[Mitchell Moloney]

ExxonMobil’s best practice is to use hard pipe connections for antifoam, but it is essential that the piping be properly designed for thermal expansion, especially as related to coker drum vertical growth and contraction as the coke drum cycles. Key points:

• Connections to piping or equipment (coke drum) should be gusseted to provide extra strength and support at the connection to keep small piping from breaking off
• Connections should also use integrally reinforced connections where possible – no pads
• Can design in “expansion loops” in short runs of pipe to provide flexibility
• Longer runs of small bore pipe tend to be inherently more flexible
• Can support small bore piping off of coke drums and/or larger piping (OH piping), and then provide “guides” vs supports on structure that doesn’t move – i.e. clamp to OH line and then let it float through the floor plate and just rest on guides below the deck. Guides allow it to move freely but still constrained within allowable limits – no overstress.
• Install wear pads where necessary. Since piping moves around quite a bit with coke drums, it can run on structural steel, supports, etc. We have seen wear on the walls of small bore piping that is really bad – almost had a hole through on one Cokers antifoam piping – wear pads help quite a bit.

A secondary option is to use braided hosing. However, an effective Inspection & Preventive Maintenance program must be in place, so that the hose is replaced as needed.
 
Best regards – Mitch Moloney

[Mitchell Moloney]

The complexity of both auto slide valves is essentially the same.  We (ExxonMobil) have completed testing of the Z&J valve at our Torrance Refinery, and are completely satisfied with its operation after almost 2 years of operation.  We have proved out its throttling capabilities and are very happy with its dual-seat design and low steam consumption, which should be very robust over the long haul.  We have also been operating Delta Valves for almost 6 months.  I recommend that you competitively bid  both valves and do a thorough evaluation relative to your installation and process needs.  If you want to talk more, call me at 703-846-5905.   Best regards – Mitch Moloney

[Mitchell Moloney]

We have recently installed hydraulically-operated swing back top head designs at our Baton Rouge and Beaumont Refineries.  The designs are similar and were provided by Bayside and Foster-Wheeler, respectively.  The designs are manually bolted but employ interlocked features which prevent inadvertent operation of the hydraulics and allow top head operations without exposure to an open top head.  The designs are not cheap and we have not done a detailed price comparison to slide valve designs.  Contact me for additional details.  Mitch Moloney

[Mitchell Moloney]

I believe that it is important to avoid the resid from being stagnant at over 900F.  Coke can form rapidly.  For that reason, I recommend having line purges on before the switch.  Better safe, than sorry. Valve purge block valves should all be open all the time.  Again it is important to verify that the steam piping arrangement is proper and that the line purge is not robbing from the valve seat purge.

[Mitchell Moloney]

Sticking of the valve is most likely due to inadequate steam purging of the valve. It is important to verify that your steam piping arrangement is proper and that you are not losing flow to the valve purges due to steam being used preferentially in another part of the process. 
 
You can install a blind to do work as long as the switch valve is holding and is deenergized and locked in place while the blind is being installed. 
 
Feed line spool flushing should start before moving the switch valve (3″ steam line is best)and should continue for 5 – 10 minutes, then shut the downstream isolation feed valve.  The amount of flow should be ~ 5klb/hr or more if the MF can handle it. 

[Mitchell Moloney]

There are three coking processes in use in the industry:
(1) Delayed Coking (DLK) – Process resid flows into the bottom of the Main Fractionator mixing with recycled heavy oil and is pumped through a furnace (900-940F) into a coke drum, which cycles with another sister coke drum (or, in rare instances, two sister coke drums) when the drum is deemed full of coke.  The product vapors are fractionated in Main Fractionator.  Coke removal is accomplished with a variety of equipment for steam stripping, quenching, coke drum head operations, coke cutting, drum heating.
(2) Fluid Coking (FBK, ExxonMobil licensed)- In this process the resid enters a fluid reactor (similar to a Gas Oil Fluid Cat Cracker) via injection nozzles located at various levels in the wall of the reactor.  The resid sprays on to small pellets of coke (similar to FCC catalyst in function, but larger in size); reactor temperature is 930 – 950F.  The cracked products are separated from the coke using cyclones (just like in the FCC).  The product vapors flow to a Scrubber vessel which removes heavy oils and recycles them (Analogous to the bottom the DLK Main Frac).  Vapors leave the Scrubber and enter a Main Fractionator.  Product processing is essentially identical to DLK coke is partially combusted in the burner vessel (analogous to the FCC regenerator) and returned to the reactor.  The combustion gases typically flow to a CO Boiler and are scrubbed (analogous to the FCC) or treated.
(3) Flexi Coking (FXK, ExxonMobil licensed) – This is basically a Fluid Coker with an additional vessel, the Gasifier, which completely combusts the coke to low-BTU gas (120 BTU/SCF).  The gas is treated in a special amine (Flexsorb) scrubber.  Typically the entire plant must be configured to burn the large amount of low-BTU gas generated.  The overall investment is high and best justified in locations with little natural gas available or very high gas prices.
 
Regards – Mitch Moloney ExxonMobil Resid Specialist

[Mitchell Moloney]

Marc –  We have used a hanging scaffold for top head inspection and repair at our Chalmetter Refinery.  I can send you that drawing. 
In the Fluid & Flexi Cokers, a number of units use an expandable scaffold referred to as a “swing stage”. It can expand in diameter and it is motorized so it can be automatically raised and lowered to gain access to the entire reactor. This has been used for a number of years at the Syncrude and Sarnia Fluid Cokers. The challenge will be the smaller access in Delayed Cokers – smaller manways to work from. It may be possible to enter with the core of a swing stage at the bottom head opening and then expand once the core is in the drum. Perhaps the swing stage can then be supported and motorized up and down from the top head to give full access to the entire drum and to allow work to be conducted, if needed.  I can send you a sketch of the concept.
Regards – Mitch

[Mitchell Moloney]

You can use sway breakers ……..
 

·         Cable can become wrapped around beans in high winds not allowing drill to go up or down.
 
·         Have new simple sway-breaker design from Jeremy Krauthammer at the Hovensa DCU.  He uses a rubber guide to hold cables in place, made from used conveyor belts.  These are placed at about three locations along the steel structure where the cables are located. 
 

I cannot post a sketch since I cannot get in to gif or jpg, and txt loses the sketch 
 
 
 
 
 
 

Cable passing through rubber guide
                                    Side View

Drill steel support beam

Rubber guide
 
 
 
 
 
 
 
 
 
 
 
 
·         Locate 3 or 4 @ different levels.
·         Problem can be alleviated are tightened and tensioned properly.
 

[Mitchell Moloney]

A risk analysis needs to be performed.  If the blowdown level is normally under control and not high, one would argue that simultaneous opening of the coke drum PRV and having a high level would constitute double jeopardy.  It is standard design practice to not design for double jeopardy.  In that case it is perfectly acceptable to have coke drum PRV’s lined up to the BD tower.  HOWEVER, if BD contactor level is unreliable and often high enough to impede a PRV release, causing pressure in the coke drum to rise over the allowed over pressure (10% for normal contingency, 21% fire, etc), then you need to mitigate the risk.  Changing PRV destination is an extreme option.  It probably makes sense to improve level reliability by installing a second independent level device, of a different design, to ensure reliability. For example, one type would be DP cell with tap blowbacks and the other could be a gamma device or a simple pressure gauge on the pump suction converted to level .
 
Regards – Mitch Moloney

[Mitchell Moloney]

We at ExxonMobil require neoprene suits if there is a risk of hot water exposure. It is uncomfortable in the summer, but it protects against burns for the short time that the deheading work must be done.

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