tha data provided by OP would classify the "kerosene" as a low vapour-pressure liquid.
in fact the difference between flash point (55.5°C) and max storage temperature (40°C) is 15.5°C, well above the 15°F / 8°C required.
in this case, the vapour released from a vent would not create a flammable...
in 30 years of refinery projects, I've seen kero stored in either fixed or floating tanks, but never blanketed with nitrogen.
by the way, OP is speaking of a "kero intermediate", without specifying its nature...
Bala,
I've performed several planning studies on this subject in the last 25 years.
There are other 3 options not mentioned up to now:
- residue hydrocracking;
- gasification / IGCC;
- asphalt production.
The optimal solution could not exist [sad] or (mainly) depend by:
- market conditions...
just to be clear: vanadium doe not exist in fuel gas!
but i'm ready to be denied, on the base of trusted documents...
vanadium could be present in flue gases generated by heavy (liquid or solid) fuels
kind regards
george,
it's the first time I read/hear of vanadium in fuel gas.
I know/use several process standards (exxon, shell, fw, eni, aramco, fluor, total....) but no one covers this topic (well known for heavy fuel oils).
regards
in my knowledge:
- HFO + gasoline: no clear relation with shale oil;
- ash is generated thru the combustion of fuel oil by the salts (mainly chlorides of Na, Mg, Ca....) and metals (organometallic compounds with Fe, V, Ni....) originally included in the oil. you can't filter them. salts, but not...
there is a high temperature limit (about 150°C) imposed by the resistance of teflon bushings.
moreover, temperatures impact densities and viscosities of the two phases.
each crude has an optimal desalting temperature: above that, the driving forces for the separation are penalized.
as far as i know of you, you should be already aware of them...but these are my 2 cents.
good luck!
https://www.amine-gas-treatment.com/amine-reclamation/mobile-unit/
frankly speaking the material you found is very poor, otherwise you would have already had the answers.
you can just start with wikipedia....
in principle, there is no difference between offshore and onshore gas.
anyway:
- pollutants: water, CO2, H2S, N2, mercaptans, He, Hg, heavy hydrocarbons
-...
there are thousands of refineries in MENA...and also several "critical" areas...
the well-designed refineries (as they are the exxon ones) have a hydrogen chain, where H2 streams rejected by more severe hydrotreatings are used as make-up in less severe HDTs. in this way the total H2 circulation...
@irstuff: thank you! better to know/hear/discuss personal advices of "experts" than googling :-)
@itsmoked: you're (partially) right but please consider this is the "chemical process engineering" forum. in our world, PFD is a well known / unique acronym :-)
This post wouldn't pass an examination at the university (at the high school, too) :-(
- SCF is referred to volume at Standard conditions
- Standard conditions are not univoque: they have to be specifically declared
- kg is referred to a mass
- you need a Molecular mass (or a gas density...
Thank you for the additional considerations.
I wouldn't like to bother anyone but... I have, again, a couple of questions: [smile]
a) You propose a helical gear pump instead of a lobe pump. Could you kindly discuss this preference?
b) The (very expert) operator was against the proposed rotary...
Thank you for your comment.
Between the surge drum and the pump there is a heat exchanger to cool down the TEG.
Moreover, the surge drum is elevated to take in consideration the effect of the dissolved hydrocarbons.
