Q&A

(2010) Question 88: What options exist for the disposition of FCC equilibrium catalyst and fines? For refineries processing residual feedstocks, what are the limitations on the contaminate levels for the various disposal options?

E-cat and ESP hopper fines are either send to a cement kiln or land filled. Fines captured by the Wet Gas Scrubber are also land filled. Metals limits are normally for leachable metals as measured by the TCLP (Toxicity Characteristic Leaching Procedure) testing, as opposed to total metals in the catalyst.

(2010) Question 89: In shifting from partial burn to full burn in a side by side unit, what has been your observed impact on the NOx emissions? What is necessary to achieve 20 ppm NOx?

Several Grace customers successfully operate with NOx emissions less than 20 ppm in full combustion without the use of NOx removal hardware in the flue gas circuit.

(2010) Question 90: Does any refiner use an on-line particulate emissions (PM) analyzer to measure PM concentration and/or particle size distribution in the flue gas? Are any of these analyzers using continuous emission monitoring systems (CEMS)? How reliable and accurate have these systems been?

Sunoco currently has a particulate matter (PM) analyzer in one location on the stack of a Wet Gas Scrubber. It is there to measure Filterable PM only, not particle size distribution. This was installed as a requirement of a local environmental permit.

(2010) Question 91: Assuming the FCCU already has a third stage separator, what are the various options you consider for further reduction of particulate emissions (PM) and what is the expected level of PM to be achieved?

The first thing to consider is the fourth stage collector. For designs that re-introduce the collected fines downstream of the expander, a fourth stage collector with fines removal and filter on the TSS underflow gas will aid in reducing PM.

(2010) Question 52: What areas of a delayed coker are susceptible to naphthenic acid corrosion? How do you determine the maximum allowable TAN for these areas?

The primary areas of concern include: •Coker feed circuit above 450 °F •Bottom section of the fractionator, including internals •Heater charge pumps and associated piping •Heater tubes.

(2010) Question 53: During the coking cycle, how are drum skin temperatures used to monitor drum wall condition?

Monitoring drum wall conditions during the drum cycle is best performed using strain gauges. Each strain gauge location will typically be fitted with gauges in both the axial and hoop directions and have an associated skin thermocouple.

(2010) Question 54: What is the current best practice for number of feed nozzles, angle, and location on coke drums considering the use of slide valves for the bottom unheading device?

There is not a one-size-fits-all answer to this question. However, we believe that an arrangement that closely matches the conventional bottom center upflow arrangement will provide more uniform thermal stresses on the drum and minimize operational impact.

(2010) Question 55: What is considered the best-in-class design for coker main fractionator wash zones? Have refiners seen good performance and target run lengths using grids in this service?

Cokers today are normally designed to operate to maximize liquid yield from the unit. This will require the coker to operate at as low a recycle as possible while still maintaining the required product specifications for the heavy coker gas oil (carbon content, metals, asphaltenes, etc.). For a low recycle operation a spray chamber is the best-in-class.

(2010) Question 56: Some crude tower overhead deposition appears to be linked to corrosion treatment programs (i.e. filming corrosion inhibitors and neutralizers). Have you confirmed this and what are the potential mechanisms that can lead to this deposition?

Corrosion inhibitors (filmers) have been known to cause deposition in several different ways. Generally, the cause is injection into an overhead that is too hot, flashing off the carrier, or injection of neat chemical, flashing off its solvent.

(2010) Question 57: Do you experience any corrosion and fouling in the preflash or crude towers as a result of running at dew point temperatures or below in the top of the towers? If so, what steps do you take to mitigate and control this problem?

Preflash towers and overheads are not particularly susceptible to corrosion and fouling because chloride hydrolysis is minimal at Preflash feed temperatures. Without chlorides, aqueous corrosion in crude oil distillation is minimal.

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