GE / Texaco Gasifier Feed to a Lurgi Methanol Plant and its Effect on Methanol Production

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GE / Texaco Gasifier Feed to a Lurgi Methanol Plant and its Effect on Methanol Production

CONTENTS
0 Methanol Synthesis Introduction
1 Executive Summary
2 Design Basis
2.1.1 Train I Design Basis
2.1.2 Train II Design Basis
2.1.3 Train III Design Basis
2.2 Design Philosophy
2.2.1 Operability Review
2.3 Assumptions
2.4 Train IV Flowsheet
2.4.1 CO2 Removal
3 Discussion
3.1 Natural Gas Consumption Figures
3.1.1 Base Case
3.1.2 Case 1 – Coal Gasification in Service
3.1.3 Case 2 – Coal Gasification in Service – No CO2 Export
3.2 Methanol Production Figures
3.2.1 Base Case
3.2.2 Case 1 – Coal Gasification in Service
3.2.3 Case 2 – Coal Gasification in Service – No CO2 Export
3.3 85% Natural Gas Availability
3.4 100% Natural Gas Availability
3.5 CO2 Emissions
3.5.1 Base Case
3.5.2 Case 1 – Coal Gasification in Service
3.5.3 Case 2 – Coal Gasification in Service – No CO2 Export
3.6 Specific Consumption Figures
3.6.1 Base Case
3.6.2 Case 1 – Coal Gasification and CO2 Import
3.6.3 Case 2 – Coal Gasification and No CO2 Import
3.7 Train IV Synthesis Gas Composition
4 Further Work
5 Conclusion

APPENDIX
Important Stream Data – Material Balance Stream Data
Texaco Gasifier with HP Steam Raising Boiler
CHARACTERISTICS OF COAL
Material Balance Considerations

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GE / Texaco Gasifier Feed to a Lurgi Methanol Plant and its Effect on Methanol Production

  1. 1. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com GBH Enterprises, Ltd. GE /Texaco Gasifier Feed to a Lurgi Methanol Plant and its Effect on Methanol Production Case Study: #06812416GB/H Process Information Disclaimer Information contained in this publication or as otherwise supplied to Users is believed to be accurate and correct at time of going to press, and is given in good faith, but it is for the User to satisfy itself of the suitability of the Product for its own particular purpose. GBHE gives no warranty as to the fitness of the Product for any particular purpose and any implied warranty or condition (statutory or otherwise) is excluded except to the extent that exclusion is prevented by law. GBHE accepts no liability for loss, damage or personnel injury caused or resulting from reliance on this information. Freedom under Patent, Copyright and Designs cannot be assumed.
  2. 2. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com CONTENTS 0 Methanol Synthesis Introduction: 1 Executive Summary 2 Design Basis 2.1.1 Train I Design Basis 2.1.2 Train II Design Basis 2.1.3 Train III Design Basis 2.2 Design Philosophy 2.2.1 Operability Review 2.3 Assumptions 2.4 Train IV Flowsheet 2.4.1 CO2 Removal 3 Discussion 3.1 Natural Gas Consumption Figures 3.1.1 Base Case 3.1.2 Case 1 – Coal Gasification in Service 3.1.3 Case 2 – Coal Gasification in Service – No CO2 Export 3.2 Methanol Production Figures 3.2.1 Base Case 3.2.2 Case 1 – Coal Gasification in Service 3.2.3 Case 2 – Coal Gasification in Service – No CO2 Export 3.3 85% Natural Gas Availability 3.4 100% Natural Gas Availability
  3. 3. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 3.5 CO2 Emissions 3.5.1 Base Case 3.5.2 Case 1 – Coal Gasification in Service 3.5.3 Case 2 – Coal Gasification in Service – No CO2 Export 3.6 Specific Consumption Figures 3.6.1 Base Case 3.6.2 Case 1 – Coal Gasification and CO2 Import 3.6.3 Case 2 – Coal Gasification and No CO2 Import 3.7 Train IV Synthesis Gas Composition 4 Further Work 5 Conclusion APPENDIX Important Stream Data – Material Balance Stream Data Texaco Gasifier with HP Steam Raising Boiler CHARACTERISTICS OF COAL Material Balance Considerations
  4. 4. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com Methanol Synthesis Introduction: The synthesis gas is fed to the methanol synthesis converter at about 130° C. The converter is of different design (typically in cascades) depending on the particular technology applied. The compressed gas is preheated to reaction temperatures inside the tubes as it flows through the hot catalyst bed. The hot reacted gas leaves the converter and provides heat to the saturator water circuit and the loop interchanger before finally being cooled. Crude methanol is separated from the uncondensed gases and the gases are recirculated back to the converter via the circulator. Figure 1: Conventional Synthesis Loop:
  5. 5. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 1. Executive Summary An operator is reviewing options for the utilization of synthesis gas derived from coal gasification in order to maintain methanol production during periods of low natural gas availability. The operator has requested that GBH Enterprises review the options for integration of such a feed gas to the existing production facilities on their site and conduct a conceptual engineering study to identify the optimal flowsheet configuration and determine if there are any specific plant limitations. The key conclusions from this study are that, • Operation utilizing a coal gasifier is possible. • Production rate will be lowered from the present maximum achievable rate due to the replacement of the purge gas exported to train IV with natural gas as reformer fuel. • Addition of a coal gasifier and the effect on the fuel balance on trains I through III will increase CO2 emissions. • Under circumstances where train IV is operated on the gasified coal feed and 100% of normal natural gas is available, site production will be increased to 11,331 mtpd, an increase of 7% over present maximum site production. • If between 91-92% of normal natural gas flowrate is available, then site production with the coal gasified feed to train IV will be the same as the base case considered as part of this study. • An operability review has been conducted to determine the effect of losing one or more of trains I through III and the effect that this will have on train IV.
  6. 6. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 2. Design Basis The client have supplied to GBH Enterprises, the following syn gas analysis for the gasified coal feed, Parameter Flowrate Composition Units kmol/hr mol % CO 2,028.4 25.9 H2O 2,124.9 27.1 CO2 1,553.6 19.8 H2 2,080.9 26.6 CH4 8.6 0.1 N2 26.7 0.3 Ar 4.8 0.1 Parameter Units Value Vapor Fraction n/a 1.0 Temperature °C 30 Pressure Bar 32.81 Feed Rate kgmol/hr 7,828 Feed Rate kg/hr 119,965 H2/CO Ratio n/a 1.026 R Ratio n/a 0.147 Plant data for trains I through III has been taken from historical plant audits; the plant was operating at a refined methanol production figure of 2,322 mtpd. The data from the previous audit was at a refined production rate of 2,747 mtpd which is more representative of maximum rate operation. All catalyst lives, and hence activities and pressure drops factors have been based on these audits.
  7. 7. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 2.1.1 Train I Design Basis The following has been used as the design basis for Train I based on the available data from historical audits. Natural Gas Feed Rate 3,868 kmol/hr CO2 0.18 mol % CH4 93.29 C2H6 5.12 C3H8 0.23 C4H10 0.06 N2 1.12 Hydrogen Recycle Flow Rate 57.5 kmol/hr Steam Flow Rate to Reformer 240 mt/hr Steam to Carbon Ratio 3.29 Reformer Inlet Temperature 595 °C Methane Slip Ex Reformer 3.22 mol % dry Reformer Exit Pressure 20.64 Bara Natural Gas Fuel Rate 429 kmol/hr Heat loss 2 % Note that the heat loss from the reformer is defined as the percentage of the total heat released in the reformer to ambient. As such it will have an effect on the amount of variable fuel (in this case natural gas) that will be added to the reformer. The same basis has been used for trains II and III. Syn gas rate 15,930 kmol/hr Circulation Rate 60,180 kmol/hr Crude Methanol Production 2,546 mtpd Refined Methanol Production 2,502 mtpd Purge Gas Rate 4,587 kmol/hr Loop Carbon Efficiency 93.7 % Note that the Crude Methanol Production figure stated above is the amount of methanol present in the crude methanol and no allowance for water has been included.
  8. 8. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 2.1.2 Train II Design Basis The following has been used as the design basis for Train II based on the available data from historical audits. Natural Gas Feed Rate 4,289 kmol/hr CO2 0.15 mol % CH4 93.36 C2H6 4.83 C3H8 0.14 C4H10 0.26 N2 1.26 Hydrogen Recycle Flow Rate 53.7 kmol/hr Steam Flow Rate to Reformer 242.3 mt/hr Steam to Carbon Ratio 3.00 Reformer Inlet Temperature 556 °C Methane Slip Ex Reformer 3.40 mol % dry Reformer Exit Pressure 20.34 Bara Natural Gas Fuel Rate 240 kmol/hr Heat loss 2 % Syn gas rate 17,433 kmol/hr Circulation Rate 64,730 kmol/hr Crude Methanol Production 2,793 mtpd Refined Methanol Production 2,747 mtpd Purge Gas Rate 5,158 kmol/hr Loop Carbon Efficiency 98.35 %
  9. 9. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 2.1.3 Train III Design Basis The following has been used as the design basis for Train III based on the available data from historical audits. Natural Gas Feed Rate 4,435 kmol/hr CO2 0.20 mol % CH4 93.28 C2H6 4.94 C3H8 0.34 C4H10 0.27 N2 0.97 Hydrogen Recycle Flow Rate 48.3 kmol/hr Steam Flow Rate to Reformer 263.4 mt/hr Steam to Carbon Ratio 3.13 Reformer Inlet Temperature 547 °C Methane Slip Ex Reformer 3.49 mol % dry Reformer Exit Pressure 20.6 Bara Natural Gas Fuel Rate 335 kmol/hr Heat loss 2 % Syn gas rate 18,158 kmol/hr Circulation Rate 74,410 kmol/hr Crude Methanol Production 2,981 mtpd Refined Methanol Production 2,930 mtpd Purge Gas Rate 4,946 kmol/hr Loop Carbon Efficiency 96.03 %
  10. 10. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 2.2 Design Philosophy The philosophy that has been developed for this study is that the synthesis gas generated from the coal gasification unit will be treated to remove any impurities that would have a detrimental effect on the downstream methanol synthesis catalysts. CO2 would be removed and purge gas (from trains I through III) added such that the stoichiometric ratio of the combined synthesis gas is suitable for the production of methanol. For the purpose of this study, it has been assumed that a combined synthesis gas stoichiometric ratio (R ratio) of around 1.95 will be suitable. Any excess CO2 will be compressed to around 80-85 bara prior to injection into trains II and III. The option of injection into train I has been rejected as the CO2 will have to be compressed to over 100 bar, increasing both the CAPEX and OPEX of the project. However, this option requires further consideration in order to maintain production when either train II or III is shut down. 2.2.1 Operability Review It has been assumed that the low gas availability operation of the operator’s site will include trains I through III operating with all available natural gas whilst train IV operates on the synthesis gas generated from the gasification of the coal mixed with purge gas from the other three trains. Analysis has been conducted assuming that one of the other plants is off line, for instance as part of the turnaround schedule or is tripped. If train I is offline, then there will be a shortage of hydrogen in the purge gas being exported to train IV. Under this scenario, the coal gasifier will have to be turned down such that the combined syn gas being feed to the loop is stoichiometric. It is estimated that train IV can be operated at around 80% of normal rates (1,815 mtpd) with CO2 being exported at a reduced rate. A similar effect is seen if either train II or III is offline. Under such circumstances, a review of whether CO2 should be exported to trains II and III need to be conducted in order to determine whether it is better to temporary halt this export and thereby increase the amount of purge gas available and maintain train IV gasified rate at its maximum value. If train II or III is offline, then there will be a reduction in the amount of hydrogen available for train IV syn gas stoichiometry correction. Furthermore, half the train IV export CO2 will have to be vented as it no longer can be imported to trains II or III (depending on which plant is off line).
  11. 11. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com If two trains out of trains I, II or III are offline, then the amount of purge gas available to be sent to train IV will clearly be reduced. Under this scenario, train IV rates would have to be dropped to around 80% of maximum whilst around 428 kmol/hr of CO2 is removed and vented to provide a stoichiometric syn gas. 2.3 Assumptions The following assumptions have been made as part of this study, • Trains I through III are capable of operation with a synthesis gas with an R ratio (stoichiometric ratio) as low as 2. This will be achieved by the addition of any excess CO2 that has to be removed from the gasified synthesis gas being feed to train IV. • It is assumed that the coal gasification unit will be self sufficient in terms of steam generation and consumption. • It is assumed that sufficient steam of the appropriate pressure and superheat temperature will be available for the operation of the train IV synthesis loop circulator. • The effect of the addition of the CO2 to either train II and III on the performance of the circulator has not been evaluated as part of this study. Clearly as CO2 is added, the molecular weight of the circulating gas will increase and therefore, assuming that the circulators are operated at maximum circulation rate or shaft power, there will be a loss of circulation rate. This will reduce the loop carbon efficiency and the methanol production from the syn loops. • The loop carbon efficiency of train IV has been assumed to be 95%. It is assumed that the loop carbon efficiency will not change when operation on the gasifier synthesis gas. • The natural gas fuel utilized on train IV has not been considered as part of this study as insufficient details of the fuel utilization and the flowsheet are available to GBH Enterprises. It is assumed that any natural gas that is utilized on train IV during normal operation as fuel will continue to be used as fuel with the coal gasification unit in service.
  12. 12. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com • No account of the purge gas from train IV syn loop has been made. It is assumed that the flow is small due to the stoichiometric nature of the syn gas generated by the front end of train IV. Furthermore, it is assumed that any purge gas will be used as fuel gas on train IV front end under either the normal operating conditions or with the coal gasification unit in service. • It is assumed that under normal operating conditions (i.e.: 100% natural gas availability) that 30,000 Nm³/hr of purge gas from trains II and III is exported to train IV front end. It is assumed that this purge gas is taken from trains II and III in a 50:50 split. It is assumed that no purge gas is exported from train I to train IV during normal operation. • The hydrogen recycle (to purification) rates have not been altered from the base case flowsheets developed as part of this study even when plant rates have been altered. Optimization of these rates will provide some additional purge gas for use as fuel on the reformer but the overall effect on the fuel requirements will be small. This is deemed to be a second order effect on the flowsheets. • The efficiencies for trains I through IV have been assumed to be 98.3, 98.3, 98.3 and 98% respectively. • The natural gas feed rate to train IV has been calculated from a methanol production rate of 2,400 mtpd assuming the above distillation efficiency as well as, o Methane slip from the reformer is 0.5 mol % dry, o The loop has a carbon efficiency of 95%. 2.4 Train IV Flowsheet For the purpose of this study, the train IV flowsheet has been assumed to consist of a coal gasifier utilizing the oxygen available from the existing ASU, followed by a CO2 removal system. It has been assumed that this will be a wet CO2 removal system. The CO2 removal system will be required to remove some of the excess CO2 present in the gasified gas to enable correction of the train IV syn gas stoichiometry.
  13. 13. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com It is recommended that provision is made to allow surplus CO2 to be exported to either trains II or III; this is required under some operating scenarios and also potentially will allow for the sale of CO2. The bulk of the gasified coal feed is then mixed with purge gas from trains I through III before being passed to the train IV synthesis loop. It is assumed that downstream of the CO2 removal system, a purification unit will be installed to remove any residual impurities present in the syn gas. Consideration should be given to the elimination of any heavy metals, sulfur, chlorides and carbonyl compounds. GBH Enterprises will review the purification requirements for this duty if this project proceeds to the front end engineering phase of the project. This will ensure that the train IV synthesis catalyst is not poisoned and should achieve its required life. An outline flowsheet is presented below, GasifierCO2 RemovalGas PurificationSynthesis LoopCO2 ExportPurge Gas Import A bypass is required around the CO2 removal system such that the amount of CO2 that is removed can be controlled. It is expected that around 2,186 kmol/hr of syn gas will have to be passed to the CO2 removal system, which represents around 28% of the total gasified gas.
  14. 14. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 2.4.1 CO2 Removal The CO2 removal system will allow for removal of CO2 from part of the gasified gas and hence can be exported to trains II and III. This will potentially increase the production from these trains whilst ensuring an optimal combined syn gas for train IV synthesis loop. It has been estimated that 400 kmol/hr (422 mtpd) of CO2 will have to be shifted and that 428 kmol/hr (452 mtpd) will have to be removed in order to provide an optimised syn gas composition inlet train IV synthesis loop. It is assumed that for the cases with CO2 export, the CO2 is split evenly between trains II and III. 3 Discussion As part of this study, a number of cases have been considered as detailed above in the operability review. These cases include, • Base Case – This case represents the operation of trains I through IV on natural gas and assumes that 100% of the required natural gas is available. • Case 1 – Trains I through III operating on a natural gas feed assuming that 75% of the natural gas required for the base case is available. o All of this natural gas is fed to trains I through III. o Train IV operating on a gasified coal feed with CO2 export to trains II and III and purge gas addition from trains I through III to obtain the correct synthesis gas stoichiometry. o CO2 is exported to trains II and III. CO2 export to train I has not been considered as the train I loop runs at a higher pressure than trains II and III and therefore would require additional compression. o No attempt has been made to optimize the natural gas utilization between trains I through III and therefore there is some potential for an incremental increase in methanol production. o No attempt has been made to optimize the CO2 distribution between trains II and III and therefore there is some potential for an incremental increase in methanol production.
  15. 15. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com • Case 2 – Trains I through III operating on a natural gas feed assuming that 75% of the natural gas required for the base case is available. o All of this natural gas is fed to trains I through III. o Train IV operating on a gasified coal feed with no CO2 export to trains II and III and purge gas addition from trains I through III to obtain the correct synthesis gas stoichiometry. o No attempt has been made to optimize the natural gas utilization between trains I through III and therefore there is some potential for an incremental increase in methanol production. • Case 3 – Trains I through III operating on a natural gas feed assuming that 85% of the normal natural gas rate for the base case is available. o Train IV is operated on the gasified coal feed. o Again no attempt has been made to optimize the natural gas utilization between trains I through III. • Case 4 – Trains I through III operating on a natural gas feed assuming that 100% of the normal natural gas rate is available. o Train IV is operated on the gasified coal feed. o Again no attempt has been made to optimize the natural gas utilization between trains I through III. 3.1 Natural Gas Consumption Figures 3.1.1 Base Case The following table details the natural gas consumption figures for trains I through IV that have been developed as part of this study for the base case, Parameter NG Feed Usage NG Fuel Usage NG Total Usage Purge To Fuel Units kmol/hr kmol/hr kmol/hr kmol/hr Train I 3,868 328 4,196 4,520 Train II 4,289 405 4,694 4,397 Train III 4,435 538 4,973 4,137 Train IV 3,261 0 3,261 unknown Total 15,853 1,271 17,124 13,054
  16. 16. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com The purge to fuel figure represents the purge gas that is utilized as fuel on the reformer after deducting the purge recycle to the purification section of the plant and any purge export to train IV. As noted above in the assumptions, the natural gas used as fuel on train IV has been ignored for the purpose of this study. It is assumed that sufficient natural gas to the fuel system on train IV will be supplied in order to raise steam etc. Furthermore it is assumed that the fuel requirements for train IV (for steam generation in the duct) operating on a natural gas feed is around the same as will be required when operating on coal. No indication of the purge gas rate is available within GBH Enterprises for train IV and therefore this is reported in the above table as unknown. The NG total column represents the total expected natural gas usage on trains I through IV during periods when the plants receive 100% of their natural gas requirement. The total NG usage figure for all four trains has been calculated as 17,124 kmol/hr. Assumptions have been made around the heat losses from the train I through III reformers and that there is no gas utilization elsewhere (including package boilers and auxiliary burners in the fluegas duct). This will affect the numbers presented in this report but should not affect the overall conclusions unless the assumptions made are a long way from the real operations on the site. The amount of natural gas used as fuel on train IV may impact on the actual production and consumption figures contained in this report, but should not affect the overall conclusions.
  17. 17. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 3.1.2 Case 1 – Coal Gasification in Service This case assumes that 75% of the natural gas used as feed and fuel as calculated above is available for utilization on trains I through III whilst train IV operates with the gasified coal feed. This means that there is a total of 12,844 kmol/hr of natural gas available. The following table details the natural gas utilization for trains I through IV under this scenario, Parameter NG Feed Usage NG Fuel Usage NG Total Usage Purge Export to Train IV Purge To Fuel Units kmol/hr kmol/hr kmol/hr kmol/hr kmol/hr Train I 2,976 923 3,899 1,601 1,484 Train II 2,979 1,375 4,354 2,643 0 Train III 3,142 1,449 4,591 2,451 0 Train IV 0 0 0 unknown unknown Total 9,097 3,747 12,844 6,695 1,484 For this case natural gas has been allocated on the same percentage basis as per the base case above, but assuming that no natural gas is utilized on train IV with the exception (as noted previously) of any natural requirement for fuel. 3.1.3 Case 2 – Coal Gasification in Service – No CO2 Export This case assumes that 75% of the natural gas used as feed and fuel as calculated above is available for utilization on trains I through III whilst train IV operates with the gasified coal feed. This means that there is a total of 12,844 kmol/hr of natural gas available. The following table details the natural gas utilization for trains I through IV under this scenario, Parameter NG Feed Usage NG Fuel Usage NG Total Usage Purge Export to Train IV Purge To Fuel Units kmol/hr kmol/hr kmol/hr kmol/hr kmol/hr Train I 2,871 1,027 3,898 1,895 1,072 Train II 3,328 1,026 4,354 2,245 1,360 Train III 3,485 1,108 4,591 2,225 1,311 Train IV 0 0 0 unknown unknown Total 9,684 3,161 12,843 6,365 3,743 In this case, there is sufficient purge gas available that some can be recycled back to the reformer for use as fuel. This enables more natural gas to be used a feed and hence is used to produce methanol.
  18. 18. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 3.2 Methanol Production Figures 3.2.1 Base Case The following table details the methanol production figures for trains I through IV that have been developed as part of this study for the base case, Parameter Loop Production Refined Production Carbon Efficiency Units mtpd mtpd % Train I 2,550 2,506 93.7 Train II 2,802 2,756 93.5 Train III 3,005 2,954 96.6 Train IV 2,449 2,400 95.0 Total 10,806 10,616 n/a Note that the loop production figures stated above are for methanol as present in the crude from the synthesis loop. The refined production figures assume distillation efficiencies for trains I through IV of 98.3, 98.3, 98.3 and 98% respectively. Note that the carbon efficiency of train IV has been assumed to be 95%. 3.2.2 Case 1 – Coal Gasification in Service The following table details the natural gas utilization under the conditions required for case 1, Train I through III operating with natural gas (75% of the normal rate available) and train IV operating with the gasified coal feed. CO2 export from the CO2 removal stage is assumed and the CO2 is split evenly between trains II and III. Parameter Loop Production Refined Production Carbon Efficiency Units mtpd mtpd % Train I 2,052 2,016 98.1 Train II 2,164 2,128 96.3 Train III 2,344 2,304 98.9 Train IV 2,390 2,342 95.0 Total 8,950 8,790 n/a It should be noted that at these lower distillation throughputs, distillation efficiency should rise. No account of this effect has been taken into account as part of this study.
  19. 19. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com It should be noted that no attempt to optimize the amount of CO2 export from the front end of train IV to trains II and III has been made. As no details are available around the design of the train IV syn loop, such an optimization study will have some fundamental assumptions which may or may not be valid. Directionally, since the syn loop carbon efficiency of train IV is lower than for trains II and III, it would be expected that addition of more CO2 to these trains will increase methanol production from trains II and III whilst there will be an incremental loss from train IV. This will lead to a reduction in the purge gas rates available from trains II and III and therefore will increase the purge export from train I to train IV. This will increase the amount of natural gas required as fuel on train I and therefore reduce the amount of natural gas available as feed. This will represent a loss of methanol production which will offset the additional methanol produced in trains II and III due to the addition of CO2. This can be reviewed at a later date. Even with train IV operating with the coal gasification gas, methanol production is reduced by some 1,826 mtpd, a reduction of 17%. The prime reason for this is that under the natural gas reduction case considered (75% of the normal available), there is only 12,674 kmol/hr of carbon (all carbon in feed gas to the reformers/gasifier) available to be converted to methanol. This compares to 16,566 kmol/hr of carbon normally available when 100% of the natural gas is available. This is a reduction of 23% in comparison to normal operation. 3.2.3 Case 2 – Coal Gasification in Service – No CO2 Export The following table details the natural gas utilization under the conditions required for case 1, Train I through III operating with natural gas (75% of the normal rate available) and train IV operating with the gasified coal feed. Under this case, no CO2 is exported from the CO2 removal stage to the other plants. Parameter Loop Production Refined Production Carbon Efficiency Units mtpd mtpd % Train I 1,984 1,950 98.2 Train II 2,245 2,208 96.5 Train III 2,411 2,370 98.7 Train IV 2,372 2,325 95.0 Total 9,012 8,853 n/a It should be noted that at these lower distillation throughputs, distillation efficiency should rise. No account of this effect has been taken into account as part of this study.
  20. 20. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com Note in this case, the amount of CO2 removed from the syn gas from the gasifier amounts to 414 kmol/hr to provide additional CO2 for conversion to methanol in the train IV loop. In this case, the methanol production is higher than for the case (1) with CO2 recycle to trains II and III. However, there are implications in terms of CO2 emissions which are detailed below. Production is still lower than the base case as there is less carbon available in the feed gas (13,288 kmol/hr) compared to the base case value of 16,566 kmol/hr. This is a reduction of 20% I terms of available carbon in the combined feed gases. 3.3 85% Natural Gas Availability If 85% of the maximum normally available natural gas can be utilized, then the overall production from the site will be 9,789 mtpd, which is 92% of the normal site production level. This utilizes a total of 14,555 kmol/hr of natural gas as feed and fuel. 3.4 100% Natural Gas Availability If 100% of the maximum normally available natural gas can be utilized, then the overall production from the site will be 11,331 mtpd, which is 107% of the normal site production level. The following graph illustrates the variance of methanol production against natural gas availability assuming CO2 addition to trains II and III, 8090100110120708090100110NG Availability (%) Production (%) 80009000100001100012000Production (%) Production (mtpd) Present Production(mtpd)
  21. 21. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com On this graph, production as a percentage of present production (10,616 mtpd) is plotted on the left hand Y axis and actual production is plotted on the right hand Y axis. This graph illustrates that the breakeven point between 91-92% of normal natural gas availability. This equates to a natural gas flow to site of 15,668 kmol/hr. 3.5 CO2 Emissions A review of the CO2 emissions from the four trains has been conducted as CO2 emissions are becoming more important due to the effect of global warming. The CO2 figures reported below are for the CO2 present in the fluegas from the steam reformers on trains I through III. No account of CO2 emissions from on/off site power generation or from train IV has been included in the analysis. 3.5.1 Base Case The following table details the CO2 emission figures for trains I through IV that have been developed as part of this study for the base case, Parameter CO2 Produced Units kmol/hr Train I 1,010 Train II 938 Train III 1,180 Train IV unknown Total 3,128 Note that these figures represent the CO2 emissions from the fluegas generated in the radiant box of the reformer and do not include contributions from fired heaters on the site, auxiliary burner or any part of train IV including train IV offsite facilities.
  22. 22. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 3.5.2 Case 1 – Coal Gasification in Service The following table details the CO2 emission figures for trains I through IV that have been developed as part of this study for case 1 of this study, Parameter CO2 Produced Units kmol/hr Train I 1,163 Train II 1,438 Train III 1,529 Train IV unknown Total 4,130 As can be seen the CO2 emissions are increased significantly when operating the coal gasifier. The major driver for this is the loss of purge gas to fuel which is replaced by natural gas. Since the natural gas comprises over 93% methane this increases the CO2 emitted by the plants by some 32% over the base case presented above. 3.5.3 Case 2 – Coal Gasification in Service – No CO2 Export The following table details the CO2 emission figures for trains I through IV that have been developed as part of this study for case 1 of this study, Parameter CO2 Produced Units kmol/hr Train I 1,216 Train II 1,268 Train III 1,354 Train IV unknown CO2 Removal 414 Total 4,252 By not recycling the CO2 from the CO2 removal units to trains II and III, the CO2 emissions are increased over and above the CO2 recycle case by 3% and an increase of 36% over the base case.
  23. 23. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 3.6 Specific Consumption Figures 3.6.1 Base Case The following table details the methanol production figures for trains I through IV that have been developed as part of this study for the base case, Parameter NG Total Usage Refined Production Specific Consumption Units kmol/hr mtpd (kmol/hr)/(mtpd) Train I 4,196 2,506 1.67 Train II 4,694 2,756 1.70 Train III 4,973 2,945 1.69 Train IV 3,261 2,400 1.36 Total 17,524 10,616 1.65 As noted above, no account of natural gas used as fuel on train IV has been made as part of this study. This is one reason why the specific consumption figure for train IV does appear lower than for the other plants. 3.6.2 Case 1 – Coal Gasification and CO2 Import The following table details the methanol production figures for trains I through IV that have been developed as part of this study for case 1 of this study, Parameter NG Total Usage Refined Production Specific Consumption Units kmol/hr mtpd (kmol/hr)/(mtpd) Train I 3,899 2,016 1.93 Train II 4,354 2,128 2.05 Train III 4,591 2,304 1.99 Train IV 0 2,342 n/a Total 12,844 8,790 1.46 The specific consumption figures for case 1 are higher than for the base case due to the loss of purge gas as fuel for trains I through III. However, the overall figure is lower for this case in comparison to the base case due to the additional production from train IV and the fact that the coal is not taken into account.
  24. 24. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 3.6.3 Case 2 – Coal Gasification and No CO2 Import The following table details the methanol production figures for trains I through IV that have been developed as part of this study for case 2 of this study, Parameter NG Total Usage Refined Production Specific Consumption Units kmol/hr mtpd (kmol/hr)/(mtpd) Train I 3,898 1,950 2.00 Train II 4,354 2,208 1.97 Train III 4,591 2,370 1.94 Train IV 0 2,325 n/a Total 12,843 8,853 1.45 The figures presented in the above table show a similar specific consumption in comparison to case detailed above. However, the methanol production figure is marginally higher due to the additional natural gas that is made available as feed gas as opposed to be utilised as fuel gas in case 1. 3.7 Train IV Synthesis Gas Composition Typically the combined syn gas combination being feed to the train IV loop has a stoichiometric number of 1.95. The composition in the table below has been calculated for case 1 considered as part of this study and is typical of the other combined gas compositions, Parameter Value Units mol % dry CO 13.65 CO2 12.99 H2 64.64 CH4 7.80 N2 0.88 Ar 0.04
  25. 25. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 4 Further Work As part of this study the following areas of further work have been identified in order to address issues generated as part of this study or to understand areas of uncertainty that have been highlighted by this study. • An evaluation of the effect of the addition of CO2 on the molecular weight and hence the circulation rates achievable on trains II and III. • A confirmation of the design basis natural gas usage (whether as feed or fuel) and the export of purge gas to train IV is required. This will confirm the amount of natural gas available to the site and for each plant and hence the amount available during period of gas shortage. • Confirmation of the performance of train IV with due regard to natural gas usage and loop performance • Confirmation of the steam balance requirements for the coal gasification front end proposed for train IV and the effect this will have on the steam generation/superheating system present on train IV. This will define whether there is additional natural gas available from train IV on the other plants during gas shortages. • Determination of the utilization of purge gas from train IV and the usage of this gas when operating train IV on syn gas derived from the gasification of coal. • Evaluation of the purge gas requirements for purification for trains I through III when natural gas utilization is lower than normal. • Confirmation of distillation separation efficiencies, most especially for train IV. • Re-optimization of the natural gas splits between trains I through III during periods of low natural gas availability should be performed if the project proceeds. • Re-optimization of the CO2 import split between trains II and III during periods of low natural gas availability should be performed if the project proceeds. • Optimization of the amount of CO2 removal from train IV front end and optimisation of this to trains II and III.
  26. 26. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com 5 Conclusion The key conclusions from this study are that, • Operation utilizing a coal gasifier is possible. • Production rate will be lowered from the present maximum achievable rate due to the replacement of the purge gas exported to train IV with natural gas as reformer fuel. • Addition of a coal gasifier and the effect on the fuel balance on trains I through III will increase CO2 emissions. • Under circumstances where train IV is operated on the gasified coal feed and 100% of normal natural gas is available, site production will be increased to 11,331 mtpd, an increase of 7% over present maximum site production. • If between 91-92% of normal natural gas flowrate is available, then site production with the coal gasified feed to train IV will be the same as the base case considered as part of this study. • An operability review has been conducted to determine the effect of losing one or more of trains I through III and the effect that this will have on train IV.
  27. 27. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com APPENDIX The Important stream data follows: MATERIAL BALANCE STREAM DATA
  28. 28. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com Texaco Gasifier with HP Steam Raising Boiler Coal is slurried and enters the Texaco gasifier along with oxygen from the existing ASU. Dirty synthesis gas leaves the gasifier and passes through an HP steam raising process boiler, followed by a quench section. The cooled synthesis gases enter an Ash Removal Unit (proprietary) from which Ash is removed. The next unit may be a chlorine guard depending on the operating conditions required to meet impurity requirements for passing to the existing Train 4 methanol loop. The gasifier pressure is limited by the maximum ASU oxygen supply pressure stated above, however, it is desirable to provide Syngas at 31.77 bg at the suction to the existing Syngas compressor. After the gasifier quench system, the synthesis gas is further cooled then passes through a bulk sulfur removal system, ZnO Sulfur Removal Guard Bed upstream of the existing reformed gas cooler, to ensure a sulfur concentration of 10 ppb or less.
  29. 29. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com CHARACTERISTICS OF COAL Hardness Hardgrave HGI 37-45 IMMEDIATE ANALYSIS: Superficial humidity (ambient T°) (%) 6-12 Residual humidity (at 105°C) (%) 15-18 Total humidity (%) 20-25 Sup Heat Value (Kcal/Kg) 5500 Ashes (%) 15-20 Volatile material (%) 35 Fixed Carbon (%) 30 ELEMENTAL ANALYSIS: Total Carbon (%) 60 Hydrogen (%) 4.5 Oxygen (%) 18 Nitrogen (%) 0.8 Total Sulfur (%) 0.8 ASHES CHEMICAL ANALYSIS: SiO2 (%) 35 Al2O3 (%) 20 CaO (%) 15 Fe2O3 (%) 5 MgO (%) 2.5 Na2O (%) 2.5 ASHES FUSION T°: Initial Deformation T° (°C) 1290 Softening T° (°C) 1340 Hemispheric T° (°C) 1380 Fluidity T° (°C) 1445 Data is on dry basis, which is the comparison basis for carbons. B.S = C.D (1/(100-H.R./100)) C.D as determined C.R = B.S ((100-H.T)/100) B.S dry basis
  30. 30. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com C.R as received H.R residual humidity H.T total humidity Material Balance Considerations: Here, it is considered that conditions of inlet streams including temperature and pressure are prefixed and the only aim is to study the performances of equipments on the compositions and flowrates of other streams. So, those parts of the process are calculated which influence appreciably the composition of these streams. The Schematic presentation of a simplified generic loop and boundaries, material balances are written around them, are shown in the following Figure 2.
  31. 31. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com Figure 2 To start mathematical modeling of methanol synthesis loop, it is noted that all streams at most contain H2, CO2, CO, CH3OH2, H2O, CH4, N2, Ar. Material balance equations are typically performed on the three boundaries corresponding to Fig. 2. Number of equations for each boundary
  32. 32. Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology – Ammonia Catalyst Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries Web Site: www.GBHEnterprises.com

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