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Olivier Le-Coz (Axens)

More severe regulation in term of Benzene in the gasoline pool can lead to increase the Benzene content to the C5/C6 isomerization unit. This can happen in two different ways.

The refinery process operation can be modified to decrease the benzene precursors content in the heavy naphtha to the Reformer. This is achieved by increasing the light naphtha end point in the topping lights ends naphtha splitter, light naphtha being the Isom unit feed. At the same time C7+ in the Isom feed must be limited to 2 – 3 vol% as those products will undergo undesired hydrocracking reactions in the Isom reactors. With such a scheme, straight run naphtha Benzene (native Benzene) is basically treated in the Isom. This approach can typically be applied in the frame of a new project.

When the “pre-fractionation” scheme cannot be implemented or if it cannot allow reaching the overall pool Benzene specification, a “post-fractionation” option can be implemented. It consists in splitting the reformer product and recover a light Benzene rich reformate which will be treated in the Isom unit in blend with the light straight run naphtha. Depending on the Isom unit existing configuration, some modification to the hardware may be required or not. As a matter of fact, Benzene concentration at the Isom reactors inlet should better not exceed certain value to ensure proper operation and performances of the Isom catalyst (about 4 vol%).

-If the Isom unit is equipped with a recirculation, the recirculated stream acting as diluent may allow maintaining Benzene below the desirable value at the reactor inlet. The extra Benzene amount in the feed will be hydrotreated by the Isom catalyst without disturbing too much the operating conditions and without preventing suitable isomerization rate to be achieved.

-If the Benzene content at the inlet of the reactors cannot be maintained low enough (too low or no recirculation), a dedicated Benzene saturation reactor must be added.

In the case of new units implementation, those schemes have proved to work very well. In the case of revamp projects, existing equipment modifications or idle equipment reuse, a through basic design study upfront including the catalytic aspects is strongly recommended.

Brad Palmer (ConocoPhillips)

In general, refineries with C5/C6 Isomerization units or Aromatic Extraction units have increased feed rate and/or benzene content to these units. Reformer octane has gone down due to ethanol blending but, in most cases, Isom octane demand has remained strong. The primary successes include implementing these projects safely and achieving our benzene reduction requirements. Additionally, heavy reformate blend qualities have improved which has made blending premium gasoline easier and has provided additional opportunities for blend component sales.

A number of technology options were chosen by ConocoPhillips refineries to meet benzene regulations according to the existing configuration and site economics. These options include revamping Aromatic Extraction Units (AEUs) to increase feed and benzene production capacity, sending light reformate or heart cut to other AEUs, modifying C5/C6 Isom units to include benzene saturation reactors, new benzene saturation unit construction, reducing benzene production through prefractionation and use of credits.

All completed projects are working, some with very few operating problems and a few with requiring design modifications and/or operating changes. Operating, design and reliability issues continue to be worked to improve unit performance; a few specific examples are provided below.

Isomerization Unit Challenges

-When all benzene saturation reactors are complete, two will have Pt catalyst and four will have nickel catalyst. One of the reactors will have changed from Pt to Ni.

-The units that added a benzene saturation reactor in front of their Isom reactors have had challenges controlling temperatures profiles of all three reactors especially when liquid recycle is added or removed.

-Isom units have heavier feeds (increased X-Factor). One unit has and XF of 30 lv% average (35 lv% highest) and 9 lv% Benzene Average (10 lv% highest). Another unit has an XF of 25 lv% average (27 lv% highest) and 5 lv% Benzene Average (10 lv% highest).

-Determining when and how much liquid recycle is necessary for safe operation while maximizing fresh feed throughput has taken time. Vendors advertise an upper benzene level of 5 lv% to the inlet of a benzene saturation reactor. While we have gone a little higher by lowering the inlet temperature to accommodate the exotherm, this is a good rule of thumb.

-Increased unit rate can impact dryer operation by fluffing up-flow desiccant beds. Higher rates increase HCl loading to existing caustic scrubbers; less than adequate neutralization can lead to corrosion problems.

-Benzene saturation catalyst has been deactivated or poisoned by feed (organic sulfur, H2S, FeS, Chlorides) or hydrogen purity (CO and CO2) problems.

Aromatic Extraction Unit Challenges

- Changes in feed quality have required operations to find new equilibrium; one unit has reported bigger swings in aromatic content with new feed streams.

- Stripper foaming has occurred in one unit.

Ujjal Roy (Indian Oil Corporation)

In India, the benzene specification in gasoline is 1 vol.% max. In order to meet this specification, number of changes in the refinery configurations have been done. (a) Light Naphtha splitter has been introduced to produce C-5 & C-6 isomerization feed. (b) Naphtha splitter modified to reduce Benzene precursor from Reformer feed Naphtha. (c) Reformate splitter has been installed to separate Benzene from the Reformate. Over and above FCC gasoline being a component of Gasoline, for reduction of Benzene, a FCC gasoline splitter has been put to take away the Benzene rich cut called Heart Cut from Gasoline. For meeting benzene regulation in the Gasoline, Isomerisation unit has been designed with catalysts having dual functions – Isomerisation and complete saturation of Benzene. The metal sites are used for saturation of benzene and acid sites are used for isomerisation of C-5/C-6. Up to 9.8 vol.% benzene in feed, catalyst is able to saturate to nil level of benzene in isomerate.

Erik Myers (Valero)

The Valero approach has been to consolidate the benzene rich streams from various refineries and capture benzene as a product stream. This has been accomplished through use of a side draw stream from the reformate splitters and then feeding these streams through a centralized benzene extraction unit.

Olivier Le-Coz (Axens)

The countermeasures to pressure drop build-up in naphtha hydrotreaters units obviously depend on the cause of the fouling. The two main causes that we know in Naphtha HDT units of are corrosion particles usually coming from outside the battery limit and gums or coke. Axens addresses those two issues at design stage.

Corrosion particles are a potential problem and we indeed address that by implementing both feed filters and grading beds. Feed filters are specified as mechanical filtration devices, usually using metallic cartridges. We don’t have experience with magnetic filters.

As regards grading, Axens uses in its new unit's design or in catalyst replacement loading diagrams a wide range of products from inactive and high void fraction materials to lower void fraction and active products which can also address the removal of specific contaminants. Grading materials have proven to be efficient against particles in many cases. Grading arrangement can be studied on case-by-case basis and when relevant. Axens can propose arrangements of newer generation high void fractions and various pore size materials called CatTrap.

The gums and coke is a problem with units treating olefin and especially diolefins rich feeds from FCC or Coker Naphtha. The important considerations when designing a unit to treat such feedstocks are:

- avoid storing these materials but treat them directly from fractionation columns.

- foresee the injection of an antioxidant chemical if storing cannot be avoided.

- avoid hot spots in the heating system that would cause diolefins to polymerize, optimize the feed preheating scheme to avoid the use of a fired heater, or to reach the full vaporization point ahead of the heater.

But the most efficient way to stay away from gums pressure drop issues is to implement a selective hydrotreating reactor upfront the main HDT reactor. At low temperature and using a dedicated selective hydrotreating catalyst this pre-treatment reactors eliminates the diolefins without giving them a chance to coke further downstream in the process in the heater or at the top of the main and more active HDS catalyst which operates at higher temperature. Axens has been successfully applying this philosophy in many Coker Naphtha and FCC Gasoline (PrimeG) units. We have successfully revamped diolefins rich Naphtha HDT units with addition of a selective pre-treatment reactor, achieving a dramatic decrease of the downstream equipment fouling rate.

Ujjal Roy (Indian Oil Corporation)

We have much naphtha hydrotreaters (NHT) in our ten refineries, some operate with total straight run naphtha and others with cracked gasoline varying from 10% to 40% in feed. In many of the hydrotreaters, we have experienced run length limitations due to high-pressure drop-in reactors or pre-heat circuits while the catalyst was still active for continued operation. Depending upon the basic design, source of feedstock and its composition, we have feed filters (magnetic or cartridge or candle) in all NHT along with graded bed in few of them.

In one of our NHT processing 40% FCC gasoline, we have both magnetic feed filter and graded bed. But even in this unit, we have experienced pressure drop problem in CFEs due to caustic carry over from up-stream FCC unit. In another unit, where we have added graded bed 3 years back in addition to cartridge filter in feed, we have observed increased run length after addition of graded bed. In another unit, in which we have basket and cartridge filters in series but no graded bed, we had to do three skimmings in four years’ operation. The feedstock for this unit is straight run naphtha comprising about 30% material transported from other refinery by tank wagon. We have, off late, replaced the transportation from tank wagon to pipeline and directionally there is improvement in pressure drop, perhaps due to reduction in oxygen and iron pick-up from tank wagon. In another unit, processing about 10% FCC gasoline, having both cartridge and magnetic filter but no graded bed, skimming had to be done five times in six years. The reasons for the high pressure drop as observed after opening of the reactor bed is found to be central hip created at catalyst top bed. This may be due to some design deficiency. In all our hydrotreaters where we are processing cracked gasoline, we directly route the gasoline to hydrotreater with provision of intermediate balancing tank. All these tanks are nitrogen blanketed. Also, in one of the refineries, we inject antioxidant stored in the tank.

General causes contributing to pressure drop in hydrotreaters are either iron scales or coke/polymers. Iron scales are carried with feed from up-stream equipment like tanks and piping. Magnetic and other filters would be helpful in arresting foulant coming from up-stream units and tanks. Coke and polymers come from CFEs and charge heaters. High olefin content in feed than design and dissolved oxygen picked up during storage will aggravate pressure drop. In some case, we have observed high sodium content in the crusts formed on top bed. The source of sodium is likely carry over from up-stream unit. We have taken additional operating measures in up-stream unit to arrest sodium carry over.

In many instances in hydrotreaters, we have observed spikes in Delta P after restart of compressor subsequent to its tripping. It is suggested by our licensor that this might be due to two phase flow at the start of the compressor carrying coke from CFEs and charge heater to reactor. To avoid two phase flow, they recommended to reduce reactor pressure considerably when starting the compressor and to increase the reactor pressure only when reactor attains 260°C and above.

Where we have coker naphtha in feed, in one of the hydrotreaters, multi-layer grading beds have been used. The selective hydrogenation upfront also acts as guard to hydrotreater.

Most of the pressure drop problems in hydrotreaters are unit specific and might have been overlooked in design stage. Preventive measures can only be determined through careful studying the problem over run length.

Brad Palmer (ConocoPhillips)

ConocoPhillips generally uses graded beds on all our hydrotreating units. Several units also have feed filters. The graded beds are usually adequate for all but the worst cases, in spite of precautions. We have experienced extreme cases of upstream corrosion that have forced us to occasionally skim reactors and clean preheat exchangers, in spite of precautions. The upstream problems were eventually corrected by alloy or chemicals, although we prefer to avoid too many chemicals in the naphtha feeds. The difficulty with iron sulfide in units is that the particles can be extremely small (< 1 micron), so filtration is not always effective. Filtration for the naphtha units is usually cartridge filters.

Another more frequent cause for fouling in our system is polymerization of cracked feed stocks. This is promoted by exposure of the feed (or any feed component) to oxygen in tankage but can also be caused by numerous other polymers initiating factors. Filtration is not often effective at removing the polymers, except for those gums already formed in tankage. Additional polymers form rapidly during preheat, downstream of any filtration. The polymers or gums will foul the preheat exchangers, fired heater and the reactors, if they make it that far. To manage polymers in a naphtha hydrotreater, we prefer to add antioxidant to the cracked stocks as they rundown to tankage and add anti-polymerants to stocks as they are feed to a unit. The chemicals help mitigate polymerization, but do not completely prevent it. We also make sure that the dry point of the feed is reached ahead of the fired charge heater to prevent polymer lay down in the heater, subsequent coking, and potential tube failure.

Erik Myers (Valero)

Valero uses the following key approaches:

1. Filter the feed

2. Aggressively use grading material as our naphtha hydrotreaters are not activity limited

3. Utilize mechanical solutions where they look to be effective, such as trash baskets or pressure drop reducing inlet trays.

A key operating area to focus on is avoiding two phase flow in the charge heater. Liquid in the charge heater can lead to coking which when thermally cycled will transfer this coke to the reactor. Similar transfers of iron scale can take place with upsets in any upstream fractionation towers or other equipment.

This topic was also covered in detail in last year’s Q&A (Gasoline question #35). I recommend referencing the transcripts from that review for more information.

At least one of our sites has had very good success with a chemical treatment program incorporating dispersant and antioxidant components to significantly extend the run length of the feed – effluent exchangers. Feed effluent exchanger fouling was also covered in depth as question #36 from the 2010 Q&A session. The 2010 answers for gasoline and FCC naphtha hydrotreating also provide good information on the impacts of olefins and feed gum and polymerization impacts.

Brad Palmer (ConocoPhillips)

There are a number of vertical RODbaffle® exchangers in ConocoPhillips Reformer preheat service. They have very good heat transfer and excellent reliability. They rarely foul; thus, seldom need cleaning. When polling the network, it was common to hear that a bundle had never been cleaned or never needed repair. Those exchangers cleaned were after multiple turnaround cycles, 10+ years. A Reformer application is provided below along with more detailed technology information from one of our heat exchanger experts.

One of our CCRs installed two very large, vertical RODbaffle® CCR Combined Feed Exchangers in 1996. Both exchangers were 83" in diameter and 40' long. The hot exchanger had a HAT of 60 °F, a CAT of 71 °F, a surface area of 48,500 ft2 and a process duty of ~ 160 MM Btu/hr. The cold exchanger had a HAT of 71 °F, a CAT of 15 °F, a surface area of 47,400 ft2 and a process duty of ~ 145 MM Btu/hr. These exchangers have just been cleaned for the 1st time since they were originally installed in 1999, and only because we wanted to inspect the equipment, not because of fouling or problems.

Over 2500 RODbaffle® exchangers have been installed in numerous process applications since ConocoPhillips patented this technology in 1971. RODbaffle® exchangers have been designed in all common TEMA configurations, having shell diameters in excess of 180" and over 80' long. Feed/Effluent service is the most common application for vertical RODbaffle® exchangers, though there are many vertical RODbaffle® thermosiphon reboilers and gas coolers. Thermal/hydraulic performance of a RODbaffle® exchanger is similar to that of a double-segmental plate-baffle unit on maximum cut and spacing. RODbaffle® offers improved shell-side flow-field uniformity, reduced form drag and flow reversals, lower weight, and reduced shell-side fouling rates when compared to traditional plate-baffled exchangers. Tube-side cleaning for RODbaffle® units is identical to that of plate-baffle units. Shell-side cleaning for RODbaffle® exchangers is normally much easier than plate-baffled exchangers, as shell-side solids collection does not occur in RODbaffle® the way it does in the stagnant flow zones found in plate baffle exchangers. There is typically not a materials spec break inside RODbaffle® exchangers. The support rod and baffle ring materials will generally be the same as that of the tubes to prevent dissimilar material corrosion. In shell-side boiling feed-effluent applications, RODbaffle® offers far superior vibration resistance to traditional plate-baffle exchangers. This is also true in high-pressure shell-side gas cooling applications.

Both HTRI and HTFS have a RODbaffle® option in their respective shell & tube exchanger design programs. Matthew C. Gentry, P.E. wrote a paper for the 1999 NPRA Meeting in San Antonio entitled, Industrial Applications for RODbaffle® Heat Exchanger Technology which provides a great deal of technical information about this technology. The NPRA RODbaffle® paper identification number is AM9

Olivier Le-Coz (Axens)

The potential problems are most of the time located in the columns overhead where some water may condense locally. Corrosion inhibitor injections are systematically foreseen in strippers' overhead columns.

In some cases, essentially in Reforming, we foresee chlorides guard beds at the inlet of the stabilizing / fractionating section.

At some point when the potential or actual corrosion is too severe, especially due to chlorides, the mitigation strategy should go through metallurgy upgrading. In the case of reforming units, chloride guard beds have most of the time proven to be very efficient.

Brad Palmer (ConocoPhillips)

Corrosion in naphtha-hydrotreater stripper or fractionator overheads is usually the result of chloride. Chloride usually comes into a hydrotreater with makeup reformer hydrogen, with naphtha from poorly desalted crudes or with wet naphtha. The chlorides exit the hydrotreater high-pressure loop as HCl. Some HCl is dissolved in the oil and some will be carried by entrained sour water from the cold high pressure separator. Management of the chlorides can take a couple of different forms: management upstream of the NHT and tolerance within the NHT.

Upstream

• Be sure the desalter is working optimally to reduce the chloride load on the crude tower. This should reduce crude overhead corrosion, which in turn helps the NHT.

• Be sure naphtha coming from the crude unit is dry. Entrained water will bring ammonium chloride from the crude overhead. If the naphtha shows any haze, it is probably sufficiently wet to be a problem. You can expect more corrosion products with hazy naphtha.

• For cokers, the same kinds of issues can also apply if the crude is poorly desalted and the coker naphtha is wet; the coker naphtha will also bring chlorides.

• Keep the water-chloride balance correct in the reformer. If you have a net gas scrubber or chloride absorber upstream of the NHT, keep it in service and change caustic solution or sorbent when necessary.

In the NHT

• Good water wash practices in the reactor effluent should help mitigate chlorides which should prevent amine salt formation.

• Do not feed a wet stream from the cold high-pressure separator to the stripper or fractionator. Correct any water separation problems.

• Consider upgrading metallurgy in Stabilizer/Stripper tower overhead to tolerate more chloride.

Erik Myers (Valero)

At minimum, chloride treat the reforming LPG that is routed to a downstream light ends unit.

Praveen Gunaseelan (Vantage Point Consulting)

As mercaptans are sulfur-bearing compounds, they are one among numerous target species for sulfur removal from naphtha or gasoline streams to meet reactor feed or finished product sulfur specifications. Streams that need to be aggressively treated to low sulfur levels, such as naphtha feed to catalytic reformers, or ultra-low-sulfur gasoline product or blend stock, often require hydrotreating, which targets removal of a broad array of contaminants, including mercaptans.

However, there are a number of instances that warrant targeted removal of mercaptans species from refinery naphtha and gasoline streams (generally achieved through mercaptans extraction or sweetening). Some examples are provided below.

For light gasolines with a high proportion of mercaptans sulfur, selective extraction of mercaptans may be a competitive alternative to hydrotreating. For example, light straight run naphtha or FCC light naphtha with a high proportion of mercaptans sulfur may require only caustic extraction to be rendered acceptable as gasoline blendstock. In the case of FCC light naphtha, caustic treating for mercaptans can help avoid octane loss from olefin saturation during hydrotreating.

Light (C1-C6) mercaptans have an objectionable odor and corrosion potential and are prone to accumulate in refinery naphtha and lighter streams. In instances where naphtha is segregated, such as for use as a feedstock for downstream processing, there may be a need to reduce light mercaptans content to render the material transportable, regardless of the total sulfur content. In such instances, caustic sweetening of the naphtha may be appropriate, where the light mercaptans are oxidized to odorless disulfides.

Besides meeting sulfur specifications, gasoline streams may require meeting a mercaptans specification, such as a negative Doctor test. If the mercaptans specification is difficult to achieve through hydrotreating (for instance, due to recombinant mercaptans), mercaptans sweetening of the stream may be required.

Selective hydrotreating of FCC gasoline can result in the formation of recombinant heavy mercaptans due to the reaction of olefinic species with H2S. Depending on the sulfur level, these mercaptans may either have to be extracted (to meet the minimum sulfur specification) or sweetened to disulfide to render the gasoline acceptable as blendstock. Proprietary reagents are typically required in such instances.

For tank inventories or cargoes of gasoline or naphtha that are off-spec due to high mercaptans levels, mercaptans scavengers are typically used to treat the material to specification in a batch/semi-batch setting. Continuous treatment of liquid streams for scavengers is not typically performed because it is uneconomical compared to dedicated treatment processes.

Michael Windham (UOP)

Gasoline and naphtha streams if routed to gasoline pool should meet the following specs: Total S, mercaptan sulfur, Doctor test, CuStrip and Silver strip corrosion. If total sulfur is not required, Minalk Merox can be used to meet all of these specs. However, if total sulfur reduction is required, an extraction Merox should be used.

Of course, mild hydrotreating can also be used if reduction of sulfur is a must. However, for increased flexibility of the hydrotreating severity, a Minalk should be installed on its product.

Brad Palmer (ConocoPhillips)

Besides the obvious need to meet gasoline sulfur specifications, mercaptans tend to be malodorous and some tend to promote fuel instability by acting to aid initiation of gum formation by peroxidation. To deal with these situations, refiners can employ either mercaptan removal using strong caustic (extraction) or mercaptan oxidation that converts mercaptans in-situ to disulfides (sweetening).

Extraction is viable for the lowest molecular weight mercaptans. As the hydrocarbon chain containing the mercaptan group grows, the less water soluble the mercaptan becomes. Extraction efficiency drops off rapidly after ethyl mercaptan. Only lighter gasoline fractions will contain mainly methyl and ethyl mercaptans, (light cat or coker naphtha, C5-C7 paraffins). Heavier gasoline fractions will contain not only heavier mercaptans, but also other sulfur compounds that will neither be subject to caustic extraction nor sweetening.

Extraction can be done on a "once-through" or regenerative basis. Since extraction is equilibrium limited, once-through treating can become costly as only a small portion of the caustic value can be consumed before a significant breakthrough to the finished product occurs. Regenerative extraction processes such as UOP's Merox™ and Merichem's Thiolex™ allow the lightly loaded caustic to be reused. Distillation regeneration as well as oxidation regeneration is available, with oxidation being the most widely employed. However, distillation regeneration is not likely to be used in gasoline extraction as the extraction of heavier mercaptans will be limited by the residual methyl mercaptan content of the lean caustic from the regeneration.

Oxidative regeneration is accomplished using air and cobalt based oxidation catalyst to convert dissolved sodium mercaptide salts from the extraction into disulfide oils. The disulfide oils are nearly insoluble in the caustic and can be gravity separated from the regenerated caustic stream. Merox™ and Thiolex™ use variations of the contact, oxidation, and disulfide separation stages to accomplish extraction. Both technologies employ naphtha wash of the regenerated caustic to re-absorb trace disulfide oil that may be entrained in the lean caustic from the disulfide separation stage to prevent "re-entry" sulfur.

Sweetening is not an option for low sulfur gasolines as the mercaptan to disulfide conversion is done in-situ, that is, the sulfur content of the gasoline does not change. Sweetening can be used after extraction to aid in product stability and odor control.

Malcolm Sharpe (Merichem Company)

In the low-sulfur (< 10 wppm total S) gasoline world, there are potentially three (3) applications where wet treating can be utilized to remove mercaptans from FCC gasoline. Two of these solutions require that a FCC gasoline splitter be installed and the third removes mercaptans from selectively hydrotreated FCC gasoline.

In the case of splitter-derived FCC gasoline, the mercaptans can either, one, be extracted from the light FCC gasoline fraction using caustic-based FIBER FILM® technology (THIOLEXTM/REGEN®) or, two, be sweetened using caustic/catalyst/air-based FIBER FILM® technology (MERICATTM II) ahead of the gasoline splitter to convert the mercaptans contained in the light gasoline fraction into the heavier disulfide oil (DSO) molecule. This DSO leaves with the heavy FCC gasoline destined for the hydrotreater. The suitability of these applications is refinery-specific and is especially dependent on the light FCC gasoline cut-point and gasoline pool blending tolerances with respect to sulfur. The mercaptan extraction method (THIOLEXTM/REGEN®) can also be used to treat light straight-run naphtha subject to the same refinery-specific operating criteria.

Third, in some cases refiners may encounter recombinant mercaptan sulfur in selectively hydrotreated FCC gasoline. The presence of high levels of hydrogen sulfide and olefins at the outlet conditions of the selective reactor can lead to the formation of heavy molecular weight recombinant mercaptan compounds. Rather than increasing hydrotreater severity, at the expense of octane loss and hydrogen consumption, to battle this increase in product sulfur, it can be optimized using EXOMERTM technology which is designed to extract the recombinant mercaptans as they form. In this way operating expense and octane reduction are minimized while reaching target gasoline sulfur specifications.

Praveen Gunaseelan (Vantage Point Consulting)

Nitrogen in naphtha feedstock can be detected using analyzers based on pyro chemiluminescence or electrochemical measurement. Pyro chemiluminescence-based analyzers appear to be more prevalent in the industry and can detect nitrogen levels over a wide range (from ppb levels to several hundred ppm) in a matter of minutes. ASTM D4629 is a standard test method for trace nitrogen detection in liquids based on pyro chemiluminescence.

As refiners increasingly process heavy crudes using cokers, the nitrogen content in naphtha feed to reformers will tend to increase. While conventional naphtha hydrotreaters can theoretically be operated at higher severity to increase nitrogen removal, there are practical limits on such operation due to potential undesirable outcomes, such as higher sulfur levels in the reformer feed due to recombination. Accordingly, preventing high nitrogen levels in reformer feeds may require specialized approaches such as using high-activity denitrification catalyst in a reactor section or a separate reactor. In extreme cases where nitrogen content is excessive and cannot be adequately removed, it may be required to limit the volume of coker naphtha processed in the reformer.

Ujjal Roy (Indian Oil Corporation)

In our refineries, ASTM D4629 is being mostly used for nitrogen detection. This method can detect 0.3 to 100 ppmw of total nitrogen with good reproducibility. Also, in some units, we are using licensors’ recommended test methods using their recommended apparatus for testing basic nitrogen.

Some naphtha hydrotreaters, having cracked material in feedstock, are designed to produce < 0.5 ppm nitrogen for feeding to reformers. Higher nitrogen level cannot be tolerated to avoid catalyst deactivation and downstream equipment fouling. These units are operated at about 50 kg/cm2 pressure using Ni-Mo catalyst. We are effectively able to control nitrogen within 0.5 ppmw in reformer feed.

Brad Palmer (ConocoPhillips)

The state-of-the-art in total nitrogen detection for naphtha and distillate streams is oxidative combustion with chemiluminescence detection. The standard test method for this technique is ASTM D4629-10. Direct injection of the sample into a vertically oriented combustion furnace will provide the best sensitivity. The reported quantitation limit for this technique is 300ppb.

Naphtha hydrotreaters are very effective at removing nitrogen IF:

1. Loaded with NiMo catalyst,

2. Catalyst replaced before denitrification reactions have stopped due to Si poisoning,

3. A proper water wash system is employed for salt removal upstream of the stripper,

4. Robust NH3 removal occurs in a reboiled stripper,

5. Nitrogen analyses on feed and product is done frequently with a low detection level

Erik Myers (Valero)

In general, Reforming units prefer low levels of nitrogen in the feed. The problem with nitrogen in the reforming feed is the deposition of salt in the cold sections of the reforming unit. Typical locations for salt deposit are cold areas of the recycle gas circuit and the top of the stabilizer system. Most naphtha hydrotreaters operate in a 300 to 700 psig range of design pressures. This means that sulfur removal is essentially 100% while nitrogen removal from the feed is seldom greater than 80%. Therefore, there is always nitrogen in the feed to the Reforming unit. Since the Reforming unit has abundant chloride present the rate of salt deposits is entirely dependent on nitrogen slip through the NHT unit.

At 0.5 ppm nitrogen in the feed each 10 mbpd will produce almost a ton per year of ammonium chloride. The ratio of chloride to nitrogen is 2.5 lbs of chloride to 1 lb. of nitrogen.

One best practice that Valero implements is to water wash the reformer recycle compressor when the unit is down to remove the salts that form during normal operation. This prevents imbalance from the sloughing off of salts that may take place during thermal cycles of the unit.

Soni O. Oyekan, PhD (Marathon Petroleum Company)

According to an analytical chemist, nitrogen determination in naphtha can be conducted via the use of an analytical procedure that incorporates an Antek Model 9000. The equipment is interfaced with an auto sampler and computer system containing an Antek 393 software. Nitrogen concentrations as low as 0.1 wppm and as high as hundreds wppm can be measured. Samples containing high nitrogen are diluted with isooctane before nitrogen determinations are made. Samples of isooctane blanks are also used as reference for zero nitrogen.

For the second part of the question, a key requirement is that the refiner has a good analytical procedure for determining nitrogen in hydrotreated naphtha and the response to the first part of this question addressed that challenge. Having established a reliable database and current hydrotreated product sulfur, nitrogen and other data, it is then possible to determine the effectiveness of a naphtha hydrotreater for nitrogen removal or reduction.

It is known that while 99.9 % hydrodesulfurization of organosulfur compounds can be achieved in naphtha hydrotreaters, hydrodenitrogenation (HDN) of organo nitrogen compounds is limited to the range of 75 % to 90 % conversion to ammonia. Therefore, the residual concentration of nitrogen compounds in hydrotreated naphtha is relatable to feed nitrogen and other factors.

The effectiveness of naphtha hydrotreating (NHT) for reducing nitrogen is highly dependent on the type of catalyst used, hydrodenitrogenation (HDN) activity of the catalyst, process conditions, concentration of metal contaminants in the feed, composition of the naphtha mix and the percentage of cracked naphtha in the naphtha mix and especially the percentage of coker naphtha in the NHT feed mix. Achievable HDN is also dependent on the degree of upgrading of naphtha from unconventional oils in the feed mix to the NHT. In addition, naphtha processing schemes are also important for the effective removal of nitrogen for straight run naphtha and especially for naphtha mixes containing other contaminants such as metals, olefins and dioolefins.

For modest concentrations of nitrogen of <2 wppm in the feed to the NHT and negligible concentrations of metal contaminants such as arsenic and silicon, the processing of the naphtha leads to hydrotreated naphtha with nitrogen in the range of 0.1 wppm to 0.5 wppm. For NHT naphtha feed containing high percentages of cracked naphtha (such as coker naphtha) and high concentrations of contaminants such as olefins, diolefins, arsenic and silicon, HDN could be limited if the concentration of organo nitrogen compounds are higher than 2 wppm with respect to meeting target nitrogen in the hydrotreated naphtha for the refiner.

The following factors are relevant for effective reduction of nitrogen in hydrotreated naphtha

1. Catalyst

For optimizing HDN, NiMo catalysts are usually preferred relative to CoMo catalysts Single reactors, moderate pressures, high quality treat gas and rates, reactor temperatures in the range of 500 to 615 F are used and the high temperature is usually limited by mercaptan reversion reactions. As the organo nitrogen compounds increase as well as other contaminants such arsenic and silicon, stacked catalysts are used in reactors to incorporate demetalization catalysts or metals scavengers to manage metal contaminants that can negatively impact HDN relative to HDS. In order to optimize organo nitrogen reductions, refiners should work closely with technology providers who offer a variety of catalysts and adsorbents for enhancing the effectiveness of the naphtha hydrotreating process for HDS and HDN.

2. Naphtha Processing Schemes

As the concentrations of nitrogen and other contaminants increase in mix naphtha feeds, refiners processing schemes include medium and high pressure stacked reactors, and multi stages of reactors (two and three reactors) to manage unsaturated compounds and metal contaminants in order to enhance HDN of the naphtha. Several catalysts are then used for effective reduction of organo nitrogen and other contaminants metals, sulfur, olefins and diolefins. As indicated, your technology provider companies will be pleased to support your efforts and plans.

3. NHT Stripper

As part of the reference database, the NHT stripper operations should be checked and determined to be operating as designed. Upsets in the NHT Stripper would also falsely suggest ineffective naphtha hydrotreating and high nitrogen (NH3) in the hydrotreated naphtha and in those cases high sulfur (H2S) and possibly water would also be carried into the catalytic reformer.