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 45: What are the procedures/rules governing the transportation and disposal of catalyst contaminated with arsenic, mercury, barium, or other heavy metals? Are there maximum limits for any of these?
SHARPE (Flint Hills Resources, LP)
The spent catalyst needs to be shipped offsite and sent for metals reclamation or disposal. If it is going for disposal, it will have to be characterized to determine if 1) it is a hazardous waste, which it is most of the time, and 2) it meets the applicable Land Disposal Restrictions (LDRs). It would have to be treated, as part of disposal, to meet the LDRs.
Regarding transportation, if the catalyst needs to be shipped offsite for reclamation, it will have to be determined if it is hazardous material or contains hazardous substance. So by default, spent catalysts generally fit into that category. Take a look at the Hazardous Materials’ Table listed on the slide.
Overall, there are no maximum limits for disposal or transportation, but the catalyst does have to be transported and disposed of properly. It ends up being classified as a hazardous waste and subject to all the laws regarding that classification.
CHRIS STEVES (Norton Engineering)
The transportation and disposal of spent catalysts are governed by DOT (Department of Transportation) and RCRA (Resource Conservation and Recovery Act) regulations. A spent catalyst with leachable levels of arsenic, mercury, or barium (or five other regulated heavy metals) above their TCLP limit, will be regulated by the U.S. EPA (Environmental Protection Agency) as RCRA hazardous waste. If the material is spent hydrotreating catalyst from the petroleum refining industry, it will automatically be regulated as RCRA hazardous waste regardless of the metals content. Regulated RCRA hazardous waste must be properly disposed of at an approved treatment, storage, and disposal facility (TSDF). The actual levels of contamination will affect the options and cost for disposal. All RCRA hazardous wastes are regulated as DOT hazardous materials when shipped offsite, and all the basic rules for hazardous materials shipment must be followed.
Question 75: What are the potential problems or negative impacts of utilizing FCC slurry/decant oil as coke drum OH (overhead) line quench oil?
SRIVATSAN (Foster Wheeler USA Corporation)
Again, FCC slurry/decant oil has a similar distillation range to HCGO but a higher endpoint. Although it could possibly be used as just overhead quench, we caution that if the slurry/decant oil is not be filtered properly, it will contain catalyst fines that could accelerate the coke deposition by settling in equipment or piping. We normally recommend using the blowdown tower bottoms as the primary source for quenching the overhead vapor line. The secondary means of quenching is provided using HCGO. LCGO and other gas oils, including slops, can also be used as desired.
PRIBNOW (CITGO Petroleum Corporation)
We do not have any experience using slurry oil as coke drum overhead quench. We utilize slop oil, as Srini mentioned, as a way to vaporize and reprocess that material. We charged slurry oil to our coker when excess capacity was available. However, we found that it degraded the heavy coker gas oil quality back to the FCC. The FCC conversion drops, and catalyst becomes dark; so, we tend not to do that much anymore.
SRINI SRIVATSAN (Foster Wheeler USA Corporation)
The purpose of the coke drum overhead quench oil is to reduce coking reaction by lowering vapor temperature and mitigating coke formation. A portion of the overhead quench is also condensed and forms recycle. Foster Wheeler recommends using the blowdown tower bottoms liquid as the primary means to quench the overhead vapor line, the secondary being the use of HCGO. LCGO and other gas oils including slops can also be used as desired. FCC slurry/decant oil has a similar distillation range as HCGO with a higher endpoint. Although it could possibly be used as an overhead quench, we caution that if the slurry/decant oil is not filtered properly, it may contain catalyst fines that could accelerate coke deposition by settling in equipment or piping.
EBERHARD LUCKE (CH2M Hill)
Although I never worked in a unit that used FCC slurry/decant oil as quench oil, we used it as coker feed; so, my concerns are based on that experience. FCC slurry/decant oil carries a significant amount of cat fines that are difficult to remove from the stream. So I would assume that with the injection of the slurry/decant oil, these cat fines will be introduced into the coke drum overhead system. The fines will end up either on the inside of the vapor line, in the bottom of the fractionator, or carried even further through the system and will act as seeds for coke buildup and cause accelerated fouling/coking of equipment. The cat fines will also most likely cause erosion in the nozzle that is used for quench oil injection. Additionally, quench oil distribution will be poor (but can be fixed by the selection of the correct material).
ROBERTSON (AFPM)
Before we get to the last question, I want to remind you that the Crude P&P is this afternoon at 2:00. During that time, a lot of these issues we have covered will be discussed in more depth. Tomorrow, the Light Tight Oil and FCC P&Ps are run concurrently. If you have any other issues you want to discuss that were not raised in this forum, please attend those P&Ps.
Question 85: What is the typical range that you employ for iron content on FCC equilibrium catalyst? What methods are available to determine how iron is accumulated on the catalyst surface? How does the distribution of iron on the catalyst surface impact the FCC operation, yield structure and emissions?
Jeff Lewis (BASF)
The histogram below shows the distribution of iron content for all ecat samples BASF receives. It should be noted that fresh catalyst has an iron content of about 0.55 wt%. The histogram shows that the median ecat iron concentration is approximately 0.62 wt%. This suggests the median contaminant iron level on ecat is 0.07 wt%.
There are several methods available to quantify iron contamination on catalyst. Scanning Electron Microscopy (SEM) pictures are a valuable means to qualitatively assess iron laydown morphology on the catalyst particle. The three images below show varying degrees of iron contamination on a catalyst particle. The first picture shows a fresh catalyst particle that is free of contaminant iron on its surface. The second picture shows a catalyst particle with a significant concentration of iron nodulation on the catalyst surface. The third picture shows a low boiling eutectic formed in the presence of an alkali metal like Ca or Na and is the severest form of iron poisoning.
David Hunt (Grace Davison)
Grace receives E-cat samples for most of the FCC units operating worldwide. The figure below shows the distribution of average equilibrium catalyst Fe levels for 2010 for all FCC units that have provided E-cat samples to Grace. Mean Fe levels are 0.57 wt% and the highest Fe level in one unit is 1.36 wt%.
Iron can be detrimental to the unit in many ways including bottoms conversion, catalyst circulation stability and SOx emissions.
Yaluris (1) showed using an Electron Probe Micro-Analysis (EMPA) technique that iron from organic iron sources is primarily a catalyst surface contaminant. Yaluris also used scanning electron microscopy and optical microscopy techniques to confirm Fe is a surface contaminant. The figure below is an EMPA image of an FCC catalyst particle cross section. Warmer colors on the surface of the particle confirm that Fe and CaO are primarily surface contaminants. EMPA Image of Two FCC Catalyst Particles
Yaluris (1) discussed how Fe contamination can lead to pore closure and nodule formation. The presence of Na and CaO can act as fluxing agents, aggravating the effect of Fe. The figure below shows Decant Oil or Main Fractionator bottoms yield vs. E-cat Fe plus CaO levels. Decant Oil increases at the higher contaminant levels due to the damaged catalyst pore structure.
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 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.