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Joe Zmich (UOP LLC)

UOP has extensively researched the tendency of metal surfaces to promote coke formation. UOP will provide specific recommendations on operating guidelines based on unit design and operating conditions. We are aware of two fixed bed units that have each operated with feed sulfur below 0.05 wppm and experienced coke growth in the reactors. Subsequent operation with a target of 0.15 wppm S successfully prevented repeat coke growth. Most fixed bed reforming catalyst systems must be properly sulfided following regeneration to attenuate the catalyst metal function. UOP has no direct experience with cyclic reforming unit operation as it relates to sulfur management. UOP’s philosophy is to regulate feed sulfur concentration and perform regular feed analysis as well as sampling recycle gas and stabilizer off gas once per shift. In addition to reactor section metal surface passivation and prevention of metal catalyzed coke, sulfur also contributes to inhibiting heater tube carburization.

In general, reactor section coke is metal catalyzed that can be prevented by ensuring adequate sulfur in the feed to the unit. UOP would need to evaluate the specifics of the unit operating conditions and the history of the coke growth to determine the course of action that UOP would recommend to prevent future coke growth in a cost-effective manner.

Rick Grubb (Chevron USA)

We have experience with both carburization and metal-catalyzed coke. In the past, we have had a furnace develop a tube leak and we have collected stringy coke on occasion in other units. We currently manage sulfur in the reformer feeds by either adding DMDS or by removing the sulfur sorbers on the effluent of the NHT’s. The spec is 0.3 to 0.5 ppmw in the feed. This spec is more critical in the lower pressure units and those units inject DMDS into the feed. Some of the older existing semi-regen units don’t have sulfur control other than what is in the product from the NHT. We test the feed for sulfur daily and test the recycle gas for H2S each shift (every 12 hours). For the older higher pressure semi-regen units that depend on the NHT’s, there are occasions were the feed sulfur is non-detectable. In those cases, we feel safe if we have some H2S in the recycle gas. If we don’t detect anything in the recycle gas then we backdown the severity in the NHT’s.

Javier Quintana (Valero Energy)

Sulfur management in reforming feed is essential to ensuring adequate protection from metal-catalyzed coking. However, this is not to suggest that it is acceptable to reduce hydrotreating severity in an attempt to control sulfur slip, as such a practice would generally be associated with slip of other impurities such as nitrogen and possibly metals. Rather, Valero’s best practice is to ensure maximum hydrotreating to remove all feed impurities, sufficient reflux in the hydrotreater stripper to ensure complete stripping of all moisture and hydrogen sulfide, followed by a controlled injection of a sulfiding agent into the liquid feed to the unit.

Our minimum recommended injection rate is 0.3 wt ppm on feed, although higher levels may be necessary depending on unit-specific history. If a unit has evidence of metal-catalyzed coking, including trace levels of carbon build-up on reactor walls between scallops or in other low flow areas of the reactors, then that unit should increase the minimum target level of sulfur injection. Negative yield effects of sulfur are not expected until injection rates are in excess of 1.0 wt ppm, at which level most units (even those at extremely high severity) should be adequately protected. Injection rate should be confirmed with draw down of the level in the sightglass of the vessel or skid containing the sulfiding agent. All reforming units are at risk of metal catalyzed coking, with some units having higher risk than others – we have experienced such coking in relatively high pressure fixed bed units, as well as in moderate pressure CCR units.

If any maintenance work is done in the hot portions of the unit, such as retubing a furnace or even taking a tube sample for metallurgical testing, then the new furnace tubes will lack the necessary passivating layer of sulfur, and may be at higher risk of forming metal catalyzed coke. In such a case, an elevated level of sulfur injection is recommended on restart.

Javier Quintana (Valero Energy)

There are various adsorbents available for effective chloride treating of the hydrogen-rich net gas stream, including activated aluminas, promoted aluminas, and zeolites. Valero has moved away from the alumina products towards a best practice of using the zeolite products, not only for reasons of cost per quantity of chloride removed, but also for ease of changeout and completeness of chloride removal. The alumina products can present certain operating issues, such as:

• Green oil or red oil formation, which fouls downstream compressors, fuel gas system piping and burner tips
• Organic chloride breakthrough, which occurs long before HCl breakthrough, yet is difficult to detect
• Powdering of the adsorbent (disintegration), which can lead to significant compressor reliability and maintenance
• Hydrocarbon freeing requires an extended hot nitrogen strip, as steam out will leach chlorides from the bed, potentially causing corrosion in associated piping

The zeolite products generally do not form the green or red oils associated with polymerization reactions due to acid activity, and can be steamed out without leaching chlorides, which results in faster bed change-out. They are also more effective at removing both organic and inorganic chlorides, whereas the alumina beds pick up primarily inorganic HCl, while forming organic chlorides as the adsorbent chloride loading increases.

Adsorbent change-out timing is best estimated using a chloride uptake calculation, verifying the inlet gas HCl content on a daily basis, and with the gas rate, maintaining a running estimate of the total chloride loaded on the bed. When that estimated level reaches ~90% of the represented saturation capacity of the adsorbent. Since organic chlorides are present, yet are extremely difficult to measure, the uptake calculation is only an estimate. A cross-check of the estimated chloride loading at change-out with samples at different levels of the adsorbent bed can provide feedback as to the ratio of organic:inorganic species in the feed gas, which can be used to adjust the uptake calculation for future treater load

Question 98 What metallurgy are you using for mesh pads in reformer compressor suction knockout drums? How often are the mesh pads inspected and how often are they replaced? Are the same criteria used for mesh pads in product separators?

Rick Grubb (Chevron USA)

We typically use 304 SS demister pads in the refinery and inspect them every 10 years. In reforming service we have been using Tefzel demister pads and have been replacing them approximately every dump and screen due to separator internal inspections. If we go into the vessel we go ahead and inspect the mesh pad, but assume before opening the vessel that the pad will need replacing. The Tefzel pads have greatly increased the reliability such that we don’t find mesh pad pieces in the compressors anymore. We have been contemplating using co-knit pads (synthetic fiber inter-woven with a SS fiber), but have not done so yet.

Edwin Yuh (UOP)

UOP has traditionally included sampling capability in our licensed units when there are multiple reactor systems. For example, a sample point is typically installed at the pretreat reactor outlet before the cracking reactor in hydrocracking units to measure nitrogen slip. Many UOP licensees collect reactor effluent samples routinely. Quite a few recently licensed units are designed as integrated hydroprocessing units processing different feeds with different catalyst systems. UOP has added sampling capability at each stage in the unit so that we can monitor catalyst performance individually to optimize unit operation. Occasionally we have had problems with sampling systems. Over the years, we have made modifications. Several considerations are important in the design of a reactor effluent sampling system,

1)The sample is normally at high pressure and high temperature containing H2 and H2S.

2)The sample is taken at the bottom of a horizontal process pipe.

3)A two-phase sample needs adequate cooling in a cooling water pot.

4)The sample system has an intermediate holding reservoir designed at operating pressure. The holding reservoir has pressure let-down capability to flash the light gaseous components to flare.

5)Proper metallurgy and piping class are used for the entire sampling system.

6)Reliable valves are important that tolerate frequent use.

7)The sample station has adequate temperature and pressure indications.

8)The system should have proper relief considerations.

9)The system should also have various purging capabilities to deal with viscous fluids.

10)Sufficient purging of the reactor effluent sample needs to occur in order to collect a representative sample.

11)The purged liquid is sent to appropriate destinations.

12)The sample system has appropriate back flow prevention.

13)The system should use a closed sample system to avoid environmental release.

14)The sampling system requires a detailed set of operating procedures.

15)The operators require proper training and safety gear when taking the sample.

David Rapavi (HOVENSA)

HOVENSA reviews and re-issues unit operating procedures in accordance with OSHA Standard 1910.119 paragraph (f)(3), which states “Operating procedures shall be reviewed as often as necessary to assure that they reflect current operating practice, including changes that result from changes in process chemicals, technology and equipment, and changes to facilities. The employer shall certify annually that these operating procedures are current and accurate.”

Unit operating procedures are updated throughout the year to reflect any changes from Management of Changes, PHAs, Incident Investigations, and recommendations from operating personnel and subject matter experts. All changes are communicated to the affected employees both at the time of implementation of the change and during procedure recertification.

Unit operating procedures are reviewed and recertified by Operations on an annual basis, and over the years we have used different types of recertification methods to assure our procedures are current and accurate. Some of the methods include reviews of the procedure by subject matter experts as part of their job responsibilities, reviews by training supervisors as part of new operator training, and our current method of reviews by the Operations shift team done during a job pre-task.

Before we execute a unit operating procedure, a job pre-task is done by the Operations shift team, which includes the operators and shift supervisor. During the job pre-task, all the steps of the procedure are reviewed and discussed, what-if scenarios are assessed, and concerns regarding the unit operating procedure are addressed. The supervisor completes a job pre-task form which includes list of attendees, topics discussed, potential reliability or safety problems and mitigation plan. Any procedural changes are redlined, and the redlined version is used to complete the work. After the work is completed, the redlined procedure is submitted by the supervisor to the PSM department which updates the procedure and applies a new revision number and date. All effected operators are then retested on the procedure.

For unit operating procedures that are not executed during the year, the procedures are recertified using the same job pre-task method by evenly distributing them over the operating shifts.

We have found the job pre-task method very effective in not only assuring that unit operating procedures reflect current operating practice, but it also facilitates training and understanding of our relatively inexperienced workforce with approximately 50% of the operating population having less than five years of experience.

Regarding hydrotreating units, the unit process engineer will have the catalyst vendor review catalyst activation and hot hydrogen strip procedures and incorporate all necessary changes by submitting a redlined copy to the PSM department before the job pre-task.

Chad Perrott/Mike Pedersen (UOP)

As a licensor, UOP evaluates operating procedure as part of our Schedule A work process. In other words, the frequency for review is much higher than a typical refiner’s procedural review. UOP considers any significant changes to design configurations and any new catalyst considerations. This is followed by an update to the general procedures in the operating manual we provide to our licensees.

During the procedure review in the engineering stage, UOP focuses on the overall issues leaving the individual numbering/line references to the refiner. This provides a learning opportunity for the refiner's responsible parties (engineers, operators, management) by using the UOP general procedure and developing a procedure specific for the refiner. This insures that the systems of the new unit are understood and site specific considerations are included. The detailed unit specific procedures are reviewed onsite by the UOP startup staff for consistency between UOP's general procedures and the intent of the refiner's developed procedures. UOP startup staff also participate in any procedure revisions learned during startup.

In the event of loading a new catalyst into an existing unit, the same general procedural review is followed by UOP and the refiner is made aware of any changes they must make to insure successful catalyst activation to retain maximum activity.

For operating units, HAZOP reviews also provide a good prompt for updating procedures. HAZOP findings will guide some of the procedure modifications. Feedback from refiner’s is that input from the process licensor is valuable.

ABIGAIL SLATER (HollyFrontier)
Salting typically occurs in the reactor effluent exchangers (shell and tube and fin fans), recycle and net gas compressors, and product stabilizer overhead system (top trays, overhead condenser, etc.). Common monitoring practices on exchangers and fin fans can be tracking exchanger duty, temperature, and delta pressure, all of which indicate increasing fouling. For compressors, the discharge flow, efficiency, and delta head (corrected for gas molecular weight) can all be indicators of compressor fouling. For stabilizer towers, tower delta pressure and similar overhead exchanger monitoring can indicate fouling.

Common practices to mitigate the fouling are to reduce the source of the foulant, which includes reducing nitrogen in the feed and chloride in the products using technologies like chloride guard beds. For compressors, continuous naphtha washes can be effective at managing fouling. For towers and exchangers, online and offline water washes can remove salt formations. In Naphtha HydroTreaters, online water washes can also be effective in removing salt fouling with no major impacts to the unit. In Naphtha Reformers, online washes can also be effective but must be done in parts of the unit where the water will not contact the catalyst (downstream of reactors and recycle compressor). If no online mitigation is possible, the unit will periodically need to be shut down to clean the affected equipment.

THOMAS PORRITT (Chevron U.S.A.)
We find that salt deposits form in the compressors, the reactor effluent fin fans, the stabilizer column overhead fin fans, and the stabilizer top trays (see figure Q8 – 1).  Process temperature is the largest factor in where the deposits are most likely.  There are two approaches the user can take to monitor and mitigate salt deposition. One is proactive the other is reactive.
The user can prevent salt deposition by choosing to operate their process above the sublimation temperature of the salt being monitored.  For exchangers or coolers, the user can also monitor the fouling rate.  For compressors, the user can track compressor efficiency.  Once fouling rate or efficiency have declined to unacceptable levels the user can mitigate with one of the methods described below.
If the user cannot practically monitor the indicators above, there are some additional reactive monitoring they can employ.  For heat exchangers or coolers, the user can monitor the approach temperature and the differential pressure. For compressors, the user can monitor vibrations. For distillation columns, the user can monitor differential pressure and flooding in the top of the column.  These indicators are less effective as they only manifest once salt deposits have begun to impact the process.

Figure Q8 - 1 Common Areas for Salt Deposition

The user has some preventative and reactive options to mitigate the effects of salt deposits in the process.  The best option is to control species that form the salts.  Most users limit nitrogen in the feed because it addresses both the ammonium chloride and the ammonium bisulfide salts.  For compressors, the user can supply a film on the rotors in the form of a coating or a continuous naphtha wash to prevent salts from gaining a foot hold.  For reactor effluent coolers or distillation overhead coolers a continuous water wash can remove the salts before they build up.  For distillation columns a chloride scavenger has been proposed by some vendors.  

For existing units and equipment where continuous washes or coatings are not an option, the user will need to periodically shut down for a water wash to remove the salts when they build up. 
 

DAVINDER MITTAL (HPCL Mittal Energy)
Chlorides have been a long standing issue in catalytic reformer operation. Until a few years ago, the focus on preventing operational problems from the chloride compounds in the catalytic reformer product stream was to remove HCl.  More recently, a growing concern for many refinery operators has become the removal of organic chloride species besides HCl.  These compound are less easy to detect and measure and also less readily adsorbed or absorbed. The effectiveness of the available chloride guard products is limited although significant improvements have been made and are being made to the formulations.

Total chloride tracking and removal presents a different challenge which requires amended chloride guard formulations that can either co-remove HCl and organic chloride compounds or alternatively a combination of two materials, one specific for each problem.

Adsorption of organic chlorides is competitive with other components in the process stream. HCl is more polar than RCl and is likely to preferentially adsorb on many surfaces. Thus the adsorbent may be effective when relatively new while both HCl and RCl are removed. The more efficient HCl removal may occur in the bed inlet zone while RCl removal further down but RCl breakthrough will occur as HCl front moves down the bed and starts to displace RCl as the active surface. 

Many Refiners struggle to accurately measure chlorides in CCR liquid streams/LPG. The best practice is to use detector tubes (say Drager 0.2/A) of correct range for detection of inorganic chloride/ HCl in gas (applicable for H2 and LPG in gas phase). Correct range means, if expected range is 1 ppm for example, detector tube should be of range 0.2 to 5 (preferable) or 10 at Max. Using larger range tube possess the risk of losing accuracy of measurement due to higher measurement interval/least count. 

For both liquid and gas samples, care should be taken to choose appropriate sample container. Suitable metallic bomb with PTFE coating is suggested to avoid chloride interaction with metal and wrong measurement. Sample collection point should be short and copper tubing to be avoided. Ensure that sample point is hot while collection. Perform detection tube analysis as quickly as possible.

UOP 910 method is for determining total chloride in gaseous hydrocarbons or liquefied petroleum gas (LPG) at concentrations ranging from approximately 1 to 1000 mg/ml(milligrams per milliliter) for gas or mass- ppm for LPG(liquefied petroleum gas). Except for fluoride, other halogens present are calculated as chloride. Chloride cannot be determined quantitatively, if sulfur is present at concentrations greater than approximately 1 mass%. 

UOP 930 method is for determining sum of organic chlorides and Hydrogen chloride(HCl) in LPG and Refinery Gas streams at concentrations ranging from approximately   0.02 to 1000 mass –ppm (mg/Kg) for LPG(liquefied petroleum gas) samples or 0.02 to 1000 ng/ml for gas samples. Other halogens present are determined as chloride.

For detection of total chlorides in liquid (applicable for Reformate/Isomerate), ASTM D 7536 is another – uses MWDXRF analyzer to detect chloride content of sample. 

Alternatively, HCl content of liquid sample can be tested by OXY-HYDROGEN COMBUSTION of sample and combustion product are absorbed in a dilute solution of sodium carbonate. The chloride ion in aqueous absorber solution is titrated by potentiometry with standard silver nitrate solution (IFP-9316). 

If liquid phase chloride testing capabilities are not available, the alternative option is to analyze LPG sample in vapor phase. It is important to ensure that sample is fully vaporized so that an accurate measurement can be made. Once the sample is in gas phase, detector tube technology can then be used to determine the concentration of chlorides present. Keep in mind the concentration results using this method will be in ppmv. It is recommended to convert the concentration back to ppmw as is customary for liquid applications.

Analysis, and particularly speciation of organic compounds at low ppm level is not trivial. A number of specialized techniques can be used which include oxidative coulometry and gas chromatography with an electrolytic conductivity detector. Methodology has been developed by specialist companies to use gas analysis tubes for detection of total chlorides and HCl.

In order to determine when a chloride treater should be changed, a routine sampling protocol could be established. This sampling can include periodic measurement of the chloride concentration on both the inlet and outlet of the chloride guard bed. The inlet sample analysis would allow for calculation of the expected saturation of the chloride media. The amount of chloride that can be absorbed prior to breakthrough can be estimated based on the expected capacity of the material for a particular application. The expected capacity can be provided by the absorbent supplier. The outlet sample analysis would confirm whether or not breakthrough has occurred.

As sampling can be cumbersome, another option would be to only take baseline chloride measurements and then calculate the life of the bed based on expected capacity. The baseline chloride concentration and flow rate across the bed over time can be used to calculate expected or residual life of the bed.

A corroboration for chloride at inlet of guard bed can be made through reformer chloride balance once a while. Chloride intake at LPG treater inlet is estimated based on balance and can be used in conjunction with the review of past spent absorbent analysis. A determination can be made as to the appropriate time to make the change out on the absorbent without experiencing any breakthrough. Change out can then be scheduled to occur during a downtime that is close to the time breakthrough is expected to occur. 

Concerning adsorbent replacement of chloride treater, when arranged in LEAD-LAG position, the best time is to plan for replacement is when chloride content of effluent at the outlet of LEAD treater vessel reached a value @ 10% of inlet chloride concentration.  Keeping more time in service the LEAD bed, though Refiners can maximize the left over adsorbent life but it possess threat of over- chloriding of alumina due to excessive HCl loading, thereby increasing risk of polymerization/green oil formation if olefins are present in streams (for example CCR hydrogen rich gas).

For a standalone chloride adsorber, it is better to replace as soon as it crosses guaranteed cycle length under normal operation or as soon as chloride break through appears if this guard bed is exposed to some upset operation. For standalone chloride guard bed, additionally use sample point a few places within the absorber bed. From a practical view point, since chloride analysis at inlet and outlet of chloride guard bed is not followed regularly, it is difficult to estimate end of life and refiner may keep an emergency spare to avoid operating a guard bed without any remaining adsorbent life and contaminating downstream equipment and tanks with chloride.

THOMAS PORRITT (Chevron U.S.A.) (3)
Metal-catalyzed coke or MCC is formed on the metal surfaces of the reactor internals. It is also known as filamentous coke or rod coke.  It is enhanced by high temperature, low hydrogen partial pressure and zones of low velocity.  MCC can be prevented by passivating the metal surfaces.  Most users do this by injecting an organic sulfide in the feed that converts to H2S in the process.  The H2S then interacts with the Chromium in the metal surface to form a passive layer of chromium sulfide.  A good rule of thumb for the sulfur injection in traditional high-pressure naphtha reformers is 0.25 – 0.5 ppmw based on the feed.  For low pressure units the user should consult their technology licensor for appropriate targets.
 

BILL KOSTKA (AXENS NORTH AMERICA)
Although HCl is the most abundant Cl-containing species in reformer effluent streams, organic chlorides (RCls) will also be present in lesser amounts due to acid-catalyzed reaction of olefins with HCl.  Removal of both HCl and RCls requires guard beds containing one or more adsorbents.  Failure to trap RCls and quantify their breakthrough may lead to downstream corrosion and fouling issues since their breakthrough precedes that of the more easily trapped and quantified HCl.

Leakage rate of chlorides from the reformer increases as its catalyst incrementally loses surface area with each regeneration.  Lower-surface-area catalyst requires a lower H2O/HCl ratio in order to maintain constant catalyst chloride content.  Chloride addition to the catalyst must be increased in the regenerator to obtain the requisite lower H2O/HCl ratio since H2O concentration remains relatively constant.  This increased chloride addition to the catalyst results in an equivalent increased loss from the catalyst once back on oil that will shorten chloride adsorbent lifetime.

Lower catalyst surface area also hinders maintenance of critically important platinum dispersion. Loss of platinum dispersion increases olefin production which along with higher HCl content can increase RCl formation as the catalyst ages.  Higher RCl formation further accelerates the loss of chloride adsorbent lifetime.  Catalysts with higher surface area stability extend the lifetime of downstream adsorbents, units and equipment.

Samples of liquid streams can be analyzed in a laboratory using a variety of standard methods including microcoulometry, extraction + potentiometry, MWDXRF and CIC.  As listed in the following table, each technique detects specific chloride species and has different levels of quantification (LOQ).
 

Samples of gas streams are typically analyzed in the field with indicator tubes; however, more accurate measurements are made in the lab using a different set of standard methods.  A good sampling system and technique are critical for achieving the requisite accuracy.  Gas phase monitoring techniques are summarised in the following table.

Examples of indicator tubes are listed in the following table.  Note that cross sensitivities and the presence of various RCl species will interfere with the accuracy of the tubes used to measure RCls, but should afford determination of chloride breakthrough.

Ideally, chloride adsorbents should be changed once RCl breakthrough occurs to ensure chloride-free operation of downstream units and equipment.    Determination of chloride breakthrough based solely on HCl measurements may lead to months of undetected RCl leakage.  Time-based replacement of chloride adsorbents is typically based on HCl breakthrough and also can lead to months of RCl leakage.

Zhen Fan (Norton Engineering Consultants, Inc.)
To prevent metal catalyzed coking, make sure that a low concentration of H2S (~1.5 ppm) is maintained in the recycle gas. Consider injection of DMDS to the reformer feed if feed sulfur from the upstream naphtha Hydrotreater is extremely low.