Question 56: How will the recently announced EPA requirement to depressure coke drums to below 2 Psig prior to venting to atmosphere regulations impact your coker operation and design?
John Metka (Foster Wheeler USA Corporation)
In order to meet the potential requirement of less than 2 psig prior to atmospheric venting, new units designed to operate at low coke drum pressure will require additional equipment such as an ejector system discharging to a condenser (potentially the blowdown or fractionator overhead condenser) to adequately reduce the coke drum pressure prior to atmospheric venting. Vent gas compressors utilized in higher pressure coke drum units that route the blowdown vent gas to the Wet Gas Compressor (enclosed blowdown system) will have to reflect the new requirements to ensure that the equipment is designed to be capable of reducing the coke drum pressure to the required level.
Existing low-pressure units may need to be revamped to include an ejector system installed on the coke drums or the Blowdown Settling Drum. Steam requirements, air-cooler condensing capacity and sour water capability will also need to be reviewed. Higher pressure units with vent gas or flare gas compression will require evaluation to determine equipment capability to achieve the lower pressure and subsequent modifications if deemed necessary.
Time taken to depressure the drums will have to be considered while setting total cycle time.
Question 58: What are you using for velocity medium in coker heaters? Are you using boiler feed water?
Jack Buckley (Foster Wheeler USA Corporation)
Foster Wheeler has used BFW as velocity media. Our order of preference for Velocity media is:
1.Steam
2.Condensate
3.BFW
If Condensate or BFW is used as velocity media or to clear the heater tubes during a heater trip, precautions must be taken as excess free water has the potential to overpressure the heater during a shut-in condition. The injection must also be stopped after a period of time after the heater trips because water will flow to the coke drums or back to the fractionator (coke drum by-passed) if the injection is continued too long.
Question 59: What is your experience processing a crude oil that has been treated with a pour point depressant and/or wax dispersant agent?
Dennis Haynes (NALCO Champion)
Some laboratory simulation experience has demonstrated that there were no adverse impacts to processing crude oil treated with a certain pour point depressant relative to oil-water separation for desalting. Due to these additives containing proprietary components, having differences between providers, and due to the potential of new variants being introduced to address increasing issues from Tight Oils, it is uncertain that past experience will equal future experience.
Question 57: If vacuum tower bottom feed to the Coker unit drops below unit minimum, what are your operating options available?
Srini Srivatsan (Foster Wheeler USA Corporation)
(Similar question answered by Srini in 2013 as a panelist)
Increasing amount of tight oil production with hardly any residual fraction will lead to challenges in filling up the Delayed Coking Unit (DCU). In order to maintain the DCU capacity, external purchase of HFO or VR will have to be made. If purchasing external feed is not an option and if you have multiple drums, you may have to shut a module down. The DCU could also be operated in turndown mode with or without high recycle.
FCC slurry oil, if available, could be sent to the DCU as feed. Since only a small portion of the FCC slurry / decant oil converts to coke, the remaining portion goes through the coker along with the rest of the cracked VR and mostly ends up with the HCGO. If the HCGO is sent directly to the FCC without hydrotreating, this may create a recycle stream that could become difficult to handle due to build-up of refractory type material. Hence, we typically limit this amount to approximately 10% of feed and depending on the limitations of the coking unit, you may have to cut back on vacuum residue (VR) feed rate.
Question 61: What measurement and/or predictive methods are you using to determine crude oil blend compatibility?
Dennis Haynes (NALCO Champion)
Various methods exist to determine blend compatibility; one method would be a comparative asphaltene instability point determination via an anti-solvent titration, or another method used is the Wiehe insolubility number to solubility blend number method. The methods available have a wide range of uses yet are not universally applicable to all crude blend scenarios.
Greg Savage (NALCO Champion)
The crude contaminants that cause fouling are frequently not identified in conventional crude assays. Some refiners observe that when two crudes are blended together, they will cause fouling and yet will not cause fouling when each crude is processed individually or blended with other crudes. Mixing a crude, or multiple crudes, containing asphaltenes with another crude can cause the asphaltenes to be destabilized and agglomerate to form solid foulant particles. This is caused by the second crude solvating the resins that were present to disperse the asphaltenes, leading to asphaltene agglomeration. Typically, this is observed when a heavy asphaltic crude is mixed with a more paraffinic crude. The proportions of each crude type and the order in which they are mixed also strongly determine the potential for asphaltene destabilization.
Resins in crude oil are bound to the large asphaltene structures and serve to keep them suspended and dispersed in the crude. The strength of the resin-asphaltene interaction decreases upon heating and the resins are removed from the asphaltenes. This allows the asphaltenes to agglomerate and form particles of foulant. The extent to which the asphaltenes are stabilized at higher temperatures depends upon the strength of the asphaltene-resin interaction. The more strongly the resins are bound to the asphaltenes, the less prone the asphaltenes are to agglomeration and fouling.
The NALCO Crude Stability Index (CSI) is used to determine the stability of fouling precursors in the crude (predominantly the asphaltenes) by titration with an aliphatic solvent. The ‘peak’ in the titration curve (the so-called ‘flocculation point’) is indicative of their stability. The amount of solvent added at the peak minimum is noted and converted to a ‘CSI Value’. This allows a direct comparison of crudes and refinery slates and indicates the fouling tendency due to asphaltene destabilization of the crude prior to refinery processing. The test is done on raw crude samples and can determine relative crude stability.
Additionally, the CSI can be used to measure intrinsic stability by testing two dilutions of the oil, low and high concentration, in toluene solvent. This method correlates very well with the Intrinsic Stability as determined by ASTM D7157 – 05.
Question 66: What desalter instrumentation issues do you experience when switching from a light gravity feed to a heavy gravity feed?
Chris Claesen (NALCO Champion)
The main influence is on level controllers, the most sensitive are the float type controllers but other instruments are also somewhat influenced by the crude Sulphur content.
Glenn Scattergood (NALCO Champion)
Increase in Amps, decrease in Voltage due to:
1.Heavy crude is more conductive, higher in metals content.
2.Heavy crude provides less naphtha used to preheat raw crude, desalter temperature is decreased, and dehydration efficiency may be decreased.
To determine which or both is occurring good monitoring of water in desalted crude along with chloride in both atmospheric and vacuum tower overheads is required.
Phil Thornthwait (NALCO Champion)
Float and differential level controllers are sensitive to changes in feed densities; operating in block modes between fuels and bitumen crudes for example can introduce difficulties in controlling the level. Heavier crudes also increase contaminants in the crude such as solids and metals and these can interfere with other types of level control. Also, these contaminants can influence the conductivity of crude, increasing amps and reducing volts.