Q&A

(2012) Question 1: For refiners using Layers of Protection Analysis (LOPA) in their OSHA (Occupational Safety and Health Administration) PHA (Process Hazard Analysis) studies, how do you quantify the frequency and consequences of initiating events?

I have a lengthy description of LOPA itself to help address this question. Layers of Protection Analysis is the structured process used to determine the appropriate layers of protection required to provide adequate safeguards for adverse and sometimes catastrophic events in process units.

(2012) Question 3: How can lubricity be improved in ultra-low sulfur jet fuel?

The increased desulfurization of distillate fuels removes sulfur nitrogen and aromatics, which are components favorable for lubricity properties. The recent market conditions have led most refiners to not only produce ULSD, but also ULSK (ultra-low sulfur kerosene), in order to maximize distillate production.

(2012) Question 4: What are the hydrotreating operating issues when processing shale-derived light, sweet, and highly paraffinic crudes such as Bakken, Eagle Ford, and Utica? What hydrotreating/catalyst strategies can offset any negative effects? What options are available to optimize the distillate hydrotreater(s) with these light, sweet crudes?

The shale crudes in question are highly paraffinic, low sulfur, low nitrogen, and low in conventional contaminants. However, we do see some trace contaminants coming in from some of the fracking and completion chemicals. These crudes have a low resid content, which impacts the bottom of the barrel.

(2017) Question 45: What are your typical consequences and probable sources of fuel gas fouling? What are your respective solutions?

Fuel gas fouling in refineries is an ongoing problem and is typically the result of many years of corrosion due to moisture in the fuel gas system. These systems are typically saturated with water vapor due to the amine scrubbing that is used to remove H2S, and water may drop out as a liquid in low velocity areas or in areas with inadequate insulation.

(2016) Question 27: What methods do you use to reduce particulate loading on or debottleneck of existing filtration equipment in a HPU unit without reducing catalyst cycle life?

The use of feed filters is highly recommended, but it is important to choose a filter size that will be manageable; meaning that if a 5-micron filter is used, it will most likely have to be replaced or backflushed several times per day, which is not practical. However, if a too-large filter size is used, it will not be effective. The only way to reduce the particulate loading on a feed filter is to increase the filter size, thus allowing more material to slip through.

(2016) Question 28: Our hydrotreating unit continues to suffer from pressure drop issues. Multiple graded-bed schemes have provided incremental improvements. What other successful solutions to further mitigate pressure drop buildup do you employ?

Solving reactor pressure drop issues has been a decades-long ongoing effort, and Haldor Topsoe has been a pioneer within this area since the early 80s when Haldor Topsoe first commercialized highly effective catalytically active grading products.

(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 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.

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