A Plant Design Project on Production of Gasoline by Sulphuric Acid Alkylation of Olefins

A Plant Design Project on Production of Gasoline by Sulphuric Acid Alkylation of Olefins

Session: 2010-2014 Project Advisors Prof. Dr. Syed Nadir Hussain Project Members Zain Ul Abidin

CE-M10-02

Ahmed Javed

PG-M10-03

Umar Draz

CE-M10-24

Ali Hasnain

CE-M10-47

Institute of Chemical Engineering and Technology UNIVERISITY OF THE PUNJAB LAHORE-PAKISTAN

STATEMENT BY THE AUTHORS We hereby declare that this submission is our own work and to the best of our knowledge, it contains no material previously published or written by another person, no material which to a substantial extent has been accepted for the award of our other degree or diploma at any educational institution, except where due acknowledgement is made in the thesis.

Signatures

Date

Approved by: Supervisor: Prof. Engr. Dr. Syed Nadir Hussain, Institute of Chemical Engineering & Technology, Faculty of Engineering & Technology, University of the Punjab.

Signature

Date

Director: Prof. Dr. Amir Ijaz, Institute of Chemical Engineering & Technology, Faculty of Engineering & Technology, University of the Punjab.

Signature

Date

DEDICATION To Almighty Allah; for His daily blessings, make all our work possible. To our Parents; who are full of sympathy and everlasting love. To Prof. Engr. Dr. Syed Nadir Hussain ; for his fatherly behavior and inspiring guidance. To our dearest homeland, Pakistan.

ABSTRACT Light Ends are the valuable products of a Petroleum refinery, their utilization as a refinery fuel is not an effective solution; considering economic, product slate and environmental factors. Alkylated Gasoline is one of the most promising additions to refinery's Gasoline pool, with its High Octane number and added advantages of Lower sulfur, Lower RVP, Lower Drivability Index, No Aromatic Contents. The new environmental regulations are forcing refineries to adapt new technologies to reduce the sulfur, aromatics contents while increasing the products quality and reducing emissions for Gasoline. There are number of ways by which these requirements can be met, and Alkylation is one of the best method that a refinery can adopt, not only to meet new environmental regulations, but also to increase the quality of Gasoline Pool by positively affecting the Refinery economic end because of the utilization of the light ends, that are converted to a more valuable Gasoline product. The installation of Alkylation unit is quite feasible, as considerable amount of Light ends can be obtained from petroleum refinery's number of processes, like FCCU, Plat-forming Unit, Coker, Thermal Cracking, Gasoline Stabilization Unit etc The Alkylated Gasoline can be produced using different patented processes available, depending on the type of catalyst or the technology offered by a specific company. The properties of the Gasoline produced using these processes depends on the type of feed available for the process, the relevant processes taking place in refineries from which light ends are obtained, the catalyst type used, the operating temperature & pressure conditions & several other factors. The H2SO4 Alkylation Process of Exxon Mobil with Auto-refrigeration technology is used; all the calculations of Material & Energy are performed with the designing of some important equipment as well. Consideration is given to related factors for the safety of the environment and people working and

residing

near

the

plant

area.

ACKNOWLEDGMENTS I have only the pearls of my eyes to admire the blessings of the Compassionate and Omnipotent because the words are bound, knowledge is limited and the time is short to express HIS dignity. We are immeasurably grateful to Almighty Allah, the Propitious, the Benevolent and Sovereign, who has endowed our brain and instable instinct contraction of knowledge and body to accomplish our work in the form of this dissertation, whose blessing and glory flourished our thoughts, thrived our ambitions, granted us talented teachers, affectionate parents, sweet sisters, loving brothers and exceptional friends. Trembling lips and wet eyes praise for The Last Prophet Hazrat Muhammad (PBUH) for enlightening our conscience with the essence of faith in ALMIGHT ALLAH, enabling us to recognize the Oneness of our creator, and showed us the right path for the success. Faithfulness in the performance of small duties gives us strength to adhere to difficult determinations that life will someday force us to make. "The ink of the scholar is more holy than the blood of the martyr."

The work presented in this thesis was accomplished under the sympathetic attitude, fatherly behavior, animate direction, observant pursuit, scholarly criticism, sheering perspective and enlightened supervision of Prof. Dr. Engr. Syed Nadir Hussain , Institute of chemical Engineering and Technology,

University of the Punjab for his thorough analysis and rigorous critique improved not only the quality of this thesis, but also our overall understanding. We are also very grateful to his ever inspiring guidance, keen interest, scholarly comments and constructive suggestions during the course of our studies. We appreciate his valuable comments and suggestions to make this work complete. We deem it our utmost pleasure in expressing our cordial gratitude with the strategic command at every step. His valuable suggestion will always serve as beacon of light throughout the course of our studies. We owe a great debt of gratitude to our worthy Director Prof. Dr. Amir Ijaz , for his kind, loving positive thoughtful criticism, keen personal interest, sincere

advice, vital instructions throughout the course of our studies besides his very busy schedule. We fervently extent my zealous thanks to him, also for creating a healthy & beautiful environment.

NOMENCLATURE SYMBOL V V

DESCRIPTION

UNIT

S E H Ad Ah An AT

volume of the reactor volume of catalyst Viscosity inside heat transfer coefficient shell side heat transfer coefficient overall heat transfer coefficient Density specific heat pressure drop Temperature Length outer diameter of tube inner dia ot tube dia of the particle dia of the dispersed phase terminal falling velocity mass velocity mass flow rate Heat gas constant number of tubes Reynolds number acceleration due to gravity Voidage total entrainment Enthalpy down comer area hole area net area total area

Ada

area under down comer apron

(m )

Df

flow width normal to liquid flow

(m)

D

diameter of tower

(m)

R

reflux ratio

R m

minimum reflux ratio

a

relative volatility

UOP

Universal Oil Products

HF

Hydrofluoric Acid

hi hs U P CP

AP T L Do Di D p Dd Ut G M q

R Nt Re g

m m Cp o W/m . C 2 o W/m . C o W/m . C kg/m kJ/kmol.K Bar °C M Mm Mm Mm um m/s kg/s.m kg/h Watt m .Pa/mol.°C m/s (kg/sec) (kJ/kgmol °C) (m ) (m ) 2 (m ) 2 (m ) 2

Table of Contents 1.1

WHAT IS GASOLINE? ................................................................................. 24

1.2

BACKGROUND & USES .............................................................................. 24

1.3

OCTANE RATING ....................................................................................... 25

1.4

PHYSICAL PROPERTIES OF GASOLINE ........................................................ 26

1.5

WHAT IS ALKYLATION? ............................................................................. 26

1.6

HISTORY OF ALKYLATION .......................................................................... 27

1.7

ALKYLATION FEEDSTOCKS......................................................................... 28

1.8

TYPES OF ALKYLATION PROCESSES ........................................................... 29

1.8.1

1.9

THERMAL ALKYLATION ........................................................................ 29

CATALYTIC ALKYLATION ............................................................................ 30

1.10 TYPES OF ACID CATALYSTS USED IN ALKYLATION ..................................... 30 1.10.1

SULPHURIC ACID ALKYLATION PROCESS .............................................. 30

1.10.2

HF ALKYLATION ................................................................................... 32

1.11 COMPARISON OF H2SO4 & HF ................................................................... 33 1.11.1

FEED AVAILABILITY AND PRODUCT REQUIREMENTS ........................... 34

1.11.2

SAFETY & ENVIRONMENTAL CONSIDERATIONS ................................... 34

1.11.3

OPERATING COSTS .............................................................................. 36

1.11.4

UTILITY COSTS ..................................................................................... 36

1.11.5

CATALYST AND CHEMICAL COSTS ........................................................ 37

1.11.6

CAPITAL INVESTMENT ......................................................................... 37

1.11.7

MAINTENANCE .................................................................................... 38

1.12 H2SO4 VS. HF SUMMARY ........................................................................... 38

2 CHAPTER # 2: ..................................................................................... 40 2.1

METHODS OF H2SO4 ALKYLATION MANUFACTURE ................................... 40

2.2

EFFLUENT REFRIGERATION ....................................................................... 40

2.2.1

2.3

CASCADE AUTOREFRIGERATION.......................................................... 41

PROCESS VARIABLES .......................................

42

2.3.1

REACTION TEMPERATURE ................................................................... 42

2.3.2

ACID STRENGTH .................................................................................. 42

2.3.3

ISOBUTANE CONCENTRATION ............................................................. 43

2.3.4

OLEFINS SPACE VELOCITY .................................................................... 43

2.4

ALKYLATION CHEMISTRY .......................................................................... 43

2.4.1

REACTION MECHANISM ...................................................................... 43

3 CHAPTER # 3: ..................................................................................... 46 3.1

CAPACITY & BASIS .................................................................................... 46

3.2

EQUATION OF MATERIAL BALANCE .......................................................... 46

3.3

REACTOR (R-101) ...................................................................................... 47

3.3.1

MATERIAL IN ....................................................................................... 47

3.3.2

REACTIONS .......................................................................................... 48

3.3.3

MATERIAL OUT .................................................................................... 49

3.4

PHASE SEPARATOR (PS-101) ..................................................................... 50

3.4.2

MATERIAL IN ....................................................................................... 50

3.4.3

MATERIAL OUT: ................................................................................... 51

3.5

DISTILLATION COLUMN (DC-101) ............................................................. 52

3.5.2

MATERIAL IN ....................................................................................... 52

3.5.3

MATERIAL OUT .................................................................................... 52

3.6

DISTILLATION COLUMN (DC-102) ............................................................. 54

3.6.2

MATERIAL IN ....................................................................................... 54

3.6.3

MATERIAL OUT .................................................................................... 55

3.7

BALANCE TO MIXING POINT ..................................................................... 55

4 CHAPTER # 4: ..................................................................................... 57 4.1

ENERGY BALANCE EQUATION ................................................................... 57

4.2

HEAT OF REACTIONS................................................................................. 57

4.2.1

At 298K ............................................................................................... 57

4.2.2

REACTION 1......................................................................................... 57

4.2.3

REACTION 2......................................................................................... 57

4.2.4

REACTION 3......................................................................................... 58

4.2.5

Heats of Formation Data: ∆H f (kJ/gmol): Vol. 6 .................................... 58

4.3

REACTOR (R-101) ...................................................................................... 59

4.3.1

Table 16: Stream 3+13: ....................................................................... 59

4.3.1.1

Table 17: Stream 4+14: ....................................................................... 60

4.3.2

Heat of Reaction Added At 298 K ........................................................ 60

4.3.3

Total Heat of Reaction: ........................................................................ 60

4.3.4

Latent Heat Required To Vaporize the Mixture ................................... 60

4.4

PHASE SEPARATOR (PS-101) ..................................................................... 61

4.5

ACROSS COMPRESSOR ............................................................................. 62

4.5.2

Balance ............................................................................................... 63

4.5.3

63

4.5.4

kJ ......................................................................................................... 63

4.6

ACROSS HEAT EXCHANGER HX-102 (CONDENSER) ................................... 63

4.6.2

Vapor Stream After Compression enters in cooler condenser: ............ 63

4.6.3

Balance: .............................................................................................. 63

4.7

ACROSS DE-PROPANIZER DC-102.............................................................. 64

4.8

ACROSS PUMP (STREAM 6)....................................................................... 65

Stream 6 in:............................................................................................................ 65 4.8.2

4.9

Table 25: Stream 6 out: ....................................................................... 65

ACROSS HEAT EXCHANGER HX-108 .......................................................... 66

Stream 6 in:............................................................................................................ 66 4.9.1.1

Table 27: Stream 6 out: ....................................................................... 66

4.10 ACROSS DE-ISOBUTANIZER DC-101 .......................................................... 67 4.10.1.1

Table 29: Stream 11: ........................................................................... 67

4.10.1.2

Table 30: Stream 7: ............................................................................. 67

4.11 AT MIXING POINT ..................................................................................... 68 4.11.1.1

Table 32: Stream 1: ............................................................................. 68

4.11.2

Table 33: Stream 2: ............................................................................. 69

4.11.2.1

Table 34: Stream 12: ........................................................................... 69

4.11.3

Balance: .............................................................................................. 69

5 CHAPTER # 5: ..................................................................................... 70 5.1

HEAT EXCHANGER .................................................................................... 70

5.2

TYPES OF HEAT EXCHANGERS ................................................................... 70

5.3

HEAT-TRANSFER FLUIDS ........................................................................... 70

5.4

HEAT-EXCHANGER EVALUATION AND SELECTION .................................... 71

5.5

SHELL AND TUBE HEAT EXCHANGER ......................................................... 74

5.5.1

Tube diameter:.................................................................................... 74

5.5.2

Tube thickness: ................................................................................... 74

5.5.3

Tube length: ........................................................................................ 74

5.5.4

Tube pitch: .......................................................................................... 75

5.6

CONSTRUCTION OF 1-2 SHELL AND TUBE HEAT

EXCHANGER

75

5.6.1

Shell .................................................................................................... 75

5.6.2

Tubes .................................................................................................. 76

5.6.3

Tube sheets ......................................................................................... 76

5.7

TUBE TO TUBE-SHEET ATTACHMENT ........................................................ 77

5.8

NOZZLES 77

5.8.2

IMPINGEMENT PLATE.......................................................................... 78

5.8.3

TUBE-SIDE CHANNELS ......................................................................... 78

5.8.4

CHANNEL COVERS ............................................................................... 78

5.8.5

PASS DIVIDER ...................................................................................... 78

5.9

BAFFLES 78

5.9.1

CLASSIFICATION OF BAFFLES: .............................................................. 79

5.9.2

Transverse Baffles: .............................................................................. 79

5.9.3

Segmental Baffles:............................................................................... 79

5.9.4

BAFFLE SPACING ................................................................................. 80

5.9.5

Disk and doughnut baffle .................................................................... 80

5.9.6

Orifice baffle ....................................................................................... 81

5.9.7

Longitudinal baffles ............................................................................. 81

5.9.8

Flanged joints ...................................................................................... 82

5.9.9

Flanged Joint Types ............................................................................. 82

5.9.10

TUBE PITCH ......................................................................................... 82

5.10 THERMO HYDRAULIC DESIGN PROCEDURE............................................... 83 5.10.1

Shell and Tube Heat Exchanger ........................................................... 83

5.10.2

SHELL SIDE CALCULATION ................................................................... 83

5.10.3

TUBE SIDE CALCULATION .................................................................... 83

5.11 DESIGN DATA............................................................................................ 86 5.11.1

Fluid 1: Process stream ....................................................................... 86

5.11.2

Fluid 2 : Cooling Utility (25 % Brine Soln.) ............................................ 86

5.11.3

Unknowns: .......................................................................................... 86

5.11.4

Heat Duty ............................................................................................ 86

5.11.5

Flowrate .............................................................................................. 86

5.11.6

Flowrate Of Utility ............................................................................... 87

5.12 PHYSICAL PROPERTIES .............................................................................. 87 5.12.1

Process Stream : .................................................................................. 87

5.12.2

Brine Solution : .................................................................................... 87

5.13 ASSUME OVERALL COEFFICIENT, U0.......................................................... 87 5.14 MEAN TEMPERATURE DIFFERENCE .......................................................... 87 5.15 HEAT TRANSFER AREA .............................................................................. 88 5.16 DECIDE THE EXCHANGER LAYOUT ............................................................ 88 5.17 INDIVIDUAL H.T.C ..................................................................................... 89 5.17.1

TUBE SIDE CALCULATION .................................................................... 89

5.17.2

Mass Vel: ............................................................................................. 90

5.17.3

Linear Vel: ........................................................................................... 90

5.17.4

Renould's # :........................................................................................ 90

5.17.5

Prandle # : ........................................................................................... 90

5.18 SHELL SIDE CALCULATION ......................................................................... 90 5.18.1

Mass Velocity ...................................................................................... 91

5.18.2

Linear Velocity..................................................................................... 91

5.18.3

Equivalent Diameter............................................................................ 91

5.18.4

Reynold Number: ................................................................................ 91

5.18.5

Prandle Number: ................................................................................. 91

5.19 OVERALL CO-EFFICIENT UO ....................................................................... 91 5.20 PRESSURE DROP ∆P .................................................................................. 92 5.20.1

TUBE SIDE ........................................................................................... 92

5.20.2

SHELL SIDE .......................................................................................... 93

6 CHAPTER # 6: ..................................................................................... 96 6.1

CHEMICAL REACTORS ............................................................................... 96

6.2

TYPES OF REACTORS ................................................................................. 96

6.3

SELECTION OF REACTOR ........................................................................... 96

6.4

WHY WE SELECTED CSTR? ........................................................................ 97

6.5

SOME IMPORTANT ASPECTS OF THE CSTR................................................ 97

6.6

PFR (PLUG FLOW REACTOR) ..................................................................... 98

6.7

CSTR (CONTINUOUS STIRRED-TANK REACTOR) ........................................ 98

6.8

SELECTION OF IMPELLER .......................................................................... 100

6.8.1

6.9

Based on: ............................................................................................ 100

DESIGN OF CASCADE AUTOREFRIGERATED REACTOR ............................... 101

6.10 VOLUME OF REACTOR .............................................................................. 101 6.11 VOLUME OF REACTION ZONE .................................... ............................... 101 6.12 VOLUME OF SETTLING ZONE .................................................................... 102 6.13 LENGTH AND DIAMETER ........................................................................... 103 6.14 BAFFLES 103 6.15 IMPELLER DESIGN ..................................................................................... 103 6.15.1

Conditions ........................................................................................... 103

6.16 REYNOLDS NUMBER ................................................................................. 104 6.17 POWER CONSUMPTION............................................................................ 104 6.18 TYPES OF HEAD COVERS ........................................................................... 104 6.19 MECHANICAL DESIGN

105

6.19.1

SHELL THICKNESS ................................................................................ 105

6.19.2

ELLIPSOIDAL HEAD THICKNESS ............................................................ 105

6.20 MATERIAL OF CONSTRUCTION ................................................................. 106 6.20.1

FOR REACTOR...................................................................................... 106

6.20.2

FOR IMPELLER BLADES ........................................................................ 106

6.20.3

FOR BAFFLES ....................................................................................... 106

6.21 SPECIFICATION SHEET ............................................................................... 107

7 CHAPTER 7:........................................................................................ 108 7.1

CHOICE BETWEEN PLATE AND PACKED COLUMN ..................................... 108

7.2

CHOICE OF PLATE TYPE ............................................................................. 109

7.3

NATURE OF FEED ...................................................................................... 113

7.4

PINCH TEMPERATURE............................................................................... 113

7.4.1

7.5

MINIMUM REFLUX RATIO ......................................................................... 114

7.5.2

7.6

Pinch temperature: ............................................................................. 113

Colburn’s Method: .............................................................................. 114

NUMBER OF PLATES ................................................................................. 114

7.6.1

Gilliland Method: ................................................................................ 115

7.7

EFFICIENCY OF THE COLUMN ................................................................... 115

7.8

FEED PLATE ............................................................................................... 116

7.8.1

7.9

Kirkbride Method: ............................................................................... 116

COLUMN DIAMETER: D C CALCULATION .................................................... 116

7.10 FLOODING VELOCITY ................................................................................ 117 7.10.1

Maximum volumetric flow rate of vapors: .......................................... 117

7.10.2

Net area required: ............................................................................... 117

7.10.3

Column Cross sectional Area: .............................................................. 118

7.10.4

Diameter Of Column: .......................................................................... 118

7.11 PROVISIONAL PLATE DESIGN .................................................................... 118 7.11.1

Column Area ....................................................................................... 118

7.11.2

Downcomer Area ................................................................................ 118

7.11.3

Net area .............................................................................................. 118

7.11.4

Active area .......................................................................................... 118

7.11.5

Hole area............................................................................................. 118

7.11.6

Assumptions: ...................................................................................... 118

7.12 WEEP POINT ............................................................................................. 119 7.12.1

WEIR LENGTH ...................................................................................... 119

7.12.2

WEIR LIQUID CREST ............................................................................. 119

7.12.3

WEEP POINT ........................................................................................ 119

7.13 PLATE PRESSURE DROP ............................................................................. 120 7.13.1

DRY PLATE PRESSURE DROP ................................................................ 120

7.13.2

orifice co-efficient ............................................................................... 120

7.13.3

Dry Head ............................................................................................. 120

7.13.4

Residual Head ..................................................................................... 120

7.13.5

Total Head loss .................................................................................... 120

7.13.6

Total Dry Pressure Drop ...................................................................... 120

7.14 DOWNCOMER LIQUID BACKUP ................................................................ 121 7.14.1

Area Of Apron ..................................................................................... 121

7.14.2

Head loss in Down Comer: .................................................................. 121

7.14.3

DownComer Backup ............................................................................ 121

7.15 RESIDENCE TIME ....................................................................................... 121 7.16 ENTRAINMENT ......................................................................................... 121 7.17 NUMBER OF HOLES PER PLATE ................................................................. 122 7.18 HEIGHT OF THE COLUMN ......................................................................... 122 7.19 SPECIFICATION SHEET ............................................................................... 123

8 CHAPTER 8......................................................................................... 124 8.1

INTRODUCTION ........................................................................................ 124

8.2

ENVIRONMENTAL EFFECTS ....................................................................... 125

8.2.1

EFFECTS OF SULPHURIC ACID ON HEALTH ........................................... 125

8.2.2

EFFECTS OF SULPHURIC ACID ON ENVIRONMENT ............................... 125

8.2.3

ACID RAIN ........................................................................................... 125

8.2.4

MSDS OF H2SO4 .................................................................................. 125

8.2.5

Product Identification ......................................................................... 125

8.3

Chemical Formula: H2SO4 in H2O Product Codes: .................................. 126

8.3.1

Composition/Information on Ingredients ............................................ 126

8.4

Hazards Identification ............................................................................... 126

8.5

Risk of cancer depends on duration and level of

exposure. SAFETY DATA(tm): ........................................................................... 127 8.6

Potential Health Effects: ........................................................................... 127

Inhalation: 127 Ingestion: 127 8.6.1

Skin Contact: ....................................................................................... 127

8.6.2

Eye Contact: ........................................................................................ 128

8.6.3

Chronic Exposure: ............................................................................... 128

8.6.4

Aggravation of Pre-existing Conditions:............................................... 128

8.7

FIRST AID MEASURES ................................................................................ 128

Inhalation: 128 Ingestion: 128 8.7.1

Skin Contact: ....................................................................................... 128

8.7.2

Eye Contact: ........................................................................................ 128

8.8

FIRE FIGHTING MEASURES ........................................................................ 129

Fire:

129

Explosion: 129 8.8.1

Fire Extinguishing Media: .................................................................... 129

8.8.2

Special Information: ............................................................................ 129

8.9

ACCIDENTAL RELEASE MEASURES ............................................................ 129

8.10 HANDLING AND STORAGE ........................................................................ 129 8.11 PHYSICAL AND CHEMICAL PROPERTIES .................................................... 130 Stability:

130

8.11.1

Hazardous Decomposition Products:

130

8.11.2

Hazardous Polymerization: .................................................................. 130

Incompatibilities: ................................................................................................... 130 8.11.3

Conditions to Avoid: ............................................................................ 131

8.12 ECOLOGICAL INFORMATION ..................................................................... 131 8.12.1

Environmental Fate: ............................................................................ 131

8.12.2

Environmental Toxicity: ....................................................................... 131

8.13 MSDS OF GASOLINE .................................................................................. 131 8.14 HAZARDS IDENTIFICATION........................................................................ 131 8.14.1

Eyes ..................................................................................................... 131

8.14.2

Skin ..................................................................................................... 131

8.14.3

Ingestion ............................................................................................. 132

8.14.4

Inhalation ............................................................................................ 132

8.15 WARNING: ................................................................................................ 132 8.15.1

Chronic Effects and Carcinogenicity .................................................... 132

8.15.2

Medical Conditions Aggravated By Exposure ....................................... 133

8.16 FIRST AID MEASURES ................................................................................ 133 8.16.1

Eyes ..................................................................................................... 133

8.16.2

Skin ..................................................................................................... 133

8.16.3

Ingestion ............................................................................................. 133

8.16.4

Inhalation ............................................................................................ 133

8.17 FIRE FIGHTING MEASURES ........................................................................ 133 8.17.1

Flammable Properties: ........................................................................ 133

8.17.2

Fire and Explosion Hazards .................................................................. 134

8.17.3

Extinguishing Media ............................................................................ 134

8.17.4

Fire Fighting Instructions ..................................................................... 134

8.18 ACCIDENTAL RELEASE MEASURES ............................................................ 135 8.18.1

Activate facility spill contingency or emergency plan. ......................... 135

8.19 HANDLING AND STORAGE ........................................................................ 135 8.19.1

Handling Precautions .......................................................................... 135

8.19.2

Storage Precautions ............................................................................ 136

8.19.3

Work/Hygienic Practices ..................................................................... 136

8.20 PHYSICAL AND CHEMICAL PROPERTIES .................................................... 137 8.20.1

Appearance ......................................................................................... 137

8.20.2

Odour .................................................................................................. 137

8.20.3

Odour Threshold ................................................................................. 137

8.20.4

Basic Physical Properties ..................................................................... 137

8.21 STABILITY AND REACTIVITY ....................................................................... 138 8.21.1

Stability: .............................................................................................. 138

8.21.2

Conditions to Avoid ............................................................................. 138

8.21.3

Incompatible Materials ....................................................................... 138

8.21.4

Hazardous Decomposition Products .................................................... 138

9 CHAPTER # 9: ..................................................................................... 138 9.1

INSTRUMENTATION AND PROCESS CONTROL .......................................... 138

9.2

TEMPERATURE MEASUREMENT AND CONTROL ....................................... 139

9.3

PRESSURE MEASUREMENT AND CONTROL............................................... 139

9.4

FLOW MEASUREMENT AND CONTROL ..................................................... 139

9.5

CONTROL SCHEME OF DISTIALLATION COLUMN ...................................... 140

9.5.1

Objectives: .......................................................................................... 140

9.5.2

Manipulated variables:........................................................................ 140

9.5.3

Loads or disturbances: ........................................................................ 140

9.5.4

Control scheme ................................................................................... 141

9.5.5

Advantage ........................................................................................... 141

9.5.6

Disadvantage ...................................................................................... 141

10 141 11 CHAPTER # 10 .................................................................................... 142 11.2 Fixed Cost: ................................................................................................ 145 11.3 Annual Production Cost: ........................................................................... 146 11.4 Processing Cost / Liter: ............................................................................. 146 11.5 Profit per annum: ..................................................................................... 146

11.6 Economic Evaluation: ............................................................................... Error! Bookm 11.6.1

Cash Flow diagram: ............................................................................. Error! Bookma

11.7 Pay Back Period: ....................................................................................... Error! Bookm 11.8 Discounted Pay Back Period: .................................................................... Error! Bookm 11.9 Net present value: .................................................................................... Error! Bookm 11.10

Profitability index: ..................................................................... Error! Bookm

12 APPENDIX .......................................................................................... 148 12.1 APPENDIX A-1 ........................................................................................... 148 12.2 149 12.3 APPENDIX A-2 ........................................................................................... 149 12.4 APPENDIX A-3 ........................................................................................... 150 12.5 150 12.6 APPENDIX A-4 ........................................................................................... 151 12.7 APPENDIX A-5 ........................................................................................... 152 12.8 APPENDIX A-6 ........................................................................................... 153 12.9 APPENDIX A-7 ........................................................................................... 154 12.10

APPENDIX B-1 ............................................................................ 155

12.11

APPENDIX B-2 ............................................................................ 156

12.12

APPENDIX B-3 ............................................................................ 157

12.13

APPENDIX B-4 ............................................................................ 158

12.14

APPENDIX B-5 ............................................................................ 159

12.15

Appendix B-6 ............................................................................. 160

12.16

APPENDIX C-1 ............................................................................ 161

CHAPTER # 01: INTRODUCTION 1.1 WHAT IS GASOLINE? A volatile mixture of flammable liquid hydrocarbons derived chiefly from crude petroleum and used principally as a fuel for internal-combustion engines. Gasoline is a complex mixture of over 500 hydrocarbons that may have between 5 to 12 carbons. Smaller amounts of alkane cyclic and aromatic compounds are present. Gasoline has a typical boiling range from 100 to 400°F (38 to 205°C) as determined by the ASTM method. Alkylate gasoline is the product of the reaction of isobutane with propylene, butylene, or pentylene to produce branched-chain hydrocarbons in the gasoline boiling range. Alkylation of a given quantity of olefins produces twice the volume of high octane motor fuel as can be produced by polymerization. In addition, the blending octane (PON) of alkylate is higher and the sensitivity (RON _ MON) is significantly lower than that of polymer gasoline.

1.2 BACKGROUND & USES Before internal-combustion engines were invented in the mid 19th century, gasoline was sold in small bottles as a treatment against lice and their eggs. At that time, the word Petrol was a trade name. This treatment method is no longer common, because of the inherent fire hazard and the risk of dermatitis. Gasoline was also sold as a cleaning fluid to remove grease stains from clothing. Gasoline was also used in kitchen ranges and for lighting, and is still available in a highly purified form, known as camping fuel or white gas, for use in lanterns and portable stoves. The invention and development of the automobile as primary mode of personal transportation required a parallel development of the fuels that

would power the automobiles. Hydrocarbon fuels were an integral component of society in the 19th century as a source of light. Automobile engines demanded unprecedented amounts of petroleum. The early refiners could convert only a small proportion of their crude oil to gasoline - the rest was wasted or spilled to the environment.

1.3 OCTANE RATING The octane number or rating of gasoline is a measure of its resistance to knock. The octane number is determined by comparing the characteristics of a gasoline to isooctane (2,2,4-trimethylpentane) and n-heptane. Isooctane is assigned an octane number of 100. It is a highly branched compound that burns smoothly, with little knock. On the other hand, n-heptane, a straight chain, un-branched molecule is given an octane rating of zero because of its bad knocking properties. Straight-run gasoline (directly from the refinery distillation column) has an octane number of about 70. In other words, straight-run gasoline has the same knocking properties as a mixture of 70% isooctane and 30% heptanes. Many of these compounds are straight chain alkanes. Cracking, Isomerization, and other refining processes can be used to increase the octane rating of gasoline to about 90. Anti-knock agents may be added to further increase the octane rating. The octane rating became important as the military sought higher output for aircraft engines in the late 1930s and the 1940s. A higher octane rating allows a higher compression ratio or supercharger boost, and thus higher temperatures and pressures, which translate to higher power output. Some scientists even predicted that a nation with a good supply of high octane gasoline would have the advantage in air power. These requirements lead to the production of high octane gasoline by alkylation of olefins.

1.4 PHYSICAL PROPERTIES OF GASOLINE Property

Gasoline

Chemical Formula

C4 to C12

Molecular Weight

100-105

Specific gravity, 60° F/60° F

0.72 –0.78

Density, lb/gal @ 60° F

6-6.5

Boiling temperature, °F

80-437

Heating values >Lower (Btu/lb)

18,676

>Higher (Btu/lb)

20,004

Freezing point, °F

-40

2

Viscosity, mm /s >@104 °F

0.5-0.6

>@68 °F

0.8-1.0

Auto ignition temperature, °F

-45

Specific heat, Btu/lb °F

0.4

1.5 WHAT IS ALKYLATION? The addition of an alkyl group to any compound is an alkylation reaction but in petroleum refining terminology the term alkylation is used for the reaction of low molecular weight olefins with an iso-paraffins to form higher molecular weight iso-paraffins (collectively called alkylate).

Alkylation is an important refining process for the production of alkylates a high-octane gasoline blending component. Alkylate product is a mixture of branched hydrocarbons of gasoline boiling range. Alkylate has a motor octane (MON) of 90-95 and a research octane (RON) of 93-98. Because of its high octane number and low vapor pressure, alkylate is considered an excellent blending component for gasoline.

1.6 HISTORY OF ALKYLATION Alkylation is a twentieth century refinery innovation. Developments in petroleum processing in the late 1930s and during World War II were directed toward production of high-octane liquids for aviation gasoline. The sulfuric acid process was introduced in 1938, and hydrogen fluoride alkylation was introduced in 1942. Humble Oil built the first commercial H 2SO4 alkylation unit in 1938 at Baytown, Texas. Alkylation for aviation gasoline grew rapidly with the Allies war effort. In 1939, six petroleum companies formed a consortium to pool their alkylation technology and develop both sulfuric acid and HF acid processes for 100 octane aviation fuel. The first commercial HF alkylation unit started up in 1942. During the war 60 alkylation units were built. Half were built with sulfuric acid as the catalyst and half with HF. Following World War II, most alkylation operations were discontinued although a few refiners continued to use the process for aviation and premium automobile gasoline. In the mid-1950s, use of higher performance automotive engines required the refining industry to both increase gasoline production and quality. The ™

development of catalytic reforming, such as UOP Plat forming , provided refiners with an important refining tool for production of high octane gasoline. However, the motor fuel produced in such operations, called reformate, is highly aromatic with a higher sensitivity (the spread between research and motor octane) and a lower lead response than alkylate. Many refiners expanded their alkylation operations and began to broaden the range of olefin feeds to both existing and new alkylation units to include propylene and occasionally even some pentenes along with the butenes.

With the phase-out of leaded gasoline and the advent of environmental gasoline the lead response of alkylate is no longer valued, but the importance of alkylate and its production have both grown because of its other properties. Its high unleaded motor octane, low volatility, low-sulfur, and nearly zero olefins and aromatics make alkylate critical to the production of quality environmental gasoline. Licensors of motor fuel HF Alkylation processes are UOP LLC and Phillips. Licensors of H2SO4 alkylation processes are Exxon Mobil and Stratco Engineering.

1.7 ALKYLATION FEEDSTOCKS Olefins and isobutane are used as alkylation unit feedstock. The chief sources of olefins are catalytic cracking and coking operations. Butenes and propene are the most common olefins used, but pentenes (amylenes) are included in some Olefins can be produced by dehydrogenation of paraffins, and isobutane is cracked commercially to provide alkylation unit feed. Hydrocrackers and catalytic crackers produce a great deal of the isobutene used in alkylation but it is also obtained from catalytic reformers, crude distillation, and natural gas processing. In some cases, normal butane is isomerized to produce additional isobutane for alkylation unit feed. Olefins and iso-butane obtained usually in Refinery are given in table.

1.7.1.1 Table 1: Olefins and isobutane production from different units LV % Iso-Butane

Olefins

Hydro-cracker

3

-

FCC

6

15

Coker

1

15

Hydrotreater

1

-

Reformer

2

-

Isomerization

1

-

Crude Unit

0.5

-

1.8 TYPES OF ALKYLATION PROCESSES There are two main types of alkylation processes, Thermal alkylation Catalytic alkylation 1.8.1 THERMAL ALKYLATION

Alkylation can be done without the use of catalysts. But a very high temperature and pressure conditions are required i.e. O

T = 950 F P = 3000-5000psi In this process iso-butane along with ethylene is used as raw materials. This is a vapor phase process and no catalysts are used, but it is commercially not favorable.

1.9 CATALYTIC ALKYLATION Catalytic alkylation of iso-paraffin involves addition of tertiary hydrogen to an o

olefin. This process occurs at low temperature (30-100 C) and pressure.

1.9.1.1 Table 2: COMPARISON BETWEEN THERMAL AND CATALYTIC ALKYLATION THERMAL ALKYLATION

It takes place at high temperature and pressure without the aid of catalyst. It occurs with both normal and isoparaffins. In this process, ethylene reacts more readily than higher molecular weight olefins. Thermal alkylation is of little importance in refinery operation.

CATALYTIC ALKYLATION

It takes place at much lower temperature pressure with the aid of catalyst. It occurs with paraffins containing tertiary carbon atom. In this process, the higher molecular weight olefins react more readily than ethylene. Catalytic process has economic advantage with better selectivity and milder operating conditions that make them preferred for commercial processing.

1.10TYPES OF ACID CATALYSTS USED IN ALKYLATION Sulphuric acid Hydrofluoric acid 1.10.1SULPHURIC ACID ALKYLATION PROCESS

Two sulphuric acid alkylation processes are commonly available. These are the auto-refrigeration process licensed by Exxon and the effluent refrigeration process licensed by Stratford Engineering Corporation. The major difference between the two processes is in the reactor design. In the auto-refrigeration process, the evaporation of iC4 and Propane induces cooling of the emulsion in the reactor. In the effluent refrigeration process, a refrigeration unit provides cooling to the reactor. The auto-refrigeration unit is shown in Figure 1.

1.10.1.1.1 Figure 1: Auto refrigeration unit:

The olefin is fed to the first reactor in the cascades, together with the recycled acid and refrigerant. Recycled and make-up isobutanes are distributed to each reactor. Evaporated gases are compressed and fed back to the reactor along with the fresh olefin feed which is also cooled by this stream. The reactor o

o

operates at a pressure of 90 kPa (10 psig) and at a temperature of 5 C (40 F) for up to 40 min. In the Stratco process, the reactor is operated at a higher pressure of 420 kPa (60 psig), to prevent evaporation of hydrocarbon, and at a temperature of 10 o

o

C (50 F). The effluent refrigeration process uses a single Stratco reactor

design as shown in Figure 2. An impeller emulsifies the hydrocarbon –acid mixture for about 20 –35 min.

1.10.1.2

Figure 2: Effluent refrigeration unit:

1.10.2HF ALKYLATION

This is highly successful process for combining iso-butane and iso-butane involves the recirculation of about 6 parts of iso-butane to 1 part of iso-butane. o

A temp of 75-105 F and a Pressure of 100-150psig is maintained on the reaction contractor. The acid is currently dried, about 6% of heavy oils are removed, and acid consumption is 0.20lb per barrel of alkylates produced. Plain carbon steel is used throughout except that some rundown lines are constructed of Monel metal. The cycle time efficiency is said to be 96%.The basic advantage of HF Alkylation process over H 2SO4 alkylation process is that acid recovery is easy. Two hydrofluoric acid (HF) alkylation processes are commonly available. These are the Phillip process and the UOP process. The HF processes have no mechanical stirring as in the sulphuric acid processes. The low viscosity of HF and the high solubility of isobutane in the acid allow for a simpler design. The emulsion is obtained by injecting the hydrocarbon feed into the continuous HF phase through nozzles at the bottom of a tubular reactor. Reaction o

o

temperature is about 30 C (86 F), allowing for the use of water as a coolant to the reactor. The two processes are quite similar. The flow diagram of the Phillips process is shown in Figure 3. The residence time in the reactor is 20 –40 s. The hydrocarbon phase is sent to the main fractionation column to obtain

stabilized alkylate. H2SO4 alkylation processes are favored over the HF processes because of the recent concern about the mitigation of HF vapors. HF is a very hazardous material for humans because it can penetrate and damage tissue and bone.

1.10.2.1

Figure 3: HF Alkylation unit:

1.11COMPARISON OF H2SO4 & HF A process comparison of H 2SO4 and HF alkylation processes shows that neither has an absolute advantage over the other. From a safety an environmental standpoint, H2SO4 has a clear advantage over HF. Economics of the processes are sensitive to base conditions for feed stocks and operating conditions, as well as refined product pricing. Thus, the actual choice for a particular location is governed by a number of site-specific factors that require a detailed analysis. Commercial alkylation catalyst options for refiners today consist of hydrofluoric (HF) and sulfuric (H 2SO4) acids. In some areas of the world, HF is no longer considered an acceptable option for a new unit due to concerns over safety; however, this is not the case everywhere. Due to site-specific differences in utility economics, feed and product values, proximity to acid regeneration facilities, etc, both H 2SO4 and HF alkylation technologies should be evaluated. The evaluation criteria can be divided into the following categories:



Feed Availability and Product Requirements.



Safety and Environmental Considerations.



Operating Costs.



Utilities.



Catalyst and Chemical Costs. And Capital Investment



Maintenance.

1.11.1FEED AVAILABILITY AND PRODUCT REQUIREMENTS

Historically, butylenes from the FCC were the traditional olefins fed to the alkylation unit. Today, alkylation units are using a broader range of light olefins including propylene, butylenes and amylenes. Alkylate composition and octanes from pure olefins are quite different for each catalyst as shown in Table for light olefin alkylate octanes.

1.11.1.1

Table 3: Types of olefins

Types of Olefin

RON

MON

HF

H2SO4

HF

H2SO4

Propylene

91-93

91-92

89-91

90-92

1-Butene

90-91

97-98

88-89

93-94

2-Butene

96-97

97-98

92-93

93-94

Iso-Butene

94-95

94-95

91-92

92-93

Amylenes

90-92

89-92

88-89

88-90

1.11.2SAFETY & ENVIRONMENTAL CONSIDERATIONS

Safety and environmental concerns are extremely important when choosing an alkylation technology. A huge concern is the large volume of LPG present within the unit. Refineries must protect against conditions that could lead to LPG releases and potential fire hazards. All of the alkylation technologies being evaluated have similar volumes of hydrocarbon within the unit. In addition, neither acid catalyst impacts the flammability of LPG; therefore, no one technology has an advantage over another in this regard.

Another major safety concern is the acid catalyst used to promote the reaction. Both HF and H 2SO4 acids are hazardous materials, however, HF is considerably more dangerous. In the United States, HF has been identified as a hazardous air pollutant in current federal and state legislation. Sulfuric acid has not. HF and H 2SO4 represent an ever-present danger to personnel working on alkylation units. Contact with either HF or H 2SO4 can result in chemical burns. However, HF burns tend to be more severe, since the fluoride ion penetrates the skin and destroys deeper layers of tissue. If not treated, it may even cause dissolution of the bone. In addition, inhalation of HF vapors may cause pulmonary edema and, in severe cases, may result in death. The volatility of the acid at ambient conditions is a chief concern. HF is a toxic, volatile gas at these conditions, while H 2SO4 is a toxic liquid. Therefore, H 2SO4 is much easier to contain in the event of an accidental release. The hazardous nature of both materials has been known and respected for years. In more densely populated areas of the world, safety and environmental concerns of HF usage have given H2SO4 alkylation a notable advantage. In 1986, tests were conducted in the Nevada desert to determine the dangers of a possible HF liquid release. Under conditions similar to those that exist in an alkylation unit, lethal concentrations of an HF aerosol were present up to 8 km (5 miles) from the release points. It was during these tests that HF releases were observed to be much more dangerous than anticipated. Due to the risk, many refiners are implementing water mitigation and detection devices in an effort to remove any HF that would vaporize in the event of a release. With water/HF ratios of 40:1, nearly 90% of the HF can be removed. However, these systems are expensive and there is the concern that the water sprays could become inoperative as a result of an accident. In addition, details have not yet been obtained, or at least reported, on the fate of the HF that is not removed by the water sprays. For a major leak (200 lb/s 100 kg/s) that might result from a 4 inch (10 cm) hole at process conditions, water systems are thought to be less effective. Major HF leaks have been rare in the industry, and when they have occurred, there has usually been a major fire event that has dissipated the HF cloud as it formed. However, the impact of a major HF release should always be considered.

Following a number of HF incidents in the 1980s, and in view of the impact that the Bhopal and Valdez calamities had on the companies concerned, many refiners have carried out Quantified Risk Assessment studies to identify the risk associated with specific HF units. In terms of offsite impact, an unmitigated HF unit will usually generate by far and away the largest element of the risk associated with the site. Tests conducted in 1991 by Quest Consultants, Inc. showed that the potential for a H 2SO4 aerosol formation from an alkylation unit release is highly unlikely. Several tests were performed under a variety of conditions resembling those observed in an alkylation unit. The tests provided conditions favorable to the formation of airborne particles. However, the released acid did not remain airborne, and an aerosol was not formed 1.11.3OPERATING COSTS

Operating costs for H 2SO4 technologies tend to be spread equally amongst steam, electric power and acid costs. With the HF process, most operating costs are associated with high pressure steam or fuel requirements for the isostripper reboiler. This reboiler provides thermal de-fluorination of the alkylate product, in addition to providing the required reboiler duty. 1.11.4UTILITY COSTS

Utility costs tend to favor the H 2SO4 systems. Many HF units require isobuteneto-olefin ratios on the order of 13 - 15/1 to produce an acceptable octane product. Other HF units and many H 2SO4 units develop conditions of mixing and recycle optimization such that they produce similar octane products with isobutane to olefin ratios on the order of 7 - 9/1. Clearly the latter, betterdesigned units operate with significantly lower fractionation costs. Today, many HF units are operating below the design isobutene-to olefin ratio, but to obtain the required octane, due to increasingly tight gasoline specifications, these ratios will need to be increased back to design ratios. The H 2SO4 process employs either electric or turbine drives for the reactors and compressor to optimize refinery utilities. Horsepower input to the HF reaction zone is lower than to the H 2SO4 reaction zone. In addition, the HF process does not require refrigeration.

1.11.5CATALYST AND CHEMICAL COSTS

Catalyst and chemical costs favor HF units, with the main difference being acid cost. Although HF is more expensive, much less is used, and, can be regenerated on site. The operating cost of H 2SO4 alkylation depends heavily on reactor design, feed pretreatment, residual contaminants, and the cost and availability of H2SO4 regeneration. Presently, refiners can either regenerate the catalyst on site or send it to an outside regenerator. The latter choice is very common in the United States, where most refiners are not too distant from H2SO4 manufacturers who can regenerate spent acid at a reasonable cost. Onsite acid regeneration is much more common outside the U.S, due to the lack of regional commercial acid regeneration facilities. Over 25% of the new alkylation units built outside the United States in the last five years have elected to build on-site regeneration facilities. Some regenerators have greatly reduced acid regeneration cost by providing total sulfur handling facilities for refiners. 1.11.6CAPITAL INVESTMENT

It has been over ten years since a comparative cost analysis was conducted between HF and H 2SO4 alkylation technologies. Changes in peripheral equipment to both technologies have changed dramatically in the past ten years, and the impact of these on capital investment will be discussed later in this section. When the above referenced cost estimate was performed there was objectively no real difference in installed costs between the two technologies. Since that time, there have been no improvements in either technology that would warrant a significant change in the cost advantage of one technology over the other. The separate studies performed by independent consulting firms (Pace Engineering and Chem Systems) found that the cost for H 2SO4 and HF alkylation units were comparable.

Installed Capital Cost ($MM) Alkylate Production (BPD)

H2SO4

HF

5000

14.9

14.5

7000

18.8

18.2

It is not surprising that the two processes are competitive on a capital cost basis, when one considers the basic process differences. The H 2SO4 process has a more expensive reactor section and requires refrigeration. However, equal costs are realized in the HF unit by the need for feed driers, product treating, regeneration equipment and more exotic metallurgy. In addition, most refiners will require a dedicated cooling system for an HF unit, to remove the risk of site-wide corrosion in the case of an HF leak. It should be noted that these capital cost estimates do not account for the additional safety and mitigation equipment now required in HF units. Due to the possible hazardous aerosol formation when the HF catalyst is released as a superheated liquid, expensive mitigation systems are now required in many locations throughout the world where HF is used as an alkylation catalyst. Consequently, capital costs for a grassroots HF unit are greater by $2-5 million (U.S.) depending upon the degree of sophistication of the mitigation design. 1.11.7MAINTENANCE

Maintenance costs and data are difficult to obtain on a comparable basis. HF units have much more peripheral equipment (feed driers, product treaters, acid regeneration column and an acid-soluble oil neutralizer); thus, more pieces of equipment to operate and maintain. H 2SO4 units have larger pieces of equipment, such as the compressor and reactor, but maintenance costs are generally lower. Unit downtime to prepare for a full unit turnaround can take longer for HF units, since the reactor-settler system and all the fractionators must be neutralized before maintenance work can proceed. In H 2SO4 units, only the reactor-settler system requires neutralization. In addition, extensive safety

equipment

(breathing

apparatus,

etc.)

is

required

whenever

maintenance is performed with a potential of HF release.

1.12H2SO4 VS. HF SUMMARY A process comparison of the alkylation processes shows that neither has an absolute advantage over the other. From a safety and environmental standpoint, H2SO4 has a clear advantage over HF. Economics of the processes

are sensitive to base conditions for feed stocks and operating conditions, as well as refined product pricing. Thus, the actual choice for a particular refinery is governed by a number of site-specific factors, which require a detailed analysis. As a result of these factors, nearly 90% of new units licensed since 1990 have selected H2SO4 alkylation technology over HF.

2 CHAPTER # 2: PROCESS DESCRIPTION On the basis of the above discussion we select ultimately H 2SO4 alkylation process.

2.1 METHODS OF H2SO4 ALKYLATION MANUFACTURE Methods for H2SO4 production is classified on the basis of reactor’s types EFFLUENT REFRIGERATION CASCADE AUTOREFRIGERATION

2.2 EFFLUENT REFRIGERATION The effluent refrigeration process is licensed by Stratford Engineering Corporation. The effluent refrigeration process (Stratco) uses a single-stage reactor in which the temperature is maintained by cooling coils. The reactor contains an impeller that emulsifies the acid –hydrocarbon mixture and recirculates it in the reactor. Average residence time in the reactor is on the order of 20 to 25 minutes. Emulsion removed from the reactor is sent to a settler for phase separation. The acid is re-circulated and the pressure of the hydrocarbon phase is lowered to flash vaporize a portion of the stream and reduce the liquid temperature to about 30 F (1C). The cold liquid is used as coolant in the reactor tube bundle. The flashed gases are compressed and liquefied then sent to the depropanizer where LPG grade propane and recycle isobutane are separated. The hydrocarbon liquid from the reactor tube bundle is separated into isobutane, n-butane, and alkylate streams in the deisobutanizer column. The isobutane is recycled and n-butane and alkylate are product streams. A separate distillation column can be used to separate the n-butane from the mixture or it can be removed as a side stream from the deisobutanizing column. The choice is a matter of economics because including a separate column to remove the n-butane increases the capital and operating costs. Separating n-butane as a side stream from the deisobutanizing can be restricted because the pentane content is usually too high to meet butane

sales specifications. The side stream n-butane can be used for gasoline blending. In this type of reactor there are chances of Degradation of alkylate Polymerization may occur at a high level Compressor demands for the effluent refrigeration process are larger 2.2.1 CASCADE AUTOREFRIGERATION

The major alkylation processes using sulfuric acid as a catalyst are the autorefrigeration process, licensed by Exxon Research and Engineering (similar to a process previously licensed by the M. W. Kellogg Company), The major differences between the auto-refrigeration and effluent refrigeration processes are in the reactor designs and the point in the process at which propane and isobutane are evaporated to induce cooling and provide the process refrigeration required. The auto-refrigeration process uses a multistage cascade reactor with mixers in each stage to emulsify the hydrocarbon –acid mixture. Olefin feed or a mixture of olefin feed and isobutane feed is introduced into the mixing compartments and enough mixing energy is introduced to obtain sufficient contacting of the acid catalyst with the hydrocarbon reactants to obtain good reaction selectivity. The reaction is held at a pressure of approximately 10 psig (69 kPag) in order to maintain the temperature at about 40 F (5C). In the Stratco, or similar type of reactor system, pressure is kept high enough [45 –60 psig (310 –420 kPag)] to prevent vaporization of the hydrocarbons. In the Exxon process, acid and isobutane enter the first stage of the reactor and pass in series through the remaining stages. The olefin hydrocarbon feed is split and injected into each of the stages. Exxon mixes the olefin feed with the recycle isobutane and introduces the mixture into the individual reactor sections to be contacted with the catalyst. The gases vaporized to remove the heats of reaction and mixing energy are compressed and liquefied, the liquefied hydrocarbon is sent to a depropanizer column for removal of the excess propane which accumulates in the system. The liquid isobutane from the bottom of the depropanizer is pumped to the first stage of the reactor. The acid –hydrocarbon emulsion from the last reactor stage is separated into acid and hydrocarbon phases. The acid is removed from the system for reclamation, and the hydrocarbon phase is then sent to a deisobutanizer. The deisobutanizer separates the hydrocarbon

feed stream into isobutane (which is returned to the reactor), n-butane, and alkylate product. Although high amount of iso-butane is required to maximize the conversion and high power input is also needed to achieve better mixing but acid consumption values are lesser and high quality Alkylate is produced.

2.3 PROCESS VARIABLES The most important process variables are. Reaction temperature Acid strength Isobutane concentration Olefin space velocity. Changes in these variables affect both product quality and yield. 2.3.1 REACTION TEMPERATURE

Reaction temperature has a greater effect in sulfuric acid processes than in those using hydrofluoric acid. Low temperatures mean higher quality and the effect of changing sulfuric acid reactor temperature from (4 to 23 C) is to decrease product octane from one to three numbers depending upon the efficiency of mixing in the reactor. In hydrofluoric acid alkylation, increasing the reactor temperature from 60 to 125 F (16 to 52 C) degrades the alkylate quality about three octane numbers. In sulfuric acid alkylation, low temperatures cause the acid viscosity to become so great that good mixing of the reactants and subsequent separation of the emulsion is difficult. At temperatures above 70 F (21C), polymerization of the olefins becomes significant and yields are decreased. For these reasons the normal sulfuric acid reactor temperature is from 40 to 50 F (5 to 10C) with a maximum of 70 F (21C) and a minimum of 30F (1 C). For hydrofluoric acid alkylation, temperature is less significant and reactor temperatures are usually in the range of 70 to 100 F (21 to 38 C). 2.3.2 ACID STRENGTH

It has varying effects on alkylate quality depending on the effectiveness of

reactor mixing and the water content of the acid. In sulfuric acid alkylation, the best quality and highest yields are obtained with acid strengths of 93 to 98% by weight of acid, 1 to 2% water. The water concentration in the acid lowers its catalytic activity about 3 to 5 times as much as hydrocarbon diluents.

2.3.3 ISOBUTANE CONCENTRATION

Higher ratios of isobutane to olefins in the feed streams to the reactor minimize the undesired polymerization reactions. The quality of alkylates hence increases as the ratios increases. Alkylation plants employing H 2SO4 as the catalyst often operate in the range of 5:1 to 8:1. 2.3.4 OLEFINS SPACE VELOCITY

It is defined as gallon per hour of olefin feed divided by the gallons of acid catalyst instantaneously resident in the true reaction zone. As the space velocity decreases octane no of alkylate goes to maximum value.

2.4 ALKYLATION CHEMISTRY The alkylation reaction combines light C 3-C5 olefins with isobutane in the presence of a strong acid catalyst. Although alkylation can take place at high temperature without catalyst, the only processes of commercial importance involve low to moderate temperatures using either sulfuric or hydrofluoric acid. 2.4.1 REACTION MECHANISM

It is accepted that alkylation of isobutane with C 3 – C5 olefins involves a series of consecutive and simultaneous reactions occurring through carbocation intermediates. A generalized reaction scheme for butene alkylation can be summarized as follows. The first step is the addition of a proton to the olefin to form a t-butyl cation.

This reaction with sulfuric acid results in the production of alkyl sulfates. Occasionally alkyl sulfates are called esters. Propylene tends to form much more stable alkyl sulfates than either C 4 or C5 olefins. With either 1-butene or 2butene, the sec-butyl cation formed may isomerize via methyl shift to give a more stable t-butyl cation.

These initiation reactions are required to generate a high level of ions but become less important at steady state. Typically, this can be observed as a higher rate of acid consumption initially when using fresh acid. The t-butyl cation is then added to an olefin to give the corresponding C 8 carbocation:

2.4.1.1.1

Figure 4: PROCESS FLOW DIAGRAM

3 CHAPTER # 3: MATERIAL BALANCE 3.1 CAPACITY & BASIS 10000 BPSD of Alkylate Produced 3

3

Since 1m = 6.29bbls & Density of Alkylate = 720 kg/m Avg. Molecular Mass of Alkylate = 113.85 kg/kmol Alkylate

= 47694.75 kg/hr

= 418.92 kmol/hr Basis: 1 hr Operation

3.2 EQUATION OF MATERIAL BALANCE

At steady State, Overall Material Balance can be given by equation,

3.3 REACTOR (R-101) 3.3.1 MATERIAL IN

3.3.1.1

Table 4: Stream 3 = 383658.1 kg

Component

kmol

Kg

Butane

412.67

23109.52

Isobutane

5105.61

296128.2

n-butane

1033.82

59961.67

Propene

6.20

260.48

Propane

95.42

4198.26

Sum

6653.76

383658.1

3.3.1.1.1

Figure 5: Reactor’s single step:

3.3.1.2


Substance

kmol

Kg

H2SO4

47.69

4674.01

Water

5.23

95.38

Sum

52.99

4769.4

3.3.2 REACTIONS

REACTION 1 C4H8 (l) + iC4H10 (l)C8H18

(l)

∆H298= -90.572 kJ/gmol

REACTION 2 C3H6 (l) + iC4H10 (l)  C7H16 (l)

∆H298 = -83.81 kJ/gmol

REACTION 3 C3H6 (l) + 2iC4H10 (l) C3H8 (l) + C8H18 (l)

∆H298 = -79.16 kJ/gmol

From Patent o

At 12 C & 25 Psig, Conversion to Alkylate according is: Reaction 1 98.51% Reaction 2 0.341% Reaction 3 1.149%

3.3.3 MATERIAL OUT

3.3.3.1


Component

kmol

kg

Isobutane

4682.54

271588

nbutane

1033.94

59968.54

propane

100.19

4408.68

alkylate

418.92

47694.04

Sum

6235.61

383659.3

3.3.3.2


Component

kg

Spent Acid

4769.4

Balance: Stream 3 = 383658.1 kg

Stream 13 = 4769.4

Total Material In = 383658.1 + 4769.4 = 388427.5 kg

kg

Stream 4 = 383659.3 kg Stream 14 = 4769.4 kg Total Material Out = 383659.3 + 4769.4 = 388428.7 kg

3.4 PHASE SEPARATOR (PS-101)

3.4.1.1.1

Figure 6: phase separator’s single step:

3.4.2 MATERIAL IN

3.4.2.1


Component kmol

kg

Isobutane

4682.54 271588

nbutane

1033.94

59968.54

propane

100.19

4408.68

alkylate

418.92

47694.04

Sum

6235.61

383659.3

3.4.3 MATERIAL OUT:

3.4.3.1


Component

kmol

kg

Isobutane

1791.62

103914.1

nbutane

271.96

15773.91

propane

62.02

2729.183

Sum

2125.61

122417.2

3.4.3.2


Component

kmol

kg

Isobutane

2890.93

167673.9

nbutane

761.97

44194.63

propane

38.17

1679.49

alkylate

418.92

47694.04

Sum

4109.99

261242.1

Balance: Stream 4 = 5+6 Stream 4

= 383659.3 kg

Stream 5+6 = 122417.2 + 261242.1= 383659.1 k

3.5 DISTILLATION COLUMN (DC-101)

3.5.1.1.1

Figure 7: De-isobutanizer:

3.5.2 MATERIAL IN

3.5.2.1


Component

kmol

kg

Isobutane

2890.93

167673.9

nbutane

761.97

44194.63

propane

38.17

1679.49

alkylate

418.92

47694.04

Sum

4109.99

261242.1

3.5.3 MATERIAL OUT

3.5.3.1

Table 11: Stream 11 = 203308.9 kg

Component

kmol

kg

Isobutane

2886.16

167397.2

n-butane

590.20

34232.16

propane

38.17

1679.49

Sum

3514.53

203308.9

3.5.3.2


Component

kmol

kg

n-butane

171.75

9962.46

Isobutane

4.77

276.73

Alkylate

418.92

47694.04

Sum

595.44

57933.23

Balance: Stream 6 = 7 + 11 Stream 6

=261242.1 kg

Stream 7+8+11

= 57933.24 + 203308.9= 261242.14 kg

3.6 DISTILLATION COLUMN (DC-102)

3.6.1.1.1 3.6.1.1.2

Figure 8: De-propanizer:

3.6.2 MATERIAL IN

3.6.2.1


Component

kmol

kg

Isobutane

1791.62

103914.1

nbutane

271.96

15773.91

propane

62.02

2729.183

Sum

2125.61

122417.2

3.6.3 MATERIAL OUT

3.6.3.1


Component

kmol

kg

Propane

28.62

1259.62

3.6.3.2


Component

kmol

kg

Isobutane

1791.62

103914.1

nbutane

271.96

15773.92

propane

33.39

1469.56

Sum

2096.98

121157.6

Balance:

Stream 5 = 9 + 10

Stream 5

= 122417.2 kg

Stream 9 + 10

= 1259.62 + 121157.6= 122417.22 kg

3.7 BALANCE TO MIXING POINT Stream 1 + Stream 2 + Stream 12 = Stream 3 Total Amount = Stream 1 + 2 + 12 = 28560.58 + 30631.06 + 324466.5 = 383658.14 kg

3.7.1.1

Table 15: Flow rates of different streams Stream 1

Stream 2

Component

kmol

kg

Butene

412.67

23109.52

nbutane

85.87

4980.665

propene

6.20

260.483

propane

4.77

209.9131

Iso Butane

Sum

509.51

28560.58

Stream 12

kmol

kg

kmol

kg

85.77

4974.926

862.17

50006.08

19.07

839.2908

71.57

3149.057

427.87

24816.84

4677.78 271311.3

532.71

30631.06

5611.52 324466.5

4 CHAPTER # 4: ENERGY BALANCE 4.1 ENERGY BALANCE EQUATION

At steady State, Overall Energy Balance can be given by equation,

4.2 HEAT OF REACTIONS 4.2.1 At 298K 4.2.2 REACTION 1

C4H8 (g) + iC4H10 (l)  C8H18 (l)

∆H298 = -90.572 kJ/gmol

∆H298 = -223.9 - (-134.5 + 1.172) = -90.572 kJ/gmol

4.2.3 REACTION 2

C3H6 (g) + iC4H10 (l)  C7H16 (l)

∆H298 = -83.81 kJ/gmol

∆H298 = -197.9-(-134.5 + 20.41) = -83.81 kJ/gmol

4.2.4 REACTION 3

C3H6 (g) + 2iC4H10 (l)  C3H8 (l) + C8H18 (l) ∆H298 = -79.16 kJ/gmol ∆H298 = -223.9 – 103.85 – (20.41 – 2(134.5)) = -79.16 kJ/gmol 4.2.5 Heats of Formation Data: ∆Hf (kJ/gmol): Vol. 6

C3H6 (g) = 20.41

C3H8 (l) = -103.85

C4H8 (g) = 1.172

C8H18 (l) = -223.9

iC4H10 (l) = -134.5

C7H16 (l) = -197.9

4.2.5.1.1

Figure 9: Graphical Representation of Hess Law

4.3 REACTOR (R-101) 4.3.1 Table 16: Stream 3+13: o

o

T= 12 C & let Tref. = 25 C Component

Cp (kJ/kmol K)

kmol

∆H (kJ)

Propene

66.92

6.20

5395.504

propane

76.96

95.41

95461.71

butene

93.51

412.67

501665.9

butane

105.82

1033.82

1422218

isobutane

106.52

5105.65

7070434

H2SO4

140.97

47.69

87405.2

Water

24.65

5.29

1698.173

∆H1: 9.18E+06 kJ

4.3.1.1

Table 17: Stream 4+14:

o

o

T= 12 C & let Tref. = 25 C Component

Cp (kJ/kmol K)

kmol

∆H(kJ)

propane

76.96

100.19

-100246.29

butane

105.822

1033.94

-1422380.91

isobutane

106.52

4682.55

-6484507.20

2,2,4,Tmpentane

196.47

417.24

-1065710.48

2,3,Dmpentane

183.49

1.67

-3995.63

H2SO4

140.97

47.69

-87405.19

Water

24.65

5.29

-1698.17

∆H2: -9.17E+06 kJ 4.3.2 Heat of Reaction Added At 298 K ∆H298 = (-90572*412.67) + (-79160*4.57) + (-83810*1.675)

= -3.8E+07 kJ 4.3.3 Total Heat of Reaction: ∆Hr

= ∆H1 + ∆H298 + ∆H2 = 9.18E+06 - 3.8E+07 - 9.17E+06 = -3.79E+07 kJ

4.3.4 Latent Heat Required To Vaporize the Mixture ∆Hl

= 4.28E+07 kJ

Balance: ∆H3

= 9.10E+06 kJ

∆H4

= 3.37E+07 kJ

∆Hi

= ∆Hr + ∆Hl = 4.89E+06 kJ (Heat added by impellers)

4.4 PHASE SEPARATOR (PS-101) 4.4.1.1

Table 18: Stream 4:

Component

Cp (kJ/kmol K)

kmol

∆H(kJ)

propane

75.80

100.19

75956.22

butane

102.62

1033.94

1061079

isobutane

102.36

4682.55

4793516

Alkylate

196.01

418.92

821137.7

∆H4: 4.95E+07 kJ (Including Latent Heat)

4.4.1.2

Table 19: Stream 5:

Component

Cp (kJ/kmol K)

kmol

∆H(kJ)

Isobutane

102.37

1791.62

1834084

nbutane

102.62

271.96

279089.47

propane

72.37

62.02

44888.853

∆H5: 4.49E+07 kJ (Including Latent Heat)

4.4.1.3

Table 20: Stream 6:

Component

kmol

Cp (kJ/kmol K)

∆H(kJ)

Isobutane

2890.92

102.37

2959444.7

nbutane

761.97

102.62

781940.14

propane

38.17

72.37

27623.909

alkylate

418.92

196.013

821137.66

∆H6 = 4.59E+06 kJ

4.5 ACROSS COMPRESSOR Inlet P1 = 14.2 psig, Target P 2 = 175 Psig o

Average Cp at inlet T1 15 C = 101.52 kJ/kmol K From Stream: From Graphs 3.8, 3.9, 3.10

Tr = 0.704 [3]

: X= 0.22

Pr = 0.053

Y= 1.06

Efficiency Ep = 0.67

4.5.1.1.1

Figure 10: Air Compressor:

m = 0.133 n = 1.114 Wp = 2270.63 kj/kmol Actual Work = W W = Wp/Ep = 3389.01 kj/kmol Power = W x No. of moles/ 3600

Z= 0.95

P = 2MW o

Final Temp = 370 K = 97 C 4.5.2 Balance

kJ

∆H into system via compressor

7203732.5

∆H out of compressor

5.21E+07

4.6 ACROSS HEAT EXCHANGER HX-102 (CONDENSER)

4.6.1.1.1

Figure 11: Condenser:

4.6.2 Vapor Stream After Compression enters in cooler condenser:

4.6.2.1

o

o

Table 21: T in = 97 C, T out = 75 C

Component kmol

Cp (kJ/kmol K)

∆H ( KJ)

λ = kJ/kmol

∆H (kJ)= N *λ

Isobutane 1791.62 145.48

5734237.5

20001.02

35834289.66

nbutane

271.96

144.84

866609.95

21799.22

5928604.833

propane

62.026

103.13

140733.06

15920.62

987506.5037

Sum

2125.61

6.74E+6

4.27E+7

Total Heat Removed / cooling utility= 6.74E+6 + 4.27E+7 = 4.95E+07 kJ 4.6.3 Balance:

Total H in =

5.21E+07 kJ

Total H out =

2.62E+06 kJ

4.7 ACROSS DE-PROPANIZER DC-102 Heat In=∆H5= 2.62E+06 kJ

4.7.1.1

Table 22: Stream 10:

Component

kmol

Cp (kJ/kmol K)

Delta T

∆H (kJ)

Propane

28.62

103.13

15

44286.493

∆Hd = 4.428E+4 KJ

4.7.1.2

Table 23: Stream 9:

Component

kmol

Cp (kJ/kmol K)

Delta T

∆H (kJ)

Isobutane

1791.62

145.48

55

14335597

nbutane

271.96

144.84

55

2166525.4

propane

33.39

103.13

55

189448.4

∆Hb = 1.67E+7 kJ

4.7.1.3

Table 24: Let: R= 0.85 Latent Heat -

Component kmol

Cp (kJ/kmol K)

Delta T kJ

∆H (kJ)

Ln

22.90

103.13

15

∆Hl=3.54E+4

Vn

51.53

103.13

15

Duty Of condenser = ∆Hv- ∆Hl- ∆Hd = 4.88E+05 kJ From Column Balance:

4.56E+5

∆Hv=5.68E+5

HF+Duty of reboiler = ∆H d+ ∆Hb+duty of condenser Duty of reboiler

= 4.428E+4 + 1.67E+7 + 4.88E+05 - 2.62E+06 =1.46E+07 kJ

4.8 ACROSS PUMP (STREAM 6)

4.8.1.1.1

Figure 12: Pump:

Stream 6 in:

P= 14.2 Psig ∆Hin = 4.59E+06 kJ

4.8.2 Table 25: Stream 6 out:

P= 100 Psig Component

kmol

Cp (kJ/kmol K)

∆H (kJ)

Isobutane

2890.92

139.74

4039785.2

nbutane

761.97

140.36

1069510

propane

38.17

101.62

38788.748

alkylate

418.92

284.02

1189816.6

∆Hout = 6.34E+6 kJ

4.8.2.1

Table 26: Balance:

∆H

kJ

Energy Added to Stream 1.75E+06 ∆H in

4.59E+06

∆H out

6.34E+06

4.9 ACROSS HEAT EXCHANGER HX-108 Stream 6 in: o

T= 15 C ∆Hin = 6.34E+6 kJ

4.9.1.1

Table 27: Stream 6 out:

o

T = 67 C Component

kmol

Cp (kJ/kmol K)

∆H (kJ)

Isobutane

2890.92

139.74

16967098

nbutane

761.97

140.36

4491942.1

propane

38.17

101.62

162912.74

alkylate

418.92

284.02

4997229.7

∆Hout = 2.66E+07 kJ

4.9.1.2

Table 28: Balance:

∆H

kJ

Energy Added to Stream

2.03E+07

∆H in

6.34E+06

∆H out

2.66E+07

4.10ACROSS DE-ISOBUTANIZER DC-101 Heat In=∆H6= 2.66E+07 KJ


4.10.1.1 o

Top T = 50 C Component

kmol

Cp (kJ/kmol K)

∆H (kJ)

Isobutane

2886.15

126.48107

9126110.5

n-butane

590.21

127.84035

1886315.2

propane

38.17

94.132021

89826.398

∆Hd = 1.11E+07 kJ

4.10.1.2

Table 30: Stream 7:

o

T = 160 C Component

kmol

Cp (kJ/kmol K)

∆H (kJ)

n-butane

172

140.0362

3.25E+06

Isobutane

4.77

137.254

8.84E+04

Alkylate

419

284.124

1.61E+07

∆Hb = 1.94E+07 kJ

4.10.1.3

Table 31: Let: R= 0.45 kmol

Cp (kJ/kmol K)

Delta T Latent Heat (kJ) ∆H (kJ)

Ln

1581.54

126.35

25

Vn

5096.08

126.35

25

∆Hl=3.54E+4

7.12E+07

∆Hv =8.73E+7

Duty Of condenser = ∆Hv- ∆Hl- ∆Hd = 7.13E+07 kJ From Column Balance: Hf+Duty of reboiler = ∆Hd+ ∆Hb + ∆Hs +duty of condenser Duty of reboiler

= 1.11E+07 + 1.94E+07 + 7.13E+07 - 2.66E+07 = 7.52E+07 kJ

4.11AT MIXING POINT Stream 1 + Stream 2 + Stream 12 = Stream 3

4.11.1.1

Table 32: Stream 1:

o

T = 22 C Substance

kmol

Cp (kJ/kmol K)

∆H (kJ)

Butene

412.67

91.41

113178.54

nbutane

85.87

106.95

27554.564

propene

6.20

68.26

1270.0411

propane

4.77

78.87

1128.9069

∆H1 = 1.43E+05 kJ

4.11.2Table 33: Stream 2: o

T =19 C Substance

kmol

Cp (kJ/kmol K)

∆H (kJ)

propane

19.07

78.87

9027.36

nbutane

85.77

106.95

55045.62

isobutane

427.87

105.27

270256.63

∆H2 = 3.34E+05 kJ

4.11.2.1


o

T = 50 C Substance

kmol

Cp (kJ/kmol K)

∆H (kJ)

Isobutane

4677.78

105.27047

12310807

nbutane

862.17

106.95793

2305408

propane

71.56

78.876949

141129.57

∆H12 = 1.48E+07 kJ 4.11.3Balance: ∆H3

= ∆H1 + ∆H2 + ∆H12

1.52E+07 kJ

=> ∆H3 = 1.43E+05 + 3.34E+05 + 1.48E+07=

5 CHAPTER # 5: HEAT EXCHANGER DESIGN 5.1 HEAT EXCHANGER A heat exchanger is a device built for efficient heat transfer from one medium to another, whether the media are separated by a solid wall so that they never mix, or the media are in direct contact. They are widely used in space heating, refrigeration, air conditioning, power plants, chemical plants, petrochemical plants, petroleum refineries, and natural gas processing. One common example of a heat exchanger is the radiator in a car, in which a hot enginecooling fluid, like antifreeze, transfers heat to air flowing through the radiator.

5.2 TYPES OF HEAT EXCHANGERS Shell and Tube heat exchanger Plate heat exchanger Regenerative heat exchanger Adiabatic Wheel heat exchanger Fluid heat exchangers Dynamic Scraped surface heat exchanger

5.3 HEAT-TRANSFER FLUIDS Before selecting a heat-transfer fluid, examine the process for any possibility of interchanging heat between process streams to conserve energy. Frequently, one process stream needs to be heated and another process stream cooled. After this possibility has been exhausted, select a heat-transfer fluid to cool or heat the process Stream. The factors that must be considered in evaluating and selecting a heat transfer fluid are: Operating temperature range Environmental effects Toxicity Flammability Thermal stability

Corrosivity Viscosity

5.4 HEAT-EXCHANGER EVALUATION AND SELECTION The process engineer must be familiar with the types of equipment that are available for the various process units. Because the evaluation and selection of equipment occur frequently, we will first establish general criteria that applies to most equipment. These criteria are to determine: Operating principles Equipment type Sealing Thermal expansion Maintenance Materials of construction - shell, tubes, and seals Temperature-pressure rating Economics The most commonly used heat exchangers are the coil and double pipe for small heat-exchange areas and the shell-and-tube design for large areas. it is recommend that if: 2

2

A < 2m (21.5 ft ) select a coiled heat exchanger 2

2

2

2 m < A < 50 m (538 ft ) select a double-pipe heat exchanger 2

A > 50 m select a shell-and-tube heat exchanger.

5.4.1.1 Table 35: Different types of tube sheets and their properties: Approximat e Type

Significant

Applications best

feature

suited

relative

cost

Limitations

in

carbon steel constructio n

Condensers; liquid-liquid; gasFixed

tube Both tube sheets

sheet

fixed to shell.

gas;

gas-liquid;

cooling

and

heating, horizontal

or

vertical, reboiling. One

tubesheet

“floats” in shell

Floating head

or

with

shell,

or tube bundle may

tubesheet

or may not be

(removable

removable from

and

shell, but

nonremova

cover

can

ble bundles) removed expose ends.

back be to tube

Temperature difference

at

extremes

of o

about 200 F Due to

1.0

differential

expansion.

High temperature Internal gaskets differentials, offer danger of above about 200 leaking. o F extremes; dirty Corrosiveness of fluids requiring fluids on shell- 1.28 cleaning of inside side floating as well as outside parts. Usually of shell, confined to horizontal or horizontal units. vertical. High temperature Bends must be

Only U-tube; U-Bundle

one

tube differentials, carefully made, or sheet required. which might mechanical Tubes bent in U- require provision damage and 0.9-1.1 shape. Bundle is for expansion in danger of rupture removable. fixed tube units. can result. Tube Easily

cleaned side velocities can

conditions both

on cause erosion of

tube

and inside of bends.

shell side.

Fluid should be free of suspended particles.

Relatively Each

tube

own

small

has transfer shell service,

area or

in

forming annular banks for larger Double pipe space

for

shell applications.

side fluid. Usually Especially suited use

externally for high pressures

finned tube.

in tube (greater

Services suitable for finned tube. Piping-up a large number

often

0.8-1.4

requires cost and space.

than 400 psig). Pipe

coil

for

submersion

in

coil-box of water Pipe coil

or sprayed with water is simplest type

of

Condensing, relatively heat

or low

loads

on

sensible transfer.

Transfer coefficient is low, requires relatively 0.5-0.7 large space if heat load is high.

exchanger. Composed

of

metal-formed Plate frame

and

thin

plates

separated

by

gaskets. Compact, easy to

Not well suited Viscous

fluids,

corrosive

fluids,

slurries, high heat transfer.

clean.

concentric plates; no

boiling

or

condensing; limit 350-500

o

F

by 0.8-1.5

gaskets. Used for liquid-liquid only; not gas-gas.

Compact, Spiral

for

bypassing,

high turbulence.

Cross-flow,

Process corrosion,

condensing,

suspended

heating.

materials.

0.8-1.5

5.5 SHELL AND TUBE HEAT EXCHANGER Shell and tube heat exchangers consist of a series of tubes. One set of these tubes contains the fluid that must be either heated or cooled. The second fluid runs over the tubes that are being heated or cooled so that it can either provide the heat or absorb the heat required. A set of tubes is called the tube bundle and can be made up of several types of tubes: plain, longitudinally finned etc. Shell and Tube heat exchangers are typically used for high pressure applications (with pressures greater than 30 bar and temperatures greater than 260°C). This is because the shell and tube heat exchangers are robust due to their shape. There are several thermal design features that are to be taken into account when designing the tubes in the shell and tube heat exchangers. These include: 5.5.1 Tube diameter:

Using a small tube diameter makes the heat exchanger both economical and compact. However, it is more likely for the heat exchanger to foul up faster and the small size makes mechanical cleaning of the fouling difficult. To prevail over the fouling and cleaning problems, larger tube diameters can be used. Thus to determine the tube diameter, the available space, cost and the fouling nature of the fluids must be considered. 5.5.2 Tube thickness:

The thickness of the wall of the tubes is usually determined to ensure: There is enough room for corrosion That flow-induced vibration has resistance Axial strength Ability to easily stock spare parts cost Sometimes the wall thickness is determined by the maximum pressure differential across the wall. 5.5.3 Tube length:

Heat exchangers are usually cheaper when they have a smaller shell diameter and a long tube length. Thus, typically there is an aim to make the heat exchanger as long as possible. However, there are many limitations for this, including the space available at the site where it is going to be used and the

need to ensure that there are tubes available in lengths that are twice the required length (so that the tubes can be withdrawn and replaced). Also, it has to be remembered that long, thin tubes are difficult to take out and replace. 5.5.4 Tube pitch:

When designing the tubes, it is practical to ensure that the tube pitch (i.e. the centre-centre distance of adjoining tubes) is not less than 1.25 times the tubes' outside diameter

5.5.4.1.1

Figure 13: Shell and tube Heat Exchanger:

5.6 CONSTRUCTION OF 1-2 SHELL AND TUBE HEAT EXCHANGER 5.6.1 Shell

The shell is simply the container for the shell-side fluid. The shell normally has a circular cross section and is commonly made by rolling a metal plate of the appropriate dimensions into a cylinder and welding the longitudinal joint large diameter, near-atmospheric pressure shells have been designed with a partial

ball-joint in the shell designed to allow the shell to partially "rotate" to accommodate stresses. 5.6.2 Tubes

The tubes are the basic component of the shell and tube exchanger, providing the heat transfer surface between one fluid flowing inside the tube and the other fluid flowing across the outside of the tubes. The tubes may be seamless or welded and most commonly made of copper or steel alloys. Other alloys of nickel, titanium, or aluminum may also be required for specific applications. 5.6.3 Tube sheets

A tube sheet is an important component of a heat exchanger. It is the principal barrier between the shell-side and tube-side fluids. Proper design of a tube sheet is important for safety and reliability of the heat exchanger. Tube sheets are mostly circular with uniform pattern of drilled holes. Tube sheets of surface condensers are rectangular shape. Tube sheets are connected to the shell and the channels either by welds (integral) or with bolts (gasketed joints) or with a combination of both. Tube-sheet connection with the shell and channel for fixed tube-sheet exchanger can be categorized into two types: Both sides integral construction Shell-side integral and tube-side gasketed construction Tube-sheet connection with the shell and channel for floating heat exchanger and U-tube heat exchangers can be categorized into three types: Both sides integral construction One side integral and the other side gasketed construction Both sides gasketed construction

5.6.3.1.1

Figure 14: Tube Sheet lay out:

5.7 TUBE TO TUBE-SHEET ATTACHMENT Tubes are attached to the tube sheet by: Rolling Welding Rolling and Welding Explosive Welding Brazing Schematic sketch of tube to tube-sheet attachment are given in fig. Expansion of the tubes into the tube sheet is most widely used and is satisfactory for many services. However, when stresses are higher, or where pressures are such that significant leakage could occur, or where contamination between fluids is not permitted, the tubes are welded to the tube sheet. Explosion welding can be used instead of conventional welding where there is incompatibility between tube and tube-sheet materials and for tube plugging under hazardous conditions.

5.8 NOZZLES The nozzles are the inlet and exit ports which allow the entrance and departure of two fluid streams separately in the shell and tube heat exchanger.

5.8.1.1.1

Figure 15: Nozzles lay out:

5.8.2 IMPINGEMENT PLATE

The inlet nozzle often has an impingement plate set just below to divert the incoming fluid jet from impacting directly at high velocity on the top row of tubes. 5.8.3 TUBE-SIDE CHANNELS

Tube-side channels and nozzles simply control the flow of the tube-side fluid into and out of the tubes of the exchanger. Since the tube-side fluid is generally the more corrosive, these channels and nozzles will often be made out of alloy materials (compatible with the tubes and tube sheets, of course). They may be clad instead of solid alloy. 5.8.4 CHANNEL COVERS

The channel covers are round plates that bolt to the channel flanges and can be removed for tube inspection without disturbing the tube-side piping. In smaller heat exchangers, bonnets with flanged nozzles or threaded connections for the tube-side piping are often used instead of channels and channel covers. 5.8.5 PASS DIVIDER

A pass divider is needed in one channel or bonnet for an exchanger having two tube-side passes, and they are needed in either channels or bonnets for an exchanger having more than two passes. If the channels or bonnets are cast, the dividers are integrally cast and then faced to give a smooth bearing surface on the gasket between the divider and the tube sheet. If the channels are rolled from plate or built up from pipe, the dividers are welded in place.

5.9 BAFFLES Baffles serve two functions: They support the tubes in the proper position during assembly and operation and prevent vibration of the tubes caused by flow-induced eddies They guide the shell-side flow back and forth across the tube field, increasing the velocity and the heat transfer coefficient.

5.9.1 CLASSIFICATION OF BAFFLES:

Baffles are either normal or parallel to the tubes. Accordingly, baffles may be classified as transverse or longitudinal. 5.9.2 Transverse Baffles:

The transverse baffles direct the shell-side fluid into the tube bundle at approximately right angles to the tubes, and increase the turbulence of the shell fluid. Transverse baffles are of two types: Plate baffles Rod baffles Three types of plate baffles are Segmental baffles Disk and doughnut baffles Orifice baffles 5.9.3 Segmental Baffles:

The segmental baffle is a circular disk (with baffle holes) having a segment removed. Predominantly, a large number of shell and tube exchangers employ segmental baffles. This cutting is denoted as the baffle cut and it is commonly expressed as a percentage of the shell inside diameter. The segmental baffle is also referred to as a single segmental baffle. The heat transfer and pressure drop of cross flow bundles are greatly affected by the baffle cut. The baffle cuts vary from 20 to 49% with the most common being 20-25%, and the optimum baffle cut is generally

5.9.3.1.1

Figure 16: Segmental Baffles lay out:

20%, as it affords the highest heat transfer for a given pressure drop. Baffle cuts smaller than 20% can result in high pressure drop. As the baffle cut increases beyond 20%, the flow pattern

5.9.3.1.2

Figure 17: Flow patterns:

deviates more and more from cross flow and can result in stagnant regions or areas with lower flow velocities; both of these reduce the thermal effectiveness of the bundle. 5.9.4 BAFFLE SPACING

The practical range of single-segmental baffle spacing is to 1 shell diameter, though optimum could be 40-50%. TEMA provides maximum baffle spacing for various tube outer diameters, tube materials, and the corresponding maximum allowable temperature limit. The baffles are generally spaced between the nozzles. The inlet and outlet baffle spacings are in general larger than the “central” baffle spacing to accommodate the nozzles, since the nozzle

dimensions frequently require that the nozzle should be located far enough from the tube sheets. 5.9.5 Disk and doughnut baffle The disk and doughnut baffle is made up of alternate “disks” and “doughnut”

baffles as shown in Fig. Disk and doughnut baffle heat exchangers are primarily used in nuclear heat exchangers.

5.9.5.1.1

Figure 18: Disk and doughnut baffles:

This baffle design provides a lower pressure drop compared to a single segmental baffle for the same unsupported tube span, and eliminates the tube bundle to shell bypass stream.

5.9.5.1.2

Figure 19: Baffle orifice:

5.9.6 Orifice baffle

In an orifice baffle, the tube-to-baffle hole Clearance is large so that it acts as an orifice for the shell-side flow. These baffles do not provide support to tubes, and, due to fouling, the annular orifices plug easily and cannot be cleaned. This baffle design is rarely used. 5.9.7 Longitudinal baffles

Longitudinal baffles divide the shell into two or more sections, providing multipass on the shell side. The longitudinal baffles are used to control the direction of the shell side flow. But this type should not be used unless the baffle is welded to the shell and tube sheet. Nevertheless, several sealing devices have been tried to seal the baffle and the shell, but none has been very effective. They are:

Sealing strips or multiflex arrangement Packing arrangement Slide-in or tongue-and-groove arrangement 5.9.8 Flanged joints

Flanges are often employed to connect two sections by bolting them together so that the

sections can be assembled and disassembled easily. In heat

exchangers, the flange joints are used to connect together the following components: Channel and channel cover Heads or channels with the shell/tube sheets Inlet and outlet nozzles with the pipes carrying the fluids The flanged joints play an important role from the standpoint of integrity and reliability of heat exchangers. Improper design of flanges causes leakage of heat exchanger fluids. Therefore, preventing the liquid or gas leaks is one of the most important considerations while designing flanged joints. 5.9.9 Flanged Joint Types

From a conceptual standpoint, flanged joints may be subdivided into two major categories: Bolted joints Pressure-actuated or self-energizing joints 5.9.10TUBE PITCH

The shortest center-to-center distance between the adjacent tubes is termed as tube pitch. Although The square pitch has the advantage of easier external cleaning, the triangular pitch is sometimes preferred because it permits the use of more tubes in a given shell diameter.

5.9.10.1.1 Figure 20: Tube Pitch:

5.10THERMO HYDRAULIC DESIGN PROCEDURE 5.10.1Shell and Tube Heat Exchanger

Thermo hydraulic design steps for shell and tube heat exchanger are, Calculation of heat duty Calculation of log mean temperature difference Finding out correction factor for LMTD Correction of LMTD Assuming overall heat transfer coefficient(Uo) Area calculation Calculation of number of tubes Corrected area 5.10.2SHELL SIDE CALCULATION

Selection of shell inside diameter Baffle spacing Pitch calculation Tube clearance Shell area Mass velocity Equivalent diameter Reynold’s number across shell side

Factor for heat transfer calculation Prandtl’s number

Individual overall heat transfer coefficient 5.10.3TUBE SIDE CALCULATION

Flow area per tube Number of tubes calculation Tube area calculation Mass velocity calculation Reynold’s number across tube side

Velocity calculation Prandtl’s number

Calculation of factor for heat transfer coefficient Calculation of individual heat transfer coefficient

5.10.3.1.1 Figure 21: Steps involved in designing Heat Exchanger:

5.11DESIGN DATA 5.11.1Fluid 1: Process stream

Flowrate = m1 = 1.848 kmol/sec o

T1 in = 25 C o

T1 out = 12 C ∆T1 = 13

Cp1 Avg = 135.6 kJ/kmol K (At mean temperature) 5.11.2Fluid 2 : Cooling Utility (25 % Brine Soln.)

Flowrate = m2 = ? o

T2 in = -5 C o

T2 out = 10 C ∆T2 =15

Cp2 Avg = 80.02 kJ/ kmol K (At mean temperature) 5.11.3Unknowns:

Duty (heat transfer rate). Flowrate of Utility.

Calculating the unknowns 5.11.4Heat Duty ∆H = m1 x Cp1 Avg x ∆T1 5.11.5Flowrate

m1 = 1.848 kgmol/sec ∆T1 = 13

Cp1 Avg = 135.6 kJ/kmol K ∆H = 3257.654 kW

5.11.6Flowrate Of Utility

m2 = ∆H / Cp2 Avg x ∆T2 ∆H = 3257.654 kJ/sec ∆T2 =15

Cp2 Avg = 80.02 kJ/ kmol K m2 = 2.714 kmol/sec

5.12PHYSICAL PROPERTIES 5.12.1Process Stream :

Viscosity = µ = 0.163508 cp Thermal Conductivity = k = 8.74E-05 kW/m K Specific heat capacity = Cp 1 = 2.416689 kJ/kg K 5.12.2Brine Solution :

Viscosity = µ = 3.3 cp Thermal Conductivity = k = 5.50E-04 kW/m K Specific heat capacity = Cp 2= 2.845 kJ/kg K

5.13ASSUME OVERALL COEFFICIENT, U 0 Assume Uo , From organics 0

Uo= 600 W/ C .m

Appendix A1

,get value of overall coefficient as light

2

5.14MEAN TEMPERATURE DIFFERENCE LMTD = ∆T2 – ∆T1 / ln ∆T2 / ∆T1 o

∆T1 = T1 in - T2 out = 25 – 10 = 15 C o

∆T2 = T1 out - T2 in = 12 – (-5) = 17 C o

LMTD = 16 C

Corrected LMTD = ∆T LM

R = 0.866 P = 0.5 Now, from the value of R and S, we find out that F for 1-2 heat exchanger Fig, (A-2) F = 0.86 o

Corrected LMTD = ∆T LM = LMTD x F = 13.76 C

5.15HEAT TRANSFER AREA Heat transfer area is evaluated using: Heat duty = ∆H = 3257.654 kW o

∆ LM = = 13.76 C 2

Heat transfer coefficient = U = 600 W/m °C A = ∆H / ∆T LM x U

A = 394.6 m

2

5.16DECIDE THE EXCHANGER LAYOUT Fixed tube exchanger is used because: Simplest & Cheapest. o

∆T is less than 80 C and Shell Pressure less than 8bars

Square pitch is selected for low pressure drop. The process stream has greater pressure than cooling utility therefore Process Stream through the tubes. Cooling utility in the shell. Let, ODt = 1” & BWG= 16 Inner Dia = ID = 0.022 m Outer dia = OD = 0.025 m

Tube thickness 0.002 m Area of 1 tube 0.379 m

2

Length Of tube =16 ft = 4.83 m (Standard) Square Pitch = 0.03125 m pitch (pitch/dia. = 1.25)

5.16.1.1.1 Figure 22: Tube Pitch and Clearance:

5.17 INDIVIDUAL H.T.C 5.17.1TUBE SIDE CALCULATION

Number of Tubes = N: Number of tubes = Area of exchanger / Area of one tube N = 394.6376 /0.379 = 1041 say 1040 For 2 tube passes, tubes / pass = 1040 / 2 = 520 2

Tube Cross-sectional area = πDi / 4 2

= π x (0.022) / 4 = 0.00038 m

2

Total Flow Area A t = Number of tubes * tube cross-sectional area = 520 x 0.00038 = 0.197808 m

2

5.17.2Mass Vel:

Gt=m1/At 2

= 538.7628 Kg/m . sec 5.17.3Linear Vel:

Vt= Gt / Density = 0.979569 m/s [normal range (1-2 m/sec)] 5.17.4Renould's # :

NRe = ρ Vt Di / µ = 7.25E+04

5.17.5Prandle # :

Pr = Cp µ / k 1/3

= 4.52 & (Pr) = 1.653 From Appendix A-3 Jh= 3.00E-03 (Graph) 1/3

hi = jh.(k/Di)( Pr) .( µ/µw)

0.14

. NRe

2

hi = 1429.15 W/m .C 0.14

Neglecting viscosity factor ( µ/µ w)

, as the temperature difference is not too

high.

5.18 SHELL SIDE CALCULATION Bundle Dia= D o x (Nt / K 1)

(1/n1)

Eq 12.3b - vol6

Bundle Dia = Db= 1.1675m Shell Dia = Ds = Db + Tube clearance Tube Clearance = 13 mm

Ds = 1.1675 + 0.013 => Ds = 1.18 m (Appendix A-4) Baffle Spacing = Ib = 0.5 times Ds => Ib= 0.59 m Cross-sectional area of Shell (A s) = (tube pitch – Do)/ pitch *Ib*Ds As = 0.14 m

2

5.18.1Mass Velocity 2

Gs= 547. 8 Kg/m . sec

5.18.2Linear Velocity

Vs= 0.52 m/s (0.3-1 m/s) 5.18.3Equivalent Diameter 2

2

= 1.27 /D o (Pt – 0.785 x D o )

De= 0.0177m 5.18.4Reynold Number:

NRe = 2.95E+03 5.18.5Prandle Number:

Pr = 17.07 1/3

(Pr) =2.57 Assuming Baffle Cut=25 percent Jh =1.00E-02 (Appendix A-5) 2 o

ho= 2348.558 W/m . C

5.19 OVERALL CO-EFFICIENT U O

2o

Fouling(dirt) factor = 1/h = m C/W For light Organics 0.0002 Refrigerated Brine 0.00025 2 o

Cupro Nickel alloy k = 50 W/m . C 1/Uo = 0.001022 + 3.20E-05 + 6.76E-04 1/Uo = 1.73E-03 Uo = 580 W/m

2o

C (Assumed = 600 W/m

2 o

C)

5.20 PRESSURE DROP ∆P 5.20.1TUBE SIDE

1040 Tubes Number of passes = N p = 2 passes Tube Di = 0.022 m Neglecting Viscosity term Linear Velocity: Vt = 0.979569 m/s Reynolds Number : NRe= 7.25E+04 From Figure for jf = 3.80E-02( Appendix A-6 ) ∆Pt= 36542.73 Pa ∆Pt= 5.30 PSI

5.20.2 SHELL SIDE

Shell Dia = Ds =1.18 m Length = L = 4.83 m Baffle Spacing = IB = 0.031 m Velocity at shell side = us = 0.52 m/s friction factor jf = 8.00E-02 (Appendix A-7) ∆Ps = 4.96E+04 Pa ∆Ps = 7.2 PSI

5.20.2.1

Table 36: SPECIFICATION SHEET

Identification:

HX101

Function:

Cooling

Operation:

Continuous

Type

1-2 Shell and Tube heat Exchanger

Heat Duty

∆H = 3257.654 kW

Tube Side Process Stream

Tubes Side

Components

Molar Fraction

Outer Dia

0.025 m

Butene

0.062

Inner Dia

0.022 m

Isobutane

0.76

BWG

16

n-butane

0.155

Length

4.8 m

Propene

0.00093

No. of tubes

1040

Propane

0.0143

No. of Passes

2

Square pitch

0.03125 m

Flowrate

1.848 kmol/sec Material Pressure Drop

Cupro Nickel Alloy 5.3 PSI

Shell Side

Shell

Utility Stream:

Shell Dia

1.18 m

Component

Mol fraction

No. of passes

1

NaCl

25

Baflle Spacing

0.59 m

Water

Flowrate

75

Velocity

0.52 m/s

Material

Steel 303

2.714 kmol/sec Pressure Drop

7.2 PSI

6 CHAPTER # 6: REACTOR DESIGN 6.1 CHEMICAL REACTORS Chemical reactor is the heart of the chemical reaction process. Chemical reactors are containers that are designed for a chemical reaction to occur inside of them. The design of a chemical reactor deals with multiple aspects of chemical engineering.

6.2 TYPES OF REACTORS There are two main types of reactors Batch reactors Flow reactors Flow reactors are further classified into two main categories Continuous Stirred Tank Reactors (CSTR) Plug Flow Reactor

6.3 SELECTION OF REACTOR The factors considered in reactor design are: 

Conversion



Selectivity



Productivity



Yield



Heat exchange



Mixing



Catalyst Distribution



Hold-up Time



Availability



Energy utilization



Safety



Economics

6.4 WHY WE SELECTED CSTR? Following are the reasons due to which CSTR is preferred for this process 

First of all the process we selected is a continuous process for the manufacture of Gasoline in which reaction mixture is of very large capacity with 10 times excess reactant.



In this process intense mixing is required.



We need a reactor in which the contents are well stirred and uniformly mixed throughout.



In plug flow reactors there is no back mixing.



In CSTR the contents are completely mixed and there is also back mixing. It is also known as back mix flow reactor.



Mixing of Reactants



Good Temperature Control



High heat and mass transfer efficiencies



Useful for slow reactions requiring large hold up time



Uniform



Distribution of Catalyst



For Liquid-Gas system Control



Less Man power requirements

6.5 SOME IMPORTANT ASPECTS OF THE CSTR In At steady-state, the flow rate in must equal the mass flow rate out, otherwise the tank will overflow or go empty (transient state). While the reactor is in a transient state the model equation must be derived from the differential mass and energy balances. All calculations performed with CSTRs assume perfect mixing. The reaction proceeds at the reaction rate associated with the final (output) concentration. Often, it is economically beneficial to operate several CSTRs in series or in parallel. This allows, for example, the first CSTR to operate at a higher reagent concentration and therefore a higher reaction rate in these cases, the sizes of the reactors may be varied in order to minimize the total capital investment required to implement the process.

It can be seen that an infinite number of infinitely small CSTRs

6.6 PFR (PLUG FLOW REACTOR) In a PFR, one or more fluid reagents are pumped through a pipe or tube. The chemical reaction proceeds as the reagents travel through the PFR. In this type of reactor, the reaction rate is a gradient; at the inlet to the PFR the rate is very high, but as the concentrations of the reagents decrease and the concentration of the product(s) increases the reaction rate slows. Some important aspects of the PFR: All calculations performed with PFRs assume no upstream or downstream mixing, as implied by the term "plug flow". Reagents may be introduced into the PFR at locations in the reactor other than the inlet. In this way, a higher efficiency may be obtained, or the size and cost of the PFR may be reduced. A PFR typically has an higher efficiency than a CSTR of the same volume. That is, given the same space-time, a reaction will proceed to a higher percentage completion in a PFR than in a CSTR.

6.7 CSTR (CONTINUOUS STIRRED-TANK REACTOR) In a CSTR, one or more fluid reagents are introduced into a tank reactor equipped with an impeller while the reactor effluent is removed continuously. The impeller stirs the reagents to ensure proper mixing. The contents of the reactors are completely mixed so that the complete contents of the reactors are at the same concentration and temperature as the product stream. Since the reactor is designed for steady state, the flow rates of the inlet and outlet streams, as well as the reactors conditions ,remain unchanged with time. Simply dividing the volume of the tank by the average volumetric flow rate through the tank gives the residence time, or the average amount of time a discrete quantity of reagent spends inside the tank.

6.7.1.1.1

1

2

3

4

5

6

7

8

9

10

Figure 23: DESIGN STEPS

• Residence Time

• Total volumetric flow rate

• Volume of the reactor

• Length and Diameter of the reactor

• Impeller specifications

• Baffles Dimensions

• Shell thickness

• Reactor head

• Power calculations

• Material of construction

6.7.1.2

Table 37: Types of Impellers

Factors/Types

Propellers

Viscosity

For

Flow Pattern

Paddles

Turbine

For

For Low to High

ModerateVisco

Moderate

Viscous Liquids

us Liquids

Viscous

For Axial Flow

For

Low

to

Radial

flow

Types

No. of Blades

RPM Ranges

Flat

Marine

Anchor 4-

2

Paddle,

and

Blade Toothed

bladed

400-800, 1150

20-150

6.8 SELECTION OF IMPELLER 6.8.1 Based on:

Viscosity of Liquid Density of liquids Degree of Mixing Flow Pattern Rpm Power Requirement Economics Selected: “ propller

”

Radial

and

Tangential Flow.

Square Pitched

3-blade,

For

4

Vertical

Flat

Curved,

and

2-8 Blades

50-250

6.9 DESIGN OF CASCADE AUTOREFRIGERATED REACTOR As the reaction vessel is divided into two zones. Reaction zone Settling zone.

6.9.1.1.1 Figure 24: The Kellogg Cascade Auto refrigeration unit:

6.10VOLUME 6.10 VOLUME OF REACTOR So, we will find out the volume of 2 compartments first.

6.11VOLUME 6.11 VOLUME OF REACTION ZONE Residence time=27 min

6.11.1.1 Table 38: Balance across Reactor T= 12C n 25 PSIg IN

Stream 3 Substance

Butane Isobutane n-butane Propene Propane Sum Stream 4 H2SO4 Water Sum

Mass

Density

Kgs 23109.52 296128.2 59961.67 260.483 4198.261 383658.1

Kg/m 601.9 566.6 588.1 528.01 512.1

4674.016 95.38808 4769.404

1853 1017

3

Volume Flow m3/hr 38.39428 522.6406 101.9583 0.49333 8.198128 671.6846

2.522405 0.093794 2.616198

Total mass flow rate of inlet streams = 388427.5 Kg/hr Average density of the entering mixture = 576.3 Kg/m

3 3

Volumetric flow rate of entering mixture into the reactor = V o = 674 m /hr Residence Time (known) = τ = 27 min = 0.45 hr.

So Volume of the reactor is given as V = Vo × τ Vr = 303.3 m

3

6.12VOLUME 6.12 VOLUME OF SETTLING ZONE Here, settling time =2 min = 0.0333 hr So,

Vol. of settling zone=0.0333*674 Vs=22.4m

3

TOTAL VOLUME=Vr+Vs = 303.3+22.4 = 325.7 m

3

6.13LENGTH 6.13 LENGTH AND DIAMETER Vr is divided into five compartments: For 1 compartment: V = Vr/5 = 60.68 m3 Since V = (π / 4) *L * D

2

L = 1.5 D D = 3.72 m L = 1.5 * D L = 5.57 m

6.14BAFFLES 6.14 BAFFLES Baffles are used to prevent vortexing and rotation of the liquid mass as a whole. Four radial baffles at equal spacing are mostly used. Baffles width Of one compartment = D/12 = 0.31 m

6.15IMPELLER 6.15 IMPELLER DESIGN 6.15.1Conditions 6.15.1 Conditions

Viscosity of feed+acid= 0.1975 mN.s/m

2

Density of liquid in the tank= 576.34 kg/m Our desired applications for impeller are

3

For pumping liquids, for high speed applications Side entry feed. If Da/Dt if ranges from 1/2-1/3 then Reynolds no. > 300 Propeller type impellers are employed.

6.16 REYNOLDS NUMBER

N Re 

Nd 2  

N= Rotation/Sec=5 (300 RPM) d = Diameter of Impeller = D/3 = 1.24 m ρ = Density = 577.589 kg/m3

µ = Viscosity = 0.1977 cp NRe = 2.24E+07

6.17 POWER CONSUMPTION Calculation of Power

For turbulent flow for NRe >10,000 Np = Power Number = 3.7 n = RPM = 5 d = Dia of impeller = 1.238 m ρ = Density = 577.59 kg/m

3

Power Consumption = 77.88 KW or 104.4 Hp

6.18 TYPES OF HEAD COVERS Flanged Only Dished Ends:

Hemispherical Ellipsoidal Torispherical Selected: Ellipsoidal Moderate Pressures Moderately Economical Less thickness for a particular Pressure as compared to Flanged only and torispherical heads.

6.19MECHANICAL DESIGN 6.19.1SHELL THICKNESS

e

P * Di 2 * J * f  P

 C

e=thickness of shell P=internal pressure=273.64 KP a 5

f=permissible stress=1.65*10 KPa J=joint efficiency=0.9 (Table 13.3 ‘Coluson & Richadson’ - ‘Chemical engineering design Vol 6’)

Type of joint: Single welded joint with bonding strips Degree of radiography: 100% C=corrosion allowance=3mm (Optimum) e = 8.5 mm 6.19.2ELLIPSOIDAL HEAD THICKNESS

e e=thickness of head P=internal pressure=273.64 KP a

P i * Di 2 * J * f  0.2 * P i

5

f=permissible stress=1.65*10 KPa J=joint efficiency=0.9 e = 5.49 mm

6.20MATERIAL OF CONSTRUCTION 6.20.1FOR REACTOR

Stainless Steel : Type 304 Cr=17 %, Ni=8 % C (max) =0.15 % Characteristics: Have good corrosion resistance Excellent mechanical properties Easy to fabricate 6.20.2FOR IMPELLER BLADES

Stainless steel: Type 316 18% Cr, 8%Ni, 2.5%Mo, 0.08%C Characteristics: Corrosion and pitting resistance. Thermal strength Shows good mechanical properties over large flow rates. 6.20.3FOR BAFFLES

Stainless steel: Type 405 11.50% Cr , 0.08%C Characteristics: Good weld ability properties. Mostly used for Baffles, Tower lining and heat Exchanger Tubing.

6.21 SPECIFICATION SHEET Identification Item

Cascade Auto Refrigeration Reactor

Item Number

R-101

Required No.

1

Function

Formation of gasoline via sulphuric acid alkylation of olefins

Operation

Continous

Type

Cascade Agitated Cylindrical Vessels

6.21.1.1

Table 39: Types of Vessels:

Design Data Overall

Compartment

Reaction Volume

303.43 m

Settling Volume

22.16 m

Total Volume

374.43 m

Residence time

3

Impeller type

Propeller

Diameter of impeller

1.24 m

RPM

300

27 min

Mixing Time

21.2 sec

Settling time

2 min

Pumpimg Rate

4.56 m /sec

Shell thickness

8.5 mm

Power Consumed

67.36 kW

Cover Head

Ellipsoidal

Material

SS-316

Head thickness

5.5 mm

No. of baffles

4

Material

SS-304

Baffle Width

0.31 m

3

3

3

7 CHAPTER 7: DE-ISOBUTANIZER COLUMN DESIGN 7.1 CHOICE BETWEEN PLATE AND PACKED COLUMN Vapour liquid mass transfer operation may be carried either in plate column or packed column. These two types of operations are quite different. A selection scheme considering the factors under four headings. Factors that depend on the system i.e. scale, foaming, fouling factors, corrosive systems, heat evolution, pressure drop, liquid holdup. Factors that depend on the fluid flow moment. Factors that depends upon the physical characteristics of the column and its internals i.e. maintenance, weight, side stream, size and cost. Factors that depend upon mode of operation i.e. batch distillation, continuous distillation, turndown, and intermittent distillation. The relative merits of plate over packed column are as follows: Plate column are designed to handle wide range of liquid flow rates without flooding. If a system contains solid contents, it will be handled in plate column, because solid will accumulate in the voids, coating the packing materials and making it ineffective. Dispersion difficulties are handled in plate column when flow rate of liquid are low as compared to gases. For large column heights, weight of the packed column is more than plate column. If periodic cleaning is required, man holes will be provided for cleaning. In packed columns packing must be removed before cleaning. For non-foaming systems the plate column is preferred. Design information for plate column are more readily available and more reliable than that for packed column. Inter stage cooling can be provide to remove heat of reaction or solution in plate column.

When large temperature changes are involved as in the distillation operations tray column are often preferred because thermal expansion or contraction of the equipment components may crush the packing. Random-Packed Column generally not designed with the diameter larger than 1.5 m and diameters of commercial tray column is seldom less than 0.67m. For this particular process, “TDI, Residues and ODCB”, I have selected plate

column because: System is non-foaming. Temperature is very high i.e. about 250°C Diameter is greater than 0.67 meter. Height of the Column is very large.

7.2 CHOICE OF PLATE TYPE There are four main tray types, the bubble cap, sieve tray, ballast or valve trays and the counter flow trays. I have selected sieve tray because: They are lighter in weight and less expensive. It is easier and cheaper to install. Pressure drop is low as compared to bubble cap trays. Peak efficiency is generally high. Maintenance cost is reduced due to the ease of cleaning. Good flexibility in operation(Turndown ratio).

7.2.1.1.1 Figure 25: DESIGN STEPS OF DISTILLATION COLUMN

1

• Calculation of Minimum Reflux Ratio R m

2

• Calculation of optimum reflux ratio

3

• Calculation of theoretical number of stages

4

• Calculation of actual number of stages.

5

• Calculation of diameter of the column

6

• Calculation of weeping point.

7

• Plate Design

8

• Calculation of pressure drop.

9

• Calculation of thickness of the shell and head.

10

• Calculation of the height of the column.

7.2.1.1.2

Figure 26: De-Isobutanizer’s Lay out:

7.2.1.2 Table 40: FEED, DISTILLATE AND BOTTOM SPECIFICATION o

Feed: T = 64 C

Kmoles

Mol.Frac X

propane

38.17

0.01

Isobutane

2890.93

0.70

nbutane

761.98

0.19

alkylate

418.92

0.10

Top: T = 58 C

Kmoles

Mol.Frac X

propane

38.17

0.01

Isobutane

2886.16

0.82

n-butane

590.21

0.17

o

o

Bottom: T = 130 C

Kmoles

Mol.Frac X

isobutane

4.77

0.01

nbutane

171.76

0.29

Alkylate

418.92

0.70

7.3 NATURE OF FEED Temperature

0

=64 C

Pressure

=100 psig

7.3.1.1

Table 41: Nature of Feed

Feed propane

Kmol

Fraction

K Value

Alpha

38.17

0.01

2.29

2.54

2890.93

0.70

1.14

1.27

761.98

0.19

0.90

1.0

418.92

0.10

0.07

0.078

Isobutane(LK)

N-butane(HK)

alkylate

7.4 PINCH TEMPERATURE Top Temperature (T p)

o

=58 C o

Bottom temperature (T b) = 130 C 7.4.1 Pinch temperature:

Upper pinch Tn=

Tp+0.33(Tb-Tp) =

o

81.76 C

Lower pinch Tm= Tp+0.67(Tb-Tp) =

o

106.24 C

7.5 MINIMUM REFLUX RATIO 7.5.1.1

Table 42: minimum reflux ratio

Component

At Tn=81.76 Α

C3 iC4 nC4 C8

2.541 1.2 1 0.0754

At Tm=106.24 Xf o C α 2.61 3.211 1 0.07581 0.10

Since: xnA 

rf

=XfL / XfH =3.8

XnA

= 0.785

X nB

= 0.215

r f (1  r f )(1    x fh )

xnB 

xnA r f

7.5.2 Colburn’s Method:

Relative Volatility (LK/HK) αAB= 1.27 Mole fraction of LK in distilate = x dA=0.82 Mole fraction of HK in distilate = x dB=0.17 xnA= 0.785

xnB= 0.215

Then the relation finds the minimum reflux ratio:

Rm = 0.361

7.6 NUMBER OF PLATES FENSKE’S Equation for minimum number of plates at total reflux:

α*Xf Xfh

0.0077

N min 

 x   x  log  LK   HK   x HK  d  x LK  b log  LK

Number of plate (min) = Nmin = 5.5 =6 plates 7.6.1 Gilliland Method:

Shows the relationship between the minimum number of plates and minimum reflux ratio to the actual number of plates and actual reflux ratio. Appendix B6

7.6.1.1 Table 43: relation between reflux ratio and number of plates (R-Rm)/(R+1) R 0.397 0.433 0.469 0.5 0.54

0.026 0.05 0.07 0.096 0.12

((n+1)-(nm+1)) /(n+2) 0.6 0.68 0.55 0.52 0.5

n 15.5 14.67 13.55 12.58 12.

When R = 1.3 R m = 0.47 then N = 13.55 or Number of plates = 14 Selecting R = 1.3 R m because its difference of change than others is large and economical.

7.7 EFFICIENCY OF THE COLUMN Empirical relation

E o  51  32.5Log (  a * a ) Viscosity = 0.136 cp αa= 1.27

Eo

=76.6%

Total plates= 18.7 or 19 (Sieve trays are used)

7.8 FEED PLATE 7.8.1 Kirkbride Method:

Nr / Ns = 0.163 Nr + Ns = 18 Ns = 15

7.9 COLUMN DIAMETER: DC CALCULATION We have:

7.9.1.1

Table 44: Flow rates and densities:

Top condition Ln=27.41 kmol /min Vn =85.99 kmol/min Lw= 1589.28 kg/min Vw= 4985.01 kg/min 3 Vap density =20.1 kg/m 3 Liq density =510.13 kg /m

Bottom condition Lm=95.91 kmol/min Vm=85.99 kmol/min Lw=9361.1 kg/min Vw=8392.5 kg/min 3 Vap density =25.46 kg/m 3 Liq density =560.28 kg /m

For calculating diameter we have to calculate:

7.10 FLOODING VELOCITY F lv

 L    w   V w 

d v d l

FLV(top)=0.063 FLV(bottom)=0.24 When Plate spacing= 0.8m k1(top)= 1.30E-01 (Appendix B-1) k1(bottom)= 7.00E-02

Top

Bottom

Surface tension = 0.0067 N/m

Surface tension =0.0069 N/m

Corrected k1 =0.1046

Corrected k1 =0.057

Uf=

Uf=

0.5167 m/s

0.26 m/s

Assuming 85 % of flooding velocity Uf top= 0.44 m/s

Uf bottom =0.221 m/s

7.10.1Maximum volumetric flow rate of vapors:

qv 3



V w d v 3

qv=4.13 m /sec

qv= 5.49 m /sec An 

qv

 7.10.2Net area required: U c

An=9.42 m

2

An=24.88 m A

An

2

7.10.3Column Cross sectional Area:

Ac= 10.7 m

2

Ac= 28.27 m

7.10.4Diameter Of Column:

Dc 

2

4 * Ac 

Dc= 3.71m

Dc=6m

Selecting Dc=6m. Constructing the column on the basis of this diameter and reducing the perforations to the top in order to accommodate the desired flow conditions.

7.11PROVISIONAL PLATE DESIGN 7.11.1Column Area

Ac = 3.14*r

2

Ac= 28.28 m

2

7.11.2 Downcomer Area

= Ad = 0.12*Ac Ad =3.4 m

2

7.11.3Net area

An= Ac – A An = 24.9m

2

7.11.4Active area

Aa = Ac-2Ad Aa = 21.5m

2

7.11.5Hole area

= 0.05 *Aa Ah =1.1 m

2

7.11.6Assumptions:

plate thickness =Hole dia =5mm

weir height =50 mm

7.12WEEP POINT 7.12.1WEIR LENGTH

hl = Factor

 

Dc

(Ad / Ac)*100 = 12

At (Ad / Ac) * 100 = 12

From Graph b/w (Ad/Ac)*100 vs. lw / Dc (Appendix B-2) lw / Dc = 0.77 lw = 4.62 m 7.12.2WEIR LIQUID CREST

Max. Liq. flowrate =156.01 kg/sec Min. Liq. flowrate= 109.21 kg/sec As Turn Down Ratio= 0.7 Q =qmin/density of vapor 3

=4.3 m /sec

how(max)

 L w    750 d l  w   w

2/3

how = 91.1 mm hw +how =141.1mm From At:

Appendix hw + how = 141.1 mm K2 = 31

7.12.3WEEP POINT

U h (min) 

 K 2  0.9(25.4  d h )

U min =2.50 m/sec

d v

o.5

B-4

Actual Uh (min) based on active hole area is given as:

U ( actual )

 V w   0.7  d  A   h   v

U actual = 3.6 m/sec

7.13PLATE PRESSURE DROP 7.13.1DRY PLATE PRESSURE DROP

Max Vapor Vel. = Uh = 5.11 m/s Ah*100/Ap=12 Plate thickness/ hole dia : Ratio = 1 From Appendix B-5 ,At (A h/Aa)*100=10, When Plate thickness to plate dia ratio is 1. 7.13.2orifice co-efficient

= Co= 0.86 7.13.3Dry Head  U  hd  51 h   C o 

= hd = 92.2 mm liq

2

 d v     d l 

7.13.4Residual Head hr

= hr= 22.31mm liq



12.5 103 d l

7.13.5Total Head loss = ht = = 267.8 mm liq

ht  hd  hr  ( ho  how )

7.13.6Total Dry Pressure Drop 3

= ΔP

 P t  9.8110  ht  dl

ΔP = 1471.92 Pa

7.14DOWNCOMER LIQUID BACKUP Height of Bottom edge of apron above the plate 7.14.1Area Of Apron

Aap = hap * lw =0.185 m

2

As Aap is less than A d 7.14.2Head loss in Down Comer:  L h  166    d  A  w

dc

hdc= 1.12 mm

l

ap

   

2

7.14.3DownComer Backup

= Hd= 409.97mm

H D

 H t  H dc 

(ho  how )

HD < 0.5*(Tray spacing +Weir height) 410<425

(So, tray spacing is acceptable.)

7.15RESIDENCE TIME t r 

Ad  hbc  d l Lw

Ad = 3.4 m

2

hbc= 1.12 mm tr= 5 sec Greater than 3 sec, so satisfactory

7.16ENTRAINMENT Where U n



V m d v

 Ah

h ap =(hw -10) = 40 mm

Un = 0.221 m/s Since: Uf (bottom) = 0.3 m/s % flooding = Un*100/uf =85% Flv = 0.237 From Appendix B-3 Fractional entrainment= ψ = 0.011

As, entrainment is less than 0.1, process is satisfactory.

7.17 NUMBER OF HOLES PER PLATE Area of one hole = = 1.96E-05 m

2

Number of Holes n= 3917.12 or =3918

7.18 HEIGHT OF THE COLUMN No. of plates = 19 Tray spacing = 0.8 m Distance between plates = 19* 0.8 = 15.2m Top clearance = 0.5m Bottom clearance = 0.5m Tray thickness = 5E-3 m /plate Total thickness of trays =19 * 5E-3 = 7E-2 m Total height of column = 16.27m

ah 

n





4

d h

Ah ah

2

7.19SPECIFICATION SHEET 7.19.1.1

Table 45: Identification:

Item No.

D-101

No. required

1

Tray type

Sieve tray

Function:

Separation of ALKYLATE from BUTANES

Operation:

Continuous

7.19.1.2

Table 46: Design data:

Design Data No. of trays =19

Active holes = 3918

Pressure = 100 Psi g

Weir height = 50 mm

Height of column = 16.27 m

Weir length = 4.62 m

Diameter of column = 6 m

Reflux ratio = 0.47

Hole size = 5 mm

Tray spacing = 0.8 m

Active area =21.5m

2

Tray thickness = 5 mm

8 CHAPTER 8 HAZOP STUDY 8.1 INTRODUCTION A HAZOP survey is one of the most common and widely accepted methods of systematic qualitative hazard analysis. It is used for both new or existing facilities and can be applied to a whole plant, a production unit, or a piece of equipment It uses as its database the usual sort of plant and process information and relies on the judgment of engineering and safety experts in the areas with which they are most familiar. The end result is, therefore reliable in terms of engineering and operational expectations, but it is not quantitative and may not consider the consequences of complex sequences of human errors. The objectives of a HAZOP study can be summarized as follows: To identify (areas of the design that may possess a significant hazard potential. To identify and study features of the design that influence the probability of a hazardous incident occurring. To familiarize the study team with the design information available. To ensure that a systematic study is made of the areas of significant hazard potential. To identify pertinent design information not currently available to the team. To provide a mechanism for feedback to the client of the study team's detailed comments.

8.2 ENVIRONMENTAL EFFECTS 8.2.1 EFFECTS OF SULPHURIC ACID ON HEALTH

Sulfuric acid is a corrosive chemical and can severely burn the skin and eyes. It may cause third degree burns and blindness on contact. Exposure to sulfuric acid mist can irritate the eyes, nose, throat and lungs, and at higher levels can cause a buildup of fluid in the lungs (pulmonary oedema). Asthmatics are particularly sensitive to the pulmonary irritation. Repeated exposures may cause permanent damage to the lungs and teeth. The International Agency for Research on Cancer has classified 'occupational exposures to strong-inorganicacid mists containing sulfuric acid' as carcinogenic to humans. 8.2.2 EFFECTS OF SULPHURIC ACID ON ENVIRONMENT

Sulfuric acid will exist as particles or droplets in the air if released to the atmosphere. It dissolves when mixed with water. It has moderate acute (shortterm) toxicity on aquatic life. Sulfuric acid is very corrosive and would badly burn any plants, birds or land animals exposed to it. It has moderate chronic (long-term) toxicity to aquatic life. Chronic effects on plants, birds or land animals have not been determined. Small quantities of sulfuric acid will be neutralized by the natural alkalinity in aquatic systems. Larger quantities may lower the pH for extended periods of time. 8.2.3 ACID RAIN

Sulfuric acid enters the air during production, use and transporting it. In the air it will react with other chemicals present (ammonia, magnesium, calcium) to form salts, which neutralize the acid. The acid particles dissolve in clouds, fog, rain, or snow, resulting in very dilute acid solutions. This may impact the environment as wet acid deposition ('acid rain'). 8.2.4 MSDS OF H2SO4 8.2.5 Product Identification

Synonyms:

Oil

of

vitriol;

Babcock

acid;

sulphuric

acid

CAS No.:

7664-93-9

Molecular Weight:

98.08

8.3 Chemical Formula:

H2SO4 in H2O

Product Codes: J.T. Baker:

5030, 5137, 5374, 5802, 5815, 5858, 5859, 5868, 5889,

5897, 5961, 5971, 5997, 6163, 6902, 9671, 9673, 9674, 9675, 9676, 9679, 9680,

9681,

9682,

9684,

9687,

9690,

9691,

9693,

9694,

9697

Mallinckrodt: 21201, 2468 8.3.1 Composition/Information on Ingredients Ingredient Hazardous --------------------------------Sulfuric Acid Yes Water No

CAS No

Percent

-----------7664-93-9 7732-18-5

-------

52 - 100% 0 - 48%

8.4 Hazards Identification Emergency Overview poison! danger! corrosive. liquid and mist cause severe burns to all body tissue. may be fatal if swallowed or contacted with skin. harmful if inhaled. affects teeth. water reactive. cancer hazard. strong inorganic acid mists containing sulfuric acid can cause cancer.

8.5 Risk of cancer depends on duration and level of exposure.

SAFETY DATA(tm): Ratings

(Provided

Health

Rating:

Flammability

4

for

your

-

Extreme

Rating:

Reactivity Contact

here

Rating: Rating:

0 2

4

-

convenience) -

Extreme

(Poison) None Moderate (Corrosive)

Lab Protective Equip: GOGGLES & SHIELD; LAB COAT & APRON; VENT HOOD; PROPER

GLOVES

Storage Color Code: White (Corrosive)

8.6 Potential Health Effects: Inhalation: Inhalation produces damaging effects on the mucous membranes and upper

respiratory tract. Symptoms may include irritation of the nose and throat, and labored breathing. May cause lung edema, a medical emergency. Ingestion: Corrosive. Swallowing can cause severe burns of the mouth, throat, and

stomach, leading to death. Can cause sore throat, vomiting, diarrhea. Circulatory collapse with clammy skin, weak and rapid pulse, shallow respirations, and scanty urine may follow ingestion or skin contact. Circulatory shock is often the immediate cause of death. 8.6.1 Skin Contact:

Corrosive. Symptoms of redness, pain, and severe burn can occur. Circulatory collapse with clammy skin, weak and rapid pulse, shallow respirations, and scanty urine may follow skin contact or ingestion. Circulatory shock is often the immediate cause of death.

8.6.2 Eye Contact:

Corrosive. Contact can cause blurred vision, redness, pain and severe tissue burns. Can cause blindness. 8.6.3 Chronic Exposure:

Long-term exposure to mist or vapors may cause damage to teeth. Chronic exposure to mists containing sulfuric acid is a cancer hazard. 8.6.4 Aggravation of Pre-existing Conditions:

Persons with pre-existing skin disorders or eye problems or impaired respiratory function may be more susceptible to the effects of the substance.

8.7 FIRST AID MEASURES Inhalation: Remove to fresh air. If not breathing, give artificial respiration. If breathing is

difficult, give oxygen. Call a physician immediately. Ingestion: DO NOT INDUCE VOMITING. Give large quantities of water. Never give

anything by mouth to an unconscious person. Call a physician immediately. 8.7.1 Skin Contact:

In case of contact, immediately flush skin with plenty of water for at least 15 minutes while removing contaminated clothing and shoes. Wash clothing before reuse. Excess acid on skin can be neutralized with a 2% solution of bicarbonate of soda. Call a physician immediately. 8.7.2 Eye Contact:

Immediately flush eyes with gentle but large stream of water for at least 15 minutes, lifting lower and upper eyelids occasionally. Call a physician immediately.

8.8 FIRE FIGHTING MEASURES Fire: Concentrated material is a strong dehydrating agent. Reacts with organic

materials and may cause ignition of finely divided materials on contact. Explosion: Contact with most metals causes formation of flammable and explosive

hydrogen gas. 8.8.1 Fire Extinguishing Media:

Dry chemical, foam or carbon dioxide. Do not use water on material. However, water spray may be used to keep fire exposed containers cool. 8.8.2 Special Information:

In the event of a fire, wear full protective clothing and NIOSH-approved selfcontained breathing apparatus with full facepiece operated in the pressure demand or other positive pressure mode. Structural firefighter's protective clothing is ineffective for fires involving this material. Stay away from sealed containers.

8.9 ACCIDENTAL RELEASE MEASURES Ventilate area of leak or spill. Wear appropriate personal protective equipment as specified in Section 8. Isolate hazard area. Keep unnecessary and unprotected personnel from entering. Contain and recover liquid when possible. Neutralize with alkaline material (soda ash, lime), then absorb with an inert material (e. g., vermiculite, dry sand, earth), and place in a chemical waste container. Do not use combustible materials, such as saw dust. Do not flush to sewer! US Regulations (CERCLA) require reporting spills and releases to soil, water and air in excess of reportable quantities.

8.10 HANDLING AND STORAGE Store in a cool, dry, ventilated storage area with acid resistant floors and good drainage. Protect from physical damage. Keep out of direct sunlight and away from heat, water, and incompatible materials. Do not wash out container and

use it for other purposes. When diluting, always add the acid to water; never add water to the acid. When opening metal containers, use non-sparking tools because of the possibility of hydrogen gas being present. Containers of this material may be hazardous when empty since they retain product residues (vapors, liquid); observe all warnings and precautions listed for the product.

8.11PHYSICAL AND CHEMICAL PROPERTIES Appearance:

:

Clear

oily

Odor:

liquid.

:

Solubility: Specific

Miscible Gravity:

with 1.84

Odorless.

water, (98%),

liberates

1.40

(50%),

much

heat.

1.07

(10%)

pH: 1 N solution (ca. 5% w/w) = 0.3; 0.1 N solution (ca. 0.5% w/w) = 1.2; 0.01 N solution Boiling

(ca. Point:

0.05% 290C

(ca.

w/w) 554F)

(decomposes

=

2.1. at

340 C)

Melting Point:

3C (100%), -32C (93%), -38 C (78%), -64C (65%).

Vapor

Density

(Air=1):

3.4

Vapor Pressure (mm Hg): 1 @ 145.8C (295F) Stability: Stable under ordinary conditions of use and storage. Concentrated solutions

react violently with water, spattering and liberating heat. 8.11.1Hazardous Decomposition Products:

Toxic fumes of oxides of sulfur when heated to decomposition. Will react with water or steam to produce toxic and corrosive fumes. Reacts with carbonates to generate carbon dioxide gas, and with cyanides and sulfides to form poisonous hydrogen cyanide and hydrogen sulfide respectively. 8.11.2Hazardous Polymerization:

The will not occur. Incompatibilities: Water, potassium chlorate, potassium perchlorate, potassium permanganate,

sodium, lithium, bases, organic material, halogens, metal acetylides, oxides

and hydrides, metals (yields hydrogen gas), strong oxidizing and reducing agents and many other reactive substances. 8.11.3Conditions to Avoid:

Heat, moisture, incompatibles.

8.12 ECOLOGICAL INFORMATION 8.12.1Environmental Fate:

When released into the soil, this material may leach into groundwater. When released into the air, this material may be removed from the atmosphere to a moderate extent by wet deposition. When released into the air, this material may be removed from the atmosphere to a moderate extent by dry deposition. 8.12.2Environmental Toxicity:

LC50 Flounder 100 to 330 mg/l/48 hr aerated water/Conditions of bioassay not specified; LC50 Shrimp 80 to 90 mg/l/48 hr aerated water /Conditions of bioassay not specified; LC50 Prawn 42.5 ppm/48 hr salt water /Conditions of bioassay

not

specified.

This material may be toxic to aquatic life.

8.13 MSDS OF GASOLINE Oxygenated Conventional and Reformulated Gasoline will have oxygenates for octane enhancement or as legally required. MSDS No. 9950

8.14 HAZARDS IDENTIFICATION 8.14.1Eyes

Moderate irritant. Contact with liquid or vapor may cause irritation. 8.14.2Skin

Practically non-toxic if absorbed following acute (single) exposure.

May cause skin irritation with prolonged or repeated contact. Liquid may be absorbed through the skin in toxic amounts if large areas of skin are exposed repeatedly. 8.14.3Ingestion

The major health threat of ingestion occurs from the danger of aspiration (breathing) of liquid drops into the lungs, particularly from vomiting. Aspiration may result in chemical pneumonia (fluid in the lungs), severe lung damage, respiratory failure and even death. Ingestion may cause gastrointestinal disturbances, including irritation, nausea, vomiting and diarrhea, and central nervous system (brain) effects similar to alcohol intoxication. In severe cases, tremors, convulsions, loss of consciousness, coma, respiratory arrest, and death may occur. 8.14.4Inhalation

Excessive exposure may cause irritations to the nose, throat, lungs and respiratory tract. Central nervous system (brain) effects may include headache, dizziness, loss of balance and coordination, unconsciousness, coma, respiratory failure, and death.

8.15 WARNING: The burning of any hydrocarbon as a fuel in an area without adequate ventilation may result in hazardous levels of combustion products, including carbon monoxide, and inadequate oxygen levels, which may cause unconsciousness, suffocation, and death. 8.15.1Chronic Effects and Carcinogenicity

It Contains benzene, a regulated human carcinogen. Benzene has the potential to cause anemia and other blood diseases, including leukemia, after repeated and prolonged exposure. Exposure to light hydrocarbons in the same boiling range as this product has been associated in animal studies with systemic toxicity. See also Section 11 - Toxicological Information.

8.15.2Medical Conditions Aggravated By Exposure

Irritation from skin exposure may aggravate existing open wounds, skin disorders, and dermatitis (rash).Chronic respiratory disease, liver or kidney dysfunction, or pre-existing central nervous system disorders may be aggravated by exposure.

8.16 FIRST AID MEASURES 8.16.1Eyes

In case of contact with eyes, immediately flush with clean, low-pressure water for at least 15 min. hold eye lids open to ensure adequate flushing. Seek medical attention. 8.16.2Skin

Remove contaminated clothing. Wash contaminated areas thoroughly with soap and water or waterless hand cleanser. Obtain medical attention if irritation or redness develops. 8.16.3Ingestion

DO NOT INDUCE VOMITING. Do not give liquids. Obtain immediate medical attention. If spontaneous vomiting occurs, lean victim forward to reduce the risk of aspiration. Small amounts of material which enter the mouth should be rinsed out until the taste is dissipated. 8.16.4Inhalation

Remove person to fresh air. If person is not breathing, ensure an open airway and provide artificial respiration. If necessary, provide additional oxygen once breathing is restored if trained to do so. Seek medical attention immediately.

8.17 FIRE FIGHTING MEASURES 8.17.1Flammable Properties:

Flash Point: -45F (-43C) Auto Ignition Temperature: highly variable; > 530 F (>280C)

Osha/Nfpa Flammability Class: 1A (flammable liquid) Lower Explosive Limit (%): 1.4% Upper Explosive Limit (%): 7.6% 8.17.2Fire 8.17.2 Fire and Explosion Hazards

Vapors may be ignited rapidly when exposed to heat, spark, open flame or other source of ignition. Flowing product may be ignited by self-generated static electricity. When mixed with air and exposed to an ignition source, flammable vapors can burn in the open or explode in confined spaces. Being heavier than air, vapors may travel long distances to an ignition source and flash back. Runoff to sewer may cause fire or explosion hazard. 8.17.3Extinguishing 8.17.3 Extinguishing Media

SMALL FIRES: Any extinguisher suitable for Class B fires, dry chemical, CO2, water spray, fire fighting foam, or Halon. LARGE FIRES: Water spray, fog or fire fighting foam. Water may be ineffective for fighting the fire, but may be used to cool fire-exposed containers. During certain times of the year and/or in certain c ertain geographical locations, gasoline may contain MTBE and/or TAME. Firefighting foam suitable for polar solvents is recommended for fuel with greater than 10% oxygenate concentration - refer to NFPA 11 “Low Expansion Foam - 1994 Edition.” 8.17.4Fire 8.17.4 Fire Fighting Instructions

Small fires in the incipient (beginning) stage may typically be extinguished using handheld portable fire extinguishers and other firefighting equipment. Firefighting activities that may result in potential exposure to high heat, smoke or toxic by-products of combustion should require NIOSH/MSHA- approved pressure-demand self-contained breathing apparatus with full face piece and full protective clothing. Isolate area around container involved in fire. Cool tanks, shells, and containers exposed to fire and excessive heat with water. For massive fires the use of unmanned hose holders or monitor nozzles may be advantageous to further minimize personnel exposure. exposure. Major fires f ires may require withdrawal, allowing the tank to burn. Large storage tank fires typically require

specially trained personnel and equipment to extinguish the fire, often including the need for properly applied fire fighting foam.

8.18ACCIDENTAL 8.18 ACCIDENTAL RELEASE MEASURES 8.18.1Activate 8.18.1 Activate facility spill contingency or emergency plan.

Evacuate nonessential personnel and remove or secure all ignition sources. Consider wind direction; stay upwind and uphill, if possible. Evaluate the direction of product travel, diking, sewers, etc. to confirm spill areas. Spills may infiltrate subsurface soil and groundwater; professional assistance may be necessary to determine the extent of subsurface impact. Carefully contain and stop the source of the spill, if safe to do so. Protect bodies of water by diking, absorbents, or absorbent boom, if possible. Do not flush down sewer or drainage systems, unless system is designed and permitted to handle such material. The use of fire fighting foam may be useful in certain situations to reduce vapors. The proper use of water spray may effectively disperse product vapors or the liquid itself, preventing contact with ignition sources or areas/equipment that require protection. Take up with sand or other oil absorbing materials. Carefully shovel, scoop or sweep up into a waste. Container for reclamation or disposal - caution, flammable vapors may accumulate in closed containers. Response and clean-up crews must be properly trained and must utilize proper protective equipment equipment

8.19HANDLING 8.19 HANDLING AND STORAGE 8.19.1Handling 8.19.1 Handling Precautions

USE ONLY AS A MOTOR FUEL DO NOT SIPHON BY MOUTH

Handle as a flammable liquid. Keep away from heat, sparks, and open flame! Electrical equipment should be approved for classified area. Bond and ground containers during product transfer to reduce the possibility of static-initiated fire or explosion. Special slow load procedures for "switch loading" must be followed to avoid the static ignition hazard that can exist when higher flash point material (such as fuel oil) is loaded into tanks previously containing low flash point products (such as this product) - see API Publication 2003, "Protection Against Ignitions Arising Out Of Static, Lightning and Stray Currents. 8.19.2Storage 8.19.2 Storage Precautions

Keep away from flame, sparks, excessive temperatures and open flame. Use approved vented containers. Keep containers closed and clearly labeled. Empty product containers or vessels may contain explosive vapors. Do not pressurize, cut, heat, weld or expose such containers to sources of ignition. Store in a well-ventilated area. This storage area should comply with NFPA 30 "Flammable and Combustible Liquid Code". Avoid storage near incompatible materials. The cleaning of tanks previously containing this product should follow API Recommended Practice (RP) 2013 "Cleaning Mobile Tanks In Flammable and Combustible Liquid Service" and API RP 2015 "Cleaning Petroleum Storage Tanks". 8.19.3Work/Hygienic 8.19.3 Work/Hygienic Practices

Emergency eye wash capability should be available in the near proximity to operations presenting a potential splash exposure. Use good personal hygiene practices. Avoid repeated and/or prolonged skin exposure. Wash hands before eating, drinking, smoking, or using toilet facilities. Do not use as a cleaning solvent on the skin. Do not use solvents or harsh abrasive skin cleaners for washing this product from exposed skin areas. Waterless hand cleaners are effective. Promptly remove contaminated clothing and launder before reuse. Use care when laundering to prevent the formation of flammable vapors which could ignite via washer or dryer. Consider the need to discard contaminated leather shoes and gloves.

8.20PHYSICAL AND CHEMICAL PROPERTIES 8.20.1Appearance

A translucent, straw-colored or light yellow liquid 8.20.2Odour

A strong, characteristic aromatic hydrocarbon odor, Oxygenated gasoline with MTBE and/or TAME may have a sweet, ether-like odor and is detectable at a lower concentration than non-oxygenated gasoline.

8.20.3Odour Threshold

Odour Detection Odour Recognition Non-oxygenated gasoline: 0.5 - 0.6 ppm 0.8 - 1.1 ppm Gasoline with 15% MTBE: 0.2 - 0.3 ppm 0.4 - 0.7 ppm Gasoline with 15% TAME: 0.1 ppm 0.2 ppm

8.20.4Basic Physical Properties

Boiling Range: 85 to 437 F (39 to 200 C) Vapor Pressure: 6.4 - 15 RVP @ 100 F (38C) (275-475 mm Hg @ 68 F (20C) Vapor Density (air = 1): AP 3 to 4 Specific Gravity (H2O = 1): 0.70 – 0.78 Evaporation Rate: 10-11 (n-butyl acetate = 1) Percent Volatiles: 100 % Solubility (H2O): Non-oxygenated gasoline - negligible (< 0.1% @ 77 F). Gasoline with 15%

8.21 STABILITY AND REACTIVITY 8.21.1Stability:

Stable. Hazardous polymerization will not occur. 8.21.2Conditions to Avoid

Avoid high temperatures, open flames, sparks, welding, smoking and other ignition sources 8.21.3Incompatible Materials

Keep away from strong oxidizers. 8.21.4Hazardous Decomposition Products

Carbon monoxide, carbon dioxide and non-combusted hydrocarbons (smoke). Contact with nitric and sulfuric acids will form nitrocresols that can decompose violently

9 CHAPTER # 9: INSTRUMENTATION AND PROCESS CONTROL 9.1 INSTRUMENTATION AND PROCESS CONTROL Measurement is a fundamental requisite to process control. Either the control can be affected automatically, semi automatically or manually. The quality of control obtainable also bears a relationship to accuracy, re product ability and reliability of measurement methods, which are employed.

Therefore, selection of the most affect means of measurements is an important first step in design and formulation of any process control system.

9.2 TEMPERATURE MEASUREMENT AND CONTROL Temperature measurement is used to control the temperature of outlet and inlet streams in heat exchangers, reactors, etc. Most temperature measurements in the industry are made by means of thermocouple to facilitate bringing the measurements to centralized location. For local measurements at the equipment bimetallic or filled system thermometers are used to a lesser extent. Usually, for high measurement accuracy, resistance thermometers are used all these measurements are installed with thermo wells when used locally. This provides protection against atmosphere and other physical elements.

9.3 PRESSURE MEASUREMENT AND CONTROL Like temperature pressure is a value able indication of material state and composition. In fact, these two measurements considered together are the primary evaluating devices of industrial materials. Pumps, compressors and other process equipment associated with pressure changes in the process material are furnished with pressure measuring devices. Thus pressure measurement becomes an indication of an energy decrease or increase. Most pressure devices in industry are elastic element devices, either directly connected for local use or transmission type to centralized location. Most extensively used industrial pressure is the Bourderi Tube or a Diaphram or Bellow gauges.

9.4 FLOW MEASUREMENT AND CONTROL Flow indicators are used to control the amount of liquid. Also all manually set streams require some flow indication or some easy means for occasional sample measurement. For accounting purposes, feed and product streams or metered. In addition utilities to individual and grouped equipment are also metered. Most flow measures in the industry are/ by Variable Head devices. To

a lesser extent variable area is used as are many types available as special metering situation arise.

9.5 CONTROL SCHEME OF DISTIALLATION COLUMN 9.5.1 Objectives:

In distillation column any of following may be the goals to achieve. Overhead composition bottom composition Constant over head product rate. Constant bottom product rate.

9.5.2 Manipulated variables:

Any one or any combination of following may be the manipulated variables. Steam flow rate to reboiler Reflux rate. Overhead product with drawn rate. Bottom product withdrawn rate. Water flow rate to condenser.

9.5.3 Loads or disturbances:

Following are typical disturbances. Flow rate of feed. Composition of feed. Temperature of feed.

Pressure drop of steam across reboiler. Inlet temperature of water for condenser.

9.5.4 Control scheme

Overall product rate is fixed and any change in feed must be absorbed by changing bottom product rate. The change in product rate is accomplished by direct level control of reboiler if the stream rate is fixed feed rate increases then vapour rate is approximately is constant and the internal reflux flow must increase. 9.5.5 Advantage

Since an increase in feed rate increases reflux rate with vapour rate being approximately constant, then purity of top product increases. 9.5.6 Disadvantage

The overhead change depends on dynamics of level control system that adjusts it.

9.5.6.1.1

Figure 27: Control scheme:

10

11 CHAPTER # 10 COST ESTIMATION 11.1.1.1

Table 47: cost estimation of equipments:

Item Reactor De-isobutanizer De-propanizer Compressor De-isobutanizer Compressor

Quantity Cost in Mid 2004 1 1 1 1 1

Cost($)

Total cost ($)

287391.28 99864 47857 9169.48 2689.92

287391.28 99864 47857 9169.48 2689.92

De-propanizer Condenser

1

9760

9760

Deisobutanizer reboiler

1

7647.12

7647.12

Deisobutanizer reboiler

1

11700

11700

Pumps

4

10123.5

40494

Total cost

12

486199.3

516570

In order to find the cost escalation (INFLATION) we take purchased cost of any one of the equipment and proceed. A = Index in 2004 = 111 B = Index in 2000 = 100 Purchased Cost in 2004 = $ 7647.12 So, Cost in year 2000 = Cost in 2000 = $ 6889.30 Therefore, Escalation is 2.75 % Following this we have, A = Index in 2004 = 111 B = Index in 2000 = 100 Purchased Cost in 2004 = $ 7647.12 So, Cost in year 2000 =Cost in 2000 = $ 6889.30

Therefore, Escalation is 2.75 % Following this we have, Total Production Cost: Variable Cost: Raw Materials comprises of the Olefins, Makeup Isobutane and H2SO4. Flow rate of Olefins = 477.46 kg/min Olefins Cost (Reference should be mentioned here) = 1 $/kg A1 = 477.46 × 60 × 330 × 24 A1 = $ 22688992 Now, Flow rate of makeup Isobutane = 1496.7 liter/min Isobutane cost (Reference) = 0.48 $/liter A2 = 1496.7 × 60 × 330 × 24 A2 = $ 341391283 And, Flow rate of H2SO4 = 79.39 kg/min H2SO4 Cost (Reference) = 0.24 $/kg A3 = 79.38 × 60 × 330 × 24 A3 = $ 9053130 Total Cost: $ 373133405 As the cost of the miscellaneous material is 10% of the maintenance and Utilities cost is 10% of the TCI. Whereas shipping and packing cost is taken as negligible, therefore.

Miscellaneous material Cost = $ 35269 Utilities Cost = $ 387959 Shipping and Packing Cost = Negligible Total Variable Cost = A = $ 373556633

11.2Fixed Cost: It comprises of the maintenance which is taken as 10% (as an initial estimate) .Similarly Operating labor cost is 10% of TCI , laboratory Cost 20% of OLC , Supervision 20% of OLC , Plant overheads 5% of OLC , Capital Charges 10% of FCI , Insurance and Royalties & license fee 1% of the FCI , furthermore local taxes 2% of FCI . Maintenance Cost = $352690.75 Operating labor Cost = $387959.82

Laboratory Cost = $77592 Supervision Cost = $77592 Plant Overheads Cost = $193980 Capital Charges Cost = $352690.75 Insurance Cost = $35269.07 Local Taxes = $ 70538.5 Royalties & licenses cost = $35269.7 Total Fixed Cost = B = $ 1583581 Direct production Cost = A + B = $ 375140214

11.3Annual 11.3 Annual Production Cost: We have sales expenses which is 20 % of the DPC, whereas General overheads and research & development cost is neglected in it . Sales Expenses = $ 75028043 Annual Production Cost = DPC + C $ 450168257 / year

11.4Processing 11.4 Processing Cost / Liter: $ 450168257

1 year

1 day

1 hour

1 bbl.

1 year

330 days

24 hour

416.66 bbl.

159 liter

Processing Cost/ liter = 0.86 $/liter

11.5Profit 11.5 Profit per annum: Present market Value = 1.1 $/liter Profit per liter = 1.1 – 0.86 = $ 0.24/liter $ 0.24

159 liter

10,000 bbl.

330 days

1 liter

1 bbl

day

1 year

Total Annual Profit = $ 125928000

12 APPENDIX 12.1APPENDIX 12.1 APPENDIX A-1 (Coluson & Richadson’ - ‘Chemical 12.1.1.1.1 Fig 12.1 (Coluson engineering design Vol 6’)

12.2 12.3APPENDIX A-2

12.3.1.1.1 Fig 12.19 (Coluson & Richadson’ - ‘Chemical engineering design Vol 6’)

12.4APPENDIX A-3


12.5APPENDIX A-4

12.5.1.1.1 Fig12.10 (Coluson & Richadson’ - ‘Chemical engineering design Vol 6’)

12.6APPENDIX A-5


12.7APPENDIX A-6

12.7.1.1.1 Fig-12.24 (Coluson & Richadson’ - ‘Chemical engineering design Vol 6’)

12.8APPENDIX A-7 Coluson & Richadson’ - ‘Chemical 12.8.1.1.1 Fig-12.30 ( engineering design Vol 6’)

12.9APPENDIX B-1


12.10

APPENDIX B-2

Fig 11.28 (Coluson & Richadson’ - ‘Chemical 12.10.1.1.1 engineering design Vol 6’)

12.11

APPENDIX B-3


12.12

APPENDIX B-4


12.13

APPENDIX B-5


12.14

Appendix B-6

Fig 11.42 Coluson & Richadson – ‘Chemical 12.14.1.1.1 Engineering Vol 2’

12.15

APPENDIX C-1

Fig 10.9 ‘Couper_ Penney_ Fair_ Walas - 2005 12.15.1.1.1 2nd ed. ‘–‘Chemical process equipment - Selection and design ‘

REFERENCES

1.

JONES, DAVID S. J. "STAN" and PUJAD O, PETER R. Handbook of Petroleum

Processing. Springer, Netherlands. : s.n., 2006. 2. Secretariat, OPEC. World Oil Outlook. Austria : s.n., 2013. ISBN: 978-3-9502722-6-0. 3. Parkash, Surinder. REFINING PROCESSES HANDBOOK. s.l. : Elsevier, 2003. ISBN: 0-75067721-X. 4. Gary, James H. Petroleum Refining Technology and Economics. New York : Marcel Dekker, Inc., 2001. ISBN: 0-8247-0482-7. 5. PUJAD O, DAVID S. J. "STAN" JONES and PETER R. Handbook of Petroleum Processing. Netherlands : Springer, 2006. ISBN-10 1-4020-2819-9. 6. Meyers, Robert A. Handbook Of Petroleum Refining Processes. s.l. : McGraw-Hill Handbooks. 7. Alkylation. Wikipedia The free encyclopedia. [Online] [Cited: November 8, 2014.] http://en.wikipedia.org/wiki/Alkylation. 8. SPEIGHT, JAMES G. The Chemistry and Technology of Petroleum. s.l. : CRC press, 2006. 9. M. A. Fahim, T. A. Al-Sahhaf. Fundamentals of Petroleum Refining. s.l. : Elsevier, 2010. ISBN: 978-0-444-52785-1. 10. Daniel.Vallejo. DuPont Clean Technologies. DuPont. [Online] March 9, 2007. http://www2.dupont.com/Clean_Technologies/pt_BR/assets/downloads/STRATCOAlkysafe Process.pdf. 11. Vina.Lam. Comparison of H2SO4 & HF Alkylation Process Technologies. DuPont. [Online] [Cited: November 11, 2014.] http://www.dupont.com/products-and-services/consulting-services process-technologies/articles/h2so4-vs-hf.html.

A Plant Design Project on Production of Gasoline by Sulphuric Acid Alkylation of Olefins

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