Question 91: What are the characteristics of FCC catalyst to minimize particulate emissions at the stack?
John Aikman (Grace Catalysts Technologies)
While there are several operational and mechanical factors that can influence a unit’s particulate emissions, the question asks specifically about the FCC catalyst; as such, the following discussion will address characteristics of fresh catalyst only.
There are four basic characteristics of FCC catalyst that can have direct effects on particulate emissions. These same characteristics will also affect particulate losses to the fractionator and slurry product. The first characteristic is simply the amount of fines content coming into the unit with the fresh catalyst due to the manufacturing process. Figure 1 is an example of a typical fresh catalyst particle size distribution, with a theoretical depiction of a cyclone’s ability to retain fresh catalyst particles. DPTh is the smallest particle diameter which can reliably be collected by a cyclone and is used to model cyclone performance. Particles below this size will be lost by the cyclone.
A review of the Grace Ecat database showed that none of the FCCU’s in North America can retain any 0-20 μ range particles. In addition, they only retain an average of approximately 4.0 wt% in the 0-40 μrange. Fresh catalyst typically ranges anywhere from 9 to 16% of 0-40 μ depending on the supplier andmanufacturing process. Some units require higher amounts of 0-40 μ range particles to help with circulation.
The next characteristic of fresh catalyst that must be considered is the particle density. he DPTh mentioned above will decrease with increased catalyst particle density, per Equation 1 below. This means that cyclones can retain smaller particle sizes as the particle density increases. This is due to the centrifugal force acting on a heavier particle. However, particle density is not the same as apparent bulk density (ABD). Industry typically measures and reports ABD as part of the routine Ecat analysis, but this should not be mistaken for particle density for cyclone efficiency purposes. Since Al2O3 is denser than SiO2, catalysts with higher alumina content will have higher catalyst particle density.
The third characteristic is the inherent attrition resistance of the fresh catalyst. Industry measures the attrition resistance via a variety of tests, with the primary goal of providing a relative indication of catalyst attrition resistance. Grace utilizes the DI test or Davison Index. On the DI scale, a lower number is less likely to cause attrition and generate microfines. It is usually not valid to compare attrition resistance results obtained from different laboratories. Additionally, it is important to note that the energy applied to a catalyst sample during attrition testing is much more severe than commercial conditions.
As discussed above, the majority of the microfines created in the FCCU will leave the unit through either the reactor or regenerator cyclones, with the latter potentially contributing to increased particulate emissions at the stack.
'The attrition resistance of the catalyst is a function of the manufacturing process and the binder material utilized during the manufacturing process. Figure 2 is an example of how a refiner improved the FCCU stack opacity with catalyst formulation. The reduction was achieved changing to a Grace supplied catalyst with lower DI and lower 0-40 μ content in the fresh catalyst.
The final characteristic of fresh catalyst that affects particulate emissions is its morphology. Morphology can be defined as the study of the form and structure of a particle and its specific structural features. A catalyst particle that has a smoother exterior surface is less likely to generate microfines in an FCCU. Even catalysts with a low fresh DI measurement can cause increased particulate emissions if there are surface irregularities resulting from the manufacturing process. In order to demonstrate this visually, Figures 3 and 4 present SEM’s (scanning electron microscopy) of “bad” and “good” fresh catalyst morphology for a side-by-side comparison.
Figure 3 and 4 SEM’s of Fresh Catalyst (magnified X250)
“Bad Morphology” “Good Morphology” In conclusion, there are several characteristics of fresh catalyst that can be controlled to reduce particle losses and thereby reduce flue gas emissions. Specifically, to lower emissions the fresh FCCcatalyst should possess the following characteristics: a particle size distribution with an optimal range of 0-40 μ particles, higher catalyst particle density, lower DI, and superior morphology. Grace’s alumina-sol technology provides superior binding to the catalyst particle leading to best-in-industry attrition resistance. The versatility and performance of alumina-sol catalysts coupled with Grace’s manufacturing capability, have resulted in wide-market acceptance and as a result, Grace is the preferred FCC technology for loss sensitive units around the world.
Question 65: What are the impacts on coker operation (yields, capacity, energy, coke quality) of FCC slurry oil in the feed?
Gary Gianzon (Marathon Petroleum Company)
When one of MPC’s refineries starts processing heavy Canadian resid, they add 5 to 10 volume percent of slurry oil in the feed to mitigate making shot coke. The slurry also helps meet anode grade specifications on metals and sulfur. Processing slurry backs out resid processing which can impact unit economics.
FCCU slurry has a similar boiling range to heavy coker gasoil, so a large amount of slurry flashes out of the drum and ends up in the heavy coker gasoil product. The coke yield from slurry feed is around 2 to 3 x Concarbon (depending on coker unit operation) which is significantly higher than vacuum resid at 1.3 to 1.6 x Concarbon. If a high percentage (over 10 percent) of slurry is processed in the coker unit, the slurry can cycle up between the coker and FCCU unit. The amount of recycle built-up is somewhat self-correcting depending on operations in the coker and FCC and whether the HCGO is processed in a FCCU Feed Hydroteater.
Rajkumar Ghosh (Indian Oil Corporation)
We are adding approx. 3–4 wt% FCC Slurry oil in Coker feed in one of our Coker and about 10 wt% in another. We also had undertaken a study in the Delayed Coker pilot plant in our R&D centre. Our experiences with processing of FCC slurry oil in the Coker feed, based on field and pilot plant results, are as under:
a) Yield: The impact of slurry oil in Coker feed depends upon the quality of the base feedstock, CLO/slurry oil and also the pressure / temperature of the coke drums. If FCC slurry oil boiling point distribution and the coke drum pressure / temperature are such that most of the slurry oil vaporizes out of the coke drum, yield of coke and gas reduces with increase in distillate yield.
In case of Fuel grade Coker, with CLO (with minimum overlap of LCO) below 10wt% in VR feed, coke yield by and large may be constant or may increase marginally depending on the relative quality of VR and CLO. Yields of total gas and liquid decrease marginally. Beyond 10 wt% (10-20 wt%) of CLO in VR feed, the coke yield may increase up to 4 wt%.
b) Capacity: The Coke produced with significant FCC slurry in Coker feed (>10 wt%) has a close-knit Coke matrix which ensures good porous structure to the Coke bed. This reduces the chances of hot spots and blowouts. But the negative impact of adding FCC slurry is pronounced where the coke drum is already limiting, as the porous structure results in lower coke bed bulk density and hence lesser vapor space in the Coke Drum. It may limit the Coker capacity.
c) Product quality: Tendency of formation of Shot coke significantly reduces with the addition of FCC slurry in the Coker feed, as it keeps asphaltenes in solution form. As per our experience at Panipat Coker, impact of slurry addition in the Coker feed is clearly visible on the Coke quality w.r.t. reduction in Shot coke formation. With increased FCC slurry in Coker feed, increase in Silica content in the green Coke would be a criterion to limit its wt% in the feed. This is significant for the Cokers producing Anode grade coke. Typical limit of Silica in Anode grade green Coke is 0.02 wt % max. Depending on the quality of the slurry oil and unit operating conditions, there may be a negative impact on the quality of the LCGO and HCGO. They will become more aromatics and heavier.
d) Energy: Slurry processing will require higher heater duty. High aromatic content in the slurry oil prevents the precipitation of Asphaltenes and thus increases the heater run length. Injection of slurry oil into the coke feed is limited by refinery configuration. In our Refineries with FCC and/or Hydrocracking units, we limit the slurry oil within 5 to 10 wt% on fresh feed to Coker. Increase in injection rate can lead to a massive recycle between the Coker and the FCC or will result in accelerated catalyst deactivation in the Hydrocracker unit.
Eberhard Lucke (Commonwealth E&C)
In general, FCC Slurry has a similar effect as VGO in terms that it replaces residue in the feed and increases mainly the HCGO yield. The difference in this case is that FCC Slurry is a highly aromatic stream and is often used as additional Coker feed (up to 15wt% max. recommended) to reduce heater fouling and to push coke morphology to sponge coke (for anode grade coke). The heavy aromatics in the FCC Slurry help keeping asphaltenes in solution a lot longer and promote coke formation by poly-condensation, therefore increasing sponge type coke content in the coke bed (preferred for low sulfur, anode grade coke production). On the downside, FCC Slurry will contain entrained catalyst fines and – if too high in concentration – may have a negative impact on fouling rates in the charge heater(s). The fine catalyst particles can deposit inside the heater tubes, act as seeds for coking and may promote deposits of heavy oil and coke fines from the oil film inside the tubes.
Question 24: Given the potential consequences of back flow in high pressure hydroprocessing services, such as furnace tube rupture and pump shutdown, what layers of protection are being employed to reduce risk?
ESTEBAN (Suncor Energy, Inc.)
We are going to skip the first slide.
The second slide shows a simple depiction of the layers of protection that we use at our different sites. In some cases, we have relief protection, basic process controls, and critical alarm systems on our feed drums to prevent a backflow scenario or the consequences of a backflow scenario. That being said, though, relief valves do not always provide an adequate level of protection for high pressure units. So obviously, take that with a grain of salt. Our primary layer of protection is provided by our trip valves which are activated by SIL-rated instruments. We do not have an SIL rating in all cases; but in some cases, it is required to get the level of protection we need. And then, of course, we also employ dual check valves of differing types downstream of our pumps. Those check valves will typically wind up on our critical check valve system as well.
The scenario is similar where you have backflow. It is not so much the concern of backflow of reactor contents through the furnace, but more just a loss of containment in the furnace itself. We do not treat these furnaces in our hydroprocessing units any differently than we do any of our other furnaces in the refinery. They all have an integrity operating window that we would like to stay in. That window defines at what burner pressures we need to operate and, of course, at what skin and overall box temperatures we can operate.
Our layers of protection are very similar here in that we have trip valves activated by SIL-rated instruments and which are only SIL-rated as required. And of course, we have basic process controls and critical alarm systems. In some, but not all, cases, we do have check valves downstream of our furnaces. That is not a standard at all our sites. However, on some sites, we are consistent about having check valves downstream of our furnaces.
KEVIN PROOPS (Solomon Associates)
I would like to comment on the heater part of the question. Reactor charge furnaces potentially have substantially higher consequences of failure than do most of the other furnaces in your refinery, so you need to be a lot more scared of them than you do of the other ones.
First, this is generally an exothermic process; so, the best case is probably that the furnace is not firing or is only minimally firing. Adequate feed-effluent heat exchange reduces firing and thus the risk of failure from flame impingement. Second is the inherent safety design. If you can go to a single-phase furnace instead of a two-phase furnace, then if it does rupture, your consequence will probably be a lot less. That also gets into the control system issues. Some refiners use hot oil utility instead of a fired heater in the hydrotreater. This is inherently safer.
Then you get into how to avoid a tube failure in the first place. There are a lot of ways to do that, but consider dry point in naphtha units, burner ring pressure controls and interlocks, and maintaining the cleanliness of the burners (fuel gas filtering). Adequate burner-to-tube spacing, feed filtration, tube monitoring (thermography), operator rounds frequency, and upgraded tube metallurgy can all add layers of protection.
Finally, it comes down to culture as well. You do not want to get into a situation of risk of a failure competing with profit to keep the unit maximizing at full throughput. Unfortunately, I have seen a case where that did happen: A furnace was experiencing flame impingement, and the operators did not reduce charge to the unit. After one shift, a tube failed, which led to the entire unit being consumed in a flash fire within a few seconds. We were very fortunate that there was no one outside at the time it happened; if there had been, we would have killed anyone in the unit.
ESTEBAN (Suncor Energy, Inc.)
We do treat them differently depending on their operating pressures and/or requirements. Certainly, from a design standpoint, the operating envelope for each individual piece of equipment changes how the furnace is designed overall. That being said, we evaluate all equipment using the same standard with a process hazard analysis to determine the appropriate layers of protection. Given the required layers of protection, we identify additional safeguards as required by LOPA. SIL-rated instruments, for example, are not required for all burner management systems. However, in some cases, they may be required because the consequences of failure are higher.
So yes, the consequences are significantly greater on a high-pressure furnace. The assessed risk ranking would define how those layers of protection will appear. In some cases, you will see a simpler system on a furnace; and in others, much more complex layers of protection will be applied because of the potential consequences of equipment failure for that furnace. So, to re-phrase my response, I will say that we evaluate every piece of equipment using the same processes.
ESTEBAN (Suncor Energy, Inc.)
In order to reduce the risk of potentially catastrophic consequences related to backflow in high pressure hydroprocessing services Suncor Energy, Inc. uses several independent layers of protection at operating pressure boundaries. One common boundary is for hydroprocessing units, is between the unit feed drum and the reactor charge pump. A typical hydroprocessing unit will have relatively low design pressure equipment upstream of the reactor charge pump which boosts the operating pressure of the feed stream to the much higher reactor operating pressure. As such preventing back flow in the event of the loss of a feed charge pump is critical to prevent equipment failure in upstream equipment with catastrophic consequences. In this application Suncor Energy, Inc. applies the use the following layers of protection:
1. Primary protection is typically a Safety Instrumented System (SIS) that monitors the run status of the feed charge pump via multiple direct and indirect instrumented signals and activates quick acting trip valves and in some cases closes the feed charge control valves in the event of a shutdown. In some cases, depending on the unit specific hazard analysis these systems may be SIL-rated to ensure reliable operation when activated. In addition, these systems are often designed to be activated by any one of several different instruments used to sense a potential backflow scenario, i.e., low-low flow shutdowns and low-low feed controller differential pressure shutdowns.
2. In some cases, pressure relief valves are used as layers of protection for overpressure due to backflow, but caution must be applied when relying on a relief valve as protection for vessels, such as feed drums, since these valves are not always sized for backflow scenarios.
3. Mechanical safety systems are also employed depending on unit design. While these systems are often not credited in a process hazard analysis of a unit they can provide additional layers of protection. Typical installations include dual check valves of different design which are often deemed critical check valves that require routine maintenance.
4. Provided the design of the system and equipment in some cases basic process controls and/or critical alarms with operator response are employed as additional layers of protection.
In addition to backflow prevention and protection as it relates to pressure boundaries, furnace tube ruptures can result in backflow from multiple large high-pressure vessels to atmosphere with catastrophic consequences. In order to address the release of reactor and high-pressure circuit equipment, layers of protection must be applied to the feed furnaces that prevent operating windows that have the potential to create damage resulting in tube rupture. The layers of protection employed for this scenario do not differ from those on other furnaces in Suncor’s refineries, as all furnaces are evaluated for tube rupture scenarios. However, in this application Suncor Energy, Inc. applies the use of the following layers of protection:
1. Primary protection is typically a SIS that monitors furnace flows, temperatures, and fuel and box pressures via multiple direct and indirect instrumented signals and activates quick acting trip valves on fuel supply and in some cases closes the fuel supply control valves in the event of operation outside a preset operating window. These SISs often activate related SISs to stop process flows. In some cases, depending on the unit specific hazard analysis these systems may be SIL-rated to ensure reliable operation when activated. In addition, these systems are often designed to be activated by any one of several different instruments used to sense operation outside of the specified window, i.e., low-low flow shutdowns and high-high burner pressure shutdowns.
2. Mechanical safety systems are also employed depending on unit design. While these systems are often not credited in a process hazard analysis of a unit, they can provide additional layers of protection. Typical installations include check valves downstream of furnaces to prevent the backflow of reactor contents. In general, these check valves are not relied upon as fail-safe devices and are not considered critical check valves.
3. Provided the design of the system and equipment in some cases basic process controls and/or critical alarms with operator response are employed as additional layers of protection.
Question 96: What are your experiences using SOx reduction additives formulated with lower rare earth content?
Ray Fletcher (Intercat)
Cerium oxide functions as an oxidant and oxygen carrier: the mixture of two oxidation states Ce(III) and Ce(IV) creates defect sites in the crystal structure where oxygen ions are missing (oxygen vacancies) – these get filled up in the regen and ceria acts as a kind of monatomic oxygen sponge. Monatomic oxygen is more reactive than O2 hence ceria catalyses oxidation reactions. Also mixing in the regen is effectively improved as oxygen is transported around the regen as the particles move around.
Most other oxidants don’t do this (e.g., Pt promotes oxidation when two molecules meet on its surface, it doesn’t sponge the oxygen). So, ceria does play a rather special role. Simply decreasing the amount of ceria works to some extent, but clearly a point will be reached where efficiency drops off.
Intercat has developed and commercialized SOx reduction additives containing 50% less cerium. What Intercat has done is to “extend” the functionality of ceria by proprietary methods to improve the overall oxidation activity of the additive thereby allowing the ceria content to be decreased at equivalent performance. At present, there are now over 28 users of this technology. In every application the lower concentration cerium additive has performed equal or slightly better than the standard SUPER SOXGETTER.
Further, Intercat is utilizing proprietary technology developed within its new owner, Johnson Matthey, for further enhancements in cerium dispersion together with new oxidation packages which will enable a 75% or greater cerium oxide reduction. These technologies include the careful construction of the physical structure of the microsphere, deployment of manufacturing technology which controls both the location and the local concentration of the cerium particles plus the addition of co-promoters to the additive. These techniques have made it possible to improve the overall oxidation activity of the additive thereby allowing the ceria content to be decreased while maintaining equivalent SOx removal performance. Two trials of this technology have been initiated and are being base loaded into two North American refineries now.
Intercat, as well as other additive suppliers, has developed rare earth free SOx reducing additive. These additives of course are lower in cost but generally require much higher concentrations in the circulating inventory. Depending on the composition of the additive this may lead to cracking dilution and possibly loss in product yield. However, it is recommended that refiners employing SOx reducing additive consider these technologies in addition to the high activity additives described moments ago.
Matthew Meyers (Western Refining)
Western Refining LLC has recently trialed several SOx reduction additives with lower levels of rare earth. The first was at half the typical rare earth levels. At 1% dosing, the result was a pickup factor of roughly 15. The second addition had zero rare earth and provided a pickup factor of roughly 5 at close to 3% dosing.
Eric Griesinger (Grace Davison Refining Technologies)
Grace Davison’s SOx reduction additives, formulated with lower rare earth content to lessen the impact of hyperinflationary costs associated with rare earth compounds, have gained wide acceptance. Within Grace’s portfolio of SOx additive products and its accounts, customers that were able to make a change to lower rare earth formulated SOx additives have done so. FCCU locations currently operating under EPA Consent Decree trial protocol have remained with the original formulation available at the start of their trial periods. Only two additional refineries are in the midst of evaluations between Grace’s Super DESOX® additive and Grace’s alternative products. Otherwise, all of Grace’s globally situated customers, existing and newly acquired, are utilizing SOx additives formulated with lower rare earth content. Grace offers three new SOx reduction additives: Super DESOX® OCI, Super DESOX® MCD, and Super DESOX® CeRO. Super DESOX® OCI, optimum cerium input; mitigates costs associated with rare earth compounds, while demonstrating on par pick-up-factor efficiency to Super DESOX® additive. Super DESOX® MCD, maximum cerium dispersion, further reduces rare earth cost exposure, yielding suitable and cost-effective balance between SOx transfer ability and slightly increased dosing rate. Additionally, Super DESOX® CeRO is formulated without rare earth compounds. All three of these new products build on the success of Grace’s Super DESOX® additive performance. These offerings provide refiners with a range flexible option, enabling a balance between rare earth inflationary exposures and dosing rates, to achieve SOx emission compliance.
Below is an example of a refiner that historically utilized Super DESOX® and then switched to Super DESOX® OCI. Observed is the ability of Super DESOX® OCI to continue controlling SOx emissions within limits, at comparable dosing rates as was the case with Super DESOX®. Utilizing Super DESOX® OCI over Super DESOX® can result in a SOx additive cost reduction roughly 35%.
Additionally, Grace Davison’s laboratory scale research indicates that the partial burn environment performance of Super DESOX® OCI and Super DESOX® MCD is similar to that of Super DESOX®. Please contact your local Grace Davison sales and technical service representative for additional insight specific to your application.
Question 34: What are your current protocols, practices, and concerns for using wireless communication between field instruments and the control room? Would wireless communication be acceptable for monitoring only, or is control allowed as well?
LOGEROT (Prosys Inc.)
The question asked about the protocols. But rather than naming the protocols, I think it would just be best to describe what the installation looks like. With wireless transmitters that are in use, you are usually installing a mesh network and you have a Modbus gateway connected to the DCS. You have a separate wireless gateway that is connected to that as well, and the wireless gateway connects to all the transmitters. Each one of the transmitters can actually act as a hub and is able to receive and transmit data with the other transmitters. That way, transmitters can find other transmitters close by and multiple pass-backs to the gateways. So, if a transmitter is out of service for any reason, the other transmitters will basically find pathways around it to get communication back to the wireless hubs.
Note that in this kind of arrangement, you need to have a robust gateway; because basically, the wireless gateway represents a single point of failure. Therefore, most installations use redundancy there, sometimes triple redundancy, to make sure that communication stays open.
Where are the main uses of wireless in refineries today? In our experience, they are usually remote areas of the refinery where a signal and power wiring are not easily run out. The big advantages, obviously, are cost savings, conduit wiring, and cable trays. Inside the battery limits of, say, a crude unit, wireless is not as common. Where used, it is usually for auxiliary type of measurements such as corrosion monitors, vibration monitors, additional temperatures, and pressures that are not central to the process. You might also consider wireless technology, as sometimes we have outside operators who have handheld devices that are wirelessly connected back to the control room. For that one-ring device, there will also be a network of gateways available for the wireless device to communicate back to the control room.
What are the concerns associated with wireless technology? The first real concern is cybersecurity. I mean, everyone is concerned about security these days. Basically, every wireless device and transmitter in your plant represents a potential entry point for intruders. So, you have to be very careful to put in strong security protocols to make sure that intruders will not get into your network. What can happen from an attacker? An attacker can jam your signals. You could lose proprietary data, and – worst of all – an attacker could end up gaining control over part of your process. You really do not want that to happen, which is why security is a big concern when using wireless. Second is overall reliability. Basically, we have been using hardwired signals for decades. Wireless signals are just not as robust in today’s technology as are the hardwired signals. For example, how often do you have to go reset the Wi-Fi in your house? That is an example of when wireless is not as reliable as it could be.
The last part of the question had to do with whether wireless is acceptable for control or if it is just for monitoring purposes. When I say ‘control’, I am talking about closed-loop control where you have a wireless transmitter communicating to the control room and there is a control action. They then signal out to the final element, usually a valve. It is probably also wireless, but it might be hardwired; but there is at least some component in that closed-loop control that is wireless. Our typical answer is that it is just not used very often for closed-loop control, and it is usually not recommended. One of the problems is battery life, because the transmitters you are using in the field are battery-operated. If you have a very high refresh rate – like, typically, a five-second refresh rate, then your batteries will die too quickly. That is one reason why you would not want to be using wireless for controls. So, generally speaking, it is not recommended or used. However, that is not to say that wireless control will not, sometime in the future, be relatively common.
THEISS (Marathon Petroleum Corporation)
The chart on the slide is really the internal guidance we use at Marathon. You can see that for what we call Class 0 and Class 1, we do not allow wireless communication, which basically inputs to an SIS (safety instrumented system) or some control point that is detrimental to the process. An example of a detrimental control point would be an FCC (fluid catalytic cracking) reactor/regenerator pressure differential transmitter for which we would not allow wireless control.
There are a couple of applications in which we allow control. I do not think they are widely used within Marathon; but with some corporate guidance and corporate technologist approval, we can use them wireless for control. These would be considered Class 2. An example would be a tray tower control for a temperature.
As you move further down the chart to Class 3, you can see an example of where you have the overhead water boot. You have a remote signal that goes into the board, but it relies on the operator to go out and make the move to drain that water boot and start to pump or open up a valve. Class 4 and Class 5 are really for informational purposes. My example for a Class 4 would be a secondary alarm on a tank where you have a primary alarm that is hardwired in and a secondary level or a backup level that could be used remotely. Class 5 would be temperature indication on heat exchangers just to gather data for fouling.
JEREMY THEISS (Marathon Petroleum Corporation)
Technology continues to progress in this field. Since 2011, we have had guidance that allows some usage of wireless instrumentation, but this technology is limited based on application. The table below identifies our stance on certain applications.
CATEGORY |
CLASS |
APPLICATION |
DESCRIPTION |
WIRELESS ALLOWED? |
Safety |
0 |
Emergency Action |
Always Critical: fundamentally necessary for reliable SIS functionality |
No |
Control |
1 |
Closed-loop regulatory |
Often Critical: required for continuous stable unit operation |
No |
2 |
Closed-loop supervisory |
Usually Non-Critical: not required for continuous stable unit operation |
Yes, with approval from corporate technologists and site engineering |
|
3 |
Open-loop control |
Human in Loop: Signal processed by human, human manipulates field device |
Yes, with approval from corporate technologists and site engineering |
|
Monitoring |
4 |
Alerting/alarming |
Potential short-term operations consequence |
Yes, with approval from site engineering |
5 |
Logging |
No immediate operations consequence |
Yes, with approval from site engineering |
Examples:
Class 0: Inputs to a Safety Instrumented System
Class 1: FCC Reactor/Regenerator pressure differential transmitter (used to manipulate flue gas stack valve)
Class 2: Tower tray temperature
Class 3: Water boot high/low level where control or field operator starts/stops a pump or opens/closes valve
Class 4: Storage tank secondary level alarm
In most of the approved applications, redundant wireless gateways are required to minimize disruptions to a failed gateway. Other points to consider for determining if wireless is acceptable include the required scan rate of the application, wireless distance limitations, and potential for wireless interference. Guidelines should be made to ensure battery life or alternate power to the wireless device is sustained and has monitoring capabilities.
DARWIN LOGEROT (ProSys Inc.)
Wireless Protocols
Rather than naming the protocols in use, it is probably better to describe the installation. Where wireless transmitters are in use, they are often installed in a mesh network similar to cellular towers or a Wi-Fi network with multiple hubs. A Modbus gateway is connected to the DCS and to the wireless gateway that is connected to all the transmitters. Each wireless transmitter acts as an individual hub and is able to receive and transmit data with others. This way, a transmitter can find other transmitters close by and have multiple paths to the wireless gateway. If one or two transmitters are out of service, the remainder will adjust to provide continuous communication.
In this arrangement, a robust wireless gateway is important. If only one wireless gateway is provided, it can represent a single point of failure, potentially losing view of all instruments using that path to the DCS. Users will typically install redundant gateways to mitigate this.
So, where are the main uses of wireless technologies in refineries today? The locations are usually remote where the signal and power wiring are not readily available. The big advantage is cost (savings in conduit, wiring, cable trays, power distribution, etc.) and the ability to monitor remote data, such as in a large, spread-out tank farm.
Inside a refinery process battery limit, use of wireless is not so common. Where it is used, some of the more common wireless applications are in corrosion monitors, vibration monitors, and additional temperature and pressure monitoring on vessels and exchangers (auxiliary to the hardwired temperatures and pressures).
Another use of wireless technology is for hand-held devices used by field operators. With this arrangement, another mesh network is employed to connect the wandering device to the DCS. The field operator can use the device to monitor operating conditions, execute periodic rounds, and take notes regarding observations. Major DCS manufacturers are offering this technology as an extension of the control system, but the control itself is done with hardwiring; only monitoring and setpoint adjustment are done through wireless.
What are the concerns associated with wireless technology?
First and foremost is cyber security. Every wireless device represents a potential entry point for an intruder. Security protocols are better and stronger now than ever, but many potential users are still reluctant to install extensive wireless devices. Security concerns include the possibility of wireless signals being jammed by an attacker, potential loss of proprietary data, or, worst of all, an outside intruder gaining control of part of a process.
The second concern is reliability. Wireless communication generally is less robust than hard-wired connections.
A third concern is the data refresh rate and its connection to battery life. For example, a one-minute update rate on the transmitters was tied to a life of about 10 years, whereas an update rate of four seconds reduced that life to two years. The relationship between refresh rate and battery life, of course, impacts how wireless can be used for basic control and impacts wireless maintenance costs.
So, is wireless communication acceptable for process control?
Allowing for a slightly wider definition of “wireless control”, it is in widespread use today – the plant radio. For example, the console operator can contact the outside operator: “Hey, go open/close the bypass valve around the control valve that is not working.” But more seriously, purely wireless communication for process control in a refinery is seldom used or recommended, especially in a unit that is tightly connected geographically, such as a crude unit or FCC. Where wireless communication is in use, it is almost exclusively for monitoring only, primarily due the problems outlined above. The closest approach to wireless control is using the handheld devices to adjust setpoints. The control itself is still through hardwire communications from the transmitters to DCS controllers and to the valves.
That said, there is no reason to expect that as technology improves, the current problems will not be overcome, at least in part. Perhaps future refineries will include widespread use of wireless process control.
Question 40: As it relates to overall catalyst cycle life management, please address the following issues: What are typical cascading practices for catalyst reuse after regeneration and eventual disposal that you employ? What quality control, catalyst properties and performance specifications, and/or warranties do you have in place for regenerated catalysts? What are some of the key decision criteria you use in determining whether to send a catalyst for metals reclamation, r
JAMES “TIM” CAMPBELL(Eurecat U.S., Inc.)
First, a response to the question: What are typical cascading practices that you employ for catalyst reuse after regeneration and eventual disposal? As the leading catalyst regenerator, Eurecat sees NiMo and CoMo hydrotreated catalysts (regenerated and regenerated plus rejuvenation) in ULSD, jet, kerosene, naphtha, and gas oil hydrotreating units. There is growing use of regenerated hydrocracking catalyst. These regenerated catalysts, or those regenerated and rejuvenated, may be used as an entire load or a partial load, depending on the specific application. Catalyst reuse management can provide substantial savings to the refining organization.
The second question concerned quality control, catalyst properties and performance specifications for regenerated catalysts. Eurecat has specific catalyst regeneration specifications for:
*Contamination metals (such as Si, As, Fe, Ni, V, Ca, Na),Physical (length/diameter, length distribution, and crush strength),
*Pressure Drop (measurement regenerated catalyst pressure drop versus fresh catalyst), and
*Activity (measurement of HDS activity versus fresh catalyst).
LIFENG ZHENG (Criterion Catalysts & Technologies)
Depending on the condition of the catalyst post regeneration, the catalyst can be cascaded to a less severe service [USLD to kero (kerosene), kero to naphtha, etc.] where the catalyst performance is less sensitive to activity. Regen can also be used on non-activity-constrained higher performance units or in units slated for a short cycle due to turnaround planning in, for example, the top bed of ULSD unit. In certain instances, it may be necessary to install some fresh catalyst to make up for a potential loss of activity and volume of the regenerated catalyst.
After a conventional regeneration and depending on the type of catalyst (Type I or II), the catalyst will typically regain anywhere from 70 to 95% of its fresh catalyst activity. Here your catalyst vendor can give guidance on the expected recovery for the particular catalyst. There will be physical catalyst loss due to breakage and attrition of pellets during unloading and regeneration that will need to be taken into account. Part of a catalyst bed that is unloaded may not be suitable for regen depending on the feed poisons and physical condition of the spent catalyst. Contact the regen vendor for additional details regarding warranties and catalyst properties on regenerated catalyst.
Some refiners actively manage a pool of their own regenerated catalyst because they can keep track of the condition of the catalyst based on the service and feed contaminants to allow cascading. Where it makes sense, Criterion works with the refiner to incorporate the regenerated catalyst into the planned loading for the next cycle. In a recent example, we successfully helped a customer transition catalyst from the bottom bed of a ULSD unit which was prematurely shut down into the top bed of a medium severity FCCPT unit in order to assist the customer with maximizing catalyst utilization.
The business case for selecting metals reclamation, regeneration, or disposal is ultimately based on economics. Regeneration is chosen when a use for the regen catalyst is identified within the refinery, if it is needed in the shared regen pool, or if there is a known market for this particular catalyst load and a third party is willing to purchase it. Service history is critical as catalysts with suspected high poison levels are not suitable for reuse. The catalyst cannot be vacuum-dumped, caustic-washed, or otherwise mishandled if it is going to be regenerated.
If the catalyst is not going to be regenerated, then it must either be reclaimed or disposed. Pricing and yield of precious metal could impact returns on metal reclamation. Reclamation companies usually charge a service fee for processing spent catalyst and give a credit for a portion of the metal reclaimed. Depending on the metals market, the metals credit can cover the processing fee; but with current depressed metals pricing, the credits usually do not offset the costs.
Disposal of spent catalyst is rarely done due to cost and potential environmental impacts. The transportation and disposal of spentcatalysts are governed by DOT (Department of Transportation) and RCRA (Resource Conservation and Recovery Act) regulations. The hazardous waste must be properly disposed of at an approved treatment, storage, and disposal facility.
HENRIK RASMUSSEN (Haldor Topsoe, Inc.)
For many years, refiners have cascaded used catalyst from a high severity to a lower severity service within their refinery. In order to do so, the catalyst needs to be regenerated and properly evaluated to make sure the level of poisons on the catalyst is acceptable for reuse in any service. Topsoe has, for many years, offered our proprietary ReFRESH™ technology, which is an add-on to the regeneration procedure. The ReFRESH™ process will restore the catalyst to 95+% of its original fresh activity, thus enabling the refiner to use the ReFRESH™ catalyst in the same service from which it was removed without any noticeable penalty in performance or cycle length.
In order to ensure that the spent catalyst is a good candidate for regeneration, as well as a candidate for the ReFRESH™ technology, we have generated the following guidelines. The spent catalyst should meet the following criteria:
*Surface area greater than 80% of fresh catalyst surface area,
*As(arsenic)lessthan0.1wt%,
*Pb (lead) less than 0.15 wt%,
*Na (sodium) less than 0.3 wt%,
*Si (silicon) less than 1.0 wt%,
*Fe (iron) less than 1.0 wt%,
*No other metal [Ni(nickle), V(vanadium), etc.] higher than 1.0 wt%,
*Total contaminant level less than 2.0wt %,
*Average length of particle higher than 3.0 mm(milliliters) for 1/20” TL (transferline), and
*SCS(syntheticcatalysticscavenger)higherthan2.5lbf/mm (pound-force foot to Newton millimeter).
Catalyst with contaminant levels higher than shown above should be set aside and sent for reclamation, because it is not economically justifiable to spend money on regenerating and investing in ReFRESH™ technology for this material. Every year, Topsoe applies our ReFRESH™ technology to millions of pounds of regenerated catalyst, which are used again in high severity hydro treating applications such as ultra-low sulfur diesel and FCC pretreatment. Many of our clients have used the same catalyst up to three times.
Question 36: What changes have you made to the C5/C6 Isomerization unit to comply with the new benzene regulations; what changes have you made to the refinery operation; and what have been your challenges and successes of implementing the new configuration?
Olivier Le-Coz (Axens)
More severe regulation in term of Benzene in the gasoline pool can lead to increase the Benzene content to the C5/C6 isomerization unit. This can happen in two different ways.
The refinery process operation can be modified to decrease the benzene precursors content in the heavy naphtha to the Reformer. This is achieved by increasing the light naphtha end point in the topping lights ends naphtha splitter, light naphtha being the Isom unit feed. At the same time C7+ in the Isom feed must be limited to 2 – 3 vol% as those products will undergo undesired hydrocracking reactions in the Isom reactors. With such a scheme, straight run naphtha Benzene (native Benzene) is basically treated in the Isom. This approach can typically be applied in the frame of a new project.
When the “pre-fractionation” scheme cannot be implemented or if it cannot allow reaching the overall pool Benzene specification, a “post-fractionation” option can be implemented. It consists in splitting the reformer product and recover a light Benzene rich reformate which will be treated in the Isom unit in blend with the light straight run naphtha. Depending on the Isom unit existing configuration, some modification to the hardware may be required or not. As a matter of fact, Benzene concentration at the Isom reactors inlet should better not exceed certain value to ensure proper operation and performances of the Isom catalyst (about 4 vol%).
-If the Isom unit is equipped with a recirculation, the recirculated stream acting as diluent may allow maintaining Benzene below the desirable value at the reactor inlet. The extra Benzene amount in the feed will be hydrotreated by the Isom catalyst without disturbing too much the operating conditions and without preventing suitable isomerization rate to be achieved.
-If the Benzene content at the inlet of the reactors cannot be maintained low enough (too low or no recirculation), a dedicated Benzene saturation reactor must be added.
In the case of new units implementation, those schemes have proved to work very well. In the case of revamp projects, existing equipment modifications or idle equipment reuse, a through basic design study upfront including the catalytic aspects is strongly recommended.
Brad Palmer (ConocoPhillips)
In general, refineries with C5/C6 Isomerization units or Aromatic Extraction units have increased feed rate and/or benzene content to these units. Reformer octane has gone down due to ethanol blending but, in most cases, Isom octane demand has remained strong. The primary successes include implementing these projects safely and achieving our benzene reduction requirements. Additionally, heavy reformate blend qualities have improved which has made blending premium gasoline easier and has provided additional opportunities for blend component sales.
A number of technology options were chosen by ConocoPhillips refineries to meet benzene regulations according to the existing configuration and site economics. These options include revamping Aromatic Extraction Units (AEUs) to increase feed and benzene production capacity, sending light reformate or heart cut to other AEUs, modifying C5/C6 Isom units to include benzene saturation reactors, new benzene saturation unit construction, reducing benzene production through prefractionation and use of credits.
All completed projects are working, some with very few operating problems and a few with requiring design modifications and/or operating changes. Operating, design and reliability issues continue to be worked to improve unit performance; a few specific examples are provided below.
Isomerization Unit Challenges
-When all benzene saturation reactors are complete, two will have Pt catalyst and four will have nickel catalyst. One of the reactors will have changed from Pt to Ni.
-The units that added a benzene saturation reactor in front of their Isom reactors have had challenges controlling temperatures profiles of all three reactors especially when liquid recycle is added or removed.
-Isom units have heavier feeds (increased X-Factor). One unit has and XF of 30 lv% average (35 lv% highest) and 9 lv% Benzene Average (10 lv% highest). Another unit has an XF of 25 lv% average (27 lv% highest) and 5 lv% Benzene Average (10 lv% highest).
-Determining when and how much liquid recycle is necessary for safe operation while maximizing fresh feed throughput has taken time. Vendors advertise an upper benzene level of 5 lv% to the inlet of a benzene saturation reactor. While we have gone a little higher by lowering the inlet temperature to accommodate the exotherm, this is a good rule of thumb.
-Increased unit rate can impact dryer operation by fluffing up-flow desiccant beds. Higher rates increase HCl loading to existing caustic scrubbers; less than adequate neutralization can lead to corrosion problems.
-Benzene saturation catalyst has been deactivated or poisoned by feed (organic sulfur, H2S, FeS, Chlorides) or hydrogen purity (CO and CO2) problems.
Aromatic Extraction Unit Challenges
- Changes in feed quality have required operations to find new equilibrium; one unit has reported bigger swings in aromatic content with new feed streams.
- Stripper foaming has occurred in one unit.
Ujjal Roy (Indian Oil Corporation)
In India, the benzene specification in gasoline is 1 vol.% max. In order to meet this specification, number of changes in the refinery configurations have been done. (a) Light Naphtha splitter has been introduced to produce C-5 & C-6 isomerization feed. (b) Naphtha splitter modified to reduce Benzene precursor from Reformer feed Naphtha. (c) Reformate splitter has been installed to separate Benzene from the Reformate. Over and above FCC gasoline being a component of Gasoline, for reduction of Benzene, a FCC gasoline splitter has been put to take away the Benzene rich cut called Heart Cut from Gasoline. For meeting benzene regulation in the Gasoline, Isomerisation unit has been designed with catalysts having dual functions – Isomerisation and complete saturation of Benzene. The metal sites are used for saturation of benzene and acid sites are used for isomerisation of C-5/C-6. Up to 9.8 vol.% benzene in feed, catalyst is able to saturate to nil level of benzene in isomerate.
Erik Myers (Valero)
The Valero approach has been to consolidate the benzene rich streams from various refineries and capture benzene as a product stream. This has been accomplished through use of a side draw stream from the reformate splitters and then feeding these streams through a centralized benzene extraction unit.