Patent Publication Number: US-9896629-B2

Title: Integrated process to produce asphalt, petroleum green coke, and liquid and gas coking unit products

Description:
RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Patent Application No. 62/028,892 filed Jul. 25, 2014, the disclosure of which is hereby incorporated by reference. 
    
    
     BACKGROUND OF THE INVENTION 
     Field of the Invention 
     This invention relates to integrated processes and systems for production of asphalt, high quality petroleum green coke, and liquid and gas coking unit products. 
     Description of Related Art 
     Crude oils contain heteroatomic molecules, including polyaromatic molecules, with heteroatomic constituents such as sulfur, nitrogen, nickel, vanadium and others in quantities that impact the refinery processing of the crude oils fractions. Light crude oils or condensates have sulfur concentrations as low as 0.01 percent by weight (W %), in contrast, heavy crude oils and heavy petroleum fractions have sulfur concentrations as high as 5-6 W %. Similarly, the nitrogen content of crude oils is in the range 0.001-1.0 W %. The heteroatom contents of various Saudi Arabian crude oils are given in Table 1. As seen, the heteroatom content of the crude oils within the same family increases with decreasing API gravity on increasing heaviness. The heteroatom content of the crude oil fractions also increases with increasing boiling point (Table 2). 
     
       
         
           
               
               
               
               
               
               
             
               
                 TABLE 1 
               
               
                   
               
               
                 Property 
                 ASL 
                 AEL 
                 AL 
                 AM 
                 AH 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
            
               
                 Gravity, ° 
                 51.4 
                 39.5 
                 33.0 
                 31.1 
                 27.6 
               
               
                 Sulfur, W % 
                 0.05 
                 1.07 
                 1.83 
                 2.42 
                 2.94 
               
               
                 Nitrogen, ppmw 
                 70 
                 446 
                 1064 
                 1417 
                 1651 
               
               
                 RCR, W % 
                 0.51 
                 1.72 
                 3.87 
                 5.27 
                 7.62 
               
               
                 Ni + V, ppmw 
                 &lt;0.1 
                 2.9 
                 21 
                 34.0 
                 67 
               
               
                   
               
               
                 ASL—Arab Super Light 
               
               
                 AEL—Arab Extra Light 
               
               
                 AL—Arab Light 
               
               
                 AM—Arab Medium 
               
               
                 AH—Arab Heavy 
               
            
           
         
       
     
     
       
         
           
               
               
               
             
               
                 TABLE 2 
               
               
                   
               
               
                 Fractions, ° C. 
                 Sulfur W % 
                 Nitrogen ppmw 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
            
               
                 C 5 -90 
                 0.01 
                   
               
               
                  93-160 
                 0.03 
                   
               
               
                 160-204 
                 0.06 
                   
               
               
                 204-260 
                 0.34 
                   
               
               
                 260-315 
                 1.11 
                   
               
               
                 315-370 
                 2.00 
                 253 
               
               
                 370-430 
                 2.06 
                 412 
               
               
                 430-482 
                 2.65 
                 848 
               
               
                 482-570 
                 3.09 
                 1337 
               
               
                   
               
            
           
         
       
     
     Contaminants (poisonous compounds) such as sulfur, nitrogen, poly-nuclear aromatics in the crude oil fractions impact the downstream processes including hydrotreating, hydrocracking and fluid catalytic cracking (FCC). The contaminants are present in the crude oil fractions in varying structures and concentrations. These impurities must be removed during the refining to meet the environmental regulations for the final products (e.g., gasoline, diesel, fuel oil) or for the intermediate refining streams that need to be processed for further upgrading such as reforming isomerization. Contaminants such as nitrogen, sulfur and heavy metals are known to deactivate or poison catalysts. 
     In conventional refining schemes, crude oil is first in an atmospheric column to separate sour gas and light hydrocarbons including methane, ethane, propane, butanes and hydrogen sulfide, naphtha (36-180° C.), kerosene (180-240° C.), gas oil (240-370° C.) and atmospheric residue bottoms which include hydrocarbons boiling above 370° C. 
     The atmospheric residue from the atmospheric distillation column is either used as fuel oil or sent to a vacuum distillation unit, depending on the configuration of the refinery. In configurations in which the bottoms are further distilled in a vacuum distillation column, products obtained include vacuum gas oil having hydrocarbons boiling in the range 370-520° C. and vacuum residue having hydrocarbons boiling above 520° C. 
     As the boiling point of the petroleum fractions increases, the quality of oil decreases and negatively impacts the downstream processing units. Table 3 and Table 4 provide quality of atmospheric (boiling above 370° C.) and vacuum residual (boiling above 520° C.) oils derived from various crude sources. It is clearly shown in these tables that the atmospheric or vacuum residues are highly contaminated with heteroatoms and have high Condranson carbon residue content and the quality deteriorates with decreasing API Gravity. 
     
       
         
           
               
               
               
               
               
               
             
               
                 TABLE 3 
               
               
                   
               
               
                   
                   
                 API 
                 Sulfur, 
                 Ni + V, 
                 CCR, 
               
               
                 Source 
                 name 
                 Gravity, ° 
                 W % 
                 ppmw 
                 W % 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
            
               
                 Middle East 
                 Arabian Light 
                 16.80 
                 3.14 
                 550.00 
                 7.60 
               
               
                 Middle East 
                 Arabian Heavy 
                 12.70 
                 4.30 
                 125.00 
                 13.20 
               
               
                 South Asia 
                 Mina 
                 26.40 
                 0.15 
                 16.00 
                 4.20 
               
               
                 South Asia 
                 Duri 
                 17.50 
                 0.22 
                 17.00 
                 9.30 
               
               
                 China 
                 Shengli 
                 18.70 
                 1.23 
                 19.00 
                 8.60 
               
               
                 China 
                 Taching 
                 25.10 
                 0.13 
                 4.00 
                 4.00 
               
               
                 Latin America 
                 Maya 
                 8.30 
                 4.82 
                 494.00 
                 17.40 
               
               
                 Latin America 
                 Isthmus 
                 13.90 
                 2.96 
                 53.00 
                 8.20 
               
               
                   
               
            
           
         
       
     
     
       
         
           
               
               
               
               
               
               
             
               
                 TABLE 4 
               
               
                   
               
               
                   
                   
                 API 
                 Sulfur, 
                 Ni + V, 
                 CCR, 
               
               
                 source 
                 name 
                 Gravity, ° 
                 W % 
                 ppmw 
                 W % 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
            
               
                 Middle East 
                 Arabian Light 
                 6.90 
                 4.34 
                 141.00 
                 20.30 
               
               
                 Middle East 
                 Arabian Heavy 
                 3.00 
                 6.00 
                 269.00 
                 27.70 
               
               
                 South Asia 
                 Mina 
                 17.30 
                 0.19 
                 44.00 
                 10.40 
               
               
                 South Asia 
                 Duri 
                 13.00 
                 0.25 
                 32.00 
                 15.20 
               
               
                 China 
                 Shengli 
                 11.70 
                 1.66 
                 28.00 
                 16.40 
               
               
                 China 
                 Taching 
                 18.70 
                 0.18 
                 9.00 
                 9.50 
               
               
                 Latin America 
                 Maya 
                 −0.10 
                 5.98 
                 835.00 
                 29.60 
               
               
                 Latin America 
                 Isthmus 
                 4.00 
                 4.09 
                 143.00 
                 21.10 
               
               
                   
               
            
           
         
       
     
     Naphtha, kerosene and gas oil streams from crude oils or other natural sources such as shale oils, bitumens and tar sands, are treated to remove the contaminants mainly sulfur, whose quantity exceeds the specifications. Hydrotreating is the most common refining technology to remove these contaminants (poisonous compounds for other processes/catalysts or to meet final fuel specifications). Vacuum gas oil is processed in a hydrocracking unit to produce gasoline and diesel or in an FCC unit to produce mainly gasoline, and LCO and HCO as by-products. The former of which is either used as a blending component in a diesel pool or fuel oil, while the latter is sent directly to the fuel oil pool. 
     Heavier fractions from the atmospheric and vacuum distillation units can contain asphaltenes. Asphaltenes are solid in nature and comprise polynuclear aromatics, smaller aromatics and resin molecules. The chemical structures of asphaltenes are complex and include polynuclear hydrocarbons having molecular weights up to 20,000 joined by alkyl chains. Asphaltenes also include nitrogen, sulfur, oxygen and metals, i.e., nickel, vanadium. They are present in crude oils and heavy fractions in varying quantities. Asphaltenes exist in small quantities in light crude oils, or not at all in all condensates or lighter fractions. However, they are present in relatively large quantities in heavy crude oils and petroleum fractions. Asphaltenes have been defined as the component of a heavy crude oil fraction that is precipitated by addition of a low-boiling paraffin solvent, or paraffin naphtha, such as normal pentane, and is soluble in carbon disulfide and benzene. In certain methods their concentrations are defined as the amount of asphaltenes precipitated by addition of an n-paraffin solvent to the feedstock, e.g., as prescribed in the Institute of Petroleum Method IP-143. The heavy fraction can contain asphaltenes when it is derived from carbonaceous sources such as petroleum, coal or oil shale. There is a close relationship between asphaltenes, resins and high molecular weight polycyclic hydrocarbons. Asphaltenes are hypothesized to be formed by the oxidation of natural resins. The hydrogenation of asphaltic compounds containing resins and asphaltenes produces heavy hydrocarbon oils, i.e., resins and asphaltenes are hydrogenated into polycyclic aromatic or hydroaromatic hydrocarbons. They differ from polycyclic aromatic hydrocarbons by the presence of oxygen and sulfur in varied amounts. 
     Upon heating above about 300-400° C., asphaltenes generally do not melt but rather decompose, forming carbon and volatile products. They react with sulfuric acid to form sulfonic acids, as might be expected on the basis of the polyaromatic structure of these components. Flocs and aggregates of asphaltenes will result from the addition of non-polar solvents, e.g., paraffinic solvents, to crude oil and other heavy hydrocarbon oil feedstocks. 
     Therefore, it is clear that significant measures must be taken during processing of crude oils and heavy fractions to deal with asphaltenes. Failure to do so interferes with subsequent refining operations. 
     There are several processing options for the vacuum residue fraction, including hydroprocessing, coking, visbreaking, gasification and solvent deasphalting. 
     In additional configurations, vacuum residue can be treated in an asphalt unit to produce asphalt by air oxidation. Asphalt oxidation is a process in which air is bubbled through the feedstock or pitch in an oxidizer column vessel to oxidize sulfur-containing compounds. It is a non-catalytic process to shift the sulfur molecules from the oil phase to the asphalt phase. 
     In some refining configurations, the vacuum residue can be processed in a solvent deasphalting unit to separate the solvent soluble (deasphalted oil) and insoluble oil (asphaltenes) fractions. 
     Solvent deasphalting is an asphalt separation process in which residue is separated by polarity, instead of by boiling point, as in the vacuum distillation process. The solvent deasphalting process produces a low contaminant deasphalted oil (DAO). These fractions can then be further processed in conventional conversion units such as an FCC unit or hydrocracking unit. The solvent deasphalting process is usually carried out with paraffin C 3 -C 7  solvents at or below critical conditions. 
     Further material regarding solvent deasphalting can be found in U.S. Pat. Nos. 4,816,140; 4,810,367; 4,747,936; 4,572,781; 4,502,944:4,411,790; 4,239,616; 4,305,814; 4,290,880; 4,482,453 and 4,663,028, all of which are incorporated herein by reference. 
     Deasphalted oil contains a high concentration of contaminants such as sulfur, nitrogen and carbon residue which is an indicator of the coke forming properties of heavy hydrocarbons and defined as micro-carbon residue (MCR) or Conradson carbon residue (CCR) or Ramsbottom carbon residue (RCR). MCR, RCR, CCR are determined by ASTM Methods D-4530, D-524 and D-189, respectively. In these tests, the residue remaining after a specified period of evaporation and pyrolysis is expressed as a percentage of the original sample. For example, deasphalted oil obtained from vacuum residue of an Arabian crude oil contains 4.4 W % of sulfur, 2,700 ppmw of nitrogen, and 11 W % of MCR. In another example, a deasphalted oil of Far East origin contains 0.14 W % sulfur, 2,500 ppmw of nitrogen, and 5.5 W % of CCR. These high levels of contaminants, and particularly nitrogen, in the deasphalted oil limit conversion in hydrocracking or FCC units. The adverse effects of nitrogen and micro-carbon residue in FCC operations have been reported to be as follows: 0.4-0.6 W % higher coke yield, 4-6 V % less gasoline yield and 5-8 V % less conversion per 1000 ppmw of nitrogen. (See Sok Yui et al., Oil and Gas Journal, Jan. 19, 1998.) Similarly, coke yield is 0.33-0.6 W % more for each one W % of MCR in the feedstock. In hydrocracking operations, the catalyst deactivation is a function of the feedstock nitrogen and MCR content. The catalyst deactivation is about 3-5° C. per 1000 ppmw of nitrogen and 2-4° C. for each one W % of MCR. 
     It has been established that organic nitrogen is the most detrimental catalyst poison present in the hydrocarbon streams from the sources identified above. Organic nitrogen compounds poison the active catalytic sites resulting in catalyst deactivation, which in turn reduces catalyst cycle process length, catalyst lifetime, product yields, and product quality, and also increases the severity of operating conditions and the associated cost of plant construction and operations. Removing nitrogen, sulfur, metals and other contaminants that poison catalysts will improve refining operations and will have the advantage of permitting refiners to process more and/or heavier feedstocks. 
     In coking processes, heavy feeds are thermally cracked to produce coke, gas and liquid product streams of varying boiling ranges. Coke is generally treated as a low value by-product. It is removed from the units and can be recovered for various uses depending on its quality. 
     The use of heavy crude oils having high metals and sulfur content as an initial feed is of interest due to its lower market value. Traditional coking processes using these feeds produce coke which has substantial sulfur and metal content. The goal of minimizing air pollution is a further incentive for treating residuum in a coking unit since the gases and liquids produced contain sulfur in a form that can be relatively easily removed. 
     While individual and discrete asphalt oxidation, solvent deasphalting and coking operations processes are well developed and suitable for their intended purposes, there remains a need in the art for more economical and efficient processes for obtaining product from heavy feeds such as atmospheric and/or vacuum residues containing asphaltenes, N, S and metal contaminants. 
     SUMMARY OF THE INVENTION 
     An integrated system and process is provided for producing asphalt, high quality petroleum green coke, and liquid and gas coking unit products. 
     In one embodiment, the integrated process includes charging a heavy feedstock to an oxidizing unit along with an effective quantity of oxidant to produce an intermediate charge containing oxidized organosulfur compounds. The intermediate charge is passed to a solvent deasphalting unit along with an effective quantity of solvent to produce a deasphalted/desulfurized oil phase and an asphalt phase containing oxidized organosulfur compounds. The deasphalted/desulfurized oil phase is passed to a coker unit including a coker furnace and at least one coker drum to produce liquid and gas coker products as an effluent stream and to recover petroleum green coke from the coker drum. 
     In certain embodiments of the integrated process, which can be carried out within refinery limits, use of the deasphalted/desulfurized oil intermediate stream as feed to the coking unit enables recovery of high quality petroleum coke that can be used as raw material to produce low sulfur marketable grades of coke including anode grade coke (sponge) and/or electrode grade coke (needle). 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The invention will be described in further detail below and with reference to the attached drawing where: 
         FIG. 1  is a process flow diagram of an integrated process for asphalt oxidation, solvent deasphalting and delayed coking. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     An integrated process is provided to produce asphalt, petroleum green coke, and liquid and gas coking unit products. In the process described herein, sulfur molecules, and in certain embodiments nitrogen molecules, that are present in heavy petroleum fractions (e.g., in atmospheric residue) are oxidized. The polar oxidized sulfur compounds and in certain embodiments oxidized nitrogen compounds which are generally insoluble in the solvent used in the process generally shift from the soluble oil phase to the insoluble asphalt phase. Advantageously, the present process and system can be integrated with solvent deasphalting units of existing refineries to remove impurities at comparatively lower cost. 
     The deasphalted/desulfurized oil is thermally cracked in a coking unit, such as a delayed coking unit. In contrast to typical coking operations in which the coke is low market value by-product, in the integrated process herein, using as an initial feed heavy crude oils or fractions having reduced asphaltenes, metal and sulfur content, high quality petroleum green coke recovered from the coker unit drums is low in sulfur and metals. The recovered high quality petroleum green coke can be used as high quality, low sulfur and metal content fuel grade (shot) coke, and/or a raw material for production of low sulfur and metal content marketable grades of coke including anode grade coke (sponge) and/or electrode grade coke (needle). Table 5 shows the properties of these types of coke. In accordance with certain embodiments of the process herein, calcination of the petroleum green coke recovered from the coking drums produces sponge and/or needle grade coke, e.g., suitable for use in the aluminum and steel industries. Calcination occurs by thermal treatment to remove moisture and reduce the volatile combustible matter. 
     
       
         
           
               
               
               
               
               
             
               
                 TABLE 5 
               
               
                   
               
               
                   
                   
                 Fuel 
                 Calcined 
                 Calcined 
               
               
                 Property 
                 Units 
                 Coke 
                 Sponge Coke 
                 Needle Coke 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
            
               
                 Bulk Density 
                 Kg/m 3   
                 880 
                 720-800 
                 670-720 
               
               
                 Sulfur 
                 W % (max) 
                 3.5-7.5 
                 1.0-3.5 
                 0.2-0.5 
               
               
                 Nitrogen 
                 ppmw (max) 
                 6,000 
                 — 
                 50 
               
               
                 Nickel 
                 ppmw (max) 
                 500 
                 200 
                 7 
               
               
                 Vanadium 
                 ppmw 
                 150 
                 350 
                 — 
               
               
                 Volatile 
                 W % (max) 
                 12 
                 0.5 
                 0.5 
               
               
                 Combustible 
                   
                   
                   
                   
               
               
                 Material 
                   
                   
                   
                   
               
               
                 Ash Content 
                 W % (max) 
                 0.35 
                 0.40 
                 0.1 
               
               
                 Moisture Content 
                 W % (max) 
                  8-12 
                 0.3 
                 0.1 
               
               
                 Hardgrove 
                 W % 
                 35-70 
                  60-100 
                 — 
               
               
                 Grindability 
                   
                   
                   
                   
               
               
                 Index (HGI) 
                   
                   
                   
                   
               
               
                 Coefficient of 
                 ° C. 
                 — 
                 — 
                 1-5 
               
               
                 thermal expan- 
                   
                   
                   
                   
               
               
                 sion, E + 7 
               
               
                   
               
            
           
         
       
     
     As used herein, “high quality petroleum green coke” refers to petroleum green coke recovered from a coker unit that when calcined, possesses the properties as in Table 5, and in certain embodiments possessing the properties in Table 5 concerning calcined sponge coke or calcined needle coke identified in Table 5. 
     As used herein, a process that operates “within the battery limits of a refinery” refers to a process that operates with a battery of unit operations along with their related utilities and services, distinguished from a process whereby effluent from a unit operation is collected, stored and/or transported to a separate unit operations or battery of unit operations. 
     In one embodiment of a process herein, which can be carried out within the battery limits of a refinery and on a continuous or semi-continuous basis, a heavy feed such as an atmospheric residue fraction, e.g., boiling 370° C. and above, is passed to an asphalt unit for air oxidation to promote desulfurization and/or denitrification, in the presence or absence of catalysts. The asphalt unit product is introduced to a solvent deasphalting unit to separate oil fractions containing a reduced content of organosulfur compounds, and in certain embodiments also a reduced content of organonitrogen compounds, from the asphalt product, as the oil phase is relatively lighter than the asphalt phase. The deasphalted/desulfurized oil is thermally cracked in a coking unit, such as a delayed coking unit, and coker liquid and gas products are recovered, along with high quality petroleum green coke. 
     The process includes the steps of:
         Providing a hydrocarbon feedstock boiling in the range 36-1500° C., in certain embodiments above about 370° C. and in further embodiments above about 520° C., which contains impurities including sulfur, nitrogen nickel, vanadium, iron and molybdenum compounds, typically from crude oil sources;   Optionally adding the homogeneous catalysts to the feedstock. Homogeneous transition metal catalysts, active species of which are Mo(VI), W(VI), V(V), Ti(IV), possessing high Lewis acidity with weak oxidation potential are used as catalysts;   Mixing oxidant with the feedstock at the inlet of an asphalt oxidation unit. In certain embodiments the oxidant can be a gaseous oxidant such as air or oxygen or nitrous oxide or ozone. In other embodiments, the oxidant can include organic peroxides or aqueous peroxides such as hydrogen peroxide. Organic peroxides can be organic hydroperoxides such as alkyl hydroperoxides or aryl hydroperoxides, dialkyl peroxides, diaryl peroxides, or a combination comprising at least one of the foregoing organic peroxides. The dialkyl and diaryl peroxides have the general formula R1-O—O—R2, wherein R1 and R2 are the same or different alkyl groups or aryl groups. The available oxygen to oil ratio is in the range 1-50 V:V %, in certain embodiments 3-20 V:V % or equivalent for gaseous oxidants other than oxygen. The asphalt unit operates at a temperature of 100-300° C. and in certain embodiments 150-200° C. at the inlet and 150-400° C. and in certain embodiments 250-300° C. in the oxidation zone, and at a pressure level ranging from ambient to 60 bars and in certain embodiments from ambient to 30 bars;   Mixing the asphalt reactor effluents in a vessel with a C 3  to C 7 -paraffinic solvent, in certain embodiments a mixture of C 4 -normal and iso-butane, at a temperature and a pressure that are below the solvent&#39;s critical pressure and temperature, to thereby disturb the equilibrium of the asphaltenes in maltenes solution and to flocculate the solid asphaltenes particles. The critical temperatures and pressures for the paraffinic solvents are given in Table 6, and other solvent properties are given in Table 7;   Optionally using adsorbents in the solvent deasphalting stage to selectively further separate the nitrogen, sulfur and poly-aromatic compounds, for instance, as described in U.S. Pat. No. 7,566,634 which is incorporated by reference herein;   Separating solid phase asphaltenes from the liquid phase in a first separator vessel and transferring the bottoms to asphalt pool and the upper liquid layer to a second separation vessel;   Separating the deasphalted/desulfurized oil in the second separation vessel and recovering the paraffinic solvent for recycling to the mixing vessel; and   Introducing the deasphalted/desulfurized oil to a delayed coker unit to produce high quality petroleum green coke, and liquid and gas coking unit products.       

     
       
         
           
               
               
               
             
               
                 TABLE 6 
               
               
                   
               
               
                 Carbon Number 
                 Critical Temperature, ° C. 
                 Critical Pressure, bar 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
            
               
                 C 3   
                 97 
                 42.5 
               
               
                 C 4   
                 152 
                 38.0 
               
               
                 C 5   
                 197 
                 34.0 
               
               
                 C 6   
                 235 
                 30.0 
               
               
                 C 7   
                 267 
                 27.5 
               
               
                   
               
            
           
         
       
     
     
       
         
           
               
               
               
               
               
               
               
             
               
                 TABLE 7 
               
               
                   
               
               
                   
                   
                   
                 Boiling 
                   
                 Critical 
                 Critical 
               
               
                   
                   
                 MW 
                 Point 
                 Specific 
                 Temperature 
                 Pressure 
               
               
                 Name 
                 Formula 
                 g/g-mol 
                 ° C. 
                 Gravity 
                 ° C. 
                 bar 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
               
            
               
                 propane 
                 C 3 H 8   
                 44.1 
                 −42.1 
                 0.508 
                 96.8 
                 42.5 
               
               
                 n-butane 
                 C 4 H 10   
                 58.1 
                 −0.5 
                 0.585 
                 152.1 
                 37.9 
               
               
                 i-butane 
                 C 4 H 10   
                 58.1 
                 −11.7 
                 0.563 
                 135.0 
                 36.5 
               
               
                 n-pentane 
                 C 5 H 12   
                 72.2 
                 36.1 
                 0.631 
                 196.7 
                 33.8 
               
               
                 i-pentane 
                 C 5 H 12   
                 72.2 
                 27.9 
                 0.625 
                 187.3 
                 33.8 
               
               
                   
               
            
           
         
       
     
     Referring to  FIG. 1 , a process flow diagram of an integrated apparatus  8  for the production of asphalt and desulfurized oil is provided. Integrated apparatus  8  includes an oxidizing unit  10  (such as an oxidizer column vessel) and a solvent deasphalting unit  18  including a first separation vessel  20 , a second separation vessel  30 , a deasphalted/desulfurized oil separator  40 , a solvent steam stripping vessel  50 , an asphalt separation vessel  60 , an asphalt stripper vessel  70 , a recycle solvent vessel  80  and a delayed coking unit  90 . 
     Oxidizing unit  10  can be any suitable oxidation apparatus effective for converting organosulfur compounds and in certain embodiments organonitrogen compounds in a residual oil feedstock  12  into oxides thereof that are insoluble in the deasphalting unit solvent. In certain embodiments oxidizing unit  10  can be an oxidizer column vessel including an inlet  15  for receiving a residual oil feedstock  12  (downstream of one or more heat exchangers, not shown) and optionally catalyst  14 , an inlet  16  for receiving blanketing steam, an oxidant inlet  11 , and an oxidized residual oil outlet  22 . 
     Solvent deasphalting unit  18  includes a first separation vessel  20 , e.g., a primary settler, includes an inlet  24  in fluid communication with outlet  22  of the oxidizer column vessel  10 , an outlet  28  for discharging an asphalt phase, and an outlet  32  for discharging a deasphalted/desulfurized oil phase. A make-up solvent stream  26 , a recycled solvent stream  62  and a second separation vessel bottoms stream  78  are also charged to the first separation vessel  20  via an optional mixing vessel  25 . 
     Second separation vessel  30 , e.g., a secondary settler, includes an inlet  34  in fluid communication with deasphalted/desulfurized oil  32  of the first settler vessel  20 , an outlet  36  for discharging a deasphalted/desulfurized oil phase and an outlet  38  for discharging an asphalt phase. 
     Deasphalted/desulfurized oil separator  40  is typically a flash separator for solvent recovery and includes an inlet  42  in fluid communication with tops outlet  36  of the second separation vessel  30 , an outlet  46  for discharging deasphalted/desulfurized oil separator bottoms, and an outlet  44  for discharging recycled solvent. 
     Solvent steam stripping vessel  50  includes an inlet  48  in fluid communication with outlet  46  of the deasphalted/desulfurized oil separator  40 , an outlet  52  for discharging steam and excess solvent and an outlet  54  for discharging a deasphalted/desulfurized oil stream. 
     Outlet  54  is in fluid communication with a coking unit  90 , which in certain embodiments is a delayed coker unit including a coking furnace  91 , two or more parallel drums  92   a  and  92   b , and a coking product fractionator  95 . 
     Asphalt separation vessel  60  includes an inlet  64  in fluid communication with the asphalt phase outlet  28  of the first separation vessel  20 , an outlet  68  for discharging asphalt separation vessel bottoms, and an outlet  66  for discharging recycled solvent to recycle solvent vessel  80 . 
     Asphalt stripper vessel  70  includes an inlet  72  in fluid communication with bottoms outlet  68  of the asphalt separation vessel  60 , an outlet  76  for discharging solvent and an outlet  74  for discharging asphalt product. 
     Recycle solvent vessel  80  includes an inlet  56  in fluid communication with tops outlet  44  of the deasphalted/desulfurized oil separator  40  and a conduit  84  which is in fluid communication with outlet  66  of asphalt separation vessel  60 . Outlet  58  of recycle solvent vessel  80  is in fluid communication with conduit  62  for admixing with the feed. 
     A residual oil feedstock is introduced into inlet  12  of the oxidizer column vessel  10  after passage through one or more heat exchangers (not shown). In certain embodiments, a homogeneous catalyst can be introduced via conduit  14 . Blanketing steam is continuously injected into the oxidizer column vessel  10  via inlet  16 . Residual oil feedstock is oxidized and discharged via outlet  22 . In embodiments in which gaseous oxidant is used, after compression (for which the compressors are not shown) the gas is passed to a knockout drum (not shown) and is routed to distributors, e.g., above the bottom of the oxidizer column. 
     Gaseous oxidant that can be effectively used in the process includes air or oxygen or nitrous oxide or ozone. The oxygen to oil ratio is in the range 1-50 V:V %, preferably 3-20 V:V % or equivalent for other gaseous oxidants. The oxidizing unit operates at a temperature of 150-200° C. at the inlet and 250-300° C. in the oxidation zone, and at a pressure level ranging from ambient to 30 bars. 
     Asphalt oxidation serves to increase the molecular size of the asphaltene components by adding oxygen atoms to the heavy hydrocarbon molecules. This results in an asphalt product that is thicker and denser (60-70 mm penetration) than the vacuum column bottoms pitch feedstock (230-250 mm penetration). In the present process a feed such as an atmospheric residue is used to selectively oxidize the sulfur- and nitrogen-containing organic compounds to shift them to the asphalt phase. Accordingly, the primary objective of the integrated asphalt oxidation and solvent deasphalting unit is to produce desulfurized oil, and asphalt is produced as a by-product. 
     Oxidized residual oil feedstock from outlet  22  of the oxidizer column vessel  10  is mixed with make-up solvent  26  and recycled solvent  62 , e.g., via one or more in-line mixers (not-shown) or the optional mixing vessel  25 . 
     The asphalt oxidation reactor effluents are mixed with a C 3  to C 7 -paraffinic solvent, in certain embodiments a mixture of C 4 -normal and iso-butane, at a temperature and a pressure that are below the solvent&#39;s critical pressure and temperature, to thereby disturb the equilibrium of the asphaltenes in maltenes solution and to flocculate the solid asphaltenes particles. The critical temperatures and pressures for the paraffinic solvents are given in Table 5, and other solvent properties are given in Table 6. The admixing can occur in one or more mixing vessels and/or via one or more in-line mixers. 
     Optionally, adsorbents are used in the solvent deasphalting stage to selectively further separate the nitrogen, sulfur and poly-aromatic compounds, for instance, as described in U.S. Pat. No. 7,566,634 which is incorporated by reference herein. 
     The mixture is passed to inlet  24  of the first separation vessel  20 , e.g., a primary settler of a solvent deasphalting unit, in which it is phase separated into a deasphalted/desulfurized oil phase discharged via outlet  32  and an asphalt phase discharged via outlet  28 . The oxidized portion of the residual oil feedstock has a polarity that results in shifting to the asphalt phase due to its insoluble nature in the solvent. The pressure and temperature of the primary settler are at or below the critical properties of the solvent. The temperature of the primary settler is low in order to recover a majority of deasphalted/desulfurized oil from the oxidized residual oil charge. The solvent-soluble deasphalted/desulfurized oil phase which is collected from the primary settler, e.g., via a collector pipe, includes of a major proportion of solvent and deasphalted/desulfurized oil, and a minor proportion of asphalt. The solvent-insoluble asphalt phase which is recovered, e.g., via one or more asphalt collector pipes, includes a major proportion of asphalt, and a minor proportion of solvent, oil phase and oxidized organosulfur compounds (and in certain embodiments oxidized organonitrogen compounds). 
     Deasphalted/desulfurized oil is passed to inlet  34  of the second separation vessel  30 , e.g., a secondary settler of a solvent deasphalting unit, to be separated into a deasphalted/desulfurized oil phase discharged via outlet  36  (e.g., a vertical collector pipe) and an asphalt phase via outlet  38  (e.g., one or more asphalt collector pipes). The remaining asphalt mixture containing oxidized organosulfur compounds (and in certain embodiments oxidized organonitrogen compounds) is rejected as asphalt phase in the secondary settler vessel  30  due to increased temperature relative to the operating temperature of the primary settler. The secondary settler is typically operated at temperatures at or approaching the critical temperature of the solvent, and enables formation of an asphalt phase at the bottom which contains relatively minor amount of solvent and deasphalted oil which is recycled back to the primary settler vessel  20 . The deasphalted/desulfurized oil phase discharged via outlet  38  includes a major proportion of solvent and deasphalted/desulfurized oil and is recycled to the primary settler vessel  20  via conduit  78  for recovery of desulfurized oil. 
     The deasphalted/desulfurized oil phase from the second separation vessel outlet  36  is passed to inlet  42  of separator  40  to be separated into a deasphalted/desulfurized oil product stream  46  and solvent recycle stream  44 . Recycled solvent via outlet  44  is passed to recycle solvent vessel  80  and returned to the primary settler vessel  20 , e.g., via mixing vessel  90 . The deasphalted/desulfurized oil separator  40  is configured and dimensioned to permit a rapid and efficient flash separation. 
     Deasphalted/desulfurized oil product stream  46  including a major proportion of deasphalted/desulfurized oil and a minor proportion of solvent and steam is conveyed to inlet  48  of vessel  50  for steam stripping of the solvent, e.g., with 150 psig of dry steam. The deasphalted/desulfurized oil is recovered via outlet  54 , and a mixture of steam and excess solvent is discharged via outlet  52 . 
     The deasphalted/desulfurized oil stream from outlet  54  is charged to a coking unit  90 . In certain embodiments, coking unit  90  is a delayed coker unit, in which the deasphalted/desulfurized oil stream is charged to a coking furnace  91  where the contents are rapidly heated to a coking temperature in the range of 480° to 530° C. and then fed to a coking drum  92   a  or  92   b . Coking unit  90  can be configured with two or more parallel drums  92   a  and  92   b  and can be operated in a swing mode, such that when one of the drums is filled with coke, the deasphalted/desulfurized oil stream is transferred to the empty parallel drum and recover coke, in certain embodiments high quality petroleum green coke. Accordingly, an integrated and continuous or semi-continuous process is provided to produce asphalt, high quality petroleum green coke, and liquid and gas coking unit products. 
     Liquid and gas stream  94  from the coker drum  92   a  or  92   b  are fed to a coking product fractionator  95 . Any hydrocarbon vapors remaining in the coke drum are removed by steam injection. The coke is cooled with water and then removed from the coke drum using hydraulic and/or mechanical means. In certain embodiments according to the system and process herein, this recovered coke is fuel grade coke or anode grade coke. 
     Liquid and gas coking unit product stream  94  is introduced into a coking product stream fractionator  95 . The coking product stream  94  is fractionated to yield separate product streams that can include a light gas stream  96 , a coker naphtha stream  97 , a light coker gas oil stream  68  and a heavy coker gas oil stream  99 , each of which are recovered from the fractionator. 
     Advantageously, the integrated process facilities production of marketable coke since the feed thereto, the deasphalted/desulfurized oil stream, has desirable qualities. In particular, the deasphalted/desulfurized oil stream from outlet  54  in the present process is characterized by a sulfur content of generally less than about 15 wt %, in certain embodiments less than about 2.5 wt % and in further embodiments less than about 1 wt %, and a metals content of less than about 700 ppmw, in certain embodiments less than about 400 ppmw and in further embodiments less than about 100 ppmw. Use of this feedstream results in a high quality petroleum coke product that can be used as raw material to produce low sulfur marketable grades of coke including anode grade coke (sponge) and/or electrode grade coke (needle), in an efficient integrated process. 
     The primary settler asphalt phase via outlet  28  is passed to inlet  64  of the asphalt separation vessel  60  for flash separation into an asphalt phase discharged via outlet  68  and recycled solvent discharged via outlet  66 . The asphalt phase  68  including a major proportion of asphalt and a minor proportion of solvent is conveyed to inlet  72  of the asphalt stripper vessel  70  for steam stripping of the solvent, e.g., with 150 psig of dry steam. Solvent is recovered via outlet  76  (which can be recycled, not shown) and an asphalt product containing oxidized organosulfur compounds (and in certain embodiments oxidized organonitrogen compounds) is recovered via outlet  74 , which can be sent to an asphalt pool. 
     Coking is a carbon rejection process in which low-value atmospheric or vacuum distillation bottoms are converted to lighter products which in turn can be hydrotreated to produce transportation fuels, such as gasoline and diesel. Conventionally, coking of residuum from heavy high sulfur, or sour, crude oils is carried out primarily as a means of utilizing such low value hydrocarbon streams by converting part of the material to more valuable liquid and gas products. Typical coking processes include delayed coking and fluid coking. 
     In the delayed coking process, feedstock is typically introduced into a lower portion of a coking feed fractionator where one or more lighter materials are recovered as one or more top fractions, and bottoms are passed to a coking furnace. In the furnace bottoms from the fractionator and optionally heavy recycle material are mixed and rapidly heated in a coking furnace to a coking temperature, e.g., in the range of 480° C. to 530° C., and then fed to a coking drum. The hot mixed fresh and recycle feedstream is maintained in the coke drum at coking conditions of temperature and pressure where the feed decomposes or cracks to form coke and volatile components. 
     Table 8 provides delayed coker operating conditions for production of certain grades of petroleum green coke in the process herein: 
     
       
         
           
               
               
               
               
               
             
               
                 TABLE 8 
               
               
                   
               
               
                 Variable 
                 Unit 
                 Fuel Coke 
                 Sponge Coke 
                 Needle Coke 
               
               
                   
               
             
            
               
                 Temperature 
                 ° C. 
                 488-500 
                 496-510 
                 496-510 
               
               
                 Pressure 
                 Kg/cm 2   
                 1 
                 1.2-4.1 
                 3.4-6.2 
               
               
                 Recycle Ratio 
                 % 
                 0-5 
                  0-50 
                  60-120 
               
               
                 Coking time 
                 hours 
                  9-18 
                 24 
                 36 
               
               
                   
               
            
           
         
       
     
     The volatile components are recovered as vapor and transferred to a coking product fractionator. One or more heavy fractions of the coke drum vapors can be condensed, e.g., quenching or heat exchange, in certain embodiments the contact the coke drum vapors are contacted with heavy gas oil in the coking unit product fractionator, and heavy fractions form all or part of a recycle oil stream having condensed coking unit product vapors and heavy gas oil. In certain embodiments, heavy gas oil from the coking feed fractionator is added to the flash zone of the fractionator to condense the heaviest components from the coking unit product vapors. 
     Coking units are typically configured with two parallel drums and operated in a swing mode. When the coke drum is full of coke, the feed is switched to another drum, and the full drum is cooled. Liquid and gas streams from the coke drum are passed to a coking product fractionator for recovery. Any hydrocarbon vapors remaining in the coke drum are removed by steam injection. The coke remaining in the drum is typically cooled with water and then removed from the coke drum by conventional methods, e.g., using hydraulic and/or mechanical techniques to remove green coke from the drum walls for recovery. 
     Recovered petroleum green coke is suitable for production of marketable coke, and in particular anode (sponge) grade coke effective for use in the aluminum industry, or electrode (needle) grade coke effective for use in the steel industry. In the delayed coking production of high quality petroleum green coke, unconverted pitch and volatile combustible matter content of the green coke intermediate product subjected to calcination should be no more than about 15 percent by weight, and preferably in the range of 6 to 12 percent by weight. 
     In certain embodiments, one or more catalysts and additives can be added to the fresh feed and/or the fresh and recycle oil mixture prior to heating the feedstream in the coking unit furnace. The catalyst can promote cracking of the heavy hydrocarbon compounds and promote formation of the more valuable liquids that can be subjected to hydrotreating processes downstream to form transportation fuels. The catalyst and any additive(s) remain in the coking unit drum with the coke if they are solids, or are present on a solid carrier. If the catalyst(s) and/or additive(s) are soluble in the oil, they are carried with the vapors and remain in the liquid products. Note that in the production of high quality petroleum green coke, catalyst(s) and/or additive(s) which are soluble in the oil can be favored in certain embodiments to minimize contamination of the coke. 
     Recycled solvent from outlet  66  of the asphalt separation vessel  60  is passed to recycle solvent vessel  80  via conduit  84  along with recycled solvent  44  from second separation vessel  40 . Recycled solvent is conveyed via outlet  58  as needed for mixing with the oxidized residual oil feedstock from outlet  22 , e.g., in mixing vessel  90  and/or in one or more in-line mixers. One or more intermediate solvent drums can be incorporated as required. 
     In the primary settler  20 , the deasphalted oil phase includes a majority of solvent and the deasphalted oil with a minor amount of asphalt discharged from the top of the primary settler (outlet  32 ). The asphalt phase which contains 40-50 liquid V % solvent leaves the bottom of the vessel (outlet  28 ). In the secondary settler  30 , the deasphalted oil phase from the primary settler  20  which contains some asphalt enters the vessel. The rejected asphalt from the secondary settler contains a relatively small amount of solvent and deasphalted oil. In the deasphalted/desulfurized oil separator  40 , greater than 90 W % of the solvent charged to the settler enter the deasphalted/desulfurized oil separator where more than 95 W % of that is recovered. Deasphalted/desulfurized oil from the deasphalted/desulfurized oil separator, which contains trace amount of solvent enters the deasphalted oil stripper  50 . Essentially all solvent is removed from the deasphalted oil by steam stripping. The asphalt separator  60  permits flash separation of the asphalt and the solvent. The asphalt phase contains 40-50 V % of solvent. Asphalt from the asphalt separator enters the asphalt stripper  70 , where the residual solvent is removed from the asphalt by steam stripping. Approximately 95 W % of circulating solvent which is recovered in high pressure system and the balance of circulating solvent which is recovered in the low pressure system join together and enter the high pressure solvent drum  80 . 
     The feedstock is generally atmospheric residue boiling above 370° C. In certain embodiments the feedstock can be whole crude oil with one or more separation steps upstream of the initial feed  12 . A feedstock can be derived from one or more naturally occurring sources such as crude oils, bitumens, heavy oils, or shale oils, and/or bottoms from one or more refinery process units including hydrotreating, hydroprocessing, fluid catalytic cracking, coking, and visbreaking or coal liquefaction. 
     In one or more embodiments, a second feed can optionally be introduced with the mixture at inlet  24 . In one or more embodiments, certain intermediate oil or asphalt streams can be recycled to the oxidizing unit  10 . 
     Advantageously, by integrating asphalt oxidation, solvent deasphalting and delayed coking, atmospheric residual oil or vacuum residual oil is desulfurized with existing units to obtain asphalt, high quality petroleum green coke effective as raw material to produce marketable coke, and liquid and gas coker products at lower cost than conventional high-pressure desulfurization process. For instance, atmospheric residue can be desulfurized so that, in certain embodiments, 40 W % of desulfurized oil is recovered, with the remaining portion passing into the asphalt phase, which is also valuable product. This 40 W % of desulfurized oil can then advantageously be used to produce gas and liquid coker products, and marketable coke. 
     Sulfur molecules contained in heavy petroleum fractions, including organosulfur molecules, and in certain embodiments organonitrogen molecules in heavy petroleum fractions are oxidized. The polar oxidized sulfur compounds shift from the oil phase to the asphalt phase. Advantageously, the present process and system can be integrated with existing solvent deasphalting units to remove impurities at comparatively lower cost, and with existing coking units to process the desulfurized oil to produce marketable coke and coker gas and liquid products. 
     While individual and discrete asphalt oxidation, solvent deasphalting and coking processes are well developed, it has not previously been suggested to integrate these processes to desulfurize atmospheric residual oil feedstock by oxidation and purify the oxidized feedstocks by solvent deasphalting process to produce desulfurized oil and asphalt products, and further integrate a coking unit, such as a delayed coking unit, to produce high quality petroleum green coke, and liquid and gas coking unit products. 
     Example 1 
     An atmospheric residue from Arab Light crude oil referenced with initial and final boiling points of 154° C. and 739° C. respectively was desulfurized in a oxidation vessel. The properties of feedstock oil are shown in Table 9. 
     In the oxidation reactions, polyoxoanions obtained by combining sodium tungsten Na 2 WO 4 , 2H 2 O with acetic acid are used as a catalytic system. A 30% H 2 O 2 /H 2 O solution is used as an oxidizing agent. The amount of the H 2 O 2  solution was selected so that the molar ratio of H 2 O 2  to s is about 5. The oxidation reactions were carried out in is glass reactor stirred with a magnetic stirrer plate at 70° C. and 1 atm for 1.5 hour were done separately. After that the reaction medium is cooled down to room temperature. The properties, after separation of aqueous phase are given in Table 10. 
     
       
         
           
               
               
               
             
               
                 TABLE 9 
               
               
                   
               
             
            
               
                   
                 Property 
                 Atmospheric Residue 
               
               
                   
               
               
                   
                 Sulfur, W % 
                 3.34  
               
               
                   
                 Nitrogen, ppmw 
                 3.34  
               
               
                   
                 Density, Kg/Lt 
                 0.9642 
               
               
                   
               
               
                   
                 Distillation, 
                   
               
               
                   
                 ASTM D2887 
                 ° C. 
               
               
                   
               
               
                   
                 IBP 
                 154 
               
               
                   
                  5 W % 
                 282 
               
               
                   
                 10 W % 
                 328 
               
               
                   
                 20 W % 
                 372 
               
               
                   
                 30 W % 
                 408 
               
               
                   
                 40 W % 
                 444 
               
               
                   
                 50 W % 
                 482 
               
               
                   
                 70 W % 
                 567 
               
               
                   
                 90 W % 
                 672 
               
               
                   
                 95 W % 
                 708 
               
               
                   
                 FBP 
                 739 
               
               
                   
               
            
           
         
       
     
     In two separate experiments, atmospheric residue and oxidized atmospheric residue feedstocks were sent to solvent deasphalting unit to separate the asphalt and deasphalted oil. Table 10 summarizes the yields and sulfur content of the fractions of the atmospheric residues. The sulfur content of the deasphalted oil is reduced from 1.98 W to 1.2 W % but at a cost of yield, about 7.5 W % 
     
       
         
           
               
               
               
               
               
             
               
                 TABLE 10 
               
             
            
               
                   
               
               
                   
                 Before Oxidation 
                   
                 After Oxidation 
                   
               
            
           
           
               
               
               
               
               
            
               
                   
                 W % 
                 S, W % 
                 W % 
                 S, W % 
               
               
                   
               
            
           
           
               
               
               
               
               
               
            
               
                   
                 DAO 
                 67.9 
                 1.2 
                 60.6 
                 1.2 
               
               
                   
                 Asphalt 
                 32.1 
                 6.3 
                 39.4 
                 6.7 
               
               
                   
                 Total 
                 100.1 
                 3.4 
                 100 
                 3.4 
               
               
                   
               
            
           
         
       
     
     The desulfurized deasphalted oil is then sent to a delayed coking unit to produce high quality petroleum green coke. The process produced 14.3 W % petroleum green coke containing 2.5 W % sulfur, within the acceptable limits for use as raw material to produce anode grade (calcined sponge) coke, as set forth in Table 5 herein. Detailed delayed coking product yields are given in Table 11. 
     
       
         
           
               
               
               
             
               
                 TABLE 11 
               
               
                   
               
               
                   
                 Product 
                 Yield, W % 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
            
               
                   
                 Coke 
                 14.3 
               
               
                   
                 Gas 
                 9.1 
               
               
                   
                 Naphtha 
                 14.4 
               
               
                   
                 Gas Oil 
                 36.0 
               
               
                   
                 Heavy Gas Oil 
                 26.2 
               
               
                   
                   
                 100.0 
               
               
                   
               
            
           
         
       
     
     Example 2 
     Petroleum green coke recovered from a delayed coker unit is subjected to calcination. In particular, samples of about 3 kg of Petroleum green coke were calcined according to the following heat-up program: Room Temperature to 200° C. at 200° C./h heating rate; 200° C. to 800° C. at 30° C./h heating rate; 800° C. to 1100° C. at 50° C./h heating rate; Soaking Time at 1,100° C.: 20 h. 
     Table 12 shows the properties of the samples of petroleum green coke and Table 13 shows the properties of the calcium samples. 
     
       
         
           
               
               
               
               
               
               
             
               
                 TABLE 12 
               
               
                   
               
               
                   
                   
                   
                   
                 Sam- 
                 Sam- 
               
               
                 Property 
                 Method 
                 Unit 
                 Range 
                 ple 1 
                 ple 2 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
            
               
                 Water Content 
                 ISO 11412 
                 % 
                 6.0-15.0 
                 0.0 
                 0.0 
               
               
                 Volatile Matter 
                 ISO 9406 
                 % 
                 8.0-12.0 
                 4.8 
                 5.9 
               
               
                 Hardgrove 
                 ISO 5074 
                 — 
                 60-100 
                 41 
                 50 
               
               
                 Grindability 
                   
                   
                   
                   
                   
               
               
                 Index 
                   
                   
                   
                   
                   
               
               
                 Sieving Analysis 
                 ISO 12984 
                 % 
                   
                   
                   
               
               
                 &gt;32 mm  
                   
                   
                 10.0-20.0  
                 0.0 
                 0.0 
               
               
                 &gt;16 mm  
                   
                   
                 20.0-40.0  
                 0.0 
                 0.0 
               
               
                 16-8 mm  
                   
                   
                 10.0-20.0  
                 37.1 
                 17.2 
               
               
                 8-4 mm 
                   
                   
                 10.0-20.0  
                 23.5 
                 18.2 
               
               
                 4-2 mm 
                   
                   
                 10.0-20.0  
                 15.2 
                 14.4 
               
               
                 2-1 mm 
                   
                   
                 10.0-20.0  
                 11.9 
                 16.1 
               
               
                 1-0.5 mm     
                   
                   
                 5.0-15.0 
                 7.0 
                 12.2 
               
               
                 0.50-0.25 mm     
                   
                   
                 5.0-15.0 
                 3.6 
                 8.5 
               
               
                 &lt;0.25 mm  
                   
                   
                 5.0-15.0 
                 1.7 
                 13.3 
               
               
                 XRF Analysis 
                 ISO 12980 
                 %/ppm 
                   
                   
                   
               
               
                 S 
                   
                   
                 0.50-4.00  
                 3.40 
                 3.36 
               
               
                 V 
                   
                   
                 50-350 
                 83 
                 76 
               
               
                 Ni 
                   
                   
                 50-220 
                 80 
                 77 
               
               
                 Si 
                   
                   
                 20-250 
                 71 
                 45 
               
               
                 Fe 
                   
                   
                 50-400 
                 92 
                 154 
               
               
                 Al 
                   
                   
                 50-250 
                 71 
                 45 
               
               
                 Na 
                   
                   
                 20-120 
                 44 
                 27 
               
               
                 Ca 
                   
                   
                 20-120 
                 18 
                 13 
               
               
                 P 
                   
                   
                 1-20 
                 2 
                 1 
               
               
                 K 
                   
                   
                 5-15 
                 0 
                 0 
               
               
                 Mg 
                   
                   
                 10-30  
                 13 
                 11 
               
               
                 Pb 
                   
                   
                 1-5  
                 0 
                 0 
               
               
                 Ash Content 
                 ISO 8005 
                 % 
                 0.10-0.30  
                 0.08 
                 0.08 
               
               
                   
               
            
           
         
       
     
     
       
         
           
               
               
               
               
               
               
             
               
                 TABLE 13 
               
               
                   
               
               
                   
                   
                   
                   
                 Sam- 
                 Sam- 
               
               
                 Property 
                 Method 
                 Unit 
                 Range 
                 ple 1 
                 ple 2 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
            
               
                 Water Content 
                 ISO 11412 
                 % 
                 0.0-0.2 
                 0.0 
                 0.0 
               
               
                 Volatile Matter 
                 ISO 9406 
                 % 
                 0.0-0.5 
                 0.3 
                 0.5 
               
               
                 Hardgrove 
                 ISO 5074 
                 — 
                 — 
                 41 
                 49 
               
               
                 Grindability 
                   
                   
                   
                   
                   
               
               
                 Index 
                   
                   
                   
                   
                   
               
               
                 Sieving Analysis 
                 ISO 12984 
                 % 
                   
                   
                   
               
            
           
           
               
               
               
               
               
               
               
            
               
                 &gt;32 
                 mm 
                   
                   
                 0.0-5.0 
                 0.0 
                 0.0 
               
               
                 &gt;16 
                 mm 
                   
                   
                  0.0-15.0 
                 0.0 
                 0.0 
               
               
                 16-8 
                 mm 
                   
                   
                 10.0-20.0 
                 27.4 
                 11.9 
               
               
                 8-4 
                 mm 
                   
                   
                 10.0-20.0 
                 31.4 
                 19.7 
               
               
                 4-2 
                 mm 
                   
                   
                 15.0-25.0 
                 14.5 
                 13.4 
               
               
                 2-1 
                 mm 
                   
                   
                 10.0-20.0 
                 12.2 
                 16.8 
               
               
                 1-0.5 
                 mm 
                   
                   
                  5.0-15.0 
                 7.7 
                 14.1 
               
               
                 0.50-0.25 
                 mm 
                   
                   
                  5.0-15.0 
                 4.4 
                 9.9 
               
               
                 &lt;0.25 
                 mm 
                   
                   
                  5.0-10.0 
                 2.5 
                 14.1 
               
            
           
           
               
               
               
               
               
               
            
               
                 XRF Analysis 
                 ISO 12980 
                 %/ppm 
                   
                   
                   
               
               
                 S 
                   
                   
                 0.50-3.50 
                 3.13 
                 3.01 
               
               
                 V 
                   
                   
                  50-400 
                 89 
                 84 
               
               
                 Ni 
                   
                   
                  50-250 
                 98 
                 89 
               
               
                 Si 
                   
                   
                  50-300 
                 8 
                 19 
               
               
                 Fe 
                   
                   
                  50-450 
                 165 
                 189 
               
               
                 Al 
                   
                   
                  50-250 
                 10 
                 11 
               
               
                 Na 
                   
                   
                  30-140 
                 18 
                 16 
               
               
                 Ca 
                   
                   
                  30-140 
                 9 
                 7 
               
               
                 P 
                   
                   
                  1-20 
                 1 
                 2 
               
               
                 K 
                   
                   
                  5-15 
                 0 
                 0 
               
               
                 Mg 
                   
                   
                 10-30 
                 5 
                 18 
               
               
                 Pb 
                   
                   
                 1-5 
                 0 
                 0 
               
               
                 Ash Content 
                 ISO 8005 
                 % 
                 0.10-0.30 
                 0.04 
                 0.07 
               
               
                 Pulverizing 
                 M168 
                 — 
                 1.05-1.25 
                 1.15 
                 1.41 
               
               
                 Factor 
                   
                   
                   
                   
                   
               
               
                 Real Density in 
                 ISO 8004 
                 kg/dm 3   
                 2.05-2.10 
                 2.102 
                 2.092 
               
               
                 Xylene 
                   
                   
                   
                   
                   
               
               
                 Crystallite Size 
                 ISO 20203 
                 Å 
                 25.0-32.0 
                 29.6 
                 28.2 
               
               
                 Lc 
                   
                   
                   
                   
                   
               
               
                 Resiflex 
                 ISO 10143 
                 μΩm 
                 460-540 
                 397 
                 400 
               
               
                 Specific Electri- 
                   
                 kg/dm 3   
                 0.85-0.92 
                 0.92 
                 0.94 
               
               
                 cal Resistance 
                   
                   
                   
                   
                   
               
               
                 Pressed Density 
                   
                   
                   
                   
                   
               
               
                 (1.4-1.0 mm) 
                   
                   
                   
                   
                   
               
               
                 Air Reactivity 
                 ISO 12982-1 
                 %/min 
                 0.05-0.30 
                 0.06 
                 0.07 
               
               
                 525° C. 
                   
                   
                   
                   
                   
               
               
                 CO2 Reactivity 
                 ISO 12981-1 
                 % 
                  3.0-15.0 
                 1.6 
                 1.9 
               
               
                   
               
            
           
         
       
     
     The method and system of the present invention, have been described above and in the attached drawing; however, modifications will be apparent to those of ordinary skill in the art and the scope of protection for the invention is to be defined by the claims that follow.