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US20160312126A1 - Fluid coking process - Google Patents

Fluid coking process Download PDF

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Publication number
US20160312126A1
US20160312126A1 US15/085,200 US201615085200A US2016312126A1 US 20160312126 A1 US20160312126 A1 US 20160312126A1 US 201615085200 A US201615085200 A US 201615085200A US 2016312126 A1 US2016312126 A1 US 2016312126A1
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US
United States
Prior art keywords
rings
steam
operated
feed
nozzles
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
Application number
US15/085,200
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English (en)
Inventor
Michael Wormsbecker
Jason S. Wiens
Jennifer MCMILLAN
Craig A. McKnight
Brian A. Knapper
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
ExxonMobil Technology and Engineering Co
Original Assignee
ExxonMobil Research and Engineering Co
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by ExxonMobil Research and Engineering Co filed Critical ExxonMobil Research and Engineering Co
Priority to US15/085,200 priority Critical patent/US20160312126A1/en
Priority to EP16716783.2A priority patent/EP3286285B1/de
Priority to PCT/US2016/025973 priority patent/WO2016171890A1/en
Priority to CA2977157A priority patent/CA2977157A1/en
Priority to PE2017002008A priority patent/PE20180108A1/es
Priority to CN201680023361.5A priority patent/CN107532090B/zh
Assigned to EXXONMOBIL RESEARCH AND ENGINEERING COMPANY reassignment EXXONMOBIL RESEARCH AND ENGINEERING COMPANY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: KNAPPER, BRIAN A., MCKNIGHT, CRAIG A., MCMILLAN, JENNIFER, WIENS, JASON S., WORMSBECKER, Michael
Publication of US20160312126A1 publication Critical patent/US20160312126A1/en
Abandoned legal-status Critical Current

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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G9/00—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G9/005—Coking (in order to produce liquid products mainly)
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10B—DESTRUCTIVE DISTILLATION OF CARBONACEOUS MATERIALS FOR PRODUCTION OF GAS, COKE, TAR, OR SIMILAR MATERIALS
    • C10B55/00—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material
    • C10B55/02—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials
    • C10B55/04—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials with moving solid materials
    • C10B55/08—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials with moving solid materials in dispersed form
    • C10B55/10—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials with moving solid materials in dispersed form according to the "fluidised bed" technique

Definitions

  • This invention relates to a fluid coker with improved liquid yield and its method of operation.
  • Fluidized bed coking is a petroleum refining process in which heavy petroleum feeds, typically the non-distillable residues (resids) from fractionation, are converted to lighter, more useful liquid products by thermal decomposition (coking) at elevated reaction temperatures, typically about 480 to 590° C., (about 900 to 1100° F.).
  • the process is carried out in a unit with a large reactor vessel containing hot coke particles which are maintained in the fluidized condition at the required reaction temperature with steam injected at the bottom of the vessel with the average direction of movement of the coke particles being downwards through the bed.
  • the heavy oil feed is heated to a pumpable temperature, mixed with atomizing steam, and fed through multiple feed nozzles arranged at several successive levels in the reactor, usually referred to as “rings” since they are arranged around the periphery of the reactor at different, vertically spaced intervals in the upper part of the reactor.
  • Steam is injected into a stripper section at the bottom of the reactor and passes upwards through the coke particles in the stripper as they descend from the main part of the reactor above and promotes fluidization of the particles in the bed.
  • the feed liquid coats a portion of the coke particles in the fluidized bed and subsequently decomposes into layers of solid coke and lighter products which evolve as gas or vaporized liquid.
  • the light hydrocarbon products of the coking (thermal cracking) reactions vaporize, mix with the fluidizing steam and pass upwardly through the fluidized bed into a dilute phase zone above the dense fluidized bed of coke particles.
  • This mixture of vaporized hydrocarbon products formed in the coking reactions continues to flow upwardly through the dilute phase with the steam at superficial velocities of about 1 to 2 metres per second (about 3 to 6 feet per second), entraining some fine solid particles of coke.
  • Most of the entrained solids are separated from the gas phase by centrifugal force in one or more cyclone separators, and are returned to the dense fluidized bed by gravity through the cyclone diplegs.
  • the mixture of steam and hydrocarbon vapors from the reactor is subsequently discharged from the cyclone gas outlets into a scrubber section in a plenum located above the reaction section and separated from it by a partition. It is quenched in the scrubber section by contact with liquid descending over scrubber sheds in a scrubber section.
  • a pumparound loop circulates condensed liquid to an external cooler and back to the top row of scrubber section to provide cooling for the quench and condensation of the heaviest fraction of the liquid product. This heavy fraction is typically recycled to extinction by feeding back to the fluidized bed reaction zone.
  • the solid coke from the reactor consisting mainly of carbon with lesser amounts of hydrogen, sulfur, nitrogen, and traces of vanadium, nickel, iron, and other elements derived from the feed, passes through the stripper and out of the reactor vessel to a burner where it is partly burned in a fluidized bed with air to raise its temperature from about 480 to 700° C. (about 900° to 1300° F.), after which the hot coke particles are recirculated to the fluidized bed reaction zone to provide the heat for the coking reactions and to act as nuclei for the coke formation.
  • the FlexicokingTM process also developed by Exxon Research and Engineering Company, is, in fact, a fluid coking process that is operated in a unit including a reactor and burner, often referred to as a heater in this variant of the process, as described above but also including a gasifier for gasifying the coke product by reaction with an air/steam mixture to form a low heating value fuel gas.
  • the heater in this case, is operated with an oxygen depleted environment.
  • the gasifier product gas, containing entrained coke particles, is returned to the heater to provide a portion of the reactor heat requirement.
  • a return stream of coke sent from the gasifier to the heater provides the remainder of the heat requirement.
  • Hot coke gas leaving the heater is used to generate high-pressure steam before being processed for cleanup.
  • the coke product is continuously removed from the reactor.
  • the tem “fluid coking” is used in this specification to refer to and comprehend both fluid coking and Flexicoking except when a differentiation is required.
  • the dense fluid bed behaves generally as a well-mixed reactor.
  • computational fluid dynamics model simulations and tracer studies have shown that significant amounts of coke particles coated in heavy petroleum feed can rapidly bypass the reaction section and descend into the shipper section at the bottom of the reactor while still coated with a film of liquid which is then largely lost as a source of potential liquid product.
  • one method of operation is to inject the heavy oil feed through the injection nozzles in the upper part of the reactor but to use the lower rings solely for the injection of steam. More feed injected higher in the bed increases the residence time between the feed zone and stripper, affording more time for the liquid film to dry reducing the fouling in the stripper region.
  • a typical commercial unit with an average feed rate per nozzle of about 230 m 3 /day (about 1450 sbpd) might have, for example, 96 feed nozzles distributed between 6 feed rings. Rings 1 and 2 at the two highest levels in the reactor might have 20 feed nozzles each, Ring 3 immediately below Ring 2 might have 19 nozzles, Ring 4 might have 116, Ring 5 might have 14 and Ring 6 might have 7. Rings 5 and 6, however, might not be used for feed injection but, instead, could be purged with steam to prevent plugging.
  • Each pair of feed rings (1&2, 3&4, 5&6) could be connected to a separate feed header line which can be varied separately, but typically all feed header lines would be controlled to the same pressure which, in a typical commercial unit, might be in the range of about 1000 to 2000 kPag (for example, from about 1500 to 1700 kPag), equivalent to about 145 to 290 psig (for example, from about 220 to 245 psig).
  • the superficial upward velocity in the reactor might range from about 60 cm/sec at the level of the lowest ring (Ring 6), increasing to about 1 m/sec at the level of the highest ring (Ring 1).
  • the average gas to liquid ratio (GLR or steam-to-oil) ratio at which the nozzles are all operated (for nozzles feeding oil) might typically be 0.86% w/w (the GLR is reported as (mass flow rate steam)/(mass flow rate oil)*100%).
  • Improvement in liquid product yield may be obtained by reducing the steam supply to the upper feed nozzles in the reactor while operating the lower nozzles at higher steam/oil ratios, with no net increase or decrease in atomization steam usage. Operation in this manner will allow for a greater improvement in feed dispersion at all feed ring levels since the nozzle operation is adapted in accordance with the local solids mixing behavior.
  • the fluid coking process is operated in a fluidized bed coking reactor in which a plurality of heavy oil inlet nozzles are arranged in a number of rings around the periphery of the dense bed reaction section at vertically spaced elevations.
  • a heavy oil feed is injected with atomization steam through the nozzles into the fluidized bed, operating at a lower steam-to-oil ratio for the upper ring or rings of nozzles than for the lower ring or rings.
  • the reactor in the unit in which the fluid bed coking is operated has a dense bed reaction section of circular horizontal cross-section about a vertical axis confined by the reactor wall.
  • the reactor has a base region where fluidizing gas is injected to fluidize a bed of finely-divided solid particles in the reaction section and an exit at the top through which gas and finely divided particulate solids exit the reactor.
  • the reactor has injection nozzles for the heavy oil feed arranged in a series of rings at vertically spaced intervals around the periphery of the upper portion of the reactor. The nozzles are fitted for injecting the oil feed with the aid of atomizing steam and in operation the ratio of steam to oil feed for the uppermost ring or rings is lower than for lower rings.
  • the lowermost ring or rings may be operated without oil feed, i.e. only with a steam purge.
  • the reactor will be coupled in the unit to a burner/heater by means of coke lines in the normal way: a cold coke transfer line takes coke from the bottom of the stripper to the burner/heater and a hot coke return line brings hot coke from the burner/heater back to the reactor.
  • the gasifier section follows the heater vessel as described above.
  • the invention may be used as the basis for modifying an existing fluid coker unit; in that case, the overall steam/oil ratio would be maintained by distributing the atomizing steam differently between the successive rings of nozzles: the upper ring or rings of nozzles will operate at a lower steam-to-oil ratio than for the lower ring or rings.
  • the invention provides a method for modifying the operation of a fluid bed coking unit which has a dense bed reaction section of circular horizontal cross-section about a vertical axis confined by the reactor wall, a base region where fluidizing gas is injected to fluidize a bed of finely-divided solid particles in the reaction section and an exit at the top through which gas and finely divided particulate solids exit the reactor.
  • the reactor has injection nozzles for the heavy oil feed arranged in a series of rings at vertically spaced intervals around the periphery of the upper portion of the reactor.
  • the nozzles are fitted for injecting the oil feed with the aid of atomizing steam.
  • the steam/oil ratio for each of the rings is substantially the same for each ring.
  • the overall steam-to-oil ratio (GLR) for all the feed injection rings is maintained at substantially the same as in the unit before modification but the GLR of the feed nozzles on the uppermost ring or rings is lower than for lower rings.
  • the lowermost ring or rings may be operated without oil feed, with only a steam purge.
  • Heavy petroleum feeds which may be treated in the fluid coking process include heavy hydrocarbonaceous oils, heavy and reduced petroleum crude oil, petroleum atmospheric distillation bottoms, petroleum vacuum distillation bottoms, or residuum, pitch, asphalt, bitumen, other heavy hydrocarbon residues, tar sand oil, shale oil, coal, coal slurries, liquid products derived from coal liquefaction processes, including coal liquefaction bottoms, and mixtures thereof.
  • Such feeds will typically have a Conradson carbon content (ASTM D 189-06e2) of at least about 5 wt. %, generally from about 5 to 50 wt. %.
  • FIG. 1 is a simplified diagram of the reactor of a fluid coking unit using frusto-conical staging baffles as shown and described in U.S. Pat. No. 8,435,452, to which reference is made for an extended description of the baffles and their functioning.
  • the reactor coking zone 10 contains a dense phase fluidized bed 11 of heated seed coke particles into which the feedstock, heated to a temperature sufficient to initiate the coking (thermal cracking) reactions and deposit a fresh coke layer on the hot fluidized coke particles circulating in the bed is injected.
  • the coking zone has a slight frusto-conical form with its major cross-section uppermost so that the gas flow decelerates towards the top of the reactor vessel; the upper portion of the vessel is typically cylindrical in shape.
  • the feed is preheated by contact with the cracking vapors passing through the scrubber section atop the reactor.
  • the feed is injected through multiple nozzles located in feed rings 12 a to 12 f, which are positioned so that the feed with atomizing steam enters directly into the dense fluidized bed of hot coke particles in coking zone 11 .
  • Each feed ring consists of a set of nozzles (typically 10-20, not designated in FIG. 1 ) that are arranged in rings around the circular periphery of the reactor wall, each ring at a given elevation and with each nozzle in the ring connected to its own feed line which penetrates the vessel shell (i.e. 10-20 pipes extending into the fluid bed at the level of the ring).
  • feed nozzles are typically arranged non-symmetrically around the reactor to optimize flow patterns in the reactor according to simulation studies although symmetrical disposition of the nozzles is not precluded if the flow patterns in the reactor can be optimized in this way.
  • Steam is admitted as fluidizing gas in the stripping section 13 at the base of coker reactor 110 through spargers 14 directly under stripping sheds 15 as well as from lower inlets 16 .
  • the steam passes up into stripping zone 13 of the coking reactor in an amount sufficient to obtain a superficial fluidizing velocity in the coking zone, typically in the range of about 0.15 to 1.5 m/sec (about 0.5 to 5 ft/sec).
  • the coking zone is typically maintained at temperatures in the range of 450 to 650° C.
  • the vaporous products of the cracking reactions with entrained coke particles pass upwards out of the dense phase reaction zone 11 , through a phase transition zone in the upper portion 17 of the vessel and finally, a dilute phase reaction zone at the inlets of cyclones 20 (only two shown, one indicated).
  • the coke particles separated from the vaporous coking products in the cyclones are returned to the fluidized bed of coke particles through cyclone dipleg(s) 21 while the vapors pass out through the gas outlet(s) 22 of the cyclones into the scrubbing section of the reactor (not shown).
  • scrubbing section which is fitted with scrubbing sheds in which the ascending vapors are directly contacted with a flow of fresh feed to condense higher boiling hydrocarbons in the reactor effluent (typically 525° C.+/975° F.+) and recycled along with the fresh feed to the reactor.
  • the vapors leaving the scrubber then pass to a product fractionator (not shown) in which the conversion products are fractionated into light streams such as naphtha, intermediate boiling streams such as light gas oils and heavy streams including product bottoms which may be recycled to the furnace of the coker for mixing with fresh feed.
  • staging baffles 30 of the type described in U.S. Pat. No. 8,435,452 extend radially inwards and downwards from their upper edges which are fixed to the reactor wall are of generally conical form with a central, circular aperture to permit downward flow of coke particles and upward flow of vapors and divide the reactor into an upper feed zone and a lower drying zone thereby minimizing the bypassing of wet solids to the stripper zone below.
  • the baffles may be located below rings 2, 4 and 6 (feed rings numbered from top down).
  • the lowest baffle is, in any event, preferably located below the bottommost feed ring as shown in FIG. 1 and successive baffles are located between pairs of feed rings at higher levels.
  • one baffle is situated below the lowest row of active feed nozzles.
  • a majority (at least 50% and preferably at least 30%) of the feed is preferably injected at the intermediate levels of the dense bed, for example, in the six feed ring reactor in rings 2, 3 and 4 (from top down).
  • Attrition steam is directed through nozzles 31 below the bottom baffle 12 f and above the top row of stripper sheds in order to control the mean particle size of the circulating coke.
  • a portion of the stripped coke that is not burned in the heater to satisfy the heat requirements of the coking zone is recycled to the coking zone through coke return line 26 , passing out of return line 26 through cap 27 to enter the reactor near the top of the reaction zone; the remaining portion is withdrawn from the heater as product coke.
  • a variation allows a smaller flow of hot coke from the heater to be admitted from a second return line 28 higher up in reactor 10 at a point in the dilute phase where it is entrained into the cyclone inlet(s) as scouring coke to minimize coking of the reactor cyclones and the associated increase in the pressure drop.
  • the gasifier section follows the heater with flow connections for the coke, return coke and gas flows in the normal way.
  • a typical mode would be to operate with a reduced steam/heavy oil ratio in the uppermost feed ring or rings (Rings 1 and 2) with a consequently lower steam-to-oil ratio for these nozzles and operating the rest of the feed rings (Rings 3-6) at higher steam-to-oil ratios.
  • Simple changes in the operation of existing nozzles will usually allow the necessary changes in steam rate relative to oil feed rate to be made, for example, by varying the sizes of the steam inlet orifices in the upstream piping or imposing some throttling on the steam header(s) to individual rings.
  • customized feed nozzles with different steam/oil ratios may be used for the specific feed rings. Either way, there can be a greater improvement in feed dispersion in all feed rings since the nozzle is adapted for the localized solids mixing behavior.
  • the improved atomization performance in the lower portion of the feed zone of the reactor resulting from the higher relative steam rate(s) in this region will aid the dispersion of the heavy oil feed from the feed nozzles in a region of the bed that is not normally as turbulent.
  • the increased dispersion of the jets of injected oil in this lower region of the reactor result in thinner oil films on the particles which can be expected to result in higher liquid yields.
  • the GLR operating window for the feed nozzles i.e. the nozzles feeding atomized heavy oil feed with atomization steam will vary according to a
  • the GLR for most nozzles will be in the range of 0.25 to 1.5% w/w with some nozzles being limited to a range of about 0.25 to 0.75% w/w while others will allow ranges up to about 1.5% w/w to be utilized.
  • the extent to which the GLR values between the upper feed rings and the lower feed rings (neglecting the rings injecting only steam) will therefore vary according to the types of nozzle installed in the unit and the safe operating parameters established for the nozzles and the unit in which they are operated.
  • the upper ring(s) might be operated with a GLR at the lower end of their operating range, about 0.25 to 0.35% w/w and the lower rings at a GLR of about 0.9 to 1.1% w/w.
  • the upper ring(s) might be operated with a GLR at the lower end of their operating range, about 0.4 to 0.6% w/w and the lower rings at a GLR of about 1.3 to 1.5% w/w.
  • Nozzles of the type shown in US 2012/0063961 can typically be operated at a higher GLR than those as shown in U.S. Pat. No. 6,003,789.
  • a reactor with a total of six rings of nozzles of the type described in U.S. Pat. No. 6,003,789 could be operated, for instance, with the top two feed rings at a steam-to-oil ratio of 0.27% w/w as compared to 0.65% w/w (in normal, unmodified operation) while remaining within the safe operating window set for this nozzle in unmodified operation.
  • a reactor with six rings of nozzles having the configuration shown in US 2012/0063961 could be operated with the top two feed rings at a steam-to-oil ratio of 0.45% w/w (vs 0.86% w/w in normal unmodified operation) and the bottom four feed rings at a steam-to-oil ratio of 1.37% w/w (vs 0.86% w/w in normal unmodified operation) while remaining within the safe operating window for this type of nozzle in the unit.
  • the estimated liquid yield benefit was 0.4% w/w with no credit for potential reactor temperature reduction due to improved feed bed contacting.
  • the overall atomization steam consumption would be comparable to the case in which the top four rings are operated with oil feed at the same steam-to-oil ratio; however, this shift in atomization steam usage would significantly improve interaction between the injected steam/oil sprays and the bed to increase liquid yields.
  • An optimal strategy would utilize customized nozzles for high solids mixing regions to generate more dispersion from the nozzle and disperser design to permit the solids mixing process to control feed dispersion.
  • nozzles that produce a spray with longer penetrations, higher momentum and finer droplets could be used to allow the jet to control dispersion of the feed.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Dispersion Chemistry (AREA)
  • Materials Engineering (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Devices And Processes Conducted In The Presence Of Fluids And Solid Particles (AREA)
US15/085,200 2015-04-24 2016-03-30 Fluid coking process Abandoned US20160312126A1 (en)

Priority Applications (6)

Application Number Priority Date Filing Date Title
US15/085,200 US20160312126A1 (en) 2015-04-24 2016-03-30 Fluid coking process
EP16716783.2A EP3286285B1 (de) 2015-04-24 2016-04-05 Verfahren zum verkoken in wirbelschicht
PCT/US2016/025973 WO2016171890A1 (en) 2015-04-24 2016-04-05 Fluid coking process
CA2977157A CA2977157A1 (en) 2015-04-24 2016-04-05 Fluid coking process
PE2017002008A PE20180108A1 (es) 2015-04-24 2016-04-05 Proceso de coquizacion de fluidos
CN201680023361.5A CN107532090B (zh) 2015-04-24 2016-04-05 流化焦化法

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201562152214P 2015-04-24 2015-04-24
US15/085,200 US20160312126A1 (en) 2015-04-24 2016-03-30 Fluid coking process

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US20160312126A1 true US20160312126A1 (en) 2016-10-27

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US15/085,200 Abandoned US20160312126A1 (en) 2015-04-24 2016-03-30 Fluid coking process

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US (1) US20160312126A1 (de)
EP (1) EP3286285B1 (de)
CN (1) CN107532090B (de)
CA (1) CA2977157A1 (de)
PE (1) PE20180108A1 (de)
WO (1) WO2016171890A1 (de)

Cited By (12)

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CN109000221A (zh) * 2018-07-16 2018-12-14 大连亿斯德制冷设备有限公司 一种煤泥处理方法
US20190161684A1 (en) * 2017-11-28 2019-05-30 SYNCRUDE CANADA LTD. in trust for the owners of the Syncrude Project as such owners exist now and Fluid coking using high thrust feed nozzles
US10703979B1 (en) * 2019-02-12 2020-07-07 Syncrude Canada Ltd. Liquid yield from fluid coking reactors
CN112048339A (zh) * 2020-08-07 2020-12-08 中科合成油技术有限公司 一种含固浆料的连续化处理方法及用于实施该方法的装置
US11345862B2 (en) 2019-11-07 2022-05-31 Indian Oil Corporation Limited Apparatus and a method for washing of hydrocarbon product vapor
US11441080B2 (en) * 2019-02-14 2022-09-13 ExxonMobil Technology and Engineering Company Lubricant base stock production from recycled oil
US11485914B2 (en) 2019-03-20 2022-11-01 Composite Recycling Corp. Process and system for recovering hydrocarbons from oil sand and oil shale
US20250043193A1 (en) * 2023-08-02 2025-02-06 SYNCRUDE CANADA LTD. in trust for the owners of the Syncrude Project as such owners exist now and i Techniques to mitigate stripper fouling in fluid cokers
US12365828B2 (en) 2021-05-11 2025-07-22 ExxonMobil Technology and Engineering Company Polyolefin-coke composite granules as a hydraulic fracturing proppant
US12466992B2 (en) 2022-03-04 2025-11-11 ExxonMobil Technology and Engineering Company Proppants derived from crosslinking mixed aromatic resins
US12521764B2 (en) 2024-06-19 2026-01-13 ExxonMobil Technology and Engineering Company Methods for preparing petroleum coke proppant particles for hydraulic fracturing
US12540273B2 (en) 2024-05-28 2026-02-03 ExxonMobil Technology and Engineering Company Proppant particles formed from fluid coke and flexicoke, fracturing fluids comprising such proppant particles, and methods related thereto

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US20110206563A1 (en) * 2010-02-23 2011-08-25 Exxonmobil Research And Engineering Company Circulating fluid bed reactor with improved circulation
US20120063961A1 (en) * 2010-05-25 2012-03-15 Exxonmobil Research And Engineering Company Fluid injection nozzle for fluid bed reactors

Cited By (13)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20190161684A1 (en) * 2017-11-28 2019-05-30 SYNCRUDE CANADA LTD. in trust for the owners of the Syncrude Project as such owners exist now and Fluid coking using high thrust feed nozzles
CN109000221A (zh) * 2018-07-16 2018-12-14 大连亿斯德制冷设备有限公司 一种煤泥处理方法
US10703979B1 (en) * 2019-02-12 2020-07-07 Syncrude Canada Ltd. Liquid yield from fluid coking reactors
US11441080B2 (en) * 2019-02-14 2022-09-13 ExxonMobil Technology and Engineering Company Lubricant base stock production from recycled oil
US11485914B2 (en) 2019-03-20 2022-11-01 Composite Recycling Corp. Process and system for recovering hydrocarbons from oil sand and oil shale
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PE20180108A1 (es) 2018-01-18
EP3286285A1 (de) 2018-02-28
CN107532090A (zh) 2018-01-02
WO2016171890A1 (en) 2016-10-27
EP3286285B1 (de) 2019-05-22
CN107532090B (zh) 2019-12-17
CA2977157A1 (en) 2016-10-27

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