Q&A

(2012) Question 60: With an increasingly varied crude slate, how are you managing substantial variability in salt levels in desalted crude and overhead neutralizer rates? How can this impact the amount and location of amine salt and other deposition in the atmospheric tower and overhead system?

The salt loading in the overhead is set by the salt loading leaving the desalters. Two key factors are the salt content of the oil and the salt coming in with the entrained water.

(2012) Question 61: Extensive use of upstream H2S scavengers in crude oils can cause salt deposition in atmospheric tower overhead systems, as well as on atmospheric tower trays, particularly when trying to operate at lower naphtha endpoints. What adjustments in desalter operation are used to mitigate amine salt deposition?

H2S scavengers may cause salt deposition in atmospheric towers. Triazine, the most common scavenger, is made by reacting formaldehyde with an amine, such as MEA (monoethanolamine), and creates an MEA-based triazine; similarly with methylamine-based triazine.

(2012) Question 62: What are causes of foaming in crude pre-flash drums and towers, and what options are available to mitigate foaming?

Surfactants cause foaming. Mike will discuss surfactants and amines that should not be in the crude. Sodium naphthenate is a common surfactant produced by the reaction of caustic injected at the desalter effluent and naphthenic hydrocarbons.

(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.

(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.

(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.

(2014) Question 67: What is your experience with toxicity issues at the Water Treatment Plant as related to naphthenic acid content in desalter brine water? What strategies are you employing employed to mitigate this issue?

Some naphthenic acids will not partition into the water phase and normally do not create a wastewater issue. In case of washwater and brine pH’s above 8.5 the naphthenic acids can form a soap, and this can cause severe emulsion formation and oil carry-under to the WTP.

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