Participants: Doug Clarke, Al Keller, Jim Asquith, Sam Lordo, Bob Falkiner, Steve DeLude and Roberto Tomotaki
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We’d like to produce less light naphtha and more liquid fuels from our hydrocracker. How do we go about it?
For changes mid-run with an existing hydrocracker catalyst load, facilities and feed, the most effective way of lowering light naphtha yield is to reduce the conversion in the hydrocracking catalyst portion of the load. This is usually accomplished by reducing the hydrocracking catalyst temperature, reducing liquid recycle rate and/or increasing recycle cut point. Often the extent of de-conversion is limited by product specifications (eg, sulfur, nitrogen, Cetane, PNAs) or equipment constraints within the unit (eg, product pump rates, hydrocracking catalyst quench / cooling, product fractionator stripping rate). Some temperature adjustments to the hydrotreating catalyst may be required to meet product specifications while equipment constraint can often be determined by doing some planned rate and performance tests. Note that reducing the conversion will also likely reduce the total liquid product yield thereby leading to an economic trade-off with light naphtha yield.
For long term reduced light naphtha yield reduction with the same/ increased total liquid product yield, a combination of changes to the loaded catalyst system and debottlenecking of unit equipment is typically required. Working with the catalyst vendors can help identify catalyst systems that have reduced naphtha selectivity / increased diesel selectivity as well as increased liquid swell for a more desirable product yield slate. Some unit constraints may be known from past operations; however, typically a good project basis for identifying and relaxing equipment constraints can be accomplished by doing a unit performance test. The performance data can then be used in simulations and to check performance against equipment data sheets limits. Upgrades to product pumps, quench valves, fractionator internals and safety valves are common for modest upgrades to run in a de-converted mode. Experience shows that desired product yield profiles shift often with economics, so some flexibility to run in both low and high conversion modes is usually maintained.
Please suggest ways of reducing steam demand in our sour water stripper.
Steam demand in a sour water stripper (SWS) can be reduced without affecting stripped sour water quality by reviewing a number of key operating parameters including:
Sour Water Generation – Are you generating excessive sour water or processing water in your SWS that that does not require treatment. If any water going to sour water meets water treatment plant inlet specifications for ammonia, COD, and BOD, it is not necessary to send it to sour water stripper.
In addition to optimizing exchanger water wash systems, if possible, use low level ammonia containing water as makeup water to water washes which will increase the ammonia level. For instance, use 100 ppmw ammonia water as makeup for a water wash where the ammonia level will go up to 5000 ppmw.
System Fouling – A stripper consuming above design steam to meet spec is most likely suffering from fouled feed-effluent exchanger, fouled trays/packing, or contaminant load has increased. Simulating the tower and comparing actual pressures, temperatures, and flows to design will help identify areas to optimize.
Crude or other process changes may lead to increased fouling. If fouling is detected from significant process change, routine mechanical cleaning of the reboiler and stripped water side of the feed/effluent exchangers might become necessary. Chemical cleaning may not be effective with some heavy hydrocarbon fouling materials.
Keep hard water (cooling water, fire water, city water) out of the SWS system. These contain water hardness (Calcium and Silica) that can SWS trays and reboilers.
Feed Contaminants – The amount of ammonia allowed in the stripped water usually sets the amount of steam required in the stripper. The ability to strip the ammonia from the water can be affected by the level of contaminants in the sour water such as strong acids. Ammonium salts of strong acid anions cannot be decomposed by steam stripping at SWS conditions. To determine if this happening, conduct a complete anion and cation ion chromatography scan of the sour water and compare the strong acid anion charge equivalents (formate, acetate, chloride) to cation equivalents. If anions exceed cations on a charge equivalent basis, caustic addition may be needed to convert ammonium salts to sodium salts. Measure ammonia in the bottoms with cation ion chromatography. Set steam rate to achieve the desired ammonia level by IC. Amines used for neutralization or from amine treating purges/upsets may interfere with field test kits based on colorimetric chemical methods. pH measurements don’t give any indication of ammonia content due to presence of many different anions and cations. Don’t control by pH!
Phenolic and Non-Phenolic Water – For systems that process both phenolic and non-phenolic water, consider using separate SWS to process these streams. Phenolic water is usually low in ammonia and takes less steam per gallon to meet ammonia specs. Non-phenolic requires more steam per gallon, but the volumes are generally lower.
We’ve increased the opportunity crude content of our feed and are experiencing high calcium issues. How can we best address this?
Removal of calcium from crude oils is best done at the desalter. Particulate calcium like its carbonate form can be removed by increasing the amount of desalter washwater and desalter mix valve DP. Other forms of calcium are best removed by adding an organic acid to the desalter wash water . The acid quantity needed is generally based on the amount of acid needed to have a desalter brine effluent pH of 5.5-6.0. Brine pH’s lower than 5.0 may cause corrosion in the piping circuits of both the desalter and desalter wash water. One consequent of adding acid is the potential acid carryover from the desalter and into the crude tower overhead system. Depending on the acids loading the overhead neutralizing additive may increase upwards of 30-50% depending on desalter operation and organic acid selected. Another unintended consequent is forming an insoluble calcium salt that can create desalter operating issues. This is particular to high levels of citric acid. When selecting which type of acid to be used the solubility of calcium salt needs to be considered. Mineral acids are not that effective in calcium removal.
Are there options for online cleaning a preheat exchanger network?
There are a number of options either using chemical additives/solvents or mechanical means available that can be used to on-line clean preheat exchanger networks.
For chemical or solvent approaches, the most appropriate choice of cleaning option and its effectiveness is dependent on the nature of the fouling that has occurred in the exchangers and the ability to ensure flow through all the exchanger tubes. Your chemical suppliers should be involved and can provide any information from past turnarounds on the deposit chemistry/characteristics to determine the most appropriate on-line cleaning chemistry to apply. The chosen solution will often be a combination of proprietary chemical formulations customized by your chemical supplier for your specific situation.
Care should be taken to ensure that chemical and deposits removed from the exchanger network does not have an adverse impact on downstream equipment or catalyst.
If the fouling is caused by deposition of asphaltenes or other heavy hydrocarbons, then a highly aromatic stream or solvent additive can assist in redissolving and dispersing the heavy deposit. If the fouled exchanger is upstream of the desalter, it may be possible to remove some of the heavy deposit with the desalter mud. Temporarily bypassing or shutting down one side of parallel banks of exchangers can increase flows and temperatures to also help move very heavy deposits.
If the deposit is mainly corrosion products, these can sometimes be removed by acidic or other chemical reactants additives.
If the deposit is an inorganic salt, a water wash may temporarily improve the exchanger heat transfer but extreme care is required to not cause any materials damage due to rapid corrosion that can occur with wet salts if they are not completely removed. This can be especially true where the exchanger pressure drop is high and there is evidence of partially plugged tubes.
However, even with the correct chemistry, there will always be some risk that the on-line cleaning will not be fully effective due to an inability to get good flow through all the fouled areas of the exchanger on both the tube side and the shell side of the exchanger.
In addition to chemical cleaning methods, several mechanical cleaning methods can also be utilized often in conjunction with chemical cleaning methods. Such methods include, attaching ultrasonic transducers to the exchanger tubesheet. This method utilizes ultrasonic transducers to generate vibration, acoustic streaming and cavitation to “shake loose” deposits from the exchanger surface.
Another option includes the use of internal vibrating systems to keep the inside of the exchanger tubes clean by installing a vibrating device or spring secured on both tube ends by a fixing wire. The energy of the fluid flow in the tubes causes these devices to vibrate creating a continuous online mechanical cleaning effect of the tube interior.
In cases where on-line cleaning is not completely successful, then improved techniques for off-line cleaning such as those applying ultra-sonic cleaning technology can be applied to regain most of the original heat transfer performance of the equipment.
Brief bio’s of the Becht participants
Steve DeLude, Becht Advisor
Stephen G. DeLude, PE., Becht Advisor, has over 30 years’ experience in oil sands development and petroleum refining with Shell Canada. His experience includes: heavy oil, bitumen processing and upgrading, oil sands extraction technology, sulphur complex, hydrogen manufacturing, utilities and offsites, fluidized bed catalytic cracker (FCCU).
Doug Clarke, Becht Advisor
Doug Clarke is a Becht Advisor with over 30 years experience in Hydroprocessing and Hydrocracking technology including unit optimization evaluations, profitability studies, startup assistance, operation procedures improvements, licensing support, facilities planning studies, design reviews, safety and reliability reviews, and competitive technology evaluations during his career with ExxonMobil.
Al Keller, Becht Advisor
Al Keller, PE., Becht Advisor has over 35 years of experience in process engineering, technology licensing, and research and development in the fields of amine treating, sulfur recovery, and alkylation technology. Al is a subject matter expert in the areas of Alkylation, Sulfur Recovery, and Amine Treating. During his career with ConocoPhillips, he was awarded over 30 US and International patents concerning syn gas generation, amine treating and sulfur recovery technology. Al has also published and presented numerous papers at US and International sulfur and gas treating conferences. He serves on several gas treating organization boards.
Jim Asquith, Becht Advisor
Robert ‘Jim’ Asquith has over 35 years process engineering and operations experience in the petroleum refining industry. Jim is a subject matter expert in the area of Sulfur Recovery and Amine Treating. He is a member of the American Institute of Chemical Engineers, and the Amine Best Practices Group
Sam Lordo, Becht Advisor
Sam Lordo, Becht Advisor, is a recognized industry expert and has over 40 years’ experience in refinery process chemistry/chemical treatments, opportunity crude processing and crude desalting. During his 40 years of corrosion / refining / petrochemical experience, he has been involved in all aspects of managing risk due changing crude slates and process conditions; including corrosion prevention, fouling prevention and control, failure analysis, and crude desalting. Sam is active in Crude Oil Quality Association (COQA) and the Opportunity Crude Conferences presenting on a wide variety of topic regarding crude oil processing. He is an active member of and American Fuels and Petrochemical Manufacturers (AFPM).
Bob Falkiner, Becht Advisor
J. ‘Bob’ Falkiner, PE., Becht Advisor, has over 30 years’ experience as an industrial chemist in the petroleum refining industry, based on his long-term career with Imperial Oil Ltd. Bob has a significant amount of experience in R&D for new process applications, pilot plant / process development, field support for process applications, development of new process analytical tools and procedures, and a proven track record of patents and development of new ASTM / API test methods and procedures. Bob supported over 100 refinery process product quality / specifications investigations.
Roberto Tomotaki, Becht Advisor
Roberto Tomotaki, Becht Advisor, has over 25 years’ experience in the design, troubleshooting, monitoring, and repair of heat exchangers during his career as a process heat transfer specialist with ExxonMobil. Roberto is well versed in HTRI and has served as an API Committee Member to develop heat exchanger codes and standards including 660 (shell-and-tube heat exchangers), 661 (aircooled heat exchangers), and 662 (plate heat exchangers). Roberto also holds one patent in the field of heat exchanger design for an anti-vibration tube support.