[evan]

In my experience, if the flow to the flare is sufficient to be seen on a mass balance….. you have a big problem! DCU matbal are typically +/-3-5% with the best being 1-2%. If 1% of some flow is going to the flare, you should see it very clearly. What is the flow to the flare system right now, absolute and a % of feed rate?

Flare flows are typically too low relative to pipe diameter to have a reliable flow measurement.

[evan]

Interesting question. I have not seen flare KO pot reprocessing on the DCU before. Seems reasonable but yes, I would expect fouling to be concern. Many units used to reprocess their slops (BD mainly) directly in the fractionator but stopped due to fouling issues.

Flare releases are heavily scrutinized in some places like california. So great care is taken to understand all the sources. Downstream of the PSV or other sources, you can put sensitive TI/PI to indicate if someone is “in” the flare. Also, PSVs will start to leak at 90% of their setpoint so find all the equipment and processes who are near this limit.

[evan]

So far as I know, DMDS will break down at the fluid conditions in the heater, especially at the wall film temperatures. Do you have a TGA analysis on this material?

DMDS is used to breakdown in the H2S under reactor conditions to passivate the metal. In the DCU, we have lots of H2S around to achieve a similar goal. Metal catalyzed coking is relevent to heater fouling but it is just part of the process. Crarcking, mesophase seperation, ashphaltene instability, deposition on the tube ID, and eventual coke formation are also big contributors.

If anyone knows of research testing this out, I would love to see it…..

[evan]

http://refiningcommunity.local/forums/topic/coking-chemical-additives/#post-22471

[evan]

The conventional time to trigger a short run drum procedure varies around the industry but it is 4-6h as a general rule to ensure a reasonable bed of coke has been formed.

2nd question is very, very, very complicated. Things like position in cycle (start, middle, end), drum-in and out temperatures before the incident. Foaming and quenching problems are likely if not done properly…. proceed with caution. When in doubt, bypass and feed a new drum after lining out the heater.

[evan]

AF comes on 12.5k cSt all the way up to 1M cSt. Their are benefits and costs to each level in terms of effectiveness, cost, and Si carryover. It depends on your injection practices, feed foam tendency, and Si carryover + bed protection downstream to reach an optimism decision.

Other chemicals include blowdown demulsifiers, APS for ovhd corrosion, and various antifoulants for HX and heaters. There are other niche applications of chemicals but they are one off’s.

RE Cyanides, water wash is effective for piping but H2 blistering in the ovhd drum can persist and should be inspected for during TAR or online (diffusion testing).

[evan]

1 – all options you present have been installed in one way or another. But d/s of settler is the most common.
2 – WGC suction, Frac ovhd, and flare have all been done.
3 – Yes, the most common solution. The requirements for a seal pot are company and site specific. If the Flare has a KO pot and recovery compressor, it is possible to avoid the water seal in some instance.

[evan]

Murthy – no, not all downtime is heater related. In some sites, online spalling is the only decoking method between TAR so there is no downtime for those plants associated with the heater. It is all site specific.

RE HCGO uses…. one can increase unit recycle to try to convert more of the material. Only ~50% may react away from HCGO on the 2nd trip to the drum but it could help. You may also consider greatly increasing your wash oil rate to “clean up” the HCGO so the FCC can take a bit more. Lastly, sales as the other comments indicated.

[evan]

Hello

There are as many answers to this question as there are stars in the sky but a common list includes

+ Delay in cycle step causing temporary slow down
+ Decoking or coke handling equipment failure
+ Structure valve issues
+ Heater Fouling and subsequent decoking

RE cycle time reduction, the lowest cycle time I’m aware of was 9 hours between switches. There are many sites which operate on a 12 hour cycle while 16 hours is a typical design basis. It would be impossible to document all the scenarios of debottlenecking to achieve shorter cycle time but the obvious ones include:

+ Fractionator loading
+ Heater duty and fouling
+ Drum cycle step reduction
+ Compressor loading
+ Heat integration (preheat, P/A, cooling, etc)

[evan]

Tarry drums are a complicated question. First, we must clarify why it was a tarry drum…..
1. low heater COT for some time?
2. Low drum vapor (DOV) temp for some time?
3. Short run drum (<4h), never reached DOV temp

Second and possibly separately, what is the cause of the steam failure? Power failure or other? Are you able to get water into the drum without steam stripping?

All of these scenarios could be handled differently by its own separate procedure. Sorry, not the clearest answer but each scenario is different. We recommend you think through each scenario completely and have a plan.

[evan]

Yes, to increase recovery you can increase flow, decrease naphtha temperature, increase pressure of the column, or alter the tray efficiency. All may be possible but I can’t say which will be your limit without checking.

[evan]

Hello, a rule of thumb value of water wash is sometimes 1 gpm per 1kbd but this is a very general estimate. pH is something that should be measured to adjust the rate but I do not know the target value. I will share your post with someone and ask them to comment.

[evan]

Hello. without considering the number of theoretical stages in your gas plant and the pressure/temperature you are running, I can say, best in class is <2% loss of LPG into fuel gas but 3% is more "normal."

[evan]

Hello, Piyush – that is a very complicated question but let’s try to unpack it a bit….

+ Maintaining draw temperatures is typically done by adjusting pumparound (flow and TC around steam gen) and wash oil flow and reflux.
+ End point is a bit variable in measurement so lets talk about 95%Pt…. HCGO > 850F is getting pretty heavy and likely to cause issues downsteam. LCGO, it totaly depends on your tower configuration.
+ HCGO underpan temperatures >750F will likely cause coking but dead zones with temps >700F could also be a problem.
+ Fractionator layouts and configuration vary significantly across licensors. In fact product seperation and recovery if one of their key selling points.

What values are you seeing for the above information? Who licensed your coker?

[evan]

I do not know of a COS test for liquids but I was referring to measuring the Oxygen and Sulfur species in the liquid feed streams using FTIR and neutron activation.

[Author]

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