Optimal Design of Petroleum Refinery Configuration Using a Model-Based Mixed- Integer Programming Approach with Practical Approximation Tareq A. Albahri, Cheng Seong Khor, Mohamed Elsholkami, and Ali Elkamel 1 Chemical Engineering Department, Kuwait University, P.O. Box 5969, Safat 13060, Kuwait 2 Chemical Engineering Programme, Xiamen University Malaysia, Jalan Sunsuria, Bandar Sunsuria, 43900 Sepang, Selangor Darul Ehsan, Malaysia 3 Chemical Engineering Department, Universiti Teknologi PETRONAS, 32610 Seri Iskandar, Perak Darul Ridzuan, Malaysia 4 Department of Chemical Engineering, University of Waterloo, Waterloo, ON N2L 3G1, Canada 5 Department of Chemical Engineering, Khalifa University, The Petroleum Institute, Abu Dhabi United Arab Emirates Tel: (+965) 2481-7662; Fax: (+965) 2483-9498 *Corresponding author. E-mail: toalbahri@gmail.com Supporting Information Cost data and relations We obtain data on capital investment and running costs from various industry standard sources. 1-5 We apply Equation (1) to conceptual curve-type costs 2 that we escalate to that of the present (third quarter (3Q) of 2016) for U.S. Gulf Coast location for the grassroots construction case as illustrated here for capital cost CC:
i F I n (1) CC CC 1 where CC F = cost for 3Q 2016 (present), CC I = cost for reported date, n = number of years between reported date to the present, and i = inflation rate (average). Note the United States West Coast location has the lowest erection cost that we adjust for other locations if desired. We assume an annual i value as 3%/year. We use factoring-type investment cost data, i.e., with fixed cost per unit of feed 3 that we adjust for capacity using the six tenth rule of Equation (9) 5-6 and then escalate similarly as for the previous data for two assumed refineries called plant 1 and plant 2: CC c F F P2 P2 CCP1 cp1 0.6 (2) where F CC P1 = cost of plant 1, F CC P2 = cost of plant 2, c P1 = capacity of plant 1, and c P2 = capacity of plant 2. If a certain cost is not available, we estimate based on the same erection and running costs for an equivalent process technology, e.g., we use the data for Stone and Webster s RFCC catalytic cracking to estimate the cost for Shell LR FCC technology. The approximation is acceptable given that there is a reported 30 to 50% error in cost estimation. 50 The detailed relations for the cost parameters in the objective function are as follows: CC cc c nu (3) k k k k
CR k = cr k F k n (4) CM nf CE k (5) k CP = cp n m (6) where cc k = unit capital cost for process unit k ($/bbl), c k = capacity of process unit k (bbl/d), n = number of days in a year, cr k = unit running cost for process unit k ($/bbl), F k = inlet flow rate of process unit k (bbl/d), f = cost factor (inflation rate) for maintenance allowance and taxes and insurance (%), CE k = total annualized erection cost for process unit k ($/yr), average daily pay per employee ($/d), and m = number of employees. Table S1 lists the refinery feed and product prices used in our study (as based on Q3 2014 data) while Table S2 gives the utility prices. Table S3 lists the process units and their operating modes that are considered in the study (which are included in the refinery superstructure).
1, 7-13 Table S1. Refinery feed and product prices for Q3 2014 (in US$) Product $/bbl $/ton Crude oil (Brent June 2014) 108 776 Liquefied petroleum gas 110 1,260 Hydrotreated naphtha 113 1,013 Gasoline 121 1,085 Hydrotreated kerosene 120 944 Hydrotreated diesel 122 905 Gas Oil product 112 756 High sulfur atmospheric residue 90 587 Low sulfur atmospheric residue 96 628 High sulfur vacuum residue 90 567 Low sulfur vacuum residue 96 607 Pitch 131 620 Asphalt 94 515 Heavy fuel oil 117 744 Light fuel oil 118 904 Natural gas ($/MBtu) 3.75 Hydrogen ($/10 6 cm 3, $/MMSCF) 544 Petroleum sulfur 166 Petroleum coke (calcined) 135 Methanol 220 Ethylene 750 Acetylene 860 Propylene 1,300 Crude butadiene 3,300 Ammonia 460 Table S2. Utility prices 1 Utility Value Unit High pressure steam 0.0041 $/lb Medium pressure steam 0.00365 $/lb Low pressure steam 0.0031 $/lb Power 0.08 $/kwh Cooling water 0.00005 $/gal Fuel (net) 2.02 $/MBtu Boiler feedwater 0.0063 $/gal Process/injection water 0.0054 $/gal Condensate 0.0054 $/gal Hydrogen 850 $/10 6 cm 3 Monoethanolamine 6.78 $/gal (MEA) solution 0.80 $/lb Oxygen 0.19 $/ton Maintenance allowance 2% of erection cost $/year Taxes and insurance 1% of erection cost $/year
Table S3. Process units and operating modes in the study 1. Gasoil Cracking: ACR Chevron Isocracking Process (gasoline, s, and diesel modes) FCC IFP Hydrocracking process S&W FCC UOP/UNOCAL Unicracking Process (Gasoline, jet fuel,, and Gasoil modes) 2. Catalytic hydrotreating/hydroconversion of AR: CANMET Chevron ARDS/VRDS hydrotreating process HDH Process HFC Hyvahl F LC-Fining MICROCAT RC Residfining RHC RHC + GHC Combined Process R-HYC high and medium conversion modes SHELL-RHC Unicracking/HDS process 3. Mild Cracking: HYCAR TERVAHL-H TERVAHL-T Visbreaking 4. Solvent Deasphalting: DEMEX (low and high extraction levels) LEDA (30%, 53% and 65% extraction modes) MDS ROSE SOLVAHL (C4 solvent and C5 solvent modes) 5. Catalytic Cracking of HSVR: ART HOT 6. Catalytic Cracking of LSAR: APC FCC CMS-RFCC HOC R2R (gasoline and distillates modes) RCC (low, medium and high carbon residue) S&W RFCC Shell LR-FCC 7A. Catalytic hydrotreating/hydroconversion of VR: CANMET Hydrocracking Process Chevron RDS/VRDS hydrotreating (4 products mode) HDH Process HFC H-Oil Process Hyvahl F - Once through Process LC-Fining Process (High Conversion - 90%) MICROCAT RC MRH RCD UNIBON (BOC) RCD UNIBON (BOC) + Thermal conversion Residfining SHELL-RHC Process SOC Unicracking/HDS process - Distillate mode VCC VisABC 7B. Thermal Cracking of VR: ASCOT Cherry-P Delayed Coking (0.1, 0.3 or 1.08 recycle ratio) ET-II EUREKA Flexicocking Fluid Coking FTC HSC KKI 8. Gasification of asphalt, pitch, tar and coke: HYBRID gasification Oxygen-Blown KRW Gasification Shell (Partial Oxidation) Texaco Gasification Process Toyo THR-R Process 9. Common units: Amine gas treating process Catalytic Reforming Process CDU Claus Sulfur Plant (98% sulfur recovery) DHTU GOHTU Hydrogen Process & PSA KHTU NHTU Refinery gas process VRU (LSAR and HSAR modes)
Refinery Superstructure Construction This section provides more detailed information on the three refinery processing schemes that are used as a basis to construct the superstructure for our MILP model development. ARDS processing scheme Figure S1 shows a residual conversion refinery topology based on an ARDS (atmospheric residue desulfurization) scheme. It uses a crude flasher followed by ARDS/VRDS hydrotreater (U 18 ) (e.g., the Chevron three-product mode technology). We next perform vacuum flashing (U 5 ) of the low sulfur atmospheric residue to produce a delayed coker feedstock. Straight-run naphtha, kerosene, and diesel are hydrotreated. Then we split the hydrotreated naphtha into light and heavy fractions for which the latter is catalytically reformed to improve octane rating. is hydrotreated to reduce its aromatic and naphthalene content to meet jet fuel specifications. We convert the low sulfur vacuum and coker gas oils in an advanced cracking reactor (U 12 ) to yield ethylene, acetylene, propylene, butadiene, and pyrolysis gasoline. This option is more profitable than using conventional gas oil FCC or hydrocracker. Delayed coker converts vacuum residue to cracked distillates and green coke. Using ARDS upstream of delayed coker improves the ultimate coke quality by reducing sulfur and metals in the coker feed. To compare, low sulfur gas oils produced via this scheme gives better advanced cracking reactor yields than untreated coker gas oils (CGO) from a straight-run naphtha residue. Because ARDS reduces the carbon residual content of coker feed, coke yield from delayed coker is less than that of untreated reduced crude oil feed. 37 A vacuum rerun unit downstream of ARDS further reduces coke yield. Moreover, operating delayed coker at 10% recycle ratio is more profitable. Hence it is
advantageous to convert coke to hydrogen in KRW gasification process (U 90 ) to supplement refinery needs. VRDS processing scheme Figure S2 shows another type of residual conversion refinery topology that is based on a VRDS (vacuum residue desulfurization) scheme. It initially performs vacuum flashing of high sulfur atmospheric residue. This configuration uses a combined crude and vacuum flasher coupled with gas oil hydrotreater and advanced cracker to hydrotreat straight-run naphtha, kerosene, and diesel. Like ARDS scheme, we then split the hydrotreated naphtha into light and heavy fractions to catalytically reform the latter while hydrotreating straightrun kerosene to jet fuel. High sulfur vacuum residue is desulfurized by Shell RHC catalytic hydrotreater/hydroconverter (U 40 ) followed by delayed coking at 10% recycle ratio (U 53 ). Low sulfur gas oil from vacuum rerun unit, delayed coker, and Shell RHC is fed to advanced cracking reactor, which as is similar to the ARDS scheme, is found to be feasible and preferred than using conventional hydrocracker or FCC. Advanced cracking reactor converts low sulfur gas oil to high yields of ethylene, acetylene, propylene, butadiene and hydrolysis gasoline. Delayed coker converts vacuum residue to cracked distillates and green coke. Since Shell RHC reduces the coker feed s carbon residual content, coke yield from delayed coker is less than that of an untreated reduced crude feed. RFCC processing scheme Figure 2 shows a residual conversion refinery based on RFCC (residue fluid catalytic cracking) scheme. It involves residual cracking of low sulfur atmospheric residue using crude
flash followed by atmospheric residue desulfurization and then RFCC. We desulfurize reduced crude by the Chevron process followed by fluid catalytic cracking (FCC, U 68 ) with advanced process control (APC) to catalytically crack low sulfur atmospheric residue. Straight-run naphtha, kerosene, and diesel are hydrotreated. As is similar to the previous configurations, we then perform the following operating sequence: (1) split the hydrotreated naphtha into light and heavy fractions to catalytically reform the latter; (2) hydrotreat kerosene to jet fuel; (3) convert low sulfur atmospheric residue in U 68 to liquefied petroleum gas, gasoline, light cycle oil, and decant oil; (4) crack light cycle oil in advanced cracking reactor, in which this option is again preferred to hydrocracker or FCC to get high yields of ethylene, acetylene, propylene, butadiene, and hydrolysis gasoline. Besides improving FCC product yields, desulfurizing residue results in lower sulfur emissions from FCC regenerator and allows using FCC decant oil as low sulfur fuel oil. Note that a low sulfur light cycle oil produced via this route gives better advanced cracking reactor yields than an untreated one from a straight-run residue.
Refinery Gas Gas Unit (U 93 ) Amin Unit (U 94 ) S Sulfur Unit (U 95 ) Sulfur HS HTU (U 1 ) LS Catalytic Reforming (U 91 ) Reformate Gasoline Crude Oil Crude Oil Distillation Process (U 0 ) HS HTU (U 2 ) LS HS HTU (U 3 ) LS HS AR Chevron ARDS/VRDS Hydrotreating Process (U 18 ) LS AR Vacuum Rerun (U 5 ) LS VR Delayed Coker (U 53 ) VGO CGO ACR (U 12 ) Ethylene Acetylene Propylene Butadiene Pyrolysis Gasoline Light Fuel Oil Heavy Fuel Oil Hydrogen Production & PSA (U 92 ) Coke KRW Gasification (U 90 ) Natural Gas + Refinery rich off gases Figure S1. Simplified schematic representation of an ARDS refinery configuration, net refinery profit = $24.53/bbl (58.40 cent/gal) of crude oil refined.
Refinery Gas Gas Unit (U 93 ) Amin Unit (U 94 ) S Sulfur Unit (U 95 ) Sulfur HS HTU (U 1 ) LS Reformate Gasoline Crude Oil Crude Oil Distillation Process (U 0 ) HS HTU (U 2 ) LS HS HTU (U 3 ) LS HS AR Vacuum Rerun (U 6 ) HS VR Shell RHC (U 40 ) HSVGO Gas Oil HTU (U 4 ) GO VGO ACR (U 12 ) Ethylene Acetylene Propylene Butadiene Pyrolysis Gasoline Light Fuel Oil Heavy Fuel Oil Delayed Coker (U 53 ) CGO Hydrogen Production & PSA (U 92 ) Coke KRW Gasification (U 90 ) Natural Gas + Refinery rich off gases Figure S2. Simplified schematic representation of a VRDS refinery configuration, net refinery profit = $22.75/bbl (54.20 cent/gal) of crude oil refined.
Refinery Gas Gas Unit (U 93 ) Amin Unit (U 94 ) S Sulfur Unit (U 95 ) Sulfur HS HTU (U 1 ) LS Catalytic Reforming (U 90 ) Reformate Gasoline Crude Oil Crude Oil Distillation Process (U 0 ) HS HTU (U 2 ) LS HS AR Chevron ARDS/VRDS Hydrotreating Process (U 18 ) LS AR APC FCC (U 68 ) Decant oil HS LCO Gasoline HTU (U 3 ) ACR (U 12 ) LS Ethylene Acetylene Propylene Butadiene Pyrolysis Gasoline Light Fuel Oil Heavy Fuel Oil Hydrogen Production & PSA (U 92 ) Natural Gas + Refinery rich off gases Figure S3. Simplified schematic representation of RFCC configuration, net refinery profit = $25.55/bbl (60.8 cent/gal) of crude oil refined
Refinery Gas Gas Unit (U 93 ) Amin Unit (U 94 ) S Sulfur Unit (U 95 ) Sulfur HS HTU (U 1 ) LS Reformate Gasoline Crude Oil Crude Oil Distillation Process (U 0 ) HS HTU (U 2 ) LS HS AR Vacuum Rerun (U 6 ) HS VR H-Oil (U 33 ) LSFO HS HSVGO RCD UNIBON (U 37 ) HTU (U 3 ) VGO VGO LS Chevron HCR (U 7 ) Light Heavy Hydrogen Production & PSA (U 92 ) Natural Gas + Refinery rich off gases Figure S4. Simplified schematic representation of SHU refinery configuration, net refinery profit = $16.76/bbl (39.90 cent/gal) of crude oil refined.
Refinery Gas Gas Unit (U 93 ) Amin Unit (U 94 ) S Sulfur Unit (U 95 ) Sulfur HS HTU (U 1 ) LS Catalytic Reforming (U 91 ) Reformate Gasoline Crude Oil Crude Oil Distillation Process (U 0 ) HS HTU (U 2 ) LS HS AR ARDS/VRDS Hydrotreating/ Hydroconversion Process (U 18 ) LS AR Vacuum Rerun (U 5 ) HS VGO HTU (U 3 ) Chevron HCR (U 7 ) LS Light Heavy Hydrogen Production & PSA (U 92 ) Natural Gas + Refinery rich off gases LSVR to MAB Delayed Coker FCC (U 10 ) Figure S4. Simplified schematic representation of MAA refinery configuration, net refinery profit = $17.27/bbl (41.10 cents per gal.) of crude oil refined.
Refinery Gas Gas Unit (U 93 ) Amin Unit (U 94 ) S Sulfur Unit (U 95 ) Sulfur HS HTU (U 1 ) LS Crude Oil Crude Oil Distillation Process (U 0 ) HS HTU (U 2 ) LS HS AR HS HTU (U 3 ) LS Hydrogen Production & PSA (U 92 ) ARDS/VRDS Hydrotreating/Hydro conversion Process (U 18 ) Natural Gas + Refinery rich off gases LS AR Vacuum Rerun (U 5 ) LS VR VGO Chevron HCR (U 7 ) Light Heavy Delayed Coker (U 64 ) GO Coke Figure S5. Simplified schematic representation of MAB refinery configuration, net refinery profit = $18.00/bbl (42.90 cents/gal) of crude oil refined.
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