Question 28: The Clean Air Act required refineries to develop and implement a Leak Detection and Repair (LDAR) program to control fugitive emissions. What is the current status of this implementation and who is responsible for it in a typical refinery management structure: production, maintenance or EHS?
Greg Harbison (Marathon Petroleum)
Background/Regulatory Requirements:
Since the inception of the Clean Air Act of 1955 and multiple amendments through 1990, Leak Detection and Repair or LDAR regulations have been a part of air pollution control. Today’s LDAR programs are governed by Federal and State regulations and agreed orders (consent decrees) that provide the control of fugitive emission leaks from process equipment by requiring equipment inspections and leaking equipment repair. As such, the specific requirements can vary company to company or even between refineries operating in different states within the same company. Marathon complies with these regulations.
Equipment Inspections
Components that are LDAR applicable can vary by type and inspection or monitoring frequency. Generally, LDAR components consist of valves, pumps and compressors that are monitored on a quarterly basis. Monitoring requirements can be more stringent for units built or modified post November 2006 and can apply to flanges, connectors, fittings, hatches, and agitators (to name a
few). Process stream speciation determines the applicable regulatory requirements for streams. The typical streams requiring the most rigorous application of LDAR regulations include:
1. gas/vapor streams that are typically > 10% ethane and heavier,
2. light liquid streams are typically heavy naphtha or kerosene depending on specific stream properties, and
3. process streams containing greater than 5% hazardous air pollutants (benzene, methanol, toluene, etc.)
These monitoring requirements can be more or less frequent and have different leak definitions based on different applicable regulations. A leak definition is the threshold in parts per million that a component must reach to be considered leaking. LDAR monitoring is outlined in EPA Method 21, which states that a toxic vapor analyzer (TVA) must be used to assess total volatile organic compound (VOC) leaks from LDAR components. As LDAR regulations become stricter, the leak definitions are increasingly being lowered. With every change in regulation, the LDAR program becomes more challenging to manage since most facilities are required to stay below a facility wide leak percentage for leaking equipment (typically 2%). Thus, a rigorous and well-structured leak repair and maintenance portion of the LDAR program is vital to minimize emissions and maintain compliance.
Program Oversight
A practical LDAR program encompasses multiple people spread across many different job functions. Overall, it is our experience that a successful LDAR program can be successfully managed if several critical items are in place. These include dedicated personnel, a robust software database, good overall management system, well defined roles and responsibilities, and a comprehensive auditing system. At our refineries, it is typically the responsibility of the facility Environmental LDAR Coordinator (HES Professional) to manage and oversee all aspects of the LDAR program. We also use a contract company to conduct the emissions monitoring, and another contract company to make the initial leak repairs on valves (typically injection of a sealant into the valve packing area). Other LDAR applicable components such as motor operated valves (MOV’s), control valves, pumps and compressors are repaired when leaking by qualified individuals within the facility Maintenance Department. The requirements for completing the repairs are often sensitive to equipment and process functionality.
The LDAR Coordinator should have daily communication with the LDAR Monitoring Contractor to go over every open leak Work Order. This information is reviewed and an updated list of all leaks within the facility is given to the Contractor and facility Maintenance Department every day.
Overall, the regulations are complex and can generate an overwhelming amount of information based on the size of the facility and how many leaks are found above the leak definition. A large refinery could have upwards of 70,000 LDAR components governed by state and federal regulations as well as additional requirements from agreed orders. It is imperative to have a functional LDAR database that manages this information. The database should be capable of scheduling all monitoring and repair dates based on applicable regulations for the facility. The progress of the monitoring schedule needs to be easily accessible for all parties involved.
Question 75: In your experience, how does the shape of an FCC catalyst particle impact the fluidization properties of the catalyst? What other properties are important to monitor?
ALEXIS SHACKLEFORD and SHAUN PAN (BASF Corporation)
The key catalyst properties affecting fluidization are particle size distribution, particle density, and particle shape. Fluidization studies have shown that a change in catalyst shape from spherical to oblong gives a 19% reduction in deaeration rate, due to more drag force with an oblong particle: meaning, itis harder to defluidize this material. However, catalyst with irregular particles and sharp edges, such as attrition generated particles, are harder to unlock and fluidize. Fluidization equations, as appear in the literature, often drop out the shape factor since it is difficult to determine, including the Abrahmsen and Geldart Umb / Umfequation (1980) and Coltters and Rivas (2004).
The variable that affects catalyst fluidization the most is the quantity of less than 45 microns particles (or fines) in catalyst. A catalyst with a range of particle size flows more smoothly than one of uniform size. The smaller particles fit between the larger ones, acting as a lubricant to make flow easier. Improvements in fluidization can also be made by a reduction in e-cat density and a change in particle shape. A reduction in the 80+ microns fraction has an influence, but it is not a major factor.
The following important properties should also be closely monitored:
1. ABD
2. 0-to-45-micron fines content,
3. APS (average particle size), and
4. Attrition, as irregularly shaped particles with sharp edges do not fluidize well.
Question 35: How far can the hydrogen to hydrocarbon ratios be decrease in gasoline hydrotreating units before experiencing high reactor pressure drops? Please provide some details of your experience with reference to the run length limitations and operating performance.
Ujjal Roy (Indian Oil Corporation)
We have number of naphtha hydrotreatment units in our refineries, some operating with straight-run naphtha as feed and others in mix mode with significant cracked feedstock varying from 10% to 40%, to produce feedstock for catalytic reformers. I suppose, the question here is for hydrotreating units processing cracked components.
Straight-run naphtha hydrotreatment units, in our case, are designed for low pressure (i.e. 20-25 kg/cm2.g) and with 40-75 Nm3/M3 of gas to oil ratio depending on feedstock characteristics and desired product quality. In case of hydrotreaters designed to process FCC gasoline, designed gas to oil ratio is about 400 – 500 Nm3/M3 of feed operating at about 50 kg/cm2. The designers recommend the partial pressure of hydrogen through gas oil ratio and system pressure based on the given feed characteristics and target product w.r.t. olefin, sulphur and nitrogen content. Difficult feedstocks with higher nitrogen content require higher hydrogen partial pressure. Reduced gas to oil ratio can only be compensated partially through higher RIT for equivalent nitrogen removal. But running at higher RIT compensating for lower gas to oil ratio with cracked component in feed will accelerate the coking rate on catalyst leading to high pressure drop. Coke formed on the top of catalyst bed can lead to excessive pressure drop and channeling within reactor which will reflect in radial temperature spread. Delta T across the first bed of the reactor will increase due to less availability of hydrogen as heat sink. Also, lower gas to oil ratio aggravates coke formation in the preheat exchangers resulting in high pressure drop. All these would finally lead to slippage of sulphur and nitrogen in product apart from reduced cycle length. This phenomena has been experienced in one of our hydrotreaters with cracked component in feed due to problem in RGC resulting in low flow over days. We normally do not practice lower gas to oil ratio below recommended value as the penalty is large over the time period as compared to pushing extra capacity or reduced energy consumption.
However, in one of our units, we have optimized gas to oil ratio to nearly 90% of recommended value with the advice of licensor, by shifting some reaction from Bed-1 to Bed-2 through reduced reactor inlet temperature in Bed-1 and reduced quench rate in Bed-2. This in turn has led to ascending temperature profile i.e. drop in Bed-1 peak temperature as compared to that of Bed-2 peak temperature. By doing so, we could maintain uniform radial temperature and no appreciable increase in reactor Delta P since about two years of operation inferring no appreciable reduction in run length due to these adjustments.
In case of coking or fouling, pressure drop across reactor will increase steadily over operation and spikes are not expected. Despite maintaining design gas to oil ratio in many of the hydrotreaters, we have experienced high pressure drop leading to frequent skimming of catalyst bed. The reasons for these incidents have been identified to be caustic carry over from upstream caustic wash units, dissolved oxygen in tank wagon while being transported from one refinery to another and carryover of foulant from feed tanks.
The decrease in run length on account of lower gas to oil ratio operation on continuous basis is a factor of type of feedstock i.e., olefin, sulphur and nitrogen contents and target product specifications. In case of margin available in the feedstock quality, gas to oil ratio can be optimized based on adjustment in reactor severity and conversions.
Praveen Gunaseelan (Vantage Point Consulting)
It is assumed that the question pertains to FCC gasoline hydrotreating. Due to the variability in unit designs, process configurations, feed compositions, contaminant levels, product quality targets, etc., a specific answer to the question cannot be provided. For site-specific guidance, refiners are advised to consult with the gasoline hydrotreating process licensor or a qualified engineering contractor.
Maintaining adequate partial pressure of hydrogen is a critical element of hydrotreater operation, as it minimizes coke formation on the catalyst. An adequate feed gas to oil ratio is also essential as the gas plays a critical role in heat removal from the reactor. For these reasons, hydrotreating process licensors often require a minimum gas to oil ratio during operation to prevent premature catalyst deactivation and reactor overheating. While a common rule of thumb is that the minimum gas to oil ratio should be at least 4 times the hydrogen consumption per barrel of feed, it is critical to recognize that this ratio is inherently unit-specific, and the licensor or designer’s operating recommendations should be strictly followed.
Other potential complications of operating at low hydrogen to hydrocarbon ratios include reactor fouling due to incomplete saturation of diolefins, accelerated catalyst deactivation due to higher temperature operation, and unsatisfactory product quality.
The chapter on Hydrotreating by A. Gruia in the Handbook of Petroleum Processing (D.S.J. Jones, P.R. Pujadó, eds., Springer, 2008) has useful information pertaining to this question.
Olivier Le-Coz (Axens)
As a general guideline, in viewpoint of catalytic performances and cycle length it always recommended to operate naphtha HDS reactors at maximum recycle gas rate. Because those reactors operate in gas phase Hydrogen partial pressure is significantly affected when the recycle gas rate varies. Maximized recycle has rate and thus Hydrogen partial pressure, allows minimizing catalyst temperature and maximizing cycle length. In the case selectivity towards HDS versus olefins saturation is targeted, maximizing recycle gas rate to maximize hydrogen partial pressure and minimize catalyst temperature is crucial.
Brad Palmer (ConocoPhillips)
COP sets the lower limit on gas/oil ratio at 300 scf/b (with a minimum of 70% hydrogen in the treat gas). Remember that the hydrogen is diluted by vaporized hydrocarbon, especially in a naphtha unit. Hydrogen partial pressures are actually very low. We also set a minimum of 3:1 treat gas hydrogen to chemical hydrogen consumption, i.e., the treat gas hydrogen rate per barrel must be at least 3 times the per-barrel hydrogen consumption. Both of these criteria are supposed to be met. In practice, some units do not meet the minimum rates.
Once the minimum is met, there are many other factors that are more critical than the hydrogen/oil ratio. These factors include the operating pressure, LHSV, feed composition, feed contaminants and percent cracked stock.
With respect to hydrogen gas/oil ratios, we can offer direct comparisons where two units feed essentially the same feedstock and operate at primarily the same conditions, except for the gas/oil ratio. The best comparison basis is barrels of oil processed per lb catalyst because in this case the units do not have exactly the same catalyst volumes.
•Case 1: Straight-run naphtha feed at about 360 psig. One unit has more catalyst in it, but the cycle lengths are the same at 18 months. One unit has 140 scf/bbl hydrogen and the other has 270 scf/bbl. The oil amounts processed in 18 months in these units are 195 and 241 Bbls/Lb catalyst, respectively. The unit with the higher gas rate processes about 24% more oil per pound with a gas/oil ratio about 93% higher.
•Case 2: Straight-run naphtha feed at about 450 psig. Again, the amounts of catalyst in the units differ, with the cycle lengths the same at 48 months. Gas/oil ratios are 570 scf/bbl and 710 scf/bbl. The barrels per pound catalyst processed are 571 and 740, respectively. The unit with the 25% higher gas rate can process about 25-30% more oil.
Question 75: The butane stream from a catalytic polymerization (cat poly) unit, which contains 69% isobutene, 14% butylenes, and 17% normal butane, would appear to be an excellent alkylation unit feedstock, especially if isobutene is i
METKA (Sunoco, Inc.) We operate a cat poly and sulfuric alkylation unit within the same refinery. The configuration offers flexibility and synergies that allow various operating and business demands to be met. In our configuration, the cat poly debutanizer overhead feeds the alkylation unit to recover the isobutane and any remaining butylenes.
Similar to our other SPA experience, acid carryover from the effluent filtration system typically drops to the bottom of the downstream fractionators resulting in fouling and corrosion of the reboilers. Historically, we have not experienced any significant impact on the alkylation unit or sulfuric acid quality due to carryover from the cat poly unit. If carryover were to occur, we do expect that the phosphoric acid would be more of a corrosion and fouling concern than an acid consumption issue.
Below is a plot that basically shows the way in which the plants are configured. The BB is treated and split to the cat poly and alky units in parallel. Once we recover the C4s off the backend of the cat poly plant, the stream is fed back into the alkylation unit.
Gasoline ProcessesGasolineProcessesFCCDebutDepropBtmsCat GasolineC4,C4=PolyTreaterAlkyContactorsDepropDebutDepropBtmsLPGPolymer GasolinenC4,iC4ContactorEffluentDIBDebutnC4/AlkylatenC4AlkylateMake-up C4iC4PolyAlkyFCCGasolineMixed ButaneiC4nC4Rxr EffluentTreated C4, C4=EffluentTreatingPolyRxrs (FUNKY GRAPHIC)
ZMICH (UOP LLC) I have three points that I would like to make.
1) UOP does not have experience with traces of phosphorus in the alkylation unit feed.
2) UOP strongly recommends avoiding the possibility of phosphorus in the feed. The reason for this is that a combination of mineral acids will lead to a more aggressive corrosion than either of the two acids by themselves.
3) From a commercial perspective, UOP is aware of at least one refinery that feeds cat poly stream with feed from an FCC to an alkylation unit, and the process flow is shown in words as such: “Process flow is a stream goes through a water wash to remove phosphoric acid, the sand tower acting like a coalescer, and a UOP MeroxTM unit to remove sulfur before going to the alkylation unit.
Question 26: What is your Best Practice for packing (material and shape) in isomerization unit off gas caustic scrubbers?
DUNHAM (UOP)
UOP recommends carbon Raschig rings. The key here is to specify to the vendor that this be used for caustic service so that the rings will be formed with the proper binder. If you get the wrong binder, the rings will dissolve. We have a similar service in HF alky units where we use carbon Raschig rings; and there, you have to make sure that the binder is resistant to acid. So, you cannot switch the two. I have seen the carbon Raschig rings ooze out of the tower when a customer bought the wrong binder.
Another material you can use is chemical-grade polypropylene. This is plastic, so it does have temperature limits. If you use this kind of material, you have to be careful not to steamout the tower because this packing is good for the operating temperature of the unit. But if you steam it out, it will melt, and all come out in one piece.
LAMBIE (KBC Advanced Technologies, Inc.)
My experience has only been with the carbon Raschig rings. I have not seen any issues with them in any other sites. My only other comment to add to Daryl’s is that the use of ceramic rings is not recommended because they are not compatible with caustic.
DOMINIC VARRAVETO (Burns & McDonnell)
My question is related to the scrubber. Have there been any comments from the operators of these units with upsets that cause caustic to go backwards into the stabilizer and create plugging in the stabilizer overhead system?
LAMBIE (KBC Advanced Technologies, Inc.)
I have not seen or heard of this happening. Normally there is a check valve in the line to prevent any backflow from the caustic scrubber to the stabilizer.
RICK GRUBB (Chevron Products Company)
We have experienced caustic back-flowing in the overhead receiver drum, so we have installed quick-acting ball valves that activate pressure differential. When the pressure differential gets low enough, it will close the valve.
SCOTT LAMBIE (KBC Advanced Technologies, Inc.)
One-inch OD carbon Raschig rings have been the standard packing material for isomerization unit off gas caustic scrubbers. Use of this packing material has proven to be very effective in minimizing caustic breakthrough and water carryover. Operating the unit per the design circulation flow rates of caustic and water insures proper wetting of the packing material for maximum effectiveness.
The use of ceramic packing material should be avoided as caustic will attack and degrade the material.
Question 74: In your experience, what are the effects of different Ni passivation technologies on the performance of CO promoters and stack emissions?
ZACH BEZON [United Refining Company (URC)]
Nickel passivation can be accomplished a few ways: antimony, bismuth, or sulfur. Adding antimony or bismuth in a solution, such as LCO, will immediately begin to passivate the negative effects of nickel poisoning. Antimony is considered a fugitive emission and may be hazardous; bismuth may be the safer option. Antimony decreases the effect of CO promoter; additionally, it can lead to elevated NOx emissions. Refinery fuel gas containing H2S can be used as lift gas and act as a temporary nickel passivator in the reactor, helping to reduce hydrogenation reactions. However, this effect is only temporary and will lead to elevated levels of nickel if nothing further is done.
CHRIS CLAESEN (Nalco Champion)
Pt promoters are sometimes used to oxidize CO to CO2in the regenerator. Antimony can passivate platinum promoters, which can result in afterburn and the need to use more platinum promoter. The Pt promoter oxides nitrogen compounds, as well as CO; so, the more Pt promoter that is used, the higher the NOx. Therefore, Sb (antimony) can theoretically result in higher NOx. Units using a Pt-based combustion promoter can consider a switch to one of the non-Pt combustion promoters if they want to eliminate the effect of increased NOx generation.
DENNIS HAYES (Nalco Champion)
Antimony-based additives are known to be effective at nickel passivation, but they have also been reported to reduce the effectiveness of CO promoter additives, resulting in increased usage of the additives.
ALEXIS SHACKLEFORD and BILGE YILMAZ (BASF Corporation)
Using antimony for Ni passivation will make CO promoters less effective. For example, one unit running 1000 ppm e-cat (equilibrium catalyst) Ni started using antimony, targeting a 0.35 Sb/Ni ratio. They had to increase their CO promoter additions from 1.1 ppm platinum (Pt) in inventory to 1.6 ppm Pt, or 50%. Running economics around unit profitability, the refinery found that using antimony improved profitability by 0.15 $/bbl (cost per barrel) due to lower hydrogenand coke. Even though this unit had relatively low Ni at 1000 ppm and had to use more CO promoter, the benefit of antimony at 0.15 $/bbl was significant, and they continued to use antimony.
For units that have operational challenges using antimony, Ni passivation based on catalyst technology is an attractive route. For example, the use of boron-based technology (BBT),developed by BASFand used in our catalyst BOROCAT™, has been demonstrated successfully in commercial operations to passivate Ni without impacting stack emission or CO promoter efficacy.