NPRA 2012 Q&A and technology forum, hydroprocessing cracked materials
What are the operating constraints in co-processing coker naphtha in a ULSD and/or gas oil hydrotreater unit?
Brian Watkins, Meredith Lansdown, Brian Watkins and Brian Slemp
Advanced Refining Technologies
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Co-processing coker naphtha in ULSD service can have several undesirable effects on the performance of the hydrotreater and the catalyst if the system was not properly designed to handle it. In general, coker stocks have a higher level of olefins present from the coking process. Once in the hydrotreater, these olefins will quickly be saturated, consuming additional hydrogen and generating heat. As a general rule of thumb, 1 mole of hydrogen is required per mole of carbon-carbon double bond, or between 5-10 times the bromine number reduction in standard cubic feet of hydrogen per barrel (SCFB). This additional heat (130-160 Btu/SCF hydrogen consumed), if not spread out through a decent portion of the catalyst bed, will initiate the subsequent reactions, creating a much higher temperature rise than expected. This excess temperature can also speed up the coking or polymerisation mechanism, which will lead to an increase in pressure drop. This can set an upper limit as to how much coker naphtha can be processed, either by a need to limit the heat rise or from too much hydrogen consumption near the reactor inlet that could starve the downstream catalysts.
A system that is properly size and activity graded will be extremely important when co- processing coker naphtha in a diesel unit. ART utilises a grading system to help mitigate pressure drop build-up. ART’s GSK-19 is a 19 mm inert ring with a very high void fraction used for trapping large particulates and is placed at the top of the reactor. GSK-9 is loaded next and is a 9 mm macroporous ring that traps iron as well as other finer particulates that can increase pressure drop. ART also utilises two other types of active grading, GSK-6A and GSK-3A, which are smaller rings with a small amount of active metals present in order to begin any olefin saturation reaction as well as provide additional void space at the top of the reactor. Underneath the grading options, it is recommended to use a layer of ART’s AT724G or AT734G, which can provide olefin saturation, additional void fraction for pressure drop mitigation, as well as a trapping mechanism for silicon (and arsenic), which is another concern with co-processing coker naphtha in a ULSD unit.
Another major concern is that coker naphtha can also bring silicon into the unit, which is a permanent poison for hydrotreating catalyst. A silicon guard, such as ART’s AT724G or AT734G, should be loaded in the reactor to mitigate silicon poisoning. Silicon pick-up is temperature dependent and, at the higher temperatures ULSD units are operating at, silicon pick-up in the order of 16-25 wt% could be expected with AT724G or AT734G. If arsenic is present in the coker stocks, the use of AT734G is preferred, as it will have the same silicon pick-up as AT724G but will also protect the active catalyst against arsenic poisoning.
A third concern is the high degree of vaporisation of the coker naphtha. ULSD hydrotreaters are typically designed such that their feed distribution system will contain liquid, and the additional gas present from the coker naphtha may cause some systems to perform poorly, giving rise to maldistribution. In order to minimise feed vaporisation and poor distribution tray utilisation, the coker naphtha should be mixed with the other feed streams at a temperature where it is still liquid before feeding to the charge heater. The recovery system should also be evaluated for the increase in naphtha that will be present so that the downstream equipment is not overloaded.
A final consideration would be that additional coker naphtha in a diesel can generate incremental dry gas products such as methane and ethane. These products will increase in concentration in the recycle gas loop, causing a decrease in the hydrogen partial pressure for the hydrotreater. It will also increase the molecular weight of the recycle gas, which can lead to compressor capacity limitations. These additional products can also lead to incremental stripper off-gas and related problems.
Processing shale-derived crudes
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 optimise the distillate hydrotreater(s) with these light, sweet crudes?
Greg Rosinski, Brian Watkins and Brian Slemp, Advanced Refining Technologies, Chicago, IL
The processing of highly paraffinic crudes can pose difficulties with various product grades meeting specifications such as cloud and pour point as well as cold filter plugging point. In these cases, where the refiner’s market demands for meeting a more stringent specification, changes to the hydrotreating operation may require the combined system of a catalytic dewax catalyst in ULSD/Jet/Kero hydrotreating or some form of mild hydrocracking in heavier applications in order to limit the longer paraffinic chains.
In refineries designed with higher hydrogen pressures and low space velocities for dealing with more refractory feedstocks, the introduction or switching to lighter paraffinic crudes can experience incremental light end generation. The high horsepower of these hydrotreaters can cause the undesirable reaction of eliminating some of the paraffin chains once the remaining reactions have gone to near completion.
Some crudes from these areas have been known to contain higher quantities of iron than typical, and processing the heavier fractions will require the use of adequate feed filtration in order to prevent fouling and plugging in equipment. The use of additional top-bed particulate trapping materials is also recommended in order to avoid an unexpected skim or turnaround.
The processing of light, sweet crudes can have benefits to a refinery as well, as the demand on hydrotreating performance can be lessened at similar processing rates. It can also allow for additional upgrading of barrels by increasing throughput or, if the process conditions warrant, provide the ability to place additional hydrogen into the feed, allowing for higher distillate yields at the current processing rates.
5. What is the panel’s experience with hydrotreater fouling/poisoning issues arising from processing of synthetic or bitumen-derived crudes? How can the impact be mitigated?
Greg Rosinski, Chuck Olsen and Brian Watkins, Advanced Refining Technologies, Chicago, IL
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