Q&A

(2018) Question 32: Have you developed processes to successfully extract the emulsion layer from the desalter, so the emulsion can be treated separately? Please describe your chemical treatment programs and equipment that have been implemented successfully to treat this extracted emulsion.

Emulsion extraction headers, sometimes called cuff headers, have been an option and have been installed in desalters for decades. The removal of the emulsion layer solves one problem and creates another as this emulsion layer can be very difficult to treat.

(2018) Question 33: When processing cracked stocks in a crude unit, what potential issues do you expect? What changes in operations or treatment programs can you mitigate these issues?

If the site does not have a Delayed Coker, then reprocessing cracked stocks through the FCC fractionator is the next option. Again, this keeps the cracked materials separate from the straight run products.

(2018) Question 41: What effective practices do you deploy to improve the removal of inorganic contaminants in crude such as iron and calcium? What has been the industry success rate with these practices?

Cracked feedstocks can be introduced into the crude unit from several sources; the most common of which in North America are diluted bitumen from Canadian sources, diluted crude oils from South American sources, and slop streams from cracking units onsite that are recycled into the reprocessed slop oil blended into the crude unit feedstream.

(2018) Question 42: Some of the lighter waxy crudes have higher paraffin melting points making it difficult to treat and remove solids, salts in the desalter. What practices do you deploy to manage these higher melting point waxy crudes?

Some of the lighter waxy crudes have higher paraffin melting points making it difficult to treat and remove solids, salts in the desalter. What practices do you deploy to manage these higher melting point waxy crudes?

(2018) Question 43: What are your economic and operational reliability implications of increasing cycles of concentration in your cooling tower?

Operationally, especially as production units are debottlenecked over time, increasing tower cycles could facilitate the ability to utilize existing Utilities Infrastructure. This minimizes the need to undergo a disruptive engineering and installation processes should unit capacity enhancement projects be identified.

(2018) Question 44: Describe your procedures for placing and operating the FCC in hot standby/safe park mode. What safety concerns do you consider and what safeguards should be in place?

If the air blower is not running, things you should consider are ensuring all ignition sources are shutdown, bypassed or isolated (ESP, torch oil, DFAH, CO Boiler). Verify all hydrocarbon sources to the reactor, riser and regenerator are closed (fresh feed, any recycles, torch oil, fuel gas purges, LCO quench, etc.) and all sources of air are not being injected (main air, plant instrument air, fluffing air, etc.).

(2018) Question 45: What are the safe and reliable options for rodding out plugged bleeders such as hydraulic ram pumps, packing gland / drill assemblies or tangential bleeders? How are these options used in a best practice for ensuring piping is hydrocarbon free and ready for maintenance?

Rod out tools or bleeder cleaners are safe and effective at clearing clogged drain, vent and instrument valves to be cleaned during normal operations. Most include some type of drill bit and local pressure gauge and are designed to handle high temperature and pressure applications.

(2017) Question 1: How do you manage organic fluoride compounds in effluent and recycle streams in an HF alkylation unit? How do you detect upsets, and how are the impacts on downstream units mitigated?

Typically, organic fluorides are managed in the butane and propane effluent streams from an HF alkylation unit. Treatment of the isobutane recycle stream is not needed. The propane and butane products are typically treated in alumina treaters to remove the organic fluorides and then in KOH treaters to remove moisture (which is created in the alumina treaters) and any HF “slip”.

(2017) Question 2: Iron is one of the most common contaminant metals seen on naphtha reforming catalyst. What is the source, what is the impact to yields and operation, and what can be done to mitigate these effects?

Naphtha feed-based iron is typically removed in the upstream hydrotreaters, but breakthrough of iron to the reformer can occur due to insufficient operating severity in the hydrotreater once the hydrotreater catalyst bed is saturated.

(2017) Question 3: What are your Best Practices for unloading solid phosphoric acid (SPA) catalyst from a catalytic polymerization unit, and what safety issues do they address?

There are two types of Honeywell UOP Cat Poly reactors: chamber and tubular. Each has different unloading concerns, and there are several different unloading options available for each.

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