every barrel of water may back out 6-8 barrels of oil. 

Heavier crudes, in general, have a higher desalted crude water content. This is due to lower density difference between oil and water resulting in less efficient dehydration in the desalter. Heavier crudes may also have greater viscosity and polarity than lighter crudes, which will also increase both soluble and insoluble water. Installing a crude booster pump on the desalted crude can help overcome hydraulic limitations due to minor changes in water content.