EP2361292A1 - Process for upgrading heavy oil and bitumen products - Google Patents
Process for upgrading heavy oil and bitumen productsInfo
- Publication number
- EP2361292A1 EP2361292A1 EP08878057A EP08878057A EP2361292A1 EP 2361292 A1 EP2361292 A1 EP 2361292A1 EP 08878057 A EP08878057 A EP 08878057A EP 08878057 A EP08878057 A EP 08878057A EP 2361292 A1 EP2361292 A1 EP 2361292A1
- Authority
- EP
- European Patent Office
- Prior art keywords
- bitumen
- reactor
- steam
- liquid
- gas
- 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.)
- Withdrawn
Links
Classifications
-
- 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
- C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
- C10G1/002—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal in combination with oil conversion- or refining processes
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
- B01J8/00—Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes
- B01J8/18—Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes with fluidised particles
- B01J8/24—Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes with fluidised particles according to "fluidised-bed" technique
- B01J8/36—Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes with fluidised particles according to "fluidised-bed" technique with fluidised bed through which there is an essentially horizontal flow of particles
-
- 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
- C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
- C10G1/02—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by distillation
-
- 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
- C10G11/00—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
- C10G11/14—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts
- C10G11/18—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts according to the "fluidised-bed" technique
-
- 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
- C10G51/00—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more cracking processes only
- C10G51/02—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more cracking processes only plural serial stages only
- C10G51/023—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more cracking processes only plural serial stages only only thermal cracking steps
-
- 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
- C10G7/00—Distillation of hydrocarbon oils
-
- 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
- C10G70/00—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00
-
- 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
-
- 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
- C10G9/28—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid material
- C10G9/32—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid material according to the "fluidised-bed" technique
-
- 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
- C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
- C10G2400/02—Gasoline
Definitions
- This invention relates generally to oil processing, and in particular, to a system for upgrading heavy oil and bitumen products.
- bitumen ultra-heavy oil
- thermal recovery involves in situ heating of the oil/sand aggregate, often using steam as the heating medium.
- the thermal energy in the steam liquefies the heavy oil / bitumen, which can then be collected and pumped to the surface.
- thermal recovery processes include steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).
- upgrading Additional processing is required for bitumen and heavy oils before they can be introduced into refining infrastructure for light crude oil; such processing is known as "upgrading”.
- the degree of upgrading depends upon how far the oil to be processed (“feedstock”) deviates from light oil, when compared using standard refining metrics.
- feedstock is usually introduced into a plant where it is usually separated into a pitch and non-pitch fraction.
- itch as generally understood in the industry means the fraction of the oil boiling above approximately 975 0 F, as measured by the standard ASTM method. This physical separation does not introduce any chemical changes to the molecules in the oil, but rather separates any higher quality oil from the heavier, low quality fraction.
- the heavier pitch fraction representing typically 30- 50% by weight of the feed mixture is then introduced into a primary upgrading (PUG) facility where it is subjected to conditions where the large molecules "crack" into smaller ones, resulting in a liquid with a lower boiling point than the starting material.
- PUG primary upgrading
- a boiling point of less than 975 0 F is targeted for the product liquid, based on producing an acceptable feedstock for conventional downstream refining equipment.
- Significant sulfur is released from the oil as part of this processing step.
- elemental hydrogen may also be introduced to the oil to remove nitrogen and any remaining sulfur, and to increase the hydrogen content of the oil.
- the PUG facility In addition to producing a hydrocarbon stream that is liquid at ambient conditions (the “liquid products”), the PUG facility will also produce a non-condensable, sour, gaseous hydrocarbon stream (the "gas”), and a hydrogen-deficient solid byproduct which is often coke. If a catalytic process is employed in the PUG facility, a purge of catalyst will also be required, upon which some of the coke resides.
- the liquid products produced by the PUG facility are then subjected to secondary upgrading (SUG) in a SUG facility.
- SUG secondary upgrading
- elemental hydrogen is added catalytically to the liquid products to increase the hydrogen content of the hydrocarbon therein, and sulfur, nitrogen and metals are removed from the liquid products.
- the SUG facility utilizes fixed-bed catalytic reactors.
- a significant amount of infrastructure is required to support the PUG and SUG facilities in prior art systems.
- steam methane reforming (SMR), gasification or other hydrogen generation means must be provided to generate the hydrogen required by both the SUG and possibly the PUG facilities.
- SMR steam methane reforming
- the conventional upgrading system is energy and resource intensive, complex, and expensive to set up and maintain.
- Reasons include: the remote and localized nature of oil sand reservoirs result in expensive labour costs; the use of expensive diluent (a low molecular weight hydrocarbon) to assist in the separation of the heavy oil from the mixture of bitumen and water that is initially recovered at surface by the thermal recovery process; and, SAGD, CSS and other thermal recovery processes are very energy intensive, requiring high pressure steam that is typically produced by combusting natural gas.
- Field upgrading is a concept used to refer to upgrading on a relatively small scale, usually constructed adjacent to the SAGD or other production facility. This is of particular interest to the many small scale bitumen/heavy oil producers operating a single SAGD facility, or "pod". To date there have been no commercial applications of the field upgrading concept, as no system utilizing PUG technology has proven economic at such smaller scales. Summary Of Invention
- One particular objective of the invention is to provide an improved system for upgrading heavy oil and bitumen.
- cracked naphtha there can also be produced cracked naphtha, in which case the process further comprises using at least some of the cracked naphtha to generate steam for use in recovering the bitumen. At least some of the cracked naphtha can be recovered as liquid naphtha for use as an upgraded product. The amount of cracked naphtha included in the liquid product depends upon the fraction of this liquid that is unstable, and the ability of the resulting mixture to meet pipeline specifications.
- the bitumen can be recovered by steam assisted gravity drainage or cyclic steam stimulation or other known steam recovery techniques.
- the steam used for such recovery techniques can be generated by a circulating fluidized bed steam generator and clean up facility.
- At least some of the coke can be partially oxidizing to generate heat; in such case, flue gas generated as a result of the partial oxidation is directed to the circulating fluidized bed steam generator and clean up facility. Sulfur is removed from the combustion gas generated in the process through contact with lime.
- At least some of the coke partially oxidized to generate heat can be used to heat one or more of the solid particles, fluidizing gas, and low grade steam.
- the reactor output and bitumen input can be selected such that the amount of coke and naphtha produced is sufficient to meet all the energy requirements of the circulating fluidized bed steam generator and clean up facility.
- the reactor output can be selected such that the amount of coke and naphtha produced is also or additionally sufficient to meet all the energy requirements for sufficiently heating the solid particles and fluidizing gas for use in the reactor.
- the heated gases can be contacted with the bitumen such that the boiling temperature of volatile material in the bitumen is reduced, thereby enabling fractionation without use of atmospheric and vacuum columns, which are elements of a traditional upgrading flowsheet.
- Figure 1 is a flowsheet of a system for producing an upgraded oil product from heavy oil or bitumen according to one embodiment of the invention.
- Figure 2 is a schematic view of a cross-flow fluid bed reactor used in the system of Figure 1.
- FIG 3 is a schematic view of the fractionation process used in the system in Figure 1.
- a system 10 which upgrades heavy oil and bitumen without using hydrogen injection.
- this system 10 does not incorporate the equipment, processes, and materials associated with hydrogen injection, this system 10 can be economically deployed for smaller scale "field upgrading" applications, wherein the upgrader feed rate is approximately equal to the production rate of a single pod oil sands thermal recovery facility such as SAGD or CSS, which is typically in the order of 20,000 - 30,000 bbl/day of a heavy oil/ bitumen feedstock.
- the system is located at an oil sands reservoir and is used to extract and upgrade bitumen into an intermediate product which meets pipeline specifications, and may also meet refinery specifications for refining by a light crude oil refinery (not shown).
- the system 10 is designed for operation at an oil sands reservoir in Alberta, Canada in which bitumen is recovered using SAGD techniques, and details of the operating parameters, inputs and outputs of components in the system 10 are provided for this specific application; however, it is to be understood that such disclosed operating parameters, inputs and outputs are provided merely to illustrate one specific application of the system 10 and that different operating parameters, inputs and outputs can be specified depending on the particular application of the system 10.
- bitumen is produced by SAGD in a bitumen production facility 12.
- Bitumen is comprised of a mixture of virgin heavy gas oil and pitch.
- steam used by the SAGD process is generated by a steam generator and gas clean-up facility (“steam generator") 14 which is fluidly coupled to the bitumen production facility 12 by steam line 13.
- steam generator steam generator and gas clean-up facility
- bitumen production is rated at 20,000 bbl/day which can be met by well known SAGD techniques.
- other bitumen recovery techniques such as CSS can be employed within the scope of this invention.
- An oil-soluble diluent is added to the mixture at a rate of 5,000 bbl/d prior to entry into the separation vessel, in order to assist in the separation.
- “Diluent” refers to a light, virgin oil that is used to dilute heavy oil in order to reduce its density and viscosity.
- the diluent / bitumen mixture (“diluted bitumen”) is then fed to a diluent splitter 16 at a rate of 25,000 bbl/d, where it is heated through indirect heat exchange with light and heavy gas oil from a fractionation apparatus 18, steam from the steam generator 14, and diluent from the diluent splitter 16 to a temperature of 235 0 C (conduits for these fluids to the diluent splitter 16 are not shown in Figure 1 ).
- the diluent splitter 16 includes a fractionator column (not shown) designed to separate the diluent from the bitumen in the diluted bitumen stream in a manner that is known in the art.
- the column contains components as known in the art to effect contacting between the vapour and liquid streams within the column.
- the liquid streams consist almost entirely of hydrocarbon, while the vapour is comprised of water and hydrocarbon.
- the column's components include an overhead receiver in which condensed steam is separated from the condensed diluent by gravity.
- the separated liquid diluent (about 5,000 bbl/d) is recycled via a return diluent stream 22 to the bitumen production facility 12 for reuse.
- the separated bitumen (about 20,000 bbl/d) is fed to the fractionation apparatus 18 as a liquid bitumen stream 20.
- the condensed steam is returned to the bitumen production facility 12 to be de-oiled (water return line not shown). After de-oiling, the water is returned to a water treatment facility 32 for purification before being transported to the steam generator 14 for conversion to steam.
- the fractionation apparatus 18 is comprised of two primary vessels: a scrubber and a fractionator column (both not shown in Figure 1 ).
- the two vessels can alternatively be combined into one, as is often done industrially, but are kept separate in this embodiment for convenience and layout considerations.
- the incoming bitumen stream 20 is preheated to 300 0 C through indirect contact in conventional heat transfer equipment with a heavy gas oil pump-around loop 27 (see Figure 3) drawn from the bottom of the fractionator column; as will be described below, heavy gas oil is a liquid product from a primary upgrader reactor 24 that is condensed in the fractionation apparatus 18
- the warmed bitumen stream 20 is then introduced into the scrubber vessel, where it is distributed onto the top of internal components that are designed to operate in a fouling service, which may be, for instance shed decks (not shown). These internal components are designed to effect contacting of the relatively heavy bitumen stream 20 with heated gases from the primary upgrader reactor 24 that is introduced into the scrubber below the internal components.
- the contacting will remove particulate solids that are entrained and carried over from the reactor 24.
- the heated reactor gases substantially consists of all of the fluidization gas (56 MMSCFD), unreacted vaporized pitch, vaporized cracked naphtha, cracked light gas oil, cracked heavy gas oil, non-condensable gas, water vapour and some suspended coke fines from the reactor 24.
- the heated reactor gases are hot and act as a stripping medium, assisting in the separation of pitch from non-pitch content in the bitumen stream 20.
- the separated pitch materials, in liquid form, along with some gas oil exit the bottom of the scrubber and are introduced as a reactor feed (pitch) stream 25 into the primary upgrader reactor 24 at 35O 0 C.
- the potential liquid product, along with the non-condensable gas and fluidization gas (81.5 MMSCFD) exit a wash grid (not shown) at the top of the scrubber, and are introduced near the bottom of the fractionator column at 37O 0 C .
- Figure 3 illustrates the flow of fluids into and out of the fractionator 18.
- the fractionator column condenses the liquid products and separates them into a number of subfractions based on boiling point.
- the fractionator column is equipped with standard internal components known in the art for this purpose.
- Steam (3,300 Ib/hr at 55 psig) is fed from the steam generator 14 to the fractionator column to assist in the separation (shown in Figure 3 but not Figure 1 ), as is common practice.
- a side stream stripper (not shown) is also incorporated as a means of sharpening the cut point between the gas oil and naphtha cuts.
- a number of pump-around loops are included in an effort to capture as much of the energy as possible, and to achieve the desired separation, as per conventional fractionator design practices.
- the fractionation apparatus 18 produces 7,650 bbl/d of heavy gas oil and 9,650 bbl/d of light gas oil as liquid products, collected as a single liquid product stream 26.
- the combined product meets pipeline specifications on both density and viscosity metrics, and is discharged from the fractionation apparatus 18 as a liquid products stream 26 for refining. Vapour off the top of the fractionator column is cooled, condensing the steam contained therein into water, which is then recycled via a water conduit 28 to the bitumen production facility 12 for de- oiling.
- a small portion of naphtha (100 bbl/d) in the pitch free vapour is also condensed, although the majority (>98%) of the cracked naphtha remains vaporized due to the large amount of non-condensable gas in the system 10.
- Both the vaporized and condensed naphtha streams are routed via cracked naphtha conduit 30 to the steam generator where it is combusted for energy. Since there is no capacity in the system 10 to add hydrogen, the unstable cracked liquid naphtha is not stabilized by hydrogen injection to meet pipeline specifications and is instead combusted on site to produce energy for the upgrading process.
- the heat contained in the gas oil product leaving the fractionation apparatus 18 is used to preheat the diluted bitumen feed to the diluent splitter 16 by means of conventional heat transfer equipment, and the water to a water treatment apparatus 32.
- the water treatment apparatus 32 serves to purify water for use by the steam generator 14 (via purified water conduit 34), and receives water for this purpose from the bitumen production facility 12 in the form of deoiled water via line 59, and from a make up water source 36.
- the non-condensable gases exiting the fractionation apparatus 18 is routed to a gas compressor 38 via a non-condensable gas conduit 40.
- the gas compressor 38 operates to increase the pressure of the gas from 5 psig to 50 psig by means of a centrifugal single stage compressor.
- Non-condensable gas not required for fluidization (7.3 MMSCFD) in the primary upgrader reactor 24 is routed to the steam generator 14 via pressurized gas conduit 42 where it is combusted to produce steam.
- Gas required for fluidization is supplied to the upgrader reactor 24 via fluidization gas conduit 43.
- vaporized naphtha could be recovered from the non-condensable gas with the use of suitable equipment.
- all of the cracked naphtha is separated from the pipeline- bound liquid product stream 26; in other words, the liquid product is substantially free of unstable fractions.
- the separated unstable fractions can be burned to produce energy for generating steam for the system 10; an additional benefit for separating the unstable fractions from the liquid product is to ensure that the liquid product has sufficient stability to meet pipeline specifications.
- some present pipeline specifications can tolerate liquid product having some amount of unstable fractions; therefore, a lesser amount of liquid naphtha and other unstable fractions can be separated from the product liquid, with the remaining unstable fractions being left in the liquid products for pipeline transport, provided that the liquid product meets pipeline specification.
- the liquid product may also have to meet refinery specifications.
- Operation of the fractionation apparatus 18 can be adjusted to change the percentage of unstable fractions that is separated from the liquid product; a bromine test, or equivalent detection methods as known in the art can be used to measure the stability of the liquid product and calculate the minimum amount of unstable fraction that must be fractionated and removed from the liquid product.
- the heavy pitch stream 25 from the fractionator apparatus 18, along with some gas oil is fed into the primary upgrading reactor 24 at a rate of 13,700 bbl/d.
- a primary upgrading reactor suitable for use with the system 10 is disclosed in Applicant's Canadian patent 2,505,632.
- the reactor 24 comprises a cross-flow fluidized bed 50 which receives the liquid pitch stream 25.
- the fluidized bed 50 comprises moving hot solid particles 51 fluidized by the fluidization gas from the fluidization gas conduit 43; the solid particles 51 in the fluidized bed 50 can be coke particles or sand particles and have a bulk horizontal velocity which is generally perpendicular to the vertical upward flow of fluidization gas.
- the fluidization gas is introduced into the bottom of the reactor 24 at a rate of 56 MMSCFD such that bubbling conditions are achieved in the fluidized bed 50.
- the fluidization gas is comprised of a mixture of non-condensable gas and cracked naphtha, although there may be also small concentrations of vaporized light gas oil and water.
- the liquid pitch stream 25 is introduced into the fluidized bed 50 by means of nozzles (not shown).
- the liquid pitch engulfs the solid particles 51 which move horizontally through the reactor 24.
- the energy contained in the fluidized solids support the chemical conversion of the pitch into lower boiling hydrocarbon products that continue until all of the feed material has been exhausted.
- the solid particles 51 drop in temperature as the feed liquid reacts.
- the cooled solid particles 51 exit the reactor 24 and are transported through cooled solids transfer lines 56 to the heater 46.
- the cooled solids are heated in the heater 46 and are returned to the reactor 24 via heated solids transfer line 57 to maintain a mean operating temperature of 500 0 C.
- the heated reactor gases containing fiuidization gas, unconverted pitch, non-condensable gas and the liquid products that are gaseous at reactor conditions, are passed through a series of cyclones to remove any entrained solids.
- the mixture of heated reactor gases is then routed to the fractionation column of the fractionator apparatus 18 via conduit 58.
- the primary function of the heater 46 is to heat the cooled solid particles 51 back up from 49O 0 C to the temperature required at the reactor inlet conditions to create a mean operating temperature of 500 0 C.
- the heater 46 is a partial oxidizer (POX) vessel (not shown) that partially oxidizes a portion of the coke; alternatively, other heaters known to those skilled in the art that are suitable for heating the solid particles can also be used.
- POX vessel is a fluidized vessel in which the coke is partially combusted under oxygen limiting conditions, at a temperature of 65O 0 C.
- the POX vessel is also used to preheat the fiuidization gas to the reactor 24, and to partially meet the site demand for superheating low grade steam (8,750 Ib/hr at 55 psig).
- the POX vessel is equipped with two different sets of heat exchange coils through which fiuidization gas and steam are circulated and heated.
- the heated solid particles 51 are returned from the POX vessel to the reactor 24 via heated solids transfer line 57, while flue gas (66 MMSCFD) resulting from the partial combustion process of the coke is directed via flue gas line 59 into the steam generator 14 for gas cleanup before discharge by flue gas lines 61 through a flare.
- the coke generated in the reactor that is not consumed in the POX vessel 46 is introduced into an Elutriator vessel (not shown), which separates the solids below a critical size from the larger particles, and returns them to the POX vessel.
- the balance of the coke (12,000 Ib/hr) is routed to the steam generator 14 via coke line 63.
- the CFB steam generator 14 has two primary purposes: to produce high quality pressurized steam for multiple applications in the system 10 and to remove sulfur released from the flue gas, coke, naphtha and fuel gas that are combusted in the process.
- the steam generator 14 produces 901 ,000 Ib/hr at 1300 psig of which 875,000 Ib/hr is routed to the SAGD facility and 27,000 Ib/hr are routed to the PUG.
- the steam generator 14 output can be varied depending on the needs of the system 10.
- the steam generator 14 comprises a circulating fluid bed boiler (CFB) of a type that as can be obtained from a number of vendors.
- CFB circulating fluid bed boiler
- the CFB is a fluidized bed unit designed to combust a number of fuels in liquid, gaseous or solid form supplied to the steam generator via fuel lines 30, 42, 63 and 65 and the flue gas line (not shown).
- One particularly suitable fuel is natural gas.
- the primary features of the steam generator 14 are:
- steam produced from the steam generator 14 is directed to the bitumen production facility 12 via steam supply line 13, with a small portion used to heat the diluent splitter 16 and preheat the diluted bitumen entering the fractionation apparatus 18 (steam supply line not shown).
- a water treatment facility 32 is provided to process water from the bitumen production facility 12, making the water suitable for steam production in the steam generator 14.
- falling film evaporator technology is provided for this purpose; however other water treatment technologies suitable for this purpose can be used as is known to those skilled in the art.
- Falling film evaporator technology is available from a number of vendors and has found utility in SAGD service.
- a three-effect evaporation system is used in this embodiment, with a single vapour recompression stage, which provides the energy required for evaporation.
- the water treatment facility 32 accepts de-oiled water (787,000 Ib/hr) from bitumen production facility 12, along with an amount of fresh water makeup (142,000 Ib/hr) through line 36.
- Caustic and scale inhibitor are added in a mixing tank. Air is removed in a de-aerator vessel (not shown), after which the water is introduced into the cascading three effect evaporator system.
- the purified water generated by the water treatment facility 32 is introduced to the steam generator 14 via purified water supply line 34, while the evaporator condensate is disposed of by deep well injection.
- system 10 Some notable features of the system 10 include:
- a cross-flow fluid bed primary upgrading (PUG) reactor 24 is used instead of a conventional furnace type delayed coking, or well-mixed fluid bed PUG units.
- the cross-flow fluid bed PUG reactor 24 generates more liquid products, produces less coke, and retains more of the native hydrogen than conventional coking technologies.
- the coke produced in the cross-flow fluid bed PUG reactor 24 is in a readily- consumable form and can thus be used as fuel to generate steam.
- the volume of fluidization gas required by the cross-flow fluid bed PUG reactor 24 is larger than other fluid bed technologies.
- an inert gas When an inert gas is put into contact with a volatile material its boiling point temperature is reduced, a process known as "stripping".
- the principle of stripping is applied in the system by contacting the fluidization gas with a whole barrel of bitumen, separating the pitch fraction from the non-pitch liquids. This configuration eliminates the need for the traditional atmospheric and vacuum columns, and the associated furnaces, that collectively perform this function;
- a circulating fluidized bed (CFB) steam generator and gas clean up facility 14 is used in the system 10 which is capable of consuming a number of fuels, including coke, hydrocarbon liquids, and fuel gas. This unit 14 is used to produce the high pressure steam required for the thermal production of bitumen.
- CFB circulating fluidized bed
- the unstable fraction of the naphtha can be consumed in the CFB steam generator and gas clean up facility 14 for energy, increasing the stability of the remaining product liquids while harnessing residual value in the unstable liquids as steam, and reducing the amount of natural gas or other imported fuel required to generate steam.
- CFB carbon capture and storage
- Water treatment is provided by falling film evaporators, a technology that enables the use of packaged boilers, keeping steam quality high while minimizing costs.
- the advantages introduced by the system 10 justify economic deployment at a much smaller scale, and potentially down to at least 20,000 bbl/d of whole bitumen feed.
- the application of the current system 10 for processing bitumen from the Peace River region of Alberta, Canada has been described.
- the bitumen feed consists of 49% (volume basis) pitch.
- the pitch has an MCR content of 23%.
- the reservoir basis using SAGD technology is a steam to oil ratio (SOR) of three.
- the system 10 generates three liquid streams: naphtha (boiling range to 177 0 C), light gas oil (boiling range from 177 0 C to 343 0 C), and heavy gas oil (boiling range from 343 0 C to 524 0 C).
- a portion of the naphtha fraction is consumed for its energy content, since this fraction is unstable without adding hydrogen, and there is no hydrogen production provided in the system 10.
- the naphtha may have more value as a liquid. This may be the case if, for instance there is a SUG facility in close proximity that can accept the liquid naphtha.
- Another embodiment of the invention involves installation of additional processing units that will allow for recovery of liquid naphtha from the gas. This equipment is well known in the prior art, and includes such units as Light Ends Recovery (LER), and others.
- LER Light Ends Recovery
- the upgrading reactor 24 is increased in size to the point where the alternative fuels generated by the reactor 24 are sufficient to completely meet all of the energy requirements of the system 10, thereby eliminating the need to externally supply natural gas to the system 10.
- the incremental bitumen required to enable this alternative embodiment is imported into the process, purchased on the open market. The economic benefits of completely eliminating all natural gas requirements, and the incremental liquid products produced from the imported bitumen are achieved with very little incremental capital, since the majority of the equipment does not change in size. This simple change dramatically increases the economics of the process.
- alternative fuels are used to offset import natural gas. While the use of alternative fuels is preferred for this embodiment, such use is not necessary. The decision not to consume alternative fuels may be made for environmental reasons. In another embodiment of the invention the energy requirements are met using conventional natural gas fired heating equipment. The solid coke byproduct is stockpiled.
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- Physics & Mathematics (AREA)
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Abstract
Description
Claims
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
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PCT/CA2008/002022 WO2010054464A1 (en) | 2008-11-14 | 2008-11-14 | Process for upgrading heavy oil and bitumen products |
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EP2361292A1 true EP2361292A1 (en) | 2011-08-31 |
EP2361292A4 EP2361292A4 (en) | 2014-05-21 |
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EP08878057.2A Withdrawn EP2361292A4 (en) | 2008-11-14 | 2008-11-14 | Process for upgrading heavy oil and bitumen products |
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US (1) | US20120000830A1 (en) |
EP (1) | EP2361292A4 (en) |
CN (1) | CN102245740A (en) |
AU (1) | AU2008364184B2 (en) |
BR (1) | BRPI0823273A2 (en) |
CA (1) | CA2743272C (en) |
MX (1) | MX2011005125A (en) |
RU (1) | RU2495079C2 (en) |
WO (1) | WO2010054464A1 (en) |
Families Citing this family (15)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
EP2655551A1 (en) * | 2010-12-23 | 2013-10-30 | ETX Systems Inc. | Method for feeding a fluidized bed coking reactor |
CA2729457C (en) | 2011-01-27 | 2013-08-06 | Fort Hills Energy L.P. | Process for integration of paraffinic froth treatment hub and a bitumen ore mining and extraction facility |
CA2853070C (en) | 2011-02-25 | 2015-12-15 | Fort Hills Energy L.P. | Process for treating high paraffin diluted bitumen |
CA2733342C (en) | 2011-03-01 | 2016-08-02 | Fort Hills Energy L.P. | Process and unit for solvent recovery from solvent diluted tailings derived from bitumen froth treatment |
CA2733862C (en) | 2011-03-04 | 2014-07-22 | Fort Hills Energy L.P. | Process and system for solvent addition to bitumen froth |
CA2735311C (en) | 2011-03-22 | 2013-09-24 | Fort Hills Energy L.P. | Process for direct steam injection heating of oil sands bitumen froth |
CA2737410C (en) | 2011-04-15 | 2013-10-15 | Fort Hills Energy L.P. | Heat recovery for bitumen froth treatment plant integration with sealed closed-loop cooling circuit |
CA2805804C (en) | 2011-04-28 | 2014-07-08 | Fort Hills Energy L.P. | Process and tsru with inlet with multiple nozzle configuration for distribution of solvent diluted tailings |
CA2857702C (en) | 2011-05-04 | 2015-07-07 | Fort Hills Energy L.P. | Process for operating a bitumen froth treatment operation in turndown mode |
CA2832269C (en) | 2011-05-18 | 2017-10-17 | Fort Hills Energy L.P. | Temperature control of bitumen froth treatment process with trim heating of solvent streams |
CA2941568A1 (en) | 2015-08-31 | 2017-02-28 | University Of New Brunswick | Process for upgrading heavy hydrocarbon liquids |
CA2963436C (en) | 2017-04-06 | 2022-09-20 | Iftikhar Huq | Partial upgrading of bitumen |
CN107597201B (en) * | 2017-09-13 | 2019-10-08 | 上海华畅环保设备发展有限公司 | Oil-containing outlet catalyst treatment and sorting reuse method and device |
CA3139525A1 (en) * | 2019-05-07 | 2020-11-12 | Kore Infrastructure, Llc | Production of renewable fuel for steam generation for heavy oil extraction |
CA3103502A1 (en) * | 2020-12-22 | 2022-06-22 | Suncor Energy Inc. | Light hydrocarbons content measurement in bitumen-containing process streams such as froth treatment tailings |
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WO2007021441A2 (en) * | 2005-08-09 | 2007-02-22 | Uop Llc | Process and apparatus for improving flow properties of crude petroleum |
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US2776799A (en) * | 1954-07-15 | 1957-01-08 | Exxon Research Engineering Co | Size reduction apparatus |
US3144400A (en) * | 1960-12-16 | 1964-08-11 | Exxon Research Engineering Co | Fluid coking process |
US3642441A (en) * | 1967-09-14 | 1972-02-15 | Falconbridge Nickel Mines Ltd | Treatment of metal chlorides in fluidized beds |
US3702819A (en) * | 1970-10-15 | 1972-11-14 | Exxon Research Engineering Co | Process for coking heavy hydrocarbons in a single vessel |
GB2108997B (en) * | 1981-11-03 | 1985-08-07 | Peter Spencer | Process and apparatus for thermal cracking and fractionation of hydrocarbons |
RU2186822C2 (en) * | 1997-06-19 | 2002-08-10 | Эксонмобил Рисерч Энд Инджиниринг Компани | Method of fluidized-bed coking |
CA2517811A1 (en) * | 2004-08-09 | 2006-02-09 | Richard Gauthier | Process for producing fuel |
US7413647B2 (en) * | 2005-03-07 | 2008-08-19 | Albert Calderon | Method and apparatus for upgrading bituminous material |
US20060231459A1 (en) * | 2005-03-28 | 2006-10-19 | Swan George A Iii | FCC process combining molecular separation with staged conversion |
RU2277638C1 (en) * | 2005-04-11 | 2006-06-10 | Евгений Иванович Кондра | Method of and device for producing electric energy from condensed fuels |
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2008
- 2008-11-14 EP EP08878057.2A patent/EP2361292A4/en not_active Withdrawn
- 2008-11-14 MX MX2011005125A patent/MX2011005125A/en active IP Right Grant
- 2008-11-14 RU RU2011120055/04A patent/RU2495079C2/en active
- 2008-11-14 BR BRPI0823273-3A patent/BRPI0823273A2/en not_active IP Right Cessation
- 2008-11-14 CA CA2743272A patent/CA2743272C/en not_active Expired - Fee Related
- 2008-11-14 WO PCT/CA2008/002022 patent/WO2010054464A1/en active Application Filing
- 2008-11-14 US US13/128,910 patent/US20120000830A1/en not_active Abandoned
- 2008-11-14 CN CN200880132322.4A patent/CN102245740A/en active Pending
- 2008-11-14 AU AU2008364184A patent/AU2008364184B2/en not_active Ceased
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US5431812A (en) * | 1994-03-07 | 1995-07-11 | Texaco Inc. | Coking process |
WO2007021441A2 (en) * | 2005-08-09 | 2007-02-22 | Uop Llc | Process and apparatus for improving flow properties of crude petroleum |
Non-Patent Citations (1)
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Also Published As
Publication number | Publication date |
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WO2010054464A1 (en) | 2010-05-20 |
AU2008364184A1 (en) | 2010-05-20 |
MX2011005125A (en) | 2011-09-06 |
EP2361292A4 (en) | 2014-05-21 |
BRPI0823273A2 (en) | 2015-06-23 |
US20120000830A1 (en) | 2012-01-05 |
RU2011120055A (en) | 2012-12-20 |
AU2008364184B2 (en) | 2013-08-22 |
RU2495079C2 (en) | 2013-10-10 |
CA2743272C (en) | 2015-11-10 |
CN102245740A (en) | 2011-11-16 |
CA2743272A1 (en) | 2010-05-20 |
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