WO2008058400A1 - Valorisation catalytique de fond de pétrole brut lourd et bitume des sables pétrolifères - Google Patents

Valorisation catalytique de fond de pétrole brut lourd et bitume des sables pétrolifères Download PDF

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Publication number
WO2008058400A1
WO2008058400A1 PCT/CA2007/002086 CA2007002086W WO2008058400A1 WO 2008058400 A1 WO2008058400 A1 WO 2008058400A1 CA 2007002086 W CA2007002086 W CA 2007002086W WO 2008058400 A1 WO2008058400 A1 WO 2008058400A1
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Prior art keywords
oil
catalyst
upgrading
hydrocracking
wellbore
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PCT/CA2007/002086
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English (en)
Inventor
Behdad Moini Araghi
Apostolos Kantzas
Perdro Pereira-Almao
Steven Larter
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The University Of Calgary
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Priority to US12/514,919 priority Critical patent/US20100212893A1/en
Publication of WO2008058400A1 publication Critical patent/WO2008058400A1/fr

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • 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
    • B01J27/00—Catalysts comprising the elements or compounds of halogens, sulfur, selenium, tellurium, phosphorus or nitrogen; Catalysts comprising carbon compounds
    • B01J27/02—Sulfur, selenium or tellurium; Compounds thereof
    • B01J27/04—Sulfides
    • B01J27/047—Sulfides with chromium, molybdenum, tungsten or polonium
    • B01J27/049—Sulfides with chromium, molybdenum, tungsten or polonium with iron group metals or platinum group metals
    • 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
    • B01J27/00—Catalysts comprising the elements or compounds of halogens, sulfur, selenium, tellurium, phosphorus or nitrogen; Catalysts comprising carbon compounds
    • B01J27/02—Sulfur, selenium or tellurium; Compounds thereof
    • B01J27/04—Sulfides
    • B01J27/047—Sulfides with chromium, molybdenum, tungsten or polonium
    • B01J27/051—Molybdenum
    • B01J27/0515—Molybdenum with iron group metals or platinum group metals

Definitions

  • the invention relates to systems and methods for catalytic down-hole upgrading of heavy oil and oil sand bitumens.
  • the method enables upgrading heavy oil in a production well within a hydroprocessing zone including the steps of: introducing a controlled amount of heat to the hydroprocessing zone; introducing a selected quantity of hydrogen to the hydroprocessing zone to promote a desired hydrocarbon upgrading reaction; and, recovering upgraded hydrocarbons at the surface.
  • the invention further includes the hardware capable of performing the method.
  • Heavy oil and bitumen are highly viscous oils that are difficult to produce and require upgrading before being sent into refineries. Costly processing methods and problematic transportation make heavy oils a reasonable substitute for conventional oil only when energy prices are high enough to justify their processing costs. Due to the sharp increase in oil prices in the 21st century, special attention has been paid to heavy oil and bitumen resources.
  • Heavy oil like any kind of petroleum or crude oil consists of a wide range of constituents mainly mixtures of hydrocarbons and compounds containing sulfur, nitrogen, oxygen and metals. Metals are typically vanadium and nickel and their percentage in the petroleum increases in most viscous oils. The physical properties of petroleum vary widely depending on its constituents and their amounts.
  • heavy oil is normally based on its API gravity and/or viscosity and is quite arbitrary.
  • a commonly accepted definition classifies the heavy oil as petroleum whose API gravity is between 10 and 20.
  • heavy oils usually and not always have sulfur contents of higher than 2 wt%.
  • bitumen the term refers to the oil produced from bituminous sand formations that are used to recover the bituminous material by mining operations.
  • Oil is also classified in the following general classifications based on the average boiling point of its constituents.
  • Gases & Naphtha The main constituent of petroleum gases is methane.
  • the other major hydrocarbons are ethane, propane, butane, isobutene and some C4+ alkanes.
  • Middle Distillates The main portion of this fraction is comprised of the saturated species; however, aromatics and heterocyclic compounds represent a considerable portion. Most of the aromatics are di- and tri-methyl naphthalenes. The percentage of the sulfur molecules is very low. Trace amounts of both basic and neutral nitrogen compounds are normally present. The boiling range is typically between 180 0 C and 34O 0 C.
  • Vacuum Gas Oils The boiling range for the vacuum gas oil (VGO) is between 340 0 C and 54O 0 C.
  • the quantity of the aromatics (mono- and di-aromatics) is greater than the saturates.
  • Saturated compounds in VGO consist of iso-paraffins and naphthene species.
  • Heterocyclic compounds are also significant in VGOs.
  • the major sulfur compounds are the thiophenes (mostly benzothiophenes and dibenzothiophenes) and thiacyclane sulfur which are present in greater amounts than sulfide sulfur.
  • Vacuum Residue This fraction is the most complex fraction and contains the majority of heteroatom molecules of the petroleum whose boiling points are over 540 0 C. Characterization of individual constituents of this fraction may utilize various empirical/semi-empirical thermo- physical models based on the observed functionalities, apparent molecular weight and elemental analysis. Heavy Oil Production from Oil Sands
  • Oil sands are deposits of bitumen and are found in 70 countries with three quarters of world reserves located in Canada and Venezuela. Production of heavy and extra-heavy oils in Canada started some 38 years ago by surface mining the Athabasca oil sands. As of December 31, 2005, Canada's proven oil reserves are estimated as 177.9 billion barrels from which 173.7 billion is in the form of oil sands.
  • bitumen from oil sands has been revolutionized in the recent years.
  • Enhanced oil recovery techniques (discussed below) enable producing reserves that are deeper than 75 meters under the ground surface.
  • Most of the in-situ production of bitumen and heavy oil comes from deposits buried more than 400 meters.
  • In-situ technology in recent years has been a subject of study for use in down-hole upgrading processes.
  • the in-situ upgrading that has been targeted in research projects includes hydrotreating of oil, mostly hydrodenitrogenation and hydrodesulfurization, hydrocracking and asphaltene precipitation. These upgrading projects mostly do not provide a high degree of upgrading in terms of contaminant removal and API gravity increase.
  • EOR Enhanced Oil Recovery
  • gases such as nitrogen and CO 2
  • liquid chemicals including polymers, surfactants and hydrocarbon solvents
  • thermal methods such as steam or hot water injection or in-situ generation of thermal energy.
  • Upgrading is generally defined as any treatment of bitumen or heavy oil that increases its value. Therefore, the minimum objective is to reduce the viscosity of oil and the maximum objective is to obtain a crude oil substitute of higher quality.
  • Hydroprocessing reactions are thermal processes that take place in the presence of hydrogen. Such reactions can be both destructive and non-destructive.
  • Destructive hydrogenation hydrolysis and hydrocracking
  • Non-destructive hydrogenation or hydrotreating are simple hydrogenation reactions during which the quality of oil improves by removing certain contaminants of oil from its molecular structure such as sulfur (hydrodesulfurization (HDS)), nitrogen (hydrodenitrogenation (HDN)) and metals.
  • HDS hydrodesulfurization
  • HDN hydrodenitrogenation
  • metals metals.
  • reaction conditions vary in the different processes, however a typical temperature range is 300-345 0 C and the hydrogen partial pressure can be in the range of 500 to 1000 psi.
  • the catalyst used in hydrotreating reactions is normally cobalt-molybdenum with typically 10% molybdenum oxide and less than 1% cobalt oxide and the support is alumina.
  • a wide range of metals can be effective: cobalt, iron, nickel promoted copper and copper chromite.
  • the type of catalyst that is used in each process can change based on the immediate objective. For example, CoMo type formulae are generally used for HDS reactions, the NiMo type are employed for hydrogenation and HDN reaction and the NiW type are used for hydrogenation of very low sulfur cuts.
  • the existence of sulfur and metals is a challenge in hydrotreating reactions because these compounds poison the catalyst. Therefore, more resistant catalysts are used such as CO-Mo-Al 2 Oi.
  • Hydrocracking is the reaction between hydrogen and oil fractions, mostly vacuum distillates and residue, in which the reactants crack into lighter fractions. Based on the objective chosen with respect to the extent of conversion and the quality of the products, hydrocracking can be divided into mild hydrocracking and conventional hydrocracking. Both of these two hydrocracking processes are similar with respect to the reactions, however, the products and their quality can vary because of the different reaction conditions. Mild hydrocracking normally takes place at some 50-80 bar (5-8 MPa) total pressure and temperature of 350-430 0 C, where conventional hydrocracking, the total pressure is about 100-200 bar (10-20 MPa) and the temperature is between 380-440 0 C. The mechanism of hydrocracking is similar to that of catalytic cracking but includes concurrent hydrogenation. The products of hydrocracking are either saturated or aromatic rings but not olefin.
  • hydrocracking reaction An important hydrocracking reaction is the partial hydrogenation of polycyclic aromatics and the ultimate rupture of saturated rings to monocyclic aromatics.
  • hydrocracking is used for processes such as desulfurization and residue conversion to lower boiling distillates.
  • Silica-alumina catalyst promotes cracking reactions where platinum, tungsten oxide, or nickel contributes to hydrogenation reactions.
  • hydrocracking and hydrotreating are major differences between hydrocracking and hydrotreating.
  • the upper limits of hydrotreating often overlap with the lower limits of hydrocracking.
  • the main advantages of down-hole upgrading include the reduction in refinery and upgrading costs, the reduction in size of surface upgrading facilities and the utilization of the pre- introduced heat from thermal processes.
  • Examples of past systems and methods of upgrading oil include US Patent 6,964,300 which describes a process of in situ thermal recovery from a permeable formation using a heater within the wellbore; US Patent 6,742,593 which describes in situ thermal processing of a hydrocarbon containing formation using heat; US Patent 7,121342 which describes thermal processes for subsurface formations; US Patent 6,996,374 which teaches a method of increasing hydrocarbon mobility within a permeable formation using gas; US patent application 2003/0062163 which teaches a method of in situ upgrading; US Patent 3,817,332 which teaches a method and apparatus of catalytically heating a wellbore; US Patent application 2006/017053 which teaches a process for improving extraction of crude oil by circulating hot hydrocarbons in order to heat an underground reservoir; US Patent 6,056,050 which teaches injecting steam through a horizontal well into a formation for enhancing viscous oil recovery; US Patent application 2006/0231455 which teaches a method for producing and upgrading oil; US Patent application 2005/023966
  • a method of upgrading heavy oil in a production well within a hydroprocessing zone comprising the steps of: introducing a controlled amount of heat to the hydroprocessing zone; introducing a selected quantity of hydrogen to the hydroprocessing zone to promote a desired hydrocarbon upgrading reaction; and, recovering upgraded hydrocarbons at the surface.
  • a catalyst is introduced to the hydroprocessing zone where the catalyst may be a nano-particle catalyst that may be circulated within the hydroprocessing zone.
  • the hydroprocessing zone is preferably a vertical section of a wellbore where heavy oil is preferably separated from water prior to introducing heavy oil into the hydroprocessing zone.
  • the catalyst may be tri-metallic catalysts of the general formula: B x M 1 y M2 z O(2 to 3) z S [(0 3 10 2) y + ⁇ 05 to 4) ⁇ ] where B is a group VIIIB non- noble metal and Ml and M2 are group VI B metals and 0.05 ⁇ y/x ⁇ 15 and l ⁇ z/x ⁇ 14.
  • l ⁇ z/x ⁇ 5 and the upgrading process is mild hydrocracking.
  • z/x 3 and the upgrading process is mild hydrocracking.
  • Other upgrading reactions may be hydrodenitrogenation and hydrodesulfurization.
  • Heat may be introduced to the one or more hydroprocessing zones (where different hydroprocessing reactions may occur) using any one of or a combination of electrical, hot fluid, or an in-well combustion device.
  • the method of the invention controls the reaction parameters in different areas of the hydroprocessing zone so as promote different hydroprocessing reactions in different areas.
  • the upgrading process is part of a steam flooding process including any one of steam assisted gravity drainage (SAGD), vapor extraction (VAPEX), cyclic steam stimulation (CSS) and CAPRI.
  • the invention provides a system for upgrading heavy oil in a production well within a hydroprocessing zone comprising: a downhole heater for introducing a controlled amount of heat to the hydroprocessing zone; a hydrogen delivery system for introducing a selected quantity of hydrogen to the hydroprocessing zone to promote a desired hydrocarbon upgrading reaction; and, a surface recovery system for recovering upgraded hydrocarbons at the surface.
  • the system may also include a downhole water separator for separating water from heavy hydrocarbon, the downhole water separator operatively located upstream of the hydroprocessing zone.
  • Figure 1 is a schematic diagram of an in situ upgrading system having horizontal and vertical wells
  • Figure 2 is a schematic diagram of an in situ upgrading system where production and injection take place through the same well;
  • Figure 3 is a schematic diagram of an in situ upgrading system where production and injection wells are located a distance from each other;
  • Figure 4 is a schematic diagram of an in situ upgrading system using a THAI configuration
  • Figure 5 is a schematic diagram of a two-stage separator within a wellbore
  • Figure 6 is a schematic diagram of horizontal wellbore segments and feed streams entering each segment
  • Figure 7 is a diagram of a HYSYS interface showing horizontal wellbore segments and entering feed streams
  • Figure 8 is a schematic diagram of vertical wellbore segments in series configuration
  • Figure 9 is a diagram of a HYSYS interface showing the vertical wellbore and the inlet streams
  • Figure 10 is diagram showing a network of hydrocracking reactions between various oil fractions
  • Figure 1 1 is a diagram showing a simplified hydrocracking network
  • Figure 12 shows HDS conversion percent for non-residue lumped fractions (Diam. 15 cm - production rate 1.39 m3/h);
  • Figure 13 shows HDS conversion percent for residue fraction (Diam. 15 cm - production rate 1.39 ⁇ i3/h);
  • Figure 14 shows HDN conversion percent for non-residue lumped fractions (Diam. 15 cm - production rate 1.39 m3/h);
  • Figure 15 shows HDN conversion percent for residue fraction (Diam. 15 cm - production rate 1.39 m3/h);
  • Figure 16 shows HDS and HDN conversion percent at 350 0 C for non-residue lumped fractions (Diam. 15 cm - production rate 1.39 m3/h);
  • Figure 17 shows HDS and HDN conversion percent at 35O 0 C for residue fraction (Diam. 15 cm - production rate 1.39 m3/h);
  • Figure 18 shows weight percent of residue sulfur compounds, non-residue lumped fractions sulfur compounds and the total sulfur compounds in feed and HDS product streams at various wellbore lengths at 35O 0 C (Diam. 15 cm - production rate 1.39 m3/h);
  • Figure 19 shows weight percent of residue nitrogen compounds, non-residue lumped fractions nitrogen compounds and the total nitrogen compounds in feed and HDN product streams at various wellbore lengths at 35O 0 C (Diam. 15 cm - production rate 1.39 m3/h);
  • Figure 20 shows Composition of feed (typical Alberta bitumen);
  • Figure 21 shows Volume percent change due to hydrocracking on conventional catalyst at 425°C (Diam. 15 cm) - SOR 0;
  • Figure 22 shows Volume percent change due to hydrocracking on conventional catalyst at 35O 0 C (Diam. 15 cm) - SOR 0;
  • Figure 23 shows volume percent change due to hydrocracking on conventional catalyst at 375°C (Diam. 15 cm) - SOR 0 ;
  • Figure 24 shows volume percent change due to hydrocracking on conventional catalyst at 403 0 C (Diam. 15 cm) - SOR 0;
  • Figure 25 shows volume percent change due to hydrocracking on conventional catalyst at 100 m wellbore (Diam. 15 cm) - SOR 0;
  • Figure 26 shows volume percent change due to hydrocracking on conventional catalyst at 200 m wellbore (Diam. 15 cm) - SOR 0;
  • Figure 27 shows volume percent change due to hydrocracking on conventional catalyst at 300 m wellbore (Diam. 15 cm) - SOR 0;
  • Figure 28 shows Volume percent change due to hydrocracking on conventional catalyst at 500 m wellbore (Diam. 15 cm) - SOR 0;
  • Figure 29 shows Volume percent change due to hydrocracking on conventional catalyst at 425°C (Diam. 1 Ocm) - SOR 0;
  • Figure 30 shows Volume percent change due to hydrocracking on conventional catalyst at 350 0 C (Diam. 10 cm) - SOR 0;
  • Figure 31 shows Volume percent change due to hydrocracking on conventional catalyst at 375°C (Diam. 10 cm) - SOR 0;
  • Figure 32 shows Volume percent change due to hydrocracking on conventional catalyst at 403 0 C (Diam. 10 cm) - SOR 0;
  • Figure 33 shows Volume percent change due to hydrocracking on conventional catalyst at 100 m wellbore (Diam. 10 cm) - SOR 0;
  • Figure 34 shows Volume percent change due to hydrocracking on conventional catalyst at 200 m wellbore (diam. 10 cm) - SOR 0;
  • Figure 35 shows Volume percent change due to hydrocracking on conventional catalyst at 300 m wellbore (Diam. 10 cm) - SOR 0;
  • Figure 36 shows Volume percent change due to hydrocracking on conventional catalyst at 500 m wellbore (Diam. 10 cm) - SOR 0;
  • Figure 37 shows Volume percent change due to hydrocracking on conventional catalyst at 350 0 C (Diam. 15cm) - SOR 1;
  • Figure 38 shows Volume percent change due to hydrocracking on conventional catalyst at 375°C (Diam. 15cm) - SOR 1 ;
  • Figure 39 Volume percent change due to hydrocracking on conventional catalyst at 403 0 C (Diam. 15cm) - SOR 1 ;
  • Figure 40 shows Volume percent change due to hydrocracking on conventional catalyst at 425°C (Diam. 15cm) - SOR 1 ;
  • Figure 41 shows Volume percent change due to hydrocracking on conventional catalyst at 100 m wellbore (Diam. 15 cm) - SOR 1 ;
  • Figure 42 shows Volume percent change due to hydrocracking on conventional catalyst at 200 m wellbore (Diam. 15 cm) - SOR 1 ;
  • Figure 43 shows Volume percent change due to hydrocracking on conventional catalyst at 300 m wellbore (Diam. 15 cm) - SOR 1 ;
  • Figure 44 shows Volume percent change due to hydrocracking on conventional catalyst at 500 m wellbore (Diam. 15 cm) - SOR 1 ;
  • Figure 45 shows Volume percent change due to hydrocracking on conventional catalyst at 350 0 C wellbore (Diam. 15 cm) - SOR 10;
  • Figure 46 shows Volume percent change due to hydrocracking on conventional catalyst at 375°C wellbore (Diam. 15 cm) - SOR 10;
  • Figure 47 shows Volume percent change due to hydrocracking on conventional catalyst at 403 0 C wellbore (Diam. 15 cm) - SOR 10;
  • Figure 48 shows Volume percent change due to hydrocracking on conventional catalyst at 425°C wellbore (Diam. 15 cm) - SOR 10;
  • Figure 49 shows API gravity increase for SOR 0 - conventional catalyst
  • Figure 50 shows API gravity increase for SOR 1 - conventional catalyst
  • Figure 51 shows API gravity increase for SOR 10 - conventional catalyst
  • Figure 52 compares the API gravity increase at 425°C for SOR 0 and SOR 1 - conventional catalyst
  • Figure 53 compares the API gravity increase at 403 0 C for SOR 0 and SOR 1 - conventional catalyst
  • Figure 54 shows volume percent change due to hydrocracking on UD catalyst at 425°C wellbore (Diam. 15 cm)
  • Figure 55 shows Volume percent change due to hydrocracking on UD catalyst at 350 0 C wellbore (Diam. 15 cm);
  • Figure 56 shows Volume percent change due to hydrocracking on UD catalyst at 375 0 C wellbore (Diam. 15 cm);
  • Figure 57 shows Volume percent change due to hydrocracking on UD catalyst at 403 0 C wellbore (Diam. 15 cm);
  • Figure 58 shows API gravity increase for SOR 0 - UD catalyst
  • Figure 59 compares the API gravity increase at 425°C for SOR 0
  • Figure 60 compares the API gravity increase at 403 0 C for SOR 0
  • Figure 61 compares the API gravity increase at 375°C for SOR 0.
  • systems and methods for upgrading hydrocarbons within a petroleum reservoir are described.
  • the methods enable upgrading of heavy, extra heavy and shale oils and bitumen within a production well bore using selective downhole heating elements, hydrogen and catalyst injection so as to integrate exploitation with in-situ upgrading.
  • the methods of the invention are particularly applicable to steam-assisted gravity drainage (SAGD) and vapor extraction (VAPEX), and cyclic steam stimulation (CSS) recovery methodologies.
  • SAGD steam-assisted gravity drainage
  • VAPEX vapor extraction
  • CSS cyclic steam stimulation
  • the invention provides a system for hydrocarbon upgrading in a well bore system having both horizontal and vertical sections.
  • the methodologies of the invention may be applied to other EOR techniques including wells having only a single vertical section.
  • the horizontal section 10 serves to collect the hot oil/water mixture feed 1 1 via perforations 12 on its surface, with any one of or both of the horizontal section 10 and/or vertical section 14 serving as a reactor with reactor elements.
  • the temperature of the feed is increased by heat introduced to the body of the well by any one of or a combination of electrical, combustion, hot gases or other localized heaters
  • the feed 1 1 may be mixed with hot hydrogen injected into the well via a gas liner
  • down-hole or in-situ upgrading processes are described for various EOR methodologies. Such processes have been a previously unsuccessful alternative to conventional upgrading processes as a result of the difficulties of placing catalyst underground, treating the abundant amounts of brine, high partial pressure of steam and low partial pressure of hydrogen.
  • down-hole upgrading by employing the down-hole energy (up to 35 MPa and 80 0 C), and the porous media (mineral formation) that can act as a natural chemical catalytic reactor.
  • the process of in-situ upgrading includes:
  • Carbon rejection is beneficial as it leaves highly carbonaceous materials in the wellbore and produces upgraded oil.
  • the deposition of such materials in the reaction medium will contribute to wellbore plugging and catalyst deactivation.
  • most oil reservoirs also contain significant amounts of brine that will have a significant effect in down-hole upgrading of heavy oils.
  • any injected gas in order to have a reasonable partial pressure to react, must have a higher pressure than that of injected steam.
  • the saturated steam pressure at 300 0 C is about 1235 psi, for a wellbore with reaction temperatures of 250-350 0 C to contain steam, a depth of 1 150 to 2800 feet is required. In other words at such conditions the gas must be injected at over 1200 psi for a length of some 2000 feet.
  • a catalyst bed is placed in an oil-bearing interval by gravel packing, proppant injection, or water injection as shown in Figure 2.
  • Oil flows over the catalyst either naturally or by induced drive mechanisms. Oil is produced through the perforations in the well casing and is directed to the surface by the production tubular.
  • An injection tubular is used to inject heated fluids, such as hydrogen or hydrogen donors into a volume below the catalyst bed.
  • the catalyst is placed in close vicinity to the production well; however, the injection process is through the injection well, placed a further distance from the production well.
  • Thermal drive is induced by a combustion front.
  • the combustion produces hydrogen and carbon monoxide which mobilizes the oil front.
  • water transfers heat ahead of the combustion front by steam override.
  • additional heat can also be provided through the production zone as per Figure 1.
  • catalyst is placed inside or around a horizontal production well, where a vertical injection well injects hot air into the reservoir. This method is called CAPRI and is the catalytic form of Toe to Heel Air Injection (THAI) method.
  • THAI Toe to Heel Air Injection
  • SAGD Steam Assisted Gravity Drainage
  • two parallel wells exist including an upper well for steam injection well and a lower one as the production well.
  • the steam injection well drives the oil into the other horizontal well underneath.
  • Catalyst can either be a solid fixed bed or an ultra dispersed catalyst in the liquid phase.
  • DOWS down-hole oil water separation
  • DOWS down-hole oil water separation
  • gas is separated from the liquid through gravity separation without introduction of any centrifugal force, nozzles or other types of mechanisms utilizing the difference in the density of the two phases as the factor in the separation.
  • This design involves the installation of a pump intake below the lowest point of fluid entry into the wellbore and requires an open casing-tubing annulus along the wellbore. The gas bubbles rise through the liquid phase and leave its surface and move upwards in the casing- tubing annulus. The liquid phase is accumulated at the bottom of the well and enters the pump intake to be discharged into the tubing.
  • separation occurs in two stages as shown in Figure 5.
  • separation of gas from liquid occurs in the wellbore tubing-casing annulus.
  • the gas bubbles leave the gaseous liquid in the annulus and move upwards in the casing.
  • the remaining mixture of gas and liquid enters the second stage down-hole gas separator through an anchor port and its perforations on its surface leading to further separation.
  • the amount of gas that flows with the liquid into the tube and to the pump intake is minimized.
  • various methods can be utilized such as introducing hot fluids, steam injection or fire flooding.
  • Other methods use point sources including down-hole steam generation or combustion, electromagnetic stimulation and down-hole heating with electric coils.
  • Down-hole gasification or combustion may be utilzed for sub-terrain heating.
  • a mixture of fuel and air are injected into the wellbore and are ignited creating a front that moves towards the production well.
  • Wet oxidation can been used to inject steam under a formation at 315-340 0 C and 2000-2500 psi.
  • a heat conductive system that employs a down-hole gas-fired burner is capable of heating a transfer fluid to 815-1400 0 C.
  • Another benefit of down-hole heating is the generation of CO which in proper conditions controls the extent of oxidation (together with combustion or partial oxidation catalysts), produces H 2 through the water-gas shift reaction.
  • a particular benefit is that operation of a down-hole steam generator or gasifier below a catalyst zone produces upward flow of heat and combustion gases that can provide heat and H 2 (or CO) for upgrading.
  • Catalyst is normally placed in the vicinity of the well either by injecting a liquid phase solution or adding solid catalyst particles around the wellbore.
  • Homogenous catalysts mostly have similar active metals to those of heterogeneous catalysts, mainly molybdenum and iron.
  • the additives are mostly cobalt and nickel and the sulfide metal is the active phase.
  • An advantage to using a fluid phase catalyst is that it can be prepared in remote areas. For example amines such as ethylene diamine can be added to aqueous ammonium heltamolybdate and cobalt nitrate mixtures which stabilizes the solution and allows the metals to be deposited in areas remote from solution preparation.
  • Homogenously dispersed catalysts can also be used for combustion catalytic upgrading.
  • Aqueous phase iron or tin salts dispersed in a mixture of sand/oil/water in a combustion tube experiment resulted in increased fuel deposition, higher velocity of combustion front and lower oxygen combustion.
  • a wellbore consisting of both horizontal and vertical sections was studied as per Figure 1 although it is understood that the upgrading technologies described herein may be applied to other EOR techniques as understood by those skilled in the art.
  • the horizontal well collects the mixture of oil and steam via the perforations on its surface and directs them to the vertical section.
  • the total length of the horizontal section may be varied based on the well location and reservoir length. In this description, the length of this section was assumed to be 1000 meters.
  • the vertical well may also have different lengths which will result in various residence times for the upgrading reactions.
  • the down-hole temperature of oil was assumed to be 220 0 C as a typical high temperature of SAGD steam injection.
  • HYSYS simulator To evaluate the effectiveness of in-situ upgrading, a HYSYS simulator was used (Aspen Tech., Houston). This simulator offers a comprehensive Oil Manager which allows introducing various oil assays to the model and the creation of pseudo-components based on the desired assay. Also the reaction package provides a high level of control over the reaction stoichiometry, kinetics, units and the phases. Finally the simulator encompasses a comprehensive set of objects and unit operations that permit simulation of the wellbore with high level of control over each segment.
  • the model consists of the vertical and horizontal sections of a wellbore and the upgrading sections.
  • the oil enters the wellbore through the perforations and the entrance point.
  • the fluids then pass through an optional steam/water separator 50, followed by flow into the vertical wellbore where the oil is mixed with the injected stream of ultra dispersed catalyst and hydrogen gas.
  • the mixture of oil, catalyst and hydrogen moves upwards where it is heated and the hydroprocessing reactions take place.
  • the produced oil is partially upgraded.
  • Simulation models in HYSYS are created based on previously defined fluid packages. The choice of any package is based on the specific system under consideration (the components that are involved and their interaction) and also the operating conditions.
  • the main thermodymic package choice is either the Equation of State or the Activity Model.
  • the Equation of State chosen for this model is Peng-Robinson which was developed originally to deal with hydrocarbon gas models. This model has been shown to be very efficient for most hydrocarbon based fluids over a wide range of operating conditions.
  • components can either be defined as pure or pseudo- components. Pure components are specific chemical compounds such as water or hydrogen.
  • the pseudo-components which are called hypothetical components in HYSYS, are not pure but are treated as those. Their definition is based on the objective and nature of the simulation and can vary.
  • a major advantage of defining pseudo-components is to limit the number of components in the system by grouping them into limited number of groups. This significantly decreases the computation time needed for analyzing the components of a stream without affecting the accuracy.
  • the components are defined based on their properties which are usually required for thermodynamic calculations. These required properties vary in different simulators but some common ones are the critical temperature, pressure and volume, acentric factor, solubility parameter, liquid molar volume, van der Waals area and volume and latent heat of vaporization. There is no need to input these properties for the pure components because they exist in the simulator's database; however, the case is different for pseudo-components and their properties are normally estimated by the correlations and some major input properties, usually normal boiling point, specific gravity and molecular weight.
  • the Oil Manager in HYSYS is used to input the characteristics of the oil assay in general and the feed in particular.
  • the main input data is the True Boiling Point (TBP) distillation curve which is obtained as part of the assay. This requires inputting the boiling points of each fraction and the corresponding volume percents in the liquid form at a specific pressure.
  • TBP True Boiling Point
  • Any blend in this section will be an arbitrary mixture of oil fractions. The blend is defined as follows:
  • a temperature is input and the number of cuts with End Boiling Points of less than this value is input.
  • the cut End Point of 204 0 C is input and then in the cell across the row, number 1 is input showing that there is one cut with a boiling point of less than 204 0 C.
  • the temperature of 343°C as the End Point is input and the number of the cuts is again 1, showing that there is one cut between 204 0 C and 343 0 C.
  • the same procedure is used to input VGO and the residue.
  • the other hypothetical components that are defined separately are sulfur and nitrogen compounds. These two are the base components for HDS and HDN reactions respectively.
  • the sulfur and nitrogen compounds, found in each cut, are intrinsically different. However, these molecules are classified into two different classes; the first one including those present in the gas oil cut with boiling points of 300-600 0 C and the second one including those in the residue fraction. Therefore, one sulfur compound and one nitrogen compound is defined in each of these two classes and HDS and HDN reactions are based on these hypothetical components.
  • the average properties of such molecules i.e. density, molecular weight, etc., are used to define such compounds.
  • H 2 S hydrogen sulfide
  • NHj ammonia
  • the mixture of oil/steam enters the horizontal wellbore via the perforations on its surface.
  • These perforations are placed on the horizontal casing at intervals of about 15 cm
  • the fluid flow rate ( n ) for each of these perforations is calculated as 0.015 m3/day.
  • each segment represents the combination of the feed streams that drain into the successive pipe segment via its perforations.
  • the length of each segment is 200 meters and assuming an interval of 15 cm for these perforations, their total number for each segment is
  • This flow rate corresponds to the new feed stream before each segment.
  • the first feed stream enters the first pipe segment. Having passed through the first pipe segment, the first feed stream mixes with the second feed stream that enters the wellbore at the start of the second segment. The mix stream is directed to the second segment. This procedure continues until the final stream is ready to enter the vertical wellbore.
  • the feed consists of oil and water with an oil/water ratio of 2.
  • the 5 feed streams in Figure 6 are mixtures of oil and water streams that have a specific oil/water ratio of 2. Calculations showed that for a total production rate of 100 m3/day (standard ideal volume flow), each oil stream entering has a standard flow rate of 0.28 m3/h which sums to 1.4 m 3 /h (33.6 m 3 /day) for the 5 streams.
  • Each water stream has a standard flow rate of twice as much as the oil or 0.56 mVh.
  • the horizontal production wellbore was simulated in HYSYS using a pipe segment and mixers as shown in Figure 7.
  • the mixers do not influence the parameters of the system such as the pressure drop.
  • the pipe sizing is based on the information input by the user. This information determines the inner diameter and pipe material and then based on pipe schedules in the HYSYS database, the other data are determined.
  • Table 3 shows some of the pipe segment input data:
  • V is the velocity of fluid and is calculated as:
  • the final pressure drop due to the friction on the walls of the wellbore is calculated for a horizontal well of 1000 meters to be 300 Pa which is negligible.
  • Model 3 20 50 0.21 The results show that the pressure drop does not change substantially in either of these models. Also the final temperature of the feed does not show a significant change (about 5°C decrease for 1000 meters wellbore). Therefore the scaling used in this model (5 segments) was maintained as the base model.
  • Upgrading reactions take place in the vertical section of the wellbore.
  • the heating system located at the start of the vertical well increases the temperature of the oil and water mixture. This increase is assumed to take place within the first 25 meters of the well. This length is arbitrary; however the exact length will be dictated by the power/intensity of the down-hole heat equipment.
  • the heated section of the well is divided into 5 segments which are 5 meters in length. For hydrotreating reactions, each segment provides a temperature increase of 25°C to eventually increase the stream temperature to 350 0 C along the first 25 meters of the vertical wellbore. Similarly, for the hydrocracking reactions the temperature will be progressively increased depending on the final desired temperature. For a reacting temperature of 400 0 C, each segment must provide some 35 0 C of temperature increase.
  • the vertical well is simulated as a number of plug flow reactors which are arranged in series.
  • the reason for using more than one plug flow reactor is to allow for a higher level of control over the model parameters and to provide better tracking of the gradual increase in the conversions due to temperature and pressure changes along the wellbore.
  • a schematic of the reactor simulation is shown in Figure 8.
  • X 7 l -(l -x, Xl -x 2 Xl -x,Xl -* 4 Xl -x $ ) where x ⁇ is the total conversion.
  • Figure 9 is the FIYSYS process flow schematic for the vertical wellbore reactor.
  • Oil, water and hydrogen streams may have different ratios and temperatures before entering the vertical wellbore.
  • Stream 1 represents the feed entering the vertical well with a temperature that may be varied by the user (22O 0 C in this model).
  • Section 2 shows five plug flow reactors, each 5 meters long, and their energy streams which control the outlet temperatures.
  • Section 3 is the long plug flow reactor without an energy stream whose length may vary between 75 m and 475 m.
  • Section 4 is the product stream. Simulation Objects
  • the streams and the mixers in the vertical section are defined similar to those in the horizontal section.
  • the major simulation object that the vertical section contains is the group of plug flow reactors.
  • the plug flow reactors in this section serve both as the vertical well and as reactors for hydroprocessing reactions.
  • Each plug flow reactor is defined by 3 major sets of input data: the geometry, the reaction sets and the specific parameters such as pressure drop.
  • the plug flow reactor can also have an energy stream when an understanding of the heat transfer parameters or temperature changes exist.
  • the desired length and diameter of the reactor is input as is the value for the void fraction of the reactor.
  • Each reactor can have one single or multiple sets of input reactions. For instance in the case of hydrocracking, four reactions in a network take place simultaneously. However in hydrotreating, only one reaction is active at a time. The pressure drop due to the hydrostatic head must be independently calculated and input.
  • the pressure drop in each segment is mainly due to hydrostatic head and not friction.
  • the pressure drop due to the friction is calculated for the vertical wellbore (length 200 m) from:
  • the data that must be found are the order by which the reactants take part in the reactions (m and n) and the values of k 0 and Ea for each reaction.
  • two sources where chosen for simulation kinetic model, namely hydrotreating and hydrocracking reaction data are two sources where chosen for simulation kinetic model, namely hydrotreating and hydrocracking reaction data.
  • the reactants in the hydrocracking reactions are a hydrocarbon and hydrogen.
  • the product is a lighter hydrocarbon of low molecular weight.
  • the following formula represents the general form of a hydrocracking reaction where HC 1 represents the heavy hydrocarbon, HC2 is the lighter one and a is the stoichiometry coefficient for hydrogen:
  • HCl can be the residue and HC2 can be the vacuum gas oil (VGO).
  • the hydrogen partial pressure effect was considered in the final conversion extent.
  • the kinetic data for the conventional catalyst were obtained from the literature where the hydrogen pressure is higher than the one used in this study (3MPa).
  • 3MPa the one used in this study
  • hydrogen consumption in the reactions at various hydrogen pressures can be an indication of the change in the conversion level which provides a similar prediction for the conversion drop.
  • the steam is assumed to be present in the reaction medium, the hydrogen partial pressure will be even lower than 3MPa depending on the amount of steam present. In severe cases it can lower the hydrogen partial pressure to an extent that the conversion drops to zero.
  • the kinetic data for the ultra dispersed catalysts did not require the corrections applied to the conventional catalyst data of the literature; the reason being that the UD catalyst data are obtained at pressures near the simulation model conditions.
  • the reactions may be defined in various forms such as inputting the kinetic data in power law or Langmuir-Hinshelwood forms, introducing the conversion function form based on the temperature or introducing the function form of the equilibrium constant based on free Gibbs energy.
  • the first set contains the stoichiometry information as well as the order by which each component participates in the reaction rate equation.
  • the reaction order for HDS reactions is 1.5 and for HDN reactions is 1.
  • Hydrogen consumption in hydroprocessing reactions was used as an indication of the relative volume or mole numbers of reactants (oil fractions and hydrogen).
  • the hydrogen consumption information for the reactions of interest the corresponding stoichiometry number by which hydrogen takes part in each reaction was obtained.
  • Table 9 A summarized example of HDS reactions data is presented in Table 9:
  • HC is the hydrocarbon with sulphur in its structure.
  • Table 10 shows an example of another set of information required to define a reaction in HYSYS. These information are:
  • the 'Basis' which is the form of the 'Basis Component' as input into the model which can be mass fraction, mass concentration, mole fraction or mole concentration.
  • the reaction phase which is one of the following cases: liquid, vapour, overall (mixture of both liquid and vapour).
  • the reaction phase for hydroprocessing reactions is normally liquid phase, where the products will partly join the vapour phase and exit the reactor rather quickly.
  • k is the kinetic constant for the forward reaction and is defined as:
  • T temperature in Kelvin.
  • E and E' are the activation energies for the forward and reverse reactions respectively.
  • the final tab in the reaction section inputs the frequency factor, the activation energy and the P factor. This factor shows the dependence of k 0 on temperature and is zero in most cases.
  • Table 11 An example of such a table for HDS reaction of non-residue fraction molecules is shown in Table 11 :
  • the results include those for hydrotreating including both HDS and HDN reactions, hydrocracking using conventional catalyst in the presence and absence of water and finally hydrocracking of heavy oil using ultra dispersed (UD) catalyst.
  • UD catalyst kinetics Conventional catalyst kinetics was found in the literature for the commonly used catalysts as discussed above. UD catalyst kinetics are discussed below.
  • the hydrotreating results show the conversion percents of sulfur and nitrogen compounds and final changes in their weight percent due to the reactions at different temperatures and residence times.
  • Figure 16 compares the results of HDS and HDN reactions at 350 0 C and different residence times for non-residue lumped fractions which shows the considerably higher conversion percent for the HDS reactions of the non-residue lumped fractions in comparison with HDN reactions.
  • the results of HDS and HDN reactions on residue fraction are also compared in Figure 17.
  • Figure 19 shows the percent conversion for hydrodenitrogenation for different oil cuts.
  • hydrocracking of bitumen targets the production of a lighter crude oil through down- hole upgrading.
  • the produced oil should have a lower molecular weight than that of bitumen.
  • hydrocracking consists of a network of reactions that occur simultaneously.
  • residue hydrocracks into VGO, middle distillates and naphtha residue hydrocracks into middle distillates.
  • VGO hydrocracks into middle distillates. Therefore the volume percent of residue is always declining while the middle distillates increase.
  • the increase or decrease of volume percent depends on the extent to which residue conversion proceeds and if this will be higher than that of the VGO conversion into middle distillates.
  • the volume percent of VGO will increase along with an increase in the quantity of middle distillates.
  • the reason is that kinetic parameters of residue hydrocracking into VGO promote a faster reaction than conversion of VGO into middle distillates. In other words, there is an accumulation of VGO in the process of production and conversion, resulting from the faster production rate in comparison with the conversion rate.
  • the composition of feed oil is shown in Figure 20.
  • Figures 21 to 24 present simulation model results for hydrocracking at four different temperatures, namely 425°C, 350 0 C, 375 0 C and 403 0 C respectively.
  • Figure 21 shows the volume percent increase of middle distillates with an increase in the wellbore length (residence time).
  • the VGO increases by up to 68% at a length of 300 meters and then suddenly decreases to 60%.
  • the reason is that the amount of residue at 300 meters is so low that its rate of conversion no longer exceeds that of VGO at a point between 300 and 500 meters.
  • This result implies that VGO from that point on will be converted into middle distillates and there is no net production of VGO anymore.
  • Another result observed in this figure is the constant amount of naphtha fractions. It can be seen that the volume percent of this fraction is not increasing when the depth of wellbore increases to 500 m.
  • Figure 22 shows that hydrocracking conversions at 35O 0 C with a conventional catalyst are very small that there are no major changes in the volume percents at different wellbore lengths. This is due to the low temperature level which is not able to promote the reactions to considerable extents.
  • Figure 23 shows the conversions at 375°C.
  • the volume percents change from 100 m to 500 m.
  • the trend of this change is that the volume percent of middle distillates and VGO increase when residue decreases.
  • Figure 24 shows the same trend as Figures 22 and 23, however the conversions are higher due to the higher temperature.
  • Figure 29 shows the volume percent change at 425°C for all three fractions of oil and the residue. Similar to Figure 21, the naphtha volume percent does not change with length.
  • Figures 30-32 show the results of runs at 350 0 C, 375 0 C and 403 0 C respectively.
  • Figures 33-36 show the results of runs for different length well bores. The trend of change in the fractions is the same as the previous set presented for diameter of 15 cm; however the conversions are lower because of small diameter or small residence time.
  • the volume percent of residue decreases while that of the VGO and middle distillates increases. For 35O 0 C the conversion is so low that no considerable change in the volume percents is observed.
  • API 14 L5 - 131.5
  • Table 16 shows the values for specific gravities of the oil cuts, based on a typical Alberta bitumen assay:
  • Residue 1.06 By assuming that the specific gravity values do vary little with conversions, the specific gravity of the product stream is calculated based on the volume percents of the oil cuts. Then, using the value of the specific gravity of the oil, the API gravity is obtained and can be compared to that of the feed.
  • Figures 49-51 present the API gravity increase as a result of the volume percent change in the fractions at three different SORs. These figures show that any increase in the residence time results in an increase in the API gravity of the feed. Note the higher temperatures provide higher API changes. When the SOR is 10, the steam/oil ratio is very high, such that the API gravity change is zero in all cases except for a temperature of 425°C.
  • Table 17 compares the frequency factors of each reaction: Table 17: Comparing the Frequency Factors for Conventional Catalyst and UD Catalyst ko (1/h) ko (1/h)
  • Figures 59-61 show the API gravity increase for the UD catalyst compared to that of conventional catalyst and as expected shows a higher conversion and therefore a higher API gravity increase.
  • the catalysts applicable to the invention are continuously introduced in the form of a micro-nano particulate dispersed in hydrocarbon media as described in Applicant's co-pending application (United States application No. 1 1/604,131 and incorporated herein by reference) or a conventional catalyst or catalyst system such as a fixed bed catalyst is used.
  • catalysts formulated to enable hydrogenation, hydrotreating including desulfurization, hydrodemetalization and denitrogenation and hydrocracking reactions may be introduced into one or more hydroprocessing zones by means of separate or combined injection systems wherein the point of injection of the hydrogen and/or catalysts will define the location of one or catalytic hydroprocessing zones.
  • the catalyst formulation and process conditions may be adjusted such that a suite of in-well processing elements can effect overall upgrading involving both hydrotreating and hydrocracking or other combinations of processes to produce an oil of desired quality and specification.
  • Temperature, hydrogen flow and catalyst flow may be continuously monitored and adjusted at the surface based on produced oil composition analysis at surface or using in situ sensors in order to adjust the downhole reactor variables during processing. Such adjustments may be made in real time using a variety of physical proxies for oil properties including viscosity, bulk chemical composition, SARA (Saturates, Aromatics, Resins, Asphaltenes) and/or chemical proxies indicative of the reaction regime (hydrotreating, hydrocracking, visbreaking etc).
  • SARA Natural, Aromatics, Resins, Asphaltenes
  • catalyst compositions as described in Applicant's co-pending United States application are useful in in situ hydrocarbon upgrading applications.
  • Catalyst compositions, characterized by their particle size and ability to form microemulsions are described herein.
  • the catalyst compositions are bi- or tri-metallic compositions dissolved in a protic medium containing a VIII B non-noble metal and at least one VI B metal (preferably one or two) in the presence of a sulfiding agent.
  • the atomic ratio of the Group VI B metal to Group VIII B non-noble metal is from about 15: 1 to about 1 : 15.
  • Suitable catalyst compositions can be used in a variety of hydrocarbon catalytic processes to treat a broad range of feeds under wide-ranging reaction conditions such as temperatures from 200 0 C to 480 0 C .
  • 0.2 ⁇ y/x ⁇ 6 and preferably y/x 3.
  • B x M 1 y M2 z O(2 to 3)zS[(0 3 to 2)y + (0 5 to 4)x]
  • B is a group VIIIB non-noble metal and Ml and M2 are group VI B metals and 0.05 ⁇ y/x ⁇ 15 and l ⁇ z/x ⁇ 14 are also effective.
  • tri-metallic catalysts include those wherein the y/x ratio is in the range of 0.2 ⁇ y/x ⁇ 6.
  • the range z/x is preferably determined by the desired use of the catalyst.
  • the hydrocracking results were also compared for two different catalyst kinetics. The results showed that the hydrocracking conversions were higher for the UD catalyst in comparison with a conventional catalyst.
  • the API gravity increase when using the D catalyst was 1 1.6 which is 1.9 points higher than when conventional catalyst kinetics was used.
  • the API gravity increase using the UD catalyst kinetics was 8.7 which was 3.3 points higher than the increase for the conventional catalyst kinetics.
  • a new method for in-situ upgrading is provided that remedies many practical problems by using the wellbore capacity for the upgrading reactions.
  • This approach optionally eliminated the need for down-hole catalyst placement by using ultra dispersed catalysts in liquid phase which enters the wellbore volume and gets produced with the upgraded oil.
  • the necessary heat of the reaction is concentrated in the vertical wellbore rather than being introduced to the large down-hole bitumen reserve in order to minimize the heat loss.
  • the reactions occur over the ultra dispersed catalysts which offer a high effective contact area and have higher kinetic frequency factor for hydrocracking reactions which then results in substantially higher conversions.

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Abstract

La présente invention concerne des systèmes et procédés pour la valorisation catalytique de fond de pétrole brut lourd et du bitume des sables pétrolifères. Le procédé permet la valorisation de pétrole brut lourd dans un puits de production à l'intérieur d'une zone d'hydrotraitement et consiste : à introduire une quantité contrôlée de chaleur dans la zone d'hydrotraitement; à introduire une quantité sélectionnée d'hydrogène dans la zone d'hydrotraitement pour favoriser une réaction de valorisation souhaitée d'hydrocarbure; et à récupérer les hydrocarbures valorisés à la surface. L'invention concerne en outre le matériel permettant de réaliser le procédé.
PCT/CA2007/002086 2006-11-14 2007-11-14 Valorisation catalytique de fond de pétrole brut lourd et bitume des sables pétrolifères WO2008058400A1 (fr)

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WO2011078681A1 (fr) 2009-12-22 2011-06-30 Institutt For Energiteknikk Procédé et dispositif de production simultanée d'énergie sous la forme d'électricité, de chaleur et de gaz d'hydrogène
KR101325908B1 (ko) 2011-09-02 2013-11-07 한국화학연구원 개선된 오일샌드 회수 및 개질기술
CN108952693A (zh) * 2018-04-19 2018-12-07 中国石油天然气股份有限公司 一种注气井吸气剖面的吸气比例的确定方法
CN108952693B (zh) * 2018-04-19 2022-02-01 中国石油天然气股份有限公司 一种注气井吸气剖面的吸气比例的确定方法

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