Director, State and Local Outreach
American Fuel & Petrochemical Manufacturers (AFPM) is a dynamic trade association representing high-tech American manufacturers of virtually the entire U.S. supply of gasoline, diesel, jet fuel, other fuels and home heating oil, as well as the petrochemicals used as building blocks for thousands of vital products in daily life, from paints to plastics, space suits to solar panels, and medicines to mobile phones.
AFPM is looking for a knowledgeable and impactful Director, State and Local Outreach to join our team of government relations and regulatory affairs professionals. This position plays a key role in the development, implementation and management of AFPM’s outreach strategy at the local, state and national levels. This position educates elected officials, stakeholders and consumers about the fuel and petrochemical manufacturing industries, leads AFPM’s outreach to third-party and non-traditional allies, and impacts national policies and proposed legislation at the state and local levels.
This is a full-time exempt position, reports to the Vice President, State and Local Outreach, and manages a team of four. This position requires frequent local and regional travel.
Responsibilities
- Identifies opportunities to educate various state, local and federal-level elected officials on issues important to AFPM’s membership, including working with third-party entities, to deliver AFPM’s message to assigned legislative bodies.
- Collaborates with the Vice President, State and Local Outreach, Government Relations department, and other AFPM staff to identify and prioritize issues that constitute the focus of AFPM’s state-level educational engagement.
- Assists the Vice President in managing the State and Local Outreach Committee, keeping members informed of all legislative and regulatory issues important to the industry and helping plan and execute monthly committee meetings.
- Represents AFPM at conferences and events, including direct interaction with a broad spectrum of state-level elected officials to articulate AFPM’s positions on a range of critical policy issues, and occasional public speaking engagements.
- Manages a coalition of groups engaged in issue-specific, regional educational advocacy efforts, including coordinating with independent contractors, monitoring legislative developments, and serving as AFPM’s primary point of contact for coalition members.
- Work closely with the Vice President, State and Local Outreach to maintain efficient and effective communications with members to ensure that AFPM’s outreach efforts remain aligned with member expectations and that members are well-informed regarding the outcomes of our engagement.
- Coordinates with AFPM’s Communications department to develop proactive messaging through social media, op-eds, speaking opportunities, blog posts and other means.
- Identifies and engages other relevant associations and entities to coordinate strategic educational and relationship-building efforts.
Qualifications
- Minimum of 6-8 years of professional experience in third-party outreach and issues advocacy in an association or industry, issues or candidate campaign management, and/or congressional or state legislative experience.
- Experience with and strong knowledge of federal and state regulatory and legislative processes in connection with energy issues.
- Firm understanding of the regulatory processes and implications of federal energy and environmental regulations at the state level.
- Exceptional communication skills, including presentation skills, evidenced by experience in communicating advocacy positions verbally and in writing.
- Strong working knowledge of traditional and new media, including social networks and web multimedia.
- Keen attention to detail, including the ability to proofread and fact-check accurately and quickly.
- Experience managing a team of professionals, collaborating and working in a team environment, and working alongside and with other departments.
- Willingness and ability to travel locally, regionally and nationally as required.
- Bachelor’s degree in government relations, communications, or a related field.
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Question 11: What process or catalyst options are available for shifting yield selectivities from gasoline to distillate while minimizing the impact on light olefin yields? How are the product properties impacted? How does change-out rate impact the viability of the catalyst options?
HEATER (BASF Catalysts)
Undercutting gasoline into light cycle is the first option and is widely employed. It is quick, it is easy, and it gives an immediate impact. Reducing riser temperature and/or cat-to-oil ratios reduces conversion, while using a ZSM-5 additive to regain C3-C4 olefins is another option.
Change-out is always an issue, particularly when the unit has a large inventory. When change-out is being done to take advantage of a small window of opportunity, consider using an accelerated change-out schedule with purchased e-cat of similar properties and technology.
Undercutting gasoline is a flexible option. As I mentioned, it is already commonly practiced, in addition to reduced conversion via lower riser temperature, and/or lower catalyst activity. Unfortunately, the bottom yield tends to increase faster than LCO as conversion is reduced, and I will have some charts in a minute to show that. You can use a heavier feed, but coke, gas, and product quality constraints may limit, for example, the wt% sulfur of some of your products.
With slurry or heavy cycle recycles, second pass yields are very non-selective. High coke and gas yield tend to be the result, with lower quality LCO that will typically require higher air rate or a lower feed rate to heat balance. And when you go to a lower feed rate, it may end up reducing your net LCO production.
Catalytic requirements for maximum distillate: Increased Lewis acidity versus Bronsted acidity decreases the zeolite-to-matrix ratio, which will increase LCO production and give you better bottoms-up grading capability than you get by dropping riser temperature only. In a minute, I will show a slide to demonstrate that. You need a catalyst with good coke selectivity by selecting the right pore architecture. BASF has commercialized products designed for distillate maximization and continues to work in that area.
This is a chart of light cycle and bottoms yield versus e-cat activity. You can see that as you decrease activity—that is, go to the left on the X-axis—slurry yield increases slightly faster than does LCO yield.
The next slide is LCO and bottoms yield versus reactor temperature.
I apologize to my American colleagues for the degree C, but here you see a decrease in riser temperature, once again, going to the left on the X-axis, which gives a much larger increase in slurry than does LCO. So that is generally not the best option.
The point of this slide is to show that there is a difference in catalyst. This is data from our e-cat data-benchmarking database. There is a difference in catalyst when you are looking at LCO yield at a given conversion. Your selection of catalyst can impact that, so you definitely want to talk to your catalyst supplier and see what they can do for you in the area of distillate maximization, if that is important to you.
THOMPSON (Chevron)
I agree with the previous comments about undercutting gasoline. That is certainly an option. Cat-to-oil reduction is also another processing option. As far as the catalytic options, bottoms cracking additives are a quick way to get increased LCO. You can also use ZSM-5 to basically make light olefins at the expense of gasoline. The problem there is that you have to make some other moves on the unit. That does not give you more LCO by itself.
The other thing you can work with is zeolite content, as we have mentioned earlier. Zeolite rare earth is another way to handle it, particularly for those who want to make higher quality LCO, since if you reduce rare earth, you are going to minimize hydrogen transfer, which is helpful.
One final comment is that there is not much potential for making distillate when you are processing very paraffinic or highly hydrotreated feeds. Conversion tends to be very high and gasoline is favored over distillates.
WARDINSKY (ConocoPhillips)
As we pushed FCC rates in this industry, one of the things that we have seen is that the diesel range material in your feed typically can be 15% to 20%. And if you think you are going to be in a distillate market for a long time, it is diesel range of material that you are downgrading to LCO, if distillate is valued over gasoline. So you may want to look at upstream projects to get that diesel range material out of your fresh feed. The other thing that we have seen people do is start installing slurry vacuum strippers to try to recover LCO out of the slurry.
One thing I wanted to elaborate on a little bit is severely hydrotreated feedstocks. We have moved a couple of our units to that type of operation and we believe that distillate mode may be limited with that kind of operation, because first of all, there are fewer LCO precursors in the feed following severe hydrotreating. You are also going to want to retain high e-cat activity and high riser severity to keep your regenerator dense bed temperature up.
Finally, in order to maintain level in the bottom main fractionator, we have seen those operations move to try to maximize heat recovery from the HCO and slurry pumparounds. So you are effectively dropping LCO material down into the bottom of the fractionator and losing it there. If you move to that kind of operation, be aware of what the pitfalls may be.
SHANKAR VAIDYAHATHAN (Fluor Corporation)
My question is regarding the heavily hydrotreated feed. Is it 1,000 ppm sulfur severely hydrotreated feed that affects the selectivity to diesel products? Or, at what severity do you begin to affect the selectivity of diesel range material?
WARDINSKY (ConocoPhillips)
We have a couple of units that run with 150 ppm feed sulfur. It is a 2,000 psia hydrotreater. It is putting in about 1,000 SCFB of hydrogen. The light cycle yield is only in the range of, say, 7% to 8%. They are running a 90 to 92 conversion.
THOMPSON (Chevron)
We have a similar operation at one of our units. They make ULSD off of the feed hydrotreater.
KEVIN PROOPS (Solomon Associates)
I would like to thank Mike for his comment. I was going to say largely the same thing; that the FCC is a gasoline-making machine. If this question was motivated by the high diesel prices in 2005 and 2006, the right answer is to get the barrel out of the cat cracker in the first place. Pete Andrews asked me to say that, by the way. [laughter]
If you have a scorecard that says you want to reward your refinery FCC people for keeping the FCC full and keep going on your same project, Mike mentioned to go get some of the gas oils out of the bottoms and put that in the FCC instead. It is the crude vacuum unit sometimes, and it is also coker gas oils in the gas oil hydrotreater. At the refineries where I have worked, we have seen that there is a lot of the diesel in the coker gas oil as well, and that is certainly fertile ground to go chase.
The comment in the question that asks about minimizing impact on LPG yield: In the past, I have seen that distillate tends to make a fair amount of LPG. So if the questioner is asking about maintaining yield, that is easy: That is overcrack. Or just put some ZSM-5 in if you have to, so that should not be an issue. I think the right answer is to keep the distillate out of the FCC when you can.
HEATER (BASF Catalysts)
No.
DOC KIRCHGESSNER (W.R. Grace Refining Technologies)
We have commercialized a catalyst system that we call Genesis and reported on it in our most recent catalogram, which has been issued for this meeting. In it, we discuss the success of this type of technology, particularly for upgrading bottoms into LCO without running into coke selectivity disadvantages. In terms of shifting economics, I think Mike pointed out, or Kevin said, that cat crackers are primarily gasoline machines. But as economic changes require a shift towards higher value for diesel, we find that it is easy to adjust the formulation of these catalysts, both for activity and for upgrade into LCO.
RAY FLETCHER (Albemarle Catalysts)
It might be interesting to let the audience know that Albemarle Catalysts has spent a substantial amount of research on this question of shifting gasoline into diesel. And, as we all know, the FCC is an asset that is designed genuinely for making gasoline. We have a catalyst that is now in the scaling-up process. We gave a presentation in Athens earlier this year, in timing with our patents going public. The catalyst is designed to make the FCC a max diesel engine. This catalyst is capable of increasing the diesel yield by 20% to 25% volume relative. But, at the same time, it reduces the LCO aromatics by 40% to 45% absolute. And if you use just a simple rule of thumb that equates aromaticity to cetane number, which is basically taking the delta in LCO aromatics and multiplying it by 0.6, you get an approximation of what the cetane improvement would be. This would give us an improvement of about 25 cetane number.
This material has been produced on a small scale. We have put it into a small heat-balanced unit running about 200 liters a day, and it produced the same yield selectivities as in our laboratory work. Again, this material is in scale-up. It probably will not be available for sale at least until next year, probably towards the end of next year, but there is light at the end of the tunnel for those refiners who wish to shift their FCC from a gasoline engine to a diesel engine.
ED PALMER (Mustang Engineering)
I had a question for the commercial experience for the severely hydrotreated cat feed, the LCO. By property, as far as gravity, is it still less than 20 and still around 50% to 60% aromatics?
THOMPSON (Chevron)
Yes. I would agree with that because those operations tend to run higher severity. It depends, in part, on your catalyst. If you are running a high activity, high matrix catalyst, you are going to get a lot of hydrogen transfer; and that is going to basically pull hydrogen out of the LCO and into the gasoline. So you can change your catalyst formulation. You can go to a low hydrogen transfer catalyst and help that a bit; but generally, the LCO quality is not nearly what you would expect for good quality diesel.
WARDINSKY (ConocoPhillips)
Gravity is at about the same range as it was prior to the feed shift. I do not know the answer to the aromatics question, whether the aromatics content has changed or not.
JIM WEITH (Mustang Engineering)
You mentioned the vacuum flasher on slurry. I did advise at a refinery in Wyoming where they had this. It was a tower that was hooked onto the side of a vacuum tower. They ran the slurry through it, and reportedly, that was going to pull the distillate out of the slurry and put it into the light cycle or into the light vacuum gas oil that then went off to a hydrofeeder and out somewhere. The vortex meters on it were too big at the time, so we really could not get a real good material balance on it; and I left before those got replaced. It did look like it was doing some benefit. And being close to Halloween, it might be a note that this was called the slurry flasher. But if you listened to people in heated conversations, it got slurred a little bit into becoming the furry slasher.
Question 12: For FCC units with closed riser termination device (RTD)/cyclone systems, do you operate with the primary separator sealed or unsealed in the stripper bed? What differences in performance do you see between these modes? Which do you prefer?
WALKER (UOP)
The answer to this question depends on the specific RTD technology. Regardless of the technology, the objective should be the same: a) disengage the catalyst from the hydrocarbon quickly and efficiently—in other words, minimize residence time from the riser exit to the main column entry; b) complete stripping of the catalyst quickly and efficiently; c) prevent hydrocarbon vapors from entering the annular space between the RTD and the reactor where they might overcrack; and d) the design should be robust and able to tolerate upsets and rough startups without catalyst losses.
This is all easier said than done. The question suggests that a catalyst seal is required to prevent hydrocarbon from entering the annular space where it might overcrack. This is one way to accomplish containment. Another way to accomplish containment is to properly design internal hydraulics with sufficient annulus purge steam. In this scenario, the purge steam will flow into the disengager rather than allowing hydrocarbon to escape from the disengager into the reactor annulus. This way, the disengager can operate unsealed. Operating unsealed eliminates the dense bed, submerging the primary disengager, and consequently minimizes hydrocarbon entrainment into the dense bed where it might overcrack.
At UOP, we have designed our VSS reactors both ways. Our VSS riser termination devices are internally stripped, so very little hydrocarbon is entrained into the dense bed. Consequently, at most units, sealing or unsealing is a non-event. However, in a few units, we have observed either a slight penalty or a slight benefit. The disengager hydraulics and stripper efficiency and configuration can impact the results. The secondary cyclones in all of our VSS units are located in the dilute phase and sealed with a flapper valve.
ASDOURIAN (Sunoco Inc.)
We recently installed a couple of two-stage riser termination devices at one of our locations. This device has significantly reduced the dry gas yield, with respect to the previous technology, and it has enabled us to operate higher cracking severity without the associated dry gas penalty. Oddly, we have observed that the dry gas may increase when the cyclone diplegs are sealed. Therefore, it is operated with the diplegs unsealed. The drawbacks to this, of course, are reducing the stripper residence time and the available ΔP across the spent catch live valve.
THOMPSON (Chevron)
We have seven units that operate with a variety of close cyclone riser termination devices, as shown up on the screen. Some operate sealed; some operate unsealed. In addition, we have two units with UOP VSS riser termination devices.
The choice between sealed and unsealed operations is often dictated by the hardware design, since some units can only operate in one mode or the other. For those that can operate either way, the choice is usually dictated by either dry gas make or catalyst losses. We have one unit that starts up unsealed and then switches to the sealed mode when the operation stabilizes.
WARDINSKY (ConocoPhillips)
ConocoPhillips operates several units with close-coupled reactor cyclones of various license or technologies. One of these units routinely operates without the riser or primary cyclone diplegs being submerged or sealed in the reactor stripper bed. Analysis of unit performance does not suggest any degradation in yields, such as an increase in dry gas, by operating with the diplegs unsealed.
DALIP SONI (ABB Lummus Global)
I think whether to seal or unseal the dipleg depends on whether to seal or unseal the primary separator. I think it also depends on the relationship of pressure in the primary separator and the reactor vessel. If the pressure in the primary separator is higher than the rector vessel, it must be sealed to reduce the blowdown. But if the pressure in the primary separator is lower than the rector vessel or the vessel it is containing, then most of the gas will flow up and get recovered. Very little will flow down. In the Lummus Direct Coupled Cyclone System, that is the case. The pressure in the primary separator is lower than the rector vessel so there is no need to submerge the dipleg.
As just an additional suggestion to the industry, I would also like to term this RTD a “reaction termination device” and not “riser termination device” because that is the purpose of this device at the end of the riser.
REZA SADEGHBEIGI (RMS Engineering)
Operators know that when they are sealing the dipleg, they have to use a density tap. They call it an upper density tap. They use this number to find out what its actual catalyst bed level is. Unfortunately, a typical density in that area should be around 35 ppcf to 40 ppcf.
I did a performance audit of a unit a couple of weeks ago. It had just come out of a turnaround where they had put a close-couple cyclone. They found out that the density reading was only 22 ppcf. So if they use that number and they think they are sealed, they will be wrong. One other thing you want to make sure is that you have, indeed, sealed the dipleg, and that the sealing is about three feet above the bottom of the trickle valve or splash plate, depending on which you have. Usually, if you unseal the dipleg, the catalyst separation efficiency improves so you will see a slight drop in ash content versus the seal. The other thing is that you can tell whether it is doing well or not by watching the dilute phase reactor temperature. If that temperature goes up, that means you are dragging hydrocarbon down. Otherwise if it cools off and there is not enough vapor in that area, then you are doing a good job. A properly designed rough-cut cyclone, or primary cyclone, should not let more than 5% vapor go down there. If it does, then obviously there is a fault in the design of that rough-cut cyclone. Either the outlet velocities are too high or the mass flux is too high and is dragging that hydrocarbon down. My recommendation is to please pay attention to that so-called density tap to make sure your actual level is what it out there.
WALKER (UOP)
As far as monitoring the level in the vicinity of the ceiling where that would occur: We install a local level indicator, a very narrow-range level indicator, right in that vicinity so you have high resolution and high accuracy.
WARREN LETZSCH (Shaw Stone & Webster)
I have two comments. One is that you have to understand whether you have either got a positive or a negative pressure cyclone system. Positive pressure cyclone systems require a larger seal than a negative pressure cyclone system. Many people who are running positive pressure cyclones do not have enough of a seal to really get the job done. It usually requires at least three feet of catalyst to be able to do that. If you seal them, theoretically, at the same flux rate going down the dipleg, the amount of catalyst you entrain down the dipleg should be the same, which brings me to the second comment about the flux in the dipleg. As Reza’s mentioned, if the flux is typically high, what they design for, the catalyst is moving down about 3 fps in the dense bed, and that is going to suck gas down with it. If you make the flux of the dipleg much smaller, the catalyst moves at a much smaller velocity. And in fact, the hydrocarbons can turn around and go out the top of the cyclone. So, the design of the cyclone is awfully important, as well as how you operate it.
Question 13: With the move toward greater utilization of “opportunity crudes” such as Canadian synthetic crudes, what shifts do you expect in FCC product yield and quality, and how will this impact the operation of the FCC unit?
HOWELL (Holly Refining)
Holly’s choice for opportunity crudes are somewhat limited by our position as an inland refiner and being located far away from many of the crude pipelines. We are making changes in both the way we operate our units, as well as our capital investment, so that we can maintain our current slate with crudes of varying quality. With the opportunity crudes that we do run, we have already experienced increased levels of traditional FCC catalyst poison. Our response to that has been increased catalyst makeup, evaluation of additives, and consideration of custom catalyst blends. We are adding mild hydrocrackers at both refineries and we expect to see a large change in our heat balance. If our crude sources change to include previously upgraded stock or crude blends, then we would expect to see our coke yield and heat balance put back in the direction of where we are today.
As in the rest of the industry, our ultimate goal is to maintain quality products and maximize yields from feedstock survey that will come with discounted and benchmarked crudes. We will continue down this path of making capital investments, catalyst changes, and additive use to try to do that. The bottom line is that we have not yet experienced anything other than that buildup of what we consider to be traditional FCC catalyst poisons. So, expect to see some changes in the very near future.
HEATER (BASF Catalysts)
All syncrudes will be processed by cokers and hydrotreaters ahead of the FCC so there is no single, generic answer. The key will be to crack the fully- and partially-saturated ring structures. With syncrudes, FCC feeds will tend to be less paraffinic and more aromatic with resulting lower conversion. Depending on the degree of hydrotreating, lower gasoline yields will be seen but will have higher octane and benzene content. You will see a higher LCO yield with the lower cetane. You will tend to see higher decant yield with lower API gravity so there is a potential for some fouling issues. BASF is developing catalysts in this area and we will be coming out with something in the very near future. In the Answer Book, I have put a response by our friends in Canada—Incut. There is a lot of detail about different types of syncrudes and the product properties therein.
WARDINSKY (ConocoPhillips)
ConocoPhillips is in the process of reconfiguring a couple of our refineries to run large quantities of Canadian tar sand derived feedstocks. This table shows a comparison of feed properties from what the units are currently running and comparing them to some premises that we have for some tar sand derived materials. As you can see, the tar sand derived feedstock is heavier. It contains higher levels of sulfur and nitrogen. It is more aromatic but does not contain as much carbon residue as the conventional crude. The more aromatic nature of the tar sand feedstock is indicated by the comparison of the UOP K factors. The tar sand material does have a higher nitrogen content as well, and the combination with the higher aromaticity should result in a decrease in conversion across the FCC with increased yields of LCO and decant relative to the yields obtained from the conventional feedstock.
KEVIN PROOPS (Solomon Associates)
I believe that this question asks about opportunity crudes. That means people want to make money on this kind of feedstock. I would like to point out that recently, one of the real opportunities is this kind of natural gas. What we saw with our 2006 field study results was that while some of these refiners were experiencing crude advantages versus the Gulf Coast, perhaps, of a few dollars per barrel, natural gas in 2006 was two-thirds the cost of West Texas Intermediate crude on an FLE basis whereas from 1998 to 2004, it averaged about 94% of WTI price. So the money that could be made in 2006 with opportunity high carbon crudes was as much as pumping in hydrogen that came from natural gas as it was in buying those crudes in the first place. I am going to suggest that even though I do not have a crystal ball and I cannot tell you that the natural gas price will remain this time, those refiners that recently could put the hydrogen back into the gas oil probably made the money running these crudes. The FCC obviously is a carbon-hydrogen balance unit. You can reject some carbon with coke; but if you put a hydrogen-deficient feedstock in, you are going to get hydrogen-deficient products back out again. That is hard to get around by most people. I am advocating that if you are going to hydrotreat anyway, when you go to these kinds of feedstocks, the value is probably to get more hydrogen into the gas oil.
RON BUTTERFIELD (Intercat)
We have a northeast refiner who runs predominantly Canadian syncrude and they have been using bottoms cracking additives since mid-2001. It helps to control their bottoms yield. Also, they found that bottoms cracking additive helps to precrack the heavy components at a lower coke yield so they can control a lower temperature in the regenerator.