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OIL  REFINING  PROCESSES Advanced  course Assoc.Prof.  Pham  Huyen [email protected]

References • Chang  Samuel  Hsu  and  Paul  R.  Robinson,  Practical  Advances  in   Petroleum  Processing,  Vol 1,  Springer,  2006 • Mohamed  A.  Fahim,  Taher A.  Alsahhaf and  Amal Elkilani,   Fundamentals  of  Petroleum  Refining,  Elsevier,  2010

Outline Unit  1.  Introduction Unit  2.  Refinery  Feedstocks and  Products Unit  3.  Modern  Petroleum  Processing   Unit  4.  Auxiliary  Processes  &  Utilities  

Unit  1.  Introduction Largest  Worldwide   Refineries Approximately 650  Refineries   in the  world

Source:   Oil  &  Gas  Journal

Unit  1.  Introduction • High   sulfur,  heavy  crude  is  lowest   cost.   àRequires   extremely  complex   refinery  to  convert  into  high  value   products. • Low  sulfur,  light  crude  is  highest  cost.     à Simple  refining  yields  high  value   products. • a  function  of  location   of  crude  supply   versus  refining  centers. à Refiners  close  to  crude  production   enjoy  advantage   over  refineries   distant  from   supply

Unit  1.  Introduction

Unit  1.  Introduction

Note:  product  blending  and  sulfur   recovery  units  are  not  shown,  but   these  are  almost  always  present

Unit  1.  Introduction • DQR  Introduction • NSRP  Introduction

Unit  2.  Refinery   Feedstocks and  Products 2.1.  Composition  of  Crude  Oils 2.2.  Products  Composition 2.3.  Physical  Property  Characterization  Data 2.4.  Chemical  Analysis  Data

2.1.  Composition   of  Crude  Oils Impurities  (sulphur,   nitrogen,  oxygen   and  metals): -­‐ low  concentrations -­‐ undesirable -­‐ affect  the  quality  of  the  produced   products -­‐ Catalyst  poisoning   and  corrosion  

2.1.  Composition   of  Crude  Oils Hydrogen  to  carbon  ratios  affect  the  physical  properties  of  crude  oil.   -­‐ As the hydrogen to carbon ratio decreases, the gravity and boiling point of the hydrocarbon compounds increases. -­‐ the  higher  the  hydrogen  to  carbon  ratio  of  the  feedstock,  the  higher  its   value  is  to  a  refinery  because  less  hydrogen  is  required.

2.1.  Composition   of  Crude  Oils

2.1.  Composition   of  Crude  Oils Hydrocarbons: -­‐ Paraffins -­‐ Olefins are  not  naturally   present  in  crude  oils   but  they  are  formed  during   the  conversion   processes -­‐ Naphthenes (cycloalkanes):   Mutli-­‐ring   naphthenes are  present  in  the  heavier   parts  of  the  crude  oil -­‐ Aromatics Polynuclear aromatic  compounds  are  found  in   the  heavy  petroleum   cuts à cause  catalyst  deactivation   and  coke   deposition   during   processing à environmental   problems  

2.1.  Composition   of  Crude  Oils

2.1.  Composition   of  Crude  Oils -­‐ Sulphur Compounds

• varies  from  less  than  0.05  to  more  than  10   wt%  (but  generally   falls  in  the  range  1–4   wt%).   • Crude  oil  with  less  than  1  wt%  sulphur is   referred  to  as  low  sulphur or  sweet,  and   that  with  more  than  1  wt%  sulphur is   referred  to  as  high  sulphur or  sour. • Sulphur heteroatoms • inorganic   forms:  elemental  sulphur S,   dissolved   hydrogen  sulphide   H2S,   carbonyl  sulphide   COS • organic  forms:  mercaptans and   sulphides,   Sulphides and   disulphides,   Thiophenes

2.1.  Composition   of  Crude  Oils -­‐ Oxygen  Compounds • less  than  2  wt%.   • include   alcohols,   ethers,  carboxylic   acids,   phenolic   compounds,   ketones,  esters  and   anhydrides.   • causes  the  crude  to  be  acidic  with   consequent  processing   problems  such  as   corrosion.

2.1.  Composition   of  Crude  Oils -­‐ Nitrogen  Compounds

• Crude  oils  contain  very  low  amounts  of   nitrogen  compounds.   • the  more  asphaltic   the  oil,  the  higher  its   nitrogen  content.   • more  stable  than  sulphur compounds   à harder   to  remove.   • be  responsible   for  the  poisoning   of  a  cracking   catalyst,  and  contribute  to  gum  formation   in   finished   products. • The  nitrogen   compounds   in  crude  oils  may  be   classified  as  basic  or  non-­‐basic.   • Basic  nitrogen  compounds:  pyridines. • Non-­‐basic  nitrogen  compounds:  pyrrole types.

2.1.  Composition   of  Crude  Oils -­‐ Metallic  Compounds • • • • • • • •

exist  in  all   crude  oil  types   in  very  small  amounts cause  operational  problems  and  contaminate  the  products,  affect  upgrading  processes cause  poisoning  to  the  catalysts used  for  hydroprocessing and  cracking.   small  amounts  of  metals  (iron,  nickel  and  vanadium)  in  the  feedstock   to  the  catalytic  cracker  affect   the  activity   of  the  catalyst  à increased  gas  and  coke   formation  and  reduced  gasoline  yields. For  high-­‐temperature  power  generators,  the  presence  of  vanadium  in  the  fuel  may  lead  to  ash   deposits on  turbine  blades  and  cause  severe  corrosion,  and  the  deterioration of  refractory  furnace   linings. inorganic  water-­‐soluble  salts,  mainly  as  chlorides  and  sulphates of  sodium,  potassium,  magnesium   and  calcium  à removed  in  desalting  operations.   oil-­‐soluble  organometallic  compounds:  Zinc,  titanium,  calcium  and  magnesium  appear  in  the  form   of  organometallic  soaps. oil-­‐soluble  compounds:  vanadium,  nickel,  copper  and  iron  àcomplexing with  pyrrole compounds.

2.1.  Composition   of  Crude  Oils -­‐ Asphaltenes: -­‐ condensed   polynuclear aromatic  layers  linked   by  saturated  links,   -­‐ lead  to  coke  formation  and   metal  deposition   on  the  catalyst  surface  causing  catalyst   deactivation. -­‐ Resins   -­‐ polar   molecules  in  the  molecular   weight  range  of  500–1000, -­‐ insoluble   in  liquid   propane   but  soluble   in  n-­‐heptane.   -­‐ responsible   for  dissolving   and  stabilizing   the  solid  asphaltene molecules   in  petroleum.   The  resin  molecules   surround   the  asphaltene clusters  (micelles)  and   suspend  them  in   liquid   oil.  Because  each  asphaltene is  surrounded   by  a  number  of  resin  molecules,  the   content  of  resins  in  crude  oils  is  higher  than  that  of  the  asphaltenes.

2.2.  Products  Composition -­‐ Liquefied   Petroleum  Gas  (LPG) -­‐ Gasoline -­‐ Kerosene -­‐ Jet  Fuel -­‐ Diesel  Fuel -­‐ Fuel  Oil  (Residual  Fuel  Oil) -­‐ Lube  Oil -­‐ Asphalt -­‐ Petroleum  Coke

2.2.  Products  Composition

2.2.  Products  Composition

2.2.  Products  Composition

2.2.  Products  Composition Major  quality  aspects  of  main  petroleum  products  

2.2.  Products  Composition

2.3.  Physical  Property  Characterization  Data 2.3.1.  Fractionation

2.3.10.  Aniline   Point

2.3.2.  True  Boiling   Point  Distillation

2.3.11.  Flash  Point

2.3.3.  ASTM  Distillation

2.3.12.  Octane  Number

2.3.4.  Simulated   Distillation   by  Gas   Chromatography

2.3.13.  Cetane Number 2.3.14.  Smoke  Point

2.3.5.  API  Gravity 2.3.6.  Pour  Point 2.3.7.  Viscosity 2.3.8.  Refractive  Index 2.3.9.  Freezing  Point

2.3.15.  Reid  Vapour Pressure 2.3.16.  Water,  Salt  and  Sediment 2.3.17.  Molecular   Weight

2.4.  Chemical  Analysis  Data 2.4.1.  Elemental  Analysis 2.4.2.  Carbon   Residue 2.4.3.  Detailed   Hydrocarbon   Analysis 2.4.4.  Hydrocarbon   Family   Analysis 2.4.5.  Aromatic  Carbon  Content 2.4.6.  SARA  Analysis

ASTM  testing  grid  for  crude  oil  and  petroleum  fractions

Unit  3.  Modern  Petroleum  Processing  

Unit  3.  Modern  Petroleum  Processing   3.1.  SEPARATION   3.1.1.  Distillation 3.1.2.  Solvent  Refining 3.2.  CONVERSION   3.2.1.  Thermal  cracking 3.2.2.  FCC 3.2.3.  Hydrotreating and  hydrocracking 3.3.  UPGRADING  NAPHTHA   3.3.1.  Catalytic  Reforming   3.3.2.  Isomerization   3.3.3.  Catalytic  Oligomerization 3.3.4.  Alkylation  

3.1.1.   Distillation • the  biggest  unit  in  most  plants • Many  downstream  conversion   units  also  use  distillation  for   production  separation • To  reduce  corrosion,  plugging,   and  fouling  in  crude  heaters   and  towers,  and  to  prevent   the  poisoning  of  catalysts  in   downstream  units,  these   contaminants  are  removed  by   a  process  called  desalting

3.1.1.   Distillation

Atmospheric  distillation • At  the  bottom  of  the  stripping   section,  steam  is  injected  into  the   column   • to  strip  the  atmospheric  residue  of   any  light  hydrocarbon  and   • To  lower  the  partial  pressure  of  the   hydrocarbon  vapours in  the  flash   zone.   àlowering  the  boiling  point  of  the   hydrocarbons   àcausing  more  hydrocarbons  to  boil   and  go  up  the  column  to  be   eventually  condensed  and  withdrawn   as  side  streams.  

Vacuum  Distillation   -­‐ residue  from  an  atmospheric   distillation  tower -­‐ The  vacuum,  which  is  created  by  a   vacuum  pump  or  steam  ejector,  is   pulled  from  the  top  of  the  tower. -­‐ vacuum  columns  have  larger   diameters  and  their  internals  are   simpler  (random  packing  and   demister  pads  are  used) -­‐ The  overhead  stream  à lube   base  stock,  heavy  fuel  oil,  or  as   feed  to  a  conversion  unit -­‐ The  vacuum  residue  à asphalt,  or   feedstock  for  coker or  visbreaker unit

3.1.2.   Solvent  Refining a. Solvent  Deasphalting b. Solvent  Extraction   c. Solvent  Dewaxing,  Wax  Deoiling

a. Solvent  Deasphalting (SDA)   • Solvent  deasphalting takes  advantage  of  the  fact   that  aromatic  compounds  are  insoluble  in   paraffins.   • Propane  deasphalting is  commonly  used  to   precipitate  asphaltenes from  residual  oils.   • Deasphalted oil  (DAO)  is  sent  to  hydrotreaters,   FCC  units,  hydrocrackers,  or  fuel-­‐oil  blending.  In   hydrocrackers  and  FCC  units,  DAO  is  easier  to   process  than  straight-­‐run  residual  oils.  This  is   because  asphaltenes easily  form  coke  and  often   contain  catalyst  poisons  such  as  nickel  and   vanadium,  and  the  asphaltene content  of  DAO  is   (by  definition)  almost  zero.  

a. Solvent  Deasphalting (SDA)   • An  advanced  version  of  solvent  deasphalting is  “residuum  oil  supercritical   extraction,”  or  ROSE.   • In  this  process,  the  oil  and  solvent  are  mixed  and  heated  to  above  the   critical  temperature  of  the  solvent,  where  the  oil  is  almost  totally  insoluble • Advantages  include  higher  recovery  of  deasphalted liquids,  lower  operating   costs  due  to  improved  solvent  recovery,  and  improved  energy  efficiency. • The  ROSE  process  can  employ  three  different  solvents, -­‐ Propane:    Preparation  of  lube  base  stocks -­‐ Butane  :    Asphalt  production -­‐ Pentane:    Maximum  recovery  of  liquid

Schematic  of   the  ROSE   process

Refinery  with  solvent  deasphalting,  Rose-­‐residue  oil  supercritical  extraction  unit

b.  Solvent   Extraction   • to  remove  aromatics  and  other   impurities  from  lube  and  grease   stocks. • The  solvent  is  separated  from  the   product  stream  by  heating,   evaporation,  or  fractionation. • Remaining  traces  of  solvent  are   removed  from  the  raffinate by   steam  stripping  or  flashing. • NMP,  phenol,  furfural,  and  cresylic   acid  are  widely  used  as  solvents.

c.  Solvent  Dewaxing,  Wax  Deoiling • Solvent  dewaxing removes  wax  (normal  paraffins)  from  deasphalted lube   base  stocks. • The  main  process  steps  include  mixing  the  feedstock  with  the  solvent,   chilling  the  mixture  to  crystallize  wax,  and  recovering  the  solvent. • Commonly  used  solvents  include  toluene  and  methyl  ethyl  ketone  (MEK). • Methyl  isobutyl  ketone  (MIBK)  is  used  in  a  wax  deoiling process  to  prepare   food-­‐grade  wax.  

Unit  3.  Modern  Petroleum  Processing   3.1.  SEPARATION   3.1.1.  Distillation 3.1.2.  Solvent  Refining 3.2.  CONVERSION   3.2.1.  Thermal  cracking 3.2.2.  FCC 3.2.3.  Hydrotreating and  hydrocracking 3.3.  UPGRADING  NAPHTHA   3.3.1.  Catalytic  Reforming   3.3.2.  Isomerization   3.3.3.  Catalytic  Oligomerization 3.3.4.  Alkylation  

3.2.1.   Thermal  cracking   • Visbreaking • Delayed  Coking   • Fluid  Coking  

3.2.1.   Thermal  cracking   Visbreaking • Feed:  AR  or  VR • Mild  heating  471–493  C   (880–920   F)  at  50–200  psig • Reduce  viscosity  of  fuel  oil • Low  conversion  (10%)  at   221oC  (430F) • Heated  coil  or  soaking   drum • Products:  gases,  naphtha,   gas  oil,  reridue or  tar

Delayed  coking • Feed:  VR,  FCC  slurry,   visbreaking tar • Moderate  heating  482–516oC   (900–960F)   at  90  psig • Soak  drums  452–482oC  (845– 900F)

Fluid  coking  and  flexicoking • Feed:  VR • Severe  heating  482–566oC   (900–1050F)   at  10  psig • Fluidized  bed  with  steam • Higher  yields  of  light  ends

• Less  coke  yield  (20%  for   • Residence  time:  until  they  are   fluid  coking  and  2%  for   full  of  coke flexicoking) • Coke  is  removed  hydraulically • Products:  gas,  naphtha,   • Coke  yield    30  wt%,   unsaturated  gases,  LN,  HN,   LCO,  HCO

LCO,  HCO,  coke

Visbreaking

(A) Coil type visbreaker. • •

more stable visbreaker products more  flexible  and  allows  the  production  of   heavy  cuts,  boiling  in  the  vacuum  gas  oil  range

(B) Soaker type visbreaker • less  capital  investment,   • consumes  less  fuel • longer  on-­‐stream  times

Delayed  coking

3.2.2.   Fluid  Catalytic  Cracking   • A  typical  FCC  unit  comprises  three  major  sections   • riser/reactor, • Regenerator • fractionation.

• Purpose • Convert  heavy  oils  into  gasoline  and/or  light  olefins

• Licensors • Axens (IFP)   • KBR   • UOP

ExxonMobil   Stone  &  Webster

3.2.2.   Fluid  Catalytic  Cracking   • Catalysts  and  Additives • • • • •

Zeolite  (highly  acidic,  catalyzes  cracking)   Rare-­‐earth  oxide  (increases  catalyst  stability) ZSM-­‐5  (increases  octane  and  production  of  light  olefins) Pt (promotes  combustion  of  CO  to  CO  in  regenerator) Desox (transfers  SOx from  regenerator  to  riser/reactor)  .

• Feeds • Atmospheric  gas  oil   • Coker  gas  oil   • Lube  extracts  

Vacuum  gas  oil Deasphalted oil Vacuum  resid (up  to  20  vol%)  

3.2.2.   Fluid  Catalytic  Cracking   • Typical  Feed  Properties • • • •

Nitrogen   Carbon  residue   Nickel  +  Vanadium   90%  boiling  point  

<3000  wppm <5.0  wt% <50  wppm <1300°F  (704°C)

• Typical  Process  Conditions • • • • •

Feed  temperature   Reactor  temperature   Regenerator  temperature Catalyst/Oil  ratio   Reactor  pressure  

300  – 700°F  (150  – 370°C) 920  – 1020°F  (493  – 550°C) 1200  – 1350°F  (650  – 732°C) 4.0  – 10.0 10  – 35  psig  (170  – 343  kPa)

3.2.2.   Fluid  Catalytic  Cracking   • Typical  Product  Yields • • • • • • • • •

Conversion   H2,  H2S,  methane,  ethane   Propane  and  propylene   Butanes  and  butenes Gasoline   LCO   Slurry  oil   Coke   Total  C3-­‐ plus  

70  – 84  vol% 3.0  – 3.5  wt% 4.5  – 6.5  wt% 9.0  – 12.0  wt% 44  – 56  wt%   13  – 20  wt%   4  – 12  wt% 5  – 6  wt% 106  – 112  vol%

3.2.3.   Hydrotreating and  hydrocacking

LGO = Light Gas Oil HCO = FCC Heavy Cycle Oil

HGO = heavy Gas Oil VGO = Vacuum Gas Oil

LCO = FCC Light Cycle Oil VBGO = Visbreaker Gas Oil

CGO = Coker Gas Oil

3.2.3.   Hydrotreating and  hydrocacking

3.2.3.   Hydrotreating and  hydrocacking

Role  of  hydrotreating (HT)  in  the  refinery 1.  Meeting  finished  product  specification. • Kerosene,  gas  oil  and  lube  oil   desulphurization. • Olefin  saturation  for  stability   improvement. • Nitrogen  removal. • De-­‐aromatization  for  kerosene  to   improve  cetane number,   2.  Feed  preparation  for  downstream   units: • Naphtha  is  hydrotreated for  removal  of   metal  and  sulphur. • Sulphur,  metal,  polyaromatics and   Conradson carbon  removal  from   vacuum  gas  oil  (VGO)  to  be  used  as  FCC   feed. • Pretreatment  of  hydrocracking  feed  to   reduce  sulphur,  nitrogen  and   aromatics.

Naphtha hydrotreating unit

Diesel fuel hydrotreating unit

Atmosphere residue desulphurization process

3.2.3.   Hydrotreating and  hydrocacking

3.2.3.   Hydrotreating and  hydrocacking

Unit  3.  Modern  Petroleum  Processing   3.1.  SEPARATION   3.1.1.  Distillation 3.1.2.  Solvent  Refining 3.2.  CONVERSION   3.2.1.  Thermal  cracking 3.2.2.  FCC 3.2.3.  Hydrotreating and  hydrocracking 3.3.  UPGRADING  NAPHTHA   3.3.1.  Catalytic  Reforming   3.3.2.  Isomerization   3.3.3.  Catalytic  Oligomerization 3.3.4.  Alkylation  

3.3.1.   Catalytic  Reforming

3.3.1.   Catalytic  Reforming  

3.3.2.   Isomerization  

3.3.2.   Isomerization  

Sơ đồ công nghệ Penex

Sơ đồ quá trình Penex kết hợp với Deisohexane

3.3.3.   Catalytic  Oligomerization ΔH  <  0

• Catalysts:   • Sulfuric  acid,  phosphoric  acid,  and  solid   phosphoric  acid  on  kieselguhr pellets  (SPA)   are  used  as  catalysts.   • The  SPA  catalyst  is   non-­‐corrosive,  so  it   can  be   used  in  less-­‐expensive   carbon-­‐steel   reactors.

• Temperatures:  300  to  450°F  (150  to  230°F)   • Pressures:  200  to  1,200  psig  (1480  to  8375  kPa).

3.3.3.   Catalytic  Oligomerization

UOP’s  indirect  Alkylation  (LnAlk)  process  

SPA:  solid   phosphoric   acid

3.3.4.   Alkylation    

(H2SO4,   HF)

3.3.4.   Alkylation     • • • •

Zeolite  catalyst Liquid  phase 50  – 90oC uncommercialized

Unit  4.  Auxiliary  Processes  &  Utilities     • Steam  Methane  Reformer  (hydrogen   production)   • Light  Ends  Recovery  Units   • Lube  Oil  Units   • Amine  Treater • Caustic  and  Merox Treaters • Sulfur  Recovery,  Tail  Gas  Treating,   NaHS Units   • Sour  Water  Strippers   • Water  Treating  (de-­‐ionization)   • Steam  Production  

Waste  Water  Processing   Relief  Systems  and  Flares   Plant  and  Instrument  Air   Flare  Gas  Recovery  Units   MSAT  Benzene  Reduction  Units   (similar  to  ISOM  unit)   • Nitrogen  Systems   • Electrical  Systems • • • • •

Energetic   issues  in   an  oil  refinery Energy by source in an oil refinery Other 7% Electricity 5% Natural gas 25% Petroleum coke 17%

• Refinery  gas  +  petroleum  coke  +  other  oil-­‐based   by-­‐products  accounts  for  65%  of  the  energy   sources  in  an  oil  refinery.

Refinery gas 46%

• 38%  of  the  energy  sources  in  an  oil  refinery  are   used  to  produce  non-­‐fuel  products  like  lubricant   oils,  wax,  asphalt,  and  petrochemical  feedstocks. • Oil  refineries  generate  large  amounts  of  electricity   on-­‐site.   • The  cost  of  energy  for  heat  and  power  accounts   for  c.a.  40%  of  the  operating  costs  in  a  refinery!!!

Energetic   issues  in   an  oil  refinery   [Worrell   2005]

Sulfur  Recovery • Purpose Converts  H2S  gas  into  elemental  sulfur,  “Claus”  Unit • 1/3  of  H2S  burned  in  Reaction  Furnace  to  produce  SO2 (sulfur  dioxide)     1.5  O2 +  H2S  àSO2 +  H2O • Zinc  Oxide  catalyst  beds  convert  SO2 and  H2S  into  elemental  sulfur  and   water     SO2 +  2H2S  à3S  +  2H2O • Sulfur  is  collected  in  pit  or  tank  and  trucked  /  railed.    Used  in  chemical   manufacture. • Process  is  about  96%  efficient,  so  Tail  Gas  Treating  (SCOT  Unit  or  other)   required  to  purify  off  gas

Steam  Production

• Purpose   Provide  steam  for  process  heating,  steam  stripping  in  distillation,  and  steam  turbine  drivers • Multiple  Boilers  at  various  steam  pressure  levels • Certain  Process  Units  are  net  producers  of  steam  from  waste  heat

Waste  Water  Treatment • Purpose   Remove  Oil,  Grease  and  other   contaminants  from  Refinery  Waste   Water  to  meet  discharge  permit   requirements • Many  processes  combined  to  meet   specific  refinery  waste  characteristics   and  discharge  requirements • Oil  removal  and  biological  treatment  are   1st step • Can  be  re-­‐used,  injected  underground   or  sent  to  waterrway

Waste  Water  Treatment

A  refinery   typically   uses   more  water   than  crude   oil!

Particulate  Emission  Control   • Wet  gas  scrubbing  (WGS)  is  very  efficient  (>90%)  for  removal  of   particulates  (4–10  mm)  from  the  FCC  regenerator  exit.  Cyclones  could   be  the  first  choice  clean-­‐up  device  for  particulates.   • Electrostatic  precipitators  (ESP)  employ  an  electrostatic  field  to  apply   a  charge  to  particulate  emissions  and  then  collect  them  on  grounded   metal  plates.  ESP  units  are  very  efficient  (99.8%)  for  removing  finer   (4–10  mm)  particulates  from  FCC  regenerator  gas.  

Treatment of FCCflue gases byWGS

Treatment of FCC flue gases by ESP

Exercise  1.  Calculating  Properties  Utilizing  UNISIM Software Process  simulators  are  used  to  characterize  crude  oil  and  determine  the   thermophysical properties  of  crude  oil  and  fractions.   UNISIM  simulator  can  be  utilized  in  defining  pseudo-­‐components  of  a  crude  oil,   given  its  crude  assay.  It  provides  the  option  of  selecting  the  thermodynamic  model   for  vapour–liquid  equilibrium  and  thermodynamic  properties  calculations.   It  is  recommended  to  use  Peng–Robinson  equation  of  state  to  model  hydrocarbon   and  petroleum  mixtures  in  UNISIM.  Detailed

Consider  the  following  crude  assay  which   has  API  =  29 à Use  UNISIM  to  divide  the  crude  into   10  pseudo-­‐components  and  calculate  all   cut  properties.  

Solution: • The  crude  assay  (vol%  versus  TBP)  is   entered  the  oil  environment  and  oil   manager  data  entry  of  UNISIM,  and  the   number  of  pseudo-­‐components  (10   cuts)  is  entered  in  the  Blend  calculation.   The  properties  calculated  by  UNISIM  are   listed  in  Table  .1.

Exercise  2:  Design  of  Crude  Distillation  Units  Using Process  Simulators The  simulation  or  design  of  the  distillation  columns  involves  dividing  the  crude  oil   into  pseudo-­‐components  (Exercise  1).  Then  a  thermodynamic  model  is  chosen  for   vapour liquid  equilibrium  and  thermodynamic  properties  calculations.  A  good   model  is  the  cubic  equations  of  state,  and  the  Peng–Robinson  equation  is  one  of   the  most  widely  used  models  for  hydrocarbon  and  petroleum  mixtures.   Next,  the  unit  operations  stage-­‐wise  or  ‘‘tray  to  tray’’  distillation  calculations  are   performed.  The  mass,  energy  balance  and  vapour liquid  equilibrium  relations  for   each  tray  are  written  and  solved  together,  subject  to  certain  specification  for  the   products.  Computer  simulation  programs  such  as  UNISIM  are  used  for  quick   simulation  of  CDU  units.

Perform  a  material  balance  for  a  CDU  using  UNISIM  for   100,000  BPCD  of  29  API  crude  with  the  following  assay. • The  crude  is   fed  to  a  pre-­‐flash  separator  operating  at   450  F  and  75  psia.  The  vapour from  this  separator   bypasses  the   crude  furnace  and  is  remixed  with  the  hot   (650F)  liquid  leaving  the  furnace.   • The  combined  stream  is   then  fed  to  the  distillation   column  (Figure  1).  The  column  operates  with  a  total   condenser,  three  side   strippers  and  three  pumparounds (Figure  2).

Figure   1

Figure   2

Solution: In  the  oil  environment  and   oil  manager  data  entry  of  the  UNISIM  software,  the  crude  assay  is   entered  as  vol%  and  TBP.  The  yield  distribution   of  the  products  is  shown   in  Figure  3. The  distillation   column  has  three  inlet  steam  streams,  with  pressures  and  flow  rates  listed  in   Table  1.  The  main   distillation   column   contains  29  stages  (see  Figure  2).  The  overhead   condenser  operates  at  19.7  psia and   the  bottoms  at  32.7  psia.  The  side  stripper  connections   are  also  shown  in  Figure  2.

Figure   3.

Exercise  3:  Simulation  of  ARDS  Unit • A heavy residue stream that contains mostly n-­‐C30 (990 lb mol/h) and some amount of thiophene (10 lb mol/h) is prepared to enter an ARDS process to crack the heavy component n-­‐C30 to more lighter components such as n-­‐C20, n-­‐C10 and n-­‐C4. In addition, thiophenes should be completely removed. The feed stream is initially at 100F and 120 psia. This feed needs to be mixed with hydrogen stream (1250 lb mol/h) available at 150F and 200 psia. The mixed feed should be heated and compressed to 700F and 1500 psia before entering the reactor. The reactions are shown in Table. • The reactor products are cooled to 200F before entering a gas–liquid separator. 300 lb mol/h of the hydrogen coming from this separator is recycled back with the feed. The rest is vented to the atmosphere. The liquid stream coming out from the separator is then expanded by a valve to reduce the pressure to 250 psia. This makes it ready to enter a distillation column in order to separate the extra hydrogen left with the hydrocarbons. A typical flowsheet of the ARDS process is shown in Figure. Perform a material and energy balance for the ARDS process using UNISIM simulator.

Solution: 1.  Enter  the   simulation  basis   environment  in  UNISIM. 2.  Add  the  components  as  follows:  Thiophene,  n-­‐C30,  n-­‐C20,  n-­‐C10 ,  n-­‐C4,  H2  and  H2S. 3.  Select   Peng–Robinson  as  the   fluid  package. 4.  Insert  Reaction-­‐1  stoichiometry  and  conversion  and  do  the   same   for  Reaction-­‐2. 5.  Enter  simulation   environment. 6.  Insert  the   first  unit  for  the  oil   feed  as  shown  in  the   flow  chart  with  compositions,  temperature   and  pressure  as  given  in  Table  2. 7.  Continue  inserting   units  as   shown  in  the  flowsheet. 8.  The   reactor  is  a   conversion  reactor. 9.  The   distillation   column  is   15  trays  with  reflux  ratio  equal   to  1.0  and  full  reflux.  The   active   specification  to  run  the   distillation   column  is  a  hydrogen  recovery  of  100%  and  an  n-­‐decane recovery  of  90%. 10.  Finally,  add  the   recycle  control  unit  to  optimize  the   connections.

UNISIM  results

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