Q&A

(2011) Question 44: What are the operating parameters, including water or chloride additions, to adjust and monitor on a continuous catalytic regeneration reforming unit when it is required to operate for a short period of time (hours/days) with the regeneration section shut down (for instance if operating in low-coke mode)?

We have four CCR/Platformers in our refineries. While two operates for gasoline production, one operates in mix mode i.e., for BT as well as for gasoline production. The other solely operates for para-xylene production.

(2011) Question 45: What tools are you using to predict the yields of Xylene, Benzene, Toluene and other aromatics in a catalytic reformer? What methods do you use and how often do you test the feedstock for these variables? Other than feedstock quality, what factors are you accounting for in the individual yields (unit pressure, RON, etc)? Do you have any rules of thumb for conversion of certain species of aromatics?

Dedicated simulators are run for prediction, either using correlations or kinetic models. To be able to perform accurate predictions, feed analyses shall be performed every time the feedstock quality is changed: the most important one is detailed hydrocarbon analysis by gas chromatography (for instance Carburane).

(2011) Question 46: Ethanol blending, and benzene management has shifted refinery octane and hydrogen balances. How are you managing hydrogen demand without giving away octane? Conversely, how are you, with excess hydrogen, maximizing availability for volume swell?

Mandated ethanol blending and limits on benzene in gasoline tend to lower the ceiling on the operating severity of catalytic reformers. While lower severity operation is theoretically desirable, in practice it can constrain H2 production, and impact regenerator operation due to lower coke make, which may require operational workarounds.

(2011) Question 47: What success have you had with installing stabilizer feed chloride treaters in reducing the salt formation and frequency of water washes?

The use of promoted alumina versus zeolite in the liquid chloride treating has several issues. For aromatics operations a Zeolite chloride treater should be selected to protect the downstream aromatics solvent from organic and inorganic chloride.

(2011) Question 48: How does naphtha derived from tar sands and shale oil differ in respect to crude oil-based naphtha? What is the impact on reformer operation?

It is assumed that “shale oil” as mentioned in the question refers to oil produced from hydraulic fracturing of shale reservoirs, as opposed to oil produced from “oil shale” rock via retorting or other techniques.

(2011) Question 49: What criteria do you use to predict coke drum hot spots (leading to blowouts) during the cutting cycle? How do you modify your standard cutting procedure if you anticipate hot spots?

Coke drum hot spots can be difficult, if not impossible, to predict but there are operating practices that can help minimize the occurrence of coke drum hot spots/blowouts.

(2011) Question 50: What unique challenges do you consider when designing a safety instrumented system (SIS) for a delayed coker heater?

We are currently constructing two new delayed coker heaters at our El Dorado, Kansas facility. As part of this project, we have performed both a process hazard analysis (PHA) and a safety integrity level (SIL) evaluation.

(2011) Question 51: What are some steps that can be taken to minimize re-foaming while steaming to the fractionator? Are there ways to predict re-foaming tendencies of different crudes or coker feed properties?

After a Coke drum is taken offline, it is steam stripped with ‘little’ steam @ 2.5 t/hr for 30 minutes (28 ft drum) to main fractionator to recover volatile hydrocarbon material.

(2011) Question 52: What test methods do you use to predict desalter performance when switching to new crudes or a blend of several crudes?

Standard laboratory tests include salt, BS&W, gravity, viscosity, and filterable solids. The amount, and type of filterable solids can be the greatest factor to consider for interface emulsion resolution and predicting performance.

(2011) Question 53: Asphaltenes are known to destabilize at higher crude preheat temperature. Are there guidelines that can be used to determine the maximum allowable desalter operating temperature before the asphaltenes begin to drop out of solution and come out in the desalter brine?

We have worked with several refining organizations that process heavy Canadian crude oils to find the optimum desalter operating temperature. In general, raising temperature reduces the crude oil viscosity, which is desirable from a Stokes’ Law stand point as it makes breaking the emulsion easier.

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