che487-finalreport-mek_production

A Novel Process for Producing Methyl Ethyl Ketone from a Hydrocarbon Waste Feed

Chemical Engineering 487 Team 17

Volume 1

April 16, 2012

A Novel Process for Producing Methyl Ethyl Ketone from a Hydrocarbon Waste Feed

Chemical Engineering 487 Team 17 Mike Chung, Engineer Vishal Desai, Engineer

Mark Dresselhouse, Engineer Jeremy Shum, Engineer

Submitted To: Robert Glied, Team Mentor

Elaine Wisniewski, Technical Communications Advisor

Volume 1

April 16, 2012

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MichiChem 2350 Hayward St. GG Brown Building

Ann Arbor MI 48109 Date: April 16, 2012 To: Robert Glied, Technical Project Supervisor Elaine Wisniewski, Technical Communication Supervisor From: Team 17

Mike Chung, Engineer Vishal Desai, Engineer Mark Dresselhouse, Engineer

Jeremy Shum, Engineer Subject: Design Report for Methyl Ethyl Ketone Production by Team 17 ChE 487 MichiPetro, a division of MichiChem, has 20,000 Short Tons per year of an n-butene waste feed from the production of Low Density Polyethylene (LDPE) and petroleum cracking. This feed has a significant amount of 2-butene which is the main precursor for the development of Methyl Ethyl Ketone (MEK), an important industrial solvent. Team 17 was assigned to provide a design for a novel plant to produce MEK and to perform an economic analysis on the design to determine whether to invest in the process or sell the waste feed on the open market. The purpose of this report is to describe the process in detail and provide the economic analysis that will allow MichiChem to determine if this process is feasible. Our novel process is broken up into 7 stages that produce MEK at ASTM standards for profit. The n-butene is hydrated with water to produce 2-butanol as the desired product in the first stage. Then the 2-butanol is purified via distillation in the second and fourth stage. The purified SBA is sent to the second reactor where hydrogen is removed to produce MEK in the fifth stage. The crude MEK product is then purified to ASTM standards in the sixth stage via distillation. The third stage takes the unreacted 2-butene from the first reaction in stage 1 and purifies the desired butenes to be recycled to the hydration reaction, while the final stage condenses the waste from the process to be sent off for disposal. Our major assumption was the composition of the waste feed from the LDPE productions, which we assumed to be a hydrocarbon raffinate feed from the catalytic cracking of crude oil that was stripped of 1-butene, isobutene, and isobutene. From researching and performing an environmental, health, and safety analysis, we found that the biggest risk was from the explosive nature of many of the chemicals that are present in our process (LPG, MEK, SBA, etc.). Many of the chemicals in our process are also hazardous to the environment and dangerous when exposed to humans. Thus, we designed our process in order to reduce risk of exposure and contamination. Our economic analysis set us at a break-even point of 26.4 years with a net present value of -$43.44 MM 12 years after start up. Because of the negative net present value present at the end of the operating life of the plant, we cannot conclude that this plant is a profitable venture. From looking at the alternative option of selling the waste feed on the open market, we found that this generates revenue of $2.94 MM per year with minimal operating costs and a small capital investment to sell the waste feed. Because of this profit generation along with the negative NPV present in our process design, we recommend that MichiChem sell the butene rich waste feed on the open market in order to obtain a profit. Thank you for giving us the opportunity to work on this project and for reading the results of our work. Enclosures: Volume 1: A Novel Process for Producing Methyl Ethyl Ketone from a Hydrocarbon Waste

Feed Volume 2: Appendices and Necessary Attachments for Volume 1

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TABLE OF CONTENTS

Volume 1 LIST OF FIGURES ...................................................................................................................................... v

LIST OF TABLES ....................................................................................................................................... vi LIST OF NOMENCLATURE .................................................................................................................... vii TABLE OF CONTENTS VOLUME 2 ...................................................................................................... viii EXECUTIVE SUMMARY ........................................................................................................................ xii 1.0 INTRODUCTION ............................................................................................................................ 1

2.0 DESIGN BASIS ................................................................................................................................ 1

3.0 DECISION CRITERIA..................................................................................................................... 3

3.1 Technical Criteria .......................................................................................................................... 3

3.2 Economic Criteria ......................................................................................................................... 3

3.3 Environmental, Health, and Safety Criteria .................................................................................. 3

4.0 PROCESS DESIGN .......................................................................................................................... 3

4.1 Stage 1: N-Butene Hydration Reaction ......................................................................................... 6

4.1.1 Objective ............................................................................................................................... 7

4.1.2 Background ........................................................................................................................... 7

4.1.3 Process Description ............................................................................................................... 9

4.2 Stage 2: SBA Purification 1 ........................................................................................................ 12

4.2.1 Objective ............................................................................................................................. 13

4.2.2 Background ......................................................................................................................... 13

4.2.3 Process Description ............................................................................................................. 14

4.3 Stage 3: Butene/Butane Separation ............................................................................................. 15

4.3.1 Objective ............................................................................................................................. 16

4.3.2 Background ......................................................................................................................... 16


4.4 Stage 4: SBA Purification 2 ........................................................................................................ 20

4.4.1 Objective ............................................................................................................................. 21

4.4.2 Background ......................................................................................................................... 21


4.5 Stage 5: SBA Dehydrogenation to MEK .................................................................................... 27

4.5.1 Objective ............................................................................................................................. 27

4.5.2 Background ......................................................................................................................... 27


4.6 Stage 6: MEK Purification .......................................................................................................... 32

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4.6.1 Objective ............................................................................................................................. 32

4.6.2 Background ......................................................................................................................... 32


4.7 Stage 7: DSBE Storage ............................................................................................................... 35

4.7.1 Objective ............................................................................................................................. 36

4.7.2 Background ......................................................................................................................... 36


5.0 ECONOMIC FEASIBILITY ANALYSIS ..................................................................................... 38

5.1 Overview of Economic Feasibility Analysis............................................................................... 38

5.2 Initial Investment ........................................................................................................................ 38

5.2.1 Overview ............................................................................................................................. 38

5.2.2 Fixed Capital Investment (FCI) .......................................................................................... 39

5.2.3 Working Capital (WC) ........................................................................................................ 41

5.2.4 Start-Up Costs ..................................................................................................................... 41

5.2.5 Total Capital Investment (TCI) ........................................................................................... 42

5.3 Operating Costs ........................................................................................................................... 42

5.3.1 Overview ............................................................................................................................. 42

5.3.2 Manufacturing Costs ........................................................................................................... 43

5.3.3 General Expenses ................................................................................................................ 46

5.3.4 Total Operating Costs ......................................................................................................... 47

5.4 Annual Sales Revenue ................................................................................................................ 47

5.5 Sell the Feed: The Alternative to Producing MEK ..................................................................... 48

5.6 Economic Projections and Profitability ...................................................................................... 48

5.6.1 Non-Discounted Cumulative Cash Flow Diagram ............................................................. 48

5.6.2 Discounted Cumulative Cash Flow Diagram ...................................................................... 49

5.6.3 Net Present Value (NPV) .................................................................................................... 50

5.6.4 Discounted Cash Flow Rate of Return on Investment (DCFROROI) ................................ 51

5.6.5 Breakeven Point .................................................................................................................. 52

5.6.6 Discounted Pay Back Period (DPBP) ................................................................................. 53

5.6.7 Present Value Ratio (PVR) ................................................................................................. 54

5.7 Economic Uncertainty................................................................................................................. 54

5.7.1 Raw Material Price Fluctuations ......................................................................................... 54

5.7.2 Projections of Demand for Product ..................................................................................... 54

5.7.3 Considering Inflation .......................................................................................................... 55

5.8 Economic Conclusion/Recommendation .................................................................................... 55

6.0 ENVIRONMENTAL, HEALTH, AND SAFETY ANALYSIS ..................................................... 56

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6.1 Environmental ............................................................................................................................. 56

6.1.1 Hydrogen and the Environment .......................................................................................... 58

6.1.2 MEK and the Environment ................................................................................................. 58

6.1.3 Liquefied Petroleum Gas (LPG) and the Environment: 1-butene, 2-butene, Isobutane, Isobutene, N-butane ........................................................................................................................... 59

6.1.4 SBA and the Environment .................................................................................................. 59

6.1.5 SBE and the Environment ................................................................................................... 59

6.1.6 TBA and the Environment .................................................................................................. 60

6.1.7 Water Handling ................................................................................................................... 60

6.1.8 Furfural and the Environment ............................................................................................. 60

6.1.9 Nitrogen and the Environment ............................................................................................ 60

6.2 Health and Safety ........................................................................................................................ 61

6.2.1 Hydrogen Safety Measures ................................................................................................. 61

6.2.2 MEK Safety Measures ........................................................................................................ 64

6.2.3 Liquefied Petroleum Gas Safety Measures: 1-butene, 2-butene, Isobutane, Isobutene, N-butane 65

6.2.4 SBA Safety Measures ......................................................................................................... 66

6.2.5 SBE Safety Measures .......................................................................................................... 66

6.2.6 TBA Safety Measures ......................................................................................................... 67

6.2.7 Water Safety Measures ....................................................................................................... 68

6.2.8 Furfural Safety Measures .................................................................................................... 68

6.2.9 Nitrogen Safety Measures ................................................................................................... 68

7.0 LIMITATIONS, UNCERTAINTIES, AND ALTERNATIVES .................................................... 69

7.1 Limitations .................................................................................................................................. 69

7.2 Uncertainties ............................................................................................................................... 70

7.3 Alternatives ................................................................................................................................. 70

8.0 CONCLUSIONS AND RECOMMENDATIONS ......................................................................... 72

9.0 WORKS CITED ............................................................................................................................. 74

10.0 WORKS CONSULTED ................................................................................................................. 77

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LIST OF FIGURES Volume 1 TABLE OF CONTENTS ........................................................................................................................... ii Figure 4.1 Overall process flow diagram ..................................................................................................... 5 Figure 4.2 Stage 1: Overall block diagram .................................................................................................. 7 Figure 4.3 Stage 1A: Process flow diagram for water preparation ............................................................ 10 Figure 4.4 Stage 1B: Process flow diagram for feed preparation .............................................................. 11 Figure 4.5 Stage 1C: Process flow diagram for hydration reaction ........................................................... 12 Figure 4.6 Stage 2: Overall block diagram for SBA purification 1 ........................................................... 13 Figure 4.7 Stage 2A: Process flow diagram for reactant/product separation ............................................. 14 Figure 4.8 Stage 2B: Process flow diagram for stream preparation ........................................................... 15 Figure 4.9 Stage 3: Overall block diagram for butane/butene separation .................................................. 16 Figure 4.10 Stage 3A: Process flow diagram for 2-butene extraction ....................................................... 18 Figure 4.11 Stage 3B: Process flow diagram for furfural extraction ......................................................... 19 Figure 4.12 Stage 3C: Process flow diagram for furfural preparation ....................................................... 20 Figure 4.13 Stage 3D: Process flow diagram for LPG storage .................................................................. 20 Figure 4.14 Stage 4: Overall block diagram for SBA purification 2 ......................................................... 21 Figure 4.15 Stage 4A: Process flow diagram for azeotropic separation .................................................... 23 Figure 4.16 Stage 4B: Process flow diagram for water separation ............................................................ 24 Figure 4.17 Stage 4C: Process flow diagram for impure SBA separation ................................................. 25 Figure 4.18 Stage 4D: Process flow diagram for DSBE removal .............................................................. 26 Figure 4.19 Stage 5: Overall block diagram for SBA dehydrogenation to MEK ...................................... 27 Figure 4.20 Stage 5A: Process flow diagram for SBA preparation ........................................................... 29 Figure 4.21 Stage 5B: Process flow diagram for dehydrogenation reaction .............................................. 30 Figure 4.22 Stage 5C: Process flow diagram for product separation ......................................................... 31 Figure 4.23 Stage 5D: Process flow diagram for impure MEK preparation .............................................. 31 Figure 4.24 Stage 6: Overall block diagram for MEK purification ........................................................... 32 Figure 4.25 Stage 6A: Process flow diagram for MEK extraction ............................................................ 33 Figure 4.26 Stage 6B: Process flow diagram for SBA extraction .............................................................. 34 Figure 4.27 Stage 6C: Process flow diagram for MEK storage ................................................................. 35 Figure 4.28 Stage 7: Overall block diagram for DSBE storage ................................................................. 36 Figure 4.29 Stage 7A: Process flow diagram for stream integration ......................................................... 37 Figure 4.30 Stage 7B: Process flow diagram for DSBE storage ................................................................ 37 Figure 5.1: Standard construction costs used to estimate the ISBL by the percentage of delivered equipment cost [15] ..................................................................................................................................... 40 Figure 5.2: Non-discounted cumulative cash flow diagram used to determine profitability measures ..... 49 Figure 5.3: Discounted cash flow diagram used to calculate NPV, break-even point, and DCFROROI .. 50 Figure 5.4: Discounted cumulative cash flow diagram displaying straight line depreciation assumed to calculate the break-even point..................................................................................................................... 53

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LIST OF TABLES Volume 1 Table 2.1 Steam and Catalytic Cracking Compositions [5,6] ...................................................................... 2 Table 2.2 Composition Adjustment, Conversion, and Literature Values [7] ............................................... 2 Table 4.1 Mass/molar Flow rates and Compositions through Hydration Reactors ...................................... 9 Table 5.1: Results from ISBL and OSBL Analysis Showing Calculated FCI ........................................... 39 Table 5.2: Summary of the Costs and Calculations to Find the ISBL ....................................................... 41 Table 5.3: Complete Initial Investment Calculations Detailing the TCI .................................................... 42 Table 5.4: Summary of the Key Costs Used in Creating the Total Operating Cost ................................... 43 Table 5.5: Summary of the Expenses that Constitute the Manufacturing Costs ........................................ 43 Table 5.6: Operating Labor Costs Calculated Using MichiSite Specifications ......................................... 44 Table 5.7: Utilities Cost Summary ............................................................................................................. 44 Table 5.8: Raw Materials Cost Summary .................................................................................................. 45 Table 5.9: Summary of Miscellaneous Costs Adding to Direct Costs ....................................................... 45 Table 5.10: Summary of Components of General Expenses ..................................................................... 46 Table 5.11: General Summary of Expenses Leading to Total Operating Cost .......................................... 47 Table 5.12: Summary of Calculated Revenue per Year ............................................................................. 47 Table 5.13: Summarized Cumulative Cash Flow Table Showing the NPV 12 Years after Start-Up ........ 50 Table 6.1: Average Emission Factors for Fugitive Equipment Leak Emissions [19] ................................ 57 Table 6.2 Control Techniques & Efficiencies Applicable to Equipment Leak Emissions [19] ................. 57 Table 6.3: Combustion & Explosion Properties of Hydrogen, Methane, Propane & Gasoline [40] ......... 62 Table 6.4: Deflagration and Detonation Characteristics [21] .................................................................... 63

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LIST OF NOMENCLATURE General Description PFD Process Flow Diagram P&ID Process and Instrumentation Diagram psig Gauge Pounds per Square Inch lb Pound Mass kg Kilogram ft Feet in Inch hr Hour sec Second yr Year °F Degrees Fahrenheit °C Degrees Celsius Chemical Description MEK Methyl Ethyl Ketone/2-Butanone SBA Sec-Butyl-Alcohol/2-Butanol DSBE Di-Sec-Butyl-Ether TBA Tert-Butyl Alcohol/Tert-Butanol/1-Butanol ppm Parts Per Million M Molar Concentration (mol/L) psi Pounds per Square Inch Economic Description ISBL Inside Boundary Limits OSBL Outside Boundary Limits FCI Fixed Capital Investment WC Working Capital NPV Net Present Value MACRS Modified Accelerated Cost Recovery System TCI Total Capital Investment TOC Total Operating Cost DCFRORI Discounted Cash Flow Rate of Return on Investment RORI Rate of Return on Investment DPBP Discounted Pay Back Period MM Million Environmental Description DOT Department of Transportation LEL Lower Explosive Limit UEL Upper Explosive Limit POTW Publicly-Owned Treatment Works SCBA Self-Breathing Contained Apparatus

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TABLE OF CONTENTS VOLUME 2

Attachments

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8. Petrus, L., et al. "Kinetics and Equilibria of the Hydration of Linear Butenes Over a Strong Acid Ion-Exchange Resin as Catalyst." Chemical Engineering Science 41.2 (1986): 217-26. Web.

9. Gerster, J. A., T. S. Mertes, and A. P. Colburn. "Ternary Systems n-Butane-1-Butene-Furfural and Isobutane-1-Butene-Furfural: Vapor-Liquid Equilibrium Data." Industrial and Engineering Chemistry 39.6 (1947): 792. Web.

10. Julka, Vivek, Madhura Chiplunkar, and Lionel O'Young. "Selecting Entrainers for Azeotropic Distillation." AIChE Journal (2009) Web.

11. Gil, Ivan D., et al. "Extractive Distillation of Acetone/Methanol Mixture using Water as Entrainer." American Chemical Society (ACS) 48.10 (2009) Web.

12. Buell, C. K., and R. G. Boatright. "Furfural Extractive Distillation for Separation and Purification of C4 Hydrocarbons." Industrial and Engineering Chemistry 39.6 (1947): 695. Web.

13. Luyben, William L. Control of the Heterogeneous Azeotropic n-Butanol/Water Distillation System. American Chemical Society. Web.

14. Pavlov, O. S., S. A. Karsakov, and S. Yu Pavlov. "Development of Processes for C4 Hydrocarbons Separation and 1,3-Butadiene Purification." Theoretical Foundations of Chemical Engineering 45.6 (2011): 858. Web.

15. Peters, Max S., Klaus D. Timmerhaus, and Ronald West. Plant Design and Economics for Chemical Engineers. 5th ed. New York, NY: McGraw Hill, 2003. Print.

16. Short-Term Energy Outlook Market Prices and Uncertainty Report. March 2012 ed. U.S. Energy Information Administration, 2012. Web.

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17. "Platts Solvents Assessments." Solventswire 34.27 (2011) Web.

18. Win, David Tin. Furfural - Gold from Garbage. Assumption University; Bangkok, Thailand, 2005. Web.

19. US Environmental Protection Agency (EPA): Office of Air Quality Planning and Standards. "Locating and Estimating Air Emissions from Sources of Methyl Ethyl Ketone." (1994) Web.

20. Hydrogen. 4th ed. Material Safety Data Sheet (MSDS) #1009; Air Products, 1994. Web.

21. Safety and Security Analysis: Investigate Report by NASA on Proposed EPA Hydrogen-Powered Vehicle Fueling Station. Assessment and Standards Division;Office of Transportation and Air Quality; Environmental Protection Agency (EPA), 2004. Web. 3/25/2012.

22. "List of Hazardous Air Pollutants, Petition Process, Lesser Quantity Designations, Source Category List." Federal Register 70.242 (2005): 75047. Web.

23. Methyl Ethyl Ketone. Material Safety Data Sheet (MSDS) No. CM09000; Fisher Scientific, 2009. Web.

24. U.S. Department of Health and Human Services, Public Health Service: Agency for Toxic Substances and Disease Registry (ATSDR). "Toxicological Profile for 2-Butanone." (1992) Web.

25. "Hazardous Waste Operations and Emergency Response." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=standards&p_id=9765>.

26. 1-Butene. Material Safety Data Sheet (MSDS) No. 106-98-9: MESA, 1999. Web. Jan. 11, 2012.

27. Cis-2-Butene. Material Safety Data Sheet (MSDS), C2B: MESA, 2004. Web. 3/25/2012.

28. Isobutane. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

29. Isobutylene. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

30. N-Butane. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

31. Trans-2-Butene. Materials Safety Data Sheet (MSDS); Praxair Web.

32. "Environmental Health Criteria 65 - Butanols: Four Isomers." InChem (1987) Web.

33. Sec-Butyl Ether. Material Safety Data Sheet (MSDS); Sigma-Aldrich, 2011. Web. 34. "Occupational Safety and Health Guideline for Tert-Butyl Alcohol." United States Department of

Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/tertbutylalcohol/recognition.html>.

35. Water. Material Safety Data Sheet (MSDS) No. W0600; Sciencelab.com, Inc., 2005. Web.

36. Furfural. 3.3rd ed. Material Safety Data Sheet (MSDS); Sigma-Aldrich, 2012. Web. 3/25/2012.

37. "Occupational Safety and Health Guideline for Furfural." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/furfural/recognition.html>.

http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=standards&p_id=9765

http://www.osha.gov/SLTC/healthguidelines/tertbutylalcohol/recognition.html

http://www.osha.gov/SLTC/healthguidelines/furfural/recognition.html

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38. Nitrogen (Compressed). 5th ed. 1011 Vol. Material Safety Data Sheet (MSDS); Air Products, 1997. Web.

39. "Occupational Safety and Health Guideline for Nitrogen." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/nitrogen/recognition.html>.

40. Haussinger, Peter, Reiner Lohmüller, and Allan M. Watson. "Hydrogen, 1. Properties and Occurence." Ullmann's Encyclopedia of Industrial Chemistry. 18 Vol. Wiley-VCH Verlag GmbH & Co. KGaA, 2000. 235. Web.

41. Häussinger, Peter, Reiner Lohmüller, and Allan M. Watson. "Hydrogen, 5. Handling." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

42. "Hydrogen." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=9749>.

43. Thompson, Stephen M., Gary Robertson, and Eric Johnson. "Liquefied Petroleum Gas." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

44. "Storage and Handling of Liquefied Petroleum Gases." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=9756>.

45. Sec-Butyl Alcohol (SBA). Material Safety Data Sheet (MSDS) No. B6302; Sciencelab.com, Inc., 2005. Web.

46. Sakuth, Michael, et al. "Ethers, Aliphatic." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

47. Tert-Butyl Alcohol, TBA. 2nd ed. Material Safety Data Sheet (MSDS) #164; Pharmco Products Inc, 2001. Web. 3/25/2012

Appendices Appendix A: Process Flow Diagrams Appendix B: Process and Instrumentation Diagrams Appendix C: Equipment Sizing and Costing Calculations Appendix C.1: Heat Exchanger Sizing and Costing Appendix C.2: Distillation Column Sizing and Costing Appendix C.3: Pump and Compressor Sizing and Costing Appendix C.4: Storage Tank Sizing and Costing Appendix C.5: Reactor Sizing and Costing Appendix C.6: Flash Drum and Boiler Sizing and Costing Appendix D: Piping Sizing and Costing Calculations

http://www.osha.gov/SLTC/healthguidelines/nitrogen/recognition.html

http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=9749




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Appendix E: Economic Calculations Appendix E.1: Capital Costs Appendix E.2: Operating Costs Appendix E.3: Revenue Appendix E.4: Cumulative Cash Flow Diagram Data Appendix E.5: Profitability Sample Calculations Appendix F: ASPEN Modeling Data and Reactor Calculations Appendix F.1: Reactor Modeling Appendix F.2: Stage 1 Hydration Reaction ASPEN Modeling Data Appendix F.3: Stage 2 SBA Purification 1 ASPEN Modeling Data Appendix F.4: Stage 3 SBA Purification 2 ASPEN Modeling Data Appendix F.5: Stage 4 Dehydrogenation Reactor ASPEN Modeling Data Appendix F.6: Stage 5 MEK Purification ASPEN Modeling Data Appendix F.7: Stage 6 Butane-Butene Separation ASPEN Modeling Data Appendix F.8: Stage 7 DSBE Storage ASPEN Modeling Data Appendix G: Plant Layout

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EXECUTIVE SUMMARY MichiPetro, a division of MichiChem, has 20,000 Short Tons per year of an n-butene waste feed. The n-butene feedstock, commonly known as Raffinate 2, is obtained from its petroleum cracking operation. [1] This feedstock is then further purified by the removal of 1-butene for its low density polyethylene (LDPE) operations. This feed has a significant amount of 2-butene, which is the main precursor for the development of Methyl Ethyl Ketone (MEK), an important industrial solvent. [1] ChE Team 17 was assigned to provide a design for a novel plant to produce MEK and to perform an economic analysis on the design to determine whether to invest in the process or sell the waste feed on the open market. The purpose of this report is to describe the proposed process in detail and provide the economic analysis to allow MichiChem to make a decision on the outcome of the waste from LDPE production. The report will present our design basis, our decision criteria, an in-depth overview of all the stages of the process design, analysis on the economic feasibility of the process, environmental, health, and safety analysis, limitations, uncertainties, and alternatives for the process, and a conclusion of the results and recommendations on whether to proceed with the plant design or to sell the n-butene waste feed on the open market. Our novel process is broken up into 7 stages that effectively produce MEK at ASTM standards for shipment and sales. These stages are: (1) the hydration reaction of 2-butene to SBA, (2) the first SBA purification process, (3) the separation of butene from the butanes, (4) the second SBA purification process, (5) the dehydrogenation process of SBA to MEK and other impurities, (6) the purification MEK process, and (7) the storage of DSBE. The process is broken up into a two-step reaction scheme. The n-butene in the feed is hydrated in a reactor with water to produce 2-butanol as the desired product in the first stage. Then the 2-butanol or sec-butyl alcohol (SBA) is purified via distillation in the second and fourth stage. The purified SBA is sent to the second reaction where hydrogen is removed via a brass catalyst from the SBA to produce MEK in the fourth stage. The crude MEK product is then purified to ASTM standards in the sixth stage via separating using distillation columns. The ASTM standards state that the MEK purity must be at least 99.5 wt%, with a maximum of 0.05 wt% water and 0.5 wt% of total alcohols. [2] The third stage takes the unreacted 2-butene from the first reaction in stage 1 and purifies the desired butenes to be recycled to the hydration reaction, while the final stage condenses the waste from the process to be sent off for disposal. Our major assumption was the composition of the waste feed from the LDPE productions, which we assumed to be a hydrocarbon raffinate feed from the catalytic cracking of crude oil that was stripped of 1-butene, isobutene, and isobutene. [3] All decisions made in terms of the technical process design were based on two highly quantifiable factors, efficiency and cost. In terms of the decisions we made, we chose to look first at the efficiency and then at the cost. In terms of efficiency, the quantifiable aspects we observed are conversions percentages, selectivity percentages, purity of separations, and flow outputs. Our economic feasibility analysis allowed us to use our equipment sizing and costing and extrapolate to estimate the total capital investment that our process design would take to get up and running producing ASTM standard MEK. In addition, we used modeling programs to create a process flow diagram that allowed us to estimate the amounts of inputs and utilities we will need from MichiSite in order to produce MEK. From these utilities costs, along with making some assumptions about employee costing, we were able to make an estimate of the total operating cost of our plant yearly. Finally, based on the market prices of our feed and products, we were able to estimate revenue for our plant based on the process flow diagrams that we developed. All of these values were used to determine our profitability criterion that is utilized in order to determine whether our process is worth investing in.

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Our economic analysis set us at a break-even point of 26.4 years with a net present value of – $43.44 MM 12 years after start up. A net present value after for a certain year after start up is defined as the amount of money earned above the investments and the earnings on those investments at a defined interest rate. In this way, this means that after the operating life of the plant has expired, we still have not made a profit above the investor’s capital investment despite taking into account the time value of money. The break-even point tells us that it will take almost two operating lives of the plant in order to make back the total capital investment given to us to start back the plant, which is not a possible option given that the typical operating period for a given design is around 10 years. From looking at the alternative option of selling the waste feed on the open market, we found that this generates revenue of $2.94 MM per year. We believe that the operating costs and the capital cost to create a storage and shipment facility for the waste feed would be much cheaper than the revenue generated from selling it on the open market, which would create a profit for MichiChem. Findings from our Environmental, Health, and Safety analysis show that the greatest hazard is the explosive nature of many of the materials involved in our process. Namely, they are hydrogen, MEK, LPG, SBA, SBE, TBA, and furfural. The next greatest hazard is the various ecological effects to the environment and toxicological effects in the workplace of the materials. The equipment involved in our process design is built to contain these hazardous materials at all times under industry-established stable conditions, with one instance of controlled and safe venting of a hydrogen-MEK vapor mixture. Health and safety of plant personnel and the surrounding community are considered paramount and require OSHA regulated preventative, incident response, and disposal measures as describe in section 6.0 of this report. Based on our economic feasibility analysis, we can conclude that our novel process design to produce MEK accomplishes the goal of producing ASTM standard MEK, but due to the high capital cost involved with creating this plant and the operating costs we believe that this plant is not profitable for MichiChem to invest in because of the short operating period. Over a longer term, our projections indicate that this plant will generate a profit, but due to our assumptions this is not possible to accurately estimate. We also conclude that the waste feed is a profitable venture to undergo in lieu of our designed MEK process. Thus, our final recommendation to MichiChem is that they pursue the avenue of trying to sell the waste feed from LDPE production on the open market in order to obtain a profit.

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1.0 INTRODUCTION MichiPetro, a division of MichiChem, has 20,000 short tons per year of n-butene available. The n-butene feedstock, commonly known as Raffinate 2, is obtained from its petroleum cracking operation. This feedstock is then further purified by the removal of 1-butene for its LDPE operations. Using this feedstock, it has been proposed to MichiChem to produce methyl ethyl ketone (MEK) via an alcohol intermediate, 2-butanol, also known as sec-butanol. [1,3] ChE Team #17 has been assigned to design a plant to produce MEK. The plant will be built on MichiSite and the n-butene feedstock will be supplied via pipeline. We have been tasked to advise MichiChem by assessing the economic profitability of the plant design to produce MEK against selling the n-butene feedstock on the open market. Methyl ethyl ketone is colorless, low-viscosity, flammable liquid with a characteristic ketone odor. MEK is a solvent, with properties similar to acetone. However, MEK has advantages over acetone due to MEK’s very high power of dissolution, high ratio of dissolved matter/viscosity, miscibility with a large number of hydrocarbons, and favorable vole/mass ratio due to its low density. Its applications include production of paints, lacquers, varnishes, paint thinners and removers, adhesives, sealants, printing inks, cosmetics, and pharmaceuticals. MEK can be used as an activator for oxidative reactions, as a selective extractive agent, as a solvent for dewaxing mineral oil fractions, and as a chemical intermediate. The global demand for MEK is growing 3% each year due to its removal from the HAP (hazardous air pollutant) list in 2005 and the growing economies in China and India. However, the US Occupational Safety and Health Administration (OSHA) permissible exposure limit (PEL) is 200 ppm. MEK is somewhat hygroscopic, meaning that MEK absorbs water from the air. So it must be stored in the absence of oxygen, as peroxides may form and cause explosions because of instantaneous decomposition of the peroxides. Carbon steel, stainless steel, and aluminum containers are recommended for storage and transportation, but only carbon steel is recommended for long-term storage. [1,2,3] The purpose of this report is to provide an economic analysis of pursuing a plant to produce MEK using the 20,000 short ton feed of n-butene or to sell the n-butene on the open market. 2.0 DESIGN BASIS The overall design basis for the MEK process was constructed using the given material outlined in the project statement along with a number of constraints. Using this material and constraints, we developed specific assumptions to determine the theoretical construction of the plant, the economic potential, and final investment advice for MichiChem. The given facts concerning the overall process stated that MichiSite would receive 20,000T/yr of n-butene from a low density polyethylene (LDPE) production facility operated by MichiPetrol, a MichiChem subsidiary. This feed of n-butene is to be received via pipeline directly onto the MichiSite location. In addition to this given information, a series of constraints were also posed in the project statement and MichiSite Data sheet. In the project statement, we are tasked with producing MEK from n-butene through the formation of an alcohol intermediate. This process is a common practice in industry because it provides relatively efficient overall conversion for the entire process. In the MichiSite data sheet, we are given the location and operation conditions of the facility. The process is to be constructed in northern Ann Arbor manned by four shifts working year round. Due to the seasonal changes, the water cooling provided by MichiSite varies between 75°F in the summer and 50°F in the winter. The process will remain on stream for 93% of the time with a 40% minimum during turn-down. In addition to operating

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conditions, a number of economic constraints are also posed. The production plant is to be subject to a 48% federal tax and a 4% state tax with a return on investment, or hurdle rate, of 22%. The depreciation method will follow the MACRS schedule with a zero percent salvage value for the plant at the end of plant life. Using these given conditions and constraints, we are able to develop specific assumptions in order to evaluate the project objectives. Our largest assumption comes from the state of the feed that enters the plant. Though the condition states that 20,000 T/yr of n-butene enters the plant, specification of the composition, temperature, pressure, and flow rate are not provided. In order to assess the composition, further research into LDPE production is required. The feed for LDPE production facilities originates from the products of catalytic and steam cracking.[5,6] The compositions for the products of these cracking processes varying even amongst similar processes therefore an average is taken to provide equal representation of all cracking processes. These compositions are detailed in Table 2.1 below: Table 2.1 Steam and Catalytic Cracking Compositions [5,6]

Compnent

Catalytic Cracking

(vol%)

Steam Cracking

(vol%)

Steam Low Severity

Cracking (vol%)

Steam High Severity Cracking

(vol%)

Catalytic Cracking

(vol%) Average (vol%)

2-butene 23 9 14 11 23 16

n-butane 13 6 4 3 13 7.8

isobutane 37 2 2 1 37 15.8

isobutene 15 26 32 22 15 22

1-butene 12 15 20 14 12 14.6

1,3-butadiene 0.5 43 26 47 0.5 23.4

other 0 0 2 2 0 0.8

Our assumption also includes the purification of this cracking feed for the removal of 1,3-butadiene and other impurities before being passed to the LDPE production facility. After purification, the LDPE plant removes 1-butene and isobutene in large amounts for use in the production process. Additionally, isobutane, due to the ease of its removal, is also removed in large quantities. These composition changes and subsequent conversion from volume percent to mass percent are detailed in Table 2.2 below:

Table 2.2 Composition Adjustment, Conversion, and Literature Values [7]

Components

After Purification

(vol%) Liquid Density

(kg/m3)

Mass Conversion

(kg) Mass Percent

(wt%)

Mass Percent After LDPE

(wt%)

Literature Composition

(wt%)

2-butene 20 626 12520 20 76.3 78.3

n-butane 6 601.4 3608.4 5.8 22.1 19.85

isobutane 2 593.4 1186.8 1.9 0.5 0

isobutene 46 626.2 28805.2 46.1 0.5 0.4

1-butene 26 630 16380 26.2 0.5 0.67

Other 0 0 0 0 0 0.31 The composition of the material leaving LDPE production is assumed to be the composition of the material entering into the MichiSite plant. Additionally, listed above is the literature composition for the feed of a pilot MEK production plant which validates our assumption of feed origin.

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Our feed flow rate was determined by the given amount of n-butene per year, 20,000 T/yr, and the number of available man hours per year to find a value of 5208 lb/hr. Additionally, our pressure was taken to be 58.8 psi with a temperature of 104°F, which are the conditions of the feed during the summer months. We took these specific conditions because they represent the summer months in Ann Arbor that cause the greatest amount of strain on the process as the feed is hardest to keep liquefied. Additionally all of our cooling water streams were taken to be 75°F, which also represents the summer conditions when cooling is least effective. 3.0 DECISION CRITERIA The following section explains the technical, economic, and the environmental, health, and safety criteria on how decisions were prioritized. 3.1 Technical Criteria

All decisions made in terms of the technical process design were based on two highly quantifiable factors. These two factors were efficiency and cost. In terms of the decisions we made, we chose to look first at the efficiency and then at the cost. In terms of efficiency, the quantifiable aspects we observed are conversions percentages, selectivity percentages, purity of separations, and flow outputs. In many decisions, these aspects were maximized by conducting research on optimal conditions before estimating the pricing cost (e.g., catalytic resins were chosen for higher conversion per pass before researching fixed cost investment). 3.2 Economic Criteria

A key restraint in our process is design is the economic feasibility. The goal of our is to determine if taking the waste feed to produce MEK is profitable or if it would be a better option to sell the waste feed from LDPE productions on the open market. Therefore, when designing our plant, we minimized the necessary materials and components in order to accomplish the goal of producing ASTM standard MEK. We chose to create our distillation setups in such a way to remove the most easily separable components first and leave the complex distillations last in order to minimize the materials moving through the second column. This allowed us to design columns using our ASPEN modeling programs that were as small as possible. When determining the flow of cooling water through condensers and heat exchangers we specified our outlet streams to be the maximum possible temperature to return to the cooling towers in order to minimize the cost of cooling water on our components. All of our decisions took this into account. 3.3 Environmental, Health, and Safety Criteria

The aspects to consider here are community and employee health and safety. We will not implement designs that undermine environmental, health, and safety standards governed by authorities such as OSHA and the EPA. Strict enforcement of adherence to safety procedures in the work environment in the form of training, periodic meetings to review safety and possible incidents, and PPE checks for malfunctions will be monitored. Programs will be established to reward performance of exceptional adherence to environmental, health, and safety standards. In all, these aspects were put above technical efficiency and economical gain in our MEK plant design. 4.0 PROCESS DESIGN

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The production of methyl ethyl ketone (MEK) from an n-butene mixture with a sec-butyl alcohol (SBA) intermediate has been developed as a seven-stage process. These stages are: (1) the hydration reaction of 2-butene to SBA, (2) the first SBA purification process, (3) the separation of butene from the butanes, (4) the second SBA purification process, (5) the dehydrogenation process of SBA to MEK and other impurities, (6) the purification MEK process, and (7) the storage of DSBE. Input impurities are extracted in stages 2,3,4 and 6 and used in a variety of manners such as being resold as liquefied petroleum gas, being released to the atmosphere, and storage for waste hauling. The overall process flow through the seven stages is shown in Section 4.1, followed by a discussion of each individual stage in Section 4.2 through 4.8. In the process flow diagrams for each stage, the stream temperatures are displayed in rectangles in units of degrees Fahrenheit and stream pressures are displayed in circles and are in units of pound per square inch (psi). The stream numbers are displayed in diamonds with flow rates in ovals. 4.1 Overview of Process The overall block diagram of the process is presented in Figure 4.1 and shows the stage-to-stage flow of material through the MEK production plant. This high level process overview of MEK’s proposed process design shows all feed, waste, and product streams, stream compositions, and flow rates. The process input and product output streams are flagged and the key process streams are shown with bolded arrows.

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From LDPE Production Pant

Stage 1Hydration Reaction

Stage 2SBA Purification 1

Stage 4SBA Purification 2

Stage 6MEK Purification

Stage 5Dehydrogenation

Reaction

Stage 3Butane/Butene

Separation

5208 lb/hr76.4 wt% 2-butene22.1 wt% n-butane0.5 wt% isobutane0.5 wt% isobutene0.5 wt% 1-butene


27.3 wt% SBATrace wt% TBA1.0% wt% DSBE3.6 wt% Water



10363 lb/hr99.9 wt% 2-butene

654 lb/hr100 wt% water

5936 lb/hr85.6 wt% SBA0.3 wt% TBA

3.1 wt% DSBE11.0 wt% Water

275 lb/hr99.9 wt% DSBE


4967 lb/hr1.4 wt% SBA

0.2 TBA88.3 wt% MEK10.1 wt% DSBE


1.8 lb/hr55.6 wt% MEK

43.4 wt% H2

0.1 wt% DSBE

4833 lb/hr99.7 wt% MEK0.3 wt% TBA


99.8 wt% DSBE


99.9 wt% DSBE

Sold As Liquified Petroleum Gas

To Loading Dock


Makeup Water

Exhaust

LDPE Waste

Unrefined SBA

Recycle butene

Unrefined Recycle

Liquefied Petroleum Gas

Impure SBA Recycle Water

Purified SBA

Waste

Waste

Waste

Unrefined MEK

SBA Recycle

MEK

Stage 7DSBE Storage

Figure 4.1 Overall process flow diagram

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The first half of the process involves the hydration of 2-butene and purification of the product stream from the hydration reactors. At the start of the process, input from an LDPE production facility enters Stage 1 as a mixture of butenes and butanes arriving at a flow rate of 5208 lb/hr. At Stage 1, specific components are reacted in a hydration reaction with water to yield a mixture composed of the feed materials and product alcohols which are sent to the first, Stage 2, of two purification processes for the extraction of SBA. In this first purification process, the unreacted feed components are separated from the products. Due to the low conversion of 2-butene to SBA in Stage 1, there is a large amount of unreacted feed, 12213 lb/hr which is separated from the relatively smaller amount of product. Stage 3 received the unreacted feed components and separates most of the 2-butene from the impurities to be sent back to Stage 1. The impurities are sold as liquefied petroleum gas from Stage 3. The products separated in Stage 2 are sent for further purification in Stage 3 in order to separate the SBA from reaction byproducts in order to be sent to the dehydrogenation reactor, Stage 5. Water is also separated in Stage 4 and sent to a deionization process in Stage 1 in order to remove cations and anions so that the water be recycled for further use in Stage 1. The di-sec-butyl ether, DSBE, is also separated in Stage 4 and combined with the DSBE byproduct of Stage 6 and sent to Stage 7 for storage. The second half of the process involves the dehydrogenation of SBA. The purified SBA is sent to Stage 5, the dehydrogenation reactor, in order to be converted to MEK. After reacting, hydrogen gas is formed and released to the atmosphere along with a negligible amount of MEK. The liquid products of the reaction are sent to the MEK purification process, Stage 6, where DSBE is separated and combined with the identical byproduct in Stage 4 for storage. Additionally, unreacted SBA is sent back to Stage 5 for further reaction while MEK is sent to loading docks for sale. The materials of construction for the entire process consist of primarily carbon steel, stainless steel, and 304 stainless steel. The pumps are all composed to stainless steel whereas the deionized water stream and attached heat exchanger are made from 304 stainless steel. All other equipment is constructed from carbon steel. Process flow diagrams (PFDs) and piping and instrumentation diagrams (P&IDs) showing the details of each stage are located in Appendices A & B, respectively. Additionally, all calculations for equipment sizing are located in Appendices C & D. A diagram of the layout of the proposed plant is located in Appendix G. 4.1 Stage 1: N-Butene Hydration Reaction

The hydration process is the chemical reaction between the double bond in the butene structure with the different polar ends of a water molecule. This results in the addition of hydrogen to one of the double bonded carbons and the addition of a hydroxyl group to the opposing double bonded carbon. The overall objective of this stage is to create alcohol intermediate necessary to produce MEK in a secondary reaction. The stage function by receiving the input feed from the LDPE production process, combining it with a recycle feed of pure 2-butene, and reacting the combined mixture with 1.5 times the molar equivalent of water to produce SBA at a conversion of roughly 14% with a selectivity for SBA of 98% [7]. The raw effluent stream will be feed to Stage 2 for purification. Stage 1 is divided into 3 sub-stages shown in the overall block diagram in Figure 4.2.

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Stage 1A:HEAT

EXCHANGER

Stage 1C:HYDRATION

REACTOR

Stage 1B:STORAGE

TANK

Stage 1B:BOILER

Stage 1B:PUMP

P-33Stage 1A:DEIONIZER







Raffinate from MichiPetrol

Recycle Stream

Makeup Water

Recycle Stream

Stage 6

Stage 6

Cooling Water

Water Collection

Stage 2





Dehydrogenation Heating Water

MEK Purification Heat Up

Warm Water

Cold Water

Unrefined SBA

Figure 4.2 Stage 1: Overall block diagram

4.1.1 Objective The objective of Stage 1 is to use the inputs of deionized water and LDPE production waste to convert the primary component of the waste, 2-butene, into the intermediate secondary alcohol, SBA, in order to produce MEK in Stage 6. The impure SBA output from the hydration reactor has a relatively low amount of SBA due to the low conversion (14%) through the reactor. The reactor itself is a combination of four reactors in both series and parallel. The specific flow rates and stream compositions of the input waste, input water, and impure product are shown in Figure 4.2 above. 4.1.2 Background The input feed for the process comes from the production waste of low density polyethylene (LDPE) plant which in turn receives their feed from raw raffinate. The raw raffinate initially contains large amounts of isobutene and 1-butene but these two components are removed in large quantity for the production of LDPE. Additionally, in the LDPE production process, isobutane is removed and separated from the waste. Thus, the waste from the LDPE process contains large weight percent values of 2-butene and n-butane and almost trace amounts of isobutane, isobutene, and 1-butene. [5,6] The main reaction of the hydration process occurs between a molecule of 2-butene and a hydronium molecule as shown in Equation 1. [7] The individual steps are shown in Equations 2, 3, and 4 which details the protonation of the 2-butene double bond, followed by the addition of the hydroxyl group. However, this is only the theoretical equation for the formation of SBA. Under these conditions and even in the excess of water, the concentration of hydronium molecules available for the first step of the reaction is little in comparison and is therefore the limiting step of the overall reaction.

1A: Water preparation 1B: Feed preparation 1C: Hydration reaction

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𝐶4𝐻8 + 𝐻2𝑂 ⇋ 𝐶4𝐻10𝑂 (1) 𝐶𝐻3𝐶𝐻 = 𝐶𝐻𝐶𝐻3 + 𝐻3𝑂+ ⇋ 𝐶𝐻3𝐶𝐻2𝐶+𝐻𝐶𝐻3 + 𝐻2𝑂 (2)

𝐶𝐻3𝐶𝐻2𝐶+𝐻𝐶𝐻3 + 𝐻2𝑂 ⇋ 𝐶𝐻3𝐶𝐻2𝐶𝐻𝐻2𝑂+𝐶𝐻3 (3) 𝐶𝐻3𝐶𝐻2𝐶𝐻𝐻2𝑂+𝐶𝐻3 + 𝐻2𝑂 ⇋ 𝐶𝐻3𝐶𝐻2𝐶𝐻𝑂𝐻𝐶𝐻3 + 𝐻3𝑂+ (4)

An acid catalyst is usually present in order to aid the progress of the reaction. In an acid-catalyzed hydration reaction, the acid transfers a proton to the double bond of 2-butene to form the intermediate carbocation since it acts as the solvated hydronium molecule. Catalysts come in a variety of methods by which they can be implemented into the process. One method is to add a strong acid to the water/butene mixture. However, this is very inefficient as the aqueous acid must be removed via an additional stripping process which adds to the already extensive equipment costs presented in the overall process. The second method is by implementing a strong acid resin catalyst. This resin operates using specific reaction sites for the necessary reactions to occur.[7] However, there are limitations to using a resin. There is a temperature and pressure drop maximum limit allowed for the operating of the resin before its integrity is compromised. In addition to the formation of SBA via hydration of 2-butene, the secondary alcohol is also formed in small amounted during the hydration of the 1-butene impurity [8]. The 1-butene can isomerize during the hydration mechanism to form a 2-butene isomer that can then be hydrated to form SBA. However this only occurs in small amounts as the rest may be converted to either 1-butanol or remains unreacted. Since 1-butene itself is in such small amounts, the 2 reaction routes are negligible additions to the process since they cannot be assessed properly. Isobutene, unlike 1-butene, only has one route which it proceeds along. This is the formation of tert-butyl alcohol (TBA). TBA occurs in such small amounts and is similar in characteristics to both SBA and MEK that it is usually left in the MEK final product as an inherent impurity. [8] Reaction impurities do not always form by the hydration of already present impurities in the feed but also through by-reactions. The only by-reaction of concern is that of the formation of DSBE. This occurs through the reaction of a molecule of either 1-butene or 2-butene with that of a molecule of SBA [7]. This is a very disruptive by-reaction as it is utilizing both the main reactant and the main product of the process to form a molecule of little use. The equipment required for Stage 1 includes a deionizer, heat exchanger, storage tank, boiler, compressor, four hydration reactors, four pumps, a nitrogen stream and a cooling stream for the reactors. Equipment specifications for Stage 1can be found in Appendix C. The deionizer functions to prevent cations and anions from accumulating in the water supply from the city water input so that the reaction can proceed in the best possible manner. The incoming city water volumetric flow rate is about 5 gpm, so we chose an adequate sized deionizer. Product specification for this deionizer are located in Appendix C. Since the water is coming in at ambient temperature, a heat exchanger is necessary to increase it to the necessary reaction pressure condition. The storage tank is designed to hold four days of incoming raffinate feed. The storage tank also includes a nitrogen stream in order to eliminate the presence of oxygen which could possibly ignite the highly combustible materials. The boilers serve to vaporize the incoming feed and recycle stream mixture. The pump increases the pressure of the feed to the necessary reaction condition pressure. Due to the varying chemical properties of the two reactants, namely their polarities, there is very little mixing present during the reaction which causes a very low conversion of 2-butene to SBA to occur. This

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results in a large recycle stream of 2-butene. In order to overcome this, four hydration reactors are used. They are set in series, in order to increase the overall conversion per overall pass, and in parallel, in order to compensate for the large recycle stream. These reactors operate at a temperature of 311°F and at a pressure of 1170 psi. These conditions are set such that the by-reaction occurring are minimal and but the main reaction is occurring at near optimal conditions. Pressure drop through the reactor is limited to 435 psi in order to keep the integrity of the resin intact. Therefore, a compressor is placed between the reactors in series to increase the pressure back up to 1170 psi in order to pass through the second series at the optimal pressure setting. Since the reaction itself is exothermic, the implementation of a cooling system is necessary to prevent a runaway reaction. 1.39E06 kJ/hr are produced by the reaction which necessitates a cooling water flow of 10571 lb/hr in order to keep the reaction at steady temperature [7]. Knowing the conversion per pass of a single reactor to be 14% of 2-butene and the selectivity to be 98% SBA, we are able to calculate the steady state amount recycled back into the reactor assuming 99.9% recovery of 2-butene through the SBA purification processes [7]. Table 4.1 below shows the flow rates and compositions of each component passing through the first and second series of reactors. Table 4.1 Mass/molar Flow rates and Compositions through Hydration Reactors

Components

1st Reactor Input (lb/hr)

1st Reactor Input

(g-mol/hr) Composition

(%)

1st Reactor Output/2nd

Reactor Input (lb/hr)

1st Reactor Output/2nd

Reactor Input


(%)

2nd Reactor Output (lb/hr)

2nd Reactor Output


(%)

2-butene 15003 121275 82.668 12861 103957 70.863 11024 89112 60.744

n-butane 1151 8981 6.342 1151 8981 6.342 1151 8981 6.342

isobutane 26 203 0.143 26 203 0.143 26 203 0.143

isobutene 26 210 0.143 22 181 0.123 19 155 0.106

1-butene 26 210 0.143 22 181 0.123 19 155 0.106

SBA 0 0 0.000 2669 16329 14.705 4956 30326 27.309

TBA 0 0 0.000 5 29 0.026 9 54 0.049

DSBE 0 0 0.000 98 340 0.538 181 631 0.998

DI Water 1917 48244 10.562 1241 31236 6.839 662 16657 3.647

The amount of 2-butene converted, SBA formed, DSBE formed and TBA formed where calculated using an iterative method in Microsoft Excel. A sample calculation for the process is shown in Appendix F. 4.1.3 Process Description The design for Stage 1 is divided into three sub-stages as labeled in Figure 4.2. In Stage 1A, the recycled water and city water pass through a deionizer and prepared for the hydration reaction using pumps and a heat exchanger. In Stage 1B, the input feed is received from LDPE production and is stored then combined with the recycle 2-butene feed and subsequently prepared for the upcoming reaction. The flow rate and stream compositions shown in Table 4.1 are for summer operation as these conditions are much more difficult to manage. Seasonal flow rates and stream compositions are specified in the PFDs located in Appendix A.

4.1.3.1 Stage 1A: Water Preparation The objective of Stage 1A is to prepare the water input for the hydration reactors. This process diagram is shown in Figure 4.3:

10

1170

444

455

75 84.7

164 50P-50

WATER DEIONIZERR-102

183 84.7

PUMPP-105

HEAT EXCHANGERE-101

451

311

Makeup Water2019 lb/hr

100 wt% water

Recycle Stream654 lb/hr

100 wt% water

Dehydrogenation Heating Steam44020 lb/hr

100 wt% water

MEK Purification Heat Up44020 lb/hr

100 wt% water

HYDRATION REACTORWATER FEED


To Stage 1C

From Stage 6

To Stage 6

105

303 106

405

PUMPP-106

Figure 4.3 Stage 1A: Process flow diagram for water preparation

The makeup water stream (stream 105) in transported to the MEK production facility via pipeline and is therefore subject to the ambient conditions dictated by seasonal changes. The recycle stream (stream 303) is determined by the conditions at which it leaves the butane/butene separation process (Stage 3). These two streams, 105 and 303, are fed to the water deionizer (R-102) via pumps P-104 and P-303 (shown in Section 4.5.3.2), respectively. Streams 105 and 303 are mixed and purified with in the deionizer resulting in a combined stream (Stream 106) with a flow rate of 1917 lb/hr. The deionized water passes through a series of pumps in order to attain the optimal pressure, 1170 psi, for the following reaction. The pump is labeled P-105 but is composed of 12 pumps in series. The temperature of Stream 106 is raised to 311°F through a heat exchanger (E-101). The heat exchanger uses a steam stream (Stream 405) that is previously used to heat a process in Stage 6. After raising the temperature of the deionized water to the necessary value, the heating water is passed back to Stage 6 to provide heat for other processes. The deionized water is passed to Stage 1C where it will enter the hydration reaction process.

4.1.3.2 Stage 1B: Feed Preparation The objective of Stage 1B is to combine the LDPE waste feed with the recycle feed and prepare the combined mixture for the hydration reaction process. The process diagram is shown in Figure 4.4:

11

1170

38.5

60

103

311

104 64.5 STORAGE TANKTK-101

PUMPP-101

101

PUMPP-103

60.3 B-101

To Stage 1C

Raffinate from MichiPetrol



99.9 wt% 2-butene

Hydration ReactorButene Feed15571 lb/hr

92.4 wt% 2-butene7.1 wt% n-butane0.2 wt% isobutane0.2 wt% isobutene0.2 wt% 1-butene

604

PUMPP-103

64.5

67.1

MichiSite Steam

To MichiSite Steam Return

108489

615


100 wt% Water

PUMPP-102

From Stage 3

Figure 4.4 Stage 1B: Process flow diagram for feed preparation

The LDPE production waste (Stream 101) is fed to the storage tank via pipeline and exits at the same rate, 5208 lb/hr. The feed is composed of five materials with the desired component being 2-butene at 76.4 wt%. The storage tank (TK-102) holds the capacity for four days’ worth of feed. This feed is subject to the conditions dictated by seasonal changes. The conditions shown above are with respect to summer conditions as they are much more difficult to maintain. From the outlet of TK-102, the Stream 101 is combined with a recycle stream of pure 2-butene (Stream 604) at a flow rate of 10363 lb/hr. The combined stream (stream 103) is then pumped (using pump P-103) into a boiler that heats the liquefied materials to 311°F. The heater uses a steam stream (Stream 108) from MichiSite to heat the feed. After this, the stream feeds into a pump (P-103) necessary to reach the optimal pressure at which the reaction occurs, 1170 psi. The feed is then passed on to Stage 1C for the hydration reaction.

4.1.3.3 Stage 1C: Hydration Reaction The objective of Stage 1C is to receive the inputs from Stages 1A and 1B and allow an efficient reaction to take place. The process flow diagram of Stage 1C is shown in Figure 4.5 below:

12

103 311 1170

311

725

701

725

311

701

1170

104

104

311

311

725

725

1063111170

R-702: Packed Bed

Reactor

R-701: Packed Bed

Reactor

R-703: Packed Bed

Reactor

R-704: Packed Bed

Reactor


Hydration ReactorButene Feed

HYDRATION REACTORWATER FEED



15.2 wt% SBATrace wt% TBA0.5 wt% DSBE6.8 wt% Water

Inter-Reactor Flow18149 lb/hr



Unrefined SBA

Pump P-701

To Stage 2From Stage 1B

From Stage 1A

Figure 4.5 Stage 1C: Process flow diagram for hydration reaction

The butene feed stream (stream 103) is split into two identical streams each with half the amount of throughput which then enter the first set of hydration reactors (R-701 and R-702). The reactors contain an acid catalytic resin, Amberlyst 70 from Dow Chemical. Within each reactor is 12117 liters of catalyst. As the feed enters the reactor, simultaneously, the water feed stream (stream 106) also enters the first set of reactors. Note that the water is a liquid at this temperature and pressure, 311°F and 1170 psi, and is therefore introduced into the reactor by sprays located throughout the inside of R-701 and R-702 in order to increase contact with the butene feed. Once the materials pass through the first set of reactors and out, the identical outputs are combined into a single stream (stream 701). Stream 701 is at a lower pressure due to the 445 psi pressure drop through R-701 and R702. Stream 701 enters a pump (P-701) in order to raise the pressure back to the optimal reaction setting of 1170 psi. Water is not required to be fed into the second set of reactors (R-703 and R-704) as it is already mixed well in R-701 and R-702. R-703 and R-704 both contain the same resin catalyst but at a volume of 10387 liters of resin. The output conditions of R-703 and R-704 is identical to those of the first set of reactors but the composition of the second set of reactors displays a larger SBA component. 4.2 Stage 2: SBA Purification 1

The first SBA purification process serves as way to separate the unreacted feed from the reaction products. The overall objective of this stage is separate SBA by grouping it with the other alcohols, DSBE, and water which have significantly different boiling points than the feed butene and butanes. Therefore the output from this stage will be a stream going to the butene/butane separation, Stage 3, and a stream proceeding to the next step in the SBA purification process, Stage 4. Stage 2 is divided into 2 sub-stages shown as Stage 2A and Stage 2B in the overall block diagram in Figure 4.6 below:

13

Stage 2A:CONDENSER

Stage 2A:DISTILLATION

COLUMN

Stage 2A:CONDENSER

Stage 2A:REBOILER

Stage 2B:HEAT

EXCHANGER



Unrefined SBA

Unrefined Recycle12213 lb/hr




Impure SBA

MichiSite Cooling Water27000000 lb/hr100 wt% water

MichiSite Cooling Water1309000 lb/hr100 wt% water

MichiSite Cooling Tower

MichiSite Cooling Tower

Figure 4.6 Stage 2: Overall block diagram for SBA purification 1

4.2.1 Objective The objective of Stage 2 is to separate the SBA so that a purified component can be reacted in the dehydrogenation reaction (Stage 5). The unrefined SBA feed to Stage 2 contains high amounts of 2-butene which much be recycled in order to reduce costs. The specific flow rates and stream compositions (in wt%) of the unrefined SBA, unrefined recycled, and impure SBA are shown in Figure 4.6. The specific flow rates and stream compositions are shown in Figure 4.6 above. 4.2.2 Background In general, distillation columns function by separating two mixtures of differing boiling points. The component with the higher boiling point is termed the heavy key while the component with the lower boiling point is termed the light key. At the very bottom of the column, the liquid phase is heated and enters the vapor phase with some composition of both the light and heavy key components. As the vapor rises through the column, the temperature decreases and the heavy key composition become steadily less as it condenses while the light key remains in the vapor state. Eventually, at the top of the column, the distillate exits which, if the column is properly operated, will contain a high purity of the light key. The distillate eventually passes through a condenser in which some amount of the condensate exits the apparatus as the distillate flow while the rest is sent back into the column as a liquid in a stream termed the reflux. The reflux ratio is the ratio between the reflux and distillate exit flow. Conversely, at the bottom of the column is the liquid which theoretically contains a high purity of the heavy key. The bottom of the column exits through a stream which is split into the bottoms and a reboiler stream. The reboiler stream enters a reboiler which vaporizes the liquid and enters the column as a vapor. The temperature of the column is not the only aspect which determines the purity of the distillate and bottoms flows. A column also includes trays which allow the vapor to contact the liquid in an efficient manner throughout the height of a column. The column is typically sized using the number of theoretical stages which summation of the number of trays plus the reboiler at the bottom as a final stage. The distillation column in Stage 2 functions similarly to the column described above. In this case, the light key refers to the 2-butene, 1-butene, isobutane, isobutene, and n-butane. These components have a significantly lower boiling point than the components that compose the heavy key. The heavy key components are composed of SBA, TBA, DSBE, and water. The reason for this separation is that the light

2A: Reactant/product separation 2B: Stream preparation

14

key components are also the unreacted feed components of which 2-butene is required to be recycled. It is necessary to separate 2-butene from the heavy key components as the heavy key contains the products of the reaction which will eventually proceed to further reactions. Other equipment in this stage includes two heat exchangers, discounting the condenser and reboiler of the distillation column. Equipment specifications for Stage 2 can be found in Appendix C. 4.2.3 Process Description The design of Stage 2 has been divided into two sub-stages as labeled in Figure 4.6 above. In Stage 2A, the unrefined SBA is prepared for the distillation process by cooling the stream and is then sent into a distillation column. The distillation column separates the mixture into unreacted feed components and reaction product components with the former exiting the top as a distillate, or unrefined recycle, and latter exiting as the bottoms, or impure SBA. The unrefined recycle is sent on to Stage 3 for the butene/butane separation while the impure SBA proceeds to Stage 2A for cooling. Preparation for Stage 4 requires that the impure SBA be cooled to a lower temperature which is accomplished using a heat exchanger and cooling water.

4.2.3.1 Stage 2A: Reactant/product Separation The objective of Stage 2A is to separate the unreacted 2-butene and various feed impurities from the SBA and impurity products. The process flow diagram of Stage 2A is shown in Figure 4.7 below.

To Mich

iSite

Cooling T

ower

T-201: Hydrocarbon Separator

104

311

725

From Stage 1

E-202: Condenser

E-203: Reboiler

202 275 79.5

P-202

P-201

E-201: Heat Exchanger

150

204

75

84.7

From M

ichiSi

te Cooling W

ater

118

To Mich

iSite Coolin

g Tower

75

84.7

120

205

From M

ichiSi

te

Cooling W

ater

206489

614

207

127

77.5

207 271 79.5


Cooling WaterHydration Reactor

Butene Feed18149 lb/hr


5002 lb/hr100 wt% steam

Steam



Impure SBA

201 127 77.5 To Stage 3

To Stage 2B




Cooling Water

Reflux12213 lb/hr




Reboiler Reflux

Figure 4.7 Stage 2A: Process flow diagram for reactant/product separation

The unrefined SBA enters from Stage 1 through Stream 104 at 18149 lb/hr. In order to separate the products from the recycle, a distillation column is used (T-201). Prior to this, Stream 104 must be cooled using a heat exchanger (E-201) to bring the temperature down from 311°F to 150°F. The unrefined recycle exits as the distillate from T-201 where it enters a condenser to change from vapor to liquid phase. The stream is then split into a reflux and Stream 201, the unrefined recycle stream. The reflux enters back into T-201 and Stream 201 is passed on to Stage 3 for further purification. The impure SBA, still containing significant amount of byreaction impurities as well as the unreacted water, exits the bottom of

15

the column and through pump P-202 where it is split into a reboiler stream and Stream 202, which is passed to Stage 2B.

4.2.3.2 Stage 2B: Stream Preparation The objective of Stage 2B is to cool the bottoms stream (stream 202) down to a lower temperature before entering Stage 3, the second SBA purification process. The process diagram is shown in Figure 4.8 below.

From Stage 2A

HEAT EXCHANGER

E-203

From MichiSite Cooling Water

To MichiSite Cooling Tower

To Stage 3202 275 79.5 158

203 75

84.7

2005936 lb/hr85.6 wt% SBA0.3 wt% TBA


Impure SBA

Impure SBA5936 lb/hr

85.6 wt% SBA0.3 wt% TBA




Cooling Water

Cooling Water

Figure 4.8 Stage 2B: Process flow diagram for stream preparation

The impure SBA stream (stream 202) from the distillation column in Stage 2A is cooled from 275°F to 158°F in a heat exchanger (E-203) for entrance into a further purification process in Stage 4. Stream 203 is the cooling stream originating from the cooling water input to MichiSite at 75°F and is subsequently heated to 200°F after passing through E-203. Stream 203 exits and is sent to a cooling tower. 4.3 Stage 3: Butene/Butane Separation

Stage 3 is divided into 4 sub-sections, 3A, 3B, 3C, and 3D in the overall block diagram in Figure 4.9. The overall objective of this stage is to separate the butane/butene azeotrope. The use of an entrainer, furfural, is used to break the azeotropic mixture of butane/butene. The furfural helps separate the boiling points of the two components, which allows for better separation. A pure butene stream is recycled back to Stage 1 and the butane/butene mixture is stored and sold as a LPG.

16


COLUMN

Stage 3B:DISTILLATION

COLUMN

Stage 3A:CONDENSER

Stage 3B:CONDENSER

Stage 3A:REBOILER

Stage 3B:REBOILER

Stage 3C:HEAT

EXCHANGER

Stage 3D:STORAGE

TANK

To Stage 1

From Stage 2



Unrefined Recycle

Furfural Makeup0.1 lb/hr

100 wt% Furfural

Furfural Recycle12212.9 lb/hr

100 wt% Furfural


100 wt% Furfural

22574 lb/hr45.9 wt% 2-butene54.1 wt% Furfural



Recycle Butene



Extracted 2-butene

25221 lb/hr100 wt% Water

Cooling Water


Cooling Water

To Shipment for Sale

Figure 4.9 Stage 3: Overall block diagram for butane/butene separation

4.3.1 Objective The objective of Stage 3 is to separate the unreacted impurities of the Stage 1 output from the 2-butene such that the 2-butene can be recycled in high purity in Stage 1. The unrefined recycle contains large amounts of 2-butene due to the low conversion of the hydration reactors. In the presence of the other butane and butene impurities, an azeotrope exists which necessitates the use of furfural as an entrainer to break said azeotrope. A second distillation column is required in order to recycle the furfural for future use and to purify the 2-butene before being fed back into Stage 1. The specific flow rates and stream compositions are shown in Figure 4.9 above. 4.3.2 Background The feed coming into this process from stage 2 is a crude hydrocarbon process consisting of butane, butene, isobutane, and isobutene. At room temperature the boiling points of these components are very similar. The goal of this process is to remove the residual butane from stage 2 to recycle the 2-butene back to the hydration reactor to continue to be reacted. The difficulty in separation arises, however, because of the difference in boiling points being between 1-3°C [14]. This causes a relative volatility α between the two components of 1.03. This means that a traditional separation of 2-butene and butane based on their boiling points is very difficult. In literature, it is stated that this separation used to take many multistage columns in order to accomplish the separation [14]. Today, modern extractive distillation methods are used. Extractive distillation is a type of separation that uses an entrainer mixed in with the components that are to be separated. The mixture of the three components creates a relative volatility between the two components that is large enough that it allows a separation to occur. Another distillation column is used to remove the entrainer from one of the components and recycle it to the first column. This process is widely used in petroleum refining in order

3A: 2-Butene extraction 3B: Furfural extraction 3C: Furfural preparation 3D: LPG storage

17

to separate difficult hydrocarbons. [10] This extractive distillation process is similar to heterogeneous azeotropic distillation in that an entrainer is added to change the chemical equilibrium between the two components to be separated. But in azeotropic distillation the entrainer is added to remove an azeotrope that occurs at a certain composition between the two components that are to be separated. The key to a successful extractive distillation is to choose the correct entrainer and in the right ratio. Selecting an entrainer for the best separation between butane and 2-butene involved looking at a variety of different chemicals. The most common components used for separation are dimethylformamide (DMF) and n-methylpyrrolidone (NMP) as well as di-methyl sulfoxide (DMSO). However, many of these components have stringent disposal and safety regulations, so another entrainer, furfural, was used as the optimal choice. All of these components have relatively the same effect on butane and butene in terms of the separation efficiency. [10] Thus, cost was also a factor in choosing the entrainer. Furfural ended up being cheaper and safer to use than the other components, so we chose this as our entrainer. [12] Finding the amount of entrainer for hydrocarbon separation was difficult due to the lack of information present in literature, so we chose to go with a ratio that was a common theme throughout extractive distillation models in literature and actual columns in industry which was a 1:1 mass ratio of feed to entrainer. [10] It is well documented that when the entrainer is increased the separation is better and it allows a purer product. [11] However, there reaches a point where adding more entrainer outweighs its opportunity cost. This is why we chose the ratio that we did to start our modeling, for economic reasons. We chose to model the extractive distillation setup in ASPEN using RADFRAC as the distillation modeling method and UNIQUAC as the property method due to the presence of these same extractive distillation modeling parameters in literature. [11] From literature, we were well aware that even with an entrainer the number of trays needed to accomplish a separation was going to be high in the ranges of 75-150 trays along with high reflux ratios. [12] We first modeled this column using the preliminary DTSWU modeling program in ASPEN with 75 stages and 10 as the guesses for the number of trays and reflux ratio. We specified a 0.99 percent recovery of the butene and butane in each of the columns and used that data as our input to the RADFRAC modeling setup. By altering the feed location of the entrainer and the hydrocarbon raffinate, the reflux ratio, the number of stages we were able to optimize our column design to obtain the desired purity of 2-butene for recycle back to the hydration reactor. 4.3.3 Process Description The design of Stage 3 has been divided into four sub-stages as labeled in Figure 4.9 above. In Stage 3A, the unrefined recycle stream, consisting of unreacted feed, enters an extractive distillation column. Along with the unrefined recycle, a feed of furfural entrainer is fed to the distillation column. The distillate from the column is composed of all the impurities fed into Stage 1 and is stored for sale as liquefied petroleum gas as shown in Stage 3D. The bottoms product of the column contains the extracted 2-butene dissolved in furfural. This bottoms product is then fed into another distillation column which separates the 2-butene and furfural based on their boiling points as shown in Stage 3B. The distillate from the Stage 3B column is fed back into Stage 1 as recycled 2-butene while the bottoms is recycled back into Stage 3A as recycled furfural for further use as an entrainer.

4.3.3.1 Stage 3A: 2-Butene Extraction The objective of Stage 3A is to selectively extract the 2-butene component from the impurities using furfural as the entrainer. This process is shown in Figure 4.10 below:

18



Furfural Makeup0.1 lb/hr

100 wt% Furfural

12212.9 lb/hr100 wt% Furfural

Furfural Recycle


Extracted 2-butene

T-601: Butane Separation by Extractive Distillation

E-601: Condenser

201

605

603

P-604

E-603: Reboiler

64.1 30.2

77.5 127

76.1

127

P-602

601 7676 74127602

From Stage 2

P-601

P-603

62.7 32.6

608

609

84.7

615

75

489

120

489

TK-602: Furfural Storage Tank

Bought Furfural

To Stage 3B

To Stage 3D


Cooling Water


Steam

64.130.2


Reboiler Reflux




Reflux

To MichiSite

Steam Return

From MichiSite Steam



606

612

62.7

32.6

Figure 4.10 Stage 3A: Process flow diagram for 2-butene extraction

The unrefined recycle stream (Stream 201) enters the extractive distillation column (T-601) to have the 2-butene component removed from the impurities. In order for this extraction to take place, an entrainer must be used which is shown by the feed of furfural to T-601 as Stream 602. Stream 201 is composed largely of 2-butene at 90.2 wt% with a relatively large flow rate of 12213 lb/hr. This necessitates that a large amount of furfural be required for proper extraction to take place, 12212.9 lb/hr. Stream 602 is largely composed of recycled furfural from Stage 3C with a small amount of furfural makeup pumped in via P-601 at a rate of 0.1 lb/hr to compensate for minor losses. The extractive distillation column functions by moving the 2-butene component from the impurity phase into the furfural phase where it can be separated much more easily in Stage 3B. After extracting the 2-butene from the impurities, the furfural/2-butene mixture leaves the distillation column through the bottoms and is pumped into a stream splitter in which one stream enters the reboiler (E-603) where it is sent back into the column and Stream 605 which exits to Stage 3B. At the top of the column, the impurities leave and enter a condenser (E-601) where it is pumped (P-603) through a splitter in which one stream enters the column as reflux and the other stream, Stream 603, proceeds to Stage 3D.

4.3.3.2 Stage 3B: Furfural Extraction The objective of Stage 3B is to recover the furfural entrainer from the 2-butene so that it may be recycled again in Stage 3A. The process is shown in Figure 4.11 below:

19

T-602: Recovering Furfural from Butene

605

604

E-602: Condenser

6038.5

E-604: Reboiler

64.1 30.2

60622.4 322.5

P-606

P-605

610

611

615

84.7

489

75

120

489


Extracted 2-butene


100 wt% Furfural


Recycle Butene


Cooling Water


Steam

From Stage 3A

To Stage 3A

To Stage 1

From MichiSiteSteam

Reboiler Reflux14192 lb/hr

100 wt% Furfural

615322.522.5

To MichiSiteSteam Return




Reflux

613

38.5

60

Figure 4.11 Stage 3B: Process flow diagram for furfural extraction

The bottoms product from the distillation column in Stage 3A is passed to a distillation column in Stage 3B (T-602) via Stream 605. Stream 605 is composed entirely of 2-butene and furfural with 45.9 wt% and 54.1 wt%, respectively, which necessitates the use of a distillation method to purify the 2-butene component. The distillate of the column enters a condenser (E-602). The condenser uses water from MichiSite to cool the distillate vapor. The resulting liquid is passed through a pump, P-606, which is then split into a reflux stream and Stream 604. These streams contain 99.9 wt% pure 2-butene. The reflux stream passes the material back into the column and Stream 604 passes the purified 2-butene to Stage 1 for further reaction. The bottoms of column is pumped (P-605) through a splitter into a reboiler stream and furfural recycle stream, Stream 606. The reboiler function by vaporizing the liquid into a gas using steam from MichiSite. Stream 606 is passed on to Stage 3C.

4.3.3.3 Stage 3C: Furfural Preparation The overall objective of Stage 3C is to cool the recycled furfural entrainer to a temperature at which it can be reused in the extraction process of Stage 3A. The process is shown in Figure 4.12 below:

20

127

From MichiSiteCooling Water

To MichiSiteCooling Tower

79.7

118.6

84.7 75

60622.4

607E-605: Heat Exchanger

322.5 From Stage 3B


100 wt% Furfural


Cooling Water

To Stage 3A

Figure 4.12 Stage 3C: Process flow diagram for furfural preparation

The bottoms product (Stream 606) from the distillation column in Stage 3B is cooled from 323°F to 127°F in a heat exchanger (E-605) for furfural recycle in Stage 3A. Stream 607 runs cooling water from MichiSite at 75°F which is subsequently heated to 119°F. Stream 607 runs back to a water collection stage.

4.3.3.4 Stage 3D: LPG Storage The overall objective of Stage 3D is to prepare the distillate from Stage 3A for storage and future product as liquefied petroleum gas. The process is shown in Figure 4.13 below:

250


Liquefied Petroleum GasP-104

32.6603 62.7From Stage 3A

TK-601: Butane Storage Tank

250 psig39 °F

Stored UnderPressurized

Nitrogen For Shipment/Sale

39

Figure 4.13 Stage 3D: Process flow diagram for LPG storage

The feed to Stage 3D originates from the distillate (Stream 603) of the distillation column from Stage 3A. The composition of Stream 603 meet the criterion for sale as liquefied petroleum gas and is therefore necessary to store. Storage requirement specify a temperature of 39°F and a pressure of 250 psi. Stream 603 passes through a pump which achieves the conditions necessary. 4.4 Stage 4: SBA Purification 2

Stage 4 is divided into 4 sub-stages, shown as 4A, 4B, 4C, and 4D in the overall block diagram, Figure 3. This novel system shown in Stage 4A, 4B, and 4C is a process where it is possible to bypass the azeotrope that is present in a water-SBA mixture. The overall objective of this stage is to separate the water from the SBA/TBA/DSBE in the stream from Stage 2 in the first system and then remove the DSBE from SBA/TBA in the Stage 4D distillation column. The water is recycled back to Stage 1, the pure SBA is fed to Stage 5, and the pure DSBE is fed to Stage 7.

21

Stage 4A:DECANTER

Stage 4A:CONDENSER


COLUMN

Stage 4C:DISTILLATION

COLUMN

Stage 4B:REBOILER

Stage 4C:REBOILER

Stage 4D:DISTILLATION

COLUMN

Stage 4D:CONDENSER

Stage 4D:REBOILER

To Stage 1

From Stage 2

To Stage 5

To Stage 7



Impure SBA


Water Recycle


Pure SBA


DSBE Waste

Figure 4.14 Stage 4: Overall block diagram for SBA purification 2

4.4.1 Objective The objective of Stage 4 is to further purify the SBA input from Stage 2 so that it can be fed into the dehydrogenation reaction in Stage 5. The impure SBA feed contains unreacted water and DSBE. Both of these impurities are detrimental to the dehydrogenation reaction which necessitates the high purity presented above in Figure 4.14. The specific flow rates and stream compositions (in wt%) are shown in Figure 4.14. 4.4.2 Background After SBA Purification 1, the bottom stream of the distillation column, which contains SBA, TBA, DSBE, and water, enters the Stage 4 system via the decanter. The SBA and water form a heterogeneous azeotropic mixture, with the azeotrope point at 76.33 mol percent water. Due to this azeotrope, a simple distillation column is not effective at separating these two components, because the boiled vapor has the same ratio of constituents as the original mixture. If the composition of water in a stream is under the azeotrope, then the highest concentration of water attainable in that stream is that of the azeotrope conditions. An azeotrope is usually broken by pressure swing distillation, where the change in azeotrope with respect to pressure is used, or by use of an entrainer, which adds a third component to the distillation that helps push the azeotrope to one’s advantage. However, for this setup in Stage 4, we are using the fact that SBA has a low solubility in water, 20.0 g in 100.0 g of water, and they have different densities, 0.808

4A: Azeotropic separation 4B: Water separation 4C: Impure SBA separation 4D: DSBE removal

22

g/cm3 for SBA and 1.00 g/cm3 for water, to form two distinct liquid phases in the decanter. The two streams entering will not encounter the azeotrope, as they are purified away from the azeotrope, therefore allowing the separation of water from the SBA, TBA, and DSBE in distillation columns. [13] Water has to be removed before the dehydrogenation reaction in Stage 5 for several reasons: the water will corrode the brass catalyst used in the dehydrogenation reactor, the water will affect the dehydrogenation reaction by producing undesired products, and that it can be recycled and reused in the hydration reaction. The SBA, TBA, and DSBE are chemically similar and will want to stay together throughout the separation of water. After the water is separated, the SBA, TBA, and DSBE stream enters another distillation column to separate SBA and TBA from DSBE. The DSBE must be removed before the dehydrogenation reaction because it will react with SBA during the dehydrogenation reaction to form a 5,3-methyl-heptanone, which is an undesired product. Equipment specifications for Stage 4 can be found in Appendix C. 4.4.3 Process Description The design of Stage 4 has been divided into four sub-stages as labeled in Figure 4.14 above. In Stage 4A, the impure SBA is fed into a decanter which separates into two relative phases each containing a different composition of materials. In the denser phase, water is the main component and in the upper phase, or less dense phase, SBA is the main component. The lower phase is sent to Stage 4B where the water is separated in high purity and sent back to Stage 1 for further use in the hydration reaction. The upper phase of the decanter is fed into Stage 4C where the SBA and DSBE components are separated from the water and sent on to Stage 4D. Stage 4D feeds the SBA/DSBE mixture into a distillation column which selectively removes the DSBE and sends it to Stage 7 for storage while the purified SBA is fed into Stage 5 for reaction into MEK.

4.4.3.1 Stage 4A: Azeotropic Separation The objective of Stage 4A is to separate the impure SBA feed into two phases differentiated by relative density with the heavier phase containing primarily water and the lighter phase containing mostly SBA. The process is shown in Figure 4.15 below:

23

From Stage 2

DECANTERTK-301

P-301

P-302


202

30115822.2

309

158

304 6961 158

24.1

21.2

158

79.5

310

75

84.7

120

3051677.35 From Stage 4C

Distillate1683 lb/hr



302 167 7.35

To Stage 4B

To Stage 4C

From Stage 4B



Impure SBA2101 lb/hr

11.0 wt% SBA0.4 wt% DSBE

88.6 wt% Water

High Density Material

Low Density Material6961 lb/hr





Distillate

Combined Distillate3130 lb/hr




Cooling Water

P-308



Figure 4.15 Stage 4A: Process flow diagram for azeotropic separation

The impure SBA feed (Stream 202) enters from Stage 2 as a liquid and enters into a decanter (D-301). The decanter separates the liquid into two phases differentiated according to relative density. Water, being the densest material, gathers at the bottom while the lighter alcohols and ether gather near the top. The bottom of the decanter is pumped (P-302) to Stage 4B via Stream 301. The flow rate of Stream 301 is 2101 lb/hr with the largest component being water at 88.6 wt%. The less dense material, SBA, TBA, and DSBE, are pumped (P-301) from the top of the decanter to Stage 4C via Stream 304 with a flow rate of 6961 lb/hr with the primary component being SBA at 82.0 wt%. There is also an additional input to the decanter (Stream 309) which is the combined distillate flows of the distillation columns located in Stages 4B and 4C shown as Stream 302 and 305, respectively. The condenser (E-301) functions as the distillation condenser for both distillation columns in Stages 4B and 4C.

4.4.3.2 Stage 4B: Water Separation The objective of Stage 4B is to separate the high density phase from the decanter in order to extract the water for reuse in the hydration reaction. The process is shown in Figure 4.16 below:

24

T-301 : Water Purification

To Stage 1

30115822.2

303

302 167 7.35

E-302: Reboiler

182.9323.9

P-303

311489 615

To Stage 4A


100 wt% Water

Distillate

From Stage 4A



2101 lb/hr11.0 wt% SBA0.4 wt% DSBE

88.6 wt% Water

High Density Material


Steam

From MichiSiteSteam

To MichiSiteSteam Return

Figure 4.16 Stage 4B: Process flow diagram for water separation

The high density material flows into the distillation column (T-301) via Stream 301 with the primary component as water. The distillation column functions by boiling off the dissolved SBA, trace amounts of TBA, and DSBE while the water is removed through the bottoms product of the T-301. The distillation has a vacuum pump (P-308) attached to attain a low pressure within the column. The bottoms product, a composition of 99.9 wt% water, is pumped (P-303) and split into a reboiler stream and Stream 303. Stream 303 is sent back to Stage 1 as recycled water for the hydration reaction via and the reboiler stream is sent to a reboiler (E-303) which vaporizes and sends the bottoms product back into the column using Steam from MichiSite flowing through Stream 311. The distillate contains the dissolved SBA, TBA, and DSBE components in water as shown in Stream 302.

4.4.3.3 Stage 4C: Impure SBA Separation The objective of Stage 4C is to remove the water from the lighter phase of the decanter in order to obtain only a mixture of SBA and DSBE. The process is shown in Figure 4.17 below:

25

P-389

T-302: SBA Purification

305

167

304 158

7.35

21.2

P-305

E-303: Reboiler

306

218

21312

489

615

To Stage 4A

SBA/SBE Mix

To Stage 4D

From Stage 4A

Low Density Material6961 lb/hr



Distillate1683 lb/hr




3.4 wt% DSBE


Steam

Figure 4.17 Stage 4C: Process flow diagram for impure SBA separation

The input to Stage 4C (Stream304) consists of the lower density material present in the impure SBA feed to the decanter. Stream 304 then enters a distillation column (T-302) which separates the SBA, TBA, and DSBE from the water. T-302 operates at low pressure necessitating the use of a vacuum pump (P-309) to maintain this condition. A high purity of SBA, 96.3 wt%, exits the bottoms stream of the T-302 which is then pumped (P-305) and split into a reboiler stream and Stream 306. The reboiler stream is sent to a reboiler (E-303) where the stream is vaporized using steam from MichiSite flowing through Stream 312. Stream 306, containing mostly SBA and DSBE, are sent to Stage 4D for further separation.

4.4.3.4 Stage 4D: DSBE Removal The objective of Stage 4D is to purify the SBA by removing the DSBE impurity via distillation. The process is shown in Figure 4.18 below:

26

To Stage 7

T-303: SBE Removal

306 218 21

248308 21.6

P-306

P-307

307 212 21

E-305: Condenser

E-304: Condenser

313

489

615

75

84.7

120

314

To Stage 5

From Stage 4CSBA/SBE Mix


3.4 wt% DSBE


Purified SBA


Steam


Cooling Water

From MichiSiteSteam



To Mich

iSite

Steam

Return

31624821.6


DSBE Waste


Reboiler Reflux

307

212

21


Reflux

Figure 4.18 Stage 4D: Process flow diagram for DSBE removal

Stage 4D receives its feed from Stage 4C via Stream 306 with a high content of SBA, 96.3 wt%, with a small amount of DSBE, 3.4 wt%, which must be removed. Stream 306 is fed into a distillation column (T-303) which separates the two components. The distillate stream, which contains the purified SBA, enters a condenser (E-307) which uses cooling water from MichiSite to cool the vapor phase distillate into a liquid phase. The liquid distillate is then pumped (P-307) through a splitter into a reflux stream and into Stream 307. The reflux stream enters back into the top of the column. Stream 307 contains the purified SBA at 99.7 wt% purity and then passed to the dehydrogenation reactor in Stage 5. The DSBE waste exits the bottoms of the column and is pumped (P-306) through a splitter into a reboiler stream and Stream 308. The reboiler stream is sent to a reboiler (E-305) which uses steam from MichiSite to vaporize the liquid into a gas. Stream 308, containing 99.9 wt% of DSBE, is sent to Stage 7 for storage and eventual disposal.

27

4.5 Stage 5: SBA Dehydrogenation to MEK

Stage 5A:FLASH DRUMVAPORIZER

Stage 5A:COMPRESSOR

Stage 5B:DEHYROGENATION

REACTOR

Stage 5B:BLOWER

Stage 5C:VAPOR-LIQUID

SEPARATOR

Stage 5C:COMPRESSOR

Stage 5D:HEAT

EXCHANGER

From Stage 4

From Stage 6

To Atmosphere

To Stage 6

From MichiSiteSteam

To Stage 1


Purified SBA

693 lb/hr100 wt% SBA

SBA Recycle44020 lb/hr

100 wt% Water

44020 lb/hr100 wt% WaterSteam

Steam

Unrefined Mek5702 lb/hr


84.5 wt% MEK3.1 wt% DSBE

88 lb/hr40.9 wt% MEK

59.1 wt% H2

Exhaust

Stage 5D:HEAT

EXCHANGER

Figure 4.19 Stage 5: Overall block diagram for SBA dehydrogenation to MEK

4.5.1 Objective The objective of Stage 5 is to convert the incoming SBA feed from Stage 4 into our final product of MEK via a dehydrogenation reaction. Stage 5 also has another objective which is to ready the reactor effluent stream for the MEK purification process in Stage 6. The SBA has been purified to 99.9 wt.% thus it can be readily fed into the reactor once reaching the proper entrance conditions. The specific flow rates and stream compositions (in wt.%) are shown in Figure 4.19 above. 4.5.2 Background The input feed for the dehydrogenation reaction present in this Stage consists purely of SBA at a composition of 99.9 wt%. It is required that the feed to the dehydrogenation reactor have no butanes, butenes, DSBE or water present lest detrimental side reactions occur which would be harmful to the life of the catalyst and reactor as many of these undesired reactions are exothermic while the reactor present in this stage only contains a heating jacket. A runaway reaction would be highly unlikely given the small amount of impurities present in the raffinate feed from MichiPetrol. A runaway reaction could possibly occur if the feed composition changed completely due to failure in separation efficiency via MichiPetrol, but we did not take this into account nor do we believe it is likely. If this was to occur, we would shut our process down immediately. The side reactions of any butanes would cause the formation of butadienes and various other compounds which the Stage 6 purification method would not be sufficient to separate [7]. Any present butenes would mean the failure of our SBA purification 1 method in Stage 2. The presence of DSBE would be extremely detrimental as DSBE is already a component in side reaction in the n-butene hydration. The additional DSBE would only serve to further its process formation. Overall, it is important to obtain a high purity of SBA before introducing the feed to the dehydrogenation reactor. As noted, SBA in the presence of high temperatures serves as a manner to rid the oxygen atom of its adjacent proton and double bond with its adjoining carbon atom.

5A: SBA preparation 5B: Dehydrogenation reaction 5C: Product preparation 5D: Impure MEK preparation

28

However, like the hydration reaction, this reaction does not occur readily as the SBA molecule is highly stable and the removal of the initial proton requires a high activation energy. Therefore, it is proposed that a metal catalyst be introduced in order to assist in the electron transfer through the reaction mechanism. The metal catalyst acts as a proton acceptor allowing the oxygen atom on the molecule to form a double bond with the adjoining carbon creating a carbanion. The hydrogen attached to the carbanion is ejected and combined with free protons to form hydrogen gas. Unlike the resin of the hydration reaction, the metal catalyst in the dehydrogenation are not subject to pressure drop limits and temperature constraints as severe. The overall conversion per pass in a catalytic dehydrogenation reaction is 88%. This in conjunction with the catalyst’s durable nature allow for a single reactor to be used as opposed to running four in series and parallel to cope with the high flow and pressure drop. The reaction itself is endothermic with the heat of reaction being -51 kJ/mol [7]. This necessitates the use of a heating stream to maintain isothermal behavior within the reactor. The optimal conditions for this reaction to take place in a catalytic fashion suggest gas phase, high temperature, and low pressure. The pressure of the system has been found to have a strong effect on the overall conversion per pass of SBA. Thus it is proposed to use a pressure of 29 psi. Temperature, varying between 210°C and 290°C, is found to have a much smaller effect such that it is almost negligible in effecting the overall conversion of SBA. However, there is a strong correlation between the temperature of the reactor and the formation of DSBE as an undesired by-reaction. As the temperature is increase, the selectivity of DSBE drops noticeably. Therefore it is proposed to use high temperature and low pressure as the optimal operating conditions. [7] The equipment in Stage5 includes a flash drum vaporizer, packed-bed reactor with catalyst, vapor-liquid separator, heat exchanger, 2 pumps, 3 compressors and a heating stream for the reactor. Equipment specifications for Stage 5 can be found in Appendix C. The flash drum vaporizer functions to convert the liquid stream in a gas phase stream in order to optimize the reaction conditions in the reactor. Product specifications for the flash drum vaporizer are located in Appendix C. In order to reach the correct pressure conditions for the reaction to take place, a compressor is used. Product specifications for the compressor are located in Appendix C. Immediately after exiting the compressor, the purified gas phase SBA feed enters the dehydrogenation reactor. Specifications for the dehydrogenation reactor can be found in Appendix C. The reactor is a fixed packed bed shell and tube catalytic reactor. Due to the endothermic nature of the dominant reaction taking place, a heating stream is required to maintain the isothermal conditions. In order to accomplish proper heating, the catalyst is placed into 1480 tubes with each tube spaced 0.105 ft apart. The volume of catalyst within all the tubes is 1400 liters of a copper-zinc material. The length of these tubes is 9.84 feet as is the length of the reactor total with the shell diameter of 4.64 ft in order to accommodate the high material flow and subsequent heating process. Upon exiting the reactor, the stream is in gas phase. In order to remove the hydrogen gas, the stream is cooled and immediately fed into a vapor-liquid separator. The liquid phase contains the MEK product while the gas phase contains the hydrogen gas with dissolved MEK. The hydrogen with dissolved MEK is ejected to the atmosphere as EPA regulations have no limit to the amount of MEK expelled in vapor form. See section 6.1.1 for further information on hydrogen’s effects on the environment. The liquid phase passes to a heat exchanger where it is heated to the appropriate conditions for the subsequent purification in Stage 6.

29

4.5.3 Process Description The design of Stage 5 has been divided into four sub-stages as labeled in Figure 4.19 above. In Stage 5A, the purified SBA stream from Stage 4 is combined with the SBA recycle stream from Stage 6 and enters a flash drum vaporizer which converts the SBA feed into a vapor and is passed on to Stage 5B. In Stage 5B, the SBA feed enters the reactor where the SBA is converted to MEK in 88% conversion and 98% selectivity via a dehydrogenation reaction. The effluent from the reactor is adjusted to the proper conditions in order to separate the hydrogen byproduct which occurs in the next sub-stage. In Stage 5C, the effluent stream from the reactor enters a vapor-liquid separator which ejects the gas phase to the atmosphere while the liquid phase is passed on to Stage 4D. In Stage 4D, the unrefined MEK stream is passed through a heat exchanger in preparation for the MEK purification process in Stage 6.

4.5.3.1 Stage 5A: SBA Preparation The objective of Stage 5A is to prepare the SBA stream for the dehydrogenation reactor in the following sub-stage. This process is shown below in Figure 4.20 below:


Purified SBA

693 lb/hr100 wt% SBA

SBA Recycle

Reactor Feed5790 lb/hr


D-401: Feed Vaporizer

From Stage4 401 29450

From Stage 6

307

212

503

21.9

203

C-401

401 212 21

P-401

P-404

407

615

489

From MichiSiteSteam

21.9

To Stage 5B


Steam


Steam

To MichiSite Steam Return

407

Figure 4.20 Stage 5A: Process flow diagram for SBA preparation

The purified SBA enters Stage 5A via Stream 307 which is combined with the recycled stream (Stream 507) which originated in Stage 6 using pumps P-401 and P-404 for Streams 307 and 507, respectively. The combined flow of the stream (Stream 401) is 5790 lb/hr at a temperature of 212°F and a pressure of 14.7 psi, conditions for a liquid phase stream. Stream 401 enters a feed vaporizers (D-401) which uses steam (Stream 407) from MichiSite to convert the liquid feed into a vapor and raise the temperature to the required 450°F for the optimized reaction temperature. The vapor then enters a compressor (C-401) which raises the pressure from 14.7 psi to 29 psi in order to attain the proper reaction pressure conditions. The content of all the streams shown in Stage 5A is almost all entirely SBA, 99.8 wt%, with the miniscule impurity being TBA which does not react in the subsequent dehydrogenation reaction and is therefore negligible as an impurity.

30

4.5.3.2 Stage 5B: Dehydrogenation Reaction The objective of Stage 5B is to convert the SBA feed into the desire MEK product via dehydrogenation. This process is shown in Figure 4.21 below:

Reactor Feed5790 lb/hr


Reactor Output5790 lb/hr


83.5 wt% MEK1.2 wt% Hydrogen

3.1 wt% DSBE

Steam44020 lb/hr

100 wt% Water

Chilled Refrigerant46313 lb/hr

100 wt% Refigerant

401

40214.7 450

29

450

405

455

615

405

489From MichiSite

Steam

To Stage 1 For Heating

402 0E-401

14.7

406

-76

-30

Refrigerant Transport To MichiSite

Refrigerant from Michisite

From Stage 5A

444

R-401: Packed Bed Reactor with Catalyst

To Stage 5C

Steam44020 lb/hr

100 wt% Water

19.7

Figure 4.21 Stage 5B: Process flow diagram for dehydrogenation reaction

The feed for the reactor (Stream 401) contains SBA at 99.8 wt% with only 0.2 wt% owing to nonreactive TBA. The conditions for Stream 401 are that of the optimal conditions for the dehydrogenation reaction to take place, 450°F and 29 psi. The SBA then enters the dehydrogenation reactor (R-401) which is a fixed packed bed catalytic reactor containing a zinc copper aluminum material as the catalyst. The reaction, being endothermic, requires that a heat stream maintain the isothermal environment for the reaction to take place which necessitates the use of a steam heating stream (Stream 405) which comes from MichiSite at a rate of 44020 lb/hr. The effluent stream Stream 402) of R-401 contains primarily MEK with unreacted SBA, TBA, Hydrogen gas, and DSBE impurities. All of the components are in a vapor phase at the given conditions and are passed through a blower (C-402) into a heat exchanger (E-401) for cooling. Upon cooling, the hydrogen impurity remains a gas but the MEK and other components become a liquid which is passed to Stage 5C.

4.5.3.3 Stage 5C: Product Separation The objective of Stage 5C is to separate the two phase output of the reactor into the desire unrefined MEK stream and the undesired hydrogen effluent stream. This process is shown below in Figure 4.22 below:

31

14.7

0

0

404

403

P-403

BL-401

D-402: Flash Drum

14.7

28.4

Hydrogen to AtmosphereEjection Tower

Reactor Output5790 lb/hr


83.5 wt% MEK1.2 wt% Hydrogen

3.1 wt% DSBE

Hydrogen Gas Phase

Liquid Phase

To Stage 5D


59.1 wt% Hydrogen



From Stage 5B 402 0 14.7

Figure 4.22 Stage 5C: Process flow diagram for product separation

The reactor output stream (Stream 402) enters Stage 5C immediately from the previous stage into a flash drum (D-402) so that the hydrogen gas phase will be easily separated from the liquid impure MEK phase. The hydrogen gas exits through the top of the drum via Stream 404 and into a blower (C-403), where it is ejected into the atmosphere. See Stream 404 contains primarily hydrogen gas with miniscule amounts of MEK in the vapor phase. The combustible characteristics of hydrogen and MEK are found in sections 6.2.1 and 6.2.2, respectively. The liquid impure MEK phase exits the bottom of the drum through Stream 403 where it is pumped (P-403) into Stage 5D.

4.5.3.4 Stage 5D: Impure MEK Preparation The objective of Stage 5D is to prepare the unrefined MEK stream for the subsequent purification process in the following stage. This process is shown in Figure 4.23 below:

To Stage 6

E-402

405

To Michisite Steam Return

175

444

451

439

443

403 28.40

From Stage 1

From Stage 5C

Liquid Phase5790 lb/hr



Steam44020 lb/hr

100 wt% Water

Figure 4.23 Stage 5D: Process flow diagram for impure MEK preparation

Stream 403 enters from Stage 5C as the impure liquid MEK phase and passes through a heat exchanger (E-402) which increases its temperature from 0°F to 175°F and passed on to Stage 6 in order to prepare the stream for MEK purification. E-402 functions using the heat steam (Stream 405) that comes from a heating process in Stage 1.

32

4.6 Stage 6: MEK Purification

The MEK purification is a multicomponent distillation process by which two distillation columns separate three significantly different components into individual purified streams for either further processing or for shipment. The primary components are unreacted SBA, DSBE byproduct, and product MEK with negligible TBA dissolved within. The unreacted SBA will be purified in this process and then sent back to Stage 6 for further reacting. The DSBE will be passed onto Stage 7 for storage and disposal. The product MEK will be stored and sold in this stage. Stage 6 is divided into three sub-stages shown as Stage 6A, Stage 6B, and Stage 6C in the overall block diagram as displayed in Figure 4.24 below:


COLUMN

Stage 6A:CONDENSER

Stage 6A:REBOILER

Stage 6C:HEAT

EXCHANGER


COLUMN

Stage 6B:CONDENSER

Stage 6B:REBOILER

Stage 6C:STORAGE

TANK

To Stage 5

To Stage 7

From Stage 5

Unrefined Mek5702 lb/hr


84.5 wt% MEK3.1 wt% DSBE 689 lb/hr

99.9 wt% SBA

SBA Recycle


99.8 wt% DSBE

Waste


MEK

Figure 4.24 Stage 6: Overall block diagram for MEK purification

4.6.1 Objective The objective of Stage 6 is to purify the unrefined MEK effluent stream of the dehydrogenation reactor in the previous stage in order to efficiently recycle the unreacted SBA, remove the DSBE impurity, and prepare the refined MEK for shipping. The entering unrefined stream contains primarily MEK, 84.5 wt%, with 12.1 wt% SBA that should be sent back to Stage 5 for further conversion to MEK. The specific flow rates and stream compositions (in wt%) are shown in Figure 4.24 above. 4.6.2 Background The stage purifies the inlet stream into mostly pure streams of DSBE, MEK, and SBA/TBA. The separation is performed through two distillation columns, which allows the components to be separated by taking advantage of differences in boiling points. The component(s) with the lower boiling points will vaporize and leave the column through the top, while the component(s) with the higher boiling points will stay liquids and leave the column through the bottom. In the first distillation, the MEK is purified in the

6A: MEK extraction 6B: SBA extraction 6C: MEK storage

33

distillate product because its boiling point is 80°C, while SBA/TBA/DSBE leave through the bottoms. SBA and TBA have a boiling around 100°C and DSBE has a boiling part at 120°C. The purified MEK needs to be at least 99.5 wt% of the stream to be able to be sold on the market, as the ASTM standards state. The second distillation takes advantage of the 20°C difference of the boiling points. The SBA/TBA leaves through the distillate and is recycled to Stage 5. The DSBE goes to Stage 7, where it is stored to be disposed as waste. Equipment specifications for Stage 6 can be found in Appendix C. 4.6.3 Process Description The design of Stage 6 has been divided into three sub-stages as labeled in Figure 4.24 above. In Stage 6A, unrefined MEK enters and is pumped into the first distillation column which separates the MEK from the unreacted SBA and DSBE. The MEK is passed on to Stage 6C where the product is stored and picked up in shipments of three trucks per day to be sold. The bottoms product of the distillation column, SBA and DSBE, is passed on to Stage 6B. In Stage 6B, the SBA and DSBE are sent into a second distillation column in which the SBA exits the top of the column where it is passed back to Stage 5 for further reaction. The bottoms product contains the DSBE impurity which is passed to Stage 7 for storage and disposal. Flow rates and compositions are specified in the PFDs located in Appendix A.

4.6.3.1 Stage 6A: MEK Extraction The objective of Stage 6A is to separate the MEK from the unreacted SBA and DSBE impurity via distillation. The process is shown in Figure 4.25 below:

T-501: Purifying MEK

E-501: Condenser

403From Stage 5

P-502

501 21.7

P-503

175

E-503: Reboiler

204 21.8502

175 28.4

84.7

75

506

615

489

508

120

79.7

Unrefined MEK5702 lb/hr




Purified MEK


20.7 wt% DSBE

SBA/DSBE Mix


Steam


Cooling Water

To Stage 6B

To Stage 6C

To MichiSite

Steam Return

From MichiSiteSteam

511204502


To MichiSiteWater Tower


20.7 wt% DSBE

Reboiler Reflux

501

21.7

175


Reflux

Figure 4.25 Stage 6A: Process flow diagram for MEK extraction

34

The unrefined MEK (Stream 405) enters from Stage 5 and is pumped (P-501) into a distillation column (T-501) at a rate of 5720 lb/hr. The distillate contains the purified MEK which enters a condenser (E-501) where the vapor is converted to liquid phase and is subsequently pumped (P-502) into a splitter with a reflux stream going back to the column and a Stream 501 which proceeds to Stage 6C. The condenser functions by using cooling water via Stream 506. The bottoms product contains the SBA and DSBE which exits and is pumped (P-503) and split into a reboiler stream and Stream 502. The reboiler stream enters a reboiler which uses steam from MichiSite to vaporize the liquid into a gas and sends the effluent back into the column. Stream 501 contains the SBA/DSBE mixture which is passed on to Stage 6B for further purification. The reboiler functions by using steam from MichiSite (Stream 508) to vaporize the bottoms liquid into a vapor.

4.6.3.2 Stage 6B: SBA Extraction The objective of Stage 6B is to separate the unreacted SBA from the DSBE impurity so that it can be sent back to Stage 5 for further reacting. This process is shown in Figure 4.26 below:

T-502: Separating SBA

To Stage 7

P-505

E-502: Condenser

E-504: Reboiler

215

245

21.8

21.4

502

To Stage 521.9203503

504

P-504

615

489509

84.7

75

507

120

79.7

From Stage 6A


20.7 wt% DSBE

SBA/DSBE Mix


Steam


Cooling Water


SBA Recycle

180 lb/hr99.8 wt% SBA0.2 wt% SBA

DSBE Waste

From

Mic

hiSi

te

Cool

ing

Wat

erTo MichiSite

Cooling Tower

To MichiSite

Steam Return

From MichiSiteSteam

512

203

21.9


Reflux


Reboiler Reflux

50421521.4

Figure 4.26 Stage 6B: Process flow diagram for SBA extraction

35

Stream 502, the SBA/DSBE mix, enters a distillation column (T-502) in order to separate the SBA for recycle from the DSBE for waste disposal. The distillate from the column contains the SBA which, as a vapor, flows through a condenser (E-501) converting it into the liquid phase which is subsequently pumped (P-504) and split into a reflux stream and Stream 505. The reflux stream enters back into the column while Stream 505 is passed along to Stage 5 for further reaction. The compositions of Stream 505 is 99.9 wt% SBA with immeasurable amounts DSBE and TBA. E-501 functions by using cooling water to cool the distillate. The bottoms product is pumped (P-505) into a splitter which divides the flow into a reboiler stream and Stream 504, the DSBE waste stream. The reboiler stream passes through a reboiler which vaporizes the liquid and the contents back into the column. Stream 504 is passed on to Stage 7 for DSBE storage and disposal.

4.6.3.3 Stage 6C: MEK Storage The objective of Stage 6C is to prepare the MEK product for storage and the subsequent storage of the material. This process is shown in Figure 4.27 below:

From Stage 6A

HEAT EXCHANGER

E-505



501 175 21.7 263.280

505 75

84.7


Purified MEK


Cooling WaterTK-501: MEK Storage Tank

250 psia80 F

Nitrogen Pressurized

P-506


Cooling Water

Figure 4.27 Stage 6C: Process flow diagram for MEK storage

The purified MEK, Stream 501, flows through a heat exchanger (E-505) in order to cool the stream from 132°F to the storage temperature requirement of 80°F. E-505 uses cooling water from MichiSite to accomplish the cooling with a flow rate of 3350 lb/hr of water at 75°F. Additionally, Stream 501 enters a series of pumps (P-506) in order to reach the storage pressure requirement of 250 psi. P-506 consists of three pumps in series. The final flow rate of purified MEK is 4833 lb/hr which is storage and eventually sold for profit. 4.7 Stage 7: DSBE Storage

We have chosen to get rid of the impurity by shipping it off to MichiSite as hazardous waste. The input comes from Stage 4 and Stage 6 which are combined and sent through a heat exchanger in order to adjust the temperature to proper storage conditions. After being cooled from 207°F to 80°F, the DSBE is sent into storage and then passed on to disposal. Stage 7 is divided into two sub-stages shown as Stage 7A and Stage 7B in the overall block diagram in the overall block diagram in Figure 4.28 below:

36

Stage 7B:HEAT EXCHANGER

From Stage 4

From Stage 6

Stage 7B:STORAGE


DSBE Waste


DSBE Waste


Combined DSBE WasteStage 7A:MIXING

Figure 4.28 Stage 7: Overall block diagram for DSBE storage

4.7.1 Objective The objective of Stage 7 is to accumulate the DSBE impurity formed in both reactions of the overall MEK production process and store this impurity in a safe manner. The DSBE enters Stage 7 in very high purities from Stage 4 and Stage 6, 99.9 wt% and 99.8 wt%, respectively. This impurity is stored for eventual disposal. The specific flow rates and stream compositions (in wt%) are shown in Figure 4.28 above. 4.7.2 Background DSBE is the product of an undesired by-reaction which occurs in both Stages 1 and 5, the hydration and dehydrogenation reactions, respectively. As such, this impurity is gathered from both aforementioned stages and allocated to a specific storage tank which will house the material until shipped for disposal by MichiSite. In order to house the impurity between disposal pick-up, the DSBE is stored in a tank. 4.7.3 Process Description The design of Stage 7 has been divided into two sub-stages as labeled in Figure 4.28 above. In stage 7A, DSBE enters from Stage 4, the SBA purification 2 process, and from Stage 6, the MEK purification process. These two stream are combined and pumped to Stage 7B. In Stage 7B, the combined stream is sent through a heat exchanger in order to reduce the temperature from 207 to the 80 required for proper storage. Once stored in the tank, the DSBE is sent for disposal in periodic intervals.

4.7.3.1 Stage 7A: Stream Integration The objective of Stage 7A is to combine the two incoming streams of DSBE into a single stream. This process is shown in Figure 4.29 below:

7A: Stream integration 7B: DSBE storage

37

From Stage 4

From Stage 6

248308

215 21.4504

21.6

P-801

235 21.4801 To Stage 7B


DSBE Waste


DSBE Waste


Combined DSBE Waste

Figure 4.29 Stage 7A: Process flow diagram for stream integration

The DSBE waste from Stages 4 and 6 (Streams 308 and 506, respectively) are combined and pumped (P-801) to Stage 7B for proper storage and eventual disposal.

4.7.3.2 Stage 7B: DSBE Storage The objective of Stage 7B is to cool the DSBE stream down to an acceptable temperature for storage and disposal. This process is shown in Figure 4.30 below:

TK-801:DSBE Storage to Waste

75

84.7

802

101


P-802

207 21.6801

80

21.6

29 psia80 F

Stored UnderPressurizing

Nitrogen



To Michisite Waste


Combined DSBE Waste


Cooling Water

From Stage 7A

801


Cooling Water


Combined DSBE Waste

Figure 4.30 Stage 7B: Process flow diagram for DSBE storage

38

The flow of the combined DSBE waste (Stream 801) enters a heat exchanger (E-801) in order to bring the temperature of the stream, 207°F, down to a proper storage temperature, 80°F. This process is accomplished using the MichiSite cooling water with a flow of 1250 lb/hr. After cooling, Stream 801 enters a pump (P-802) in order to bring the pressure to a proper storage pressure of 29 psi. The DSBE waste is stored using a nitrogen feed to inert the free space until it is shipped for disposal. 5.0 ECONOMIC FEASIBILITY ANALYSIS The subsections below detail the calculations along with the procedure that we used to evaluate the profitability and feasibility of our process design that was outlined in section 4.0. A conclusion to the investors about the process is given along with our recommendation to move forward or terminate this design based on our calculations. 5.1 Overview of Economic Feasibility Analysis

The following sections outline our procedure to determine the economic feasibility of the process design that we laid out in section 4.0. As a general procedure, we used the equipment costs estimated from previous literature on the costing of industrial chemical components in industry to help size and determine the types of components in our process. This method allowed us to estimate the plant equipment installation costs. From the plant layout that is to scale with our design we estimated piping costs using the same manuals. Together, using these costs along with the estimated engineering man hours for this design, we were able to estimate the TCI of our process design. Total operating costs were estimated from the manned labor costs along with the utilities. Using these values, we were able to calculate a feasibility analysis to determine the profitability of our plant design over a 10-year operating period. 5.2 Initial Investment

The following subsections outline the procedure that was used by our team to calculate the total capital investment that is needed to completely build, supply, and set up our manufacturing plant. These sections also detail the specific costs that make up the TCI and describe how these costs were estimated for our process. 5.2.1 Overview The initial investment for our process is the total dollar amount that we will need to buy our land, build our plant, and supply the facility with all the necessary equipment in order to produce MEK. The summation of these costs is known as the total capital investment (TCI) which includes the fixed capital investment, the working capital, and the start-up costs. The fixed capital investment is defined as the amount of money that is needed to supply the required manufacturing and plant facilities, usually provided by investors interested in the venture. The working capital is the total amount of money invested in the raw materials, supplies, products in stock, products being manufactured, accounts receivable, cash kept on hand for monthly payment of operating costs, accounts payable, and taxes payable. It is viewed as the liquid money that is needed for plant operation. [15] Start-up costs are defined as the initial investment that is not refundable used in obtaining permits to build, contractors, creating a suitable building space on the plot of land, buying the land, etc. From our calculations and results for the economic analysis that can be referenced in Appendix E we found the Total Capital Investment to be $96.2 MM, which is broken down into a fixed capital investment (ISBL and OSBL) of $74.0 MM, a working capital of $14.8 MM, and a start-up cost in the amount of $7.4 MM.

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The subsections below outline the procedures and results that allowed us to calculate the TCI, FCI, WC, and start-up costs. These specifically include the inside and outside boundary limits. 5.2.2 Fixed Capital Investment (FCI) The fixed capital investment is the total amount of money that is needed to purchase and supply the required manufacturing components and plant facilities for successful operation. It consists of two components, the ISBL and the OSBL. ISBL is defined as “inside boundary limits” which are defined as the total on-site construction costs that are necessary for building the plant. ISBL includes the equipment costs, piping, instrumentation and control, civil and structural, construction management and engineering costs. OSBL is defined as “outside battery limits” which includes components of the manufacturing process that are not on the plant site but may be affiliated with the plant such as processes from MichiChem and MichiPetrol. These components can be a steam plant, cooling towers, cafeterias, parking lots, research labs, etc. Table 5.1: Results from ISBL and OSBL Analysis Showing Calculated FCI

ISBL OSBL (25% of ISBL) Fixed Capital Investment (FCI)

Cost ($)

$67.3 MM

$6.73 MM $74.0 MM The following subsections go over the calculations necessary to obtain the ISBL and the OSBL in order to calculated the fixed capital investment.

5.2.2.1 Inside Boundary Limits (ISBL) Using a modified method to estimate the ISBL we size and priced our equipment based on the flow rates and conditions in our PFD that can be referenced in Appendix E. The sizing of all the components in the PFD allowed us to calculate the plant equipment cost as shown below in Figure 5.1.

40

Figure 5.1: Standard construction costs used to estimate the ISBL by the percentage of delivered equipment cost [15]

The plant equipment cost was found by taking a sum of all the installed equipment costs that were adjusted for inflation from their cost estimations. The sizing and costing of all the equipment can be referenced with sample calculations in Appendix C. The plant equipment cost allowed us to estimate the rest of the costs by assuming that the plant equipment cost was exactly 24.3 percent of our ISBL. The piping costs, which were determined by the plant layout and a cost estimation chart, were also assumed to be exactly 14.5% of the ISBL. Piping costs and sizing with sample calculations can be referenced in Appendix D. Finally, we calculated the amount of man hours needed to determine this current process design from our own time sheets and calculated the process design cost which we assumed to be exactly 3 percent of the 17.5% used in the engineering cost of the ISBL. Our calculations for total process design cost can be referenced in Appendix E .We normalized the rest of the costs outlined in Figure 5.1 based on these numbers above and the calculation procedure shown in the same figure. Adding a 20% contingency to the ISBL was necessary to account for a natural disaster or unexpected costs that may occur during the construction process. From all of these calculations, we were able to produce our ISBL. The calculations and results are detailed in the table below.

41

Table 5.2: Summary of the Costs and Calculations to Find the ISBL Base Estimated Costs ($) % of ISBL Normalized Cost

($) Civil and Structural Cost ($) 13.3 $10.8 MM Insulation/Painting/Fire Protection/HVAC ($)

3.6 $2.93 MM

Electrical Cost ($) 6.7 $5.44 MM Instrumentation & Control Cost ($) 13.5 $11.0 MM Construction Management Cost ($) 6.2 $5.0 MM Plant Equipment Cost ($) $19.7 MM 24.3 $19.7 MM Piping Cost ($) $197,315 14.5 $197,315 Engineering Process/Project $104,040 3 Included in

Engineering Cost Engineering Cost 17.5 $606,900 Miscellaneous 0.4 $325,000 Subtotal $56.1 MM 20% Contingency $11.2 MM ISBL $67.3 MM

5.2.2.2 Outside Boundary Limits (OSBL) As described in previous sections the OSBL is defined as the costs that are outside of the plant limits. These components may include the steam plant, cooling towers, employee facilities (cafeteria, parking lots, etc.), and other facilities that may be shared with adjoining manufacturing plants (MichiPetrol). Based on estimates from literature the OSBL is within a range of 10 to 20 percent of the ISBL cost. [15] Because we are building this plant on MichiChem’s property which already contains many of the units that we need offsite that are shared between different manufacturing plants, we assumed the minimal OSBL percentage which is 10 percent. From the calculations present in Appendix E, we were able to estimate the OSBL at a cost of $6.73 MM. 5.2.3 Working Capital (WC) Working capital is defined as the liquid monetary amount that is necessary for day-to-day operation of the plant. Costs that may include working capital may include monthly utility bills, accounts payable and taxes. The value of the raw materials, products, and products in manufacture is also included. We are able to estimate the working capital by assuming that it is approximately 20 percent of the fixed capital investment. [15] By calculating this (shown in Appendix E) we are able to obtain the working capital which is $14.8 MM. 5.2.4 Start-Up Costs Start-up costs are defined as the expenses that arise when priming a plot of land to be constructed upon along with various expenses that aren’t included in the fixed capital investment that may occur over the course of the construction process. We are able to estimate the start-up cost of our process by assuming that it is approximately 10 percent of our FCI. [15] Performing this calculation (shown in Appendix E) we obtain a start-up cost of $7.4 MM.

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5.2.5 Total Capital Investment (TCI) The total capital investment is a combination of costs from all of the above sections. Specifically, it is the sum of the FCI, WC, and the start-up costs that we calculated based on the purchased and installed equipment costs using the method described in section 5.2.2.1. This requires the calculations from all of the above sections, which we summarized in the table below. Calculations for all of these values can be referenced in Appendix E. Table 5.3: Complete Initial Investment Calculations Detailing the TCI Base Estimated Costs ($) % of ISBL Normalized Cost ($) Civil and Structural Cost ($) 13.3 $10.8 MM Insulation/Painting/Fire Protection/HVAC ($)

3.6 $2.93 MM

Electrical Cost ($) 6.7 $5.44 MM Instrumentation & Control Cost ($) 13.5 $11.0 MM Construction Management Cost ($) 6.2 $5.03 MM Plant Equipment Cost ($) $19,747,674.88 24.3 $19.7 MM Piping Cost ($) $197,315 14.5 $197,315 Engineering Process/Project ($) $104,040 3 Included in

Engineering Cost Engineering Cost ($) 17.5 $606,900 Miscellaneous ($) 0.4 $325,000 Subtotal $56.1 MM 20% Contingency $11.2 MM ISBL $67.3 MM OSBL (10% of ISBL) $6.73 MM Fixed Capital Investment (FCI) $74.0 MM Working Capital (20% of FCI) $14.8 MM Start-Up Costs (10% of FCI) $7.40 MM Total Capital Investment (TCI) $96.2 MM 5.3 Operating Costs

The following sections detail the hourly operating costs that accrue during the manufacturing process. They also detail how we estimate and calculate these costs based on a few assumptions. The operating cost allows us to determine the economic feasibility. 5.3.1 Overview Total operating costs are the yearly expenses that the manufacturing plant accumulates from running the manufacturing process and producing the desired product. As a general overview, the total operating cost is made up of manufacturing costs and general expenses. Manufacturing costs are the expenses generated from the raw materials, labor, maintenance, lab supplies, utility costs, as well as plant overhead and fixed costs. General expenses are composed of the administrative and sales/marketing expenses as well as research and development costs. Using a procedure that will be detailed in the following sections we were able to estimate the total operating cost of the process design. The data and calculations can be referenced in Appendix E and are summarized in the table below.

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Table 5.4: Summary of the Key Costs Used in Creating the Total Operating Cost Manufacturing Costs ($/yr) $48.4 MM Direct Costs + Fixed Costs + Plant Overhead Costs General Expenses ($/yr) $4.99 MM Administrative Expense + Sales/Marketing + R&D Total Operating Cost ($/yr) $53.4 MM The following subsections will provide detailed procedures of how we calculated the costs summarized in the table above such as the manufacturing costs, plant overhead, and R&D costs. They also will provide tables that describe these costs. 5.3.2 Manufacturing Costs Manufacturing costs are the expenses that are present because of the process running to produce our desired product. The manufacturing cost includes the direct costs. Direct cost is composed of raw material prices, operating labor costs, supervision/clerical costs, utilities, maintenance, general supplies and lab costs. In addition to this, we included the fixed costs (insurance and property taxes) as well as plant overhead (the business side of the company) in the manufacturing cost. The manufacturing cost is calculated by summing the costs of all of these components which is summarized in the table below. Sample calculations as well as the data in detail can be referenced in Appendix E. Table 5.5: Summary of the Expenses that Constitute the Manufacturing Costs Direct Costs ($/yr) $35.6 MM Fixed Costs ($/yr) $2.69 MM 4% of ISBL (No Rent Assumed) Plant Overhead Costs ($/yr) $10.1 MM 50% of Operating Labor + Supervising + Maintenance Manufacturing Costs ($/yr) $48.4 MM Direct Costs + Fixed Costs + Plant Overhead Costs The following subsections will describe in detail how each of the costs summarized in the table are calculated and why we chose the assumptions that we did in calculating and estimating these costs.

5.3.2.1 Direct Product Costs Direct product costs are the yearly expenses that arise directly from the manufacturing process when it is producing the desired product. It is calculating by summing the raw materials cost, the operating labor cost, supervisory/clerical cost, utilities cost, maintenance cost, supplies cost, and lab cost. The tables below summarize the costs that make up the direct product cost. The rest of the operational cost data as well as sample calculations can be referenced in Appendix E.

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Table 5.6: Operating Labor Costs Calculated Using MichiSite Specifications Operating Labor

Cost ($/hr)

Person per Shift

Shifts Available Man Hours per Person per Shift per Year

Total Hours Worked for 4 Shifts

Total Cost per Year ($)

Operators $35.75 8 4 1922 7688 $8.80 MM Lab Personnel $40.25 1 1 1922 1922 $77,400 Engineers $85.50 1 4 1922 7688 $2.63 MM Total Operating Labor Costs ($/yr) $11.5 MM We chose to run the plant with 8 operators due to the amount of complex equipment in our plant. We run 8 distillation columns continuously in order to keep our reactions running cleanly and producing the desired product. Having 8 operators will ensure that the control schemes implemented in the P&ID Appendix B are not malfunctioning and that everything is running smoothly at steady state. This number of operators will minimize the mistakes and disorganization that could arise when one operator has too many components that are within his responsibility. On each shift, we decided to man an engineer in place to oversee the operators and the efficiency of the plant as a whole over the course of his/her shift. We minimized the cost of multiple engineers on a shift by adding operators which can adequately control the plant processes. In the lab, we man one researcher/scientist in order to test the components in different parts of our process for purity and consistency requirements that we will set once steady state is in place. Table 5.7: Utilities Cost Summary Equipment Total Cooling

Water Costs ($/hr)

Total Steam Costs ($/hr)

Total Refrigerant Costs ($/hr)

Total Electricity Costs* ($/hr)

DSBE Disposal

Heat Exchangers $21.82 $0.00 $253.58 $0.00 $0.00 Distillation Columns $46.14 $308.63 $0.00 $0.00 $0.00 Storage Tanks $0.00 $0.00 $0.00 $0.00 $0.00 Reactors $0.00 $200.29 $0.00 $0.00 $0.00 Flash Drums/Boilers $0.00 $12.33 $0.00 $0.00 $0.00 Pumps $0.00 $0.00 $0.00 $2.20 $0.00 Compressors/Blowers $0.00 $0.00 $0.00 $1.38 $0.00 Total Costs ($/hr) $67.96 $521.25 $253.58 $3.58 $418.60 Total Costs per Year ($/yr) $522,500 $4.0 MM $1.95 MM $31,613 $3.22 MM Total Utilities ($/yr)

$9.73 MM *Adjusted 15% for Electrical

Utilities costs were estimated from the ASPEN models that were used to model the components present in our PFD which can be referenced in Appendix A. Sample calculations for each of these values can be observed in Appendix F. Costs per year are calculated from the cost per hour and the specified man hours for 4 shifts running 24 hours a day 7 days a week which totals out to 7688 plant running hours per year. Electricity costs are increased by 15% from their original value due to fluctuations that are present in energy costs.

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Table 5.8: Raw Materials Cost Summary

Material Cost Amount Needed Units

Running Time

Cost per year

Furfural

$0.45/lb

12213

lb/hr

Once/week

$253,500

MichiPetrol Feed

$3.5/MMBTU

5208

lb/hr

7688 hours

$2.94 MM

Total Raw Materials $3.20 MM/yr All of the costs determined above for each of the raw materials that are shown were found from literature or company specifications which are shown in the attachments in volume 2 of this report. We chose to cycle out the furfural (the entrainer for butane-butene separation via extractive distillation) completely every week because at the conditions that we run our column at the furfural can start to degrade into undesired components in a significant concentration. Also, impurities can start to accumulate in the furfural from imperfect separation from the desired products. We again assume a 7688 hour yearly run time because of the limitations of manning hours from employees given to us by our supervisors. Table 5.9: Summary of Miscellaneous Costs Adding to Direct Costs Supervising/Clerical

17% of Labor Cost Lab Costs

10% of Labor Cost

Maintenance Cost 10% of ISBL

Supplies 20% of

Maintenance

Direct Costs

$1.96 MM/yr

$1.15 MM/yr

$6.73 MM /yr

$1.35 MM /yr

$35.6 MM/yr

We made a few key assumptions when calculating the costs above in table 5.9. Because this is a chemical that is produced in mass quantities all over the world, and the processes for production are well documented, we assumed that the supervising costs would be around the average range of costs for most manufacturing plants. We had a range of 10-25% of the labor cost as limitations for our estimates of the supervising/clerical costs, so we chose right in the middle of that range. [15] For our maintenance costs, we chose the highest percent of the ISBL out of the 2-10% range that we had in our estimate because of the amount of complex machinery that we have in our process. [15] The amount of distillation columns in our process surely means that problems and errors will occur in the control schemes every once in a while, as well as faulty equipment. Thus, this is why we chose a high maintenance cost. We also believed that the supplies that would be needed for keeping the plant clean and maintained properly would be at the highest range of 10-20% of the maintenance costs. [15] We chose this because the plant has a high maintenance cost due to the distillation columns and packed bed reactors with catalyst. All calculations and further data can be referenced in Appendix E.

5.3.2.2 Fixed Charges Fixed charges are the costs that are associated with governmental and state regulations as well as property costs. Luckily for our group, our rent is free because we are building on MichiChem’s plot of land. Thus, our fixed charges are only due to depreciation, insurance, and property taxes. We make an assumption that fixed charges are 4% of the ISBL, which allows us to calculate our fixed charges which come out to be $2.69 MM per year. The procedure for calculating this value can be referenced in Appendix E.

5.3.2.3 Plant Overhead Plant overhead is defined as the business side of the company. The employees that are behind the office desks and deal with the workings of the economic side of the company are included in this cost. We make

46

an assumption that this cost is 50-70% of the operating labor cost, supervising cost, and maintenance cost combined. [15] Because our product and manufacturing processes are well documented in literature and industry, we believe that the overhead will be minimized compared to other processes, and thus assume a 50% of the combined cost which gives us a plant overhead estimate cost of $10.1 MM per year. The procedure to calculate this can be referenced in Appendix E. 5.3.3 General Expenses General expenses are defined as the sum of the administrative costs, the sales/marketing costs, and the research and development costs. A summary of the components that make up the general expenses along with the actual value can be referenced in the table below. A procedure and calculations for these values can be referenced in Appendix E. Table 5.10: Summary of Components of General Expenses Administrative Expenses

($/yr) Sales/Marketing Costs

($MM/yr) R&D

($MM/yr) General Expenses

($MM/yr)

997,000

2.49

1.50

4.99 The following subsections will detail the calculations and method to calculate the components of the general expenses based on assumptions that are made.

5.3.3.1 Administrative Expenses Administrative expenses are the costs associated with work involving the organization and legal work of the company. A typical assumption is to choose the administrative expense as 2-6% of the total operating cost of the company. [15] Because our plant produces such a common chemical that is already sold very well in industry, we chose to have a 2% of total operating cost expense, which brought our administrative expenses to a total of $997,000 per year. The procedure for how this was calculated can be referenced in Appendix E.

5.3.3.2 Sales/Marketing Sales and marketing is defined as the cost of making sure that your company is known by the world and can obtain customers based on their reputation as a quality producer. A typical assumption is that sales/marketing constitutes 2-20% of the total operating cost. [15] We assumed that Sales/Marketing would make up 5% of the total operating cost. This was because although the market for MEK is well established and the chemical has been produced for a significant period of time, the market is saturated where the demand for MEK meets the supply. Thus, it will take some extra costs into sales and marketing in order to break possible longstanding relationships between suppliers and buyers in order to convince them to purchase our product. This brought our total cost for sales/marketing to $2.50 MM per year. The procedure for calculating this value can be referenced in Appendix E.

5.3.3.3 Research and Development Research and development is defined as the cost that is required by the company to create new processes to make the company more efficient, looking into new ways to produce a profit. A typical assumption is that R&D constitutes anywhere from 3-50% of your total operating cost. [15] Because our chemical that we are producing is common and well documented in literature, we chose the minimum of 3% which brought our R&D cost to $1.50 MM per year. The procedure for calculating this can be referenced in Appendix E.

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5.3.4 Total Operating Costs As described before, the total operating cost is defined as the manufacturing cost plus the general expenses. From the previous sections, we can summarize these two costs and the costs that create them in a table below. Table 5.11: General Summary of Expenses Leading to Total Operating Cost

Fixed Costs ($MM/yr) 2.69

Plant Overhead Costs ($MM/yr) 10.1

Direct Costs ($MM/yr) 35.6 Total Operating Labor Costs ($MM/yr) 11.5

Supervising/Clerical ($MM/yr) 1.96 Lab Costs ($MM/yr) 1.15

Total Utilities ($MM/yr) 9.73 Total Raw Materials ($MM/yr) 3.20 Maintenance Cost ($MM/yr) 6.73

Supplies ($MM/yr) 1.35

Manufacturing Costs ($MM/yr) 50.5

Administrative Expenses ($MM/yr) 1 Sales/Marketing Costs ($MM/yr) 2.49

R&D ($MM/yr) 1.5

General Expenses ($MM/yr) 4.99

Total Operating Cost ($MM/yr) 53.4 5.4 Annual Sales Revenue

Revenue is defined as the amount of money that you make from the product that you are producing without considering any of the costs in the process. We calculated revenue from the sales of two product streams, our butane/butene mixture that can be sold as natural gas, and our MEK produced to ASTM standard purity. The revenue generated from this each year is summarized in a table below. Procedures for these calculations can be referenced in Appendix E. Table 5.12: Summary of Calculated Revenue per Year

Material Amount of Product (lb/hr)

Hours of Run Time

(hrs)

Pricing of

Product Units

Avg. Heat of Combustion

(BTU/lb)

Revenue ($/yr)

Liquified Petroleum

Gas 1850.9 7688 3.5 $/MMBTU 21000 $1.04 MM

48

Methyl Ethyl Ketone (MEK)

4833 7688 1.45 $/lb N/A $53.9 MM

Total Revenue ($/yr) $54.92 MM We determined the production from the mass flow rates present from our process design on our PFD which can be referenced in Appendix A. From these flow rates and stream compositions and temperatures we were able to estimate some of the physical properties using ASPEN as a modeling system in the UNIQUAC property method. The heat of combustion was found from literature for liquefied petroleum gas. The pricing for each of the chemicals was also found online from literature. The yearly amount was calculated based on the 4 shift plant run time calculation of 7688 hours proposed previously. The complete calculation for these numbers can be referenced in Appendix F. 5.5 Sell the Feed: The Alternative to Producing MEK

Our problem statement requires us to evaluate the economic viability of selling the feed stream coming from us via MichiPetrol on the open market in comparison to our process design. This means that the cost of our feed which is included in the total operating cost would end up being pure revenue for MichiPetrol. From table 5.8 we can see that this revenue would total $2.94 MM per year. We will use this value in comparison with our profitability analysis to give our recommendation to our supervisors and curious investors in our project design. If we went through with this venture, MichiPetrol would be making this extra profit per year for the 12 years that our theoretical plant was operating, which ends up creating an NPV of $35.3 MM per year which is significantly more profitable than our process in its current design. We assume that MichiPetrol incurs minimal capital costs from building a shipping facility to transport this waste feed and that the operating costs are minimal as well in terms of the revenue that is generated by the waste feed. 5.6 Economic Projections and Profitability

Many different ways to determine the profitability of a process exist. Some do not consider the time value of money such as the rate of return on investment (ROROI), while others do such as the net present value (NPV) and the discounted cash flow rate of return on investment (DCFROROI). The methods that account for the time value of money recognize that invested money can earn more money. Each of these calculations uses a discounted and non-discounted cumulative cash flow diagram that is constructed based on the company’s FCI, WC, start-up costs, revenue, and cost of manufacturing. Depreciation in the cumulative cash flow diagram is modeled by a 10-year MACRS program. We chose this program because of a reasonable assumption that the plant profitability can only be determined on a 10-year operating life. This life span is due to the advances in technology that occur over the course of a decade that may render our current process uneconomical and inefficient in the years to come. We also assumed a 2-year start-up time for construction and installation of materials because that is a typical industry standard. [15] In addition from profitability suggestions based on the calculations in Peters and Timmerhaus, we assumed that the depreciation allowance that is added to the cash flow ceases once the break-even point is reached on the cumulative cash flow diagram, if it is reached at all. These diagrams are the basis of how we are able to calculate our profitability measures that allow us to determine whether this process is a feasible venture to undertake. 5.6.1 Non-Discounted Cumulative Cash Flow Diagram The non-discounted cash flow diagram accounts for the depreciation allowance that occurs when a company’s net cumulative cash flow is negative but it does not account for the interest due to the time

49

value of money. The procedure and sample calculations used to calculate the values on the graph shown below can be referenced in Appendix E, along with the table of calculations that produced this figure.

Figure 5.2: Non-discounted cumulative cash flow diagram used to determine profitability measures

5.6.2 Discounted Cumulative Cash Flow Diagram The discounted cumulative cash flow diagram uses the non-discounted cumulative cash flow that is shown in figure 5.3 above and adjusts for the time value of money by multiplying the non-discounted cash flow by an interest rate raised to the power of the year since start up. In these calculations we assume an after tax interest rate of 10% because that is a value that is common for manufacturing processes of our type. [15] This calculation is summarized below:

𝐷𝑖𝑠𝑐𝑜𝑢𝑛𝑡𝑒𝑑 𝐶𝑎𝑠ℎ 𝐹𝑙𝑜𝑤 = (𝑁𝑜𝑛 − 𝐷𝑖𝑠𝑐𝑜𝑢𝑛𝑡𝑒𝑑 𝐶𝑎𝑠ℎ 𝐹𝑙𝑜𝑤 ∗ 1.1)𝑛 (5) where n is the number of years since start-up of the plant. Using this calculation and calculating the cumulative cash flow, we obtained the discounted cumulative cash flow diagram which is shown below. The procedure for calculating the values along with calculations and a summarized table are referenced in Appendix E.

-100.00

-90.00

-80.00

-70.00

-60.00

-50.00

-40.00

-30.00

-20.00

-10.00

0.000 2 4 6 8 10 12

Non

-Dis

coun

ted

Cum

ulat

ive

Cas

h Fl

ow ($

x M

illio

ns)

Time Since Start Up (Years)

50

Figure 5.3: Discounted cash flow diagram used to calculate NPV, break-even point, and DCFROROI

5.6.3 Net Present Value (NPV) Net present value is defined as the present worth of all cash flows minus the present worth of all capital investments at the time of calculation. It is the amount of money earned above the repayment of all the investments and earnings on those investments at the discounted interest rate (we assume 10%). [15] We calculate our NPV at the end of the 10-year operating period in order to see where our plant stands in terms of making a profit. If the net present value is positive at the given time period where it is calculated, then the plant is making a profit. From our calculations which can be referenced in Appendix E, we found the net present value to be -$37,577,091.20, which is a negative present value. The table below summarizes the analysis. Table 5.13: Summarized Cumulative Cash Flow Table Showing the NPV 12 Years after Start-Up

End of Year

(k)

ND Cash Flow

($ MM)

ND Cumulative Cash Flow ($ MM)

Discounted Cash Flow

($ MM)

Discounted Cumulative Cash Flow

($ MM) 0 -7.40 -7.40 -7.40 -7.40 2 -66.61 -66.61 -55.05 -55.05 2 -88.81 -88.81 -73.39 -73.39 3 4.59 -84.22 3.45 -69.95 4 7.67 -76.55 5.24 -64.71

-80

-70

-60

-50

-40

-30

-20

-10

00 2 4 6 8 10 12

Dis

coun

ted

Cum

ulat

ive

Cas

h Fl

ow ($

x M

illio

ns)

Years Since Start of Start-Up (Years)

51

5 6.28 -70.27 3.90 -60.81 6 5.17 -65.09 2.92 -57.89 7 4.29 -60.80 2.20 -55.69 8 3.58 -57.23 1.67 -54.02 9 3.26 -53.96 1.38 -52.63

10 3.26 -50.70 1.26 -51.38 11 3.27 -47.44 1.14 -50.23 12 3.26 -44.18 1.04 -49.19 12 18.06 -29.37 5.76 -43.44

The non-discounted cumulative cash flows were calculated based on the cost of manufacturing, the revenue, and the depreciation based on the 10-year MACRS system. The calculations for this column can be referenced in Appendix E. The discounted cash flow is calculated based on a 10% interest that we assumed previously that considers the time value of money in investments. Summing all of the cash flows from year zero to the current year allows us to obtain the cumulative cash flow for the discounted and non-discounted systems. This calculation can be summarized in the equation below in the NPV at year n since start up:

𝑁𝑃𝑉 = ∑ 𝐷𝑖𝑠𝑐𝑜𝑢𝑛𝑡𝑒𝑑 𝐶𝑎𝑠ℎ 𝐹𝑙𝑜𝑤𝑛𝑖=𝑜 (6)

A sample calculation for convenience from table 5.13 above showing the NPV in year 5 after start-up:

𝑁𝑃𝑉5 = −73.39 + 3.45 + 5.24 + 3.90 = −60.81 (7)

where the numbers above are multiplied by a million to get the cash value in dollars. The NPV after 12 years suggests that the plant is still in negative cumulative cash flow after the operating life of 10 years, which suggests that this plant is never going to make a profit in the operating time that is laid out for it. This suggests that our process design is not feasible in the operating time that we have set since start up, and that it isn’t a good economic investment. 5.6.4 Discounted Cash Flow Rate of Return on Investment (DCFROROI) The DCFROROI is the return obtained from an investment in which all investments and cash flows are discounted by the interest rate. [15] It is directly related to the NPV. If the NPV is favorable, the DCFROROI will also be favorable, and will describe the actual rate of return on the investment. However, we can see from the calculations above that our NPV is negative. The procedure to calculate the DCFROROI involves setting the NPV to zero and solving for the discount interest rate that allows this to occur using the discounted cash flows in table 5.13 above. This requires an iterative method where the interest rate is guessed, the discounted cash flows calculated based on the interest rate, and the discounted cash flows are calculated to find the NPV. If the NPV equals zero, then the interest rate chosen equals the DCFROROI. However, based on our numbers that are calculated in Appendix E, even if the interest rate was zero percent (which is the case in the non-discounted cumulative cash flow diagram shown in figure 5.3 above) our NPV would still be negative. No matter what interest rate we choose to try to get our NPV equal to zero, it will never reach zero. This led us to the conclusion that we cannot calculate the DCFROROI if the NPV is less than zero. This makes sense based on the theory behind the profitability relations between DCFROROI and NPV. Because we don’t ever make a profit based on the NPV, there isn’t a rate of return of investment that’s possible to calculate that could cost us to break even after 10 years of operating.

52

We cannot actually calculate a DCFROROI because the NPV is negative before starting the iterative calculations; therefore the plant is not feasible for profitability in the 10-year operating life that we have assumed. The plant will not make a profit in the time allotted from production. Therefore, we can conclude that the plant we designed is not a good investment. Normally the DCFROROI is compared to the after tax hurdle rate (which from MichiSite specifications is 10.65%) in order to determine if the plant is a viable option to invest in. If the DCFROROI is higher than the after tax hurdle rate, then the project is a worthwhile investment. Because our DCFROROI cannot be calculated due to the reasoning above, we cannot make a recommendation on the profitability of our plant based solely on the relationship between the DCFROROI and the hurdle rate. The ROROI before taxes was calculated, and found to be 1.6%. This can be referenced in the data of Appendix E. From MichiSite specifications we know the before tax hurdle rate is 22%. Because the ROROI is not greater than the before tax hurdle rate, we can conclude based on this analysis that our process is not a worthwhile investment. 5.6.5 Breakeven Point The break-even point is an approximation of the amount of time that it will take for the NPV to reach zero given that straight-line depreciation is assumed on the discounted cumulative cash flow diagram shown above in figure 5.4. The straight line is approximated by assuming the slope of the line is based on the lowest cumulative cash flow and the NPV after 12 years. The line that we assumed to calculate the break-even point is shown below on the discounted cumulative cash flow diagram.

-80

-70

-60

-50

-40

-30

-20

-10

00 2 4 6 8 10 12

Dis

coun

ted

Cum

ulat

ive

Cas

h Fl

ow ($

x M

illio

ns)

Years Since Start of Start-Up (Years)

53

Figure 5.4: Discounted cumulative cash flow diagram displaying straight line depreciation assumed to calculate the break-even point

From table 5.13 above and the figure shown above the slope of the line is estimated to be:

𝑚 = −43.44−−73.3910

= 3.00 (8)

From this slope and the point of the lowest cumulative cash flow we can estimate the intercept of this line:

𝑏 = −73.39 − 3.00(2) = −79.3 (9) This gives us an estimate linear line equation to calculate the break-even point in the form of y = mx +b where m is the slope calculated above, b is the intercept, x is the time after start up in years, and y is the net present value NPV in millions of dollars. Setting y equal to zero gives us the time until we break even on our profitability.

𝐵𝑟𝑒𝑎𝑘 − 𝐸𝑣𝑒𝑛 𝑃𝑜𝑖𝑛𝑡 = 79.33

= 26.4 𝑦𝑒𝑎𝑟𝑠 (10) As we can see from our break-even point calculation, the time until we would actually be making a profit, assuming that our revenue is constant, is 27 years after start up. This value is also assuming a depreciation allowance throughout those years due to the straight line approximation. Because the operating life of our plant is a maximum of 10 years, this isn’t a good break-even point for investors. This calculation means that we won’t ever be able to make money in the life of the plant, which further leads us to conclude that our plant is not a great investment. 5.6.6 Discounted Pay Back Period (DPBP) The discounted pay-back period is defined as the amount of time it will take to recover the FCI that was given to the company from investors. This FCI is the total amount of negative discounted cumulative cash flow present in table 5.13 above minus the working capital and start-up costs. Again in this calculation, straight line depreciation is used in the exact same way as the line approximated in the calculation for the break-even point. Thus, we will use the same linear equation calculated in section 5.6.5 in this calculation. From table 5.13 the working capital plus the start-up costs is -7.4 million plus -19.83 million which equals -27.23 million dollars. So we use the linear equation described in section 5.6.5 and set y equal to -27.23 to find the DPBP:

𝑦 = 3𝑥 − 79.3 (11) −25.74 = 3𝑥 − 79.3 (12) 𝐷𝑃𝐵𝑃 = 79.3−25.74

3= 17.9 𝑦𝑒𝑎𝑟𝑠 (13)

As we can see, the DPBP is outside the operating life of our plant, but not by a large amount, only 5.9 years. However, we have to understand that the DPBP is the amount of time to recover the money invested, not the time required to make a profit. Thus, the DPBP further concludes what the previous profitability sections have also pointed to. Because we aren’t even able to recover the investor’s initial monetary donation in the operating life of the plant, this process that we designed is not a profitable investment.

54

5.6.7 Present Value Ratio (PVR) The present value ratio is calculated by summing all of the positive cash flows and dividing that number by all of the negative cash flows in the given set of years that the plant is operating. Calculating this we get a present value ratio of 0.408. Peters and Timmerhaus states that if the PVR is greater than 1 then the process is profitable and is a worthwhile investment. [15] As we can see, the PVR is much less than one which further leads us to the conclusion that this process is not profitable in the operating period that we have set and isn’t a good investment. 5.7 Economic Uncertainty

The following subsections describe the uncertainties that we have found in our calculations and assumptions and how they will affect the profitability of the plant design. We also will detail how this will affect our recommendation to investors looking to take part in this plan. 5.7.1 Raw Material Price Fluctuations Because our products and initial reactants in this process are sold in the open market at open value, they are subject to price fluctuations based on world supply and demand for these products. Based on our literature reviews, we found that the raffinate feed bought from MichiPetrol and the LPG sold from our process as a product are both subject to massive price fluctuations depending on the time of the year. Because the feed and the product hydrocarbon mixture are similar in terms of composition, we assume that they are both sold on the open market as natural gas or liquefied petroleum gas (LPG). The demand for these materials increases during the winter months because of the high combustion energy that these materials provide makes them optimal for heating residential and commercial buildings. [16] Because the demand increases during these months, and the supply stays relatively constant, the price of these materials increases. When costing our raw materials, we used the current market price for natural gas at the time that the report was written because this was the most recent material that was available. However, by looking at the natural gas pricing charts in this article over the past year, we can see that the price fluctuated almost 3 dollars per million BTUs. Hence, we are led to the conclusion that our profits could change drastically from these costs and revenues from the hydrocarbon feed and product. Based on literature about the market price for methyl ethyl ketone and the demand we can conclude that the price for methyl ethyl ketone stays relatively constant. [17] The fluctuations of this price are around 3 or 4 cents per lb of MEK produced, which of course will product price fluctuations that will affect our revenues. But nonetheless, our economic model based on the most current market price will still be accurate in terms of the revenue produced from MEK. Furfural, the extragent in Stage 3, on the open market has had a relatively constant pricing for the past year based on our literature review, which leads us to believe that our costing for furfural purchase is accurate in relation to our economic model and projections for profitability. [18] 5.7.2 Projections of Demand for Product Because the price fluctuations for the MichiPetrol natural gas raffinate feed that we use for our product change drastically based on the season in the United States (winter is colder versus summertime) we believe that our profits will increase slightly during the winter months because of the demand for natural gas and liquefied petroleum gas to power furnaces to heat homes and buildings. [16] This projection is based on the assumption that we can buy our raffinate feed from MichiPetrol at a wholesale value and not at a market price. If we have to buy our raffinate and sell our butane/butene product at market price, then our profit will stay constant because they will always be bought and sold at the same market price because they are sold as the same product on the market.

55

In the long term, the liquefied petroleum gas product will have a relatively constant demand due to its ability to easily heat and power furnaces and boilers. We do not project that over the course of the 10 year operating period we will have trouble selling our LPG product on the open market. [16] Methyl ethyl ketone is used as an industrial solvent in laquers and varnishes as well as other industrial production processes. [17] Because the production of these materials stays relatively constant based on projections from literature, we believe that the demand for MEK currently and over the next 10 years during the operation life of the plant will be the same as it is now. [17] Therefore, our profitability based on the revenue from our product will stay around the same value, fluctuating minimally based on the market value. This lends more credibility to our economic profitability analysis. 5.7.3 Considering Inflation Inflation has a negative effect on the profitability of any process when it affects the raw materials and utilities costs necessary to produce the product. [15] This is because as the plant goes on in its operating life the costs of the materials necessary to make it run increases, which increases the total operating costs and decreases the net profit which makes our process less profitable than it was the year before. However, inflation affects not only the inputs of our manufacturing process but our products and outputs as well. The market prices for our products may increase as well due to inflation. If this is the case, then our revenues will increase due to inflation as well. An accurate projection on how inflation would affect our process requires detailed projections on the inflation in the next decade, which can be estimated but is not entirely accurate. Therefore, although we recognize that inflation could affect the economic projections of our plant, we don’t believe that this will change the outlook of our recommendations and economic projections drastically. It would take a very large inflation in the market prices of MEK and LPG to make our process profitable. 5.8 Economic Conclusion/Recommendation

As we can see from our profitability analysis in section 5.7 none of our profitability criteria specify that our process is going to be a good investment. The NPV for our process 12 years after start-up is a significantly negative value, and it would take a large change in our operating costs or capital cost to change this profitability criteria. We can see from the DPBP and the break-even point that we would have to operate significantly out of the range for our plant life (at least 8 years operating time) to even gain back the money that was initially invested. Because of depreciation/deterioration of our plant processes components we cannot guarantee that the revenue we will be initially producing will be constant throughout our manufacturing process. Despite the uncertainty and inaccuracy that could be present in our economic analysis, there is still a small chance that this production process could come close to making the amount of money that would be needed in order to convince investors to provide the TCI needed to start-up and build this manufacturing process. We can see from section 5.5 that if MichiPetrol simply stored and sold their raffinate feed (which is well within the specifications for natural gas and LPG) on the open market they would be estimated to make 2.9 million dollars of profit per year. This would create a positive net present value after the 12 years that it would take to operate our process because with selling this feed they would have a minimal TCI (all that would be needed is to build a storage facility) and minimal operating costs (due to maintaining conditions of storage facilities) along with this significant profit that accrues from simply disposing of a waste feed. Based on the amount of profit that would come from simply selling the waste feed on the open market and the minimal costs associated with that venture along with the massive amount of money that we are

56

losing on our process after a 10 year operating time we would recommend to investors and to MichiChem that producing MEK from this waste feed is not a feasible option, and that selling the waste feed on the open market is the best option for MichiChem. 6.0 ENVIRONMENTAL, HEALTH, AND SAFETY ANALYSIS Below is the Environmental, Health, and Safety Analysis of our MEK production plant based on documented material toxicology, OSHA guidelines, industry practices, and other relevant documentation to our process design. 6.1 Environmental

Regarding the environmental impact our MEK production process, we investigated various methods of handling our process materials. Our materials of concern are hydrogen, MEK, liquefied petroleum gases (LPG), SBA, SBE, TBA, water, furfural, and nitrogen gas. Possible routes of handling our waste in particular are to find ways to recycle them, consider reaction routes to eliminate their hazardous characteristics or for selling as a different product, venting to the atmosphere if legal, and other techniques. The conclusion is to vent hydrogen to the atmosphere, store SBE for hazardous waste disposal, store MEK appropriately as well as vent it along with the hydrogen, and provide preventative measures against ignitions and leaks of TBA, furfural, and the other volatile organics. Water presents a much smaller environmental threat in terms of the atmosphere and spillage, and nitrogen gas is an inert with minimal environmental dangers associated with it. In the Appendices are a collection of MSDSs, EPA articles, and OSHA guidelines on handling the materials in relation to the environment. We will implement industry-established spillage containment and runoff prevention procedures, as well as means of piping or transporting off hazardous materials in the event of emergency leakages for disposal. This is either through publicly owned treatment works (POTW) or through specialized means. Namely, the dike surrounding the plant can contain 53,338 ft3 of spillage, as determined from multiplying the largest tank volume in our plant of 35,559 ft3 by 1.5. The dike height will be 3.56 inches, spanning an area of 180,000 ft2 which our plant is located within. Process, fugitive, and storage and loading emissions have also been considered throughout our process. These contribute to the plant’s overall emissions and can be calculated with the aid of the table and equation below for Synthetic Organic Chemical Manufacturing Industry (SOCMI) as averaged by the EPA. [19]

57

Table 6.1: Average Emission Factors for Fugitive Equipment Leak Emissions [19]

Equipment Service Emission factor (lb/hr/source) Valves Gas 0.0123

Light Liquid 0.0157

Heavy liquid 0.00051

Pumps Seals Light Liquid 0.1089

Heavy liquid 0.0472

Compressor Seals Gas/Vapor 0.503

Gas/Vapor 0.229

Flanges All 0.00183 Open-Ended Lines All 0.0037

Sampling Connections All 0.0331

𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠 𝑏𝑦 𝑚𝑎𝑠𝑠 (𝑘𝑔 𝑜𝑟 𝑙𝑏)

= � 𝑁𝑜. 𝑜𝑓 𝑒𝑞𝑢𝑖𝑝𝑚𝑒𝑛𝑡 𝑐𝑜𝑚𝑝𝑜𝑛𝑒𝑛𝑡𝑠� ∗ �

𝑊𝑒𝑖𝑔ℎ𝑡 % 𝑜𝑓 𝑐ℎ𝑒𝑚𝑖𝑐𝑎𝑙 𝑖𝑛 𝑠𝑡𝑟𝑒𝑎𝑚

�

∗ �𝐶𝑜𝑚𝑝𝑜𝑛𝑒𝑛𝑡 − 𝑠𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝑒𝑚𝑖𝑠𝑠𝑖𝑜𝑛 𝑓𝑎𝑐𝑡𝑜𝑟 � ∗ �𝑁𝑜. 𝑜𝑓

ℎ𝑟𝑠𝑦𝑟

𝑖𝑛 𝑠𝑒𝑟𝑣𝑖𝑐𝑒�

In addition, a set of control techniques and scheduling have been developed by the EPA concerning MEK production in Table 6.2 below, which may act as a scheduling guide for our environmental, health, and safety considerations. [19] Table 6.2 Control Techniques & Efficiencies Applicable to Equipment Leak Emissions [19] Equipment Component (Emission Source) Control Technique

Percent Reduction

Pump Seals Packed &

mechanical Seal area enclosure vented to a combustion device 100 a

Monthly LDAR b 61

Quarterly LDAR 32

Semiannual LDAR 0

Annual LDAR 0

Double mechanical c N/A d -- Compressors Vent degassing reservoir to combustion device 100 a Flanges None available 0 Valves

Gas Monthly LDAR 73

Quarterly LDAR 64

Semiannual LDAR 50

Annual LDAR 24

58

Liquid Monthly LDAR 59

Quarterly LDAR 44

Semiannual LDAR 22

Annual LDAR 0 Pressure Relief Devices

Gas Monthly LDAR 50

Quarterly LDAR 44

Rupture Disk 100 Sample Connections Closed-purge sampling 100 Open-ended Lines caps on open ends 100

a Combustion devices approach 100 percent control efficiency. b LDAR (Leak detection and repair program). c Assumes the seal barrier fluid is maintained at a pressure above the pump stuffing box pressure and the system is equipped with a sensor that detects failure of the seal and/or barrier fluid system. d N/A (Not applicable). There are no volatile organic compound emissions from this component. 6.1.1 Hydrogen and the Environment According to MSDS information, no adverse ecological effects are expected from hydrogen being released into the atmosphere. Hydrogen is also not listed as a marine pollutant by the Department of Transportation (DOT). [20] Because of MEK’s high reactivity, it is estimated to have a short lifetime in the atmosphere of ~11 hours. Atmospheric lifetime is defined as the time required for the concentration to decay to 1/e (37%) of its original value [21] Hydrogen (40.9 wt % MEK content) is primarily released from blower C-403 after its separation from MEK. This is acceptable with MEK, as MEK was taken off the list of hazardous air pollutants by the EPA under the Clean Air Act, effective since 2005 [22]. In addition, use of the C-403 dramatically reduces the chance of an ignitable vapor mixture from forming. The downstream installation of the hydrogen release tower at 16 feet above the highest structure in its vicinity minimizes the risk of ignition of the vented vapors as well. [35] For information on hydrogen’s combustion hazards, see section 6.2.2.1. 6.1.2 MEK and the Environment The MSDS for MEK states that its vapor pressure is 1.52 psi at 68 °F (20 °C). [23] MEK may be emitted to the atmosphere during its production and storage. [24] Process emissions can be expected from the dehydrogenation reactor, the MEK purification tower, and condensers E-401 and E-501. Most notably is the controlled release of a 40.9 wt % MEK with 50.1 wt % hydrogen stream from blower C-403 to the atmosphere. This is acceptable with, as MEK was taken off the list of hazardous air pollutants by the EPA under the Clean Air Act, effective since 2005 [22]. In addition, use of the C-403 dramatically reduces the chance of an ignitable vapor mixture from forming. Fugitive emissions can be expected from separation drum D-401 and reflux drum D-501, and storage and loading emissions can be expected from MEK storage tank TK-503. [19] For information on the combustion hazards of MEK, see section 6.2.2.1. Once MEK is in the atmosphere, it is expected to undergo a vapor-phase reaction with photo chemically produced hydroxyl radicals, where the half-life for this process is approximately 1 day. [24] If MEK finds itself in nearby sources of water, it is expected to undergo microbial degradation under both aerobic and anaerobic conditions. Chemical oxidation, direct photolysis, and hydrolysis of 2-butanone under environmental conditions are not expected to occur to any significant extent. [24] Very much like MEK in water, it may degrade in soil under aerobic and anaerobic conditions. It is not expected to hydrolyze, undergo photolysis on the surface, or undergo chemical degradation. [24]

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Spillage containment in the form of a dike or specially design sewer system will surround the MEK storage tank. Once the necessary amounts of carbon adsorbents are used on spills, the spent carbon will be packed off, piped and/or transported by other means to a hazardous material processing zone i.e. burner for incineration, as governed by OSHA guidelines for proper disposal. [25, 36] 6.1.3 Liquefied Petroleum Gas (LPG) and the Environment: 1-butene, 2-butene,

Isobutane, Isobutene, N-butane Based on the ecological profiles of all the components of the LPG in our system, they are all environmentally stable and will dissipate in well-ventilated areas. Regarding its effect on animals and plant life, no adverse effect is expected with the exception of frost produced in the presence of rapidly expanding gases. Lastly, little evidence is currently available on the effects of these LPG components on aquatic life. [26, 27, 28, 29, 30, 31] Process emissions can be expected from the hydration reactor R-101, SBA purification tower T-201, the butane separation tower T-601, and the furfural recovery tower T-602. Fugitive emissions can be expected from the feed boiler B-101, compressor C-101, condenser E-202, reflux drum D-201, condensers E-601, E-602, reboiler E-603, reflux drums D-601, and D-602. Storage and loading emissions can be expected from the butane storage tank TK-601. Spillage containment in the form of a dike or specially design sewer system will surround the LPG-containing vessels. Once the necessary amounts of carbon adsorbents are used on spills, the inerted material will be piped or transported by other means to a hazardous material processing zone as governed by OSHA guidelines for proper disposal. [25] 6.1.4 SBA and the Environment Process emissions can be expected from the hydration reactor R-101, distillation column T-201, SBA purification tower T-302, SBE removal tower T-303, dehydrogenation reactor R-401, and SBA purification tower T-503. Fugitive emissions can be expected from condenser E-202, reflux drum D-201, decanter D-301, condensers E-301,E-304, reflux drum D-302, reboiler E-303, flash drum D-401, condenser E-401, separation drum D-401, and exchanger E-402. 2-Butanol is readily biodegradeable by bacteria and does not bioaccumulate. It is not toxic for aquatic animals, algae, protozoa, or bacteria. However, 2-Butanol should still be managed in the environment as a slightly toxic compound as it poses an indirect hazard for the aquatic environment. [31] Spillage containment in the form of a dike or specially design sewer system will surround the SBA-containing vessels. Once the necessary amounts of carbon adsorbents are used on spills, the inerted material will be piped or transported by other means to a hazardous material processing zone as governed by OSHA guidelines for proper disposal. [25] 6.1.5 SBE and the Environment Substantial amounts of data are not readily available on the ecological effects of SBE. [33] However, containment and carbon absorbent are the recommended procedures to cleaning up spills. Very small weight percentages of SBE are found throughout process, so major process emissions of SBE can expected from the SBE removal tower T-303, MEK purification tower T-502, and SBA separation tower T-503. Fugitive emission can be expected from reboilers E-305, E-503, and E-504. Storage and loading emissions can be expected from SBE storage tank TK-801. Since such little SBE is sent to storage, it is more economical to dispose of it with the Michisite pricing $0.95/lb for hazardous waste than to develop and invest in a process to convert it into nonhazardous material. Spillage containment in the form of a dike or specially design sewer system will surround the SBE-containing vessels. Once the necessary amounts of carbon adsorbents are used on spills, the inerted

60

material will be piped or transported by other means to a hazardous material processing zone as governed by OSHA guidelines for proper disposal. [25] 6.1.6 TBA and the Environment TBA is not found in substantial concentrations or amounts throughout our process. Even so, TBA is not subject to EPA emergency planning requirements under the Superfund Amendments and Reauthorization Act. Also, employers are not required by the Comprehensive Environmental Response, Compensation, and Liability Act to notify the National Response Center of an accidental release of TBA. (There is no reportable quantity for this substance.) Nonetheless, our focus here is a clean and safe workplace environment. In the event of a spill, potentially explosive atmospheres are to be ventilated. Water spray may be used to reduce vapors, but the spray may not prevent ignition in closed spaces. Dikes far ahead of the spill will contain the TBA for later reclamation or disposal. Carbon absorbent material will be used at this point. [34] 6.1.7 Water Handling The liquid water used within our process is completely contained for the hydration reaction and its deionization and recycling systems. The water leaving the plant facility grounds is simply the water from Michisite for heat exchange purposes, where the temperature of the water leaving our processes must not exceed 120 °F before being sent to the cooling towers and back to Michisite. Our process inherently is designed to abide by this restriction with the use of various heat-exchange equipment. This water is industrial grade but possesses minimal toxicity, so no ecological effects are of concern. [35] In the event of a spill of contaminated water from within the hydration and its supporting processes, spillage containment in the form of a dike or specially designed sewage system will be in place surrounding the relevant vessels (R-101, T-201, T-301, and D-301). The water used in the hydration reaction contacts essentially all of our initial and intermediate organic materials of our process (N-butene feed, SBA, SBE, TBA). Spillage from the deionizer vessel R-102 is not an issue chemically to the environment. However, for spills from units where water contacts organic materials, once the necessary amounts of carbon adsorbents are used on spills, the inerted material will be piped or transported by other means to a hazardous material processing zone as governed by OSHA guidelines for proper disposal. [25] 6.1.8 Furfural and the Environment The ecological effects of furfural on the environment are not widely documented. Limited evidence is available on the harmful effects on animal and aquatic life [36] However, a relatively minuscule amount is used (0.1 lb/hr) in the butane-butene separation process leaving TK-602. Larger amounts are recovered in downstream processes, such as in T-601 and T-602, but are completely contained. The reportable quantity of furfural is 5,000 pounds according to the EPA. In terms of vapor emissions, it is toxic if inhaled and procedures are available to mitigate such a release to the environment e.g. proper ventilation. [37] Overall, the amount of furfural in our process does not raise concerns on its impact on the environment, as we will also divert any possible spillage away from drains and the environment. In the event of a liquid furfural spill, containment in the form of a dike or specially design sewer system will surround the furfural-containing vessels. Once the necessary amounts of carbon adsorbents are used on spills, the inerted material will be piped or transported by other means to a hazardous material processing zone as governed by OSHA guidelines for proper disposal. Furfural disposal when recharged will be handled in a similar manner. [25] 6.1.9 Nitrogen and the Environment Nitrogen is an inert substance and in its gaseous form and has no adverse ecological effects both in the air and to marine environments. [38] Nonetheless, OSHA standards are in place in the event of gaseous

61

leakage from the streams pressurizing various vessels throughout the MEK plant. [39] Health and safety concerns are a greater risk, as described in section 6.2.9. 6.2 Health and Safety

We have gathered all of the relevant MSDS and health-related information on the hazardous chemicals of our processes. OSHA regulations and standards are available to keep a safe environment for working plant employees as well as that of the community. Employees will be trained extensively in the safe operation of equipment related to their respective duties in addition to being provided proper Personal Protection Equipment (PPE). Eyewash stations and safety showers will be located appropriately throughout the plant. A pre-startup review will be scheduled as well. Pressurized vessels with code-built specifications will only be allowed to be operated on only by code-certified welders, technicians, etc. For any work involving a spark-producing type of work, the Chief Operator will issue hot-work permits and ensure that non-sparking tools are used e.g. beryllium tools. Modifications and relevant changes to be made to process equipment will require adherence to management-of-change (MOC) procedures. Incident investigation reports will be issued when appropriate. The plant will be sure to adhere to compliance audits when conducted. Lastly, emergency procedures will be abided by all personnel and visitors of the plant according to OSHA’s guidelines and regulations in the event of such emergencies. All hazardous chemicals are appropriately handled from the beginning to the end of their use in our design. As mentioned above, the procedures are to vent hydrogen to the atmosphere, store SBE for hazardous waste disposal, store MEK appropriately as well as vent it along with the hydrogen, and provide preventative measures against ignitions and leaks of TBA, furfural, and the other volatile organics. Water presents a much smaller safety issue in terms of spillage, and nitrogen gas is an inert with minimal dangers associated with it. 6.2.1 Hydrogen Safety Measures Below is information on safety measures prepared for hydrogen based on its explosive properties, exposure effects, and documented preventative procedures. 6.2.1.1 Explosive Properties of Hydrogen Approximately 88 lb/hr of hydrogen will be released to the atmosphere from the dehydrogenation process through carbon steel equipment, as there is minimal danger of hydrogen ignition with the air in the absence of a confined space. In addition, the installation of the hydrogen release tower at 16 feet above the highest structure in its vicinity minimizes the risk of ignition of the vented vapors. [35] After leaving the separation drum D-401, the separated hydrogen (with 40.9 wt% MEK content) goes to the blower, BL-401, which helps reduce an ignitable vapor mixture concentration buildup as well. Combustion and explosion properties of hydrogen compared to other combustible materials are listed below: [40]

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Table 6.3: Combustion & Explosion Properties of Hydrogen, Methane, Propane & Gasoline [40] Property Hydrogen Methane Propane Gasoline

Density of gas at standard conditions, kg/m3 (STP)

0.084 0.65 2.42 4.4

Heat of vaporisation, J/g 445.6 509.9 250 – 400

Lower heating value, kJ/g 119.93 50.02 46.35 44.5

Higher heating value, kJ/g 141.8 55.3 50.41 48 Thermal conductivity of gas at standard conditions, mW cm–1 K–1

1.897 0.33 0.18 0.112

Diffusion coefficient in air at standard conditions, cm2/s

0.61 0.16 0.12 0.05

Flammability limits in air, vol % 4.0 – 75 5.3 – 15 2.1 – 9.5 1 – 7.6 Detonability limits in air, vol % 18.3 – 59 6.3 – 13.5 1.1 – 3.3 Limiting oxygen index, vol % 5 12.1 11.6

Stoichiometric composition in air, vol % 29.53 9.48 4.03 1.76

Minimum energy for ignition in air, mJ 0.02 0.29 0.26 0.24

Autoignition temperature, K 858 813 760 500 – 744

Flame temperature in air, K 2318 2148 2385 2470 Maximum burning velocity in air at standard conditions, m/s

3.46 0.45 0.47 1.76

Detonation velocity in air at standard conditions, km/s

1.48 – 2.15 1.4 – 1.64 1.85 1.4 – 1.7

Energy of explosion, mass-related, gTNT/g 24 11 10 10

Energy of explosion, volume-related, gTNT/m3 (STP)

2.02 7.03 20.5 44.2

Hydrogen at high purity, as may be found in our system, must react with an oxidizer in stoichiometric amounts before any hazardous reaction can take place. Air is the greatest concern, whether hydrogen is released into the air, or air leaks into the hydrogen system. The lower detonability limit is 18% hydrogen in air. A trail of pure hydrogen can rise as fast as 9 m/s. [21] Hydrogen combustion comes in two forms: deflagration and detonation. These generate high temperatures, shockwaves, and overpressures. Shockwaves could also cause equipment damage and further release of hydrogen. Table 6.4 lists some of the characteristics of deflagrations and detonations.

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Table 6.4: Deflagration and Detonation Characteristics [21] Characteristic Deflagration Characteristics Energy Transport Type Diffusion of radical species Shock wave Flame Temperature 2045 C (3713) 2674 C (4845 F) Flame Velocity 2.7-1294 m/s >1800 m/s Rate of Pressure Onset 1-100 ms 2-20 ∝s Range of Final Pressure to Initial 1- 8 15-20 Unburned Gas Pressure

Both processes require confinement such as pipes, ducts, narrowly spaced walls, or large initiation energies to occur. Keeping the hydrogen dispensing system away from structures will give plumes from a large release a chance to rise. In the open air, powerful explosives or very large sparks are required to initiate detonation. [21] The worst-case scenario is the buildup of a large cloud of hydrogen, where its ignition can burn personnel or cause other fires with surrounding combustible materials. Combustion of a hydrogen cloud occurs fully within 1 to 2 seconds. Personnel caught in close proximity may be severely burned; and flammable liquids, if directly exposed, may be ignited. [21] 6.2.1.2 Consequences of Hydrogen Exposure Leaks may pose a hazard to neighboring system components or personnel directly exposed to combustible mixtures in the area of the leak. The concern includes not only direct exposure to hydrogen combustion over a larger area, but exposure to thermal and UV radiation that may cause burns, shrapnel ejection, and the possibility of further ignition with nearby sources. [21] Hydrogen does not show poisonous effects regarding its inhalation other than sleepiness and a high-pitched voice. Even smoke inhalation due to hydrogen fires is not considered as serious since its combustion product is water vapor (unlike other types of fires where smoke inhalation is considered the major cause of injury). However, if the oxygen content sinks below 18% in volume due to hydrogen accumulation in the atmosphere of some confined space, then a danger of asphyxiation is present. Direct skin contact with cold gaseous or liquid hydrogen leads to numbness and a whitish coloring of the skin or even frostbite. However, liquid hydrogen is not present at all in our process, so this is not a concern. [41] 6.2.1.3 Preventative Measures Against Hazards of Hydrogen To deal with the above dangers, a restricted space in the area of BL-401, as defined according OSHA, can be referenced and considered for our purposes. This restricted zone requires at least 25 ft of separation from stored flammable materials or oxidizing gases, open flames, ordinary electrical equipment or other sources of ignition, and concentrations of people. Other required distances are described according to OSHA. [42] Personnel working within this zone will typically be operators who are specifically trained with the surrounding dehydrogenation equipment along with wearing the proper PPE. Leak checks by these trained personnel will be performed on a regular basis (as shown in Table 6.2) with the aid of portable hydrogen sensors (which are more sensitive to detecting smaller leaks).General personnel and the public are prohibited from this restricted space. In response, the types of issues that are more likely for our plant design are small gas leaks at valve stems or connectors which could release very small quantities of hydrogen under normal operating conditions. Our system is to be built under ASME standards which allows for this robustness. [21] In terms of equipment, the hydrogen release-to-atmosphere system and associated operations should be safe, posing no risks greater than current EPA operations to the personnel, operations, existing facilities, and surrounding public. [21]

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Primary safety precautions implement engineering measures such as prevention of leakage and formation of explosive mixtures e.g. open-air installation, flame arrestors, etc. The installation of blower BL-401 will minimize this hazard greatly as mentioned above. The next level of measures consists mainly with maximizing the proximity of the hydrogen source from ignition sources. These ignition sources may be electrostatically or mechanically generated by the surrounding equipment, except we will abide by the spacing rules. The last level of measures deals with minimizing the consequences of explosions and other hazards that result. Installation of explosion-proof or relief systems, hydrogen process shut-down systems, strategic placement of hydrogen leak detection devices in between packed-bed reactor R-401 and separator D-401, and fire extinguishing systems are considered. [41] 6.2.2 MEK Safety Measures Below is information on safety measures prepared for MEK based on its explosive properties, exposure effects, and documented preventative procedures. 6.2.2.1 Explosive Properties of MEK The physical properties of MEK, including explosive ones, can be found in its MSDS. [23] The lower explosive limit (LEL) and upper explosive limit (UEL) is 2% and 12% volume of MEK in air, respectively. The flashpoint is 19.4 °F and the ignition temperature is 759.2 °F. MEK is found in the stream leaving the dehydrogenation reactor, the stream entering the MEK purification process, and its eventual storage tank. Process emissions can be expected from the dehydrogenation reactor, the MEK purification tower, and condensers E-401 and E-501. Fugitive emissions can be expected from separation drum D-401 and reflux drum D-501, and storage and loading emissions can be expected from MEK storage tank TK-503. [19] Otherwise, MEK in our plant design is completely contained. 6.2.2.2 Consequences of MEK Exposure From the emission sources as described above of MEK, there are indeed explosive hazards, where creating an explosive mixture with the air is a significant concern, along with thermal decomposition into Carbon monoxide (CO), Carbon dioxide (CO2) as irritating gases and vapors. The MSDS on MEK in goes into greater toxicological detail, where our OSHA trained personnel and safety procedures will be developed around. [23] Leaks may pose a hazard to neighboring system components or personnel directly exposed to combustible mixtures in the area of the leak. The concern includes not only direct exposure to MEK combustion over a larger area, but exposure shrapnel ejection and the possibility of further ignition with nearby sources. 6.2.2.3 Preventative Measures Against Hazards of MEK To deal with the above dangers, stored flammable materials or oxidizing gases, open flames, ordinary electrical equipment or other sources of ignition, and concentrations of people (untrained personnel or other individuals) will be kept at a safe distance away from the MEK emission source units in the dehydrogenation, MEK purification, and MEK storage areas of our plant. Personnel, with their PPE, working within this zone will typically be operators who are specifically trained with the surrounding equipment by OSHA standards. Leak checks by these trained personnel will be performed on a regular basis (as shown in Table 6.2 Our system is to be built under ASME standards which allows for this robustness. In terms of equipment, the operations associated with MEK should be safe, posing no risks greater than current EPA operations to the personnel, operations, existing facilities, and surrounding public. Carbon steel piping and equipment will be used. In particular for the storage tank TK-503, this will be made of steel and requires an inert nitrogen stream to keep the MEK contents under pressure (to avoid vaporization into an explosive mixture with air) in addition to excluding air from the upper space within

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the tank. A pressure relief valve will be installed on this tank as well as on the vessels of fugitive sources of emission [19] Primary safety precautions implement engineering measures such as prevention of leakage and formation of explosive mixtures e.g. open-air installation, flame arrestors, etc. The next level of measures consists mainly with maximizing the proximity of the hydrogen source from ignition sources. These ignition sources may be electrostatically or mechanically generated by the surrounding equipment, except we will abide by the spacing rules. The last level of measures deals with minimizing the consequences of explosions and other hazards that result. Installation of explosion-proof or relief systems, process shut-down systems, and fire extinguishing systems are considered. 6.2.3 Liquefied Petroleum Gas Safety Measures: 1-butene, 2-butene, Isobutane, Isobutene,

N-butane Below is information on safety measures prepared for LPG based on its explosive properties, exposure effects, and documented preventative procedures. 6.2.3.1 Explosive Properties of LPG Throughout our process, we implement high safety standards due to the hazardous nature of LPG. It is flammable and can release large amounts of flammable gas if leakage occurs. This accumulation can travel substantial distances from the source before reaching an ignition source. Leaked LPG readily accumulates at low points, including open and closed drains and sewers as it is heavier than atmospheric air. [43] Further properties can be found in the LPG components’ MSDSs. [26, 27, 28, 29, 30, 31] 6.2.3.2 Consequences of LPG Exposure Toxicological information is described in the MSDS documentation of the LPG constituents. OSHA standards and training will be provided for relevant employees, as well as being given proper training and PPE. In terms of inhalation, LPG is an asphyxiant and can cause suffocation. On the other hand, it is not considered toxic. Established measures focus on preventing exposure of people to suffocating atmospheres caused by LPG. For example at our plant, personnel are not permitted to enter a vessel unless that vessel has been physically disconnected from other plant equipment (de-energized) and purged with inert gas e.g nitrogen, etc. [43] 6.2.3.3 Preventative Measures Against Hazards of LPG Safety measures are taken to minimize the likelihood of unintended leakage and eliminate ignition sources. When controlled leakage of LPG from storage or plant must occur for various reasons, the LPG must be piped to a safe location for disposal in a controlled manner. Thus, equipment used in the processing and storage of LPG is constructed according to the appropriate codes. These specify construction materials, wall thickness, inspection requirement, safety relief valves, depressurizing facilities, flooding systems, inert nitrogen streams, and emergency shutdown valves. Ignition sources are also kept out of plant or storage areas containing LPG. Lastly, static electricity as a source of ignition is prevented by having all such equipment grounded. [43, 44] Primary safety precautions implement engineering measures such as prevention of leakage and formation of explosive mixtures e.g. open-air installation, flame arrestors, etc. The next level of measures consists mainly with maximizing the proximity of the hydrogen source from ignition sources. These ignition sources may be electrostatically or mechanically generated by the surrounding equipment, except we will abide by the spacing rules. The last level of measures deals with minimizing the consequences of explosions and other hazards that result. Installation of explosion-proof or relief systems, process shut-down systems, and fire extinguishing systems are considered.

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6.2.4 SBA Safety Measures Below is information on safety measures prepared for SBA based on its explosive properties, exposure effects, and documented preventative procedures. 6.2.4.1 Explosive Properties of SBA The physical properties of SBA, including explosive ones, can be found in its MSDS. [45] The LEL and UEL is 1.7% and 9.8% volume of SBA in air, respectively. The flashpoint is 75 °F closed cup and 87.8°F open cup. The ignition temperature is 763 °F. SBA in our plant design should be completely contained. If SBA is leaked, it readily accumulates at low points, including open and closed drains and sewers as it is heavier than atmospheric air. 6.2.4.2 Consequences of SBA Exposure From the emission sources as described above of SBA, there are indeed explosive hazards, where creating an explosive mixture with the air is a significant concern. The MSDS on SBA in goes into greater toxicological detail, where our OSHA trained personnel and safety procedures will be developed around. [45] Leaks may pose a hazard to neighboring system components or personnel directly exposed to combustible mixtures in the area of the leak. The concern includes not only direct exposure to SBA combustion over a larger area, but exposure shrapnel ejection and the possibility of further ignition with nearby sources. 6.2.4.3 Preventative Measures Against Hazards of SBA To deal with the above dangers, stored flammable materials or oxidizing gases, open flames, ordinary electrical equipment or other sources of ignition, and concentrations of people (untrained personnel or other individuals) will be kept at a safe distance away from the SBA emission source units. Personnel, with their PPE, working within this zone will typically be operators who are specifically trained with the surrounding equipment by OSHA standards. Leak checks by these trained personnel will be performed on a regular basis (as shown in Table 6.2). Our system is to be built under ASME standards which allows for this robustness. In terms of equipment, the operations associated with MEK should be safe, posing no risks Primary safety precautions implement engineering measures such as prevention of leakage and formation of explosive mixtures e.g. open-air installation, flame arrestors, etc. The next level of measures consists mainly with maximizing the proximity of the hydrogen source from ignition sources. These ignition sources may be electrostatically or mechanically generated by the surrounding equipment, except we will abide by the spacing rules. The last level of measures deals with minimizing the consequences of explosions and other hazards that result. Installation of explosion-proof or relief systems, process shut-down systems, and fire extinguishing systems are considered. When leakage of SBA occurs for various reasons, the SBA must be piped to a safe location for disposal in a controlled manner. 6.2.5 SBE Safety Measures Below is information on safety measures prepared for SBE based on its explosive properties, exposure effects, and documented preventative procedures. 6.2.5.1 Explosive Properties of SBE Throughout our process, we implement high safety standards due to the hazardous nature of SBE. It is flammable and can release large amounts of flammable gas if leakage occurs. This accumulation can travel substantial distances from the source before reaching an ignition source. Its flashpoint is 77 °F,

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ignition temperature is 347° F, LEL % volume in air is 0.9, and UEL is 8.5. Ethers form peroxides or hydroperoxides in the presence of atmospheric oxygen which can cause explosions. The peroxides can be neutralized by treatment with an iron(II) salt solution, titanium (III) salt solution, potassium pyrosulfite, or triethylentetramine. [46] 6.2.5.2 Consequences of SBE Exposure SBE is a poison by inhalation, and when it decomposes through heat input it emits acrid smoke and irritating vapors. Leaks may pose a hazard to neighboring system components or personnel directly exposed to combustible mixtures in the area of the leak. The concern includes not only direct exposure to combustion over a larger area, but exposure to shrapnel ejection and the possibility of further ignition with nearby sources. [33] 6.2.5.3 Preventative Measures Against Hazards of SBE Primary safety precautions implement engineering measures such as prevention of leakage and formation of explosive mixtures e.g. open-air installation, flame arrestors, etc. The next level of measures consists mainly with maximizing the proximity of the SBE source from ignition sources. These ignition sources may be electrostatically or mechanically generated by the surrounding equipment, except we will abide by the spacing rules. The last level of measures deals with minimizing the consequences of explosions and other hazards that result. Installation of explosion-proof or relief systems, process shut-down systems, inert nitrogen streams, and fire extinguishing systems are considered. [33] Equipment used in the processing and storage of SBE is constructed according to the appropriate codes. These specify construction materials, wall thickness, inspection requirement, safety relief valves, depressurizing facilities, flooding systems, and emergency shutdown valves. 6.2.6 TBA Safety Measures Below is information on safety measures prepared for TBA based on its explosive properties, exposure effects, and documented preventative procedures. 6.2.6.1 Explosive Properties of TBA The physical properties of TBA, including explosive ones, can be found in its MSDS. [47] The LEL and UEL is 2.4% and 8.0% volume of MEK in air, respectively. The flashpoint is 52 °F and the ignition temperature is 892 °F. TBA in our plant design is completely contained. 6.2.6.2 Consequences of TBA Exposure From the emission sources as described above of TBA, there are limited explosive hazards. The MSDS on TBA goes into greater toxicological detail, where our OSHA trained personnel and safety procedures will be developed around. [47] Also, the effect of TBA on humans includes eye, skin, and mucous membrane irritation. At high concentrations, it causes narcosis. [34] Leaks may pose a hazard to neighboring system components or personnel directly exposed to combustible mixtures in the area of the leak. The concern includes not only direct exposure to TBA combustion over a larger area, but exposure shrapnel ejection and the possibility of further ignition with nearby sources. 6.2.6.3 Preventative Measures Against Hazards of TBA To deal with the above dangers, stored flammable materials or oxidizing gases, open flames, ordinary electrical equipment or other sources of ignition, and concentrations of people (untrained personnel or other individuals) will be kept at a safe distance away from the TBA emission source. Personnel, with their PPE, working within this zone will typically be operators who are specifically trained with the surrounding equipment by OSHA standards. Leak checks by these trained personnel will be performed on

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a regular basis (as shown in Table 6.2). Our system is to be built under ASME standards which allows for this robustness. For extinguishing fires involving TBA, dry chemical, carbon dioxide, alcohol foam, or water fog will be used. Water spray may be used to cool fire-exposed containers, as it may be ineffective to directly use water on the fire. If a leak or spill has not ignited, water spray may be used to disperse vapors and to dilute spills to a nonflammable mixture. Dikes should be used to contain fire-control water for later disposal. 6.2.7 Water Safety Measures As described in the environmental section for water handling, Spillage from the deionizer vessel R-102 is not an issue chemically to the environment. [35] However, the temperature of the water may be of concern if personnel come into contact and receive burn injuries as a result. In particular, this is in the form of hot steam and condensate exposure wherever they are used for heating in the process e.g vaporizer D-401, packed-bed reactor R-401, reboilers, heat exchangers etc. Signs of cracked surfaces, bulges, corrosion or other deformities should be repaired by an authorized technician immediately to prevent such leakage. Once again, trained personnel with proper PPE will only be allowed in the vicinity of the equipment and units, where these equipment and units have been separated the recommended distances away. [37] 6.2.8 Furfural Safety Measures Below is information on safety measures prepared for furfural based on its explosive properties, exposure effects, and documented preventative procedures.

6.2.8.1 Explosive Properties of Furfural Furfural is a flammable substance with an LEL of 2.1% and a UEL of 19.3% by volume. The flashpoint is 140 °F closed cup, and the ignition temperature is 599 °F. Throughout our process, we implement high safety standards. Furfural accumulates at low points, including open and closed drains and sewers as it is heavier than atmospheric air. Further properties can be found in the MSDS for furfural. [36]

6.2.8.2 Consequences of Furfural Exposure Furfural is toxic as an inhalant and causes irritation on physical contact. The MSDS on furfural in goes into greater toxicological detail, where our OSHA trained personnel and safety procedures will be developed around. [36] Leaks may pose a hazard to neighboring system components or personnel directly exposed to combustible mixtures in the area of the leak. The concern includes not only direct exposure to furfural combustion over a larger area, but exposure shrapnel ejection and the possibility of further ignition with nearby sources.

6.2.8.3 Preventative Measures Against Hazards of Furfural Safety measures will be conducted similar to that for hydrogen, MEK, LPG, etc. as documented above. [37] 6.2.9 Nitrogen Safety Measures Below is information on safety measures prepared for nitrogen based on its explosive properties, exposure effects, and documented preventative procedures.

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6.2.9.1 Explosive Properties of Nitrogen Compressed nitrogen is nonflammable and does not support combustion. Explosive hazards still do exist, though, where a vessel pressurized with nitrogen exposed to intense heat or a flame source may vent rapidly and/or rupture violently. [38]

6.2.9.2 Consequences of Nitrogen Exposure Nitrogen is a simple asphyxiant as a gas, where an emergency would require a self-breathing contained apparatus (SCBA) or a positive pressure air line with mask and escape pack in the affected zone e.g. oxygen concentration less than 19.5%. Otherwise, respiratory protection is not required. Serious issues do occur, however, with inhalation of nitrogen in excessive concentrations. This leads to dizziness, nausea, vomiting, and loss of consciousness. With pure nitrogen, fainting happens immediately without warning followed shortly by death a few seconds after. Skin and eye contact pose no threats. [38, 98]

6.2.9.3 Preventative Measures Against Hazards of Nitrogen Most cylinders are designed to vent contents when exposed to elevated temperatures. Pressure in a container can build up due to heat and may rupture if pressure relief devices fail. In response, safety measures will be conducted similar to that for hydrogen, MEK, LPG, etc. as documented above. [39] Concerning the inhalation hazards known to occur with nitrogen, use of ventilation systems, atmospheric monitoring, retrieval systems, etc will be used and routinely inspected around vessels using nitrogen in their process. Safe handling of air and nitrogen delivery systems must be communicated and implemented appropriately to employees and contractors, where specifically the fittings for air and nitrogen tanks should be incompatible to avoid confusion and environments not meant to contain elevated levels of nitrogen (such as purging confined spaces for personnel entry). Also, training should cover rescue procedures in the form of body harnesses and lifelines, worn by multiple personnel, before entry into confined spaces. This allows the rescuer to retrieve the victim without exposing his/herself to the unsafe confined space if dangerous levels of nitrogen are unknowingly present. The last measure of defense would be for a trained individual to don proper PPE and physically retrieve and carry the victim out from the space. General safety procedures apply as well e.g. confined space entry, work permits, etc. [39] 7.0 LIMITATIONS, UNCERTAINTIES, AND ALTERNATIVES The following section explains the limitations, uncertainties, and alternatives considered for the process and economics. 7.1 Limitations

The major factors that have limited the completeness of the project are the lack of the butene-butane separation resources, not being able to achieve an 100% 2-butene recovery from the butene-butane separation, the reactors were sized as heat exchangers, and not knowing the rate laws for both the hydration and dehydrogenation reaction. Only two articles from the 1930s and 1940s were found that dealt with butene-butane separation with an entrainer, sulfur dioxide and furfural, respectively. The separation is extremely difficult with a distillation column, as the boiling points are extremely similar. The entrainer acts to help separate the boiling points to make the separation easier, but larger amounts of the entrainers are needed, the distillation columns have many stages, and it still does not provide a pure 2-butene stream. Per Robert Glied, the team mentor, we were advised to size our reactors as heat exchangers. The reactor should have been sized using reactor sizing equations, but the reaction rate is needed for that calculation. The references found on the reaction rates for the reactions were not well developed enough and were for pilot-plant scale. Even though our conditions were not exactly the same, we sized the reactors, assuming conversions and selectivities based on the references found. Knowing

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exact reaction rates would have helped us accurately size the reactors and would make our process design more accurate. If we had more time, we would have spent more time into research to find any reaction rates that are published in literature and not patented. A significant limitation of our process is the amount and type of catalyst that is needed for the initial n-butene hydration to SBA. The reactor is a large volume, and the cost of the catalyst is extremely high. From Dow Chemical, we found that reaction life of the catalyst is approximately 5 years. Thus, in the 10 year operating period of the plant, we would have to change out our catalysts completely twice. This was taken into account in the equipment costing of the economics section under the reactor costing (it was included in the capital cost of the reactor based on the knowledge we obtained from literature). However, we chose to buy two complete sets of catalyst right as the plant started so that when one set of catalyst needed to be recharged with strong acid ions, the other could be put into the reactor in order to keep the process running smoothly. This can be referenced in Appendix E. This increased each batches catalyst life because it was only used half of the 10 year operating time, which is the 5 year life of the catalyst. The extremely high cost of the catalyst caused our equipment costs to be through the roof, which is why our TCI is so high and our process isn’t profitable. Our revenue outweighs the operating costs, but we are so far in the hole initially from the costs it takes to build the plant that we can’t possible make up the profit in the operating life of the plant. If we were able to use a different, cheaper type of catalyst, this would make the process more feasible. If we had more time to do research for this process, we would look into creating our own catalyst which is described in the alternatives section. 7.2 Uncertainties

Many uncertainties in our process exist that may have resulted in different results. A significant uncertainty is the reaction scheme of 1-butene in the hydration reaction. 1-butene can react to 1-butanol and 2-butanol, but literature was not found stating the selectivity of the reactions. This reaction could have changed the amount of MEK produced. Another uncertainty is the feed composition. The feed is assumed to originate from petroleum cracking, which was then refined in the LDPE production, but different references shows different ranges for components that come from petroleum cracking and it was assumed that LDPE only separated 1-butene and isobutene from the raffinate and none of the other components are removed. In additional components such as 1,3-butadiene were not consider because the composition occurs in small amounts in the raffinate. If the feed was different, the process would be completely different. There was another uncertainty in the assumption that the butanes, n-butane and isobutane, does not react in the hydration reaction. An assumption was made that no reaction occurs with the butanes because of its chemical stability at the temperature and pressure of the hydration reaction, but no literature reassuring the assumption exists. If reactions occurred, then the products would have to be dealt with. 7.3 Alternatives

A number of alternative decisions exist which could have been made in the process which are detailed here. The most notable alternative to our process involves the amount of water fed into the system. In the process proposed in Section 4, there is an input of 2673 lb/hr which is 1.5 times the molar equivalent of 2-butene entering the hydration reactor in Stage 1. However, the water necessary to account for the high flow recycle stream was not taken into account. Since this error occurs in the first stage of the process, it was propagated throughout the design and caused decisions to be made that would have differed if excess water was taken into account. The largest effect would have occurred in Stage 4, the second SBA purification process. The reason for the specific distillation set shown in Section 4.5 is to overcome an azeotrope which occurs at the given water mole percentage. Had excess water been used, the water

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component would have been past the azeotropic point and a simple distillation set up could have been implemented. Another alternative concerns the hydration reaction, Stage 1. In the reactors of this stage is a high quality resin catalyst that costs almost $10 million for the required amount for the reactor to function. The alternative to this design is to instead use a plug flow reactor with a liquid sulfuric acid catalyst combining with the n-butene feed. However, the mixing of the feed with a liquid catalyst necessitates the design of a subsequent stripping tower to remove the sulfuric acid for recycle. The preliminary reasoning for not taking this approach was due to the overestimation of the stripping tower cost, the underestimation of the resin catalyst cost, and appeal of the high conversion per pass achieved by the resin catalyst for a process which inherently yields a very low conversion of 2-butene to SBA. An alternative to the overall order of the stages exists that are presented in the proposed process. A more efficient order would be to have the butane/butene separation occur prior to the hydration reaction, Stage 3 before Stage 1. The effect of this change in order would purify the feed to exclusively 2-butene such that less impurities would by formed. The impurity to note that would be most largely affected by this is TBA. When isobutene reacts with water TBA is formed and is very difficult to remove at any point in the process. As shown in Stage 6, the purified MEK stream contains 0.3 wt% TBA as impurity which is avoidable by removing isobutene before the hydration reaction. This alternative was not considered because the research necessary to design the butane/butene separation was not found until the process was well on its way to completion with little time before the lock-in date for the PFD by upper management. An alternative approach to assessing the n-butene feed is to assume a pure 2-butene composition. This assumption was initially proposed during the research phase of designing the process but was quickly denied after conducting basic research. It is found that while LDPE production processes do remove 2-butene from the desired 1-butene and isobutene, 2-butene is notoriously difficult to separate from the butane and isobutane components of the cracking feed. It is futile and wasteful for LDPE production facilities to separate two components defined as impurities when they can be removed together. Therefore, it is implausible to assume that the feed to MichiSite is pure 2-butene. When calculating the plant running time we assumed that the plant would only be producing a product when there were operators and engineers in the plant observing and overseeing the process. MichSite specified 1922 man hours available per year per shift and there were 4 shifts possible, so we multiplied the two values together to get 7688 hours per year as our on time for the plant. This is what allowed us to calculate our hourly inflow of waste feed from MichiPetrol, and essentially was the base flow rate for all of the modeling in our process. We realized too late that the 93% on time specified by MichiSite was the value that we were supposed to use when calculating this flow rate, thus this is why our flow rates are off from what would be expected. This does not, however, change our reasoning for the process design or the components used just the sizing and costing of the equipment, pumps, and piping which would alter our economic analysis by increasing the TCI which would cause this process to be even less profitable than it already is. Thus, this is why we left the flow rate the way it was, because it would require us to remodel and price everything over again and because it wouldn’t change the outcome of our process in terms of economics. If we had more time to continue research into this process, we would remodel our process with the changed flow rates in order to obtain a more accurate economic analysis. One alternative that we could have researched more significantly if time permitted was developing our own strong acid catalyst for the n-butene hydration to SBA. The catalyst that we obtained from Dow Chemical was extremely expensive and when included in the capital cost of the equipment it drove our TCI up drastically due to the procedure that we used to calculate our capital costs which can be referenced in Appendix E and in Section 5 of this report. Developing our own catalyst would have allowed us to bypass the patented catalyst from Dow that was so expensive and decreased our costs, possibly making

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this process profitable. We were not able to find much literature on how to make these catalysts on the industrial scale, only in lab scale experiments. Thus, we did not pursue this further because of the amount of time it would have taken in order to scale this up to the amount of catalyst that we need in our process. 8.0 CONCLUSIONS AND RECOMMENDATIONS MichiPetro, a division of MichiChem, has 20,000 short tons per year of n-butene waste stream available. This feed has a significant amount of 2-butene, which is the main precursor for the development of MEK, an important industrial solvent. We have been tasked to advise MichiChem by assessing the economic profitability of the plant design to produce MEK against selling the hydrocarbon feedstock on the open market. The basis for all decisions made in terms of the technical process design was based on two highly quantifiable factors: efficiency and cost. In terms of the decisions we made, we chose to look first at the efficiency and then at the cost. In terms of efficiency, the quantifiable aspects we observed are conversions percentages, selectivity percentages, purity of separations, and flow outputs. Our novel process is broken up into 7 stages that effectively produce MEK at ASTM standards for shipment and sales. The process is broken up into a two-step reaction scheme. The n-butene in the feed is hydrated in a reactor with water to produce 2-butanol as the desired product in the first stage. Then the 2-butanol or sec-butyl alcohol (SBA) is purified via distillation in the second and fourth stage. The purified SBA is sent to the second reaction where hydrogen is removed via a brass catalyst from the SBA to produce MEK in the fourth stage. The crude MEK product is then purified to ASTM standards in the sixth stage via separating using distillation columns. The ASTM standards state that the MEK purity must be at least 99.5 wt%, with a maximum of 0.05 wt% water and 0.5 wt% of total alcohols. The third stage takes the unreacted 2-butene from the first reaction in stage 1 and purifies the desired butenes to be recycled to the hydration reaction, while the final stage condenses the waste from the process to be sent off for disposal. Our major assumption was the composition of the waste feed from the LDPE productions, which we assumed to be a hydrocarbon raffinate feed from the catalytic cracking of crude oil that was stripped of 1-butene, isobutene, and isobutene. Findings from our Environmental, Health, and Safety analysis show that the greatest hazard is the explosive nature of many of the materials involved in our process. Namely, they are hydrogen, MEK, LPG, SBA, SBE, TBA, and furfural. The next greatest hazard is the various ecological effects to the environment and toxicological effects in the workplace of the materials. The equipment involved in our process design is built to contain these hazardous materials at all times under industry-established stable conditions, with one instance of controlled and safe venting of a hydrogen-MEK vapor mixture. Health and safety of plant personnel and the surrounding community are considered paramount and require OSHA regulated preventative, incident response, and disposal measures as describe in section 6.0 of this report. Our economic analysis set us at a break-even point of 26.4 years with an NPV of -$43.44 MM at 12 years after start up. An NPV after a certain year after start up is defined as the amount of money earned above the investments and the earnings on those investments at a defined interest rate. In this way, this means that after the operating life of the plant has expired we still have not made a profit above the investor’s capital investment despite taking into account the time value of money. The break-even point tells us that it will take almost two operating lives of the plant in order to make back the total capital investment given to us to start back the plant, which is not a possible option given that the typical operating period for a given design is around 10 years. From looking at the alternative option of selling the waste feed on the open market, we found that this generates revenue of $2.94 MM per year. We believe that the operating

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costs and the capital cost to create a storage and shipment facility for the waste feed would be much cheaper than the revenue generated from selling it on the open market, which would create a profit for MichiChem. In summary, ChE Team 17 recommends that the n-butene waste stream be sold on the open market rather than designing a plant to produce MEK under the conditions proposed. It should be noted that after making the changes outlined in Section 7.3 Alternatives, we estimate that costs will be lowered enough to profit from the production of MEK. Further research into these changes should be conducted and pilot-scale experiments should be performed to evaluate the changes proposed in order to obtain more information about this process design.

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9.0 WORKS CITED

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4. Obenaus, Fritz, Wilhelm Droste, and Joachim Neumeister. "Butenes." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

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7. LIU, Zhenhua, et al. "Development and Commercial Application of Methyl-Ethyl-Ketone Production Technology." Chinese Journal of Chemical Engineering 14.5 (2006): 676-84. Web.

8. Petrus, L., et al. "Kinetics and Equilibria of the Hydration of Linear Butenes Over a Strong Acid Ion-Exchange Resin as Catalyst." Chemical Engineering Science 41.2 (1986): 217-26. Web.

9. Gerster, J. A., T. S. Mertes, and A. P. Colburn. "Ternary Systems n-Butane-1-Butene-Furfural and Isobutane-1-Butene-Furfural: Vapor-Liquid Equilibrium Data." Industrial and Engineering Chemistry 39.6 (1947): 792. Web.

10. Julka, Vivek, Madhura Chiplunkar, and Lionel O'Young. "Selecting Entrainers for Azeotropic Distillation." AIChE Journal (2009) Web.

11. Gil, Ivan D., et al. "Extractive Distillation of Acetone/Methanol Mixture using Water as Entrainer." American Chemical Society (ACS) 48.10 (2009) Web.

12. Buell, C. K., and R. G. Boatright. "Furfural Extractive Distillation for Separation and Purification of C4 Hydrocarbons." Industrial and Engineering Chemistry 39.6 (1947): 695. Web.

13. Luyben, William L. Control of the Heterogeneous Azeotropic n-Butanol/Water Distillation System. American Chemical Society. Web.

14. Pavlov, O. S., S. A. Karsakov, and S. Yu Pavlov. "Development of Processes for C4 Hydrocarbons Separation and 1,3-Butadiene Purification." Theoretical Foundations of Chemical Engineering 45.6 (2011): 858. Web.

15. Peters, Max S., Klaus D. Timmerhaus, and Ronald West. Plant Design and Economics for Chemical Engineers. 5th ed. New York, NY: McGraw Hill, 2003. Print.

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17. "Platts Solvents Assessments." Solventswire 34.27 (2011) Web.

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18. Win, David Tin. Furfural - Gold from Garbage. Assumption University; Bangkok, Thailand, 2005. Web.

19. US Environmental Protection Agency (EPA): Office of Air Quality Planning and Standards. "Locating and Estimating Air Emissions from Sources of Methyl Ethyl Ketone." (1994) Web.

20. Hydrogen. 4th ed. Material Safety Data Sheet (MSDS) #1009; Air Products, 1994. Web.

21. Safety and Security Analysis: Investigate Report by NASA on Proposed EPA Hydrogen-Powered Vehicle Fueling Station. Assessment and Standards Division;Office of Transportation and Air Quality; Environmental Protection Agency (EPA), 2004. Web. 3/25/2012.

22. "List of Hazardous Air Pollutants, Petition Process, Lesser Quantity Designations, Source Category List." Federal Register 70.242 (2005): 75047. Web.

23. Methyl Ethyl Ketone. Material Safety Data Sheet (MSDS) No. CM09000; Fisher Scientific, 2009. Web.

24. U.S. Department of Health and Human Services, Public Health Service: Agency for Toxic Substances and Disease Registry (ATSDR). "Toxicological Profile for 2-Butanone." (1992) Web.

25. "Hazardous Waste Operations and Emergency Response." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=standards&p_id=9765>.

26. 1-Butene. Material Safety Data Sheet (MSDS) No. 106-98-9: MESA, 1999. Web. Jan. 11, 2012.

27. Cis-2-Butene. Material Safety Data Sheet (MSDS), C2B: MESA, 2004. Web. 3/25/2012.

28. Isobutane. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

29. Isobutylene. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

30. N-Butane. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

31. Trans-2-Butene. Materials Safety Data Sheet (MSDS); Praxair Web.

32. "Environmental Health Criteria 65 - Butanols: Four Isomers." InChem (1987) Web.

33. Sec-Butyl Ether. Material Safety Data Sheet (MSDS); Sigma-Aldrich, 2011. Web. 34. "Occupational Safety and Health Guideline for Tert-Butyl Alcohol." United States Department of

Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/tertbutylalcohol/recognition.html>.

35. Water. Material Safety Data Sheet (MSDS) No. W0600; Sciencelab.com, Inc., 2005. Web.

36. Furfural. 3.3rd ed. Material Safety Data Sheet (MSDS); Sigma-Aldrich, 2012. Web. 3/25/2012.

37. "Occupational Safety and Health Guideline for Furfural." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/furfural/recognition.html>.

38. Nitrogen (Compressed). 5th ed. 1011 Vol. Material Safety Data Sheet (MSDS); Air Products, 1997. Web.




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39. "Occupational Safety and Health Guideline for Nitrogen." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/nitrogen/recognition.html>.

40. Haussinger, Peter, Reiner Lohmüller, and Allan M. Watson. "Hydrogen, 1. Properties and Occurence." Ullmann's Encyclopedia of Industrial Chemistry. 18 Vol. Wiley-VCH Verlag GmbH & Co. KGaA, 2000. 235. Web.

41. Häussinger, Peter, Reiner Lohmüller, and Allan M. Watson. "Hydrogen, 5. Handling." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

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43. Thompson, Stephen M., Gary Robertson, and Eric Johnson. "Liquefied Petroleum Gas." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

44. "Storage and Handling of Liquefied Petroleum Gases." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=9756>.

45. Sec-Butyl Alcohol (SBA). Material Safety Data Sheet (MSDS) No. B6302; Sciencelab.com, Inc., 2005. Web.

46. Sakuth, Michael, et al. "Ethers, Aliphatic." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

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48. National Aeronautics and Space Administration. Safety Standard for Hydrogen and Hydrogen Systems: Guidelines for Hydrogen System Design, Materials Selection, Operations, Storage, and Transportation. Washington, DC: Office of Safety and Mission Assurance, 1997. Web.

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10.0 WORKS CONSULTED 1-Butene. Material Safety Data Sheet (MSDS) No. 106-98-9: MESA, 1999. Web. Jan. 11, 2012.

AmberlystTM 70 High Temperature Strongly Acidic Catalyst. Rohm and Haas, 2005. Print.

Barkel, PE B. M. ChE 487 Cost Manual., 2000. Print.

Buell, C. K., and R. G. Boatright. "Furfural Extractive Distillation for Separation and Purification of C4 Hydrocarbons." Industrial and Engineering Chemistry 39.6 (1947): 695. Print.

Calamur, Narasimhan, Martin E. Carrera, and Richard A. Wilsak. "Butylenes." Kirk-Othmer Encyclopedia of Chemical Technology.John Wiley & Sons, Inc., 2000. Web.

Cis-2-Butene. Material Safety Data Sheet (MSDS), C2B: MESA, 2004. Web. 3/25/2012.

"Compliance Guidelines." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_id=9768&p_table=STANDARDS>.

Cursaru, Diana, and Ulrich Kunz. "Kinetic Investigation on Direct Hydration of n-Butene in a Multiphase Reactor." Revista De Chimie (Bucharest) 61.12 (2009): 1245-53. Print.

Data Sheet: Methyl Ethyl Ketone. Shell Chemicals, 2005. Print.

Dixon, G. Anthony. "Correlations for Wall and Particle Shape Effects on Fixed Bed Bulk Voidage." Canadian Journal of Chemical Engineering 66 (1988): 706. Print.

"Environmental Health Criteria 65 - Butanols: Four Isomers." InChem (1987)Print.

Falbe, Jürgen, et al. "Alcohols, Aliphatic." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

Ford, F. E., and D. D. Perlmutter. "The Kinetics of the Brass-Catalysed Dehydrogenation of Sec-Butyl Alcohol." Chemical Engineering Science 19.6 (1964): 371-8. Print.

Fruehauf, Paul S., and Donald P. Mahoney. "Distillation Column Control Design using Steady State Models: Usefulness and Limitations." ISA transactions 32.2 (1993): 157-75. Print.

Furfural. 3.3rd ed. Material Safety Data Sheet (MSDS); Sigma-Aldrich, 2012. Web. 3/25/2012.

Pavlov, O. S., S. A. Karsakov, and S. Yu Pavlov. "Development of Processes for C4 Hydrocarbons Separation and 1,3-Butadiene Purification." Theoretical Foundations of Chemical Engineering 45.6 (2011): 858. Web.

Gerster, J. A., T. S. Mertes, and A. P. Colburn. "Ternary Systems n-Butane-1-Butene-Furfural and Isobutane-1-Butene-Furfural: Vapor-Liquid Equilibrium Data." Industrial and Engineering Chemistry 39.6 (1947): 792. Print.

Gil, Ivan D., et al. "Extractive Distillation of Acetone/Methanol Mixture using Water as Entrainer." American Chemical Society (ACS) 48.10 (2009)Print.

"Global Outlook for Feedstocks (C4s) & Elastomers." CMAI Global.615 (2008)Print.

http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_id=9768&p_table=STANDARDS

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Hahn, Heinz-Dieter, et al. "Butanols." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web. Jan. 11, 2012.

Haussinger, Peter, Reiner Lohmüller, and Allan M. Watson. "Hydrogen, 1. Properties and Occurence." Ullmann's Encyclopedia of Industrial Chemistry. 18 Vol. Wiley-VCH Verlag GmbH & Co. KGaA, 2000. 235. Print.

Häussinger, Peter, Reiner Lohmüller, and Allan M. Watson. "Hydrogen, 5. Handling." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

---. "Hydrogen, 6. Uses." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Print.

"Hazardous Waste Operations and Emergency Response." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=standards&p_id=9765>.

Hoell, Detlef, et al. "2-Butanone." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web. Jan. 11, 2012.

Hydrogen. 4th ed. Material Safety Data Sheet (MSDS) #1009; Air Products, 1994. Web.

"Hydrogen." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=9749>.

Isobutane. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

Isobutylene. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

Julka, Vivek, Madhura Chiplunkar, and Lionel O'Young. "Selecting Entrainers for Azeotropic Distillation." AIChE Journal (2009)Print.

Keuler, J. N., L. Lorenzen, and S. Miachon. "The Dehydrogenation of 2-Butanol Over Copper-Based Catalysts: Optimising Catalyst Composition and Determining Kinetic Parameters." Applied Catalysis A: General 218.1–2 (2001): 171-80. Print.

Kovach, J. W., and W. D. Seider. "Heterogeneous Azeotropic Distillation: Experimental and Simulation Results." AIChE Journal 33.8 (1987): 1300-14. Print.

"List of Hazardous Air Pollutants, Petition Process, Lesser Quantity Designations, Source Category List." Federal Register 70.242 (2005): 75047. Print.

LIU, Zhenhua, et al. "Development and Commercial Application of Methyl-Ethyl-Ketone Production Technology." Chinese Journal of Chemical Engineering 14.5 (2006): 676-84. Print.

Loh, H. P., and Jennifer Lyons. Process Equipment Cost Estimation., 2002. Print.

Luyben, William L. Control of the Heterogeneous Azeotropic n-Butanol/Water Distillation System. American Chemical SocietyPrint.

Marek, L. F., and R. K. Flege. "Catalytic Vapor-Phase Hydration of 2-Butene Under High Pressures." Industrial and Engineering Chemistry 24.12 (1932): 1429. Print.



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Mertes, T. S., and A. P. Colburn. "Binary Mixtures of n-Butane, Isobutane, and 1-Butene with Furfural: Vapor-Liquid Equilibria and Thermodynamic Properties." Industrial and Engineering Chemistry 39.6 (1947): 787. Print.

Methyl Ethyl Ketone. Material Safety Data Sheet (MSDS) No. CM09000; Fisher Scientific, 2009. Print.

Ministry of Science and Technology (India): Department of Scientific and Industrial Research. "Executive Summary - Methyl Ethyl Alcohol." (1995)Print.

N-Butane. Material Safety Data Sheet (MSDS); MESA, 1999. Web. 3/25/2012.

Nitrogen (Compressed). 5th ed. 1011 Vol. Material Safety Data Sheet (MSDS); Air Products, 1997. Print.

Obenaus, Fritz, Wilhelm Droste, and Joachim Neumeister. "Butenes." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

"Occupational Safety and Health Guideline for Furfural." Unidted States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/furfural/recognition.html>.

"Occupational Safety and Health Guideline for Nitrogen." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/nitrogen/recognition.html>.

"Occupational Safety and Health Guideline for Tert-Butyl Alcohol." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/SLTC/healthguidelines/tertbutylalcohol/recognition.html>.

Peters, Max S., Klaus D. Timmerhaus, and Ronald West. Plant Design and Economics for Chemical Engineers. 5th ed. New York, NY: McGraw Hill, 2003. Print.

Petre, Diana Luciana. "Kinetic Investigations on Direct Hydration of n-Butene in a Multiphase Reactor." Ph.D Technical University of Clausthal, 2006. Print.

Petre, Diana-Luciana. "Kinetic Investigations on Direct Hydration of n-Butene in a Multiphase Reactor." Grades eines Doktor-Ingenieurs Fakultät für Mathematik/Informatik und Maschinenbau der Technischen Universität Clausthal, 2006. Print.

Petrus, L., et al. "Kinetics and Equilibria of the Hydration of Linear Butenes Over a Strong Acid Ion-Exchange Resin as Catalyst." Chemical Engineering Science 41.2 (1986): 217-26. Print.

"Platts Solvents Assessments." Solventswire 34.27 (2011)Print.

Safety and Security Analysis: Investigate Report by NASA on Proposed EPA Hydrogen-Powered Vehicle Fueling Station. Assessment and Standards Division;Office of Transportation and Air Quality; Environmental Protection Agency (EPA), 2004. Web. 3/25/2012.

Sakuth, Michael, et al. "Ethers, Aliphatic." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Web.

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Sec-Butyl Ether. Material Safety Data Sheet (MSDS) ; Sigma-Aldrich, 2011. Print.




80

Short-Term Energy Outlook Market Prices and Uncertainty Report. March 2012 ed. U.S. Energy Information Administration, 2012. Print.

"Storage and Handling of Liquefied Petroleum Gases." United States Department of Labor.Web. 3/25/2012 <http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=9756>.

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Tert-Butyl Alcohol, TBA. 2nd ed. Material Safety Data Sheet (MSDS) #164; Pharmco Products Inc, 2001. Web. 3/25/2012.

Thompson, Stephen M., Gary Robertson, and Eric Johnson. "Liquefied Petroleum Gas." Ullmann's Encyclopedia of Industrial Chemistry.Wiley-VCH Verlag GmbH & Co. KGaA, 2000. Print.

Trans-2-Butene. Materials Safety Data Sheet (MSDS) ; PraxairPrint.

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---. "Toxicological Profile for 2-Butanone." (1992)Print.

US Environmental Protection Agency (EPA): Office of Air Quality Planning and Standards. "Locating and Estimating Air Emissions from Sources of Methyl Ethyl Ketone." (1994)Print.

Water . Material Safety Data Sheet (MSDS) No. W0600; Sciencelab.com, Inc., 2005. Print.

Weissermel, Klaus, and Hans-Jürgen Arpe. "Olefins." Industrial Organic Chemistry.Wiley-VCH Verlag GmbH, 1997; 2007. 59-89. Print.

Welty, James, et al. Fundamentals of Momentum, Heat and Mass Transfer. 5th ed. Wiley, 2007. Print.

Widagdo, Soemantri, Warren D. Seider, and Donald H. Sebastian. "Bifurcation Analysis in Heterogeneous Azeotropic Distillation." AIChE Journal 35.9 (1989): 1457. Print.

---. "Dynamic Analysis of Heterogenous Azeotropic Distillation." AIChE Journal 38.8 (1992): 1229. Print.

Willis, Dr M. J. Selecting a Distillation Column Control Strategy (A Basic Guide). University of Newcastle:, 2000. Web. 3/25/2012.

Win, David Tin. Furfural - Gold from Garbage. Assumption University; Bangkok, Thailand, 2005. Print.


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