Q&A

(2016) Question 29: What level measurement technology is used in the hydrotreater high-pressureseparator? Is the recommendation different if the unit runs in block modes (with feeds of varying densities)? What design considerations should be taken into account when selecting a high-pressure separator level control valve?

Like any instrumentation, there are advantages and disadvantages for different types of instrumentation in almost any service; therefore, there is no single choice of a Best Practice in all situations. Experiences vary from refiner to refiner, and even sometimes from unit to unit within a refinery depending on many factors, both technical and non-technical. It is important to understand the choices within both contexts. As the non-technical factors –such as instrument technician experience, refinery standards, etc. –are too general, they will not be addressed directly.

(2016) Question 30: What technologies do you use for mild hydrocracking of heavy gas oil over a range of conversions and product selectivity? Please elaborate on commercial experiences.

The theory and key considerations in utilizing mild hydrocracking (MHC) in an FCCPT unit were covered very thoroughly in Question 77 in the 2009 Answer Book, so I will not repeat what I consider to be the basic background information. Instead, I will try to compare the actual results achieved commercially from the various options. Several different technologies are available, and I will only highlight the keys.

(2016) Question 1: Do you have experience isolating air coolers to water-wash the process side while the unit continues to operate? What safety concerns do you consider beforeremoving this equipment from operation?

Safe isolation with block valves can also be an issue, especially in high pressure units with two-phase flow. We have had experience with water-washing exchangers and air coolers offline.

(2016) Question 2: What procedures do you use to test alkylation unit rapid deinventory systems? Do you perform a functional test using acid?

High level guidelines and philosophy of testing of the valves (as well as all other components) of HF alky safety systems –including rapid acid deinventory or “Dump” systems -is covered in API RP 751 section 2.3.6. The bits of that section that are directly applicable to dump valve testing suggest that the testing procedure should include valve stroking and testing of primary elements and controls. It also says that in addition to individual component tests, each active mitigation system as a whole should be tested to confirm that the system will work as designed. It also says that a service history should be maintained to assist in identifying and correcting problem areas.

(2016) Question 3: What process safety PSM) factors do you consider when contemplating a reformer unit rate increase?

Any change should be handled through the MOC (management of change) process, according to OSHA 1910.119: Process Safety Management of Highly Hazardous Chemicals. This standard includes requirements for preventing or minimizing the consequences of catastrophic releases that may result in toxic, fire, or explosion hazards.

(2016) Question 4: The economic benefit for propylene and amylene alkylation is improving. What considerations do you use in the feed pretreatment and alkylation unit operations before increasing these feeds?

Increased processing of propylene and amylene feedstocks in alkylation (alky) units does bring challenges, but most will depend on the configuration of the existing unit and whether any of these feedstocks have been processed before.

(2016) Question 10: What strategies do you employ to meet cycle-length targets in naphtha hydrotreaters that are reaching catalyst activity limits due to capacity increases or feedstock quality decreases?

To increase cycle length on an NHT hydrotreater, the refinery needs to understand the contaminants that the reactor must handle and optimize the bed loading to maximize cycle length, as well as have the ability to handle the contaminant.

(2016) Question 31: With heavy gas oil hydrotreating and mild hydrocracking units producing diesel product with 30 to 50 ppm sulfur, what options do you employ to recover maximum volume of ULSD? Are there other diesel quality concerns, and how are they resolved? How does the yield and quality change over the cycle?

We have many customer examples of FCCPT units and mild hydrocracking (MHC) units directly producing on-spec ULSD with Criterion catalyst systems. Many refiners who are making 30 to 50 ppm sulfur diesel from hydrotreating and/or mild hydrocracking units are able to blend this into the diesel pool and still have the whole pool meet the less than 15 ppm diesel sulfur specification.

(2016) Question 35: What are possible causes do you see of high product nitrogen in a naphtha hydrotreater processing coker naphtha? Please include monitoring, identification, and troubleshooting techniques, inside and outside battery limit considerations, and mitigation options.

Daily monitoring of feed nitrogen and distillation, via the Sim Dist (simulated distillation) method, will allow the refiner to adjust reactor temperature or control the final boiling point to meet the desired product nitrogen.

(2016) Question 36: Which refinery water sources do you accept for hydrotreater water wash (e.g., stripped fractionator overhead water, stripper sour water, etc.)? What are typical water quality guidelines?

Water wash systems must be designed well, with good water contact and draining, or the wash can create significant corrosion concerns, potentially resulting in process safety incidents. MPC experienced this first-hand with an intermittent wash system on an NHT unit.

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