Supporting Processes 1
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Transcript of Supporting Processes 1
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Supporting ProcessesSupporting Processes
CHE 735
Navid Omidbakhsh
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Supporting ProcessesSupporting Processes Not directly involved in the processing of petroleum
based fuels
Processes
Hydrogen production & purification Gas processing units
Acid gas treating
Sulfur recovery
Water treatment
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Hydrogen Production &Hydrogen Production &
PurificationPurification
Steam Reforming of methane
Most common method of manufacturing hydrogen, Methane, ethane, or heavy
components reformed to hydrogen, carbon dioxide, & water in a series of threereactions
Partial Oxidation of heavy hydrocarbons such as fuel oil
Steam Reforming produces hydrogen at a lower price if the price of methane isless than about 65% of fuel oil on a BTU basis. Therefore, it is widely used in
NA.
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Steam-Methane ReformingSteam-Methane Reforming Four process steps
Reforming. Endothermic catalytic reaction at 1400 1500F
CH4 + H2O CO + 3 H2 Shift conversion. Exothermic fixed-bed catalytic reaction at
650F
CO + H2O CO2 + H2 Gas Purification. Absorption of CO2 in amine or hot KCO3
solution.
Methanation. Exothermic fixed-bed catalytic reactions at 700 800F.
CO + 3 H2 CH4 + H2OCO2 + 4 H2 CH4 + 2 H2O
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Hydrogen production by Steam Reforming
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Partial Oxidation of Fuel OilsPartial Oxidation of Fuel Oils
Burning the fuel at high pressures (800 to 1300 psig) with an amount
of pure oxygen which is limited to that required to convert the fuel oil
to carbon monoxide and hydrogen.
2CnHm + nO2 2nCO + mH2
2nCO + 2nH2O 2nCO2 + 2nH2
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Gas Processing UnitsGas Processing Units Two primary functions
Recover C3+ components from the various gas streams
Crude distillation, cokers, FCCU, reformers, hydrocrackers,
Produce low sulfur, dry gas for use as fuel or hydrogen feedstock
Primarily methane & ethane
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Gas Processing Unit
D
eethanizer
S.A
De
butanizer
Nap
hthaSplitter
Depropinizer
Lean oilG.B.S
SpongeAbsorber
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Gas Processing UnitsGas Processing Units
Low Pressure (0-20Psig) gases are collectede and compressed to 200 Psig and are
fed to an absorber-deethanizer.
This column contains 20-24 trays in the absorption (top) and 16-20 trays in the
stripping section (bottom).
Lean absorption oil is fed to the top tray to absorb 85%-90% of the C3s and
almost all of the C4s and heavier components from the feed gas and from the
vapor rising from the stripping section. This lean oil is usually a dehexanized
naphtha.
Lighter hydrocarbons (such as C7) are vaporized from the lean oil and leave the
top of the column. They are recovered in the sponge absorber (8-12 trays).Sponge oil is a heavy non-volatile material like kerosine or #2 fuel oil.
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Gas Processing UnitsGas Processing Units
From the bottom of deethanizer, the rich oil is fed into debutanizer.
125-150Psig, 26 to 30 trays.
The bottom product from the debutanizer contains C5+ and is fed to
the naphtha splitter.
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Acid Gas RemovalAcid Gas Removal
What is Acid Gas?
Hydrogen Sulfide and carbon dioxide are generally termed acid gases.
Where they come from?Gases from various operations in a refinery processing sour crudes contain
hydrogen sulfide and occasionally carbonyl sulfide. This comes from
conversion of sulfur compounds in processes such as hydrotreating, cracking,
and coking.
Until 1970, it was common practice to simply burn this hydrogen sulfide along
with other gasses as refinery fuel, since its removal was not economical.
However, due to recent air pollution regulations, it now has to be removed
from refinery fuel gas, and converted to elemental sulfur.
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Acid Gas RemovalAcid Gas Removal ProcessesProcesses
Chemical solvent processes
Amine sweetening (MEA, DEA, MDEA, DGA)
Hot potassium carbonate
Physical solvent processes
Selexol
Propylene carbonate
Sulfinol
Rectisol
Dry absorbents
Molecular sieve Activated charcoal
Iron sponge
Zinc Oxide
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Absorber Fla
shTank
Sti
ll
Acid gases
Acid Gas Removal Process
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Sulfur RecoverySulfur Recovery
Until 1970, the major reason to recover sulfur from refinery gases was an
economic one. The hydrogen sulfide was commonly used with other
gases as a refinery fuel and the sulfur dioxide concentrations in the
flue gases were within acceptable limits. In those refineries with sulfurrecovery units, the typical recovery was about 90-93% of that
contained in the hydrogen sulfide stream. Implementation of federal
and state regulations now require recovery of at least 99% of the sulfur
in the refinery gas. This requires a two-stage process with a modified
Claus unit for the first stage followed by a second stage such as the
SCOTT process.
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Sulfur RecoverySulfur Recovery Most typically a modified Claus process
H2S rich stream burned with 1/3 stoichiometric air. Hot gasses passed
over alumina atalyst to produce free sulfur
Burner: 2 H2S + 3 O2 2 H2O + 2 SO2Reactor: 2 H2S + SO2 2 H2O + 3 S
Sulfur formation reaction mildly exothermic
Sulfur conversion reactors kept above 400F (sulfur dew point)
Carbon-sulfur compounds cannot be completely converted to elementalsulfur
Tail gas units containing titanium catalysts can be used (SCOT process)
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Claus sulfur process
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Carbon Sulfur CompoundsCarbon Sulfur Compounds
Carbonyl sulfide (COS) and carbon disulfide (CS2) cannot be converted
completely to elemental sulfur and carbon dioxide. These compounds may be
formed in the combustion step by reaction of hydrocarbons and carbon
dioxide:
CH4+SO2 CO2+H2O+H2
CO2+H2 COS+H2O
CH4+2S2 CS2+H2S
If they are not recovered, will increase in sulfur emission to the atmosphere.
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SCOT ProcessSCOT Process
Claus unit tail-gas is combined with small quantity of hydrogen or a
mixture of carbon monoxide and hydrogen and heated to about 480 to
570 F.
This hot gas flows through a fixed catalyst bed where various sulfurcompounds are converted into hydrogen sulfide by reaction with
hydrogen.
The reactor effluent is cooled to RT and the hydrogen sulfide is
selectively absorbed from the gas with an aqueous amine solvent.
The hydrogen sulfide is regenerated from the solvent in a conventionalamine still and recycled to the claus unit feed.
The exiting gas is incinerated to convert the remaining hydrogen
sulfide to sulfur dioxide before venting.
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SCOT Process
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Ecological Considerations inEcological Considerations in
Petroleum RefiningPetroleum Refining Refineries are required to minimize discharge of wastes into
surrounding environment.
The potentially harmful substances which must be carefully controlledinclude discharge of liquid hydrocarbon into streams, rivers, lakes, and
oceans, and relief of hydrocarbon vapors into the atmosphere.
Therefore, water treatment is a very important part of a refinery to
control emission of these pollutants to the environment.
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Waste Water TreatmentWaste Water Treatment Potential sources of waste water
Surface runoff Leaks, open drains, spills, rain
Crude & product storage tank water drains
Desalter water Water drains from atmospheric still reflux drums
Water drains from barometric sumps or accumulators on vacuum towerejectors
Water from hydraulic decoking of coke drums
Condensed steam form coke-drum purging operations
Product fractionator reflux drums on cat crackers, hydrotreaters,alkylation units, light ends recovery,
Cooling tower & boiler water blow down
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Waste Water TreatmentWaste Water Treatment Oil contaminated water skimmed in API separators
Large concrete sumps
Skimmed oil pumped to slop tanks & reprocessed
Some water used in desalters. Balance further purified
Flotation tanks
Mixture ferric hydroxide & aluminum hydroxide added to cause
impurities to coagulate
Froth further thickened & sludge incinerated
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Waste Water TreatmentWaste Water Treatment Digestion tanks
Water from Flotation Tanks oxygenated under pressure
May be mixed with sanitary sewage
Controlled amount of bacteria consumes remaining oil or phenolics
Bacteria continuously removed & incinerated
Final polishing in sand filters
Reused in refinery Further oxidized & discharged