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(2012) Question 63: Crude and vacuum tower off gas production from bitumen crudes can be quite variable depending on feedstock quality. Please comment on observed off gas production when processing bitumen crudes.

Our response to this particular question is based on the presumption that bitumen crudes include the conventional Canadian heavy supply of crudes such as Lloydminster and Cold Lake. There has not been much Canadian tar sands bitumen actually processed within BP, either as a synbit (bitumen diluted with synthetic crude) or a dilbit (bitumen diluted with condensate) as of yet. Some of this new bitumen supply includes supplies such as Christina Lake, Sunrise, and Firebag bitumen.
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(2012) Question 64: Based on your experience, what are causes of fouling in the diesel/distillate draws of crude, vacuum, and coker fractionation towers? Does this migrate to downstream diesel hydrotreating units? What mitigation strategies are being employed to overcome these issues?

We have been concerned with potential phosphorous fouling on units processing Canadian heavy crude oil. We are aware that some refiners have experienced and reported on significant phosphorus fouling issues in the light diesel or jet draw section of the crude tower, as well as in the crude furnace. While we are concerned with the issue and monitor for it, we have not had any particular callout issues with CDU phosphorus fouling.
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(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.
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(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.
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(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.
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(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.
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(2012) Question 69: How do you detect that amine salts are forming and causing corrosion, either in the fractionator or other locations ahead of the water dew point? What are chemical and operational strategies for mitigation?

We have the chemical service vendor perform routine calculations for ammonia and/or amine salt points. We typically monitor the water dew point ourselves. The amine salt point is to be differentiated from the ammonia chloride salt point. Depending on the amine, a salt point can be higher, and often is.
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(2012) Question 70: What are your experiences with processing oil sludge in the delayed coker?

One of our delayed cokers does process crude rag layer draw, wastewater sludge, and oily water. I think they primarily process the crude rag layer, however. What we do here is introduce the sludge after we have steamed the coke bed and established the quench water flow. We then temporarily remove the quench water to allow the sludge injection, and then we maintain a minimum temperature – I think it is around 600°F – to ensure that no oil accumulates in the cutting water.
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(2012) Question 71: Is there any test method for performance evaluation of silicon-based antifoam agent used in coker?

Don mentioned the ASTM test procedure. It may also be beneficial to conduct elemental silicon loading. Silicone is a known molecule: dimethylpolysiloxane. The amount of elemental silicon introduced into the drum over a period of time can be tracked and compared with silicon in the distillate. Generally, the biggest step change to silicon loading is improving the chemical feed system.
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