Question 13: Severe fouling of diesel and gas oil hydrotreating preheat exchangers has been a growing problem. In your experience, what are the causes and how can these be prevented? Have you tried antifoulant injection in this service?
Dan Webb (Western Refining)
Fouling of the heat exchanger train is sometimes a problem particularly when processing cracked feed stocks. The fouling is often caused by polymer like compounds (gums) that form when petroleum distillates come in contact with air. When heated olefinic compounds react with absorbed oxygen to form gums that deposit in the preheat train.Iron scale and other particulates in the feed often adhere to these gums to produce severe fouling that restricts unit capacity and accelerates heat exchanger corrosion rates. Typically, every effort is made to avoid air ingress into any of the unit feed stocks. Fouling precursors may also be present in straight run feed stocks in the form of certain chemical contaminants that may be present in the crude or inadvertently introduced in an upstream process unit. Some precursors such as amines, carboxylic acids, and carbonyls form gums without air ingress into the feed. Antifoulants have been used successfully to mitigate fouling caused by these compounds in addition to mitigated fouling caused by oxygen contaminate cracked feed stocks.
Michael Chuba (Sunoco)
Typically distillate hydrotreaters exchanger fouling has been associated with cracked stocks that contain olefinic material and trace amounts of O2 coming in with the feed from tankage. In addition to oxygen-initiated polymerization, other impurities can lead to free radical formations that can promote polymerization reactions. These impurities include certain nitrogen and sulfur compounds well as some metal ions including iron, calcium, and magnesium.
In addition to free radial polymerization, condensation polymerization reactions can also result in fouling. In this route, two radicals can react to form a larger molecule. The new compound can continue to react and grow until it precipitates out of solution forming deposits.
What I would like to present here is an example of fouling we had on one of our units and how we have significantly reduce fouling via a simple jump over line.
Prior to conversion of this unit to ULSD the unit processed a mix of virgin and cracked distillate stocks. Historically this unit had exchanger fouling that was attributed to the presence of the cracked stocks. When the unit was converted to ULSD the cracked stocks were removed. The resulting feed was a 50:50 mix of direct rundown material from the crude unit and tankage. As a result of this change in operation it was anticipated that the fouling rate would decrease, however, during actual operation the fouling rate actually increased.
An initial program to address the problem included detailed analysis of the various feed stream followed by a targeted antifoulant chemical injection program. Results were somewhat effective but still left significant room for improvement. Continued investigation into the problem targeted O2 contamination coming from the material coming from tankage. The intermediate distillate tanks are cone roof design which would be relatively costly to convert to blanketed tanks. As a first step it was decided to install a jump over from the tank inlet line directly to the suction of the tanks’ transfer pumps. With this simple connection the average volume of material actually drawn from the tanks dropped dramatically.
This plot shows the impact on the heat transfer coefficient of the feed effluent exchanger as a result of this simple jump-over. The pink plot represents the previous cycle. At about ¼ of the cycle the jumpover line was installed. At this point significant fouling had already occurred. The discontinuity in heat transfer coefficient a week or two later was the result of a power failure. It is suspected that the rapid depressurization dislodges some of the fouling material thereby improving the heat transfer when the unit is re-streamed. This same response has been seen in previous emergency shutdowns. The green plot represents the current cycle which started with a clean set of exchangers and operation of the jumpover in service from day 1 of the cycle. As can be seen this simple jumpover has significantly reduced the rate of fouling compared to previous cycles. Since the only change was the potential ingress of O2 from the tank, this project confirmed the impact O2 had fouling.
Gregg McAteer (Nalco Company)
Fouling can be a serious problem in hydro-desulfurization (HDS) units because of their importance in producing fuels that should meet environmental specifications. Fouling can limit a unit's ability to maintain a specific feed rate or meet an extended turnaround date. It can greatly influence product quality as well as energy consumption, and catalyst or equipment life. Stricter limits on sulfur and aromatic content of finished fuels make fouling control even more important today. To achieve today’s limits of 0.05 wt.% for diesel, refiners must increase severity of refining operations, which often worsen fouling. Fouling ultimately necessitates shutdown and extensive maintenance, a costly process, both in terms of maintenance expenditures and lost production. Causes of fouling in diesel and gas oil hydrotreaters are both organic and inorganic in nature. The organic foulants are primarily gums formed as a result of processing cracked material and accelerated if the material is exposed to oxygen at any time. Antioxidants and/or antipolymerants are used to reduce the formation of gums and dispersants are used to keep any gums already formed from growing in size.
In one case an antifoulant program utilizing both an antioxidant and a dispersant was applied to a gas oil hydrotreater that normally fouled enough to require a shut down after an average of 440 days. The antifoulant program started on a fouled system and showed
a slight recovery of pressure drop. After a shutdown they started again and achieved a 1300 day run (see graphic below).
“Run 1” is shown in red and light blue. The red trend shows the steep increase in pressure drop during normal operation (without antifoulant program). The light blue trend shows the antifoulant program started, saw a small decrease in pressure drop, and then the unit was brought down for a regeneration. “Run 2” is shown as the dark blue trend and shows a lower fouling rate and longer run length with the antifoulant program. Customer estimated the ROI to be between 400-500%.
Phil Thornthwaite (Nalco Company)
Foulants typically found on the feed side of the preheat exchangers include various gums or polymers, iron sulphide and salts.
The organic fouling due to gums & polymers results from the polymerization of unstable species in the unit feed. The problematic species include olefins (generated in cracking processes), organic acids, mercaptans, ketones, aldehydes, phenols, organo-nitrogen and organo-sulphur compounds. Therefore, in order to determine the risk of organic fouling for a particular feed stream, detailed analysis for the problematic species can be useful guide in evaluating fouling propensity and mitigation strategies.
A typical level for concern for each problematic specie is outlined below:
Another key factor to consider is the oxygen content of the feed stream as this can promote the polymerization of various unstable compounds, particularly olefins. Therefore, it is good practice to exclude oxygen from feed storage tanks by ensuring tank seals and vents are in good condition and through the use of a nitrogen blanket. However, this method is ineffective with streams already exposed to oxygen since the nitrogen blanket will have no effect on oxygen reaction products such as aldehydes, peroxides and hydroperoxides.
Inorganic fouling is mainly caused as a result of iron sulphide that can either be carried from upstream units or generated in-situ in the preheat exchanger network. However, the latter is not so common since refiners choose the metallurgy to mitigate against sulphidic corrosion in most cases.
In order to mitigate and control fouling in the preheat train, chemical dispersants and antipolymerants are used. The properly selected dispersant will act upon the organic polymers by keeping them finely dispersed within the feed stream thus minimizing the risk of deposition on the exchanger surfaces. Likewise, dispersants can also prevent deposition of FeS by keeping them dispersed in the feed stream.
Antipolymerants act by disrupting the propagation and chain extending stages of the free radical polymerization reactions and by increasing the rate of termination. This will limit the rate of polymer growth within the preheat system. They will also minimize carbonyl formation which will in turn disrupt condensation polymerization reactions.
The key to monitoring the program effectiveness is through accurate monitoring of the preheat exchanger network. If the fouling results in a limitation of heat transfer efficiency, then a temperature survey of the exchanger network is carried out and this data is entered into a rigorous thermodynamic process model, such as Nalco’s MONITOR® program. This model will then use the plant data to calculate actual and normalized exchanger duties and heat transfer coefficients plus it will calculate the normalized furnace inlet temperature (NFIT). A successful antifoulant program will limit the decay in the NFIT and will generate significant returns for the refiner by improved energy efficiencies and optimized unit operation.
Robert Wade (ART)
We have not had success reducing fouling effects by adding antifoulants. It is our experience that adding antifoulants at best treats the symptom of the problem, and at worst further contributes to localized and downstream fouling. We recommend that the source of the fouling contaminant be identified through analysis and addressed at the source. If this is not possible then we revisit the basic design of the heat exchanger in question and ensure that it is operating in a shear controlled flow regime so that fouling effects are minimized
Question 41: Have the panel members considered 15% ethanol (E15) gasoline blending?
KOONTZ (HollyFrontier)
My first slide shows a little background. The EPA administers the Renewable Fuel Standard program that has volume requirements for renewable fuels. They established these volume requirements under the Energy Independence and Security Act of 2007. The EPA tracks compliance with the Renewable Identification Number (RIN) system, and they assigned a RIN to each gallon of renewable fuel.
HollyFrontier satisfies much of its requirement for conventional biofuel, which is essentially corn ethanol, by blending E10 gasoline at many of its terminals. Most of HollyFrontier’s gasoline is sold via pipeline to terminals owned by others; therefore, we are not able to supply our full mandated volume. HollyFrontier does purchase RINs from others. The decision to purchase ethanol to blend or the RINs is based on the economics of the cost of the RINs.
Ethanol blending for the refiner does have a significant impact on two critical gasoline properties: namely, octane and RVP. The hydrocarbon blend stock used for 90% of the E10product, which HollyFrontier calls sub-grade, has an octane rating of about 84. After blending with the 10% ethanol, the resulting octane is the regular 87. So being a refinery that adjusts total octane with its reformer severity, this allows us to run a lower severity, which is especially beneficial to those refineries with semi-regen reformers that operate at relatively high pressures and relatively low liquid volume product yield.
RVP is the other critical property affected by blending. When ethanol is blended with naphtha at a low concentration, the RVP of the gasoline is increased. Pure ethanol does have a low RVP; but when it is blended with hydrocarbon, it behaves more like a light hydrocarbon and actually raises the RVP. For example, with E10 for naphtha having an RVP of 9, the resultantE10 product has an RVP of about 10. So, to encourage ethanol blending, in 1990, the U.S. Congress passed a waiver known as the “One-Pound Waiver” which allows E10 gasoline to be sold at one psi (pound per square inch) higher than that normally required.
For the refinery, E15 would allow lower octane severity reformer operation, which would be beneficial. However, the EPA regulation implementing the “One-Pound Waiver” specifically references gasoline containing between 9% and 10% ethanol. The EPA has refused to extend this One Pounder Waiver to E15. Therefore, marketing E15 requires a sub-grade blendstock that has an RVP approximately 1 psi lower than normal gasoline sub-grade blendstock used for E10.
In addition, since January 2011, E15 has been permitted for use in light-duty motor vehicles manufactured after 2001. It was not approved to be used in small gasoline engines or other vehicles built before that due to concerns of material incompatibilities and corrosion. Furthermore, I have seen several places where current automobile manufacturers will not honor their warranties if the person used E15, even if the vehicle was manufactured after 2001. Also, the EPA requires that in order to sell E15 gasoline, a Misfuelling Mitigation Plan must be in place to prevent consumers from using the product in an unapproved engine. Today, there are very few retailers who have chosen to go through the additional trouble in order to sell the E15.
In conclusion, due to the absence of the “One-Pound Waiver” and the legal risk of corrosion or voiding the warranties of customers’ cars, HollyFrontier has chosen not to produce or blend E15.
SUBHASH SINGHAL (Kuwait National Petroleum Company)
Does the 15% have to do with the oxygen in the ethanol and other oxygenate like MTBE, or it is just because of the RVP limitations and other issues that you explained? From safety point of view, is there oxygen contained in the old oxygenate like ethanol? Is that one of the criteria for limiting the blending from 15% or 10%? Does this have to do with the oxygen
attached even though it is oxygenate?
KOONTZ (HollyFrontier)
My understanding, from reading, is that the E15 decision is not really based on logic. I think it was more of a U.S. Congress action. I do not really understand why they have not extended the “One-Pound Waiver” to E15. I do not think it is based on science.
KOONTZ (HollyFrontier Corporation)
The Environmental Protection Agency (EPA) administers the Renewable Fuel Standard (RFS) program with volume requirements for several categories of renewable fuels. EPA establishes the volume requirements for each category based on EISA (Energy Independence and Security Act of 2007) legislated volumes and fuel availability. EPA tracks compliance through the Renewable Identification Number (RIN) system, which assigns a RIN to each gallon of renewable fuel.
HollyFrontier satisfies much of its requirement for Conventional Biofuel (essentially corn ethanol) usage within RFS by selling E10 (10% ethanol) at many of its terminals. Most of HFs’ gasoline is sold via pipeline to terminals owned by others; therefore, to fully satisfy its mandated volume, HF purchases RINs from others. The decision to purchase ethanol from others and blend to E10 or to purchase RINs from others is based on economics.
Ethanol blending has a significant impact on two critical gasoline properties controlled by the refiner: octane and RVP. The hydrocarbon blendstock used for 90% of the E10 product (termed sub-grade by HF) has an octane rating of ~84. After blending with 10% ethanol (octane ~114) the resultant E10 octane is “regular” 87. For a refinery that normally adjusts reformer severity to satisfy the total gasoline pool octane, producing sub-grade allows for lower reformer severity and higher liquid yield. This improved yield is more pronounced for a semi-regeneration reformer that operates at relatively high pressure.
RVP is the other critical gasoline property affected by ethanol blending. When ethanol is blended with naphtha at low concentration, the RVP of the gasoline is increased. Even though pure ethanol has a low RVP [about 2 psia (pounds per square inch absolute)] due to O-H bonding, it behaves more like a hydrocarbon with a molecular weight of 46 when mixed with naphtha at low concentration. If ethanol is blended to 10% with 84 octane naphtha having an RVP of 9, the resultant E10 gasoline has an RVP of ~10. In order to encourage ethanol blending, the U.S. Congress passed the One-Pound Waiver in 1990 allowing E10 gasoline RVP to be 1 psi higher than that normally required by the EPA (One-Pound Waiver).
E15 would allow a refiner to produce an even lower octane sub-grade to blend with the ethanol and the RVP effect would be similar. However, the EPA regulation implementing the One-Pound Waiver specifically references gasoline containing between 9% and 10% ethanol. The EPA has refused to extend the one-pound waiver to E15. Therefore, to market E15 requires a sub-grade blendstock having an RVP over 1 psi lower than that required for E10.
Since January 2011, E15 has been permitted for use in light-duty motor vehicles manufactured after 2001. However, it is not approved for use in small engines and older vehicles due to concerns with material incompatibilities and corrosion. Furthermore, several automobile manufacturers will not honor their warranties if E15 gasoline was used in the vehicle (even for those manufactured after 2001). The EPA requires that in order to sell E15 gasoline, a Misfueling Mitigation Plan must be in place to prevent consumers from using the product in an unapproved engine. There are very few retailers who have chosen to get approval to sell E15.
Due to the absence of the One-Pound Waiver for RVP, the significant legal risk in selling a controversial product, and the minimal market demand HF has decided that it would be unwise to enter the E15 market at this time.
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 58: What issues are experienced at the desalter and pre-heat train when recirculating brine at the desalter?
SHENKLE (Flint Hills Resources, Ltd.)
Before answering this question, I want to clarify that the panel has defined ‘recirculating brine’ as brine going back to the freshwater makeup. For example, it may be used when insufficient makeup is available to maintain recommended washwater rates. We do not recirculate brine. We inject makeup water upstream of the second stage mix valve. Second-stage brine is pumped back to the first stage upstream of the mix valve, and then the first-stage brine is effluent. We operate washwater rates that are typically in the range of 4 to 5%.
SLOLEY (CH2M Hill)
Brine can be recirculated at the desalter. Additionally, there are some plants that recirculate brine found upstream in the heat train network. This is used in plants that have insufficient water to get proper contacting across the mix filter and which are often trying, in extreme cases, to move even from 2 or 3% water up to around 4 or 5% water. Since the freshwater rate does not increase when you do this operation, if it is more effective, you will increase the solid content of the brine. After all, that is the objective.
In some units, problems can arise due to oil and water emulsification because the pump that needs to recirculate this water – if you have oil in it – is a great mixing device. If the brine does not effectively de-oil, this water will recirculate and could cause problems with the rag layer in the desalter. Additionally, if the soap content of the water is high, you will get emulsions forming. With higher total water rates in many of these desalters also, the total water residence time is reduced, making the oil and water emulsions more difficult. The downstream exchange of equipment fouling and corrosion rate should be lower. If it is not changed or gotten worse, you should stop the brine recirculation.
HODGES (Athlon Solutions)
We are huge fans of recycling brine. In most cases, it is the Best Practice to increase the effectiveness of your desalter by increasing the effective washwater percentage through brine recycle, which will drive optimum desalting. As I mentioned earlier, one of the key items that is often overlooked when doing this is your seal flush. Make sure that you do not use the recycled water for your seal flush because it will erode your seal. Use fresh water. This may be subtle to some and obvious to others. Make sure that when you are recycling, you are not replacing your fresh water with recirculated brine. Recirculating brine is only used to add more effective percentage washwater. If you back out the freshwater, you will be taking a step back in effective desalting and contaminant removal across the desalter.
TOM COLLINS (Forum Energy Technologies)
Recirculating effluent water back to the desalter can improve efficiency by increasing water droplet population, allowing for larger droplets and faster settling. When recycle water is used, it is typically injected just before the mixing valve, not into the pre-heat train. It is also recommended that you divert the recycle when mud-washing unless a continuous mud-wash is used. Additional water volume may also allow for improved mixing efficiency, due to an increase in the water droplets created in the mixing valve or emulsification device. Care should be taken not to recycle water high in oily solids or other emulsifiers that may help stabilize interface emulsions and increase BS&W.
GLENN SCATTERGOOD (Nalco Champion Energy Services)
It is important to recognize the benefits of desalter washwater recycle, which improves dehydration and leads to improved salt removal. A higher rate of desalter washwater may also increase solids removal when processing high solids crudes.
DENNIS HAYNES (Nalco Champion Energy Services)
Recirculation of brine is a very good strategy to increase washwater to the desalter while minimizing effluent flow to wastewater treatment. The issues that may be experienced during this recirculating brine include a potential reduction in solids removal due to sending desalter effluent containing some solids through a pump motivating the flow back to the combined washwater inlet. More so, an issue is that if there is any upset or degree of oil in the effluent, the shearing action of the recycle pump will tighten the effluent emulsion. This emulsion, combined with the washwater into the raw crude oil which is then emulsified via the mix valve, may create interface growth in the desalter to the point that the system upsets. The brine recycle should be used with a non-oily effluent.
PHILIP THORNTHWAITE (Nalco Champion Energy Services)
It should be remembered that if a desalter operation is washwater-limited, the use of a brine recycle is an effective means of increasing the washwater volume and improving both dehydration and desalting performance. However, the operation is not without risk, and there are operation considerations to be made.
First, the recirculation of effluent brine is, in effect, adding salt to the crude oil when the two are mixed together. As a consequence of this combination, if the salinity of the brine significantly increases, the mixture can limit the salt removal efficiency across the desalters, the optimum salt content of the desalted crude increases, and the process efficiency can actually decrease. This reaction can be mitigated to an extent since the increased washwater volume leads to improved dehydration and desalting efficiency. Additionally, any increase in overhead chlorides can be mitigated to a degree through good monitoring and caustic management practices.
The other major consideration is that any deterioration in the effluent quality can have a significant impact on the whole desalter operation. If there is an upset leading to an oil undercarry, the oily brine will be passed through the brine recycle pump leading to the formation of a very stable emulsion. As this stable emulsion forms part of the total washwater feed, it can lead to emulsion layer growth within the desalter vessel and begin to exacerbate the already upset conditions. Key to mitigating this threat is regular visual checks of the try lines and effluent quality so that any onset in effluent deterioration can be quickly acted upon.
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.