Question 58: What issues are experienced at the desalter and pre-heat train when recirculating brine at the desalter?
SHENKLE (Flint Hills Resources, Ltd.)
Before answering this question, I want to clarify that the panel has defined ‘recirculating brine’ as brine going back to the freshwater makeup. For example, it may be used when insufficient makeup is available to maintain recommended washwater rates. We do not recirculate brine. We inject makeup water upstream of the second stage mix valve. Second-stage brine is pumped back to the first stage upstream of the mix valve, and then the first-stage brine is effluent. We operate washwater rates that are typically in the range of 4 to 5%.
SLOLEY (CH2M Hill)
Brine can be recirculated at the desalter. Additionally, there are some plants that recirculate brine found upstream in the heat train network. This is used in plants that have insufficient water to get proper contacting across the mix filter and which are often trying, in extreme cases, to move even from 2 or 3% water up to around 4 or 5% water. Since the freshwater rate does not increase when you do this operation, if it is more effective, you will increase the solid content of the brine. After all, that is the objective.
In some units, problems can arise due to oil and water emulsification because the pump that needs to recirculate this water – if you have oil in it – is a great mixing device. If the brine does not effectively de-oil, this water will recirculate and could cause problems with the rag layer in the desalter. Additionally, if the soap content of the water is high, you will get emulsions forming. With higher total water rates in many of these desalters also, the total water residence time is reduced, making the oil and water emulsions more difficult. The downstream exchange of equipment fouling and corrosion rate should be lower. If it is not changed or gotten worse, you should stop the brine recirculation.
HODGES (Athlon Solutions)
We are huge fans of recycling brine. In most cases, it is the Best Practice to increase the effectiveness of your desalter by increasing the effective washwater percentage through brine recycle, which will drive optimum desalting. As I mentioned earlier, one of the key items that is often overlooked when doing this is your seal flush. Make sure that you do not use the recycled water for your seal flush because it will erode your seal. Use fresh water. This may be subtle to some and obvious to others. Make sure that when you are recycling, you are not replacing your fresh water with recirculated brine. Recirculating brine is only used to add more effective percentage washwater. If you back out the freshwater, you will be taking a step back in effective desalting and contaminant removal across the desalter.
TOM COLLINS (Forum Energy Technologies)
Recirculating effluent water back to the desalter can improve efficiency by increasing water droplet population, allowing for larger droplets and faster settling. When recycle water is used, it is typically injected just before the mixing valve, not into the pre-heat train. It is also recommended that you divert the recycle when mud-washing unless a continuous mud-wash is used. Additional water volume may also allow for improved mixing efficiency, due to an increase in the water droplets created in the mixing valve or emulsification device. Care should be taken not to recycle water high in oily solids or other emulsifiers that may help stabilize interface emulsions and increase BS&W.
GLENN SCATTERGOOD (Nalco Champion Energy Services)
It is important to recognize the benefits of desalter washwater recycle, which improves dehydration and leads to improved salt removal. A higher rate of desalter washwater may also increase solids removal when processing high solids crudes.
DENNIS HAYNES (Nalco Champion Energy Services)
Recirculation of brine is a very good strategy to increase washwater to the desalter while minimizing effluent flow to wastewater treatment. The issues that may be experienced during this recirculating brine include a potential reduction in solids removal due to sending desalter effluent containing some solids through a pump motivating the flow back to the combined washwater inlet. More so, an issue is that if there is any upset or degree of oil in the effluent, the shearing action of the recycle pump will tighten the effluent emulsion. This emulsion, combined with the washwater into the raw crude oil which is then emulsified via the mix valve, may create interface growth in the desalter to the point that the system upsets. The brine recycle should be used with a non-oily effluent.
PHILIP THORNTHWAITE (Nalco Champion Energy Services)
It should be remembered that if a desalter operation is washwater-limited, the use of a brine recycle is an effective means of increasing the washwater volume and improving both dehydration and desalting performance. However, the operation is not without risk, and there are operation considerations to be made.
First, the recirculation of effluent brine is, in effect, adding salt to the crude oil when the two are mixed together. As a consequence of this combination, if the salinity of the brine significantly increases, the mixture can limit the salt removal efficiency across the desalters, the optimum salt content of the desalted crude increases, and the process efficiency can actually decrease. This reaction can be mitigated to an extent since the increased washwater volume leads to improved dehydration and desalting efficiency. Additionally, any increase in overhead chlorides can be mitigated to a degree through good monitoring and caustic management practices.
The other major consideration is that any deterioration in the effluent quality can have a significant impact on the whole desalter operation. If there is an upset leading to an oil undercarry, the oily brine will be passed through the brine recycle pump leading to the formation of a very stable emulsion. As this stable emulsion forms part of the total washwater feed, it can lead to emulsion layer growth within the desalter vessel and begin to exacerbate the already upset conditions. Key to mitigating this threat is regular visual checks of the try lines and effluent quality so that any onset in effluent deterioration can be quickly acted upon.
Question 38: What measurements and criteria do you use to decide when to change your gas and liquid chloride absorber material? How do you determine the selection of absorber material?
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.
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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.
Question 14: What is industry experience of using tri-metal (platinum-rhenium with promoter) catalysts?
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.
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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.
Question 35: When processing tight oil crudes, are lower bed pressure drop problems in VGO/resid hydrotreater reactors a concern? If so, what mechanisms explain this issue?
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.
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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.
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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.
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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.