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John Clower (Chevron)

For both gas and liquid service, Chevron monitors the inlet HCL/Total Chloride and replaces the adsorbent/molecular sieve based on material balance loading of chloride on the adsorber media. Chevron does monitor adsorbent outlet HCL/Total Chlorides, but as a best practice will change the adsorbent material before vendor maximum loading if breakthrough has not occurred. Spent adsorbent will become acidic and pass chloride as organic chloride to the downstream processes. Organic chlorides are difficult to detect by conventional tubes in gas service and will form HCL in downstream processing units.

This performance-based approach is not without problems, e.g., the accuracy of both chloride measurements and represented adsorbent capacity, and therefore requires a trial-and-error

approach.

Represented capacity of any chloride trap material will have been set the vendor to minimize high acidity conditions that lead to organic chloride and polymer (red/green oil) production. Commercially there are four main types of chloride adsorbent material available:

•Alumina

•Modified/Promoted Alumina

•Molecular Sieve

•Metal Oxide

 Each of these materials is used in Chevron Refineries and joint ventures. Each adsorbent type will have various properties that can be used in making a decision on application:

•Total chloride capacity (HCL and Organic)

•Reactivity – potential for organic chloride and red/green oil formation

•Interferences (e.g., Sulfur)

•Cost per pound of chloride removed

Also, the design of the vessel used is important (L/D for adequate flow distribution, contact time) and can result in shorten life versus predicted breakthrough. Selection of adsorbent versus service will usually be made on a cost per pound of chloride removed.

Janel Ruby (Johnson Matthey Catalysts)

Chloride can be removed from streams using various products. These chloride guard products can differ in the way they are manufactured and in the way they work in certain applications, so it is important to choose the right one for your needs. The most common products are chemical absorbents or promoted alumina adsorbents. Chemical absorbents remove chlorides by irreversible chemical reaction, meaning that the chloride is chemically bound within the absorbent. Chloride removal in promoted alumina is accomplished mainly by adsorption in which hydrogen chloride is adsorbed onto the alumina surface. Both types of beds are non-regenerable and require change-out at chloride breakthrough.

When determining which product is right for a particular service, it is important to evaluate the operating parameters of the chloride guard bed. The location of the bed in the reforming flow sheet, the operating temperature of the bed, and the normal and maximum inlet chloride levels are important factors to consider when selecting an absorbent type.

Promoted alumina products are available for liquid and gas services. Promoted alumina can work over a range of operating temperatures but chlorides that are adsorbed onto the material may desorb at higher temperatures which will decrease the effectiveness of the product in these regimes. These products also have a lower chloride capacity usually ranging from 12 to 15% wt/wt, and require a high change-out frequency. An area of concern when utilizing promoted alumina materials is the formation of undesirable side products. When the chloride binds to the alumina surface of the guard material, it creates surface acid sites. The acidic surface of the material can catalyze side reactions and lead to the creation of organic chlorides or high-molecular weight hydrocarbons called “green oils.” Green-oils not only foul equipment, but also the guard bed itself, which can cause difficulties in bed discharge (increased purge time) and disposal.

Chemical absorbents are the most favorable option for chloride removal. These products are available for use in liquid and gas services. Chemical absorbents work over a wide range of temperatures. These products have high chloride pick-ups, for example PURASPECJM 2250 is a mixed metal oxide chemical absorbent which can achieve a chloride capacity of 30% wt/wt in non-fouling, gas phase applications. As previously stated, these products remove chloride through an irreversible chemical reaction. The alumina structure present in these types of chemical absorbents acts only as a binder which minimizes the tendency for unwanted side reactions. PURASPECJM 2250 can commonly be employed with the use of just a single guard bed.

There a few other considerations surrounding chloride guard bed materials. It is important to avoid two-phase flow in these beds as this will affect the performance of the chloride guard. Both promoted alumina products and chemical absorbents have a higher pick-up in gas phase, non-fouling and non-wetting applications. In liquid applications, diffusion through the liquid film around the chloride guard particle is the rate limiting step and capacities are generally lower than gas phase duties because of the mass transfer effects. Chemical absorbent products, PURASPECJM 6250 and PURASPECJM 6255 were designed to address this concern. These products have a high capacity and specific pore structure to allow improved removal capacity. They are comprised of the same chemical formulation and micromeritic properties but represent two differing particle sizes; PURASPECJM6255 is manufactured as a smaller sized sphere. The smaller size provides better performance as this minimizes the liquid film through which the HCl must diffuse, reducing the depth of the mass transfer zone and leads to higher average chloride pick at the point of HCl breakthrough.

The presence of HCl or organo-chlorides (RCl) in the exit stream of the chloride guard bed will indicate it is time to change out the material. The life of the guard depends on how the bed(s) is configured and what type of product(s) has been installed. Unless the bed needs to be shut down for inspection or is involved in a larger turnaround plan, chloride breakthrough will be the main reason for a shutdown to replace product. Regular testing for chlorides in the exit stream will help to determine when change out is needed. In applications with longer life cycles (years) testing may only be needed monthly until the bed is getting closer to its expected change-out interval. In applications with shorter life expectancies (months), the frequency of testing should be at least weekly.

Throughout the life of the bed, it is important to measure the HCl and RCl levels both inlet and exit the chloride guard beds. It has been shown that when promoted alumina is used for HCl removal, it catalyses the conversion of HCl to organic chloride species that can then slip from the bed. If the operator is only measuring for HCl then this chloride slip can go undetected until downstream issues occur. Chlorides passing through the bed can cause corrosion of downstream equipment and formation of ammonium chloride that cause fouling and blocking of equipment e.g., stabilizer columns, exchangers and compressors.

JAMES “TIM” CAMPBELL(Eurecat U.S., Inc.)

First, a response to the question: What are typical cascading practices that you employ for catalyst reuse after regeneration and eventual disposal? As the leading catalyst regenerator, Eurecat sees NiMo and CoMo hydrotreated catalysts (regenerated and regenerated plus rejuvenation) in ULSD, jet, kerosene, naphtha, and gas oil hydrotreating units. There is growing use of regenerated hydrocracking catalyst. These regenerated catalysts, or those regenerated and rejuvenated, may be used as an entire load or a partial load, depending on the specific application. Catalyst reuse management can provide substantial savings to the refining organization.

The second question concerned quality control, catalyst properties and performance specifications for regenerated catalysts. Eurecat has specific catalyst regeneration specifications for:

*Contamination metals (such as Si, As, Fe, Ni, V, Ca, Na),Physical (length/diameter, length distribution, and crush strength),

*Pressure Drop (measurement regenerated catalyst pressure drop versus fresh catalyst), and

*Activity (measurement of HDS activity versus fresh catalyst).

LIFENG ZHENG (Criterion Catalysts & Technologies)

Depending on the condition of the catalyst post regeneration, the catalyst can be cascaded to a less severe service [USLD to kero (kerosene), kero to naphtha, etc.] where the catalyst performance is less sensitive to activity. Regen can also be used on non-activity-constrained higher performance units or in units slated for a short cycle due to turnaround planning in, for example, the top bed of ULSD unit. In certain instances, it may be necessary to install some fresh catalyst to make up for a potential loss of activity and volume of the regenerated catalyst.

After a conventional regeneration and depending on the type of catalyst (Type I or II), the catalyst will typically regain anywhere from 70 to 95% of its fresh catalyst activity. Here your catalyst vendor can give guidance on the expected recovery for the particular catalyst. There will be physical catalyst loss due to breakage and attrition of pellets during unloading and regeneration that will need to be taken into account. Part of a catalyst bed that is unloaded may not be suitable for regen depending on the feed poisons and physical condition of the spent catalyst. Contact the regen vendor for additional details regarding warranties and catalyst properties on regenerated catalyst.

Some refiners actively manage a pool of their own regenerated catalyst because they can keep track of the condition of the catalyst based on the service and feed contaminants to allow cascading. Where it makes sense, Criterion works with the refiner to incorporate the regenerated catalyst into the planned loading for the next cycle. In a recent example, we successfully helped a customer transition catalyst from the bottom bed of a ULSD unit which was prematurely shut down into the top bed of a medium severity FCCPT unit in order to assist the customer with maximizing catalyst utilization.

The business case for selecting metals reclamation, regeneration, or disposal is ultimately based on economics. Regeneration is chosen when a use for the regen catalyst is identified within the refinery, if it is needed in the shared regen pool, or if there is a known market for this particular catalyst load and a third party is willing to purchase it. Service history is critical as catalysts with suspected high poison levels are not suitable for reuse. The catalyst cannot be vacuum-dumped, caustic-washed, or otherwise mishandled if it is going to be regenerated.

If the catalyst is not going to be regenerated, then it must either be reclaimed or disposed. Pricing and yield of precious metal could impact returns on metal reclamation. Reclamation companies usually charge a service fee for processing spent catalyst and give a credit for a portion of the metal reclaimed. Depending on the metals market, the metals credit can cover the processing fee; but with current depressed metals pricing, the credits usually do not offset the costs.

Disposal of spent catalyst is rarely done due to cost and potential environmental impacts. The transportation and disposal of spentcatalysts are governed by DOT (Department of Transportation) and RCRA (Resource Conservation and Recovery Act) regulations. The hazardous waste must be properly disposed of at an approved treatment, storage, and disposal facility.

HENRIK RASMUSSEN (Haldor Topsoe, Inc.)

For many years, refiners have cascaded used catalyst from a high severity to a lower severity service within their refinery. In order to do so, the catalyst needs to be regenerated and properly evaluated to make sure the level of poisons on the catalyst is acceptable for reuse in any service. Topsoe has, for many years, offered our proprietary ReFRESH™ technology, which is an add-on to the regeneration procedure. The ReFRESH™ process will restore the catalyst to 95+% of its original fresh activity, thus enabling the refiner to use the ReFRESH™ catalyst in the same service from which it was removed without any noticeable penalty in performance or cycle length.

In order to ensure that the spent catalyst is a good candidate for regeneration, as well as a candidate for the ReFRESH™ technology, we have generated the following guidelines. The spent catalyst should meet the following criteria:

*Surface area greater than 80% of fresh catalyst surface area,

*As(arsenic)lessthan0.1wt%,

*Pb (lead) less than 0.15 wt%,

*Na (sodium) less than 0.3 wt%,

*Si (silicon) less than 1.0 wt%, 

*Fe (iron) less than 1.0 wt%,

*No other metal [Ni(nickle), V(vanadium), etc.] higher than 1.0 wt%,

*Total contaminant level less than 2.0wt %,

*Average length of particle higher than 3.0 mm(milliliters) for 1/20” TL (transferline), and

*SCS(syntheticcatalysticscavenger)higherthan2.5lbf/mm (pound-force foot to Newton millimeter).

Catalyst with contaminant levels higher than shown above should be set aside and sent for reclamation, because it is not economically justifiable to spend money on regenerating and investing in ReFRESH™ technology for this material. Every year, Topsoe applies our ReFRESH™ technology to millions of pounds of regenerated catalyst, which are used again in high severity hydro treating applications such as ultra-low sulfur diesel and FCC pretreatment. Many of our clients have used the same catalyst up to three times.

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.

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.

MELDRUM (Phillips 66)

Promoted or multi-metallic reformer catalysts have been a topic of research since at least the early 1970s. They have been tried commercially in various forms over the years, all with the objective of improving yields by suppressing the demetallization reactions. The current promoted catalysts have advanced the formulation of manufacturing techniques to new levels of performance. Recently, Phillips 66 has selected promoted catalysts for future reloads in at least three of our sites. The additional cost of the catalyst is justified when considering increased product yield and improved activity that allows a lower reactor temperature requirement, which both provide for a very quick payback on the additional catalyst cost.

The example shown on the slide indicates the additional yields – both in the C5+, as well as hydrogen – and some improved activity that might be expected with a promoted catalyst. When selecting the promoted catalyst, regeneration procedures should be reviewed with the catalyst vendor to ensure that maximum catalyst performance from regeneration to regeneration is achieved, particularly in the area of reduction and dryout steps.

BULLEN (UOP LLC, A Honeywell Company)

We have two catalysts that we offer in the semi-regenerator market and also for cyclic reforming applications. One of them is the R-98 catalyst that was introduced in 2005 and which has over 50 installed applications. We have a new catalyst called R500 that has better activity and stability, and we have put it in 10 units. As Craig said, proper regeneration procedures are very important for any semi-regeneration unit, and maybe even more so for these tri-metallic systems, because of the issues related to dryout and reduction. It is important to get consistency with this procedure because you will lose the advantage of the tri-metallic system if you do not do the dryout and reduction correctly. Getting that repeatability is very important.

CRAIG MELDRUM (Phillips 66)

Regeneration procedures should be reviewed with the catalyst vendor to ensure maximum catalyst performance from regeneration to regeneration. For example, UOP R-72 was a promoted catalyst offered about 15 years ago and required a different reduction procedure than the non-promoted catalyst for hydrogen concentration, pressure, temperature, and dry-down schedule.

PATRICK BULLEN (UOP LLC, A Honeywell Company)

Trimetallic catalysts containing rhenium are typical for use in fixed-bed reforming applications, both semi-regenerative and cyclic reforming applications. In recent years, both additional metals and oxides have been added to platinum-rhenium reforming catalysts. Metal promoters have been added to increase selectivity and product yields. The additional metal partially suppresses platinum-rhenium activity, reducing metal-catalyzed hydrogenolysis that lowers selectivity.

Over the past decade, UOP successfully developed the proper catalyst base, formulations (including promoter type), and manufacturing techniques needed to generate catalysts that demonstrate excellent yield stability and regenerability. UOP’s R-98 catalyst was introduced in 2005 and has over 50 successful applications with many regeneration cycles, and our customers are benefiting from the higher yields. UOP recently introduced a new product, R-500, that shows even great activity and stability, with over 10 commercial applications. It is well suited for reforming units where even longer cycle lengths are desirable or where higher activity is needed to push more barrels. The gradual acceptance of promoted catalysts is analogous to that of the bimetallic catalysts having higher rhenium content that preceded them in this market.

Proper regeneration procedures are critical for the success of any semi-regeneration catalyst; and in particular, promoted formulations that have reduced metal activity. One Best Practice is to ensure proper dry-down, reduction, and sulfiding. Cyclic reforming applications are a little more demanding due to the regeneration environment (higher moisture and sulfur, for example), but new promoted formulations have been demonstrated in these applications as well.

SONI OYEKAN (Prafis Energy Solutions)

This question needs some more definition to elicit appropriate responses with respect to what is truly a “trimetallic” catalyst. My initial response is that my experiences in the use of “trimetallic” platinum-rhenium catalysts for fixed-bed cyclic regeneration reformer operations were good. The catalysts performed as projected by the catalyst and technology supplier for catalysts containing a third metal that was specifically added for modifying the acidic functionality of the catalysts.

Having written that, it is important to understand the type of catalysts commonly referred to as “trimetallic” catalysts. The term could cover Pt/Re (platinum/rhenium) catalysts with a third metal as a modifier for the alumina to moderate the acidic functionality of the catalysts or those in which the third metals are added to modify the hydrogenation functionality of the platinum or to moderate rhenium hydrocracking activity. In other trimetallic catalyst formulations, the third metal can work in conjunction with the rhenium as co-promoters for the platinum functionality.

The performance objective of the third metal is crucial in order to assess long-term performance and benefits of the third metal. Metals on catalytic reformer catalysts typically undergo varying degrees of reduction to different oxidation states at different temperatures and adequate metals redispersion are achieved at different oxidative conditions. Trimetallic catalysts’ expected performances and potential limitations should be well understood by oil refiners before acquiring them for use. Catalyst suppliers should provide test data to show multiple regenerations and adequate reactivations of the three metals, even if the other two metals are acting as co-promoters for the platinum. Another key factor is to ensure that optimal metals distributions are achieved during catalyst manufacture. There are other factors to consider that are beyond inclusion in this short response on trimetallic catalysts.

If the third metal has been added to moderate catalyst acidic functionality and reactivation of that third metal is not an important factor other than decoking, then the refiners’ challenges are lessened to some extent. It should be recalled, however, that the history of catalytic reforming is dotted with an oil refiner’s experiences with second metals that had been added to the platinum and which led to significant performance problems. The problems were related to inadequate metals activation, especially poor redispersion of the promoter metals, and these problems led to poor catalyst performance for subsequent cycles after the first cycle for fixed-bed catalytic reforming systems. Furthermore, in reforming catalyst development programs, the addition of metals to Pt/Re catalysts led to increased feed sulfur sensitivity challenges for the resultant trimetallic catalysts. Feed sulfur sensitivity and catalyst regeneration challenges should be studied sufficiently by the catalyst and technology supplier during that supplier’s catalyst development studies leading to the production of “trimetallic” catalysts.

LIOLIOS (DuPont Clean Technologies)

The highly paraffinic nature of the tight crudes and the destabilization of asphaltene molecules can cause precipitation and agglomeration. One of our customers with a gas oil mild hydrocracker switched feedstock to increase amounts of black wax crude. This was a five-reactor system. A guard bed reactor was first, followed by four other reactor beds. In the polishing reactor bed, this customer saw an increase in pressure drop. It was theorized that this pressure drop was caused by asphaltene precipitation and polymerization in the bed.

The following graphs show some of what was happening at this unit. It is a constant feedstock. They raised the temperature to get some additional cracking. You will notice an elevated pressure drop in the last bed shortly after they increased the severity of the unit. If you look at the next chart, you can see where they decreased the severity of operation of the unit and the pressure drop recovered. Our theory is that there was a recombination of those asphaltenes.

SHARPE (Flint Hills Resources, LP)

We have had no second and third bed ∆T problems when running high rates of Eagle Ford crude. When there were high bed ∆Ps in the lower treating beds, they were usually a result of coke fouling due to hydrogen starvation, and low hydrogen partial pressure.

GLENN LIOLIOS (DuPont Clean Technologies)

The highly paraffinic nature of tight oil crudes, and the potential increase in asphaltene precipitation when these crudes or cuts of these are mixed with polar asphaltenic oils or cuts, has been well documented. The increase in paraffin content can lead to destabilization of the asphaltene core which can then agglomerate to form larger macromolecules that may precipitate out under hydrotreating conditions.

A number of published documents2 detail the causes and reactions behind this phenomenon and outline methods to determine which crude type and cuts are compatible and what ratios are required to minimize the chance of this phenomenon occurring.

Much of the industry experience indicates that asphaltene precipitation and fouling in process units normally occurs in regions of high heat flux when agglomerated asphaltenes easily crack or dehydrogenate leaving coke-like deposits such as feed/effluent exchangers or where hydrotreater reactions are initiated; i.e., the top bed of a hydrotreating reactor. However, it was observed that a gas oil mild hydrocracking unit experienced a noticeable increase in pressure in a final polishing reactor after the feed to the unit was switched to process a feed that had been mixed with an increased percentage of highly paraffinic (black wax crude) feedstock. At the same time, the severity was increased by lowering the throughput without reducing inlet temperatures. The polishing reactor was the last in a series of five reactor beds, the bed being a separate bed reactor. During the observed increased pressure drop in the polishing reactor, no appreciable pressure drop was observed in the guard bed or main reactor beds. It is important to point out that after the space velocity and feedstock to the system were normalized, the pressure drop decreased almost to the baseline range prior to the event.

It is theorized that the observed bed pressure drop increase in the last bed was a result of asphaltene precipitation and polymerization on the bed that occurred after increased severity reactions cracked the smaller molecules that kept the increased asphaltenes in solution. According to work conducted by Wiehe on asphaltene precipitation3 , asphaltenes are maintained in solution in oil by a micelle type of configuration. This theory has been also explained by other authors4 . The asphaltene core is surrounded by a solvated shell that consists of resins. Resins are molecules with aromatic and naphthenic rings.

Under high severity conditions such as those experienced in this mild hydrocracker operation, the resins can crack into smaller molecules. This can disrupt the micelle type configurations at which asphaltenes are kept in solution, and the asphaltenes can precipitate upon cooling.

Analytical tests carried out on the hydrocarbon feed samples indicated that the asphaltene content (heptane insolubles), although low in comparison with a heavy residue5, was found to be approximately three times higher than the one on the sweet GO FCC feed sample that was being recirculated to the unit and the regular GO sample fed to the GHC.

This theory explains why the upstream reactor beds did not experience a corresponding increase in pressure drop. If it were due to deposits, catalyst fines, or simply rust from upstream units, the first two reactors should have acted as filters preventing the last bed from getting plugged-up.

JUAN ESTRADA (Criterion Catalysts & Technologies)

Two primary mechanisms for pressure drop in bottom beds are coking and asphaltene precipitation. Coking results from operation at elevated temperatures and hydrogen deficiency. Asphaltene precipitation results from a reduction in liquid solvency. The design of VGO hydrotreaters with elevated pressure, low space velocity, and high treat gas rates helps minimize coking; however, elevated saturation of aromatics reduces the solvency of the oil, increasing the potential for asphaltene precipitation in the catalyst bed.

Processing tight oils in the crude diet reduces the aromatic content of the gas oils. For this reason, the coking potential of the feed is lowered, but the potential for asphaltene precipitation increases. With lower feed aromatics and severe hydrotreatment, the solvency change may be sufficient in the lower catalyst beds to precipitate asphaltenes introduced with the other gas oil components from conventional or synthetic-derived crude sources.

The mechanism of asphaltene precipitation from a reduction in liquid solvency has been connected to many historical pressure drop problems involving changes in operation and feedstock qualities such as aromatic and C7/C9 asphaltene contents and the distillation tail. Applying this accepted mechanism to lower bed pressure drop problems in units processing tight oil derived gas oils logically explains recent pressure drop problems in a few VGO hydrotreaters. Refiners continue to learn compatibility limitations of co-processing tight oils in the crude diet, including impacts on VGO reactor pressure drop growth has become a consideration.

CHRIS STEVES (Norton Engineering)

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.

Modification of a butylene-only alkylation unit to handle larger volumes of propylene may involve significant capital modifications to add or expand the capacity of C3 handling equipment. Examples include the depropanizer, C3 defluorinations (in HFalky units), and refrigeration equipment (for sulfuric acid alky units). With sulfuric acid alky plants, consideration will also be required for treating the reactor hydrocarbon stream before fractionation. Caustic treating systems may require the caustic circulation rate to increase by as much as twice the butylene-only rate to treat and remove esters from the reactor effluent of a propylene alky unit. In addition, the temperature required to break down these esters in the caustic treater will need to increase, potentially as much as 40°F above current operating temperatures, due to the higher stability of esters in the reactor effluent of a propylene alky unit.

In sulfuric acid alkylation units, separate reactors for propylene-rich and butylene-rich streams can help in managing acid consumption, as the different feedstocks respond differently with regard to acid consumption at different acid strengths and operating temperatures. A strategy of processing a propylene-rich stream in the high strength reactor and the butylene-rich stream in the low acid strength contactor can help to minimize overall unit acid consumption.

In addition to alkylation unit modifications for propylene alkylation, the alky feed treating will need to be reviewed to ensure that the sulfur is adequately handled and that C2is properly stripped from the alky feed stream. For addition of propylene feed, removal of H2S (hydrogen sulfide) with amine and/or expansion of the caustic pre-wash equipment should be considered so as to not negatively impact the operation of the mercaptan removal system with the production of non-regenerable sodium sulfide.

Addition of amylene to alky feed may also typically require modifications to the alky unit equipment. The extent of the modifications will depend on the desired level of amylene. Some considerations include the following:

In sulfuric acid alkylation units, amylene alkylation can be safely practiced at lower acid strengths than with propylene or butylene alkylation. With a separate reactor for amylene processing, the overall acid consumption on the unit can be minimized by allowing the final spending strength to fall lower than what would be practiced with butylene alkylation.

In sulfuric acid units, amylene alkylation is more sensitive to temperature than butylene alkylation; but with limited propane in a separate amylene reactor, the desired lower temperature may be difficult to achieve. Modifications to the refrigeration system may be required to optimize the individual reactor sections with regard to operating temperature.

In both sulfuric acid and HF alkylation, introduction of amylene feeds will increase production of isopentane through hydrogen transfer reactions (although at higher rates in HF alkylation). Removal of isopentane from alkylate may require fractionation changes in the alky unit. The isopentane production can be minimized through recycling of isopentane from the fractionation section back into the reaction zone, but this process would require additional fractionation equipment.

Amylene alkylation will also require a review of the alky feed treating system. Introduction of heavier feedstocks to the mercaptan treating section may impact the overall sulfur of the alky feed (which will then impact acid consumption), as the heavier mercaptans are more difficult to extract. Introduction of heavier feedstocks to the alky feed can also bring undesirable species into the alky feed, such as cyclopentane and diolefins which consume acid at a significant rate. While cyclopentane can usually be excluded from the alky feed via upstream fractionation, treatment of diolefins may require separate reaction systems to remove them from alky unit feed.

KURT DETRICK (Honeywell UOP)

The issues in an HFAlkylation unit are different for propylene and amylenes.

For Propylene:

The types of contaminants and the concentrations of those contaminants that must be removed in the feed pretreatment section is not much different from butylene. The one difference is that there can be some ethane and ethylene that comes in with the propylene feed. Ethane tends to act as a Non condensable and requires venting from the depolarizer overhead system, which will cause increased acid losses. Ethylene does not react with iC4 in the HF alky unit but tends to make ethyl fluoride, which will cause higher organic fluoride content in the untreated propane and resulting in higher alumina consumption in the propane defluorinations.

The operational issues with propylene are primarily increased consumption of isobutane and propane rejection. The increased isobutane consumption is due to the fact that about 20% of the propylene will undergo a hydrogen transfer reaction where one molecule of propylene will react with two molecules of isobutane to produce one molecule of propane and one molecule of isooctane (C8 alkylate). This reaction actually helps improve the alkylate octane, but it causes a somewhat higher consumption of isobutane than might otherwise be expected.

The propane rejection issue is often the controlling factor in how much propylene feed can be handled in each particular unit. There is a limit to how much propane the fractionation and stripping columns can handle, and that limit is dependent on the specific unit design. One problem that can occur as the amount of propane coming though the unit increases is that the concentration of propane in the main fractionator or isostripper overhead vapor increases, causing a decrease in the condensation temperature, and this temperature reduction can “pinch out” the overhead condenser, thus limiting the available cooling duty of this exchanger.

For Amylenes:

The types of contaminants present in the amylenes are a little different from the propylene and butylene feed. Also, the concentration of contaminants such as sulfur and diolefins is higher. These changes can require adjustment of the operation–or even the design –of the feed pretreatment units. For example, the heavier mercaptans that co-boil with amylenes have a lower solubility in caustic, and they tend to be present in higher concentrations; therefore, a higher caustic circulation rate may be required for the mercaptan extraction unit in the feed pretreatment section.

Amylenes can also undergo a hydrogen transfer reaction in which one molecule of amylene will react with two molecules of isobutane to produce one molecule of isopentane and one molecule of isooctane (C8 alkylate). As with the propylene hydrogen transfer reaction, the amylene hydrogen transfer reaction actually helps improve the alkylate octane; however, it causes a somewhat higher consumption of isobutane. The amount of amylene that undergoes this hydrogen transfer reaction depends on several factors and can be anywhere between 30% and 60%.

The isopentane that results from feeding amylenes (both in the amylene feed itself and that which is produced by the hydrogen transfer reaction) can cause the alkylate to have a somewhat higher Reid Vapor Pressure (RVP). It may be necessary to draw some of the isopentane out with the n-butane product if a relatively low RVP alkylate product is desired.

For Both Propylene and Amylenes:

The octane number –both RON and MON (motor octane number)–of the C7 and C9 alkylate that is produced is about 5 to 10 numbers lower than the RON and MON of C8 alkylate. So, higher concentrations of propylene or amylene in the feed will decrease the alkylate octane if all other variables are held constant. Of course, if the addition of propylene or amylene to the feed results in more total olefin in the feed to the unit, the isobutane-to-olefin ratio may decrease, which will cause lower alkylate octane and higher ASO production.