[Paul R Orlowski]

Jeff,
Oil and Gas Journal (OGJ) sells an annual summary that lists refineries as a pdf. For a higher price you can get a spreadsheet. You can go state by state and refinery by refinery to select out those that have CatCracking.

You might try EIA.gov. They have graphs that show capacity by state and you can choose Fluid CatCracking capacity. You might be able to piece it together – sounds like a lot of work. I don’t recall seeing a downloadable refinery list or spreadsheet though.

If you strike out there, contact me. We sell a list.

1.360.966.7251
Paul

[Paul R Orlowski]

While recovering sulfur in an SRU depends on condensation of sulfur, its unintended condensation and accumulation can present problems. The paper analyses areas where this may be expected and presents case histories of sulfur build-up in SRU equipment, such as waste heat boilers, reheaters, sulfur condensers and coalescers.

The risks involved in accumulation of sulfur are discussed, both for the operation of Claus plants and for the operation of SUPERCLAUS® plants, for which liquid sulfur may pose extra risks. Ways are discussed to prevent accumulation and minimize the risks

http://www.jacobs.com/uploadedFiles/wwwjacobscom/20_Learn_About_Us/25_Products/253_Comprimo_Sulfur_Solutions/2534_News/Article_Risks%20of%20Accumulated%20Sulfur%20in%20SRUs_May2013%20final.pdf

[Paul R Orlowski]

Here’s Marathon Petroleums list of PPE to have before coming onsite.
http://www.marathonrefinerycontractor.com/_Garyvill/What_You_Need_to_Know_Before_Coming_Onsite/
Standard Personal Protective Equipment – PPE required for entry into a process unit and/or tank farm areas is as follows:
– Hard Hat with goggles attached
– Safety Glasses
– Hearing Protection
– FR Clothing
– Gloves
– Personal H2S Monitor
– Safety Toed Shoes

[Paul R Orlowski]

Air Quality Designations for Sulfur Dioxide
After EPA sets a new National Ambient Air Quality Standard (NAAQS) or revises an existing standard, the Clean Air Act requires the agency to designate areas in the United States as “attainment” (meeting), “nonattainment” (not meeting) or “unclassifiable” (insufficient data). This website provides information on the process EPA, the states, and the tribes follow to designate areas for the health-based sulfur dioxide standard established in 2010
http://www.epa.gov/sulfur-dioxide-designations

On June 2, 2010, EPA strengthened the primary National Ambient Air Quality Standard (NAAQS) for sulfur dioxide (SO2). The revised standard will improve public health protection, especially for children, the elderly, and people with asthma. These groups are susceptible to the health problems associated with breathing SO2.
EPA revised the primary SO2 standard by establishing a new 1-hour standard at a level of 75 parts per billion (ppb). EPA’s evaluation of the scientific information and the risks posed by breathing SO2 indicate that this new 1-hour standard will protect public health by reducing people’s exposure to high short-term (5-minutes to 24-hours) concentrations of SO2.

http://www.epa.gov/so2-pollution/2010-primary-national-ambient-air-quality-standards-naaqs-sulfur-dioxide

[Paul R Orlowski]

Here’s a case study on a Risk-Based Decommissioning of a Sulphur Storage Facility

Risk-Based Decommissioning of a Sulphur Storage Facility

[Paul R Orlowski]

India Fuels Gasoline and Diesel policy is here

http://transportpolicy.net/index.php?title=India:_Fuels:_Diesel_and_Gasoline

[Paul R Orlowski]

This is the EPAs SO2 home page
http://www.epa.gov/so2-pollution

[Paul R Orlowski]

William Minyard:
If you overfeed the Sb passivator, you could potentially cause fouling in the MF bottoms. As long as you control the dosage this shouldn’t be a problem.

Alvin Lee:
Just curious. Whose RFCC technology is this?

Alan English:
As Bill said, fouling in the bottoms circuit is usually only seen when excess antimony is injected. The correct dosage of antimony is specific to each unit. Antimony is only stable if it reacts with nickel or vanadium on the catalyst. Excess antimony will not stick to the catalyst, but instead will concentrate in the bottoms product. The amount of antimony that will remain stable ranges from 20% to 80% of the nickel on catalyst and varies with catalyst type, regenerator conditions, Ni/V ratio, metals deposition rate and presence of metals traps. Generally, refiners should control the antimony injection rate to be no more than 20% above the stable amount. In other words, if your deposition efficiency is less than 80% you should reduce additions. You mention adding fines that already contain antimony. Presumably, this antimony is on the fines because it has been stabilized by the nickel and vanadium on the fines and should therefore not give any problems in the bottoms circuit.

Stuart Foskett:
According to a former colleague of mine well versed on the subject, the laydown efficiency for various forms of antimony are not equal. Much better laydown efficiency is obtained with hydrocarbon-based antimony solutions, compared to the more common water-based colloidal suspensions. It is important to accurately monitor how much passivator is being injected, and calculate how much is actually staying on the catalyst, how much is lost with fines and catalyst withdrawals, and how much is unaccounted for. Laydown efficiency in the region of 50-75% is not uncommon.
I am assuming that there is a reason to suspect Sb as the cause for fouling (a chemical analysis of a coke deposit for example), but some amount of Sb in the bottoms circuit is to be expected and one should be cautious not to exclude other likely causes of slurry circuit fouling/coking.

Hee Jung Jeon:
I have also similar experience in the past though it could be different with this case. With the security policy, I cannot share the story in detail so I want to ask the understanding on vague description.
To reduce the amounts of off-gas, excess Sb was introduced for several months in RFCC. After that, the problem of catalyst carryover was happened caused by the deposit in dipleg. So we should have to check the Sb effect as one of the main reasons of catalyst carryover.
With analysis of deposits, we could find that the average Sb contents in deposit surprisingly was about 10 vol%(over 30 wt%) and Sb was existed with the form of metal particle or layer in mixing with lump coke and catalyst. We couldn’t find any clue about filament coke or linkage with adjacent coke on surface of Sb metal.
So we concluded and reported that excess Sb seems to be that it doesn’t act as the catalyst for directly making catalytic coke by dehydration/olefin oligomerization reaction but it affects fouling in RFCC units by making deposit that could interrupt smooth flow of catalyst.
This problem has no longer been occuring after using the proper dosage of Sb and cleaning the deposit in unit at regular maintenance.

[Paul R Orlowski]

It is OK/safe to proceed with the FCCU Rx Outlet Temp (ROT) test run.
The LCO quench is for yield optimization.
The LCO quench does not have any impact on the metallurgy or mechanical integrity.
From a metallurgy/integrity point-of-view, the Rx is good up to 1050F; but, let’s use 1025F just to err on the side of safety.

Also, the unit volume balance for your unit process conditions should be 110-112 vol%.
The 97+% wt. balance and the 107+% vol. balance suggests that either one or both of the LPG flow-meters C3 and C4 are off.
-comments by KP

[Paul R Orlowski]

ATC/NC coker cat: How many coke drums do you have? Extended period of time could mean you are on T/A or Heater Decoke or whatever? If coke drum is not being placed on standby mode or ready for changeover as in the case of T/A situation or Charge oil Heater Decoke, then it will be safer not to have the coke drum in warm-up mode. Your savings will depend on a specific plan scenario & operation scheduled activity. Please be specific in your query.

Coker Squirrel: We have two Coker Units, eight Drums total. We are not considering putting a Drum in warm-up early. We are only considering saving steam energy by not steam purging a Drum that has been headed up for several hours. Currently we are on 14 hour coking cycles but at times we still have several hours to spare before putting a Drum in warm-up. We currently put a minimal amount of steam into the Drum after heading up but we thought that we could conserve even on that. I have heard that there is a remote chance that a relief valve could leak back into the Drum which would cause a hazardous atmosphere in a headed up Drum. That is why we have a minimal steam purge in a headed up Drum until time to pressure test and go to warm-up. If we mitigate that remote chance of a leaking relief valve back into the empty Drum, is there any other hazard concerning a headed up Drum without a steam purge on it? Thank you, Mr. Cat. 

Coker Crazy: Can you give me the Coke Drum Cycle activities in times. I wonder how much you spare time for steam purging..in 14 hrs cycle? Do U have 3 drums in one block? Why Don’t you put spare drum in Vapor heating. What is the problem in puting drum in vapor heating…? It is better to heat drum before switch over to enhance coke drum life…
 
Coker Squirrel: We target a 1.5 hr warm-up. We also do a slow switch so Drum integrity does not suffer, 40 minute steam quench to Frac and Blowdown, and a 5 hour quench cycle. Usually, we don’t have a great deal of time to spare but at times we have a few hours before we need to go to warm-up. It is at these times that we are considering saving energy on steam purge. 

Sudhakar Bonthala @ril I have a few Q’s for you – Mr. Squirrel – 1.What is the age of your Coke drums -there are two ages -one is actual years in service -other is actual thermal cycles it is exposed to -pl. tell us both 2. Is the warm-up time 1.5 hrs from the beginning ? We now have 3.5 hrs warm up for the 16 hour filling cycle. At 14 hrs. we plan to go to 3 hrs warm-up. 3. Are your drums inspected by CII(lowering video cameras etc.)? What are the findings? Coming back to your original Q -There is one more hazard scenario. If your drum is full of coke and for any reason , you keep it headed while keeping the vent valves open – cold air from bottom will gush thru the coke bed -eventually making so much of CO + CO2. Believe me -this can turn the coke bed red hot, provided sufficient time is available. 

Four Drums on one coker were changed out in ‘2001 so they are now 3 yrs old. Four Drums on the other coker are 7 yrs old. CIA periodical checks them. Warm-up time has less of an impact on the metalurgy than the quench cycle. Strain gauging is a useful tool that will tell you this. Thanks for the info on leaving a Drum full of coke with the vent and drain open. The coke will dry out and could result in what you say. For that reason we normally will leave the drum full of water if it will be a while before drilling it. This rarely happens unless we have a maintenance problem of some sort. 

bruce kerr: Mr. Squirrel, I agree with Mr. Crazy you should head up the drum, air free, steam test and warm up as soon as you’re finished decoking.As far as the safety leaking back to the drum you should block the inlet to the safety and interlock it with the vent valve. The interlock should not allow to close the vent with the PSV inlet valve in the closed position. 

Coker Squirrel: Thanks for the feedback. We may consider going straight to warmup after steamout rather than waste steam. We were also looking into an interlock between the PSV’s isolation and the vent as an option. Is this what most are considering doing about the PSV’s? 
Jim Blevins, Chevron Texaco: Some good comments from the others on the question of leaving the drum headed up with the vent and drain open but no steam. Here are two other thoughts; if you leave it headed up you may find you build up some liquid in the bottom even with drain open so you may get some increased foam. Additionally you may find you leave oxygen in the drum which can cause polymers to build up in fractionator top trays and finfans. Be sure to purge the drum of all oxygen before starting the cycle.

Kaz Ganji: We have tried purging the drum with superhead steam instead of saturated steam in few refineries,which resulted in less amount of steam use with same period of purging time, surely purged all the oxygen out. Superheated steam does have more than 3 times the specific value than the saturated steam (lb/ft3). Also, it did help a little in heating the drum wall. A good news is that we are offering to use a new short warm-up line rather than the current warm-up line(i.e.less than 100 ft of warm-up line, instead of more than 300 ft). Warm up time will be 30 minutes, for purging with super heated steam followed by 60 minutes of hot vapor. The vapor temperature at the top of empty drum will be more than 800 F and at almost same pressure of the live drum). Future purgin and warm up time will be one and half hour instead of 4-6 hours. Temperature will be much hotter prior to switching the drum and in a shorter time.

Coker Squirrel: Thanks Kaz. I remember many discussions with you back when you worked at our Refinery. One such discussion concerned Drum warm-up and the possibility of making a shorter route. Good information on using super-heated steam for purge but it should have some saturation to help in heat transfer on the Drum wall. Thanks for the information. 

bruce kerr: The interlock system we did at Exxon/Mobil Baton Rouge has this interlock and also BP in Toledo.

[Paul R Orlowski]

The code specifies an inert gas system. Nitrogen sounds like the obvious choice because it eliminates the oxidizing agent – oxygen.

But iron sulfide (FeS) is created in the absence of oxygen – anaerobic conditions – which would be found in unvented tanks or tanks swept with nitrogen. The iron sulfide is fine in the “dormant” state when covered, but when tanks are opened to atmosphere it can spontaneously catch on fire (it’s pyrophoric). Since sulfur is also combustible, there is potential risk.

So you weigh the risk factor when using nitrogen. Do the benefits offset the safety issues caused by the formation of the pyrophoric iron sulfide.

Would anyone care to share experience when using nitrogen or other gas?

-Paul

[Paul R Orlowski]

I have to agree with Huzefa – use the larger number. In re-reading the code, I would go even farther. The code refers to “volume” without making any clarification on vapor volume or total pit volume. Without that clarification, the only reasonable approach is to use the volume of the pit, not the volume of the vapor space.

Martin Taylor
Sulfur Technologist at Bechtel Hydrocarbon Technology Solutions, Inc.
Houston, Texas

[Paul R Orlowski]

Reducing the operating liquid level in a sulphur pit or a tank should NOT affect the already designed snuffing steam system. Because in most cases, the amount of snuffing steam would have been calculated based on entire enclosure volume (empty tank or pit). This would be resulting in a higher steam flow. The idea for considering such a high steam flow is only to develop a positive pressure (lesser than 2.5 psi-g in case of API 650 tanks) in the enclosure in order to prevent the outside air entering inside and extinguishing the fire. If in case, snuffing steam flow was calculated based on HLL or HHLL (wrong approach!!), then reducing the operating liquid level – or increasing vapor space – can reduce the degree of pressure which is to be developed in case of fire. And if the inside pressure drops and equals the atmospheric pressure, then the purpose of having snuffing steam would be defeated.

Huzefa Dhinda
Process Consultant at UniverSUL Consulting
United Arab Emirates

[Paul R Orlowski]

In case of operating level changed from higher to lower, the free space volume will increase. Does it full fill the requirements of NFPA655, since it is already calculated.

Pronab Mistry

[Paul R Orlowski]

I would like to contribute by one example applied in one of the companies I worked for. They based their calculations using the minimum operating level of the pit.

Edward Vera
Sr. Process Engineer Al Hosn Gas
United Arab Emirates

[Author]

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