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

Supporting Processes 1

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