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LIOLIOS (DuPont Clean Technologies)

In any major revamp of throughput for a DHT (distillate hydrotreater), establishing a realistic design basis and engineering certainly never really exists. The idea is to look not just to the point but at deviations and feedstock properties, expected changes in compositions, and past history of contaminants. Evaluation of the reactors in the high-pressure loop is where we tend to do a concentrated effort because there is a lot of give-and-take on cycle life versus temperatures to accomplish the objectives of a particular throughput increase in the revamp. Obviously, we have to look at liquid and space velocity, catalyst selection, and hydrogen availability.

We have been successful revamping a couple of DHTs by adding liquid hydrotreating reactors, either adding or revamping series reactors by putting a liquid reactor in front. In one case, converting a trickle bed to a liquid reactor had some substantial advantages without significant changes in the stripping or fractionation areas. It is a great way to get a revamp. It not only increased capacity; but in some cases, you will be able to get to the lower sulfur in the product.

SHARPE (Flint Hills Resources, LP)

If your charge feeds are limited, especially for end-of-run conditions or with no cracked stocks in the feed, the feed effluent train can be upgraded for additional heat recovery. You have to give careful consideration to doing that to avoid dropping the downstream hot high-pressure separator below the salt deposition temperature. If the hot high-pressure separator gets too cold, the salts can partition to the liquid phase and end up in your downstream fractionation equipment causing fouling, plugging, or corrosion issues. I have referenced API 932B for you to review the guidelines. If your hot high-pressure separator is too cold, you can put a cold feed bypass around the exchangers to help control the temperature. Obviously, it will not work if your charge feed is limited. In our Eagle Ford crude cases, we are running cold on the reactor circuit, in general, and then putting a cold feed bypass, which will help control your hot high-pressure separator temperature. In that case, make sure you design your mixing point very carefully to avoid thermal fatigue issues. API 570 and 571 have some guidelines on proper design.

Other envelope issues to consider: Your waterwash systems need to be evaluated and revised to provide adequate washwater capability. Water removal capabilities of the upstream charge drum and downstream equipment need to be evaluated to avoid reliability issues associated with corrosion or potential product quality issues. On ULSD revamps, the feed cutpoint has to be a major bearing on your sulfur species and, therefore, treating requirement reactor sizes. If you are not changing out the reactor, catalyst life and run-length penalties must be assessed. Potential vibration issues in exchangers, piping, thermal wells, and quills need to be evaluated due to changing velocities and flow regimes.

The fractionation capabilities need to be evaluated and will be very unit-specific, depending on your required product specs and fractionator heater capabilities. One of the big considerations is hydrogen system management and optimization for an upgrade on rate in optimizing catalyst life management. You need to look at what maximum catalyst axial ∆Ts (temperature differentials) are allowable, which will depend on your bed outlet hydrogen partial pressure. You also must ensure that there is enough emergency reserve quench available for feedstock variations and unit perturbations and upsets. That is important, especially if you will be running more cracked stocks with your revamp. By the same token, quench valve capacity testing and availability are important for sizing basis. Hydrogen uptake for bed and hydrogen partial pressure limits of the bed outlets, both for catalyst light management and potential ∆P problems, needs to be evaluated. That is important from your emergency reserve quench as well.

R.E. “ED” PALMER (Wood Group Mustang, Inc.)

One of the biggest issues on a revamp is the mechanical design conditions of the entire reactor loop; because once you push capacity, the whole pressure outlet system goes up. The other point is really the upset pressure on the separator drum.

I want to make another comment. On any revamp study, we like to see a good set of operating data before we do a process simulation of the whole unit based on the data, including a really good reactor loop hydraulic profile to understand the real equipment and piping pressure drops versus the target pressure drops

JEFF JOHNS (Chevron Products Company)

I agree with a lot of the points that were shared. One of the most neglected considerations I have seen most recently has been the relief system. One of the easiest ways to get more feed through a hydroprocessing unit is to increase the size of letdown valves from the separator, but a lot of people forget to then evaluate the relief capacity downstream for a potential blow-through case. That omission has caused serious incidents within the industry.

GATES (Motiva Enterprises LLC)

I also want to add that as you are increasing unit charge rates, you are likely changing the operator response times to unit upset conditions. So, it is probably a good idea to take a quick look at the PHA (Process Hazard Analysis) and reevaluate to confirm that there were no sudden changes in operator responses to emergency conditions.

HELMY ANDRAWIS (WorleyParsons)

We get a chance to revamp quite a few hydrotreaters. Most of them are 30 to 40 years old, so certainly design pressure and temperatures on relief systems. For quite some time, we have seen many units pushed beyond their design limits and throughput.

I also want to make a comment about inspection reports. We take for granted that some of this equipment is good. We have had quite a few experiences where the inspection reports did not quite reflect the exact conditions of the units.

SHARPE (Flint Hills Resources, LP)

That is a very good point about the PSV (pressure safety valve) of a blow-through case. When reviewing a blow-through case, you need to look not just for liquid and hydrogen together, but also for hydrogen only. Frequently, a hydrogen-only blow-through case will set your downstream and relief valve pressure rating and sizing basis.

XIOMARA PRICE (GE Water & Process Technologies)

I agree with the waterwash revamp and making sure it is adequate because a little waterwash can be worse than no waterwash at all in your system. In addition, when revamping your unit, make sure that the filters are in front of the unit so that:

1) the throughput you have is continuous,

2) you are not fouling the system, and

3) you are able to maximize your throughput.

One other area that tends to get neglected is that you have not designed the unit to have problems; but when you do, to have the right-sized valves to put in the chemistries that you may need to address the problems. It is quite important to think about injection points when designing your systems.

JOHN PRICE (WorleyParsons)

Another consideration that is often overlooked is the assessment of cooling capabilities with revamps. Reviewing the cooling tower’s designed hydraulic and cooling capability and/or the air fin cooler’s design as compared with the current operating performance is typically neglected in the early stages of an engineering effort for expanding hydrotreating units.

GLENN LIOLIOS (DuPont Clean Technologies)

The first step in any revamp analysis is to establish a realistic design basis with careful consideration to sensitivity of changes in feed stream properties, composition, and contaminants. We generally start by evaluating the reactors and the high-pressure loop as these two systems are typically the major limitation. For most systems, the reactor space velocity and hydrogen availability limit high throughput increase.

Considering liquid-phase hydrotreating technology can provide a unique solution. Adding a reaction loop upstream of the existing trickle bed can provide great capacity increase capabilities. This allows for expanding the unit capacity without having to modify the existing high-pressure loop as the hydrogen is carried by a liquid recycle. By moving part of the hydroprocessing load to the new reactor system, the trickle bed reactor and compressor loop can be optimized to maximize high hydrogen concentrations and lower heat loads. In some cases, it is possible to design the new reactor system to operate at higher pressure, thereby allowing additional optimization of the new purposed trickle bed reactor.

If the existing trickle bed unit has two reactors in series, revamping the first reactor to liquid phase technology has also shown substantial capacity increases with much lower capital investment than other options.

As with all revamp studies, the aforementioned work is evaluated several times to make sure that the capital optimization and operability meet the project threshold. There are always tradeoffs, and this re-evaluation is a critical step to maximize the benefits based on the constraints of the existing unit.

Next, we evaluate the heat integration and the fractionation equipment. Finally, we evaluate the product rundown system and safety valves. A thorough evaluation will also include a review and potential upgrade of existing reactor internals to state-of-the-art internals.

Other items that may need to be considered are amine absorber, including amine type; catalyst options for higher activity; and, feed section, including charge heater.

JESUS PEREZ (Alfa Laval Inc.)

A key study to perform is how to increase heat recovery without adding pressure drop on the diesel hydrotreater unit. Significant fuel savings in the fired heater can be achieved by minimizing the HAT (hot approach temperature), which is also known as ROT-HIT (reactor outlet temperature–heater inlet temperature) of the feed-effluent heat exchanger. The installation of a welded-plate heat exchanger can provide both higher heat recovery and lower pressure drop. Since the 1990s, Alfa Laval Packinox has commissioned 22 welded-plate heat exchangers in distillate hydrotreating applications all over the world with one more unit being delivered next year. For additional information on the subject, we suggest that you refer to Alfa Laval Packinox’s response to Question 23 from the 2008 NPRA Q&A. This question was, “What is your experience with and acceptance of high efficiency plate exchangers in high-pressure hydrotreating service?”

HOWARD WU (Haldor Topsøe, Inc.)

1) Kinetics are used to determine if the existing reactor would have enough catalyst volume to meet the process objective for the higher throughput. If it does not, then one may need to add an additional reactor or accept shorter cycle lengths. Topsøe has done many ULSD, CGO, and coker naphtha unit revamps. We have found that adding additional reactor volume is quite feasible and economical for refiners and allows the unit to operate at a lower gas-to-oil (G/O) ratio, thereby avoiding investment in a larger compressor. Topsøe offers Reactor Design Packages (RDPs) which are geared for the addition of reactors for refiners whose main bottlenecks were in catalyst volume.

2) Engineering is utilized to determine if existing equipment can handle the higher flow. With a higher throughput, the pressure drop will be higher in the system and the existing compressors, heaters, exchangers, vessels, towers, and pumps may no longer be adequate. Topsøe will provide refiners with a Revamp Process Design Package (Revamp PDP) or a Revamp Engineering Design Package (Revamp EDP) to simulate the whole unit and identify limitations of equipment. It includes development of new PFD with hydraulic analysis, heat integration, and process evaluation of vessels, rotating equipment, and towers.

SIVADASAN (UOP LLC, A Honeywell Company)

When you are trying to remove the attachments from the reactor, do not touch them unless it interferes with your process flow, catalyst loading, or internal installation or access. When the rings are welded to the support rigs, remove the rings and leave the lugs in its place. If both the lugs and the rings are welded into the shell, try to cut a short distance from the shell, using appropriate cutting methods, in order to minimize the heat input and potential damage to the shell from the cutting operation. When trying to install the attachment, avoid welding to the base metal; because once welded, a post-weld heat treatment may be required.

If you plan to go ahead with the cutting operation, do the removal of the coke and hydrogen from the base metal and do an NDE (non-destructive examination) of the area to be welded to detect any flaws that may be affected or ruined by welding. The weld needs to be full-penetration and ground to a generous concave contour. The weld-and-attachment chemistry should match what it is being welded to at the base metal. Once the welding has been done, do an NDE to detect any defects. Once the NDE is complete, a recertification based on the laws prevailing in that country may be required.

RAJESH SIVADSAN (UOP LLC, A Honeywell Company)

In hydroprocessing reactors, support rings are used to support internals like a tray or catalyst support grid. Support rings are fixed on the reactor ID (inner diameter) either by weld buildup to the base metal or forged as part of the shell course. The following recommendations apply to reactors made of low chrome base metal in hydrogen service:

Recommendations on Removal of Rings and Other Attachments

1. If possible, leave unused attachments in place. They should be removed if they will interfere with process flow, catalyst loading, internals installation, or access.

2. Where the ring is welded to support lugs but not to the shell, and when leaving everything in place is not possible but only the ring needs to be removed, then remove the ring and leave the lugs in place. In this case, cutting at or near the shell is not required. If cutting near the shell is necessary, the points in #3 (below) apply.

3. Cut lugs and rings welded to the shell a short distance from the shell (e.g., closest approach of the cut to the shell at least 10mm). The intent is to minimize heat input into the shell and minimize the potential for damage to the shell from the cutting operation. The cutting method should be chosen considering the potential heat input. A dehydrogenation heat treatment may be necessary before cutting, and NDE before and after cutting is advisable. If coke is present, it must all be removed. NDE before cutting may identify a defect (e.g., crack) that might be driven by the cutting operation, and NDE afterwards may identify a defect caused or enlarged by the cutting operation.

Recommendations on Installation of Rings and Other Attachments

1. Welds should be full-penetration, ground to a generous concave contour. Stainless steel rings should not be circumferentially welded. Weld (and attachment) chemistry should match to what it is welded (base metal or lining).

2. Welding to the base metal should be avoided. PWHT (post-weld heat treatment) of low chrome requires an elevated temperature [e.g., 690°C ± 15°C (1275°F ± 25°F)]

3. Removal of hydrogen from the base metal (dehydrogenation heat treatment) and removal of coke may be necessary.

4. NDE of the area to be welded to find any flaws that may affect or be driven by welding. If welding to lining, UT to confirm the lining is 100% bonded. For heavy loads, UT of the base metal may be necessary to ensure there are no laminations.

5. Weld the lining using a procedure that does not require PWHT of the base metal, i.e., the heat-affected zone does not penetrate the lining. This will require a mockup to confirm.

6. NDE should be conducted after completion of the attachment to detect any defects caused or driven during the attachment process.

7. A recertification of the reactors may be required.

KLAUS RISBJERG JARLKOV (Haldor Topsøe, Inc.)

Adding support rings or clips to a reactor shell depends on several factors:

• Existence or absence of weld overlay,

• Size of bracket/support ring, and/or

• Magnitude of the load size support and weld size.

If the reactor is provided with weld overlay, adding a support ring/support clip may be done using low heat input welding using a weld size, which will not affect the base material. The welding must be done by a certified stainless steel welder. If a strong weld is required, a larger weld can be applied by using several pass welds with sufficient cooling time in between the passes. The root pass should be touchable by hand before continuing with the next pass.

If the support ring/lug/bracket is heavily loaded and requires being fully welded to the base material, pre-heat treatment and post-weld heat treatment will be required in accordance with the code.

Carbon steel reactors will require both pre-heat treatment and post-weld heat treatment in accordance with the code.

Support rings/lugs made of stainless-steel material can be removed by grinding. Use caution not to damage the weld overlay. Sometimes it will be possible to weaken the weld beads on the brackets and thereafter remove it by knocking it from side to side until it breaks. For heavier brackets/support rings, gauging may be used. Leave at least 1/8" to the weld overlay and use a protection shield between the weld overlay and gauge. If the bracket is removed flush to the weld overlay, pre-treatment of the area is recommended.

Attachments that are welded to carbon steel or low alloy steel, pre-heating, and other heat treatments specified in the welding procedure shall also be applied in order to prevent cracking.

ROBERT TORGERSON and SYDNEY GARRETT (Gayesco International)

We find it extremely rare, during hydroprocessing reactor modification, that rings or support lugs are added to the reactor other than near the outlet collector on the final bed. It is much more common to use low profile support rods attached to the distribution tray for inlet points with only the end of thermocouple penetrating into the active catalyst to minimize interference. Outlet points utilize low profile supports coming up from the catalyst support beams directly aligned with the inlet point above. This prevents the necessity of welding to the reactor.

Additionally, it is possible to use any existing attachments in the reactor as part of the thermocouple support network. Supports for old pipewells or previous thermocouple installations are good examples. We have also had retrofits involving welding of supports to the wall; but given the ease of the vertical support rod installations, that practice has significantly decreased.

SIVADASAN (UOP LLC, A Honeywell Company)

The UOP bed thermometry consists of a stab-in type of assembly with three thermocouples on top of the bed. Typically, a multipoint thermometer is provided in the case of the first bed of a hydrotreating unit and if the bed length is more than 11 feet for a hydrocracking bed. At the bottom of the catalyst bed, industry-standard flexible-type multipoint thermocouples are specified.

Radial temperature spread is the difference between the maximum and minimum temperature at the same elevation level. It is monitored at various levels in the reactor and is the primary indicator of flow distribution within the catalyst bed. Ideally, the thermocouple at the same level should register identical temperatures; but sometimes, less-than-perfect distribution of the reactants in the catalyst bed happens due to different factors.

Our guideline is that a radial gradient higher than 20°F is considered a point of concern. It is not acceptable for it to be more than 30°F. So how can you prevent this radial spread? Try to have a well-designed internal with proper installation and maintenance and good catalyst loading with appropriate catalyst bed design. Also, avoid process upsets and loss of catalyst containment and prevent contaminants in the feed or recycle oil.

LIOLIOS (DuPont Clean Technologies)

Configuration of thermocouples at the top of the bed are effective for evaluation of quench and distributor performance. When placed in the top, middle, and bottom of the bed, they are used to evaluate catalyst activity and flow distribution. Point density, of course, depends on the application. Higher density is required for systems prone to coking and which require a very uniform flow for successful operations, such as hydrocracking or ultra-low sulfur diesel. Lower density is also necessary for less severe applications. The 2005 AFPM Q&A transcript has a lot of valuable discussion on point density. A flexible thermometry can be arranged to provide the appropriate number of points in almost any geometry at different bed elevations. In any case, an open area of approximately 36 inches in diameter is recommended.

The acceptable radial temperature spread of 5°C is typical for good operation of the trickle bed. For a liquid-phase hydroprocessing reactor, the radial temperature spread is lower due to the heat sink of the recycled liquid. Typically, we experience about 5°F as a maximum radial temperature spread.

This graph shows an example of thermocouple configuration and acceptable radial temperature spread. It was derived from a liquid-full reactor with 12 thermocouples and two concentric rings and basically shows very uniform and comprehensive fuel temperature differences in the radial change in FCC pre-treat service.

VICHAILAK (Marathon Petroleum Corporation)

From the picture, you can see that we require 6” below the top, as well as 6” both at the bottoms and one-third of the bed and then two-thirds of the bed. These are the minimum readings per ring, which add up to nine readings. The radius of the ring has to be two-thirds of reactor radius. If you have high severity like in a hydrocracker, then you will have an additional four skin thermocouples at the bottom of each bed, too. Also, we add another ring at the very bottom and one more thermocouple in the middle of the reactors. The more you add thermocouples, the more information will be available to you.

We have one reactor that did not have enough thermocouples. Once added in, we started seeing new information, and people were not able to sleep. A hot side is normally a dry side because liquid is a very good heat sink. If you have a dry side, then you see that the temperature will be higher. We normally require 10°F as it is considered normal radial ∆T. But if you do not have axial ∆T, you should not have radial ∆T; nor if you have 10°F or 20% of axial ∆T, whichever is lower. Thirty degrees is considered the normal maximum probably for as long as you have quench. For example, if you have a 60-foot catalyst bed and 30°F at the bottom, there is no way you will be able to quench as well; so that scenario can be considered severe. But if a temperature of greater than 50°F is not acceptable, we will shut down and replace the bed.

RAJESH SIVADSAN (UOP LLC, A Honeywell Company)

UOP bed thermometry typically contains a stab-in-type assembly with three thermocouples at the top.

For hydrotreating beds, mid-bed thermometry for the first bed is provided and not included in any other hydrotreating beds. Mid-bed thermometry is also provided for long cracking catalyst beds (greater than 11 feet).

The thermocouples at the bottom of bed are specified as industry standard flexible multipoint thermocouples. A typical Flexible Multipoint Sheathed Thermocouple arrangement is shown below.

The radial temperature profiles are monitored at the various levels in the reactor and are the primary indicator of flow distribution within the catalyst beds. Radial temperature differential is defined as the difference between the maximum and minimum temperatures at the same elevation. Ideally, the thermocouples at the same level should read the same temperature. The bulk of our experience suggests that most Unicracking™/Unionfining™ units do have fairly uniform radial temperature profiles in the catalyst beds. However, less than perfect distribution of reactants in the catalyst beds can occur. This may be due to improper catalyst loading, damage to reactor internals, or the reliance on older reactor designs with deep catalyst beds and older internals. Consequently, the temperature of the fluids leaving the catalyst bed at different locations can vary.

As a general guideline, a hydrocracking/hydrotreating catalyst radial gradient greater than 20°F (11°C) is considered by UOP to be high and a point of concern, while greater than 30°F (17°C) is considered unacceptable. In order to prevent radial gradients, there should be a perfect distribution of reactants in the catalyst beds, and this can be obtained by:

• Good internals design,

• Proper internals installation and maintenance,

• Good catalyst loading,

• Appropriate graded bed design, and

• Avoiding process upsets by

   o Preventing contaminants in the feed or recycle oil (particulates including iron sulfide, organic iron) and

   o Preventing loss of catalyst containment (usually leads to hot spots or temperature excursions and pressure drop buildup).

MONTRI VICHAILAK (Marathon Petroleum Corporation)

For a high severity unit with ∆T > 20°F to 70°F, the following parameters are recommended:

- 6 inches inside the top of the active catalyst bed,

- 6 inches inside the bottom of the active catalyst bed,

- 1/3 level from the top of the active catalyst bed,

- 1/3 level from the bottom of the active catalyst bed, and

- minimum 4 readings (90°) for each level: up to nine readings at 2/3 of the reactor radius

For a very high severity unit with ∆T > 70°F ∆T, in addition to the above suggestions, you will need:

- Four skin thermocouples at the 6 inches above bed outlet,

- Four readings (or more) 6 inches from the wall, 90° from each other, and

- A single reading at the center of the bottom level.

Flow maldistribution can be detected by observing the radial temperature differences. The hot side is almost always the dry side. We prefer to see any radial ∆T is less than 10°F or at most 20% of axial ∆T. Radial ∆T of 30°F is considered as normal maximum as long as unit has quench capability or reserved. Radial ∆T of 50°F or more is considered unacceptable and should be shutdown to solve the problem.

GLENN LIOLIOS (DuPont Clean Technologies)

Prior responses to this question [from the 2005 NPRA Q&A by Krause (Albemarle Corporation), McGrath (Foster Wheeler USA Corporation), and Spearman (Barnes and Click)] give good recommendations for the thermometry layout.

Thermocouples are useful in determining performance of the quench and distributor at the top of the bed and catalyst activity and flow distribution at the middle and/or bottom of the bed. Radial deviations can help troubleshoot issues inside the reactor that can influence the operation of the unit.

Using flexible thermocouples, radial arrangements in different geometries can be created at any bed level desired. Sufficient thermocouples at a particular level to monitor any process deviations are recommended; however, the exact number is open to discretion. A higher density should be used in applications that are prone to coking or where very uniform flow is required to achieve process goals. A lower density can be used in simpler applications. In any application, an open space of approximately 36” diameter should be left in the center of the reactor to allow for access and catalyst loading.

In IsoTherming® liquid phase hydroprocessing, the radial temperature spread is typically low, as the heat sink of the liquid and the more uniform distribution of single-phase hydroprocessing avoids hot spots and the associated temperature gradients. A point density on the low end of the scale should be considered. Regarding acceptable radial temperature spread, a maximum of 5°C would be typical for a trickle bed with lower spread as reported for state-of-the-art internals from some licensors. Recent experience shows 5°F as a maximum (with 2 to 3°F typical) in liquid phase hydroprocessing.

DAN MORTON (Haldor Topsøe, Inc.)

We recommend use of the new flexible thermocouples in a ring pattern at the top and the bottom of each bed.

Top Layer: Two to four sensing points are required. This is enough sensing points to be sure that interbed and inlet stream mixing is sufficient. These points are located on equally spaced intervals, each at 70% of the diameter at 50 mm below the bottom of the inert layer. Also, preferably they are not directly below a “dead” spot like dump tubes, beam, etc. in the bed above. Access down through the center of the reactor – from manways, for example – needs to be considered on smaller reactors. Keeping the points as far from the manways as possible also limits the possibility of damage during a turnaround.

Middle Layer: This is at the client’s discretion or optional if the catalyst bed is higher than 5 meters (about 15 feet). If so, there should be four sensing points, with the same considerations as above, midway between the other sensing points. Adding thermometry in the middle of the bed is not a must, but it will provide additional information flow maldistribution.

Bottom Layer: This is a ring of sensing points near the reactor wall and in the middle which are located 50 mm above the bottom inert layer. The number of points here increases with the diameter. For small reactors less than 1.8 meters, we recommend four in the outer. There is no need for inner points as the reactor is so small. For 1.8-to-3.0-meter diameter reactors, we recommend configuration of four inner and four outer points. For diameters greater than 3 meters, we see as many as four inner and eight outer points. The middle ring diameter should be selected so that each sensing point covers a reactor cross-sectional area of equivalent size. We have a formula which we use to determine this, again, also keeping a minimum distance from the manways. The flow distribution through the bed is considered good if the radial temperature spread at the bottom is less than 20% of the axial ∆T across the bed. 

For hydrocracking reactor beds, we will recommend a similar scheme but will add more temperature points for additional safety.

ROBERT TORGERSON and SYDNEY GARRETT (Gayesco International)

It is most common these days to find the modern flexible thermometry in the active catalyst, and the use of pipewell designs has really diminished over that past decade in hydroprocessing applications. This is due to the modern flexible thermometry designs allowing for a much quicker response time and more measurement points and locations.

The number and placement of points is always a Process/Engineering decision. As a multipoint manufacturer, we do see a wide variation in number and location of points specified. Generally, the greatest emphasis has been on bed outlet temperatures. Bed inlet temperature requirements have been increasing over the past 10 years, especially where new reactor internals are being used. The use of mid-bed temperature measurement has been limited. In hydrotreating, we see that most applications require a thermocouple to cover between 10 and 25 ft2 of cross-sectional area. In hydrocracking where the service is more difficult, we see the thermocouples covering between 2.5 and 15 ft2 of a cross-sectional area.

In any case, one of the most critical ways to successfully utilize radial temperature measurement information is to know the exact accuracy of that data. Calculating true factory calibrations of actual individual sensors is a good Best Practice for new units, and field verification is essential for existing units that may have seen years of service. This eliminates any questions about sensor variation and its effect radial temperature spread.

ROBERTSON (AFPM)

Those are the responses from the panel. Before we get to the last Hydro question, I want to remind you that there is a P&P (Principles & Practices) session tomorrow at 8:00. The topics and presenters are listed in the program. If you have a subject that was not discussed in this forum, tomorrow’s P&P session is a great place to bring it up to the group. It will be an open session. The subjects listed in the program are discussion starters, as you know if you have attended in the past. The P&P is a good place to get more information or have more one-on-one/back-and-forth if you would like.

SIVADASAN (UOP LLC, A Honeywell Company)

UOP has designed around 1000 PSA units. For most of the refinery applications, the impurity limit has been set to less than 10 ppm. The table shows a comparison between specs when relaxed from 10 to 100 ppm. H2 recovery was also checked when specs were tightened from 10 ppm to 1 ppm. You can see that the delta hydrogen recovery is not that much – about 1%, but relaxing the specs has an effect on the downstream hydroprocessing unit.

These carbon oxides may get absorbed on the catalyst’s active surface and affect the HDN and hydrogenation reactions. They can also undergo methanation reactions in the reactor if present in higher concentrations. Some of the partial reaction products from the methanation reaction and un-reactive carbon oxides reduce the hydrogen partial pressure and increase the deactivation rate of the catalyst. If these carbon oxides increase in percent levels in a short period of time, there will be the risk of getting a temperature excursion. However, the main concern is temperatures less than 200°C. Carbon monoxide reacts with reduced nickel to produce nickel carbonyl, which causes health and safety issues when you are trying to open your reactor flanges or valves during the shutdown of the unit.

GATES (Motiva Enterprises LLC)

For PSAs, the design of a 10 to 50 ppmv (parts per million by volume) slip is common. A downstream noble metal catalyst may require a lower value. Base metal hydrocracking and hydroprocessing catalysts can typically tolerate a higher slip. But as was already mentioned, you will want to maintain a constant slip. If the CO and/or CO2 suddenly spikes up, you may have temperature instability in your reactors. Increasing the slip can increase the hydrogen recovery by increasing the adsorption time on the PSA; but really, it is limited overall by the adsorbent. There is some concern for hydroprocessing units that CO or CO2 in the gas going to the unit can form nickel carbonyl at shutdown. So, make sure you reduce the CO that might be in that reactor, as well as the temperatures, before you open up any flanges or change the atmospheres.

SHARPE (Flint Hills Resources, LP)

CO is a temporary catalyst poison which inhibits the HDS reaction more so than HDA (hydrodealkylation). The effect is not visible at 5 ppm; CO is insignificant at 15 ppm. CO2 has about 50% less of an impact than CO. The recommended mitigation is to increase your purge and/or reduce CO in the makeup hydrogen. I have a bullet on the slide suggesting you consult with your catalyst vendor about the recommended maximum for your unit. I have seen guidelines from less than 20 ppm to less than 50 ppm to 100 ppm; so, it seems to be catalyst-specific.

RAJESH SIVADSAN (UOP LLC, A Honeywell Company)

High hydrogen purity is obtainable with a PSA process (99.9%+). However, a very modest advantage, with respect to hydrogen recovery, can be gained at the expense of a less-severe purity specification. The table below shows the impact of the CO levels on the hydrogen recovery in a PSA. As can be seen, the delta recovery is small for a relaxed specification. UOP has supplied close to 1000 PSA units, and the product specification has been typically less than 10 ppm volume CO+CO2 for refinery applications.

Ni catalyst is great for methanation reactions (exothermic). Consequently, there is a concern that it can experience a temperature excursion upon the carbon oxides spiking up. If the carbon oxides content of the makeup gas jumps to percent levels in a short time, it can cause a temperature excursion. CO is worse than CO2 because it adsorbs more strongly, reacts with more heat release, and is not readily sponged out of the recycle gas into the separator liquid.

However, there are also some process/catalyst activity effects which are outlined below:

• Some of the CO compounds are chemisorbed at the active sites of the catalyst, and this suppresses the HDN and hydrogenation functions of the catalyst. This activity impairment is only temporary as the chemisorption is fully reversible.

• Methanation and shift reactions occur in the hydrocracking environment, and the methanation reactions can result in substantial exotherms.

• Carbon oxide reaction products and unreacted carbon oxides concentrate in the recycle gas diluting the hydrogen purity and lowering the system hydrogen partial pressure.

• At temperatures less than 200°C, CO reacts with reduced nickel to form extremely toxic nickel carbonyl. This is a problem on unit shutdown, and any flanges or valves are opened. To avoid exceeding the eight-hour exposure limit nominally requires less than 10 ppmv CO in the makeup hydrogen during cooldown to below 200°C.

CHRIS STEVES (Norton Engineering)

10 ppmv (CO + CO2) in the product stream from an H2 PSA unit is a typical design condition. If (CO + CO2) exceeds this value for short periods of time, then, initially, there is no major impact on the life of the adsorbent. However, extended off-spec operation, which is anywhere from several hours to a full shift at levels approaching an order of magnitude higher than design, will start having an impact on adsorbent life. H2 PSA vessels are typically a multi-layered packed bed with the upper layers sensitive to impurities being removed in the lower layers. Common examples are water vapor/C3+ hydrocarbon removal in the alumina/silica gel pre-layers and CO2 removal in the activated carbon layer below the zeolite.

Off-spec impurity levels in the product are often a tell-tale sign that strongly adsorbing impurities being contained in the lower layers of the packed bed may be moving further into the adsorbent mass than intended. If the CO2 breakthrough wave is allowed to slip from the activated carbon layer into the zeolite layer during off spec operation, then adsorption-desorption working capacity of the zeolite layer for CO removal will progressively decrease over time. Once contaminated, an adsorbent layer is very difficult to regenerate, even with the vessel offline. Special care should be taken with off spec operations during warmer conditions as adsorption-desorption capacity will decrease with increasing temperature based on the equilibrium isotherm.

Running the PSA with higher H2 recovery, and hence higher (CO + CO2) levels, needs to be weighed against adsorbent life based on progressive contamination. When the source of feed gas is from a steam methane reformer, there is little margin for increased impurity levels. Verify that the CO slip from the SMR (steam methane reformer)/water gas shift reactor train is within normal operating limits; otherwise, the PSA will consume more H2 than design for the internal regeneration steps to decrease CO level. Another option is reloading the upper layer in the vessel with a zeolite that offers higher working capacity for CO removal. With off gas PSA systems where the source of feed gas is a H2-rich stream from a different process unit, consider bypassing a portion of feed gas around the PSA unit to achieve the desired H2 purity level. If downstream equipment is insensitive to all species present in the feed, and if hydrogen partial pressure is the primary driver for PSA cleanup, then running the PSA at design impurity levels with bypass will maximize adsorbent life while maximizing H2 recovered from the feed. An additional consideration with off gas PSA systems is tail gas compression downstream of the buffer drum if the destination is a fuel gas header at elevated pressure. Significant increases in H2 recovery can be achieved when the tail gas from a PSA vessel is discharged at pressures approaching 3 to 5 psig.

HERLEVICH (Marathon Petroleum Corporation)

We receive crude by truck and rail at two of our seven refineries. I have prepared three slides to share with you: one for personnel, one for process, and one for sampling. Most of the tight oils we bring in are from under-developed fields that do not have proper gas plants; therefore, they come in fairly wild. Light ends are really the biggest issue.

From a personnel safety standpoint, we wear normal PPE (personal protective equipment), as you would find elsewhere in the refinery: Nomex® and the H2S (hydrogen sulfide) monitor. If there is a benzene hazard, we use respirators. This situation may occur when making up the hose connections. As I mentioned, tight oils tend to be high vapor pressure, which is the real issue. There are also normal hazards associated with elevated work on gangways. Anyone who has worked on a rack knows the difficulties of raising gangways, especially when ergonomic issues are present. So be mindful of ergonomics when you are going through your refineries. Take time to ensure the best possible situation for the people moving the gangways.

The next slide focuses on Process Safety. First: typical chalking and grounding practices. Sometimes you find folks getting a little lax in these areas, but they are very important. The biggest issue is the light ends; so in both facilities, we de-pressure the railcar to a safe location with vapor recovery. Next, we unload either by pushing the crude with nitrogen or by using a pumped system.

As far as sampling goes, we typically do routine BS&W (basic sediment and water). One of the plants has an RVP (Reid Vapor Pressure) analyzer located nearby. At this plant, they analyze for wild batches and then track its progress through the plant. Full crude analysis is done less frequently, perhaps annually.

I have also included some information related to Process System Refinements. Being so wild, we had to install vapor eliminators upstream of the pumps. Even after letting the pressure off of the railcar, there were still problems with the pumps gassing off. Regarding piping system hydraulics, they were designed to minimize flashing. Whereas in a refinery you would normally desire very big pipes, in this case you might need to minimize the discharge piping diameter to avoid two-phase flow due to flashing service. Interestingly, in our pumped service, we installed variable frequency drives to change the speed of the pump. Here the motor speed was tied to the pump vibration monitor. It is a fairly unique system. Then when we get a really wild batch of crude, we can dial back the offloading rate.

SLOLEY (CH2M Hill)

A few plants use specific laboratory analysis. They are using tests that are essentially standard crude assay tests including the Reid Vapor Pressure, hydrogen sulfide content, and flashpoint when unloading. Most crude transported by either railcar or truck has some hydrogen sulfide scavenger added at some point in the handling system before it gets to the plant. Since trucks are typically driven into the plant by individual drivers, safety issues with access and control are more difficult with trucks. The largest personnel exposure in unloading comes from the physical connection and movement at the trucks and railcars. The facilities need to be arranged to allow for simple, straightforward control of vehicle and personnel access to minimize risks. The safety procedures put in place per our clients include blue-light and blueflag signaling to prevent moving connected railcars. These procedures need to be followed rigorously. Nearly all facilities have automatic de-railers and truck/tank immobilizer systems as a final layer of protection. However, the intent is for this to be a backup layer. It is not a standard control feature. If you have a derailment or truck immobilization, it will need to be investigated and the root cause identified and solved. The intent of the standard facilities and procedures should be to have no derailed tanks or trucks. The facilities can be configured to either use pusher cars or puller cars when moving rail. If at all possible, you should favor puller cars having a locomotive on the front end of the cars where the personnel can see what is going on as they control the train. This setup has resulted in significantly fewer derailments and safety incidents than with puller trains. In addition, facilities need proper layout and grading for the spill containment and handling and other environmental issues.

TOM GERMANY (Calumet Specialty Products Partners, L.P.)

One of our exposure times is when we actually do our measurement. When we put in our rail system, we did not put in a flow meter; we actually gauged the tanks. Does anyone have techniques to gauge it without opening up the big manway using a bent or gauging nozzle?

HERLEVICH (Marathon Petroleum Corporation)

I am not aware of any.

SHENKLE (Flint Hills Resources, Ltd.)

We recommend pre-turnaround development of a PPE matrix that can be used during the turnaround which outlines the PPE required should you discover mercury during the outage. We would remove residual material with vacuums rated for the service and then tunnel the tower, wearing the proper PPE, to survey for mercury. We also recommend, as a good practice, to increase air exchanges when possible. For hot work, we require breathing air in full suits. I encourage you to reference AFPM Annual Meeting Paper #AM12-22 for further information on mercury management during a turnaround.

HERLEVICH (Marathon Petroleum Corporation)

During the online run, not during turnaround, we found mercury in some of the foulants in the overhead and in the naphtha circuits. We have observed this material while blowing down sight glasses or working on a pump or exchangers, so we have become very mindful of the potential for exposure during the turnaround. During the actual turnaround, our Industrial Hygiene personnel conducted monitoring for mercury and found exposure levels well below the concern level. One of our chemical vendors indicated a marked increase in the trend of finding mercury during turnarounds, so that is a very good question. At least one of the vendors has a new technology that includes a chelating agent which lets you remove the mercury from the wastewater collected in the temporary tanks. This was a very novel approach. I do not think that this technology is commercial yet, but I believe it is in the development process.

UNIDENTIFIED SPEAKER (Shell Global Solutions U.S.)

Have you considered trying to detect or monitor the presence of mercury in crudes in the first place and stopping it there by getting back to your traders or purchaser and putting specifications in your purchasing contracts?

SHENKLE (Flint Hills Resources, Ltd.)

We have done sampling for particular crudes to try and identify sources, but I am not aware of any specific having been include in a contract.

RUSSELL “RUSTY” STRONG (Athlon Solutions)

The mercury in crude oil has been a problem for many years now. It seems to pop up sporadically. The first time I saw it at least about 20 years ago, it was attributed to oils coming out of Alaska down the pipeline. Certainly the Indonesian gas wells are laden with mercury, and any of the crude oils that come from that same area can also be contaminated. The question I have is: When mercury has been seen in a refinery, has there been an effort to look at the record of crude oils processed to get a general idea of possible sources of mercury? If so, a common sharing of that information could be a heads-up for future operations, as well to other operators, at least until such time as mercury determination in the crude can simply be determined by the refinery lab during operation.

HERLEVICH (Marathon Petroleum Corporation)

We have not done any monitoring. We know it is present in the crudes, and we are mindful of this when we do work.

SHENKLE (Flint Hills Resources, Ltd.)

So as suggested, I encourage you to read Annual Paper #AM12-22. In this paper, there is some discussion about mass balances and estimations around mercury deposition.

BOB SHENKLE (Flint Hills Resources, LP)

At FHR, we put together a PPE matrix pre-turnaround to tell us the type of PPE required to execute the scope of work if mercury is present. We then remove residual material (potentially containing mercury) using vacuums designed for the application. Then, wearing the proper PPE, we tunnel the tower and take readings for mercury. Increasing air exchanges, when possible, is a good practice to follow. All hot work requires fresh air and full suits. Non-welding work would be assessed and PPE defined accordingly. AFPM Annual Meeting Paper #AM-12-22 “Mercury in Hydrocarbon Process Streams: Sampling/Analysis Methods, Exposure Monitoring, Equipment Decontamination, and Waste Minimization” – by Brad Hase, FHR Global Turnaround Manager; Ron Radford, PEI Business Development Manager; and, Vic Vickery, PEI Technical Manager – can be reviewed for additional information.