Patent Grant
11912945
There are two basic marine fuel types: distillate based marine fuel, also known as Marine Gas Oil (MGO) or Marine Diesel Oil (MDO); and residual based marine fuel, also known as heavy marine fuel oil (HMFO). Distillate based marine fuel both MGO and MDO, comprises petroleum middle distillate fractions separated from crude oil in a refinery via a distillation process. Gasoil (also known as medium diesel) is a petroleum middle distillate in boiling range and viscosity between kerosene (light distillate) and lubricating oil (heavy distillate) containing a mixture of C10 to C19 hydrocarbons. Gasoil (a heavy distillate) is used to heat homes and is used blending with lighter middle distillates as a fuel for heavy equipment such as cranes, bulldozers, generators, bobcats, tractors and combine harvesters. Generally maximizing middle distillate recovery from heavy distillates mixed with petroleum residues is the most economic use of these materials by refiners because they can crack gas oils into valuable gasoline and distillates in a fluid catalytic cracking (FCC) unit. Diesel oils for road use are very similar to gas oils with road use diesel containing predominantly contain a middle distillate mixture of C10 through C19 hydrocarbons, which include approximately 64% aliphatic hydrocarbons, 1-2% olefinic hydrocarbons, and 35% aromatic hydrocarbons. Distillate based marine fuels (MDO and MGO) are essentially road diesel or gas oil fractions blended with up to 15% residual process streams, and optionally up to 5% volume of polycyclic aromatic hydrocarbons (asphaltenes). The residual and asphaltene materials are blended into the middle distillate to form MDO and MGO as a way to both swell volume and productively use these low value materials.
Asphaltenes are large and complex polycyclic hydrocarbons with a propensity to form complex and waxy precipitates, especially in the presence of aliphatic (paraffinic) hydrocarbons that are the primary component of Marine Diesel. Once asphaltenes have precipitated out, they are notoriously difficult to re-dissolve and are described as fuel tank sludge in the marine shipping industry and marine bunker fueling industry. One of skill in the art will appreciate that mixing Marine Diesel with asphaltenes and process residues is limited by the compatibility of the materials and formation of asphaltene precipitates and the minimum Cetane number required for such fuels.
Residual based fuels or Heavy Marine Fuel Oil (HMFO) are used by large ocean-going ships as fuel for large two stroke diesel engines for over 50 years. HMFO is a blend of the residues generated throughout the crude oil refinery process. Typical refinery streams combined to from HMFO may include, but are not limited to: atmospheric tower bottoms (i.e. atmospheric residues), vacuum tower bottoms (i.e. vacuum residues) visbreaker residue, FCC Light Cycle Oil (LCO), FCC Heavy Cycle Oil (HCO) also known as FCC bottoms, FCC Slurry Oil, heavy gas oils and delayed cracker oil (DCO), deasphalted oils (DAO); heavy aromatic residues and mixtures of polycyclic aromatic hydrocarbons, reclaimed land transport motor oils; pyrolysis oils and tars; aspahltene solids and tars; and minor portions (often less than 20% vol.) of middle distillate materials such as cutter oil, kerosene or diesel to achieve a desired viscosity. HMFO has a higher aromatic content (especially polynuclear aromatics and asphaltenes) than the marine distillate fuels noted above. The HMFO component mixture varies widely depending upon the crude slate (i.e. source of crude oil) processed by a refinery and the processes utilized within that refinery to extract the most value out of a barrel of crude oil. The HMFO is generally characterized as being highly viscous, high in sulfur and metal content (up to 5 wt %), and high in asphaltenes making HMFO the one product of the refining process that has historically had a per barrel value less than feedstock crude oil.
Industry statistics indicate that about 90% of the HMFO sold contains 3.5 weight % sulfur. With an estimated total worldwide consumption of HMFO of approximately 300 million tons per year, the annual production of sulfur dioxide by the shipping industry is estimated to be over 21 million tons per year. Emissions from HMFO burning in ships contribute significantly to both global marine air pollution and local marine air pollution levels.
The International Convention for the Prevention of Pollution from Ships, also known as the MARPOL convention or just MARPOL, as administered by the International Maritime Organization (IMO) was enacted to prevent marine pollution (i.e. marpol) from ships. In 1997, a new annex was added to the MARPOL convention; the Regulations for the Prevention of Air Pollution from Ships—Annex VI to minimize airborne emissions from ships (SOx, NOx, ODS, VOC) and their contribution to global air pollution. A revised Annex VI with tightened emissions limits was adopted in October 2008 and effective 1 Jul. 2010 (hereafter called Annex VI (revised) or simply Annex VI).
MARPOL Annex VI (revised) adopted in 2008 established a set of stringent air emissions limits for all vessel and more specifically designated Emission Control Areas (ECAs). The ECAs under MARPOL Annex VI are: i) Baltic Sea area—as defined in Annex I of MARPOL—SOx, only; ii) North Sea area—as defined in Annex V of MARPOL—SOx, only; iii) North American—as defined in Appendix VII of Annex VI of MARPOL—SOx, NOx, and PM; and, iv) United States Caribbean Sea area—as defined in Appendix VII of Annex VI of MARPOL—SOx, NOx and PM.
Annex VI (revised) was codified in the United States by the Act to Prevent Pollution from Ships (APPS). Under the authority of APPS, the U.S. Environmental Protection Agency (the EPA), in consultation with the United States Coast Guard (USCG), promulgated regulations which incorporate by reference the full text of Annex VI. See 40 C.F.R. § 1043.100(a)(1). On Aug. 1, 2012 the maximum sulfur content of all marine fuel oils used onboard ships operating in US waters/ECA was reduced from 3.5% wt. to 1.00% wt. (10,000 ppm) and on Jan. 1, 2015 the maximum sulfur content of all marine fuel oils used in the North American ECA was lowered to 0.10% wt. (1,000 ppm). At the time of implementation, the United States government indicated that vessel operators must vigorously prepare to comply with the 0.10% wt. (1,000 ppm) US ECA marine fuel oil sulfur standard. To encourage compliance, the EPA and USCG refused to consider the cost of compliant low sulfur fuel oil to be a valid basis for claiming that compliant fuel oil was not available for purchase. For over five years there has been a very strong economic incentive to meet the marine industry demands for low sulfur HMFO, however technically viable solutions have not been realized and a premium price has been commanded by refiners to supply a low sulfur HMFO compliant with Annex VI sulfur emissions requirements in the ECA areas.
Since enactment in 2010, the global sulfur cap for HMFO outside of the ECA areas was set by Annex VI at 3.50% wt. effective 1 Jan. 2012; with a further reduction to 0.50% wt, effective 1 Jan. 2020. The global cap on sulfur content in HMFO has been the subject of much discussion in both the marine shipping and marine fuel bunkering industry. There has been and continues to be a very strong economic incentive to meet the international marine industry demands for low sulfur HMFO (i.e. HMFO with a sulfur content less than 0.50 wt. %. Notwithstanding this global demand, solutions for transforming high sulfur HMFO into low sulfur HMFO have not been realized or brought to market. There is an on-going and urgent demand for processes and methods for making a low sulfur HMFO compliant with MARPOL Annex VI emissions requirements.
Replacement of heavy marine fuel oil with marine gas oil or marine diesel: One primary solution to the demand for low sulfur HMFO to simply replace high sulfur HMFO with marine gas oil (MGO) or marine diesel (MDO). The first major difficulty is the constraint in global supply of middle distillate materials that make up 85-90% vol of MGO and MDO. It is reported that the effective spare capacity to produce MGO is less than 100 million metric tons per year resulting in an annual shortfall in marine fuel of over 200 million metric tons per year. Refiners not only lack the capacity to increase the production of MGO, but they have no economic motivation because higher value and higher margins can be obtained from using middle distillate fractions for low sulfur diesel fuel for land-based transportation systems (i.e. trucks, trains, mass transit systems, heavy construction equipment, etc.).
Processing of residual oils. For the past several decades, the focus of refining industry research efforts related to the processing of heavy oils (crude oils, distressed oils, or residual oils) has been on upgrading the properties of these low value refinery process oils to create middle distillate and lighter oils with greater value. The challenge has been that crude oil, distressed oil and residues contain high levels of sulfur, nitrogen, phosphorous, metals (especially vanadium and nickel); asphaltenes and thus exhibit a propensity to form carbon or coke on the catalyst. The sulfur and nitrogen molecules are highly refractory and aromatically stable and thus difficult and expensive to crack or remove. Vanadium and nickel porphyrins and other metal organic compounds are responsible for catalyst contamination and corrosion problems in the refinery. The sulfur, nitrogen, and phosphorous, must be removed because they are well-known poisons for the precious metal (platinum and palladium) catalysts utilized in the processes downstream of the atmospheric or vacuum distillation towers.
The difficulties treating atmospheric or vacuum residual streams has been known for many years and has been the subject of considerable research and investigation. Numerous residue-oil conversion processes have been developed in which the goals are same: 1) create a more valuable, preferably middle distillate range hydrocarbons; and 2) concentrate the contaminates such as sulfur, nitrogen, phosphorous, metals and asphaltenes into a form (coke, heavy coker residue, FCC slurry oil) for removal from the refinery stream. Well known and accepted practice in the refining industry is to increase the reaction severity (elevated temperature and pressure) to produce hydrocarbon products that are lighter and more purified, increase catalyst life times and remove sulfur, nitrogen, phosphorous, metals and asphaltenes from the refinery stream.
In summary, since the announcement of the MARPOL Annex VI standards reducing the global levels of sulfur in HMFO, refiners of crude oil have had modest success in their technical efforts to re-purpose high sulfur HMFO. With demand for high sulfur HMFO decreasing and the use of low sulfur alternatives in the marine industry, there exists a long standing and unmet need for processes and devices that transform high sulfur HMFO for use as a feedstock to other subsequent refinery processes.
It is a general objective to transform high sulfur a Heavy Marine Fuel Oil (HMFO) in a multi stage process that minimizes the changes in the desirable feed properties of the HMFO and minimizes the production of by-product hydrocarbons (i.e. light hydrocarbons having C1-C4 and wild naphtha (C5-C20)).
A first aspect and illustrative embodiment encompasses a multi-stage process for treating high sulfur Heavy Marine Fuel Oil for use as feedstock in a subsequent refinery unit, the process involving: mixing a quantity of the Feedstock Heavy Marine Fuel Oil with a quantity of Activating Gas mixture to give a Feedstock Mixture; contacting the Feedstock Mixture with one or more catalysts under reactive conditions to form a Process Mixture from the Feedstock Mixture; receiving the Process Mixture and separating the Product Heavy Marine Fuel Oil liquid components of the Process Mixture from the gaseous components and by-product hydrocarbon components of the Process Mixture and, discharging the Product Heavy Marine Fuel Oil.
A second aspect and illustrative embodiment encompasses a device or plant for treating high sulfur Heavy Marine Fuel Oil and producing a Product HMFO for use as feedstock in a subsequent refinery unit. The illustrative devices embody the above illustrative core processes on a commercial scale.
A third aspect and illustrative embodiment encompasses a feedstock Heavy Marine Fuel Oil composition resulting from the above illustrative processes and devices.
The inventive concepts as described herein utilize terms that should be well known to one of skill in the art, however certain terms are utilized having a specific intended meaning and these terms are defined below:
Heavy Marine Fuel Oil (HMFO) is a petroleum product fuel compliant with the ISO 8217 (2017) standards for residual marine fuels except for the concentration levels of the Environmental Contaminates.
Environmental Contaminates are organic and inorganic components of HMFO that result in the formation of SOx, NOx and particulate materials upon combustion.
Feedstock HMFO is a petroleum product fuel compliant with the ISO 8217 (2017) standards for the physical properties or characteristics of a merchantable HMFO except for the concentration of Environmental Contaminates, more specifically the Feedstock HMFO has a sulfur content greater than the global MARPOL Annex VI standard of 0.5% wt. sulfur, and preferably and has a sulfur content (ISO 14596 or ISO 8754) between the range of 5.0% wt. to 1.0% wt.
Product HMFO is a petroleum product fuel that has a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05% wt. to 1.0% wt. and is suitable for use as a feedstock in subsequent refinery process such Coking or Fluid Catalytic Cracking.
Activating Gas: is a mixture of gases utilized in the process combined with the catalyst to remove the environmental contaminates from the Feedstock HMFO.
Fluid communication: is the capability to transfer fluids (either liquid, gas or combinations thereof, which might have suspended solids) from a first vessel or location to a second vessel or location, this may encompass connections made by pipes (also called a line), spools, valves, intermediate holding tanks or surge tanks (also called a drum).
Merchantable quality: is a level of quality for a residual marine fuel oil so the fuel is fit for the ordinary purpose it should serve (i.e. serve as a residual fuel source for a marine ship) and can be commercially sold as and is fungible and compatible with other heavy or residual marine bunker fuels.
Bbl or bbl: is a standard volumetric measure for oil; 1 bbl=0.1589873 m3; or 1 bbl=158.9873 liters; or 1 bbl=42.00 US liquid gallons.
Bpd or bpd: is an abbreviation for Bbl per day.
SCF: is an abbreviation for standard cubic foot of a gas; a standard cubic foot (at 14.73 psi and 60° F.) equals 0.0283058557 standard cubic meters (at 101.325 kPa and 15° C.).
Bulk Properties: are broadly defined as the physical properties or characteristics of a merchantable HMFO as required by ISO 8217 (2017); and more specifically the measurements include: kinematic viscosity at 50° C. as determined by ISO 3104; density at 15° C. as determined by ISO 3675; CCAI value as determined by ISO 8217, ANNEX B; flash point as determined by ISO 2719; total sediment—aged as determined by ISO 10307-2; carbon residue—micro method as determined by ISO 10370; and preferably aluminum plus silicon content as determined by ISO 10478.
The inventive concepts are illustrated in more detail in this description referring to the drawings, in which
As for the properties of the Activating Gas, the Activating Gas should be selected from mixtures of nitrogen, hydrogen, carbon dioxide, gaseous water, and methane. The mixture of gases within the Activating Gas should have an ideal gas partial pressure of hydrogen (pH2) greater than 80% of the total pressure of the Activating Gas mixture (P) and more preferably wherein the Activating Gas has an ideal gas partial pressure of hydrogen (pH2) greater than 95% of the total pressure of the Activating Gas mixture (P). It will be appreciated by one of skill in the art that the molar content of the Activating Gas is another criterion the Activating Gas should have a hydrogen mole fraction in the range between 80% and 100% of the total moles of Activating Gas mixture.
The Feedstock Mixture (i.e. mixture of Feedstock HMFO and Activating Gas) is brought up to the process conditions of temperature and pressure and introduced into a Reactor System, preferably a reactor vessel, so the Feedstock Mixture is then contacted under reactive conditions with one or more catalysts (8) to form a Process Mixture from the Feedstock Mixture.
The core process conditions are selected so the ratio of the quantity of the Activating Gas to the quantity of Feedstock HMFO is 250 scf gas/bbl of Feedstock HMFO to 10,000 scf gas/bbl of Feedstock HMFO; and preferably between 2000 scf gas/bbl of Feedstock HMFO 1 to 5000 scf gas/bbl of Feedstock HMFO more preferably between 2500 scf gas/bbl of Feedstock HMFO to 4500 scf gas/bbl of Feedstock HMFO. The process conditions are selected so the total pressure in the first vessel is between of 250 psig and 3000 psig; preferably between 1000 psig and 2500 psig, and more preferably between 1500 psig and 2200 psig. The process reactive conditions are selected so the indicated temperature within the first vessel is between of 500° F. to 900° F., preferably between 650° F. and 850° F. and more preferably between 680° F. and 800° F. The process conditions are selected so the liquid hourly space velocity within the first vessel is between 0.05 oil/hour/m3 catalyst and 1.0 oil/hour/m3 catalyst; preferably between 0.08 oil/hour/m3 catalyst and 0.5 oil/hour/m3 catalyst; and more preferably between 0.1 oil/hour/m3 catalyst and 0.3 oil/hour/m3 catalyst to achieve deep desulfurization with product sulfur levels below 0.1 ppmw.
One of skill in the art will appreciate that the core process reactive conditions are determined considering the hydraulic capacity of the unit. Exemplary hydraulic capacity for the treatment unit may be between 100 bbl of Feedstock HMFO/day and 100,000 bbl of Feedstock HMFO/day, preferably between 1000 bbl of Feedstock HMFO/day and 60,000 bbl of Feedstock HMFO/day, more preferably between 5,000 bbl of Feedstock HMFO/day and 45,000 bbl of Feedstock HMFO/day, and even more preferably between 10,000 bbl of Feedstock HMFO/day and 30,000 bbl of Feedstock HMFO/day.
One of skill in the art will appreciate that a fixed bed reactor using a supported transition metal heterogeneous catalyst will be the technically easiest to implement and is preferred. However, alternative reactor types may be utilized including, but not limited to: ebullated or fluidized bed reactors; structured bed reactors; three-phase bubble reactors; reactive distillation bed reactors and the like all of which may be co-current or counter current. It is also contemplated that high flux or liquid full type reactors may be used such as those disclosed in U.S. Pat. Nos. 6,123,835; 6,428,686; 6,881,326; 7,291,257; 7,569,136 and other similar and related patents and patent applications.
The transition metal heterogeneous catalyst utilized comprises a porous inorganic oxide catalyst carrier and a transition metal catalytic metal. The porous inorganic oxide catalyst carrier is at least one carrier selected from the group consisting of alumina, alumina/boria carrier, a carrier containing metal-containing aluminosilicate, alumina/phosphorus carrier, alumina/alkaline earth metal compound carrier, alumina/titania carrier and alumina/zirconia carrier. The transition metal catalytic metal component of the catalyst is one or more metals selected from the group consisting of group 6, 8, 9 and 10 of the Periodic Table. In a preferred and illustrative embodiment, the transition metal heterogeneous catalyst is a porous inorganic oxide catalyst carrier and a transition metal catalyst, in which the preferred porous inorganic oxide catalyst carrier is alumina and the preferred transition metal catalyst is Ni—Mo, Co—Mo, Ni—W or Ni—Co—Mo. The process by which the transition metal heterogeneous catalyst is manufactured is known in the literature and preferably the catalysts are commercially available as hydrodemetallization catalysts, transition catalysts, desulfurization catalyst and combinations of these which might be pre-sulfided.
The Process Mixture (10) in this core process is removed from the Reactor System (8) and from being in contact with the one or more catalyst and is sent via fluid communication to a second vessel (12), preferably a gas-liquid separator or hot separators and cold separators, for separating the liquid components (14) of the Process Mixture from the bulk gaseous components (16) of the Process Mixture. The gaseous components (16) are treated beyond the battery limits of the immediate process. Such gaseous components may include a mixture of Activating Gas components and lighter hydrocarbons (mostly methane, ethane and propane but some wild naphtha) that may have been formed as part of the by-product hydrocarbons from the process.
The Liquid Components (16) in this core process are sent via fluid communication to a third vessel (18), preferably a fuel oil product stripper system, for separating any residual gaseous components (20) and by-product hydrocarbon components (22) from the Product HMFO (24). The residual gaseous components (20) may be a mixture of gases selected from the group consisting of: nitrogen, hydrogen, carbon dioxide, hydrogen sulfide, gaseous water, C1-C3 hydrocarbons. This residual gas is treated outside of the battery limits of the immediate process, combined with other gaseous components (16) removed from the Process Mixture (10) in the second vessel (12). The liquid by-product hydrocarbon component, which are condensable hydrocarbons formed in the process (22) may be a mixture selected from the group consisting of C4-C20 hydrocarbons (wild naphtha) (naphtha—diesel) and other condensable light liquid (C4-C8) hydrocarbons that can be utilized as part of the motor fuel blending pool or sold as gasoline and diesel blending components on the open market. It is also contemplated that a second draw (not shown) may be included to withdraw a distillate product, preferably a middle to heavy distillate. These liquid by-product hydrocarbons should be less than 15% wt., preferably less than 5% wt. and more preferably less than 3% wt. of the overall process mass balance.
The Product HMFO (24) resulting from the core process is discharged via fluid communication into storage tanks or for use beyond the battery limits of the immediate core process. The Product HMFO complies with ISO 8217 (2017) and has a maximum sulfur content (ISO 14596 or ISO 8754) between the range of 0.05 mass % to 1.0 mass % preferably a sulfur content (ISO 14596 or ISO 8754) between the range of 0.05 mass % ppm and 0.7 mass % and more preferably a sulfur content (ISO 14596 or ISO 8754) between the range of 0.1 mass % and 0.5 mass %. The vanadium content of the Product HMFO is also ISO compliant with a maximum vanadium content (ISO 14597) between the range from 350 mg/kg to 450 ppm mg/kg, preferably a vanadium content (ISO 14597) between the range of 200 mg/kg and 300 mg/kg and more preferably a vanadium content (ISO 14597) less than 50 mg/kg.
The Product HFMO should have bulk physical properties that are ISO 8217 (2017) compliant. The Product HMFO should exhibit Bulk Properties of: a maximum of kinematic viscosity at 50° C. (ISO 3104) between the range from 180 mm2/s to 700 mm2/s; a maximum of density at 15° C. (ISO 3675) between the range of 991.0 kg/m3 to 1010.0 kg/m3; a CCAI value in the range of 780 to 870; a flash point (ISO 2719) no lower than 60.0° C.; a total sediment—aged (ISO 10307-2) of less than 0.10 mass %; a carbon residue—micro method (ISO 10370) lower than 20.00 mass %, and preferably an aluminum plus silicon (ISO 10478) content of less than 60 mg/kg.
Relative to the Feedstock HMFO, the Product HMFO will have a sulfur content (ISO 14596 or ISO 8754) between 1% and 20% of the maximum sulfur content of the Feedstock HMFO. That is the sulfur content of the Product will be reduced by about 80% or greater when compared to the Feedstock HMFO. Similarly, the vanadium content (ISO 14597) of the Product HMFO is between 1% and 20% of the maximum vanadium content of the Feedstock HMFO. One of skill in the art will appreciate that the above data indicates a substantial reduction in sulfur and vanadium content indicate a process having achieved a substantial reduction in the Environmental Contaminates from the Feedstock HMFO while maintaining the desirable properties of an ISO 8217 (2017) compliant and merchantable HMFO.
As a side note, the residual gaseous component is a mixture of gases selected from the group consisting of: nitrogen, hydrogen, carbon dioxide, hydrogen sulfide, gaseous water, C1-C4 hydrocarbons. An amine scrubber will effectively remove the hydrogen sulfide content which can then be processed using technologies and processes well known to one of skill in the art. In one preferable illustrative embodiment, the hydrogen sulfide is converted into elemental sulfur using the well-known Claus process. An alternative embodiment utilizes a proprietary process for conversion of the Hydrogen sulfide to hydrosulfuric acid. Either way, the sulfur is removed from entering the environment prior to combusting the HMFO in a ships engine. The cleaned gas can be vented, flared or more preferably recycled back for use as Activating Gas.
Pre and Post Process Units: It will be appreciated by one of skill in the art, that the conditions utilized in the core process have been intentionally selected to minimize cracking of hydrocarbons, but remove significant levels of sulfur and other Environmental Contaminates from the Feedstock HMFO. However, one of skill in the art will also appreciate there may be certain compounds present in the Feedstock HMFO removal of which would have a positive impact upon the subsequent process feedstock qualities of the Product HMFO. These processes and systems must achieve this without substantially altering the subsequent process feedstock qualities of the Product HMFO. Process for the Pre and Post treatment of the HMFO in the above illustrative core process have been described in greater detail in co-owned patent applications. These pre- and post-process units may include, but are not limited to: removal of Detrimental Solids (such as catalyst fines); treatment with microwave energy; treatment with ultrasound energy; extraction of sulfur and other polar compounds with ionic liquids; absorption of sulfur and organosulfur compounds on absorptive media; selective oxidation of the organosulfur compounds, including the use of peroxides and ozone to form sulfones which can be subsequently removed; dewatering and desalting units; the use of guard beds to remove detrimental materials such as clays, ionic solids, particles, and the like; and combinations of these.
Product HMFO and Use as Feedstock The Product HFMO resulting from the disclosed illustrative process may be used as a feedstock in subsequent refinery process selected from the group including: anode grade coking process unit, needle grade coking process unit and fluid catalytic cracking process unit. The Product HMFO has a sulfur content (ISO 14596 or ISO 8754) less than 0.5 wt % and preferably less than 0.1% wt. and thus forms a low sulfur feedstock material that is useful in subsequent refinery processes. That is the sulfur content of the Product HMFO has been reduced by about 80% or greater when compared to the Feedstock HMFO. One of skill in the art will appreciate the Product Heavy Marine Fuel Oil may be fractionated to remove a light to middle distillate fraction, said light to middle distillate fraction have a maximum boiling point less than 650° F., preferably less than 600° F. In this way one can remove a valuable by-product light and middle distillate fraction prior to sending it to the subsequent refinery processes. To illustrate and further explain the above inventive concepts examples of using the Product HMFO as a coker process unit feedstock and a fluid catalytic cracking process feedstock are described below.
Product HMFO as Coker Feedstock: Coking is a severe thermal cracking process during which residual feedstocks are cracked to produce lighter, more valuable products and simultaneously produce a coke material of desired quality. A fired heater is used in the process to reach thermal cracking temperatures of 485° C. to 505° C. For a delayed coker, the coking is delayed until the feed reaches the coking drums. The preheated feed in the tubes undergoes decomposition and condensation reactions and once the feed reaches the drum, the condensation reactions between the liquids result in the formation of coke along with the evolution of light gases and liquids.
The quality of the coke formed depends on the quality of the feed and the temperature, pressure and the recycle ratio of the process. Typically there are three kinds of cokes that can be obtained in the process: anode grade (sponge) coke, shot coke and needle coke. Anode grade coke is a porous solid which is used as a solid fuel or for the production of anodes for use in the aluminum industry. Shot coke is a less desirable coke occasionally produced along with sponge coke; it consists of small hard spheres of low porosity and typically is used as fuel. Needle coke is premium quality coke, which is characterized by a needle-like appearance and crystalline microstructure. The graphite artifacts made from needle coke have a low coefficient of thermal expansion and low electrical resistance and is used for making electrodes for use in the steel industry. The characteristics of the various cokes and their end use are presented below:
One of skill in the art of coking will understand that key feedstock properties that affect Coke Yield and Quality are: Gravity; Distillation; Conradson Carbon Residue; Asphaltene Content; Sulfur; Metals/Ash; Nitrogen; Hydrogen Content/Aromaticity. Typical Feedstock Limitations to produce Anode Grade Coke generally include, but are not limited to: Sulfur: less than about 1.0 wt %; Vanadium: less than about 100 ppmw and Nickel: less than about 100 ppmw. Typical Feedstock Limitations to produce Needle Coke generally include, but are not limited to: Sulfur: in the range from about 0.0-0.7 wt %; Vanadium: less than about 50 ppmw; Nickel: less than about 50 ppmw; Aromatic Content: in the range from about 50-80 wt %; Asphaltene Content: less than about 8 wt %; Nitrogen Content: in the range from about 0.0-0.7 wt; Ash: less than about 100 ppmw. It will be quickly realized by one of skill in the art that the Product HMFO has meets all of the requirements necessary to be used as high quality coker feedstock, that is: low sulfur content (<1%), low vanadium content (typically <20 ppmw), low nickel content (typically <20 ppmw), high aromatics content (50-80%), low asphaltene content (<10%), low saturates content (<15%), micro carbon residue (MCR) content of 5-20% wt.
In a variation of the processes and devices disclosed above, specifically when a coker feedstock is the desired goal, certain modifications can be made to enhance or optimize the Product HMFO as a high quality coker feedstock material. For example, the design of the Product Stabilizer may be modified to take a distillate side cut product, to separate mid-boiling (<approximately 600 F) components from the Product HMFO Coker Feedstock. Alternatively, the separation of distillate product and Coker Feedstock can be achieved in a separate distillation column. One of skill in the art will appreciate that the cutpoint between Coker Feedstock and distillate may be adjusted to optimize coker performance. These modifications are well within the scope and skill of one in the art of refinery engineering and refinery process design.
Product HMFO as Fluid Catalytic Cracking Process Unit Feedstock: As the term is used in this disclosure, Fluid Catalytic Cracking (FCC) is utilized as a generalized term to encompass both Fluid Catalytic Cracking and Resid Fluid Catalytic Cracking processes.
The FCC Unit is the most common refinery unit used to upgrade heavier fractions to light products. The FCC cracks the feed material using heat in the presence of a catalyst. The primary product is FCC naphtha, which is used in gasoline product blending. The FCC also produces lighter products and heavier products that can be blended into diesel and residual fuel oil.
The FCC is particularly valuable in a refinery that is trying to maximize gasoline production over residual fuel oil. The FCC yields a high volume of high quality naphtha (high octane and low vapor pressure). However, the diesel yield is low and of low quality, since it is made up of cracked material which tends to have low cetane.
The RFCC is a variant on the FCC. It is a similar unit yielding a similar range and quality of products, but it is designed to handle heavier residual streams as a feed.
In the FCC Unit, heated feed is mixed with a heated catalyst and injected into a reactor, where the catalyst freely mixes with the feed as a fluid. As the feed is cracked, coke deposits on the catalyst, causing it to gradually deactivate. Cracked product is drawn off at the top of the reactor and is sent to a fractionator. Deactivated catalyst is drawn off the bottom of the reactor and is sent to a regenerator, where the coke is burned off by injecting heat and air. The cleaned (regenerated) catalyst is then sent back to the reactor, and the cycle repeats.
The catalyst moves around the reactor and regenerator circuits in seconds at very high velocities, so many internal surfaces on the catalyst circuit must be protected against erosion by having ceramic coatings. The heat generated in the regenerator from burning the coke off the catalyst provides the majority of the heat required for the separation reactions taking place in the reactor, and the unit has to be heat-balanced between the reactor and regenerator. Coke burned off the catalyst in the regenerator creates a mix of carbon monoxide and carbon dioxide plus some SOx. This gas stream is passed through a carbon monoxide boiler and recovery gas compressor to recover some energy, then cleaned of catalyst fines and evacuated to the atmosphere, so the FCC is a major emitter of carbon dioxide from refineries.
The FCC produces a range of mostly lighter products, with the most significant being FCC gasoline. Typical products are: FCC naphtha—This material has octane and vapor pressure close to the quality specifications for finished gasoline. This is typically the largest product at around 50% of FCC output; Cycle oils—The FCC produces a diesel range product called cycle oil. This is highly aromatic, which makes it a poor diesel blendstock. It is typically blended into lower quality diesel, used as a cutter stock in fuel oil blending, or sent to the hydrocracker for upgrading; FCC slurry—The heaviest product from the FCC is a highly aromatic residual stream. This is sent for fuel oil blending, used as feed for the coker, or used to make specialty products such as carbon black or needle coke; FCC gas—The light ends from the FCC include both saturated and unsaturated hydrocarbons, such as C3 and C4 hydrocarbons. Lighter gases (ethane and methane) are sent to a fuel system and utilized to power the refinery operations.
Upon review of the properties and characteristics of the Product HMFO, one of skill in the art will appreciate that the disclosed process and devices improve the properties of a low value material in the form of high sulfur Heavy Marine Fuel Oil (which preferably is ISO 8217 (2017) compliant) in a way which allow it to be used as FCC Unit feedstock. More specifically, the Product HMFO exhibits desirable properties of an FCC Unit feedstock that include: Sulfur Content below 0.5 wt % and more preferably in the range of 0.1 to 0.05 wt % sulfur; Metals Content, preferably Vanadium: less than about 50 ppmw; and Nickel: less than about 50 ppmw; reduced Asphaltene Content, preferably to less than 10 wt %; reduced micro carbon residue (MCR) content of 5-20% wt and reduced Nitrogen Content: in the range from about 0.0-0.7 wt.
Because of the present invention, refiners will realize multiple economic and logistical benefits, including: no need to alter or rebalance the refinery operations and product streams in an effort to meet a new market demand for low sulfur or ultralow sulfur HMFO; instead to the otherwise previously low value high sulfur HMFO is transformed into a feedstock suitable for use in subsequent refinery process, more specifically in anode grade cokers and as feedstock into a fluid catalytic cracker. No additional units are needed in the refinery with additional hydrogen or sulfur capacity because the illustrative process can be conducted as a stand-alone unit; refinery operations can remain focused on those products that create the greatest value from the crude oil received (i.e. production of petrochemicals, gasoline and distillate (diesel); refiners can continue using the existing slates of crude oils without having to switch to sweeter or lighter crudes to meet the environmental requirements for HMFO products.
Production Plant Description: Turning now to a more detailed illustrative embodiment of a production plant,
In
The Feedstock HMFO (A) is withdrawn from the Oil Feed Surge Drum (1) via line (1b) by the Oil Feed Pump (3) and is pressurized to a pressure required for the process. The pressurized HMFO (A′) then passes through line (3a) to the Oil Feed/Product Heat Exchanger (5) where the pressurized HMFO Feed (A′) is partially heated by the Product HMFO (B). The pressurized Feedstock HMFO (A′) passing through line (5a) is further heated against the effluent from the Reactor System (E) in the Reactor Feed/Effluent Heat Exchanger (7).
The heated and pressurized Feedstock HMFO (A″) in line (7a) is then mixed with Activating Gas (C) provided via line (23c) at Mixing Point (X) to form a Feedstock Mixture (D). The mixing point (X) can be any well know gas/liquid mixing system or entrainment mechanism well known to one skilled in the art.
The Feedstock Mixture (D) passes through line (9a) to the Reactor Feed Furnace (9) where the Feedstock Mixture (D) is heated to the specified process temperature. The Reactor Feed Furnace (9) may be a fired heater furnace or any other kind to type of heater as known to one of skill in the art if it will raise the temperature of the Feedstock Mixture (D) to the desired temperature for the process conditions.
The fully heated Feedstock Mixture (D′) exits the Reactor Feed Furnace (9) via line 9b and is fed into the Reactor System (11). The fully heated Feedstock Mixture (D′) enters the Reactor System (11) where environmental contaminates, such a sulfur, nitrogen, and metals are preferentially removed from the Feedstock HMFO component of the fully heated Feedstock Mixture. The Reactor System contains a catalyst which preferentially removes the sulfur compounds in the Feedstock HMFO component by reacting them with hydrogen in the Activating Gas to form hydrogen sulfide. The Reactor System will also achieve demetallization, denitrogenation, and a certain amount of ring opening hydrogenation of the complex aromatics and asphaltenes, however minimal hydrocracking of hydrocarbons should take place. The process conditions of hydrogen partial pressure, reaction pressure, temperature and residence time as measured by liquid hourly velocity are optimized to achieve desired final product quality. A more detailed discussion of the Reactor System, the catalyst, the process conditions, and other aspects of the process are contained below in the “Reactor System Description.”
The Reactor System Effluent (E) exits the Reactor System (11) via line (11a) and exchanges heat against the pressurized and partially heats the Feedstock HMFO (A′) in the Reactor Feed/Effluent Exchanger (7). The partially cooled Reactor System Effluent (E′) then flows via line (11c) to the Hot Separator (13).
The Hot Separator (13) separates the gaseous components of the Reactor System Effluent (F) which are directed to line (13a) from the liquid components of the Reactor System effluent (G) which are directed to line (13b). The gaseous components of the Reactor System effluent in line (13a) are cooled against air in the Hot Separator Vapor Air Cooler (15) and then flow via line (15a) to the Cold Separator (17).
The Cold Separator (17) further separates any remaining gaseous components from the liquid components in the cooled gaseous components of the Reactor System Effluent (F′). The gaseous components from the Cold Separator (F″) are directed to line (17a) and fed onto the Amine Absorber (21). The Cold Separator (17) also separates any remaining Cold Separator hydrocarbon liquids (H) in line (17b) from any Cold Separator condensed liquid water (I). The Cold Separator condensed liquid water (I) is sent OSBL via line (17c) for treatment.
The hydrocarbon liquid components of the Reactor System effluent from the Hot Separator (G) in line (13b) and the Cold Separator hydrocarbon liquids (H) in line (17b) are combined and are fed to the Oil Product Stripper System (19). The Oil Product Stripper System (19) removes any residual hydrogen and hydrogen sulfide from the Product HMFO (B) which is discharged in line (19b) to storage OSBL. It is also contemplated that a second draw (not shown) may be included to withdraw a distillate product, preferably a middle to heavy distillate. The vent stream (M) from the Oil Product Stripper in line (19a) may be sent to the fuel gas system or to the flare system that are OSBL. A more detailed discussion of the Oil Product Stripper System is contained in the “Oil Product Stripper System Description.”
The gaseous components from the Cold Separator (F″) in line (17a) contain a mixture of hydrogen, hydrogen sulfide and light hydrocarbons (mostly methane and ethane). This vapor stream (17a) feeds an Amine Absorber System (21) where it is contacted against Lean Amine (J) provided OSBL via line (21a) to the Amine Absorber System (21) to remove hydrogen sulfide from the gases making up the Activating Gas recycle stream (C′). Rich amine (K) which has absorbed hydrogen sulfide exits the bottom of the Amine Absorber System (21) and is sent OSBL via line (21b) for amine regeneration and sulfur recovery.
The Amine Absorber System overhead vapor in line (21c) is preferably recycled to the process as a Recycle Activating Gas (C′) via the Recycle Compressor (23) and line (23a) where it is mixed with the Makeup Activating Gas (C″) provided OSBL by line (23b). This mixture of Recycle Activating Gas (C′) and Makeup Activating Gas (C″) to form the Activating Gas (C) utilized in the process via line (23c) as noted above. A Scrubbed Purge Gas stream (H) is taken from the Amine Absorber System overhead vapor line (21c) and sent via line (21d) to OSBL to prevent the buildup of light hydrocarbons or other non-condensable hydrocarbons. A more detailed discussion of the Amine Absorber System is contained in the “Amine Absorber System Description.”
Reactor System Description: The core process Reactor System (11) illustrated in
A description of the process catalyst, the selection of the process catalyst and the loading and grading of the catalyst within the reactor vessel is contained in the “Catalyst in Reactor System”.
Alternative configurations for the core process Reactor System (11) are contemplated. In one illustrative configuration, more than one reactor vessel may be utilized in parallel as shown in
In the embodiment shown in
A cascading series as shown in
An alternative implementation of the parallel reactor concept is illustrated in greater detail in
One of skill in the art upon careful review of the illustrated configuration will appreciate that multiple flow schemes and configurations can be achieved with the illustrated arrangement of reactor vessels, control valves and interconnected lines forming the reactor System. For example, in one configuration one can: open all of inflow diversion control valves (68, 68a, 68b and 68c); open all of the reactor inlet valves (60, 60a, 60b, 60c, and 60d); open all of the reactor outlet valves 62, 62a, 62b, 62c and 62d; open all of the outflow diversion control valves (70, 70a, 70b and 70c); and close lower by-pass control valve (6464a, 64b, 64c) and upper by-pass control valve (66, 66a, 66b and 66c), to substantially achieve a reactor configuration of five parallel reactors each receiving fully heated Feedstock from line 9b and discharging Reactor Effluent into line 11a. In such a configuration, all of the reactors are loaded with catalyst in substantially the same manner. One of skill in the art will also appreciate that closing of an individual reactor inlet valve and corresponding reactor outlet valve (for example closing reactor inlet vale 60 and closing reactor outlet valve 62) effectively isolates the reactor vessel 11. This will allow for the isolated reactor vessel 11 to be brought off line and serviced and or reloaded with catalyst while the remaining reactors continue to transform Feedstock HMFO into Product HMFO.
A second illustrative configuration of the control valves allows for the reactors to work in series as shown in
Another illustrative embodiment of the replacement of the single reactor vessel Reactor System 11 in
One of the benefits of having a multi-reactor Reactor System is that it allows for a reactor that is experiencing decreased activity or plugging as a result of coke formation to be isolated and taken off line for turn-around (i.e. deactivated, catalyst and internals replaced, etc. . . . ) without the entire plant having to shut down. Another benefit as noted above is that it allows one to vary the catalyst loading in the Reactor System so that the overall process can be optimized for a specific feedstock. A further benefit is that one can design the piping, pumps, heaters/heat exchangers, etc. . . . to have excess capacity so that when an increase in capacity is desired, additional reactors can be quickly brought on-line. Conversely, it allows an operator to take capacity off line, or turn down a plant output without having a concern about turn down and minimum flow through a reactor.
Catalyst in Reactor System: The reactor vessel in each Reactor System is loaded with one or more process catalysts. The exact design of the process catalyst system is a function of feedstock properties, product requirements and operating constraints and optimization of the process catalyst can be carried out by routine trial and error by one of ordinary skill in the art.
The process catalyst(s) comprise at least one metal selected from the group consisting of the metals each belonging to the groups 6, 8, 9 and 10 of the Periodic Table, and more preferably a mixed transition metal catalyst such as Ni—Mo, Co—Mo, Ni—W or Ni—Co—Mo are utilized. The metal is preferably supported on a porous inorganic oxide catalyst carrier. The porous inorganic oxide catalyst carrier is at least one carrier selected from the group consisting of alumina, alumina/boria carrier, a carrier containing metal-containing aluminosilicate, alumina/phosphorus carrier, alumina/alkaline earth metal compound carrier, alumina/titania carrier and alumina/zirconia carrier. The preferred porous inorganic oxide catalyst carrier is alumina. The pore size and metal loadings on the carrier may be systematically varied and tested with the desired feedstock and process conditions to optimize the properties of the Product HMFO. One of skill in the art knows that demetallization using a transition metal catalyst (such a CoMO or NiMo) is favored by catalysts with a relatively large surface pore diameter and desulfurization is favored by supports having a relatively small pore diameter. Generally the surface area for the catalyst material ranges from 200-300 m2/g. The systematic adjustment of pore size and surface area, and transition metal loadings activities to preferentially form a demetallization catalyst or a desulfurization catalyst are well known and routine to one of skill in the art. Catalyst in the fixed bed reactor(s) may be dense-loaded or sock-loaded and the inclusion of inert materials (such as glass or ceric balls) may be needed to ensure the desired porosity.
The catalyst selection utilized within and for loading the Reactor System may be preferential to desulfurization by designing a catalyst loading scheme that results in the Feedstock mixture first contacting a catalyst bed that with a catalyst preferential to demetallization followed downstream by a bed of catalyst with mixed activity for demetallization and desulfurization followed downstream by a catalyst bed with high desulfurization activity. In effect the first bed with high demetallization activity acts as a guard bed for the desulfurization bed.
The objective of the Reactor System is to treat the Feedstock HMFO at the severity required to meet the Product HMFO specification. Demetallization, denitrogenation and hydrocarbon hydrogenation reactions may also occur to some extent when the process conditions are optimized so the performance of the Reactor System achieves the required level of desulfurization. Hydrocracking is preferably minimized to reduce the volume of hydrocarbons formed as by-product hydrocarbons to the process. The objective of the process is to selectively remove the environmental contaminates from Feedstock HMFO and minimize the formation of unnecessary by-product hydrocarbons (C1-C8 hydrocarbons).
The process conditions in each reactor vessel will depend upon the feedstock, the catalyst utilized and the desired properties of the Product HMFO. Variations in conditions are to be expected by one of ordinary skill in the art and these may be determined by pilot plant testing and systematic optimization of the process. With this in mind it has been found that the operating pressure, the indicated operating temperature, the ratio of the Activating Gas to Feedstock HMFO, the partial pressure of hydrogen in the Activating Gas and the space velocity all are important parameters to consider. The operating pressure of the Reactor System should be in the range of 250 psig and 3000 psig, preferably between 1000 psig and 2500 psig and more preferably between 1500 psig and 2200 psig. The indicated operating temperature of the Reactor System should be 500° F. to 900° F., preferably between 650° F. and 850° F. and more preferably between 680° F. and 800° F. The ratio of the quantity of the Activating Gas to the quantity of Feedstock HMFO should be in the range of 250 scf gas/bbl of Feedstock HMFO to 10,000 scf gas/bbl of Feedstock HMFO, preferably between 2000 scf gas/bbl of Feedstock HMFO to 5000 scf gas/bbl of Feedstock HMFO and more preferably between 2500 scf gas/bbl of Feedstock HMFO to 4500 scf gas/bbl of Feedstock HMFO. The Activating Gas should be selected from mixtures of nitrogen, hydrogen, carbon dioxide, gaseous water, and methane, so Activating Gas has an ideal gas partial pressure of hydrogen (pH2) greater than 80% of the total pressure of the Activating Gas mixture (P) and preferably wherein the Activating Gas has an ideal gas partial pressure of hydrogen (pH2) greater than 90% of the total pressure of the Activating Gas mixture (P). The Activating Gas may have a hydrogen mole fraction in the range between 80% of the total moles of Activating Gas mixture and more preferably wherein the Activating Gas has a hydrogen mole fraction between 80% and 100% of the total moles of Activating Gas mixture. The liquid hourly space velocity within the Reactor System should be between 0.05 oil/hour/m3 catalyst and 1.0 oil/hour/m3 catalyst; preferably between 0.08 oil/hour/m3 catalyst and 0.5 oil/hour/m3 catalyst and more preferably between 0.1 oil/hour/m3 catalyst and 0.3 oil/hour/m3 catalyst to achieve deep desulfurization with product sulfur levels below 0.1 ppmw.
The hydraulic capacity rate of the Reactor System should be between 100 bbl of Feedstock HMFO/day and 100,000 bbl of Feedstock HMFO/day, preferably between 1000 bbl of Feedstock HMFO/day and 60,000 bbl of Feedstock HMFO/day, more preferably between 5,000 bbl of Feedstock HMFO/day and 45,000 bbl of Feedstock HMFO/day, and even more preferably between 10,000 bbl of Feedstock HMFO/day and 30,000 bbl of Feedstock HMFO/day. The desired hydraulic capacity may be achieved in a single reactor vessel Reactor System or in a multiple reactor vessel Reactor System as described.
Oil Product Stripper System Description: The Oil Product Stripper System (19) comprises a stripper column (also known as a distillation column or exchange column) and ancillary equipment including internal elements and utilities required to remove hydrogen, hydrogen sulfide and light hydrocarbons lighter than diesel from the Product HMFO. Such systems are well known to one of skill in the art, see U.S. Pat. Nos. 6,640,161; 5,709,780; 5,755,933; 4,186,159; 3,314,879 3,844,898; 4,681,661; or 3,619,377 the contents of which are incorporated herein by reference, a generalized functional description is provided herein. Liquid from the Hot Separator (13) and Cold Separator (7) feed the Oil Product Stripper Column (19). Stripping of hydrogen and hydrogen sulfide and light hydrocarbons lighter than diesel may be achieved via a reboiler, live steam or other stripping medium. The Oil Product Stripper System (19) may be designed with an overhead system comprising an overhead condenser, reflux drum and reflux pump or it may be designed without an overhead system. The conditions of the Oil Product Stripper may be optimized to control the bulk properties of the Product HMFO, more specifically viscosity and density. It is also contemplated that a second draw (not shown) may be included to withdraw a distillate product, preferably a middle to heavy distillate.
Amine Absorber System Description: The Amine Absorber System (21) comprises a gas liquid contacting column and ancillary equipment and utilities required to remove sour gas (i.e. hydrogen sulfide) from the Cold Separator vapor feed so the resulting scrubbed gas can be recycled and used as Activating Gas. Because such systems are well known to one of skill in the art, see U.S. Pat. Nos. 4,425,317; 4,085,199; 4,080,424; 4,001,386; which are incorporated herein by reference, a generalized functional description is provided herein. Vapors from the Cold Separator (17) feed the contacting column/system (19). Lean Amine (or other suitable sour gas stripping fluids or systems) provided from OSBL is utilized to scrub the Cold Separator vapor so hydrogen sulfide is effectively removed. The Amine Absorber System (19) may be designed with a gas drying system to remove the any water vapor entrained into the Recycle Activating Gas (C′). The absorbed hydrogen sulfide is processed using conventional means OSBL in a tail gas treating unit, such as a Claus combustion sulfur recovery unit or sulfur recovery system that generates sulfuric acid.
The following examples will provide one skilled in the art with a more specific illustrative embodiment for conducting the process disclosed and claimed herein:
Overview: The purpose of a pilot test run is to demonstrate that feedstock HMFO can be processed through a reactor loaded with commercially available catalysts at specified conditions to remove environmental contaminates, specifically sulfur and other contaminants from the HMFO to produce a product HMFO that is MARPOL compliant, that is production of a Low Sulfur Heavy Marine Fuel Oil (LS-HMFO) or Ultra-Low Sulfur Heavy Marine Fuel Oil (USL-HMFO).
Pilot Unit Set Up: The pilot unit will be set up with two 434 cm3 reactors arranged in series to process the feedstock HMFO. The lead reactor will be loaded with a blend of a commercially available hydrodemetallization (HDM) catalyst and a commercially available hydro-transition (HDT) catalyst. One of skill in the art will appreciate that the HDT catalyst layer may be formed and optimized using a mixture of HDM and HDS catalysts combined with an inert material to achieve the desired intermediate/transition activity levels. The second reactor will be loaded with a blend of the commercially available hydro-transition (HDT) and a commercially available hydrodesulfurization (HDS). Alternatively, one can load the second reactor simply with a commercially hydrodesulfurization (HDS) catalyst. One of skill in the art will appreciate that the specific feed properties of the Feedstock HMFO may affect the proportion of HDM, HDT and HDS catalysts in the reactor system. A systematic process of testing different combinations with the same feed will yield the optimized catalyst combination for any feedstock and reaction conditions. For this example, the first reactor will be loaded with ⅔ hydrodemetallization catalyst and ⅓ hydro-transition catalyst. The second reactor will be loaded with all hydrodesulfurization catalyst. The catalysts in each reactor will be mixed with glass beads (approximately 50% by volume) to improve liquid distribution and better control reactor temperature. For this pilot test run, one should use these commercially available catalysts: HDM: Albemarle KFR 20 series or equivalent; HDT: Albemarle KFR 30 series or equivalent; HDS: Albemarle KFR 50 or KFR 70 or equivalent. Once set up of the pilot unit is complete, the catalyst can be activated by sulfiding the catalyst using dimethyldisulfide (DMDS) in a manner well known to one of skill in the art.
Pilot Unit Operation: Upon completion of the activating step, the pilot unit will be ready to receive the feedstock HMFO and Activating Gas feed. For the present example, the Activating Gas can be technical grade or better hydrogen gas. The mixed Feedstock HMFO and Activating Gas will be provided to the pilot plant at rates and operating conditions as specified: Oil Feed Rate: 108.5 ml/h (space velocity=0.25/h); Hydrogen/Oil Ratio: 570 Nm3/m3 (3200 scf/bbl); Reactor Temperature: 372° C. (702° F.); Reactor Outlet Pressure: 13.8 MPa(g) (2000 psig).
One of skill in the art will know that the rates and conditions may be systematically adjusted and optimized depending upon feed properties to achieve the desired product requirements. The unit will be brought to a steady state for each condition and full samples taken so analytical tests can be completed. Material balance for each condition should be closed before moving to the next condition.
Expected impacts on the Feedstock HMFO properties are: Sulfur Content (wt %): Reduced by at least 80%; Metals Content (wt %): Reduced by at least 80%; MCR/Asphaltene Content (wt %): Reduced by at least 30%; Nitrogen Content (wt %): Reduced by at least 20%; C1-Naphtha Yield (wt %): Not over 3.0% and preferably not over 1.0%.
Process conditions in the Pilot Unit can be systematically adjusted as per Table 4 to assess the impact of process conditions and optimize the performance of the process for the specific catalyst and feedstock HMFO utilized.
In this way, the conditions of the pilot unit can be optimized to achieve less than 0.5% wt. sulfur product HMFO and preferably a 0.1% wt. sulfur product HMFO. Conditions for producing ULS-HMFO (i.e. 0.1% wt. sulfur product HMFO) will be: Feedstock HMFO Feed Rate: 65.1 ml/h (space velocity=0.15/h); Hydrogen/Oil Ratio: 620 Nm3/m3 (3480 scf/bbl); Reactor Temperature: 385° C. (725° F.); Reactor Outlet Pressure: 15 MPa(g) (2200 psig)
Table 5 summarizes the anticipated impacts on key properties of HMFO.
Table 6 lists analytical tests to be carried out for the characterization of the Feedstock HMFO and Product HMFO. The analytical tests include those required by ISO for the Feedstock HMFO and the product HMFO to qualify and trade in commerce as ISO compliant residual marine fuels. The additional parameters are provided so that one skilled in the art will be able to understand and appreciate the effectiveness of the inventive process.
Table 7 contains the Feedstock HMFO analytical test results and the Product HMFO analytical test results expected from the inventive process that indicate the production of a LS HMFO. It will be noted by one of skill in the art that under the conditions, the levels of hydrocarbon cracking will be minimized to levels substantially lower than 10%, more preferably less than 5% and even more preferably less than 1% of the total mass balance.
(1) It is expected that property will be adjusted to a higher vaue by post process removal of light material via distillation or stripping from product HMFO.
The product HMFO produced by the inventive process will reach ULS HMFO limits (i.e. 0.1% wt. sulfur product HMFO) by systematic variation of the process parameters, for example by a lower space velocity or by using a Feedstock HMFO with a lower initial sulfur content. The resulting product will make a ideal feedstock for anode or needle coking.
Pilot Unit Set Up: A pilot unit was set up as noted above in Example 1 with the following changes: the first reactor was loaded with: as the first (upper) layer encountered by the feedstock 70% vol Albemarle KFR 20 series hydrodemetallization catalyst and 30% vol Albemarle KFR 30 series hydro-transition catalyst as the second (lower) layer. The second reactor was loaded with 20% Albemarle KFR 30 series hydrotransition catalyst as the first (upper) layer and 80% vol hydrodesulfurization catalyst as the second (lower) layer. The catalyst was activated by sulfiding the catalyst with dimethyldisulfide (DMDS) in a manner well known to one of skill in the art.
Pilot Unit Operation: Upon completion of the activating step, the pilot unit was ready to receive the feedstock HMFO and Activating Gas feed. The Activating Gas was technical grade or better hydrogen gas. The Feedstock HMFO was a commercially available and merchantable ISO 8217 (2017) compliant HMFO, except for a high sulfur content (2.9 wt %). The mixed Feedstock HMFO and Activating Gas was provided to the pilot plant at rates and conditions as specified in Table 8 below. The conditions were varied to optimize the level of sulfur in the product HMFO material.
Analytical data for a representative sample of the feedstock HMFO and representative samples of product HMFO are provided below:
As noted above in Table 7, both feedstock HMFO and product HMFO exhibited observed bulk properties consistent with ISO 8217 (2017) for a merchantable residual marine fuel oil, except that the sulfur content of the product HMFO was significantly reduced as noted above when compared to the feedstock HMFO.
One of skill in the art will appreciate that the above product HMFO produced by the inventive process has achieved not only an ISO 8217 (2017) compliant LS HMFO (i.e. 0.5% wt. sulfur) but also an ISO 8217 (2017) compliant ULS HMFO limits (i.e. 0.1% wt. sulfur) product HMFO. This material will make an excellent feedstock for needle coking or processing in an FCC unit.
The feedstock to the pilot reactor utilized in example 2 above was changed to a commercially available and merchantable ISO 8217 (2017) RMK-500 compliant HMFO, except that it has high environmental contaminates (i.e. sulfur (3.3 wt %)). Other bulk characteristic of the RMK-500 feedstock high sulfur HMFO are provide below:
The mixed Feedstock (RMK-500) HMFO and Activating Gas was provided to the pilot plant at rates and conditions and the resulting sulfur levels achieved in the table below
The resulting product (RMK-500) HMFO exhibited observed bulk properties consistent with the feedstock (RMK-500) HMFO, except that the sulfur content was significantly reduced as noted in the above table.
One of skill in the art will appreciate that the above product HMFO produced by the inventive process has achieved a LS HMFO (i.e. 0.5% wt. sulfur) product HMFO having bulk characteristics of a ISO 8217 (2017) compliant RMK-500 residual fuel oil. It will also be appreciated that the process can be successfully carried out under non-hydrocracking conditions (i.e. lower temperature and pressure) that substantially reduce the hydrocracking of the feedstock material. It should be noted that when conditions were increased to much higher pressure (Example E) a product with a lower sulfur content was achieved, however it was observed that there was an increase in light hydrocarbons and wild naphtha production.
It will be appreciated by those skilled in the art that changes could be made to the illustrative embodiments described above without departing from the broad inventive concepts thereof. It is understood, therefore, that the inventive concepts disclosed are not limited to the illustrative embodiments or examples disclosed, but it is intended to cover modifications within the scope of the inventive concepts as defined by the claims.
This application is a continuation of U.S. application Ser. No. 16/681,093, filed 12 Nov. 2019; U.S. application Ser. No. 16/681,093 is a continuation of U.S. application Ser. No. 16/103,897, filed 14 Aug. 2018, now U.S. patent Ser. No. 10/533,141, granted 14 Jan. 2020; U.S. application Ser. No. 16/103,897 is a continuation-in-part of Application No. PCT/US2018/017863, filed 12 Feb. 2018, Application No. PCT/US2018/017863 claims priority to U.S. Provisional Application No. 62/589,479, filed 21 Nov. 2017, and Application No. PCT/US2018/017863 also claims priority to U.S. Provisional Application No. 62/458,002, filed 12 Feb. 2017; U.S. application Ser. No. 16/103,897 is also a continuation-in-part of Application No. PCT/US2018/017855, filed 12 Feb. 2018 now expired, Application No. PCT/US2018/017855 claims priority to U.S. Provisional Application No. 62/589,479, filed 21 Nov. 2017, now expired, and Application No. PCT/US2018/017855 also claims priority to U.S. Provisional Application No. 62/458,002, filed 12 Feb. 2017, now expired, the entire contents of each of the recited foregoing applications being incorporated herein in their entirety.
| Number | Name | Date | Kind |
|---|---|---|---|
| 3163593 | Webster et al. | Dec 1964 | A |
| 3227645 | Frumkin et al. | Jan 1966 | A |
| 3234121 | Maclaren | Feb 1966 | A |
| 3287254 | Paterson | Nov 1966 | A |
| 3306845 | Poll | Feb 1967 | A |
| 3531398 | Adams | Sep 1970 | A |
| 3544452 | Jaffe | Dec 1970 | A |
| 3551328 | Cole et al. | Dec 1970 | A |
| 3562800 | Carlson et al. | Feb 1971 | A |
| 3577353 | White | May 1971 | A |
| 3658681 | Wilson et al. | Apr 1972 | A |
| 3668116 | Adams et al. | Jun 1972 | A |
| 3684688 | Roselius | Aug 1972 | A |
| 3749664 | Mickleson | Jul 1973 | A |
| 3809644 | Johonson et al. | May 1974 | A |
| 3814683 | Christman et al. | Jun 1974 | A |
| 3859199 | Gatsis | Jan 1975 | A |
| 3880598 | Van Der Toorn | Apr 1975 | A |
| 3893909 | Selvidge | Jul 1975 | A |
| 3902991 | Christensen et al. | Sep 1975 | A |
| 3910834 | Anderson | Oct 1975 | A |
| 3968026 | Frayer et al. | Jul 1976 | A |
| 4006076 | Christensen et al. | Feb 1977 | A |
| 4017382 | Bonnell et al. | Apr 1977 | A |
| 4051021 | Hamner | Sep 1977 | A |
| 4054508 | Milstein et al. | Oct 1977 | A |
| 4089774 | Oleck et al. | May 1978 | A |
| 4115248 | Mulaskey | Sep 1978 | A |
| 4118310 | Frayer et al. | Oct 1978 | A |
| 4138227 | Wilson et al. | Feb 1979 | A |
| 4225421 | Hensley, Jr. et al. | Sep 1980 | A |
| 4267033 | Heck et al. | May 1981 | A |
| 4306964 | Angevine | Dec 1981 | A |
| 4357263 | Heck et al. | Nov 1982 | A |
| 4404097 | Angevine et al. | Sep 1983 | A |
| 4420388 | Bertolacini et al. | Dec 1983 | A |
| 4430198 | Heck et al. | Feb 1984 | A |
| 4460707 | Simpson | Jul 1984 | A |
| 4498972 | Toulhoat et al. | Feb 1985 | A |
| 4499203 | Toulhoat et al. | Feb 1985 | A |
| 4510042 | Billon et al. | Apr 1985 | A |
| 4548710 | Simpson | Oct 1985 | A |
| 4552650 | Toulhoat et al. | Nov 1985 | A |
| 4604185 | McConaghy, Jr. et al. | Aug 1986 | A |
| 4645584 | Didchenko et al. | Feb 1987 | A |
| 4925554 | Sato et al. | May 1990 | A |
| 5167796 | Didchenko et al. | Dec 1992 | A |
| 5306419 | Harrison et al. | Apr 1994 | A |
| 5342507 | Dai et al. | Aug 1994 | A |
| 5374350 | Heck et al. | Dec 1994 | A |
| 5389595 | Simpson et al. | Feb 1995 | A |
| 5391304 | Lantos | Feb 1995 | A |
| 5401392 | Courty et al. | Mar 1995 | A |
| 5417846 | Renard | May 1995 | A |
| 5543036 | Chang et al. | Aug 1996 | A |
| 5591325 | Higashi | Jan 1997 | A |
| 5620592 | Threlkel | Apr 1997 | A |
| 5622616 | Porter et al. | Apr 1997 | A |
| 5686375 | Iyer et al. | Nov 1997 | A |
| 5759385 | Aussillous et al. | Jun 1998 | A |
| 5779992 | Higashi | Jul 1998 | A |
| 5827421 | Sherwood, Jr. | Oct 1998 | A |
| 5837130 | Crossland | Nov 1998 | A |
| 5868923 | Porter et al. | Feb 1999 | A |
| 5882364 | Dilworth | Mar 1999 | A |
| 5888379 | Ushio et al. | Mar 1999 | A |
| 5897768 | McVicker et al. | Apr 1999 | A |
| 5917101 | Munoz | Jun 1999 | A |
| 5922189 | Santos | Jul 1999 | A |
| 5928501 | Sudhakar et al. | Jul 1999 | A |
| 5948239 | Virdi et al. | Sep 1999 | A |
| 5958816 | Neuman et al. | Sep 1999 | A |
| 5961709 | Hayner et al. | Oct 1999 | A |
| 5976361 | Hood et al. | Nov 1999 | A |
| 5997723 | Wiehe et al. | Dec 1999 | A |
| 6017443 | Buchanan | Jan 2000 | A |
| 6117306 | Morel et al. | Sep 2000 | A |
| 6136179 | Sherwood, Jr. et al. | Oct 2000 | A |
| 6160193 | Gore | Dec 2000 | A |
| 6162350 | Soled et al. | Dec 2000 | A |
| 6171477 | Morel et al. | Jan 2001 | B1 |
| 6171478 | Cabrera et al. | Jan 2001 | B1 |
| 6193766 | Jordan | Feb 2001 | B1 |
| 6203695 | Harle et al. | Mar 2001 | B1 |
| 6207041 | Morel et al. | Mar 2001 | B1 |
| 6217749 | Espeillac et al. | Apr 2001 | B1 |
| 6251262 | Hatanaka et al. | Jun 2001 | B1 |
| 6251263 | Hatanaka et al. | Jun 2001 | B1 |
| 6265629 | Fava et al. | Jul 2001 | B1 |
| 6299759 | Bradway et al. | Oct 2001 | B1 |
| 6303531 | Lussier et al. | Oct 2001 | B1 |
| 6306287 | Billon et al. | Oct 2001 | B1 |
| 6306289 | Hayashi et al. | Oct 2001 | B1 |
| 6328880 | Yoshita et al. | Dec 2001 | B1 |
| 6344136 | Butler et al. | Feb 2002 | B1 |
| 6383975 | Rocha et al. | May 2002 | B1 |
| 6402940 | Rappas | Jun 2002 | B1 |
| 6406615 | Iwamoto et al. | Jun 2002 | B1 |
| 6531054 | Gerritsen et al. | Mar 2003 | B1 |
| 6540904 | Gun et al. | Apr 2003 | B1 |
| 6554994 | Reynolds et al. | Apr 2003 | B1 |
| 6566296 | Plantenga et al. | May 2003 | B2 |
| 6576584 | Iijima et al. | Jun 2003 | B1 |
| 6589908 | Ginestra et al. | Jul 2003 | B1 |
| 6620313 | Soled et al. | Sep 2003 | B1 |
| 6649042 | Dassori et al. | Nov 2003 | B2 |
| 6656348 | Dassori et al. | Dec 2003 | B2 |
| 6656349 | Fujita et al. | Dec 2003 | B1 |
| 6673230 | Hagen | Jan 2004 | B2 |
| 6673245 | Nasser, Jr. et al. | Jan 2004 | B2 |
| 6712955 | Soled et al. | Mar 2004 | B1 |
| 6733659 | Kure et al. | May 2004 | B1 |
| 6774275 | Smith, Jr. et al. | Aug 2004 | B2 |
| 6783661 | Briot et al. | Aug 2004 | B1 |
| 6797153 | Fukuyama et al. | Sep 2004 | B1 |
| 6827845 | Gong et al. | Dec 2004 | B2 |
| 6858132 | Kumagai et al. | Feb 2005 | B2 |
| 6860987 | Plantenga et al. | Mar 2005 | B2 |
| 6863803 | Riley et al. | Mar 2005 | B1 |
| 6929738 | Riley et al. | Aug 2005 | B1 |
| 6984310 | Ginstra et al. | Jan 2006 | B2 |
| 7001503 | Koyama et al. | Feb 2006 | B1 |
| 7108779 | Thakkar | Sep 2006 | B1 |
| 7119045 | Magna et al. | Oct 2006 | B2 |
| 7166209 | Dassori | Jan 2007 | B2 |
| 7169294 | Abe et al. | Jan 2007 | B2 |
| 7232515 | Demmin et al. | Jun 2007 | B1 |
| 7244350 | Martin et al. | Jul 2007 | B2 |
| 7265075 | Tsukada et al. | Sep 2007 | B2 |
| 7276150 | Nagamatsu et al. | Oct 2007 | B2 |
| 7288182 | Soled et al. | Oct 2007 | B1 |
| 7384537 | Nagamatsu et al. | Jun 2008 | B2 |
| 7402547 | Wellington et al. | Jul 2008 | B2 |
| 7413646 | Wellington et al. | Aug 2008 | B2 |
| 7416653 | Wellington | Aug 2008 | B2 |
| 7449102 | Kalnes | Nov 2008 | B2 |
| 7491313 | Toshima et al. | Feb 2009 | B2 |
| 7507325 | Gueret et al. | Mar 2009 | B2 |
| 7513989 | Soled et al. | Apr 2009 | B1 |
| 7517446 | Lott | Apr 2009 | B2 |
| 7534342 | Bhan et al. | May 2009 | B2 |
| 7585406 | Khadzhiev et al. | Sep 2009 | B2 |
| 7588681 | Bhan et al. | Sep 2009 | B2 |
| 7651604 | Ancheyta Juarez et al. | Jan 2010 | B2 |
| 7651605 | Sahara et al. | Jan 2010 | B2 |
| 7695610 | Bolshakov et al. | Apr 2010 | B2 |
| 7713905 | Dufresne et al. | May 2010 | B2 |
| 7718050 | Gueret et al. | May 2010 | B2 |
| 7754162 | Dassori | Jul 2010 | B2 |
| 7901569 | Farshid et al. | Mar 2011 | B2 |
| 7938955 | Araki et al. | May 2011 | B2 |
| 7943035 | Chornet et al. | May 2011 | B2 |
| 8012343 | Plantenga et al. | Sep 2011 | B2 |
| 8021538 | Klein | Sep 2011 | B2 |
| 8114806 | Bhan et al. | Feb 2012 | B2 |
| 8133446 | McGehee et al. | Mar 2012 | B2 |
| 8163166 | Wellington et al. | Apr 2012 | B2 |
| 8173570 | Maesen et al. | May 2012 | B2 |
| 8193401 | McGehee et al. | Jun 2012 | B2 |
| 8241489 | Bhan et al. | Aug 2012 | B2 |
| 8268164 | Wellington et al. | Sep 2012 | B2 |
| 8318000 | Bhan et al. | Nov 2012 | B2 |
| 8318628 | Brun et al. | Nov 2012 | B2 |
| 8343887 | Maesen et al. | Jan 2013 | B2 |
| 8371741 | Hassan | Feb 2013 | B2 |
| 8372268 | Ginestra et al. | Feb 2013 | B2 |
| 8394254 | Wellington et al. | Mar 2013 | B2 |
| 8394262 | Guichard et al. | Mar 2013 | B2 |
| 8475651 | Milam et al. | Jul 2013 | B2 |
| 8506794 | Bhan et al. | Aug 2013 | B2 |
| 8546626 | Daudin et al. | Oct 2013 | B2 |
| 8563456 | Dillon et al. | Oct 2013 | B2 |
| 8608938 | Wellington et al. | Dec 2013 | B2 |
| 8608946 | Bhan et al. | Dec 2013 | B2 |
| 8613851 | Wellington et al. | Dec 2013 | B2 |
| 8652817 | Milam et al. | Feb 2014 | B2 |
| 8663453 | Wellington et al. | Mar 2014 | B2 |
| 8679319 | Milam et al. | Mar 2014 | B2 |
| 8679322 | Marzin et al. | Mar 2014 | B2 |
| 8702970 | Maesen et al. | Apr 2014 | B2 |
| 8716164 | Dillon et al. | May 2014 | B2 |
| 8721871 | Dindi | May 2014 | B1 |
| 8722558 | Konno et al. | May 2014 | B2 |
| 8722563 | Soled et al. | May 2014 | B2 |
| 8722564 | Soled et al. | May 2014 | B2 |
| 8741129 | Brown et al. | Jun 2014 | B2 |
| 8747659 | Kiss et al. | Jun 2014 | B2 |
| 8764972 | Bhan et al. | Jul 2014 | B2 |
| 8784646 | Sanchez et al. | Jul 2014 | B2 |
| 8795514 | Kimura et al. | Aug 2014 | B2 |
| 8821714 | Chaumonnot et al. | Sep 2014 | B2 |
| 8877040 | Hoehn et al. | Nov 2014 | B2 |
| 8894838 | Dindi et al. | Nov 2014 | B2 |
| 8926826 | Dindi et al. | Jan 2015 | B2 |
| 8946110 | Toledo Antonio et al. | Feb 2015 | B2 |
| 8962514 | Seki et al. | Feb 2015 | B2 |
| 8987537 | Droubi et al. | Mar 2015 | B1 |
| 8999011 | Stern et al. | Apr 2015 | B2 |
| 9057035 | Kraus | Jun 2015 | B1 |
| 9074143 | McGehee et al. | Jul 2015 | B2 |
| 9102884 | Xu et al. | Aug 2015 | B2 |
| 9109176 | Stern et al. | Aug 2015 | B2 |
| 9127215 | Choi et al. | Sep 2015 | B2 |
| 9127218 | Banerjee et al. | Sep 2015 | B2 |
| 9139782 | Dindi et al. | Sep 2015 | B2 |
| 9206363 | Woo et al. | Dec 2015 | B2 |
| 9212323 | Dindi et al. | Dec 2015 | B2 |
| 9216407 | Duma et al. | Dec 2015 | B2 |
| 9234145 | Banerjee et al. | Jan 2016 | B2 |
| 9260671 | Shafi et al. | Feb 2016 | B2 |
| 9278339 | Bellussi et al. | Mar 2016 | B2 |
| 9340733 | Marchand et al. | May 2016 | B2 |
| 9359561 | Bazer-Bachi et al. | Jun 2016 | B2 |
| 9365781 | Dindi | Jun 2016 | B2 |
| 9365782 | Dindi et al. | Jun 2016 | B2 |
| 9387466 | Rana et al. | Jul 2016 | B2 |
| 9434893 | Dufresne | Sep 2016 | B2 |
| 9458396 | Weiss | Oct 2016 | B2 |
| 9487718 | Kraus et al. | Nov 2016 | B2 |
| 9499758 | Droubi et al. | Nov 2016 | B2 |
| 9512319 | Chatron-Michuad et al. | Dec 2016 | B2 |
| 9540573 | Bhan | Jan 2017 | B2 |
| 9546327 | Krasu et al. | Jan 2017 | B2 |
| 9605215 | Lott et al. | Mar 2017 | B2 |
| 9624448 | Joo et al. | Apr 2017 | B2 |
| 9650312 | Baldassari et al. | May 2017 | B2 |
| 9650580 | Merdrignac et al. | May 2017 | B2 |
| 9657236 | Yang et al. | May 2017 | B2 |
| 9675968 | Alonso Nunez et al. | Jun 2017 | B2 |
| 9737883 | Yamane et al. | Aug 2017 | B2 |
| 9803152 | Kar | Oct 2017 | B2 |
| 9896630 | Weiss et al. | Feb 2018 | B2 |
| 9908105 | Duma et al. | Mar 2018 | B2 |
| 9908107 | Osaki et al. | Mar 2018 | B2 |
| 9919293 | Rana et al. | Mar 2018 | B1 |
| 9920270 | Robinson et al. | Mar 2018 | B2 |
| 10072221 | Bazer-Bachi et al. | Sep 2018 | B2 |
| 10138438 | Van Houten | Nov 2018 | B2 |
| 10144882 | Dindi et al. | Dec 2018 | B2 |
| 10150930 | Van Houten | Dec 2018 | B2 |
| 10260009 | Ackerson et al. | Apr 2019 | B2 |
| 10308884 | Klussman et al. | Jun 2019 | B2 |
| 10443006 | Fruchey et al. | Oct 2019 | B1 |
| 10501699 | Robinson et al. | Dec 2019 | B2 |
| 10518251 | Matsushita et al. | Dec 2019 | B2 |
| 10533141 | Moore et al. | Jan 2020 | B2 |
| 10563133 | Moore et al. | Feb 2020 | B2 |
| 10584287 | Klussman et al. | Mar 2020 | B2 |
| 10597591 | Weiss et al. | Mar 2020 | B2 |
| 10597594 | Fruchey et al. | Mar 2020 | B1 |
| 10604709 | Moore et al. | Mar 2020 | B2 |
| 10640718 | Wohaibi et al. | May 2020 | B2 |
| 10668451 | Boualleg et al. | Jun 2020 | B2 |
| 10683461 | Wohaibi et al. | Jun 2020 | B2 |
| 10876053 | Klussmann et al. | Jun 2020 | B2 |
| 10717938 | Ackerson et al. | Jul 2020 | B2 |
| 10760020 | Kashio et al. | Sep 2020 | B2 |
| 10800982 | Peer et al. | Oct 2020 | B2 |
| 10870804 | Wohaibi et al. | Dec 2020 | B2 |
| 10883056 | Wohaibi et al. | Jan 2021 | B2 |
| 10899983 | Kar et al. | Jan 2021 | B1 |
| 10920160 | Wohaibi et al. | Feb 2021 | B2 |
| 10954456 | Moore et al. | Mar 2021 | B2 |
| 10961468 | Moore et al. | Mar 2021 | B2 |
| 10995290 | Anderson et al. | May 2021 | B2 |
| 11001768 | Liu et al. | May 2021 | B2 |
| 11015133 | Wohaibi et al. | May 2021 | B2 |
| 11015134 | Wohaibi et al. | May 2021 | B2 |
| 11118120 | Brown et al. | Sep 2021 | B2 |
| 11118122 | Ramaseshan et al. | Sep 2021 | B2 |
| 11124714 | Eller et al. | Sep 2021 | B2 |
| 11149217 | Marques et al. | Oct 2021 | B2 |
| 11168264 | Brahem et al. | Nov 2021 | B2 |
| 11203724 | Pereira Almao et al. | Dec 2021 | B2 |
| 11236281 | Rogel et al. | Feb 2022 | B2 |
| 11261387 | Wei et al. | Mar 2022 | B2 |
| 11345865 | Zhang et al. | May 2022 | B2 |
| 11384301 | Eller et al. | Jul 2022 | B2 |
| 11396633 | Kar et al. | Jul 2022 | B2 |
| 11421166 | Weiss et al. | Aug 2022 | B2 |
| 11459514 | Pupat | Oct 2022 | B2 |
| 11466222 | Markkanen | Oct 2022 | B2 |
| 20010001036 | Espeillac et al. | May 2001 | A1 |
| 20010013484 | Zeuthen et al. | Aug 2001 | A1 |
| 20020037806 | Dufresne et al. | Mar 2002 | A1 |
| 20020045540 | Bartholdy | Apr 2002 | A1 |
| 20020056664 | Chabot | May 2002 | A1 |
| 20020070147 | Sonnemans et al. | Jun 2002 | A1 |
| 20020117426 | Holder | Aug 2002 | A1 |
| 20020144932 | Gong et al. | Oct 2002 | A1 |
| 20020148757 | Huff et al. | Oct 2002 | A1 |
| 20020157990 | Feimer et al. | Oct 2002 | A1 |
| 20020195375 | Chapus et al. | Dec 2002 | A1 |
| 20030042172 | Sharivker et al. | Mar 2003 | A1 |
| 20030125198 | Ginestra et al. | Jul 2003 | A1 |
| 20030131526 | Kresnyak et al. | Jul 2003 | A1 |
| 20030146133 | Nagamatsu et al. | Aug 2003 | A1 |
| 20030217951 | Marchal-George et al. | Nov 2003 | A1 |
| 20040007501 | Sughrue et al. | Jan 2004 | A1 |
| 20040020829 | Magna et al. | Feb 2004 | A1 |
| 20040040890 | Morton et al. | Mar 2004 | A1 |
| 20040055934 | Tromeur et al. | Mar 2004 | A1 |
| 20040134837 | Dassori | Jul 2004 | A1 |
| 20040178117 | Morton et al. | Sep 2004 | A1 |
| 20040186014 | Tsukada et al. | Sep 2004 | A1 |
| 20040209771 | Abe et al. | Oct 2004 | A1 |
| 20040232041 | Kiser et al. | Nov 2004 | A1 |
| 20040256293 | Abe et al. | Dec 2004 | A1 |
| 20050020446 | Choudhary et al. | Jan 2005 | A1 |
| 20050101480 | Ackerman et al. | May 2005 | A1 |
| 20050109674 | Klein | May 2005 | A1 |
| 20050113250 | Schleicher et al. | May 2005 | A1 |
| 20050133405 | Wellington et al. | Jun 2005 | A1 |
| 20050133406 | Wellington et al. | Jun 2005 | A1 |
| 20050133411 | Zeuthen et al. | Jun 2005 | A1 |
| 20050133416 | Bhan et al. | Jun 2005 | A1 |
| 20050133417 | Bhan et al. | Jun 2005 | A1 |
| 20050135997 | Wellington et al. | Jun 2005 | A1 |
| 20050139512 | Wellington et al. | Jun 2005 | A1 |
| 20050139520 | Bhan et al. | Jun 2005 | A1 |
| 20050139522 | Bhan et al. | Jun 2005 | A1 |
| 20050145537 | Wellington et al. | Jul 2005 | A1 |
| 20050145538 | Wellington et al. | Jul 2005 | A1 |
| 20050145543 | Bhan et al. | Jul 2005 | A1 |
| 20050148487 | Brownscombe et al. | Jul 2005 | A1 |
| 20050150156 | Karas et al. | Jul 2005 | A1 |
| 20050150818 | Bhan et al. | Jul 2005 | A1 |
| 20050155906 | Wellington et al. | Jul 2005 | A1 |
| 20050167321 | Wellington et al. | Aug 2005 | A1 |
| 20050167327 | Bhan et al. | Aug 2005 | A1 |
| 20050167328 | Bhan et al. | Aug 2005 | A1 |
| 20050167329 | Bhan et al. | Aug 2005 | A1 |
| 20050167331 | Bhan et al. | Aug 2005 | A1 |
| 20050269245 | Huve | Dec 2005 | A1 |
| 20060052235 | Bai et al. | Mar 2006 | A1 |
| 20060060501 | Gauthier et al. | Mar 2006 | A1 |
| 20060060509 | Miyauchi et al. | Mar 2006 | A1 |
| 20060060510 | Bhan | Mar 2006 | A1 |
| 20060102522 | Turaga et al. | May 2006 | A1 |
| 20060115392 | Dassori | Jun 2006 | A1 |
| 20060175229 | Montanari et al. | Aug 2006 | A1 |
| 20060211900 | Iki et al. | Sep 2006 | A1 |
| 20060231456 | Bhan | Oct 2006 | A1 |
| 20060231465 | Bhan | Oct 2006 | A1 |
| 20060234876 | Bhan | Oct 2006 | A1 |
| 20060234877 | Bhan | Oct 2006 | A1 |
| 20060249429 | Iki et al. | Nov 2006 | A1 |
| 20060281638 | Zaid et al. | Dec 2006 | A1 |
| 20060289340 | Brownscombe et al. | Dec 2006 | A1 |
| 20070000808 | Bhan et al. | Jan 2007 | A1 |
| 20070000810 | Bhan et al. | Jan 2007 | A1 |
| 20070012595 | Brownscombe et al. | Jan 2007 | A1 |
| 20070072765 | Soled et al. | Mar 2007 | A1 |
| 20070084753 | Iki et al. | Apr 2007 | A1 |
| 20070105714 | Turaga et al. | May 2007 | A1 |
| 20070108098 | Flint et al. | May 2007 | A1 |
| 20070131584 | Kalnes | Jun 2007 | A1 |
| 20070138055 | Farshid et al. | Jun 2007 | A1 |
| 20070170096 | Shan et al. | Jul 2007 | A1 |
| 20070175797 | Iki et al. | Aug 2007 | A1 |
| 20070284285 | Stepanik et al. | Dec 2007 | A1 |
| 20080017551 | Kiriyama et al. | Jan 2008 | A1 |
| 20080047875 | Karas et al. | Feb 2008 | A1 |
| 20080073247 | Bolshakov et al. | Mar 2008 | A1 |
| 20080085225 | Bhan et al. | Apr 2008 | A1 |
| 20080135453 | Bhan | Jun 2008 | A1 |
| 20080149531 | Roy-Auberger et al. | Jun 2008 | A1 |
| 20080167180 | Van Den Brink et al. | Jul 2008 | A1 |
| 20080210595 | Bolshakov et al. | Sep 2008 | A1 |
| 20080223755 | Roy-Auberger et al. | Sep 2008 | A1 |
| 20080230440 | Graham et al. | Sep 2008 | A1 |
| 20080245700 | Wellington et al. | Oct 2008 | A1 |
| 20080245702 | Wellington et al. | Oct 2008 | A1 |
| 20080262115 | Calis et al. | Oct 2008 | A1 |
| 20080272027 | Wellington et al. | Nov 2008 | A1 |
| 20080272028 | Wellington et al. | Nov 2008 | A1 |
| 20080308459 | Iki et al. | Dec 2008 | A1 |
| 20090048097 | Jones et al. | Feb 2009 | A1 |
| 20090057194 | Farshid et al. | Mar 2009 | A1 |
| 20090057197 | Bhan et al. | Mar 2009 | A1 |
| 20090062590 | Nadler et al. | Mar 2009 | A1 |
| 20090114569 | Osaheni et al. | May 2009 | A1 |
| 20090134064 | Reynolds | May 2009 | A1 |
| 20090139902 | Kressmann et al. | Jun 2009 | A1 |
| 20090166260 | Roy-Auberger et al. | Jul 2009 | A1 |
| 20090178951 | Balthasar et al. | Jul 2009 | A1 |
| 20090230022 | Gorbaty et al. | Sep 2009 | A1 |
| 20090234166 | Gorbaty et al. | Sep 2009 | A1 |
| 20090255850 | Bhan et al. | Oct 2009 | A1 |
| 20090255851 | Bhan et al. | Oct 2009 | A1 |
| 20090275788 | Bedard et al. | Nov 2009 | A1 |
| 20090283444 | Bhan et al. | Nov 2009 | A1 |
| 20090288987 | Bhan et al. | Nov 2009 | A1 |
| 20090288989 | Wellington et al. | Nov 2009 | A1 |
| 20090308791 | Bhan et al. | Dec 2009 | A1 |
| 20090308812 | Osaheni et al. | Dec 2009 | A1 |
| 20090314686 | Zimmerman | Dec 2009 | A1 |
| 20100006475 | Ginestra | Jan 2010 | A1 |
| 20100018902 | Brownscombe et al. | Jan 2010 | A1 |
| 20100025291 | Shafi et al. | Feb 2010 | A1 |
| 20100044274 | Brun et al. | Feb 2010 | A1 |
| 20100055005 | Bhan et al. | Mar 2010 | A1 |
| 20100098602 | Bhan et al. | Apr 2010 | A1 |
| 20100155301 | Guichard et al. | Jun 2010 | A1 |
| 20100200463 | Patron et al. | Aug 2010 | A1 |
| 20100213103 | Patron et al. | Aug 2010 | A1 |
| 20100243526 | Ginestra et al. | Sep 2010 | A1 |
| 20100243532 | Myers et al. | Sep 2010 | A1 |
| 20100264067 | Osaheni et al. | Oct 2010 | A1 |
| 20100294698 | e Mello et al. | Nov 2010 | A1 |
| 20100326890 | Bhan | Dec 2010 | A1 |
| 20110017637 | Reynolds et al. | Jan 2011 | A1 |
| 20110079542 | Ellis et al. | Apr 2011 | A1 |
| 20110083997 | Silva et al. | Apr 2011 | A1 |
| 20110094938 | Morel | Apr 2011 | A1 |
| 20110108461 | Gabrielov et al. | May 2011 | A1 |
| 20110127194 | Zhang et al. | Jun 2011 | A1 |
| 20110155558 | Cardoso et al. | Jun 2011 | A1 |
| 20110155644 | Bhattacharyya et al. | Jun 2011 | A1 |
| 20110174681 | Milam et al. | Jul 2011 | A1 |
| 20110178346 | Milam et al. | Jul 2011 | A1 |
| 20110186477 | Milam et al. | Aug 2011 | A1 |
| 20110186480 | Milam et al. | Aug 2011 | A1 |
| 20110203971 | Kiss et al. | Aug 2011 | A1 |
| 20110218097 | Rayo Mayoral et al. | Sep 2011 | A1 |
| 20110240517 | Chornet et al. | Oct 2011 | A1 |
| 20110277377 | Novak et al. | Nov 2011 | A1 |
| 20120018352 | Seki et al. | Jan 2012 | A1 |
| 20120103868 | Dindi et al. | May 2012 | A1 |
| 20120116145 | Bhan et al. | May 2012 | A1 |
| 20120145528 | Myers et al. | Jun 2012 | A1 |
| 20120175285 | Bhan et al. | Jul 2012 | A1 |
| 20120175286 | Bhan et al. | Jul 2012 | A1 |
| 20120181219 | Seki et al. | Jul 2012 | A1 |
| 20130037447 | Zimmerman | Feb 2013 | A1 |
| 20130081977 | Woo et al. | Apr 2013 | A1 |
| 20130105357 | Bhan | May 2013 | A1 |
| 20130105364 | Bhan | May 2013 | A1 |
| 20130126393 | Ginestra et al. | May 2013 | A1 |
| 20130171039 | Graham et al. | Jul 2013 | A1 |
| 20130186806 | Diehl et al. | Jul 2013 | A1 |
| 20130225400 | Liang et al. | Aug 2013 | A1 |
| 20130256190 | Van Wees et al. | Oct 2013 | A1 |
| 20130267409 | Lee et al. | Oct 2013 | A1 |
| 20130277273 | Mazyar | Oct 2013 | A1 |
| 20130288885 | Domokos et al. | Oct 2013 | A1 |
| 20130306517 | Kester et al. | Nov 2013 | A1 |
| 20130319910 | Koseoglu | Dec 2013 | A1 |
| 20140001089 | Bazer-Bachi | Jan 2014 | A1 |
| 20140027351 | Bazer-Bachi et al. | Jan 2014 | A1 |
| 20140061094 | Xu et al. | Mar 2014 | A1 |
| 20140073821 | Mitsui et al. | Mar 2014 | A1 |
| 20140076783 | Bhan | Mar 2014 | A1 |
| 20140097125 | Bazer-Bachi et al. | Apr 2014 | A1 |
| 20140166540 | Guichard et al. | Jun 2014 | A1 |
| 20140174980 | Brown et al. | Jun 2014 | A1 |
| 20140174983 | Klein et al. | Jun 2014 | A1 |
| 20140183098 | Cooper et al. | Jul 2014 | A1 |
| 20140183099 | Ginestra et al. | Jul 2014 | A1 |
| 20140291201 | Banerjee et al. | Oct 2014 | A1 |
| 20140291203 | Molinari et al. | Oct 2014 | A1 |
| 20140299515 | Weiss et al. | Oct 2014 | A1 |
| 20140305843 | Kraus et al. | Oct 2014 | A1 |
| 20140315712 | Smegal | Oct 2014 | A1 |
| 20140323779 | Alphazan et al. | Oct 2014 | A1 |
| 20140326642 | Tanaka et al. | Nov 2014 | A1 |
| 20140332444 | Weiss et al. | Nov 2014 | A1 |
| 20140353210 | Graham et al. | Dec 2014 | A1 |
| 20150057205 | Morishima et al. | Feb 2015 | A1 |
| 20150108039 | Bhan | Apr 2015 | A1 |
| 20150111726 | Bhan et al. | Apr 2015 | A1 |
| 20150144531 | Ginstra et al. | May 2015 | A1 |
| 20150144532 | He et al. | May 2015 | A1 |
| 20150217261 | Norling | Aug 2015 | A1 |
| 20150224476 | Plecha et al. | Aug 2015 | A1 |
| 20150240174 | Kraus et al. | Aug 2015 | A1 |
| 20150315480 | Hanks et al. | Nov 2015 | A1 |
| 20150321177 | Rana et al. | Nov 2015 | A1 |
| 20150337225 | Droubi et al. | Nov 2015 | A1 |
| 20150337226 | Droubi et al. | Nov 2015 | A1 |
| 20150344791 | Banerjee et al. | Dec 2015 | A1 |
| 20150353848 | Patron | Dec 2015 | A1 |
| 20150353851 | Buchanan | Dec 2015 | A1 |
| 20160001272 | Daudin | Jan 2016 | A1 |
| 20160017240 | Duma et al. | Jan 2016 | A1 |
| 20160024396 | Zink et al. | Jan 2016 | A1 |
| 20160060549 | Ancheyta Juarez et al. | Mar 2016 | A1 |
| 20160074840 | Duma et al. | Mar 2016 | A1 |
| 20160075954 | Monson et al. | Mar 2016 | A1 |
| 20160122666 | Weiss et al. | May 2016 | A1 |
| 20160129428 | Bhan | May 2016 | A1 |
| 20160145503 | Xu et al. | May 2016 | A1 |
| 20160145508 | Xu et al. | May 2016 | A1 |
| 20160145509 | Mukherjee et al. | May 2016 | A1 |
| 20160152901 | Dufresne | Jun 2016 | A1 |
| 20160160139 | Robinson | Jun 2016 | A1 |
| 20160177205 | Evans et al. | Jun 2016 | A1 |
| 20160200990 | Mori et al. | Jul 2016 | A1 |
| 20160220985 | Osaki et al. | Aug 2016 | A1 |
| 20160220986 | Osaki et al. | Aug 2016 | A1 |
| 20160230102 | Osaki et al. | Aug 2016 | A1 |
| 20160243528 | He et al. | Aug 2016 | A1 |
| 20160250622 | He et al. | Sep 2016 | A1 |
| 20160256856 | Kester et al. | Sep 2016 | A1 |
| 20160264887 | Davydov | Sep 2016 | A1 |
| 20160304794 | Majcher et al. | Oct 2016 | A1 |
| 20160312130 | Merdrignac | Oct 2016 | A1 |
| 20160340597 | Baldassari et al. | Nov 2016 | A1 |
| 20160348012 | Zhao et al. | Dec 2016 | A1 |
| 20160348013 | Ladkat et al. | Dec 2016 | A1 |
| 20160362615 | Ancheyta Juarez et al. | Dec 2016 | A1 |
| 20170002273 | Rubin-Pitel et al. | Jan 2017 | A1 |
| 20170002279 | Brown et al. | Jan 2017 | A1 |
| 20170009163 | Kraus et al. | Jan 2017 | A1 |
| 20170022433 | Brown et al. | Jan 2017 | A1 |
| 20170029723 | Bazer-Bachi et al. | Feb 2017 | A1 |
| 20170037325 | Ackerson et al. | Feb 2017 | A1 |
| 20170044451 | Kar | Feb 2017 | A1 |
| 20170058205 | Ho et al. | Mar 2017 | A1 |
| 20170058223 | Droubi et al. | Mar 2017 | A1 |
| 20170066979 | Lei et al. | Mar 2017 | A1 |
| 20170073592 | Nonaka et al. | Mar 2017 | A1 |
| 20170120224 | Boualleg et al. | May 2017 | A1 |
| 20170120228 | Boualleg et al. | May 2017 | A1 |
| 20170120229 | Boualleg et al. | May 2017 | A1 |
| 20170121612 | Boualleg et al. | May 2017 | A1 |
| 20170128912 | Boualleg et al. | May 2017 | A1 |
| 20170136446 | Carati et al. | May 2017 | A1 |
| 20170137725 | Boualleg et al. | May 2017 | A1 |
| 20170165639 | Klein et al. | Jun 2017 | A1 |
| 20170175012 | Schleiffer et al. | Jun 2017 | A1 |
| 20170183575 | Rubin-Pitel et al. | Jun 2017 | A1 |
| 20170183582 | Hoehn et al. | Jun 2017 | A1 |
| 20170192126 | Koseoglu | Jul 2017 | A1 |
| 20170232414 | Hassan | Aug 2017 | A1 |
| 20170260463 | Schleiffer et al. | Sep 2017 | A1 |
| 20170267937 | Schleiffer et al. | Sep 2017 | A1 |
| 20170306250 | Ginestra | Oct 2017 | A1 |
| 20170306252 | Malek Abbaslou et al. | Oct 2017 | A1 |
| 20170335206 | Mukherjee et al. | Nov 2017 | A1 |
| 20170349846 | Ding et al. | Dec 2017 | A1 |
| 20170355913 | Mountainland et al. | Dec 2017 | A1 |
| 20170355914 | Weiss et al. | Dec 2017 | A1 |
| 20170362514 | Hanks et al. | Dec 2017 | A1 |
| 20180016505 | Matsushita | Jan 2018 | A1 |
| 20180104676 | Yamane et al. | Apr 2018 | A1 |
| 20180134965 | Brown et al. | May 2018 | A1 |
| 20180134972 | Brown et al. | May 2018 | A1 |
| 20180134974 | Weiss et al. | May 2018 | A1 |
| 20180147567 | Matsushita et al. | May 2018 | A1 |
| 20180154340 | Boualleg et al. | Jun 2018 | A1 |
| 20180155647 | Robinson et al. | Jun 2018 | A1 |
| 20180195013 | Dreillard et al. | Jul 2018 | A1 |
| 20180207622 | Boualleg et al. | Jul 2018 | A1 |
| 20180230387 | Moore et al. | Aug 2018 | A1 |
| 20180230388 | Li et al. | Aug 2018 | A1 |
| 20180230389 | Moore et al. | Aug 2018 | A1 |
| 20180251690 | Mountainland et al. | Sep 2018 | A1 |
| 20180291291 | Brown et al. | Oct 2018 | A1 |
| 20180340126 | Klussman et al. | Nov 2018 | A1 |
| 20180346828 | Liu et al. | Dec 2018 | A1 |
| 20180355263 | Moore et al. | Dec 2018 | A1 |
| 20180371343 | Rubin-Patel et al. | Dec 2018 | A1 |
| 20190002772 | Moore et al. | Jan 2019 | A1 |
| 20190010405 | Moore et al. | Jan 2019 | A1 |
| 20190010406 | Moore et al. | Jan 2019 | A1 |
| 20190010407 | Moore et al. | Jan 2019 | A1 |
| 20190010408 | Moore et al. | Jan 2019 | A1 |
| 20190016972 | Moore et al. | Jan 2019 | A1 |
| 20190016974 | Moore et al. | Jan 2019 | A1 |
| 20190040329 | Moore et al. | Feb 2019 | A1 |
| 20190078027 | Deimund | Mar 2019 | A1 |
| 20190093026 | Wohaibi et al. | Mar 2019 | A1 |
| 20190136144 | Wohaibi et al. | May 2019 | A1 |
| 20190153340 | Weiss et al. | May 2019 | A1 |
| 20190153942 | Wohaibi et al. | May 2019 | A1 |
| 20190185772 | Berkhous et al. | Jun 2019 | A1 |
| 20190203130 | Mukherjee | Jul 2019 | A1 |
| 20190233732 | Sun | Aug 2019 | A1 |
| 20190233741 | Moore et al. | Aug 2019 | A1 |
| 20190256784 | Klussman et al. | Aug 2019 | A1 |
| 20190300806 | Kashio et al. | Oct 2019 | A1 |
| 20190338203 | Umansky et al. | Nov 2019 | A1 |
| 20190338205 | Ackerson et al. | Nov 2019 | A1 |
| 20190382668 | Klussmann et al. | Dec 2019 | A1 |
| 20200095508 | Moore et al. | Mar 2020 | A1 |
| 20200095509 | Moore et al. | Mar 2020 | A1 |
| 20200123458 | Moore et al. | Apr 2020 | A1 |
| 20200131443 | Moore et al. | Apr 2020 | A1 |
| 20200131446 | Wohaibi et al. | Apr 2020 | A1 |
| 20200131447 | Wohaibi et al. | Apr 2020 | A1 |
| 20200140765 | Moore et al. | May 2020 | A1 |
| 20200172819 | Wohaibi et al. | Jun 2020 | A1 |
| 20200172820 | Wohaibi et al. | Jun 2020 | A1 |
| 20200199462 | Klussman et al. | Jun 2020 | A1 |
| 20200199463 | Klussman et al. | Jun 2020 | A1 |
| 20200199465 | Wohaibi et al. | Jun 2020 | A1 |
| 20200199466 | Wohaibi et al. | Jun 2020 | A1 |
| 20200199467 | Wohaibi et al. | Jun 2020 | A1 |
| 20200216766 | Wohaibi et al. | Jul 2020 | A1 |
| 20200224108 | Moore et al. | Jul 2020 | A1 |
| 20200231886 | Kraus et al. | Jul 2020 | A1 |
| 20200248080 | Peer et al. | Aug 2020 | A1 |
| 20200291317 | Anderson et al. | Sep 2020 | A1 |
| 20200339894 | Marques et al. | Oct 2020 | A1 |
| 20200385644 | Rogel et al. | Dec 2020 | A1 |
| 20210017458 | Wohaibi et al. | Jan 2021 | A1 |
| 20210017459 | Wohaibi et al. | Jan 2021 | A1 |
| 20210017460 | Wohaibi et al. | Jan 2021 | A1 |
| 20210017461 | Wohaibi et al. | Jan 2021 | A1 |
| 20210024838 | Wohaibi et al. | Jan 2021 | A1 |
| 20210024839 | Wohaibi et al. | Jan 2021 | A1 |
| 20210024840 | Wohaibi et al. | Jan 2021 | A1 |
| 20210024842 | Fruchey et al. | Jan 2021 | A1 |
| 20210032551 | Wohaibi et al. | Feb 2021 | A1 |
| 20210062096 | Hodgkins et al. | Mar 2021 | A1 |
| 20210102130 | Marques et al. | Apr 2021 | A1 |
| 20210155858 | Koseoglu et al. | May 2021 | A1 |
| 20210238487 | Moore et al. | Aug 2021 | A1 |
| 20210246391 | Anderson et al. | Aug 2021 | A1 |
| 20210253960 | Eller et al. | Aug 2021 | A1 |
| 20210253965 | Woodchick et al. | Aug 2021 | A1 |
| 20210253964 | Eller et al. | Sep 2021 | A1 |
| 20210284919 | Moore et al. | Sep 2021 | A1 |
| 20210292661 | Klussmann et al. | Sep 2021 | A1 |
| 20210363434 | Zhang et al. | Nov 2021 | A1 |
| 20210363444 | Kar et al. | Nov 2021 | A1 |
| 20220073830 | Harada et al. | Mar 2022 | A1 |
| 20220235275 | Iversen et al. | Jul 2022 | A1 |
| 20220411702 | Sarjovaara et al. | Dec 2022 | A1 |
| Number | Date | Country |
|---|---|---|
| 1054130 | May 1979 | CA |
| 1060370 | Aug 1979 | CA |
| 1238005 | Jun 1988 | CA |
| 1248513 | Jan 1989 | CA |
| 1041133 | Oct 2000 | EP |
| 1050572 | Nov 2000 | EP |
| 1052015 | Nov 2000 | EP |
| 2130895 | Dec 2009 | EP |
| 2947133 | Nov 2015 | EP |
| 2992070 | Mar 2016 | EP |
| 2681871 | Apr 1993 | FR |
| 3011004 | Mar 2015 | FR |
| 3011004 | Mar 2015 | FR |
| 3013723 | May 2015 | FR |
| 3013723 | May 2015 | FR |
| 3053356 | Jan 2018 | FR |
| 1324167 | Jul 1973 | GB |
| 1502915 | Mar 1978 | GB |
| 1504586 | Mar 1978 | GB |
| 1505886 | Mar 1978 | GB |
| 2124252 | Feb 1984 | GB |
| 2121252 | Jun 1986 | GB |
| 4801344 | Oct 2011 | JP |
| 2015059220 | Mar 2015 | JP |
| 20200122450 | Aug 2020 | JP |
| 2700705 | Sep 2019 | RU |
| 9113951 | Sep 1991 | WO |
| 9820969 | May 1998 | WO |
| 9820969 | May 1998 | WO |
| 0197971 | Dec 2001 | WO |
| 0209870 | Feb 2002 | WO |
| 2004052534 | Jun 2004 | WO |
| 2004053028 | Jun 2004 | WO |
| 2005028596 | Mar 2005 | WO |
| 2005063933 | Jul 2005 | WO |
| 2009001314 | Dec 2008 | WO |
| 2011071705 | Jun 2011 | WO |
| 2013083662 | Jun 2013 | WO |
| 2014096703 | Jun 2014 | WO |
| 2014096703 | Jun 2014 | WO |
| 2014096704 | Jun 2014 | WO |
| 2014177424 | Nov 2014 | WO |
| 2015034521 | Mar 2015 | WO |
| 2015147222 | Oct 2015 | WO |
| 2015147223 | Oct 2015 | WO |
| 2017168312 | Oct 2017 | WO |
| 2018073018 | Apr 2018 | WO |
| 2018075017 | Apr 2018 | WO |
| WO-2018073018 | Apr 2018 | WO |
| 2018053323 | Mar 2019 | WO |
| 2019104243 | May 2019 | WO |
| 2019125674 | Jun 2019 | WO |
| 2019133880 | Jul 2019 | WO |
| 2019178701 | Sep 2019 | WO |
| 2020262078 | Dec 2020 | WO |
| 2021066265 | Apr 2021 | WO |
| Entry |
|---|
| A. M. Aitani, M.F. Ali, H.H. Al-Ali, “A Review of Non-Conventional Methods for the Desulfurization of Residual Fuel Oil”, Petroleum Science and Technology, 2000 18:5-6, 537-553, Marcel Dekker Inc. New York, New York USA. |
| Daniel Monzon, et al. “Petroleum refiners and shippers struggle over marine fuel”, Author D Little opinion/ position paper, May 9, 2017, pp. 1-4, Arthur D. Little, https://www.adlittle.com/sites/default/files/viewpoints/adl_petroleum_refiners_and_shippers_struggle_over_marine_fuel.pdf. |
| Gulam Gaush Zeelani, et al. “Catalystic Oxidative Desulfurization of Liquid Fuel: A Review”, International Research Journal of Engineering and Technology, May 2016 pp. 331-336, vol. 3; Issue 5, Fast Track Publications, Tamilnadu, India. |
| Kristin Rist Sorheim et al. “Characterization of Low Sulfur Fuel Oils (LSFO)—A new generation of marine fuel oils”, Oct. 7, 2020, pp. 1-22 , Report No. OC2020 A-050, Project No. 302004929, Version 3.1, SINTEF Ocean AS, Trondheim, Norway. |
| S. Brynolf et al. “Compliance possibilities for the future ECA regulations through the use of abatement technologies or change of fuels”, Transportation Research Part D May 2014, pp. 6-18, vol. 28, Elsevier Ltd. London United Kingdom. |
| Alun Lewis, “Composition, Properties and Classification of Heavy Fuel Oils” Third R&D Forum on High-density Oil Spill Response, Mar. 11, 2002, pp. 11-25, Intype, London United Kingdom. |
| Tong-Rong Ling et al. “Desulfurization of Vacuum Gasoil by MCM-41 Supported Molybdenum-Nickel”, Ind. Eng. Chem. Res. Jan. 14, 2009, vol. 48, pp. 1797-1803, American Chemical Society. |
| S.K. Maity et al. “Early Stage Deactivation of Heavy Crude Oil Hydroprocessing Catalysts”, Fuel, vol. 100 (Nov. 23, 2011), pp. 17-23, Elsevier Ltd. London United Kingdom. |
| Kevin Cullinane et al. “Emission Control Areas and Their Impact on Maritime Transport”, Transportation Research Part D May 2014, pp. 1-5, vol. 28, Elsevier Ltd. London United Kingdom. |
| Selma Brynolf, “Environmental Assessment of Present and Future Marine Fuels”, Thesis for the Degree of Doctor of Philosophy, 2014, pp. 1-105, Department of Shipping and Marine Technology, Chalmers University of Technology SE-412 96 Gothenburg, Sweden. |
| Alexey Y. Kirgizov, et al. “Ex Situ Upgrading of Extra Heavy Oil: The Effect of Pore Shape of Co—Mo/—Al2O3 Catalysts”, Catalysts Oct. 18, 2022, vol. 12, pp. 1271-1284, MDPI, Basel Switzerland https://doi.org/10.3390/catal12101271. |
| Sundaramurthy Vedachalam, et al., “Hydrotreating and oxidative desulfurization of heavy fuel oil into low sulfur marine fuel over dual function NiMo/γAl2O3 catalyst” Catalysis Today. Vol. 407 (2023) pp. 165-171, available on-line Jan. 19, 2022, Elsevier Ltd. London United Kingdom. |
| Susana Trasobares, et al., “Kinetics of Conradson Carbon Residue Conversion in the Catalytic Hydroprocessing of a Maya Residue”, Ind. Eng. Chem. Res. Jan. 5, 1998, vol. 37, pp. 11-17, American Chemical Society. |
| Jiang Zongxuan, et al., “Oxidative Desulfurization of Fuel Oils”, Chin. J. Catal., 2011, vol. 32: pp. 707-715. Elsevier Ltd. London United Kingdom. |
| Sara Houda, et al., “Oxidative Desulfurization of Heavy Oils with High Sulfur Content: A Review”, Catalysts Aug. 23, 2018, vol. 8, pp. 344-370. MDPI, Basel Switzerland , www.mdpi.com/journal/catalysts. |
| Fawzi M. Elfghi & N.A.S.Amin, “Parametric Study of Hydrodesulfurization and Hydrodearomatization of Gasoil in Hydrotreating Process of Over CoMo—S Catalyst Using a Pilot Plant Integral Reactor”, Jurnal Teknologi, Dec. 2011, vol. 56, pp. 53-73. Penerbit UTM Press, Universiti Teknologi Malaysia. |
| Jose Luis Garcia-Gutierrez, et al., “R & D in Oxidative Desulfurization of Fuels Technologies: From Chemistry to Patents”, Recent Patents on Chemical Engineering, Dec. 2012, vol. 5, pp. 174-196. |
| Antoine Halff, et al., “The likely implications of the new IMO standards on the shipping industry”, Energy Policy, Nov. 2018, vol. 126, pp. 277-286, Elsevier Ltd. London United Kingdom. |
| S. Houda, et al., “Ultrasound assisted oxidative desulfurization of marine fuels on MoO3/Al2O3 catalyst” Catalysis Today, Oct. 17, 2020, vol. 377, pp. 221-228, Elsevier Ltd. London United Kingdom. |
| James G. Speight, The Desulfurization of Heavy Oils and Residua, 2nd Ed. 1999, Chapter 5, pp. 168-205, Marcel Dekker Inc. New York NY US. |
| James G. Speight, The Desulfurization of Heavy Oils and Residua, 2nd Ed. 1999, Chapter 6, pp. 206-253, Marcel Dekker Inc. New York NY US. |
| James G. Speight, The Desulfurization of Heavy Oils and Residua, 2nd Ed. 1999, Chapter 8, pp. 302-334, Marcel Dekker Inc. New York NY US. |
| James G. Speight, The Desulfurization of Heavy Oils and Residua, 2nd Ed. 1999, Chapter 9, pp. 335-385, Marcel Dekker Inc. New York NY US. |
| International Search Report issued in corresponding International Application No. PCT/US2018/017855 dated Apr. 27, 2018 (3 pages). |
| International Search Report issued in corresponding International Application No. PCT/US2018/017863 dated Apr. 27, 2018 (3 pages). |
| Tesoro Refining & Marketing Co. Material Safety Data Sheet—Fuel Oil, pp. 1-10, Jul. 26, 2012, San Antonio, Texas, US. |
| Tesoro Refining & Marketing Co. Material Safety Data Sheet—Marine Gas Oil, pp. 1-11, Nov. 17, 2012, San Antonio, Texas, US. |
| Tesoro Refining & Marketing Co. Material Safety Data Sheet—Resid pp. 1-10, Apr. 6, 2015, San Antonio, Texas, US. |
| Coutrymark Refining and Logistics, LLC, Material Safety Data Sheet—No. 6 Fuel Oil, Dec. 2012, pp. 1-4, Mt. Vernon, Indiana US. |
| Valero Marekting & Supply Company, Material Safety Data Sheet—Residual Fuel Oil, Dec. 4, 2010, pp. 1-14, San Antonio, Texas US. |
| Oceanbat SA. Material Safety Data Sheet—Marine Fuel Oil, Jul. 2013, pp. 1-7, Guayaquil Ecuador. |
| ExxonMobilCorporation, Material Safety Data Sheet—Marine Fuel Oil, pp. 1-12, Sep. 18, 2013, Fairfax Virginia US. |
| Shell Trading (US) Company, Material Safety Data Sheet—Ultra Low Sulfur Fuel Oil, pp. 1-21, Jun. 19, 2018, Houston, Texas US. |
| Suncor Energy Inc., Material Safety Data Sheet—Heating Fuel Oil Type 6 / Residual Marine Fuel, pp. 1-11, Jun. 7, 2018, Calgary Alberta Canada. |
| Marathon Petroleum Company LP, Material Safety Data Sheet—Marathon No. 6 Fuel Oil, Dec. 7, 2010, pp. 1-14., Findlay, Ohio US. |
| BP Australia Pty Ltd., Material Safety Data Sheet—BP380 Marine Fuel, Oct. 27, 2011. pp. 1-6, Docklands, Victoria Australia. |
| U.S. Oil & Refining Co., Material Safety Data Sheet—Residual Fuel Oil, Dec. 18, 2008, pp. 1-11. Tacoma, Washington US. |
| American Bureau of Shipping, Publication 31 Notes on Heavy Fuel Oil, 1984, pp. 1-68, Houston Texas US. |
| American Bureau of Shipping, Notes Use of Low Sulphur Marine Fuel for Main and Auxiliary Diesel Engines, Jan. 1, 2010, pp. 1-68, Houston Texas US ( https://www.eagle.org/eagleExternalPortalWEB/ShowProperty/BEA%20Repository/pdfs/Regulatory/Docs/LowSulphurNote_Engine). |
| Shuyi Zhang, Dong Liu, Wenan Deng, Guohe Que, A Review of Slurry-Phase Hydrocracking Heavy Oil Technology, Energy & Fuels, vol. 21, No. 6, Nov. 2007, pp. 3057-3062, American Chemical Society, Washington DC US. |
| Peiman Pourmoghaddam, Susan Davari, Zahra Delavar Moghaddam, A Technical and Economic Assessment of Fuel Oil Hydrotreating Technology for Steam Power Plant SO2 and NOx Emissions Control, Advances in Environmental Technology vol. 2, Issue 1, Accepted Oct. 3, 2016, pp. 45-54, Iranian Research Organization for Science and Technology, Tehran Islamic Republic of Iran. |
| Dawoud Bahzad, Jamal Al-Fadhli, Ayyad Al-Dhafeeri, Ali Abdal, Assessment of Selected Apparent Kinetic Parameters of the HDM and HDS reactions of Two Kuwaiti Residual Oils, Using Two Types of Commercial ARDS Catalysts, Energy & Fuels, vol. 24, Jan. 8, 2010, pp. 1495-1501, American Chemical Society, Washington DC US. |
| A. Marafi, A. Hauser, A Stanislaus, Atmospheric Residual Desulfurization Process for Residual Oil Upgrading: An Investigation of the Effect of Catalyst Type and Operation Severity on Product Oil Quality, Energy & Fuels, vol. 20, Apr. 4, 2006, pp. 1145-1149, American Chemical Society, Washington DC US. |
| M.M. Boduszynki, C.E. Rechsteiner, A.S.G. Shafzadeh, R.M.K. Carlson, Composition and Properties of Heavy Crudes, No. 1998.202 UNITAR Centre for Heavy Crude and Tar Sands, 1998, pp. 1-12, Canada. |
| Gard AS, Bunkers and Bunkering—A selection of articles previously published by Gard AS, Jan. 2014, pp. 1-53, Arendal Norway. |
| Monique B. Vermeire Everything You Need to Know About Marine Fuels, Jun. 2012, pp. 1-32, Ghent Belgium. |
| Chevron Lummus Group, Product web page—RDS / VRDS, 2013-2018, pp. 1-2, http://www.chevrontechnologymarketing.com/CLGtech/rds_vrds.aspx. |
| T.M. Saleh, H. Ismail, J.E.Corbett, R.S. Bali, Commercial Experience in the Operation of Atmospheric Residue Desulfurization Unit in Kuwait national Petroleum Company at Mina Al-Ahmadi Refinery, Catalyst in Petroleum Refining, 1989, pp. 175-189, Elsevier Science Publishers B.V., Amsterdam The Netherlands. |
| Victor S. Semeykina, Ekaterina V. Parkhomchuk, Alexander V. Polukhin, Pavel D. Parunin, Anton I. Lysikov, Artem B. Ayupov, Svetlana V. Cherepanova, Vladislav V. Kanazhevskiy, Vasil V. Kaichev, Tatyana S. Glazneva, Valentina V. Zvereva, CoMoNi Catalyst Texture and Surface Properties in Heavy Oil Processing. Part I: Hierarchical Macro / Mesoporous Alumina Support, Industrial & Engineering Chemistry Research, vol. 55, Feb. 29, 2016, pp. 3535-3545 American Chemical Society, Washington DC US. |
| Victor S. Semeykina, Ekaterina V. Parkhomchuk, Alexander V. Polukhin, Pavel D. Parunin, Anton I. Lysikov, Artem B. Ayupov, Svetlana V. Cherepanova, Vladislav V. Kanazhevskiy, Vasil V. Kaichev, Tatyana S. Glazneva, Valentina V. Zvereva, CoMoNi Catalyst Texture and Surface Properties in Heavy Oil Processing. Part II: Macroporous Sepiolite-Like Mineral, Industrial & Engineering Chemistry Research, vol. 55,Aug. 1, 2016, pp. 9129-9139 American Chemical Society, Washington DC US. |
| Andre Hauser, Abdulazim Marafi, Adel Almutairi, Anthony Stanislaus, Comparative Study of Hydrodemetallization (HDM) Catalyst Aging by Boscan Feed and Kuwait Atmospheric Residue, Energy & Fuels, vol. 22 Aug. 27, 2008, pp. 2952-2932, American Chemical Society, Washington DC US. |
| Criterion Catalysts & Technologies LP, Residue Upgrading Product Information Sheet, pp. 1 & 2, Aug. 2008, Houston Texas US. |
| John-Laurent Tronche, Jelena Grigorjeva, Annie Siebert (editor), How Are Refiners Preparing for 2015 Marine Fuel Spec Changes?, pp. 1-2, Jun. 6, 2014, S&P Global Platts. Houston Texas US. |
| DNV GL Maritime, Hong Kong Requires Ocean-Going Vessels to Comply with 0.50% M/M Sulphur Limit While at Berth, Statutory Update No. 1, Mar. 2015, p. 1, DNV GL Maritime, Hamburg Germany. |
| Mike Stockle, Tina Knight, Impact of Low-Sulphur Bunkers on Refineries, Catalysis 2009, p. 1-7, www.digitalrefining.com/article/1000090, article based on presentation from the Nov. 2008 ERC Annual Meeting, Vienna Austria. |
| Ekaterina V. Parkhomchuk, Anton I. Lysikov, Alexey G. Okunev, Pavel D. Parunin, Victoria S. Semeikina, Artem B. Ayupov, Valentina A. Trunova, Valentin N. Parmon, Meso / Macroporous CoMo Alumina Pellets for Hydrotreating of Heavy Oil, Industrial & Engineering Chemistry Research, vol. 15 Nov. 13, 2013, pp. 17117-17125 American Chemical Society, Washington DC US. |
| Cristian J. Calderon Jorge Ancheyta, Modeling of Slurry-Phase Reactors for Hydrocracking of Heavy Oils, Energy & Fuels, vol. 30 Jan. 28, 2016, pp. 2525-2543, American Chemical Society, Washington DC US. |
| DNV GL Maritime, Notice for Low Sulphur “Hybrid” Fuel Operation, Technical Update No. 3, Mar. 2015, p. 1&2, DNV GL Maritime, Hamburg Germany. |
| Abdul Waheed Bhutto, Rashid Abro, Shurong Goa, Tauqeer Abbas, Xiaochun Chen, Guangren Yu, Oxidative Desulfurization of Fuel Oils Using lonic Liquids: A Review, Journal of the Taiwan Institute of Chemical Engineers, vol. 62, Feb. 28, 2016, pp. 84-97, Elsevier B.V. Amsterdam The Netherlands. |
| I.V. Babich, J.A. Moulijn, Science and Technology of Novel Processes for Deep Desulfurization of Oil Refinery Streams: A Review, Fuel, vol. 82 ,Nov. 14, 2002, pp. 607-631 Elsevier B.V. Amsterdam The Netherlands Published first on the web via fuelfirst.com—http://www.fuelfirst.com. |
| A. Hauser, A. Marafi, A. Stanislaus, A. Al-Adwani, Relation Between Feed Quality and Coke Formation in a Three Stage Atmospheric Residue Desulfurization (ARDS) Process, Energy & Fuels, vol. 19 Feb. 8, 2005, pp. 544-553, American Chemical Society, Washington DC US. |
| A Marafi, H. Al-Bazzaz, M. Al-Marri, F. Maruyama, M. Absi-Halbi, A. Stanislaus, Residual-Oil Hydrotreating Kinetics for graded Catalyst Systems: Effect of Original and Treated Feedstocks, Energy Fuels, vol. 17(5), Jul. 2, 2003 pp. 1191-1197 American Chemical Society, Washington DC US. |
| Hmaza Al-Bazza, Jia-Lin Kang, Dduha Chehadeh, Dawoud Bahzad, David Shan-Hill Wong, Shi-Shang Jang, Robust Predictions of Catalyst Deactivation of Atmospheric Residual Desulfurization, Energy Fuels, vol. 29, Oct. 21, 2015 pp. 7089-7100 American Chemical Society, Washington DC US. |
| A.G. Okunev, E.V. Parkhomchuk, A.I. Lysikov, P.D. Parunin, V.S. Semeykina, V.N. Parmon, Catalytic Hydroprocessing of Heavy Oil Feedstocks, Russian Chemical Reviews, vol. 84, Sep. 2015, pp. 981-999, Russian Academy of Sciences and Turpion Ltd. Moscow, Russia. |
| Ernest Czermanski, Slawomir Drozdziecki, Maciej Matczak, Eugen Spangenberg, Bogusz Wisnicki, Suplphur Regulation—Technology Solutions and Economic Consequences, Institute of Maritime transport and Seaborne Trade, University of Gdansk, 2014, pp. 1-76, University of Gdansk, Gdansk Poland. |
| Charles Olsen, Brian Watkins, Greg Rosinski, The Challenges of Processing FCC LCO, Catalagram 110 Special Edition, Fall 2011, pp. 6-8, W.R. Grace & Co. Advanced Refining Technologies, Columbus Maryland, US. |
| Yanzi Jia, Qinghe Yang, Shuling Sun, Hong Nie, Dadong Li, The Influence of Metal Deposits on Residue Hydrodemetallization Catalyst in the Absence and Presence of Coke, Energy Fuels, vol. 30 Feb. 22, 2016 pp. 2544-2554 American Chemical Society, Washington DC US. |
| James G. Speight, Upgrading Heavy Oils and Residua: The Nature of the Problem, Catalysis on the Energy Scene, 1984, pp. 515-527, Elsevier Science Publishers B.V. Amsterdam, The Netherlands. |
| Blessing Umana, Nan Zhang, Robin Smith, Development of Vacuum Residue Hydrodesuphurization—Hydrocracking Models and Their Integration with Refinery Hydrogen Networks, Industrial & Engineering Chemistry Research, vol. 55, Jan. 27, 2016, pp. 2391-2406, American Chemical Society, Washington DC US. |
| Mike Stockle, Tina Knight, Impact of Low Sulphur Bunkers on Refineries, Catalysis, 2009, pp. 1-7, downloaded from website: www.digitalrefining.com/article/1000090. |
| Mohammad Farhat Ali, et al. A review of methods for the demetallization of residual fuel oils, Fuel Processing Technology, Mar. 8, 2006, pp. 573-584, vol. 87, Elsevier B.V. |
| Mohan S. Rana, et al., A review of recent advances on process technologies for upgrading of heavy oils and residua, Fuel, Available online Sep. 7, 2006, pp. 1216-1231, vol. 86, Elsevier B.V. |
| Carolina Leyva, et al., Activity and surface properties of NiMo/SiO2—Al2O3 catalysts for hydroprocessing of heavy oils, Applied Catalysis A: General, Available online Feb. 28, 2012, pp. 1-12, vol. 425-426, Elsevier B.V. |
| Oliver C. Mullins et al., Asphaltenes Explained for the Nonchemist, Petrophysics, Jun. 2015, pp. 266-275, vol. 56, No. 3. |
| M. Ghasemi, et al., Phase Behavior and Viscosity Modeling of Athabasca Bitumen and Light Solvent Mixtures, SPE165416, Jun. 2013, pp. 1-26, Society of Petroleum Engineers. |
| Marten Ternan, Catalytic Hydrogenation and Asphaltene Conversion of Athabasca Bitumen, The Canadian Journal of Chemical Engineering, Oct. 1983, pp. 689-696, vol. 61. |
| Jeremías Martínez, et al., Comparison of correlations to predict hydrotreating product properties during hydrotreating of heavy oils, Catalysis Today, Available online Dec. 5, 2009, pp. 300-307, vol. 150, Elsevier B.V. |
| Luis C. Castñeda, et al., Current situation of emerging technologies for upgrading of heavy oils, Catalysis Today, Available online Jul. 4, 2013, pp. 248-273, vol. 220-222, Elsevier B.V. |
| C. Ferreira, et al., Hydrodesulfurization and hydrodemetallization of different origin vacuum residues: Characterization and reactivity, FUEL, Available online Apr. 14, 2012, pp. 1-11, http://dx.doi.org/10.1016/j.fuel.2012.03.054, Elsevier B.V. |
| C.V. Philip, et al. GPC Characterization for Assessing Compatibility Problems with Heavy Fuel Oils, Fuel Processing Technology 1984: pp. 189-201., Elsevier B.V. |
| Muhammad A. Altajam & Marten Ternan, Hydrocracking of Athabasca bitumen using Co—Mo catalysts supported on wide pore carbon extrudates, FUEL, Aug. 1989, pp. 955-960, Butterworth & Co. Publishers Ltd. |
| J.W. Holmes & J.A. Bullin, Fuel Oil Compatibility Probed, Hydrocarbon Processing, Sep. 1983: pp. 101-103. |
| Charles J. Glover, & Jerry A. Bullin, Identification of Heavy Residual Oils by GC and GCMS, Journal of Environmental Science and Health A24(1), 1989: pp. 57-75. |
| H. Puron, et al., Kinetic analysis of vacuum residue hydrocracking in early reaction stages, FUEL, Available online Sep. 27, 2013, pp. 408-414, vol. 117, Elsevier B.V. |
| Yanet Villasna, et al. Upgrading and Hydrotreating of Heavy Oils and Residua, Energy Science and Technology, vol. 3, Oil and Natural Gas, 2015, pp. 304-328, Stadium Press LLC, Houston TX USA. |
| Phillips 66, Phillips 66, Petitioner v Magēmā Technology LLC, Patent Owner, Petition for Inter Parties Review, Case IPR2021-01168, U.S. Pat. No. 10,308,884 B2, Dated Jul. 7, 2021, All pages. |
| Phillips 66, Phillips 66, Petitioner v Magēmā Technology LLC, Patent Owner, Petition for Inter Parties Review, Case IPR2021-01173, U.S. Pat. No. 10,584,287 B2, Dated Jul. 12, 2021, All pages. |
| Phillips 66, Phillips 66, Petitioner v Magēmā Technology LLC, Petition for Inter Parties Review, Case IPR2021-01174, U.S. Pat. No. 10,604,709 B2, Dated Jul. 13, 2021, All pages. |
| Phillips 66, Phillips 66, Petitioner v Magēmā Technology LLC, Patent Owner, Petition for Inter Parties Review, Case IPR2021-01175, U.S. Pat. No. 10,533,141 B2, Dated Jul. 14, 2021, All pages. |
| International Organization for Standardization. Petroleum products—Fuels (class F)—Specifications of marine fuels (ISO Standard No. 8217:2017(E)), 2017. pp. 1-30 as presented in Petitioner's Exhibit 1003 in IPR2021-01168; IPR2021-01173; IPR2021-01174; IPR2021-01175. |
| Phillips 66, Petitioner's Exhibit 1015 Defendants Supplemental Preliminary Invalidity Contentions pp. 1-50, as presented in IPR2021-01168; IPR2021-01173; IPR2021-01174; IPR2021-01175. |
| Mafalda Silva, Life Cycle Assessment of Marine Fuel Production, Jul. 2017, Norwegian University of Science and Technology, pp. 16-18, 32-35, 66 as presented Petitioner's Exhibit 1055 in IPR2021-01168; IPR2021-01173; IPR2021-01174; IPR2021-01175 and cited in Petitioner's Exhibit 1015 in IPR2021-01168; IPR2021-01173; IPR2021-01174; IPR2021-01175. |
| Cambiaso Risso Group, Challenges of IMO's 0.5% Global Bunker Sulfur Cap, Dec. 12, 2016, p. 9, as presented in Petitioner's Exhibit 1057 in IPR2021-01168; IPR2021-01173; IPR2021-01174; IPR2021-01175 and cited in Petitioner's Exhibit 1015 in IPR2021-01168; IPR2021-01173; IPR2021-01174; IPR2021-01175. |
| Phillips 66, Petitioner's Exhibit 1082 Declaration of Edward L. Sughrue II, pp. 1-84 as presented in IPR2021-01168; IPR2021-01173; IPR2021-01174; IPR2021-01175. |
| Surinder Parkash, Petroleum Fuels Manufacturing Handbook, 2010, R.R Donnelley, Publisher, pp. 82, 83, 84, 94, 95, 96 as presented in Petitioner's Exhibit 1102 in IPR2021-01174. |
| Number | Date | Country | |
|---|---|---|---|
| 20230103802 A1 | Apr 2023 | US |
| Number | Date | Country | |
|---|---|---|---|
| 62589479 | Nov 2017 | US | |
| 62458002 | Feb 2017 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16681093 | Nov 2019 | US |
| Child | 18074212 | US | |
| Parent | 16103897 | Aug 2018 | US |
| Child | 16681093 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | PCT/US2018/017855 | Feb 2018 | US |
| Child | 16103897 | US | |
| Parent | PCT/US2018/017863 | Feb 2018 | US |
| Child | PCT/US2018/017855 | US |
