Q&A

(2012) Question 65: Our vacuum column wash bed has lasted seven years in service and now needs to be replaced due to excessive coking and pressure drop. What is the typical life expectancy of the wash grid and packing? What is the panel's experience for the use of wash oil to the vacuum column wash section bed in gpm/ft2 (gallons per minute per square foot) with structured packing and/or grids in the bed? What is the recommended maximum slop wax draw temperature? Should a limit be set on this temperatu

This topic was discussed extensively in the previous Q&A, so my response will focus on wash bed replacement after seven years due to excessive coking and pressure drop. The typical life expectancy of a wash bed has to be qualified. It is dependent on cutpoint, design of the column, internals, operation, and severity.

(2012) Question 66: Some refiners are considering substituting potassium hydroxide for sodium hydroxide as a desalted crude treatment to lower overhead chlorides. What is the impact of this change on coker operation and other downstream units? What are the advantages and disadvantages?

They are both alkali metals. Potassium hydroxide should, in theory, act like sodium hydroxide. The effect should be similar with regard to reducing the overhead chlorides in the desalted crude or, similarly, in metal-catalyzed fouling.

(2012) Question 67: We have an atmospheric overhead system with inadequate waterwashing,and we experience fouling and corrosion issues in the bundle. What might be the pros and cons of making a bundle modification or installing direct water spray into the shell side of the atmospheric tower overhead condenser in terms of underdeposit corrosion and bundle life?

We would not recommend direct water sprays into the shell, regardless of whether this is the first overhead condenser, because direct sprays can cause many problems, including erosion.

(2012) Question 68: After the operating temperature of the crude column overhead has been raised, corrosion rates in trim coolers’ inlets have increased greatly. Ultrasonic thickness (UT) measurement has indicated some increase in local thinning, but not to the degree of actual damage. What are new trends for monitoring corrosion in distillation columns and overhead condensing systems?

When we talked about this on the panel, we had some very interesting discussions. Generally speaking, increasing temperatures tends to help with most overhead corrosion issues as it moves you away from salt and dew point consideration. What we think is going on here is that if you increase the temperature, you may shift your dew point downstream of where you are designed to handle it.

(2012) Question 76: The check valve on the air blower discharge line is designed to protect the blower from hot catalyst that backs into it when the blower fails. What type of valve is used in this service, where is it located, and what is done to ensure that it closes properly?

UOP specifies two special check valves in the blower discharge line. The first special check valve is installed a minimum distance from the blower discharge downstream in the snort (or anti-surge) valve in a horizontal pipe run.

(2012) Question 77: For our emergency interlock system, we employ two-out-of-three voting systems for slide valve differential pressure transmitters. We use dedicated transmitter taps for each transmitter, but we get inconsistent readings. What can we do, regarding design and maintenance, to ensure that these transmitters read more consistently? What should we do if we are unable to achieve consistent readings?

To obtain a more consistent reading, plant personnel should examine three phases: the transmitter, its physical location, and its instrument gas system. As for the transmitter, the technician should analyze it to ensure that it is within the accuracy specified by the manufacturer.

(2012) Question 78: What inputs or trips are typically included in FCC flue gas expanders and CO (carbon monoxide) boilers' safety interlock systems? Are there any governing standards [(e.g., API and NFPA (National Fire Protection Association)] that apply?

I would like to address this question as two different parts, beginning with the flue gas expanders. BP has three flue gas expanders in its system. These expanders are all set up with slightly different configurations. We have one FCCU flue gas expander that is directly coupled to the main air blower.

(2012) Question 80: We are considering severe hydrotreating of our FCC feed. What yield shifts or unusual operating problems might we expect? What can be done to address these issues?

Processing Hydrotreated Feed: First of all, let’s define what ‘severely’ hydrotreated feed means. One unit in our system hydrotreats the feed down to 50 ppm sulfur and 50 ppm nitrogen, so you can see that processing that type of feedstock has tremendous yield benefits.

(2012) Question 81: Is there experience with continuous torch oil and/or air preheater firing; and if so, for what reasons? What are the demonstrated effects from doing either of these processes?

We do not have much experience with continuous torch oil firing. We do have one unit that fires torch oil if the bed temperature drops below 1250ºF.

(2012) Question 82: Do you have any experience with the recycle of C4/C5 streams from the FCC gas plant back to the FCC? If so, what was your motivation? What is the system configuration, and what are the key operating parameters?

We have some experience recycling BBs (butane-butylenes) from the gas plant back to the FCC reactor, and even some C5s. I will start by saying that this is a very unusual operation.

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