Q&A

(2015) Question 90: We are planning to purchase a new flue gas steam generator. What is your preferred configuration? What are the critical operating parameters you employ to ensure reliable operation? What is your sparing philosophy?

The configuration of the flue gas steam generator will be predominantly governed by FCC design. For a partial-combustion unit, it will be a CO boiler or a CO incinerator cum FGC (flue gas cooler) combination. For complete combustion, it will be a FGC or waste heat boiler alone. By CO boiler, typically we mean a boiler where the steam generating tubes are exposed to direct flame.

(2015) Question 91: What are your top three causes of unit slowdowns, and what is the loss in onstream factor for each? Please provide the same information for your top three causes of unit shutdowns.

FCC/RFCC units are the one of the major secondary units in almost all of IOCL’s refineries. Irrespective of demand positions, these units are always required to operate at high capacities. All of our refineries had been participating in the benchmarking surveys conducted by Solomon Associates, and the results comparing IOCL FCC units with rest of the world (2014 study) are indicated below.

(2013) Question 77: What are the consequences associated with continuing to operate the FCC without main fractionator bottoms cooling circulation?

We considered this question as three parts: What is the action to follow in the event of a loss of bottoms’ cooling? What is the consequence if you lose the net slurry product? What are the operational possibilities if you have a well-planned outage of the slurry circuit? In situations one and two where you have lost circulation or you have lost the net bottoms’ product in the system here, we expect that you would shut down the unit consistent with your licensure’s emergency shutdown procedures.

(2013) Question 78: What procedures (maintenance and operational) are being used to minimize risk when swinging the blind between the reactor/main fractionator?

There are two scenarios to consider: shutdown and startup. I will address the shutdown scenario first. For the shutdown scenario, catalyst is de-inventoried from the reactor and regenerator systems, and the main column and reactor are cooled down to 350°F. There are certain operational conditions that must be satisfied before the blind is installed.

(2013) Question 79: How do you mitigate the risk of falling coke deposits from the reactor plenum chamber and vapor line during initial vessel entry?

We have not had the experience of falling coke deposits on vessel entry. We usually experience difficulty in removing the coke deposits, and we do this by mechanical means. Prior to entry into the reactor, a visual inspection is made from the manway. It is typical to see stalactites from the reactor plenum.

(2013) Question 80: We have coke deposits in the plenum chamber and vapor line and are concerned the deposits may spall off or ignite during refractory dryout. What precautions should be taken to avoid re-igniting these coke deposits during the dryout?

We prevent hot air from entering into the reactor system during the regenerator dryout. Subsequently, we will use initial catalyst circulation for the reactor side dryout. Prior to lighting the DFAH (direct fire air heater) for the regenerator refractory dryout, we will introduce dry steam into the reactor, feed distributors, reactor riser, reactor dome, and stripper section.

(2013) Question 81: How do CO (carbon monoxide) and NOx (nitrogen oxide) emissions change when you operate at low regenerator temperatures? What can be done to mitigate any increases?

I will initially address this question from a CO standpoint and then discuss the NOx. CO emissions typically increase if the regenerator falls below a certain temperature threshold. That temperature threshold will vary based on your regenerator configuration and definitely on the type of air distribution.

(2013) Question 82: For those operating units with electrostatic precipitators (ESPs), share your experience with using SOx (sulfur oxide) reduction additives and their impact on: 1) ESP performance, 2) stack opacity, and 3) filterable solids mass.

We have two ESPs in our system. One of them is on a unit currently using less than 2.0% of SOx additive. We have not seen any impact at all on performance, opacity, or filterable solids. The other ESP went through a retrofit within the past four years, going from a smaller, older version of an ESP to a larger ESP with more modern technology.

(2013) Question 83: Wet flue gas scrubber NOx removal technology often results in excessive nitrates in the purge water. What are refiners doing to limit nitrates going to their wastewater treatment plant?

Nitrates and nitrites are inevitable byproducts from the removal of NOx from FCC flue gas. Obviously, one way to lower this nitrate concentration going into the purge water is to reduce the NOx in the flue gas, which we discussed a couple of questions ago.

(2013) Question 84: What are the commercial experiences with low rare earth and zero rare earth SOx reduction additives? What are the incentives to return to traditional products now that rare earth prices have returned to historical levels?

During the run-up in the cost of rare earth in 2011, Grace embarked on an expedited and extensive R&D (research and development) program to develop future generations of our Super DeSOx® additive to cut the rare earth content and try to minimize the financial impact that the ever-increasing cost of rare earth had on our customers’ cost of SOx compliance.

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