AFPM Q&A-3 Refiners discuss FCC reliability issues, catalyst selection

Indian Oil Corp. Ltd. (IOCL) started the 4.27-million tonne/year (tpy) INDMAX fluid catalytic cracking (FCC) unit to produce a high-yield of light olefins and high-octane gasoline from an array of petroleum fractions at its recently commissioned 15-million tpy, full-conversion refinery at Paradip in India's state of Odisha, on the country's northeastern coast (OGJ Online, Apr. 22, 2016). Photo from IOCL.

Reliability

The industry continues to experience process safety incidents associated with FCC electrostatic precipitators. What are you doing to prevent these incidents?

Reynolds: Phillips 66 has six electrostatic precipitators (ESPs). We have not been immune to serious incidents on our ESPs. In 1994 we had an ESP explode, which actually led to a fatality. In order to minimize the likelihood of these kinds of incidents happening again, the company has a standard that outlines features of an FCC emergency shutdown system all refineries must follow. It lays out how the safety system is supposed to be configured and which features it is supposed to have. Adherence to the standard by each refinery is tracked at the corporate level, and refineries that do not meet the standard must have plans to close the gaps. We actually have one wet ESP at the Billings refinery that is downstream of the scrubber, and it must meet the compliance requirements just like regular ESPs.

One of the standard's requirements is that the ESP shall shut down if the main FCC safety system engages or trips, regardless of the cause. There are several other features as well. If the inlet carbon monoxide (CO) level exceeds the standard's prescribed limit for CO of no greater than 5,000 ppm, the safety system engages. Also, if the air preheater has a safety system on it which then trips, the ESP is required to trip along with it.

The ESP must have its own separate shutdown button. The CO is used basically as a surrogate for other combustible material. CO is combustible itself, but if you are having poor combustion in your regenerator, you are likely to be generating CO as well. One of the more important features is that the ESP cannot have the ability to reenergize itself after it trips.

So the highest potential for operating on ESP and explosive composition in your flue gases during startups comes from the use of torch oil along with air preheaters, which can lead to poor combustion. Our recommended practice is to keep the ESP down during startup until the unit is stable. Stability is defined as feed in the unit, stable pressure balance, CO within limit, and nothing bypassed in the safety system. For certain locations, you may not be able to have the luxury of starting up without ESPs, in which case the standard recommends that you have an air-preheater safety system as well.

The standard also includes some recommendations: for instance, minimizing the personnel around the ESP during startup, shutdown, or if an upset occurs. It also recommends using the methane analyzer in conjunction with the CO analyzer. For the sites that do start up with an ESP online, having a methane analyzer-in addition to a CO analyzer-is strongly recommended.

The standard additionally includes some scenarios you must consider whenever you do a process hazard analysis (PHA), such as the loss of combustion air, any kind of upset in the regenerator, upset in the stripper, low-riser outlet temperature, and pressure reversals. A lot of this information also can be found in a presentation Phillips 66's own Mike Wardinsky gave at the 2009 AFPM Q&A Principles & Practices session.

Larsen: Within Marathon, we have two units with ESPs on them. Our setup is very similar to what Mark described with Phillips. Any activation of the normal FCC safety instrumented system (SIS) will deenergize the ESP. Our trip point for CO is 1,500 ppm, which is a little more conservative. Also, we will trip the ESP if excess oxygen is less than 0.1%. Either of those inputs will act to deenergize the ESP. For safety purposes, we only run our ESPs energized during stable, normal operations, not during the times of hot standby or startup, etc.

Proops: Mark and Nik, thank you for your comments. I had the misfortune of visiting the unit Mark mentioned about a week after that catastrophe happened. I want to add a couple of comments to what you described during the startup, when that explosion occurred. Natural gas backed in from the fractionator, through the reactor, and got all the way to the regenerator. I believe that there would not have been any significant CO at that time. Oxygen was high.

So panel members and the audience, if you are worried about ESPs on startup, recognize that they can be very abnormal to what you are used to seeing. I believe the incident investigation also found that the ESP had been in a deenergized state, but it still exploded. So you have to watch out for potentially explosive mixtures of oxygen and methane at higher temperatures.

Lanouette: I am curious about the shutdown system. Our analyzer people are telling us that there is interference with CO and methane in doing the analysis, as well as calibration difficulties. Is there a specific analyzer that you have come across that is better for this kind of service? The second part of this question is: Is this a safety integrated level (SIL)-rated shutdown system?

Larsen: I know a lot of folks are turning to the tunable diode laser (TDL) technology. I can meet with you after the session to go over the specific analyzer we use with good success.

Fry: Does anyone have any experience or insight as to whether or not this would be important to have in a partial-burn unit with a CO boiler on the backend? Is that at any greater or lesser risk than a full-burn unit?

Wilson: Just to add another question about it, is there greater risk with an ESP and CO boiler, or is the risk the same? I think it is at least the same, and I certainly think the standards will be the same on our units. I imagine other people who have standards will probably apply the same standards.

Miller: I will address two issues. One is the analyzer. As Nik said, the Phillips 66's standard also calls for TDL analyzers because they are very fast-responding and very accurate and sensitive for CO. You can also get a TDL for methane. Some of our units have that as well.

As Kevin pointed out, the incident that Mark mentioned would not have been stopped by one of these analyzers. The explosive mixture was fuel gas, and the ESP was not energized at the time. What that site and about half of our other FCCs have done since then is install these overhead blinding devices between the reactor overhead and the main fractionator. Those are reusable devices that can seal off the reactor from the main fractionator so you avoid getting migration of fuel gas or other hydrocarbons during periods when you are down or starting up. Those are very effective, and we recommend them strongly in our system.

Ludolph: I would like to open up the ESP safety question to include any ESP manufacturer respresentatives who may be in the audience. What are the ESP manufacturers doing to help improve the safety and operation of their equipment, and, in turn, the overall safety of the refineries?

Dahlberg: Hamon Research Cottrell has supplied a large number of precipitators to US refineries during the last 15 years. Many of these suggestions are implemented in our design, and we participate in a hazard and operability (HAZOP) study at the beginning of each design process. An additional level of protection would be to limit the power to the operating transformer and rectifiers at startup to stay below the threshold of sparking, which will eliminate a source of sparking in the precipitator and a potential source of ignition of combustible gases.

Catalysts

Under what conditions do gasoline-sulfur reduction additives and catalysts reduce sulfur in gasoline, and by how much? What is the lowest gasoline-sulfur level for which the gasoline-sulfur reduction products are effective? At this gasoline-sulfur level, please quantify the gasoline-sulfur reduction and the amount of additive-catalyst required.

Larsen: That is a very long breath of a question. I will summarize some of Marathon's findings on gasoline-sulfur reduction additives. We have done a lot of testing in our pilot plant in the past. Some of that has already been presented. You can reference Jeff Sexton's response to Question 46 of the 2009 AFPM Q&A FCC session if you want to see a little more data.

In general, we already mentioned our pre and post-treat scenarios and went over how gasoline-sulfur reduction additives work. I will hit on the mechanism of how we believe they work, some of the variables that would impact their performance, and then some of our more recent testing and applicability at already low gasoline-sulfur levels.

In terms of the mechanism, in our pilot-plant testing, we have seen that recombinant reactions play a large role. So no matter what feed-sulfur species end up entering the pilot plant, we get the same gasoline-sulfur species coming out the backend, thereby emphasizing that recombinant reactions in the riser play a large, dominating role in generating gasoline-sulfur species. The additives we tested, for the most part, will crack the gasoline-sulfur species into H2S. I believe there is other technology that will move the sulfur down into coke.

Several variables can cause an effect. Bart already identified vanadium as one of them. Vanadium's impact on the gasoline sulfur-to-feed sulfur ratio in one of our units with operation at low and high-vanadium levels is very significant.

We also have done testing with nitrogen and noticed big effects in the gasoline sulfur. In general, we have tried many types of gasoline-sulfur reduction catalysts and found two that worked well for us. It is important to recognize the importance of balancing the ability of the gasoline-sulfur reduction catalyst to reduce sulfur without having any adverse yield impacts.

We have done economic modeling and confirmed the pilot-plant testing with actual unit post-audits to find additives that work best for us, and we have then gone on to do some of our testing recently at already low gasoline-sulfur levels.

The gasoline sulfur we are starting at is 20 ppm. This is full-range gasoline-sulfur concentration. We have experienced about the same reduction in gasoline sulfur that previously occurred when starting with higher levels of gasoline sulfur. It appears, then, that the additives we have tested worked in about the same range, even when starting with lower gasoline-sulfur levels or reloads.

De Graaf: Additives can help to reduce gasoline sulfur 20-35%, but they cannot perform miracles. Their performance depends on how much hydrogen transfer is already present in the system. There are various contributing factors to the success of this reduction.

I visited a refinery in China that had two different FCC units. They processed the same feed and used the same base catalyst. One FCC, however, had a sort of fluid bed in the unit, while the other was more of a typical side-by-side FCC unit. At similar conversion level, the unit with the sort of fluid bed in the riser had 35% less sulfur in gasoline due to the huge spent-catalyst recycle caused by the fluid bed.

The base catalyst contributes to hydrogen transfer as well. You can optimize the amount of rare earth. The more rare earth you put in the catalyst, the higher the acid-site density in the zeolite, which will result in more hydrogen transfer. A high-alumina catalyst helps reduce sulfur; and as I mentioned before, high vanadium levels also help to reduce gasoline sulfur.

Another factor is how much hydrogen the feed brings in itself. If there is a lot of hydrogen transfer from the feed, the performance of the gasoline-sulfur additive will be affected. It will be more of an uphill battle vs. feed that presents a low amount of hydrogen transfer.

Mercaptans, thiophenes, or hydrothiophenes are easier to remove than benzothiophenes. Typically, you would use about 10- 20% of gasoline-sulfur additive in one inventory, but we have seen that gasoline-sulfur additives are effective over a very wide range of applications.

Clough: I will just add a couple of comments. Both Nik and Bart did a good job talking about a number of key aspects, including speciation. It is important to understand how or what kind of game plan you need in terms of gasoline-sulfur reduction additives. Use of the additive, like Bart said, is about 10-20%. Another point to consider is preblending in order to avoid diluting the base catalyst.

Regarding the use and effectiveness of gasoline-sulfur additives in an instance where you already have low sulfur in the gasoline, I want to share another story from the refinery experience side. Some of our customers in Japan running very low-sulfur feeds are using gasoline-sulfur reduction additives and are still seeing around 20% reduction. So even at already low gasoline-sulfur levels, further reductions are possible.

Reliability

What operating practices or technology upgrades are you using to manage coking in the reactor overhead line at the main fractionator inlet?

Singh: Feedstock, catalyst, and reactor hardware all play a very major role in vapor-line coking. Coking of the reactor overhead line is a major concern, particularly when we are processing resids. Catalyst formulations designed for higher hydrogen-transfer reactions, coupled with high-aromatic feed, tend to produce higher-boiling point polynuclear aromatics (PNAs), which have a tendency to condense and form coke in the vapor line. Design and configuration of the vapor line is also a very important factor.

There are different reasons that are all extremely unit-specific for vapor-line coking, and they can predominantly be classified into two categories. The first includes factors leading to the presence of components that tend to produce coke at the reactor outlet. These factors include heavier feeds, aromatic feeds, improper atomization, post-riser cracking, high residence time in the reactor, low activity of the catalyst, comparatively more thermal cracking, etc. The second involves factors related to the configuration and design of the reactor vapor line, which influences condensation and coking. The phenomena of vapor-line coking gets aggravated by cold spots in the reactor vapor line, improper insulation, damaged insulation, low velocities, improper slope, cool patches in the vapor line, etc.

We have experience operating both hot and cold-walled vapor lines, as well as a variety of feed injectors, including old-designed shower heads used for vacuum gas oil (VGO), and modern injectors with resid feed. Our experience has been that, even with the old design of feed injectors, the extent of vapor-line coking was much less while processing VGO vs. processing resid feed with modern atomizers, indicating the significance of feed type on vapor-line coking.

In one of the units, configuration of the vapor line was such that it had too many cold spots. It had the worst slope, and while the unit did have a modern feed-injection system, we had the tremendous problem of vapor-line coking. After correcting the problems related to the vapor line's configuration, to a very large extent, the problem was eliminated. The type of feed you're using and the configuration of your vapor line, then, are very important factors to consider when encountering vapor-line coking.

Here are some suggestions to avoid coking of the vapor line:

• Start with the best feed vaporization. Avoid mixing slurry with feed. While using slurry filters, we find it better to use feed as the backwash medium in lieu of heavy cycle oil (HCO) to avoid having the once-cracked material going back to the riser.

• Avoid cold spots in the vapor line and, based on the design, insulate the vapor line well. During insulation, special attention should be paid to supports, manways, fittings, and flanges.

• Avoid cooling the vapor line with cool-purge streams. In one of our units, we had to provide some steam purges in the vapor line that significantly enhanced coking within the line. Some old designs might be having some purges or bypasses going in the vapor line which, again, should be avoided.

Reynolds:I will just reemphasize one point. Yes, you want to make sure you minimize all of the heat sinks on the overhead line. I recommend you do regular infrared scans or thermography and look for hotspots. Do that annually, quarterly, or some other frequency, which is especially important after a turnaround. Make sure you get a high-quality baseline infrared scan so you have a baseline of where you started. I think the dew point in the overhead vapor lines is also 600-700° F., or so. You want to make sure you stay well above that temperature.

Jawad: There are a lot of technology options available to help you minimize coking. It is really difficult to measure pressure drop across the vapor line. Typically, you are limited to instrumentation measuring single pressures, and you then have to subtract those pressure measurements. Obviously, you can take pressure at the top of the plenum, but on the main fractionator, you may not have a spot. So you might want to think about having some dedicated tubing, if it is not short, to have an actual differential pressure (DP) at the top of the level bridle to get a downstream pressure.

Wells: The actual question stated that the main fractionator inlet was the concern. I did not write the question, but we have a similar concern. It is not on the line itself; it is only right where it goes into the fractionator, in the dead spot. The line comes in from the side and elbows into the main fractionator. On the inside of that sweep, there is a dead spot that tends to build up coke, which breaks off and fills up the bottom of the main fractionator.

Does anyone have an answer as to why that occurs? Also, has anyone else seen coke buildup in the same location? Obviously, someone else submitted this question.

Letzsch: It is not uncommon to actually get a donut around the inlet to your main fractionator. In our old units I have seen areas where we have built up a 5-lb pressure drop across the donut. I think it has a lot to do with the velocity going into the main fractionator-whether it is too low or too high, or if it is sloped properly-and the insulation around it. Frankly, that has been addressed in old AFPM (formerly National Petrochemical and Refiners Association) transcripts.

I will just tell you about one even more interesting situation. You know, when you guys get your FCC units, you go to the licensor. He gives you a process design package, and then you go to the detailed-engineering company. You think the detailed-engineering company personnel are experienced and know what they are doing. Here is your reactor coming out with the main overhead vapor line, and you thought it would go into the main fractionator. But, oh, no! This guy from the detailed-engineering company was really clever. He brings the vapor line out, down, and around to the pipe rack. It went around and then came all the way back around to the back of the fractionator, and you ended up with about a 300-ft vapor line. And the guy was complaining about finding coke in it! These situations really do happen.

Russeff: I have seen a similar phenomenon right at the blind flange location on the tower where the coke tends to build up and then streak into the tower building, creating a good pressure drop. We had that same issue, which we ended up solving with a combination of steam rings and insulation to try and eliminate that particular spot during normal operations. It was quite a bit to chisel out, however. It was very oddly shaped because it had started at the flange and then worked its way into the tower, making horizontal stalactites on its way into the tower. Is that the same situation you saw?

Wells: We do not have a flange in that location, and we do not see stalactites.

Ludolph: We have seen a variety of coke formations pinching the main fractionator inlet, creating pressure drop between the top of the reactor and the top of the main fractionator. Shell did a review of what might have been contributing to the coke growth and concluded that velocity was a player. The ranking of the process parameters suspected as coke growth contributors, however, is quite site-specific. We have conducted computational fluid dynamics (CFD) analysis to better understand what might be occurring, but we are not satisfied with the results. Suspected locations and causes of pressure-drop increases are, many times, unconfirmed when entering the equipment during turnaround. Remediation and prevention of main fractionator-inlet coking remains a big area of learning for us.

Marri: The question also asks about some technology practices, as Warren and Sanjiv already discussed. I want to add a couple of thoughts. We recommend that the velocity be somewhere about 120-150 fps toward the coking in the reactor because that also relates to residence time. Secondly, many of these units do not normally have the capability to measure the change in DP (ΔP), as was already mentioned.

So you could look at this as a prevention measure. When you clean the unit and power it up, it would be better to take a single-gauge pressure survey and monitor the present profile across the whole reactor and up to the fractionator, or over to the wall. That helps us keep track of the ΔP across the column and across the vapor line. So typically, there is 1-2.5 psi ΔP across the reactor vapor line, which establishes a guideline. If something in the process changes, such as the hydraulics of the main fractionator, you could monitor and prevent the coking tendencies.

Unit slowdowns

What are your top three causes of unit slowdowns, and what is the loss in on-stream factor for each? Please provide the same information for your top three causes of unit shutdowns.

Russeff: I get the fun one! For us, it has been the main-column bottoms exchanger cleaning. We've been achieving some new recoveries at a residual oil supercritical extraction (ROSE) unit located upstream of the FCC that have resulted in high asphaltenes in our feed and slurry. Slowdowns are the result of the combination of that and PNA formation. Some people get excited over 15% asphaltenes in their slurry. When the ROSE unit is not online, we go from about 3% up to as high as 40%, which is very discouraging. A typical turndown for replacing a bundle in that service is about 75% max capacity. We have a spare steam generator online, so we could switch back and forth between the two units.

Another contributor to unit slowdowns is feed availability. The FCC at our Wynnewood refinery does have to compete with other units for feed, depending upon market conditions, whereas the FCC at our Coffeyville doesn't necessarily have a competitor for feed within the refinery itself. We have changed some operations, however, as a result of positioning and some of the prices we have seen in terms of premium gasoline and diesel. We try to make up for that price fluctuation in other areas of the gasoline crack. We have also been able to locate opportunity feed from some external sources. We have good synergy between the two refineries, and since they're relatively close to one another, when Coffeyville was going into turnaround this year, we managed to turn through a lot of its gas and oil at Wynnewood. So the answer on feed availability during turnaround is: It varies, depending upon the market.

Limitations on our wet-gas machine also can contribute to slowdowns. We have a dry-screw machine in wet-gas service. This is a first for me and has been a painful process. We've had a couple of outages as a result of problems with the dry-screw machine in wet-gas service, and we also have a current rebuilding going on that has led to some efficiency losses. We do have a reciprocating compressor as a backup machine, but we have a considerable turndown, basically down to 50%. As for upstream-unit recoveries such as the ROSE I mentioned earlier, we are turning up the knob on recoveries and the asphaltenes. Conradson carbon residue (CCR) leads to metals taking up capacity in the wet-gas machine with a higher hydrogen-to-methane ratio, which we've been addressing by aggressively flushing the additional metals in the catalyst. I've also switched over to a nickel trap catalyst, which is working well.

Given the lack of condensing and cooling capacities our Oklahoma and Kansas refineries have during the summertime, the loss in capacity is really directly dependent on ambient conditions. So that turndown I mentioned earlier also depends on how hot it is outside at each moment.

As far as causes for our top three shutdowns, we don't typically have full shutdowns of the units. But I have to say that rotating-equipment reliability, especially with the dry-screw machine, has been challenging. We have a reciprocating wet-gas machine as a spare machine, but it just doesn't have the capacity. You would think that some of the parts on that dry-screw machine were made of fresh panda blood because it is very difficult to get parts for it.

We've also had some other problems during a rigorous pump-rebuild program that's under way as part of our goal to start a new benchmark in terms of reliability. We've had to send pumps out for complete rebuilds, which does take more time. Pump availability for the spares has not been there during this revamp of our reliability program, so we have had some issues there.

Finally, the other main contributor to slowdowns or shutdowns is probably the catalyst. This is a very sensitive subject, but it is a catalyst issue. We had an opportunity to run what I'll call opportunity equilibrium catalyst (e-cat). Right now, I want to say that we are really happy with our long-time catalyst vendor, and running that opportunity e-cat from another vendor didn't turn out to be such a good opportunity after all, as it resulted in a unit shutdown. Alongside proving to us that our long-time catalyst vendors really are probably the best out there, that shutdown gave us a chance to truly understand the critical importance of paying attention to your e-cat, no matter from whom you get it. You have to pay attention to your e-cat's additives, activity, metals, particulate size, yield projections, and required addition rates.

Singh: Cat crackers are one of the major secondary units for all of our refineries. Irrespective of demand and market condition, our units are always required to operate at high capacities. All of our refineries have been participating in Solomon Associates Inc.'s Comparative Performance Analysis benchmarking studies, which show clients where their operations stand vs. their competition. Results of these studies in 2014, which are based on more than 300 cat crackers worldwide, show the percentage of slowdowns for Indian Oil's (IOCL) eight cat crackers is much lower compared with their global competition, consistent with our refineries' focus on consistently high-capacity performance of FCC units.

There is no single reason for unplanned outages of FCC units at IOCL's refineries. Our youngest unit is 13 years old, with most of the units between 17-32 years old. All eight units have been revamped to operate at rates more than 25% to as much as 50% higher than their original design capacities.

During the past 5 years, IOCL's FCC units collectively have experienced 41 interruptions. Out of these 41 incidents, however, not a single cause has been predominant. About 15% resulted from power and utilities interruptions at our captive power plants, while 19% were caused by catalyst-loss issues attributable to aging reactor-regenerator internals. About 24% were a result of rotary equipment issues stemming from wet-gas compressor (WGC) failures, as none of our refineries are equipped with a spare WGC. Static and instrumentation issues, respectively, have resulted in 27% and 15% of our total FCC outages during the 5-year period.

Note that these statistics include all interruptions, irrespective of the duration. Any incident that led to a feed outage also has been accounted for in the evaluation.

Larsen: I tracked internal problems associated with our FCCs and the reliability impact of these for all of our Marathon FCCs. I'll highlight two incidents that occurred in 2014 and one that took place in 2015.

In 2014, a flue-gas steam generator leak led to a slowdown that resulted in a 0.7% loss in our overall FCC mechanical reliability. The incident basically stemmed from the presence of older cyclones at this particular site. We chose to operate the unit at higher velocities than our normal operating guidelines, which caused higher catalyst losses and impacted the flue-gas steam generator.

The second slowdown, also in 2014, involved the waste-heat boiler situation I previously mentioned, where older CO boilers were converted to just normal waste heat boilers. An improper quench design where the boiler-feed water was injected too close to a geometry change in the flue-gas line resulted in significant erosion and corrosion problems. This slowdown resulted in a 3% loss in our total FCC mechanical liability for that year. To correct this, we'll be installing new waste-heat boilers on this unit in the future.

The last slowdown occurred in 2015 and was an unforced error that resulted from a blast steam that was left open on the guides of the spent slide valves, which caused a loss of control on the reactor level. This slowdown led to a 1.3% loss in our overall FCC mechanical reliability.

In terms of slowdowns, I just want to add one interesting example. We have one unit that experiences main-column coking as a result of high vapor velocity and slurry entrainment. It requires us to reduce throughput to manage the coking until getting to the next turnaround where we can properly swap some of the fractionation beds. This unit has high inlet velocities to the fractionator, high slurry entrainment, and a fractionation section located right above the slurry section, which combined, leads to low-liquid rates contributing to the coking problem. To eliminate that concern, we'll ultimately swap the beds around in the fractionator.

Prorok: You again mention waste-heat boilers as a factor that sometimes contributes to reduced reliability. On our unit, the mud drum hangs on the bottom of the tubes inside the flue-gas duct, so you cannot get to it very easily. We had manway gaskets on the mud drum. You could tell it was leaking by the water balance on the boiler. So yes, when you do maintenance of your unit and have startup and shutdown, the thermal cycling of the system may cause the gaskets to leak. It may have stretched bolts and leaked where the gaskets were crushed and then cooled, ending in failure.

The panel

Bart De Graaf, head of FCC research and development,

Johnson Matthey Process Technologies

Todd Foshee, FCC licensing and design,

Shell Global Solutions US

Nik Larsen, cat cracker technologist,

Marathon Petroleum Corp.

Mark Reynolds, FCC process engineer-

Billings, Wash., refinery, Phillips 66

Rich Russeff, operations superintendent-

Wynnewood, Okla., CVR Refining LP

Sanjiv Singh, director of refineries, Indian Oil Corp. Ltd.

The respondents

Melissa Clough, BASF Corp.

Neil Dahlberg, Hamon Research-Cottrell Inc.

Emerson Fry, Delek Refining Ltd.

Ziad Jawad, Technip Stone & Webster, Process Technology

Roger Lanouette, Monroe Energy LLC

Warren Letzsch, Technip USA

Robert Ludolph, Shell Global Solutions (US) Inc.

Rik Miller, Phillips 66

Rama Rao Marri, CB&I Lummus Technology

Kevin Proops, Koch Industries Inc.

James Prorok, Husky Energy Inc.

W. Lee Wells, LyondellBasell Industries NV

J.W. Wilson, BP Products North America Inc.