RU2634135C2 - In situ completed upgrading by injecting hot fluid medium - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: recovery method and in-situ performing the hydrocarbon upgrading in the pair of wells, consisting of the injection well and the recovery well within the oil-bearing reservoir, containing the heavy hydrocarbons, includes the following operations: injection of the hot pumped fluid selected amount, including the heavy hydrocarbons fraction, into the injection well to facilitate the recovery of hydrocarbons and in-situ upgrading; the hydrocarbons extraction from the recovery well.

EFFECT: increase of the hydrocarbons extraction with simultaneous upgrading, the impact on the environment reduction, energy costs decrease.

67 cl, 10 dwg

Description

Technical field

[0001] The present invention relates to systems, devices and methods for combined in situ production and performance (in the oil reservoir) of increasing the grade of heavy oil and tar oils from oil sand. These systems, devices, and methods enable enhanced recovery of heavy oil through a producing well by introducing hot fluid, including a vacuum or atmospheric residual fraction or deasphalting agent, into the producing well under conditions conducive to increasing the grade of hydrocarbons. These methods may further include introducing hydrogen and a catalyst along with injecting hot fluid into the production well to further facilitate hydrocarbon grade reactions. In addition, the present invention relates to improved methods of oil production within conventional oil reservoirs.

BACKGROUND OF THE INVENTION

[0002] In situ recovery methods for heavy oil or bituminous oil are often used in oil reservoirs where the thickness of the overburden is too high for the economical use of open pit mining. Being very viscous, heavy oil and tar oil do not flow as easily as light oil. Therefore, most bituminous oil production processes include the operation of decreasing the viscosity of the bituminous oil in such a way that the bituminous oil becomes more mobile and can flow from the oil formation into the producing well. A decrease in the viscosity of tar oil can be realized by increasing the temperature of the tar oil and / or by diluting the tar with a solvent.

Gravity drainage with steam injection

[0003] Gravity drainage with injection of water vapor (SAGD) is a known method of extracting bituminous oil from an underground oil reservoir. In a conventional gravity drainage process with water vapor injection, two horizontal wells (lower well and upper well) are drilled substantially parallel to each other and at different depths above each other. The lower well is an extraction well, usually located just above the base of the oil reservoir. The upper well is an injection well located about 5-10 meters above the producing well. Water vapor is injected into the upper well to form a vapor chamber within the geological formation, which eventually grows predominantly in the vertical direction to the top of the oil reservoir and down to the recovery well. Water vapor raises the temperature of the surrounding bituminous oil in the oil reservoir, decreasing the viscosity of the bituminous oil and allowing the bituminous oil and condensed water vapor to flow under the influence of gravity into a downstream extraction well. Bituminous oil and condensed water vapor either flow or are pumped from the extraction well to the surface for separation and further processing. On the surface, the separated bituminous oil is often mixed with a viscosity reducer such that the bituminous oil and the viscosity reducer can be easily transported to the refinery through a pipeline. At a refinery, a viscosity reducer is removed and bituminous oil is subjected to various processes to separate fractions and increase the grade of bituminous oil to produce useful products. Preferably, the tar oil is subjected to a vacuum distillation process to recover from the tar oil a residue, heavy and light components, intended for use in various grading processes.

[0004] Gravity drainage with injection of water vapor is usually a very effective way to extract heavy oil or tar oil from the formation to the surface. However, as is known, high capital and operating costs are associated with gravity drainage with the injection of water vapor, in particular, related to the construction and operation of a steam generating unit and extraction system at the drilling site. In addition, since gravity drainage with water vapor injection requires a large amount of water, the water source must be available at the drilling site or water must be transported to the drilling site. During gravity drainage with injection of water vapor, a large amount of fuel is also necessary to increase the temperature of water with the formation of water vapor. Moreover, the production of high-quality water vapor from the extracted water requires substantial surface treatment to purify the extracted water before converting the extracted water back to water vapor. This treatment usually requires that the extracted water, which is mixed with the extracted bituminous oil, must first be separated from the extracted bituminous oil and then subjected to further purification to remove any residual contaminants from the water. After the completion of these cleaning operations, the produced water must then be reheated to produce high-quality water vapor, followed by reintroduction back into the oil reservoir. In addition, the cleaning and reheating operations require a significant input of additional energy both to stimulate the cleaning processes and to reheat the produced water with the formation of water vapor. Although a certain amount of energy from these processes can be recovered through heat exchangers, the inefficiency of these processes necessitates the introduction of significant additional energy into the system.

[0005] Thus, although gravity drainage processes with water vapor injection are effective, there are significant environmental costs associated with the large-scale use of gravity drainage with water vapor injection and, in particular, with the presence of a carbon footprint in gravity drainage with water injection steam, which is significantly greater than with other forms of hydrocarbon production. As a result, there is a need for heavy oil production methods that improve the efficiency of heavy oil production from heavy oil reservoirs and, in particular, reduce environmental impact.

Vertical injection / recovery wells

[0006] Other recovery methods include the use of one or more vertical wells as a means of supplying heat to the oil reservoir to promote hydrocarbon mobility. For example, one vertical well can be used to stimulate cyclic steam injection (CSS), which includes successive periods of steam injection, steam impregnation and production. Similarly, two or more vertical wells close to each other can be used where, after the start-up period, when heat is introduced into the oil reservoir, one or more wells are used to supply heat to the oil reservoir, and one or more wells are used as production / extraction wells.

Steam extraction process

[0007] Another known in situ process for recovering bituminous oil or heavy oil is a vapor extraction process (VAPEX) in which a gaseous solvent (eg, propane, ethane, butane, etc.) is introduced into the upper injection well, where its condensation and mixing with tar oil to reduce the viscosity of tar oil. Then, bituminous oil and dissolved solvent flow under the influence of gravity into the lower production chamber, from where they go to the surface.

[0008] The steam extraction process is generally considered less harmful to the environment and, in some circumstances, more commercially viable than gravity drainage with water vapor injection, since the steam extraction process does not require the generation of large amounts of water and water vapor, as is the case with gravity drainage with the injection of water vapor. However, a gaseous solvent usually needs to be transported to the production site and a long start-up interval takes place during the steam extraction process, since more time is required for the formation of a vapor chamber with gaseous solvents compared to water vapor.

[0009] In addition, since the steam extraction process is a non-thermal process carried out at normal temperatures in the oil reservoir, it is not effective in promoting grading reactions.

[0010] Thus, there are also significant disadvantages that prevent the widespread use of the steam extraction process.

Catalytic Grading

[0011] Certain methods may include the use of hydrocracking catalysts to facilitate a recovery / grade process designed to grade and recover heavy oil and tar oil. However, the hydrocracking catalyst particles do not exhibit good dispersion in the presence of water, since the catalyst minerals tend to migrate preferentially to the aqueous phase and, when found, become less accessible for reactions with hydrocarbons. In addition, water has a limited ability to transport dispersed particles through sand formations due to the low viscosity of the water. Therefore, although water vapor and water do not constitute poisons for the catalyst, dispersing the catalyst particles in a gravity drainage chamber with water vapor injection determined by condensate and water vapor is believed to be associated with significant technical problems.

[0012] In addition, it is generally believed that at temperatures below 150 ° C, the viscosity of bituminous oil or a vacuum residue is too high to effectively combine catalyst particles and gases, such as hydrogen. In other words, in very viscous bituminous oil, the reaction time is slow due to restrictions on mass transfer in addition to kinetic restrictions due to the relatively low energy level.

Increased Oil Recovery

[0013] In addition to heavy oil formations, other types of oil formations, including conventional peak formations and carbonate formations, continue to explore relatively new or enhanced methods for recovering oil. For conventional oil reservoirs with decreasing production volume, there continues to be a need to use cost-effective methods to assist in recovering and / or reducing the rate of decline in production in such oil reservoirs. In addition, hydrocarbon production methods from various carbonate formations continue to be of interest as oil companies seek to exploit these types of oil reservoirs. Also of interest are new ways to increase oil recovery.

Prior art

[0014] In the prior art, there are many examples of different extraction methods. For example, recovery methods using a combination of water vapor injection and solvent have been proposed. US Patent Application Publication No. 2005/0211434 describes a recovery process by gravity drainage with water vapor injection, including an expensive initial production step, during which water vapor and a heavy hydrocarbon solvent are injected into the oil reservoir, and a cheaper subsequent production step, during which the solvent of light hydrocarbons is injected into the oil reservoir to help increase the mobility of bituminous oil.

[0015] US Patent No. 4,444,261 describes a method for improving the efficiency of displacement in a process of oil displacement by steam during oil recovery by means of a vertical production well located at a distance from the vertical injection well. In this method, water vapor is injected into the formation through an injection well until water vapor injection or the formation of a zone of oil displacement by water vapor in the upper part of the formation takes place. The high molecular weight hydrocarbon is then injected at high temperature (500-1000 ° F) into the oil vapor displacement zone as a deflecting fluid, and allowed to cool to form a stationary plug in the oil vapor displacement zone. After the cork is formed, the injection of water vapor is resumed and the cork rejects water vapor, forcing it to pass below the cork and below the oil displacement zone by water vapor, thereby ensuring mobility of the lower parts of the oil. As another example, US Patent No. 6,662,872 describes a combined extraction process with water vapor and other steam in a production system such as gravity drainage with water vapor injection.

[0016] Since a grading operation is usually performed on bituminous oil or heavy oil after it has been extracted, several methods have proposed the concept of grading in situ, whereby the viscosity of the heavy oil and its density in degrees of the American Petroleum Institute gradually decrease as the oil is produced. For example, US Pat. No. 6,412,557 describes an in situ process for upgrading bituminous oil in a subterranean oil formation in which a catalyst for improving the grade is immobilized in a downhole and an in situ combustion process is used to supply heat to facilitate grade improvement in the sock process to the heel of the well. "

[0017] As other examples, US Patent No. 7363973 describes a method for stimulating heavy oil production by gravity drainage with water vapor injection using solvent vapors, which may use in situ grade upgrading, and US Patent Application Publication No. 2008/0017372 describes an in situ process for the extraction of heavy oil and tar oil in a recovery system such as gravity drainage with water vapor injection using C3 + solvents (in particular, C3-C10). Grading is described as inherently due to the presence of solvents in contact with bituminous oil.

[0018] Another example is shown in Publication No. 2006/0175053 for a US patent, which describes a process for improving the recovery of crude oil. This process uses an insulated pipe to transfer hot fluids to the formation to facilitate recovery. Such hot fluids may include paraffins and asphaltenes.

[0019] In accordance with this, although various technologies continue to develop that improve the general methodologies for gravity drainage with steam injection and steam extraction, the need for an improved in situ extraction process that does not need to send large quantities of water or gaseous solvents to the place of production, and there is no need for the presence of a large amount of water vapor and water in the oil reservoir. In addition, in general, improved forms of in-situ grading methods are needed that are more economical, efficient and able to recover a higher proportion of oil.

[0020] Moreover, there is a need for improved enhanced recovery methods and oil recovery methods that can be used in conventional oil formations and carbonate formations.

Disclosure of invention

[0021] According to the present invention, systems and methods for in situ conducted hydrocarbon grading within a hydrocarbon geological formation are provided.

[0022] As a first feature of the present invention, there is provided a method for recovering and conducting in situ upgrading of hydrocarbons in a pair of wells, consisting of an injection well and an extraction well, within an oil reservoir containing heavy hydrocarbons, the method comprising the steps of: a) entering a selected amount hot injection fluid, including a heavy hydrocarbon fraction, into an injection well to facilitate hydrocarbon recovery and in situ grade improvement; and b) recovering hydrocarbons from the extraction well.

[0023] In another embodiment of the present invention, the heavy hydrocarbon fraction comprises any material from shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof.

[0024] In further embodiments of the present invention, hydrocarbons recovered from the extraction well are subjected to a separation process in which the heavy and light fractions are separated, the heavy fraction containing a residual fraction.

[0025] In another embodiment of the present invention, the residual fraction from the separation process is mixed with the injected fluid before being introduced into the injection well.

[0026] In another embodiment of the present invention, the method further comprises the step of mixing make-up heavy hydrocarbons with the injected fluid prior to introducing the injected fluid into the injection well, the temperature and pressure of the injected fluid being controlled so as to facilitate downgrade reactions.

[0027] In another embodiment of the present invention, the injected fluid comprises a viscosity reducer.

[0028] In further embodiments of the present invention, the temperature and pressure of the pumped fluid are controlled to facilitate thermal cracking grade reactions.

[0029] In other embodiments of the present invention, the temperature of the injected fluid is controlled so as to provide a temperature of 320 ± 20 ° C in the downhole sump and / or a residence time of 24-2400 hours for the injected fluids in the downhole.

[0030] In another embodiment of the present invention, the temperature and pressure of the injected fluid is controlled so that more than 30% of the residual heavy hydrocarbon in the recovered bituminous oil is converted to lighter fractions.

[0031] In another embodiment, the temperature and pressure of the injected fluid are controlled so that the viscosity of the recovered hydrocarbons is less than 500 centipoises at a temperature of 25 ° C.

[0032] In another embodiment, the viscosity of the recovered hydrocarbons is less than 250 centipoises at a temperature of 25 ° C.

[0033] In another embodiment, prior to step a), water vapor is injected into a pair of horizontal wells to initiate communication between the injection well and the production well and form an underground reaction chamber.

[0034] In another embodiment, prior to step a), the steam is gradually replaced with a heavy hydrocarbon fluid containing any material from heavy oil, shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof.

[0035] In yet another embodiment of the present invention, the method includes the step of mixing the catalyst into the injection fluid prior to introducing the injection fluid into the injection well.

[0036] In another embodiment of the present invention, the method further includes the step of mixing hydrogen into the injection fluid prior to introducing the injection fluid into the injection well.

[0037] In other embodiments of the present invention, the temperature and pressure of the injected fluid are controlled to facilitate any reaction from hydroprocessing, hydrocracking, or steam cracking reactions, or a combination thereof.

[0038] In another embodiment of the present invention, hydrogen is mixed with a pumped fluid to provide excess hydrogen for hydroprocessing and hydrocracking reactions.

[0039] In yet another embodiment of the present invention, hydrogen is injected along the length of the injection well.

[0040] In another embodiment, about 1/3 of the hydrogen is mixed with the surface fluid to be injected and about 2/3 is injected into the oil reservoir along the horizontal length of the recovery well.

[0041] In yet another embodiment of the present invention, hydrogen is injected from the production well through at least one casing operatively connected to the production well.

[0042] In various embodiments of the present invention, the catalyst is any catalyst of nanocatalysts or ultra-dispersed catalysts, or a combination of such catalysts, the nanocatalyst can be particles with sizes less than 1 micron and / or less than 120 nm.

[0043] In another embodiment of the present invention, a plurality of adjacent interconnected pairs of wells are in the form of a single well cluster, wherein one pair of interconnected pairs of wells is a pair of wells designed to increase grade, and fluids from heavy hydrocarbons extracted from each well, mixed with injected fluid for a pair of wells designed to increase grade.

[0044] In a further embodiment of the present invention, the heavy hydrocarbon fluids comprise any material of heavy oil, shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof.

[0045] In another embodiment of the present invention, the injection well and the extraction well comprise vertically overlapping horizontal sections, and the injection well is a lower well from the injection well and the extraction well.

[0046] In yet another embodiment of the present invention, the injection well and the extraction well comprise vertically overlapping horizontal sections, and the injection well is an upper well from the injection well and the recovery well.

[0047] As another feature of the present invention, there is provided a method for increasing the rating of heavy hydrocarbons during hydrocarbon recovery from a heavy hydrocarbon formation, the process comprising the steps of: a) drilling an injection well and an extraction well into a heavy hydrocarbon formation; b) creating a chamber for increasing the mobility of hydrocarbons within the heavy hydrocarbon formation by introducing hot fluid into the injection well to facilitate mobility of the hydrocarbons towards the producing well; c) recovering heavy hydrocarbons from the extraction well to the surface; d) performing a separation process on hydrocarbons recovered in step c) to form lighter hydrocarbon fractions and residual heavy hydrocarbon fractions; f) introducing part or all of the residual heavy hydrocarbon fractions at certain temperatures and pressures to facilitate hydrocarbon grading reactions in the hydrocarbon mobility chamber; and f) recovering co-mixed high-grade hydrocarbons from the producer well.

[0048] In another embodiment of the present invention, a portion of the separation of the heavy residual fraction is used as fuel to generate heat to heat injected fluids to perform grade-up reactions.

[0049] In yet another embodiment of the present invention, the method further comprises the step of using a portion of the light hydrocarbons to carry out additional separation processes for commercialization.

[0050] In another embodiment of the present invention, step e) includes introducing a catalyst into the injection well to promote catalytic grade improvement within the injection well and hydrocarbon mobility chamber, and / or step e) further includes introducing hydrogen into the injection well to facilitate reactions grade improvement in the chamber for increasing the mobility of hydrocarbons.

[0051] As another feature of the present invention, there is provided a system for recovering and in situ upgrading heavy hydrocarbons within a formation containing heavy hydrocarbons, the system comprising: an injection well; extraction well; moreover, the injection well and the extraction well are operatively connected to the hydrocarbon distillation column for separating the fluids extracted from the extraction well into heavy and light fractions; and a hot fluid mixing and injection system operatively coupled to the distillation column to extract heavy fractions from the distillation column and to mix the heavy fraction with additional injected fluids for injection into the injection well.

[0052] In another embodiment of the present invention, the system further comprises a gas and liquid separation system operatively coupled to the extraction well for separating gas and liquids extracted from the extraction well and for supplying the separated liquids to the distillation column, and / or a catalyst injection system, functionally coupled to the hot fluid mixing and pumping system for introducing the catalyst into the hot fluid mixing and pumping system and / or the pumping system in a plug functionally coupled to the hot fluid mixing and pumping system for introducing hydrogen into the hot fluid mixing and pumping system, and / or a viscosity reducing agent pumping system operably connected to the hot fluid mixing and pumping system for introducing the viscosity reducing agent into the mixing system and hot fluid injection, and / or at least one additional injection and recovery well operably connected to the distillation column to introduce additional additional heavy hydrocarbons from at least one additional recovery well to a distillation column.

[0053] As yet another aspect of the present invention, there is provided a method for increasing the rating of heavy hydrocarbons during hydrocarbon recovery from a heavy hydrocarbon formation, the process comprising the steps of: a) drilling an injection well and an extraction well into a heavy hydrocarbon formation; b) creating a chamber for increasing the mobility of hydrocarbons within the heavy hydrocarbon formation by introducing hot fluid into the injection well to facilitate mobility of the hydrocarbons towards the recovery well; c) recovering heavy hydrocarbons from the extraction well to the surface; d) performing a solvent-free deasphalting separation process with respect to hydrocarbons recovered in step c) to form a deasphalting agent and asphalt pitch; f) introducing the deasphalting agent obtained in step d) into the injection well at certain temperatures and pressures to facilitate hydrocarbon grading reactions in the hydrocarbon mobilization chamber; and f) recovering co-mixed high-grade hydrocarbons from the producer well.

[0054] In another embodiment of the present invention, a portion of the asphalt pitch is used as fuel for generating heat to heat pumped fluids to perform grade upgrading reactions.

[0055] In yet another embodiment of the present invention, the method further includes the step of using a portion of the light hydrocarbons to perform additional separation processes for commercialization.

[0056] As another feature of the present invention, there is provided a system for extracting and performing in situ grade upgrading of heavy hydrocarbons within a formation containing heavy hydrocarbons, the system comprising: an injection well; extraction well; moreover, the injection well and the extraction well are functionally connected to the deasphalting system under the influence of a solvent to extract a fraction of the deasphalting agent for mixing with additional injection fluids for injection into the injection well.

[0057] As another feature of the present invention, a method for increasing the rating of heavy hydrocarbons during the recovery of hydrocarbons from a formation with heavy hydrocarbons, comprising the following operations: a) drilling a well into a formation with heavy hydrocarbons; b) introducing heat into the well to create a chamber for increasing the mobility of hydrocarbons within the heavy hydrocarbon formation to facilitate mobility of hydrocarbons within the well; c) recovering heavy hydrocarbons from the extraction well to the surface and initially storing the heavy hydrocarbons in a heated reservoir; d) introducing heavy hydrocarbons from the heated reservoir into the well at a certain temperature and pressure to facilitate hydrocarbon grading reactions in the hydrocarbon mobility chamber; f) compaction of the well and maintaining pressure in the well for a time sufficient to facilitate hydrocarbon grade reactions; and f) after sufficient time has passed, depressurizing the well and recovering the high grade hydrocarbons from the well.

[0058] In other embodiments, the present invention includes the steps of introducing a catalyst into the well during step d); and / or introducing hydrogen into the well during operation d).

[0059] As yet another aspect of the present invention, there is provided a method for extracting and improving in situ grade of hydrocarbons in a pair of wells, consisting of an injection well and an extraction well, inside an oil-bearing formation with heavy hydrocarbons, the method comprising the following operations: (a) introducing a selected amount hot pumped fluid, including a heavy hydrocarbon fraction, including any material from shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting or a combination thereof to facilitate hydrocarbon recovery and in situ grade upgrading; (b) recovering hydrocarbons from an extraction well; (c) performing a separation process for hydrocarbons recovered from an extraction well during which heavy and light fractions are separated to form any material from shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof; (d) re-introducing any material from shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting fluid fraction into the well as a hot injected fluid at certain temperature and pressure values, to help increase grade and repeat steps (a) to ( d)

Brief Description of the Drawings

[0060] The invention is described with reference to the accompanying drawings, in which:

In FIG. 1 is a schematic diagram of an in situ process for increasing grade by using a residue in accordance with a first embodiment of the present invention;

In FIG. 2 is a schematic diagram of an in situ catalytic grade upgrade process using a residue in accordance with a second embodiment of the present invention;

In FIG. 2A is a schematic top view of an in situ process for increasing grade by using a residue using multiple pairs of wells;

In FIG. 2B is a schematic cross-sectional view of various in situ grade improvement processes using a residue using one or more vertical wells as injection / recovery wells;

In FIG. 3 is a schematic diagram of an extraction chamber in accordance with one embodiment of the present invention;

In FIG. 4 is a schematic diagram of a typical temperature gradient in a pair of wells designed to increase grade and in an extraction chamber in accordance with one embodiment of the present invention;

In FIG. 5 is a schematic diagram of a surface equipment for a pair of wells designed to increase grade in accordance with another embodiment of the present invention;

In FIG. 6 is a schematic diagram of ground equipment for a pair of wells designed to increase grade, in accordance with another embodiment of the present invention using deasphalting;

In FIG. 7 is a schematic diagram of the upgrade zones according to the present invention; and,

In FIG. 8 is a schematic diagram of another embodiment of the present invention using a method of cyclic injection of steam into a well.

DETAILED DESCRIPTION OF THE INVENTION

Overview

[0061] According to the present invention and with reference to the drawings below, systems, devices and methods for conducting in situ upgrading of hydrocarbons in hydrocarbon production operations are described. In particular, these methods provide an opportunity to increase the grade of heavy oil and bituminous oil inside the extraction well and the formation chamber when using hot injection fluids. In a first embodiment of the present invention, the hot injected fluid contains a residual fraction. In a second embodiment of the present invention, the injected fluid contains deasphalting agent. In both cases, hydrogen gas and catalyst can be injected together with the hot residue or deasphalting agent to facilitate in situ grading and recovery of heavy oil and bituminous oil.

[0062] According to the present invention and in the context of this description, the following general definitions are given for the terms used here. Superheavy hydrocarbons are usually defined as hydrocarbon fractions whose distillation takes place at temperatures above 500 ° C (at atmospheric pressure) or having a density in degrees of the American Petroleum Institute of less than 10 (more than 1000 kg / m ³ ). Heavy hydrocarbons are distilled between temperatures of 350 ° C and 500 ° C or have a density in degrees of the American Petroleum Institute between 10 and 22.3 (920-1000 kg / m ³ ). Medium hydrocarbons are distilled between temperatures of 200 ° C and 350 ° C and are usually defined as having a density in degrees of the American Petroleum Institute between 22.3 and 31.1 (870-920 kg / m ³ ). Light hydrocarbons are defined as having a density in degrees of the American Petroleum Institute above 31.1 (less than 870 kg / m ³ ) and distilled at temperatures below 200 ° C.

[0063] The residual fraction is a fraction distilled at temperatures above 540 ° C. The deasphalting fraction is a coarse fraction obtained in a deasphalting device that separates bitumen from bituminous oil.

In Situ Grade Raising Process Using Residue

[0064] In the first embodiment shown in FIG. 1, the present invention provides a system for performing in situ grade upgrading using a residue in an in situ grade chamber 12, comprising a pair of 13 wells designed to improve grade. In accordance with this embodiment of the present invention, one of the pair of wells designed to increase the grade, is an injection well 16, and the other well is an extraction well 18. These pairs of wells can be made horizontal, vertical or inclined and may contain combinations of such wells as shown in FIG. 2b. For the purposes of this description, a pair of horizontal wells has been described, although it is clear that other combinations of pairs of wells may be used. First, hot fluid or water vapor is injected into the injection well, which causes the chamber 12 to grow at and around injection site 16a. The extraction well 18 is designed to collect the recovered fluids from which the recovered fluids flow or are pumped to the surface. On the surface, the extracted fluids enter the atmospheric and / or vacuum distillation column 20, where the heavy oil is fractionated by weight, leaving heavy vacuum or atmospheric residue fraction 20a at the bottom of the distillation column (“residual fraction”), and at higher column levels lighter oil fractions 20b, recovered gases 20c and recovered viscosity reducer 20d (if used).

[0065] According to the present invention, the hot fluids injected into the injection well comprise a residual fraction 20a from the distillation column, additional tar oil 20e from another source and / or a viscosity reducer 20f and / or other hot fluids, including water vapor. It is important to note that the injection of residual fraction contributes to in situ thermal cracking / grading reactions within the formation. In addition, the injection of the residual fraction affects the overall efficiency of the grading reactions, since the heavy oil fractions are most reactive with respect to grading reactions when exposed to heat.

[0066] It is important to note that the “re-injection” of the hot residual fraction into the injection well is also an effective source of introducing heat into the chamber 12. Moreover, although it is preferable that the residue be recovered from the distillation column 20 located on the well, that the residual fraction 20a may be formed elsewhere on the surface, including injection into the well site from other wells or treatment centers that may adjoin or be close to the well, as shown in f ig. 2A and 2B.

[0067] Accordingly, in a preferred embodiment, the hot residue is generated in the distillation column 20 and re-injected into the injection well at a temperature in the range of 350 ± 20 ° C, which ideally provides an average sump temperature of the oil reservoir of 320 ± 20 ° C. It is important to note that since the temperature of the injected hot residue is usually higher than the temperature of water vapor, the hot residue will lead to a more rapid expansion of the chamber during startup operations and / or to a faster maintenance of the size in a stable state.

[0068] In addition, a sump temperature in the range of 320 ± 20 ° C contributes to the in situ thermal grade improvement of bituminous oil in the injection well and in the oil reservoir by increasing the temperature of the bituminous oil to a temperature at which grade-up reactions can occur (eg, thermal cracking), as well as reducing the viscosity of bituminous oil to improve the overall mobility of bituminous oil in the oil reservoir.

[0069] Under steady state conditions, the residence time for the injected residue can be about 24-2400 hours (normal upper limit is about 500 hours) depending on the size of the chamber and the permeability of porous media, as those skilled in the art will understand. The recovered bituminous oil will be partially, but significantly, upgraded to produce a combination of heavy oil products having a typical viscosity of less than 300 centipoises at a temperature of 60 ° F and a density of 14-15 in degrees from the American Petroleum Institute compared to a typical density of 8-10 in degrees from the American Petroleum Institute for extracted bituminous oil under similar conditions. Under normal conditions, a residence time of 24-48 hours will result in a higher grade for more than 30% of the extracted bituminous oil.

[0070] Another advantage of injecting a hot residue according to the present invention is that the recoverable oil has a higher temperature and contains much less water than when injecting water vapor. Accordingly, injection of the hot residue can substantially eliminate the need for injection of water into the oil reservoir such that the only water in the oil reservoir is buried water. As a result, the costs of water treatment and / or water removal will be eliminated or significantly reduced.

[0071] However, during startup, water vapor may be injected into the injection well to start chamber growth during the startup phases, in which case the water vapor is gradually replaced with a hot residue over time. Thus, during start-up, water treatment and extraction operations may be necessary. However, it should also be noted that the use of water vapor in this operation can be replaced by using heated oil from the storage tank and allowing hot oil to be recirculated inside the wells until the wells reach connectivity. The choice of either water vapor and / or heated oil to ensure connectivity can be made based on the specific characteristics of the combination of wells and the economics of these wells.

[0072] Alternatively, hot oil (tar oil, deasphalting oil, vacuum gas oil, etc.) can be pumped during the startup phases and used to grow the chamber from the very beginning if the economy of a particular project supports this approach.

[0073] It should be borne in mind that the use of hot residue for chamber growth usually leads to greater horizontal expansion of the chamber instead of vertical expansion resulting from the usually higher horizontal permeability of heavy oil formations compared to the vertical permeability. It is significant that a chamber more laterally expanded can lead to more complete extraction than a conventional vertical chamber used in gravity drainage processes with water vapor injection, since a larger horizontal expansion will lead to a larger total volume of the extraction chamber.

In situ catalytic grade upgrade process using residue

[0074] In accordance with another aspect of the present invention and with reference to FIG. 2-8, systems and methods for the in situ process of catalytic grade improvement using a residue in a hydrocarbon recovery operation are described. In particular, these methods make it possible to carry out a catalytic upgrade of heavy oil and bituminous oil within an extraction well and a formation chamber containing a pair of wells.

[0075] As shown in FIG. 2, in this embodiment of the present invention, the catalyst 30 and hydrogen 28 are injected into the injection well to further promote upgrade reactions, including hydroprocessing and hydrocracking reactions in addition to thermal cracking reactions. As in FIG. 1, the system comprises a pair 13 of grade-improvement wells, consisting of an injection well and an extraction well 18, the injection well serving as an entry point for the injected fluid 38, and the extracting well collects the extracted fluids 44 that flow or are pumped to the surface. As explained in more detail below, any well of a pair of wells may be used as an injection well. However, for purposes of illustration, in situations with one or more pairs of horizontal wells, the upper well is shown in FIG. 2-5 as injection well 16, and the lower well is shown as recovery well 18.

[0076] In one embodiment of the present invention, the system is intended for use with multiple pairs of horizontal wells serviced by a single well pad 50, in which one of the adjacent pairs (50a, b, c, d) of wells is used to perform grade-up reactions (FIG. 2A). For example, bituminous oil recovered in adjacent pairs (50b, c, d) of wells may be upgraded in a pair of 50a wells, in which all bituminous oil recovered from an adjacent pair of wells (approximately 500-1000 barrels per day per pair of wells ), can be subjected to an increase in the grade in one pair of wells to improve the grade for reasons of efficiency.

[0077] As shown in FIG. 2, in this embodiment of the present invention, the injected fluids 38 preferably comprise hydrogen 28, a residual fraction 20a extracted from the column, another tar oil 20e, a viscosity reducer 20f (optional) and a catalyst 30. As noted, the other tar oil 20e may include tar extracted from surrounding pairs of wells and / or from other sources.

[0078] Initially, during startup, typically 10 to 15% of a viscosity reducer (condensate) 20f (FIG. 1) may be added to the hot tar oil to aid in the transport and mobility of the tar oil when directed to the well during startup, as explained in more detail below. After a pair of wells reach a steady state grade during an in situ grade upgrade operation, the viscosity reducer can be removed for recycling and bituminous oil is no longer injected into the oil reservoir, and the residual fraction from the distillation column is used instead.

[0079] During stationary operation, the incoming bituminous oil 20e and the viscosity reducer 20f are mixed with the hot residue 20a together with the recovered and make-up hydrogen 28 and the make-up catalyst 30 together with the recovered hydrogen and gases 32 before being injected into a pair of wells to increase the grade. The recovered fluids 44 are suitably separated into gas / fluid to recover hydrogen for re-injection.

[0080] The catalyst is preferably a nanocatalyst or an ultrafine catalyst, as described in US Pat. No. 7,897,537, incorporated herein by reference. The catalyst may be performed at the drilling site by transporting the catalyst precursors to the drilling site, or the pre-produced catalyst may be transported to the drilling site. Hydrogen can be initially transported to the drilling site and generated using small devices (hydrogen generators), since the hydrogen pressure and its consumption are much lower than is usually necessary during the normal surface upgrade operation, and, as noted above, after the start of production, unreacted hydrogen dissolved in produced oil arriving at the surface can be recovered through a distillation and gas / fluid separation process 32.

[0081] In the case where the average residence time of the injected fluids 38 in the grading zone is more than 150 hours, more than 45% of the heavy oil fractions can be converted to higher grade oils with a density of 14-16 degrees ANI. After a sufficient residence time, the extracted fluids 44 from the extraction well 18 are pumped into the separation column 20. The lighter fractions 20b are removed and the residual catalyst, i.e., the residual fraction, is separated from the vacuum / atmospheric residue to extract and recycle the catalyst particles, resulting in higher grade 32 oil with a density exceeding 20 degrees ANI. Recovered fluids 44 contain excess hydrogen, higher grade oil with a density of 14-16 degrees ANI, unconverted bituminous oil and atmospheric / vacuum residue, other produced gases (CH ₄ , H ₂ S and H ₂ O from buried water) and a catalyst not remaining in the grade improvement zone.

[0082] On the surface, excess hydrogen and other gases 32 are separated and recycled. The remaining recovered liquids 44 are sent to a distillation column 20 to recover the vacuum / atmospheric residue and catalyst. It is usually preferred that the upgrading zone 40 retains the proportion of catalyst particles, since this minimizes the amount of catalyst extraction and reduces the amount of catalyst injection that can be carried out, thereby reducing the cost of the catalyst. In the distillation column, viscosity reducer 24 may be recovered and recycled to an adjacent pair of wells or, if desired, to another pair of wells. Crude oil 34 obtained from the remainder is sent to the market. The recovered catalyst and residual fraction 20a are returned to a pair of wells designed to improve the grade.

[0083] The catalyst will typically be stored in the oil reservoir until it begins to rise in the recovered fluids and reaches a plateau value at a certain concentration, moreover, this value is less than the injection value. A stable concentration of catalyst will come to the surface. Since the catalyst is heavier (in terms of density) of the heaviest upstream oil molecules, it will usually remain in residue during distillation. Particle entrainment and / or removal is unlikely, as distillation columns are typically designed to prevent entrainment and removal. However, filters will typically be placed downstream of the base of the distillation column to retain any large particle in the residue (or sand or agglomerated particles containing catalyst that may go up to the surface). In addition, it has also been noted that the heaviest distillation products from a vacuum distillation column will usually not transfer particles of carbonaceous material of lower density (microcoke particles) that can ultimately be captured by distillation, which indicates that these columns are effective for separating particles. Moreover, the concentration of the catalyst upon injection will be low (less than 1000 ppm in residue (<0.1% by weight)), and it will be substantially lower in produced fluids; for example, a typical BWS rate (bottom water and sediment) is 0.5% by weight.

[0084] Thus, the catalyst particles are effectively separated at the lowest cost from the high-grade oil produced, remaining in the fraction that is recycled to the oil reservoir. As a result, the lighter oil produced from the distillation column is usually ready for transport without catalyst particles. In addition, the re-injected residual fraction will ultimately be completely converted to lighter fractions, and inconsequential grades will ultimately be left in the oil reservoir if necessary.

[0085] In addition, the tar oil contains naphthenic molecules that can be subjected to repeated dehydrogenation and hydrogenation cycles in the upgrading zone 40. Therefore, naphthenic molecules can contribute to the redistribution of hydrogen to large residue molecules, thereby improving the conversion efficiency of the residue according to the following chemical equation:

Grading and Extraction Chamber

[0086] The in situ catalytic grade upgrade process using the residue also results in the recovery of bituminous oil from the formation containing a pair of grade grade wells. As shown in FIG. 2, 3 and 4, the upgrade / recovery chamber 12 typically comprises two zones, namely, the upgrade zone 40 and the recovery zone 42. The grade improvement zone is typically a zone 50 between the wells through which pumped fluids flow. It is usually maintained at a temperature of about 350 ° C by the heat of a grading reaction.

[0087] An extraction zone is located above the grading zone. As shown in FIG. 3, the heat from the upgrading zone 40 is transferred through thermal conductivity and heats the surrounding bituminous oil, reducing its viscosity. Very hot hydrocarbon vapors produced by a grading reaction and replenished with a viscosity reducer and distillate, recirculated, if necessary, from the surface, rise to the extraction zone, transferring additional heat through convection. The dissolution of hot hydrocarbon vapors occurs in the formation tar oil and a further decrease in the viscosity of the formation tar oil. Gravity drainage, supported by the displacement of rising gases 52, including hydrogen, hydrocarbon vapors, water vapor and other gases, provides the mobility of the bituminous oil 54 and extracts it through an extraction well. This process leads to an increase in the grade of bituminous oil produced by adjacent pairs of wells, as well as to the extraction and increase of the grade of bituminous oil from a pair of wells designed to increase the grade. Preferably, in a pair of wells designed to increase the grade, there is no injection of water vapor, but the injection of hydrogen is acceptable. Therefore, bituminous oil is recovered through steam extraction, gravity drainage and gas displacement, along with a much smaller contribution to the recovery (relative to gravity drainage with water vapor injection) of water vapor from buried water.

Launch

[0088] In order to start the in situ grade upgrade process using a residue or the in situ catalytic grade upgrade process using a residue, in one embodiment of the present invention, two horizontal wells are drilled spaced apart by about 5 m in the vertical direction, and the length of the horizontal section is subject to optimization. Increased length usually increases the daily rate of increase in the grade of bituminous oil and the remainder. At a temperature of 350 ° C, up to 1000 barrels (~ 160 m ³ ) per day can be injected per 100 m of well length containing 50% bituminous oil and 50% residue. For example, 5,000 barrels per day of bituminous oil can flow through a pair of 1000 m long grade grade wells, providing ample opportunity to increase the grade of bituminous oil produced by 3 to 4 adjacent pairs of wells using gravity drainage with water vapor injection, each from which it produces 500-1000 barrels per day, as well as the residual fraction subjected to recycling.

[0089] As noted, wells are optionally / preferably preheated by recirculating water vapor or hot oil inside the wells. As you know, during pre-heating with water vapor, it usually takes about 4 months to establish a connection between the hot fluids between the wells, and the region 50 between the wells should reach a temperature of about 160 ° C. As an alternative to the aforementioned water vapor injection, low viscosity oil (vacuum gas oil) with a temperature of about 300 ° C can be recycled inside the wells to establish a connection between the hot fluids between the wells, with the region 50 between the wells reaching a temperature of about 160 ° C. As noted above, this procedure can eliminate the need for water vapor and water treatment, however, it requires a certain tank capacity to run vacuum gas oil. Thus, a volume exceeding the volume of drilled wells to be heated would be necessary depending on the use (or not) of vacuum gas oil during the next phase.

[0090] After the preheating phase, low viscosity oil at 350 ° C (ie, atmospheric residue or vacuum gas oil used during the preheating) is pumped and circulated using the upper injection well and the lower recovery well. The injected oil is saturated with hydrogen and nanocatalysts to protect it from coking. When a temperature of approximately 250 ° C is reached between the wells, bituminous oil is injected instead of low viscosity oil. The purpose of this phase is to heat the zone between the wells to the required grade-improvement temperature of 350 ° C.

[0091] At the same time, there is a gradual increase in the volume of hydrogen in the injected fluid until the excess hydrogen conditions necessary to effectively increase the grade are achieved, which increases the fraction of the volume occupied by the gas in the pair of wells and in the inter-well porous space.

[0092] The injection pressure is typically limited to 2,000 to 3,500 kPa (~ 300-500 psi) to remain below the fracturing pressure of the formation and to guarantee gas retention for most oil formations in oil sands. Obviously, for deeper oil reservoirs, the injection pressure used should be higher and this will further increase the efficiency of the in situ grading process of the present invention.

Steady Operations

[0093] After the temperature between the wells reaches 350 ° C, injection of bituminous oil and the vacuum residue with hydrogen and hydrocracking catalysts begins.

[0094] Surface hydrocracking catalysts generally operate at high residue conversion values, for example 90%, and consume 200-250 standard m ³ hydrogen per m ³ residue, and the inlet hydrogen concentrations are about 3 times the consumption (~ 650 standard m ³ hydrogen per m ³ residue). The described conditions for increasing the grade relate to a 50% conversion of the residue, which requires a hydrogen consumption of only 40-60 standard m ³ hydrogen per m ³ residue. The estimate of the volume of injected hydrogen is also 3 times higher than the consumption, or 150 standard m ^{3 of} hydrogen per m ^{3 of} bituminous oil. The injection of hydrogen in the process according to the present invention can be performed simultaneously with the injection of the residue containing the catalyst, or the hydrogen to be pumped is divided into two fractions, usually 1/3 of the total amount being pumped together with the residue and 2/3 are introduced in the form of bubbles from the casing, which is attached at the top of the production well to enrich the grade improvement zone with bubbling hydrogen.

[0095] Ideally, the partial pressure of hydrogen is maintained above 2500 kPa (360 psi) for effective reaction kinetics. The conditions described above with an excess of hydrogen guarantee a sufficient partial pressure of hydrogen in the injection well, the grade improvement zone and in the produced fluids.

[0096] Under injection conditions (350 ° C and 3,450 kPa), gas volumes are reduced by about 15 times compared to standard conditions. In addition, 5-10% of the injected volume of hydrogen is expected to be dissolved in oil. Thus, on the assumption that the mixture will flow as a dispersion of gas in oil (that is, in the bubbling mode) or in the mixed bubble-plug flow mode, the gas delay fraction will be approximately the same as the flowing oil fraction. Therefore, the partial volume occupied by the gas in the injection well will be 50% or lower.

[0097] In the upgrade zone, approximately one third of the injected hydrogen is consumed. Other gases are produced through various mechanisms (in particular: methane, oil vapors, water vapor from buried water and hydrogen sulfide). Therefore, it can be expected that the partial gas volume will increase as it passes through the grade improvement zone. The partial gas volume in the grade improvement zone located between the wells will be above 25%.

[0098] It can also be expected that the gas / liquid ratio in the production well will be similar to the conditions in the injection well.

[0099] As expected, the shape of the grade and extraction chamber 12 will be more elliptical than conical, as in gravity drainage processes with water vapor injection. Given that the vertical permeability is usually only 0.2 to 0.5 of the horizontal permeability within the formation, the lateral size of the upgrade zone placed between the wells will usually be greater than the vertical distance between the wells. Factors that control the growth rate and the shape of the chamber can be estimated through numerical and physical modeling.

[0100] The residence time in the drilled wells will typically be about 1 hour for each, but will depend on the flow rate of the injected bituminous oil. However, the residence time in the area between the wells will depend on factors such as:

a. porosity (usually about 30%)

b. partial volume of liquids (usually about 75%)

c. lateral movement of injected fluids (usually about 5-10 m in each direction); and

d. flow rate of injected bituminous oil and atmospheric residue.

[0101] The residence time in the interwell reaction zone will be approximately 50-500 hours (typically), meeting or exceeding the kinetics of the reaction for the hydrocracking catalyst used, as in US Pat. No. 7,897,537.

[0102] The discharge flow rate is a constant volumetric flow rate, but production is typically organized to maintain a constant pressure in the reaction chamber. Typically, the volume of liquid production will be higher than the discharge flow rate due to an increase in oil volume with the addition of hydrogen and a gradually increasing recovery from the formation subjected to grade improvement.

[0103] Some grade improvement will occur in the wells, but most will occur in the grade zone. Grading by adding hydrogen is an exothermic process and can usually increase the temperature of the oil by about 40 ° C in the reaction zone. This exothermic process more than compensates for the local heat loss and maintains the grading zone at temperatures suitable for grading. The heat of hydrocracking reactions ranges from 42 to 50 kilojoules per mole of hydrogen and is also exothermic.

[0104] A grade improvement zone maintained at 350 ° C will over time heat the surrounding formation of tar oil through thermal conductivity, reducing the viscosity of the surrounding tar oil and making the tar oil mobile. Part of the surrounding bituminous oil, in particular from the areas above the chamber, will flow under the influence of gravity through the grade improvement zone into the producing well and will be replaced by rising hydrogen and produced gas. Consequently, the size of the extraction zone will increase due to a gradually increasing extraction.

[0105] It is important that during catalytic grading processes, as a result of increased chamber temperatures and grading reactions, a large proportion of the heaviest molecules that would otherwise remain in the sand of the formation during recovery by known methods such as gravity drainage with the injection of water vapor will be made movable for extraction.

[0106] By increasing the grade, light oil fractions will be generated that will rise above the grade area with hydrogen and produced gas. These very hot hydrocarbon vapors will act as solvents and further reduce the viscosity of bituminous oil in addition to causing thermal effects. The amount of existing hydrocarbon vapor can be increased by recycling the distillation products from the column.

[0107] The gradually increasing extraction and growth of the chamber will be controlled by steam extraction, gravity drainage and gas displacement. Heat losses and the presence of hydrocarbon vapors are two factors that control increasing recovery. A typical estimate of the recovery of bituminous oil from a formation with an increase in the grade is 50 barrels per day per 100 m of the length of the well, as is well known to specialists in this field of technology.

[0108] Heat losses will be significantly less than conventional heat losses during gravity drainage with water vapor injection, since

a. the latent heat of hydrocarbons is less than the latent heat of water vapor; in addition, most of the heat exchange will be accomplished through heat conduction, which is less efficient than convection;

b. a steam chamber located above the grade improvement zone will contain light gases (for example, H ₂ , CH ₄ ) and condensed water forming an insulating layer between the grade improvement zone and the overburden; and,

c. the size of the steam chamber and the surface area for heat transfer will usually be smaller than in a comparable gravity drainage system with water vapor injection.

[0109] In addition, the gas in the produced fluid provides a gas lift, and there is no injection of water and the formation of a conventional chamber for gravity drainage with the injection of water vapor. At the end of the upgrade operations or during the interruption of the upgrade operations, bituminous oil in a pair of wells designed to increase the grade can be recovered by gravity drainage with water vapor injection (if feasible) due to the presence of a pair of horizontal wells and the possibility of producing water vapor at a level wellbore (if feasible).

[0110] Alternatively, a pair of wells designed to improve the grade can be located in the adjacent thin zone of bituminous oil, which cannot be used or otherwise extracted.

Mass Balance Considerations

[0111] When considering the mass balance of a system based on the usual operating conditions described above, the vacuum residue is pumped and circulated through the interwell reaction zone at an oil production rate of up to 10 times the flow rate of water vapor in a conventional gravity drainage process with water vapor injection. However, the absence of condensed water vapor means that the flow rate of liquids is only 2.5 times higher than during gravity drainage with injection of water vapor.

[0112] Hydrogen injected in an amount three times the consumption requirements guarantees a partial pressure of hydrogen (2600 kPa) sufficient for effective reaction kinetics. The use of hydrogen gradually reduces the concentration and volume of hydrogen to one third. Conditions with an excess of hydrogen and the production of other gases compensate for the consumption of hydrogen and maintain a partial gas volume of approximately 90%.

[0113] The injected catalyst flows with the injected oil. Some catalyst particles will be deposited on the sand in the grading zone, while others will come out with the produced fluids.

[0114] Bituminous oil becomes mobile due to steam extraction, heat loss, and gas displacement flowing down due to gravity. Hydrogen, light hydrocarbon vapors and other gases (CH ₄ , H ₂ S and water vapor from buried water) rise into the extraction zone.

[0115] The produced liquids contain high-grade bituminous oil and an atmospheric residue inflated with a hydrogen additive and extracted bituminous oil. Consequently, liquid production is greater than injected liquids.

Energy Balance Considerations

[0116] When surface treatment is performed, thermal energy is needed to heat the tar oil to 320 ° C, control the distillation column, and deliver the residue at 320 ° C (FIG. 5). Heat exchangers are deployed to maximize energy efficiency by cooling hot fluids (i.e., high-grade oil sent to the market) with cold fluids (i.e., bituminous oil coming in). Additional requirements related to surface energy required include:

energy to control the compressor of the recirculated gas and to re-establish the pressure and flow in the recirculated gas;

energy for hydrogen production and gas purification;

energy to compress make-up hydrogen to a discharge pressure, if required; and heat loss in the injection well.

[0117] The supply of thermal energy includes the circulation of bituminous oil and atmospheric residue with a temperature of 300 ° C through the grade improvement zone. Some of the thermal energy contained in the circulating fluid is lost to the formation due to thermal conductivity and convection (evaporation of light oil fractions). These heat losses heat the surrounding bituminous oil and control the gradually increasing recovery of bituminous oil. In addition, grading reactions in the reaction zone produce heat energy that compensates for heat loss and maintains the reaction zone at the required temperature of 280-320 ° C.

[0118] In situ thermal energy requirements include servicing a grade improvement zone at a temperature of 280-320 ° C; evaporation of light oil fractions; heating porous media and bituminous oil to increase mobility; heating the extracted bituminous oil to a grade increase temperature; and the evaporation of buried water.

Temperature Distribution Considerations

[0119] FIG. Figure 4 outlines temperature distribution considerations for the in situ catalytic grade improvement process using a residue and the in situ grade development process using a residue. Surrounding formation 56 has a temperature drop of 10 ° C at the site closest to the surface to a temperature that increases the mobility of bituminous oil (~ 100 ° C) near the recovery zone. Recovery zone 42 has a temperature difference from a temperature of increasing the mobility of tar oil to 300 ° C. Upgrade zone 40 is typically maintained at a temperature between 280 ° C and 320 ° C. Exothermic reactions generate thermal energy and the temperature melts due to the heat of reaction. The temperature is reduced by the flow of colder bituminous oil from the recovery zone.

[0120] The inlet temperature of the injection well 16 is equal to the temperature of the injected fluids, that is, about 300 ° C. The temperature at the outlet of the extraction well 18 is equal to the temperature of the produced fluids, i.e. approximately 280 ° C.

Surface process and ground equipment

[0121] In FIG. 5 is a schematic diagram of an arrangement of potential ground equipment according to the present invention. As shown, two pairs of wells are included in the circuit of FIG. 2A. That is, the first pair of boreholes 13a is a conventional pair of gravity-pumped drainage boreholes that has been subjected to conventional injection of steam through a steam generator 60. The second pair of boreholes 13b has undergone an in situ catalytic rate upgrading process. Fluids recovered from the first pair of wells may be combined with fluids from the second pair of wells.

[0122] Most of the gas stream from the production well, mainly excess hydrogen, is recycled 32 along with the purge gas stream 60 sent to the gas purification device 62. A purge gas stream 60 is used to control the concentration of produced gas components (i.e., C ₁ -C ₄ , H ₂ S, CO-CO ₂ gases) in the recirculated gas. It may be necessary to remove water before recompression.

[0123] Liquids are sent to distillation column 20. High grade oil 34 with a density above 20 degrees ANI is sent to market 34a. A viscosity reducer 34b, 64 may be added to high grade oil.

[0124] As an alternative or addition, the distillation / viscosity reducer stream 64 may be separately recovered and recycled to a pair of grade wells to increase the amount of hydrocarbon vapor available for steam extraction and to control the amount of bituminous oil recovered. In addition, distillation products / viscosity reducer can be recovered for sale 64a.

[0125] The distillation column 20 produces a residue 26 that has not been converted in the grade chamber along with the recovered catalyst that has not been stored in the grade chamber. This residue 26 is recycled to a pair of wells designed to increase the grade by conditioning residue 26a.

[0126] Bituminous oil 22 from adjacent pairs of gravity drainage wells 13a with water vapor injection is mixed with residue 26, with hydrogen 28 and catalyst 30. The combined stream is added to the recirculated gas 32 and injected into the pair 13b of wells designed to increase the grade.

[0127] A heat exchanger can be used to preheat incoming bituminous oil 22 and a viscosity reducer 24, wherein the high-grade oil 34 is sent to the market.

[0128] The recycle gas compressor 68 is needed to restore the appropriate pressure and flow rates in the recycle gas. A make-up hydrogen compressor 28a may also be needed.

Process controls and rate indicator for injection of bituminous oil

[0129] The rate of injection of bituminous oil determines the 25 volume of oil of high grade, as well as the intensity of the flow of thermal energy into the geological formation. Thermal energy comes from heat losses incurred by the remainder of β-bituminous oil injected at a temperature of 350 ° C, as well as from heat generated in situ by hydrocracking reactions. This 30 variable also determines the volume of light oil fractions available for recovery. Therefore, this variable controls:

high-grade oil production;

the rate of gradually increasing extraction; and

growth rate of the reaction chamber.

Location of injection and production

[0130] The startup configuration is injection from the upper well and production from the lower well. However, this configuration can be reversed and cyclically repeated to control:

temperature distribution in the reaction chamber;

catalyst distribution;

the shape of the reaction chamber; and

the pace of ever-increasing extraction.

Upper injection well and lower production well

[0131] After startup, the typical configuration for a pair of wells is an upper injection well and a lower recovery well, since this configuration minimizes the size of the productive zone located below the producing well. As it should be understood, the productive zone located below the producing well cannot be extracted, since the movement of oil and catalyst from the injection well into the producing well occurs in the direction of gravity. Oil vapors produced in the interwell region are provided with the opportunity to rise in the extraction zone.

Lower injection well and upper production well

[0132] In an alternative embodiment of the present invention, the configuration of the lower injection well and the upper production well maximizes the temperature in the interwell reaction zone. The bituminous oil of the formation, the mobility of which is provided from zones above the chamber, is located at temperatures below 350 ° C, since the increase in mobility begins at low temperatures of about 150 ° C. Excessively increasing recovery of bituminous oil can suppress the temperature in the reaction zone. If the upper well is an extraction well, the extracted bituminous oil is produced immediately when it reaches the upper producing well and does not cool the interwell area. The temperature of the interwell region may increase above the injection temperature due to the heat generated by the grade improvement reactions, and the hotter interwell zone maximizes the grade increase. In addition, there is a rise of hydrogen through the interwell reaction zone.

Hydrogen injection from the tubing string in the upper producing well

[0133] Conditions with an excess of hydrogen are determined to allow the presence of a sufficient amount of hydrogen during the process. However, hydrogen is a very light gas and its amount, which can flow down from the upper injection well into the lower extraction well, may be less than necessary. In this case, the secondary injection of hydrogen can be carried out by means of a tubing inserted into the lower extraction well, which results in replenishment of hydrogen in the wellbore surrounding the lower extraction well and inside the producing well.

Electric heating

[0134] In a further embodiment of the present invention, electrical or other heating methods may be used to increase the amount of heat supplied, if this should lead to improved performance.

Close and restart strategies

[0135] An unplanned interruption of operations likely results in the accumulation of fluids at the bottom of a vertical well, where they can cool and solidify in the event of a prolonged interruption. Therefore, effective temperature measurement and control in both the injection well and the production well are desirable. The prompt injection of vacuum gas oil during an unplanned interruption of work probably eliminates the adverse effects, and also provides the possibility of displacement of water vapor, as noted above.

Simulation results

[0136] The results of a simulation of the in situ grading process using a residue and the in situ catalytic grading process using a residue show that at 350 ° C more than 50% of the vacuum residue can be graded with a residence time longer than 16 hours. The resulting high grade crude oil has a specific gravity of 16 degrees API or more, with a viscosity lower than 200 centipoises (at 25 ° C). Table 1 shows mass balance data for a typical catalytic grading process with a residence time of less than 24 hours and conversion of more than 50% of the vacuum residue, with a hydrogen consumption of 9 cubic meters under normal conditions / per barrel and a catalyst consumption of 0.10 tons per day, excluding catalyst recovery.

[0137] Table 2 shows model heat balance data for a catalytic grade upgrade process.

[0138] Table 3 shows, for comparison, heat balance data for a conventional gravity drainage process with water vapor injection.

[0139] Table 4 shows the regenerated heat in a simulated catalytic grading process.

Catalytic Grading Process with Deasphalting (DAISCU)

[0140] The catalytic upgrade process using deasphalting agent is a variant of the in situ catalytic upgrade process using a residue. In this embodiment of the present invention, discussed with reference to FIG. 6, bituminous oil 22, extracted from a pair of 13 wells, is subjected to deasphalting processes to create a deasphalting product used as a modernized heat carrier for injection and bitumen pitch, with part of the pitch used as fuel (fuel part) and the other part (non-fuel part) pitch mixed with deasphalting for injection. Typically, the relative proportion of the fuel part compared to the non-fuel part depends on the degree of grade increase achieved, and this proportion will change as the oil reservoir reaches the target temperature in the grade range.

[0141] In the process of catalytic grade upgrading with deasphalting, initially during the development of the grade chamber, the mobility of bituminous oil is increased and steam is produced to create an initial grade chamber in a manner similar to initiating an in situ grade improvement process using the remainder. At this stage, water is separated and the produced bituminous oil is placed in a large tank 82 until enough oil is accumulated to start the solvent-free deasphalting operation (SDO), during which deasphalting and pitch are obtained, as well as a sufficient increase deasphalting temperature to the grade reaction temperature (~ 320 ° C).

[0142] More specifically, the recovered fluids 81 (containing bituminous oil and high grade oil) are injected into the ultrafine grinding system 80 to create very fine particles of recovered bituminous oil. The recovered fluids are then pumped into a storage tank 82 having a volume sufficient to collect and store the recovered fluids for subsequent processing. Gas 85 from the storage tank may be subjected to a gas purification operation 62. After collecting a suitable volume of recovered fluids, high grade oil products 34 (from a distillation column, not shown) are collected and marketed.

[0143] The heavier fractions 84a containing substantially heavier fractions will be pumped into the deasphalting unit 86 by means of a solvent which, when added, forms the deasphalting fraction 87 and the heavier bituminous oil / pitch 88a (fuel fraction) and 88b (non-fuel fraction) ) will depend on the relative increase in the grade improvement chamber and the grade improvement reactions. The fuel portion 88a is fed to the furnace 90, in which the fuel portion is burned along with the recovered gases 62a coming from the gas purification device 62 to heat the asphalting agent 87 for injection into the well 16.

[0144] The non-fuel portion 88b may be returned to the fine grinding system 80 and the storage system 84.

[0145] The heated deasphalting agent can be combined by injection with hydrogen 28 and catalyst 30, as described above.

[0146] The upgrade zone is described with reference to FIG. 7 regarding the processes of catalytic grade upgrading under deasphalting. The production chamber is similar to the cameras in FIG. 1, 2, 3 and 4. As shown, the upper and lower wells provide the opportunity for injection of hydrogen, and deasphalting is injected into the upper injection well. An upgrade zone can usually be described as consisting of three areas. In the first region (a), hydrogen, catalysts and deasphalting agent are injected at the reaction temperature. Typically, the volume of the injection well determines a residence time of the order of 0.5 to 3 hours, so that a relatively small degree (approximately 10%) of grade improvement will take place.

[0147] The second region (b) extends directly below the injection well towards the producing well. In a mature well, a significant amount of bituminous oil has already been produced, and thus this zone can be described as having a higher degree of injectivity compared to other zones, since the flow between the injection well and the producing well is provided. As such, the injected deasphalting agent will predominantly flow downward and its grade will be increased largely due to the reaction conditions in this zone.

[0148] Bituminous oil in the region above the injection well flows down as a result of dissolution and convective heat transfer by volatile hydrocarbon vapors and gases produced during the grade increase by injected hydrogen, but also by superheated water vapor generated from buried water. All of these gases tend to concentrate and form a backflow at the top of the chamber, which supports the ability of heat and solvent to help increase the mobility of bituminous oil down into the extraction well. Thus, bituminous oil from an area above the injection well also improves the grade along with zone (b).

[0149] Bituminous oil heated by heat conduction from a deasphalting agent adjacent to the side walls of the interwell region also has increased mobility and a significantly increased grade, since it is mixed with deasphalted material transporting catalysts near the producing well and is in contact with a stream of hydrogen coming from a hydrogen casing (b) attached externally to the upper hemisphere of the producing well.

[0150] A third region, zone (c), is located around the producing well and provides additional volume and therefore additional residence time to complete the reaction, the grade increase before the oil is produced or reaches a temperature or below the reaction temperature.

In situ nano-catalytic grade upgrade (n-CISU)

[0151] In another embodiment, with reference to FIG. 8, an in situ nano-catalytic upgrade method will be described. The in situ process of nano-catalytic upgrading can be applied to a simple well configuration using extraction with cyclic injection of water vapor into the well. In this embodiment of the present invention, a vertical well 13c may be used into which hot fluids (that is, including produced oil) are injected along with other additives, including hydrogen 28 and catalyst 30. After injection, the well is sealed and pressurized for a time extracts to allow for in situ grade improvement. After a sufficient exposure time has passed, the pressure is released and fluids, including high-grade oil 80, are pumped out of the well. The cycle can be repeated while the well is productive.

[0152] In more detail, the launch and production phases will be described in the following representative description. First, water vapor 60 is used to preheat the oil formation zone around the vertical well 13 in accordance with conventional cyclic water vapor injection procedures. During this phase, preliminary quantities of oil / bituminous oil 80 will be produced from the well and stored in a heated reservoir 62 (at a temperature of ~ 80-140 ° C) for subsequent use. When sufficient injectivity is achieved (if it was not originally there), the stored oil 62a can be used for two purposes, firstly to disperse nanocatalysts 30 (with an approximate concentration of 600 ppm) in this oil and, secondly, to transfer heat to oil reservoir at a typical discharge temperature of 270-290 ° C. The catalyst is injected once in the first injection cycle and in small quantities. Any additional amount of catalyst can be injected during subsequent cycles in order to maintain the concentration of catalyst at the required level. Hydrogen 28 is injected along with the oil going down (the ratio of H ₂ / bituminous oil is 90 cm ³ / bituminous oil in m ³ ).

[0153] The injected material is introduced at a pressure slightly higher than the pressure in the oil reservoir. After injection of a sufficient amount of hot oil (usually about 90% of the oil originally produced and stored for 10-15 days from the initial production), a closed well period (holding time) of 10 to 15 days is maintained. Over the course of the holding time, grades and pumped oil and recoverable oil increase.

[0154] During the holding time, pressure and gas composition in the well are monitored to ensure that favorable conditions are maintained to improve grade. Additional hydrogen may be added during the holding time, which may be necessary to maintain pressure in the oil reservoir and promote favorable reaction kinetics.

[0155] Hydrogen is typically consumed in an amount of 15 cm ³ per barrel of oil pumped and produced. As a maximum, 45 cm ^{3 of} hydrogen per barrel of heated oil / injected bituminous oil can be consumed under the assumption that the oil productivity is doubled relative to the usual operation of cyclic injection of water vapor into the well (highest expectation). Thus, approximately 25-50% of the injected hydrogen will be consumed.

[0156] After a holding period, the recovered fluids will be distilled in a distillation column 20 to separate the high-grade oil supplied to the market 34 and recover the gas components 85. As in previous embodiments of the present invention, high viscosity components, including the remainder, can be re-injected into the well with repeated cycles.

[0157] The same general methodology can be applied to each of the well configurations shown in FIG. 2B.

Another comparison with gravity drainage with steam injection

[0158] The methods and devices according to the present invention can provide significant advantages compared with gravity drainage with injection of water vapor in terms of total energy balance. As you know, in the gravity drainage operation with the injection of water vapor, heat is injected into the formation in the form of water vapor and is usually extracted in the form of warm water. In addition, water is heated on the surface using a substantial amount of fossil fuel energy to generate the required volumes, pressures and temperature of water vapor for injection into a downhole. In particular, the amount of energy required to heat water with its transformation into water vapor requires the energy of the heat of evaporation of water to create steam. Although the energy of the heat of evaporation of water is introduced into the oil-bearing formation by condensing steam into water, the water returns to the surface in the form of a contaminated water / mineral / hydrocarbon stream, which requires substantial purification before re-heating with conversion to water vapor. In particular, mineral contaminants should be removed to prevent scale formation in steam generating equipment, and hydrocarbons should be separated from water.

[0159] It should be understood that the energy cost of removing mineral / hydrocarbon pollutants from the water leads to a concomitant energy requirement, which is significantly reduced with the use of this technology because the volume of water recovered from the formation will be significantly smaller, since it is usually the only the water existing in the system will be buried water. After the separation of hydrocarbons, no additional water treatment may be necessary.

[0160] Furthermore, the environmental impact of the present technology is significantly lower since significantly smaller volumes of water are needed to complete the process. The need for settling ponds can be eliminated.

[0161] Moreover, since the in situ grading reactions are exothermic reactions, the requirement for heat input to the surface is reduced.

Carbonate formations and increased oil production in conventional oil reservoirs

[0162] This technology can also be applied to formations other than heavy oil formations, including conventional oil formations with reduced production, deeper formations than oil sands that are relatively shallow, and carbonate formations. In particular, compared to gravitational drainage with injection of water vapor, which usually can only be applied to relatively small oil reservoirs, the present methods can be applied to other formations as a method of increased oil production.

[0163] The amount of additional oil available for recovery by the hot fluid injection method may be 10-30% more than the volume extracted by exposure to water vapor, which provides significantly higher recovery rates than when using the steam injection methods. In addition, oil produced using these technologies can reach a transportable level (p <280 centipoise at 25 ° C) for sands with embedded bituminous oil with minimal or no reduction in the permeability of the oil reservoir and with at least a similar oil recovery .

[0164] As a result, these methods can eliminate the need to use grade upgrading devices to enable transport and / or dilution.

[0165] Although the present invention has been described and illustrated with respect to preferred embodiments and preferred uses, it should not be limited thereto, since, as understood by those skilled in the art, modifications and changes can be made that fall within the full intended scope inventions.

Claims (143)

1. The method of extraction and conducted in situ improvement of hydrocarbon grades in a pair of wells, consisting of an injection well and an extraction well, within the oil reservoir containing heavy hydrocarbons, the method comprising the steps of: a) introducing a selected amount of hot injection fluid, including a heavy hydrocarbon fraction, into an injection well to facilitate hydrocarbon recovery and in situ grade upgrading; and b) recovering hydrocarbons from an extraction well. 2. The method according to p. 1, in which the injection well and the extraction well are a pair of horizontal wells. 3. The method according to p. 1 or 2, in which the heavy hydrocarbon fraction contains any material from shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof. 4. The method according to p. 1 or 2, in which hydrocarbons recovered from the extraction well are subjected to a separation process in which the heavy and light fractions are separated, the heavy fraction containing a residual fraction. 5. The method according to p. 4, in which the residual fraction from the separation process is mixed with the injected fluid before being introduced into the injection well. 6. The method of claim 5, further comprising the step of mixing make-up heavy hydrocarbons with the injected fluid prior to introducing the injected fluid into the injection well, wherein the temperature and pressure of the injected fluid is controlled so as to facilitate downgrade reactions in the downhole. 7. The method according to any one of paragraphs. 1, 2, 5, 6, in which injection fluid contains a viscosity reducer. 8. The method according to any one of paragraphs. 1, 2, 5, 6, in which the temperature and pressure of the pumped fluid is controlled to promote thermal cracking grade reactions. 9. The method according to p. 8, in which the temperature of the injected fluid is controlled so as to provide a temperature of the borehole sump 320 ± 20 ° C. 10. The method according to any one of paragraphs. 1, 2, 5, 6, 9, in which the residence time of injected fluids in a downhole is 24-2400 hours. 11. The method according to any one of paragraphs. 1, 2, 5, 6, 9, in which the temperature and pressure of the injected fluids are controlled so that more than 30% of the residual heavy hydrocarbon in the extracted bituminous oil is converted to lighter fractions within the oil reservoir. 12. The method according to any one of paragraphs. 1, 2, 5, 6, 9, in which the temperature and pressure of the injected fluids are controlled so that the viscosity of the recovered hydrocarbons is less than 500 centipoises at a temperature of 25 ° C. 13. The method according to p. 12, in which the viscosity of the recovered hydrocarbons is less than 250 centipoises at a temperature of 25 ° C. 14. The method according to any one of paragraphs. 2, 5, 6, 9, 13, in which before operation a), steam is injected into a pair of horizontal wells to initiate communication between the injection well and the producing well and the formation of an underground reaction chamber. 15. The method according to p. 14, in which prior to operation a), water vapor is gradually replaced by a heavy hydrocarbon fluid selected in the form of any material from heavy oil, shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof. 16. The method according to any one of paragraphs. 1, 2, 5, 6, 9, 13, 15, further including the operation mixing the catalyst into the injection fluid prior to introducing the injection fluid into the injection well. 17. The method according to p. 16, further comprising the step of mixing hydrogen into the injected fluid prior to introducing the injected fluid into the injection well. 18. The method according to p. 17, in which The temperatures and pressures of the injection fluid are controlled to facilitate any reaction from hydroprocessing, hydrocracking or steam cracking reactions, or a combination thereof. 19. The method according to p. 18, in which hydrogen is mixed with injected fluid to provide excess hydrogen for hydroprocessing and hydrocracking reactions. 20. The method according to any one of paragraphs. 17-19 in which hydrogen is injected along the length of the injection well. 21. The method according to p. 20, in which about 1/3 of the hydrogen is mixed with the injected fluid on the surface and about 2/3 is injected into the oil reservoir along the horizontal length of the extraction well. 22. The method according to p. 21, in which hydrogen is pumped from the extraction well through at least one casing pipe operatively connected to the producing well. 23. The method according to any one of paragraphs. 17, 18 in which the catalyst is any catalyst of nanocatalysts or ultradispersed catalysts, or a combination of such catalysts. 24. The method according to p. 23, in which the nanocatalyst has particles with a diameter of less than 1 micron. 25. The method according to p. 24, in which ultrafine catalyst has particles with diameters less than 120 nm. 26. The method according to any one of paragraphs. 1, 2, 5, 6, 9, 13, 15, 17-19, 21, 22, 24, 25, in which many neighboring interconnected pairs of wells are made in the form of a single well cluster, moreover one pair of interconnected pairs of wells is a pair of wells designed to improve the grade, and heavy hydrocarbon fluids recovered from each well are mixed with injected fluid for a pair of wells designed to increase grade. 27. The method according to p. 26, in which heavy hydrocarbon fluids contain any material from heavy oil, shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof. 28. The method according to any one of paragraphs. 2, 5, 6, 9, 13, 15, 17-19, 21, 22, 24, 25, 27, in which the injection well and the extraction well contain vertically overlapping horizontal sections, and the injection well is a lower well from the injection well and the extraction well. 29. The method according to any one of paragraphs. 2, 5, 6, 9, 13, 15, 17-19, 21, 22, 24, 25, 27, in which the injection well and the extraction well contain vertically overlapping horizontal sections, and the injection well is an upper well from the injection well and the extraction well. 30. A method of increasing the rating of heavy hydrocarbons during the recovery of hydrocarbons from a formation with heavy hydrocarbons, comprising the following operations: a) drilling an injection well and an extraction well into a formation with heavy hydrocarbons; b) creating a chamber for increasing the mobility of hydrocarbons within the heavy hydrocarbon formation by introducing hot fluid into the injection well to facilitate mobility of the hydrocarbons towards the producing well; c) recovering heavy hydrocarbons from the extraction well to the surface; d) performing a separation process on hydrocarbons recovered in step c) to form lighter hydrocarbon fractions and residual heavy hydrocarbon fractions; e) introducing part or all of the residual heavy hydrocarbon fractions at certain temperature and pressure values to facilitate hydrocarbon grading reactions in the hydrocarbon mobility chamber; and f) recovering co-mixed high-grade hydrocarbons from the producer well. 31. The method according to p. 30, in which a portion of the heavy residual fraction obtained by separation is used as fuel to generate heat, heating the injected fluids to perform grade-up reactions. 32. The method of claim 30, further comprising the step of using a portion of the light hydrocarbons to conduct additional separation processes to form additional hydrocarbon fractions. 33. The method according to any one of paragraphs. 30-32, in which step e) involves introducing a catalyst into the injection well to promote a catalytic grade improvement within the injection well and a hydrocarbon mobility chamber. 34. The method according to any one of paragraphs. 30-32, in which operation e) further includes introducing hydrogen into the injection well to facilitate upgrade reactions in the hydrocarbon mobility chamber. 35. A system for recovering and conducting in situ grade upgrading of heavy hydrocarbons within a formation containing heavy hydrocarbons, the system comprising: a) injection well; b) an extraction well; moreover, the injection well and the extraction well are operatively connected to the hydrocarbon distillation column for separating the fluids extracted from the extraction well into heavy and light fractions; c) a hot fluid mixing and injection system operably coupled to the distillation column to extract heavy fractions from the distillation column and to mix the heavy fraction with additional injected fluids for injection into the injection well. 36. The system of claim 35, further comprising a gas and liquid separation system operably coupled to the extraction well for separating gas and liquids extracted from the extracting well and for supplying the separated liquids to the distillation column. 37. The system according to any one of paragraphs. 35, 36, further comprising a catalyst injection system operably coupled to the hot fluid mixing and injection system for introducing the catalyst into the hot fluid mixing and injection system. 38. The system according to any one of paragraphs. 35, 36, further comprising a hydrogen injection system operatively coupled to the hot fluid mixing and pumping system for introducing hydrogen into the hot fluid mixing and pumping system. 39. The system according to any one of paragraphs. 35, 36, further comprising a viscosity reducer injection system operably coupled to the hot fluid mixing and injection system for introducing the viscosity reducer into the hot fluid mixing and injection system. 40. The system according to any one of paragraphs. 35, 36, further comprising at least one additional injection and recovery well operably coupled to the distillation column for introducing additional heavy hydrocarbons from said at least one additional extraction well into the distillation column. 41. A method of increasing the rating of heavy hydrocarbons during the recovery of hydrocarbons from a formation with heavy hydrocarbons, comprising the following operations: a) drilling an injection well and an extraction well into a heavy hydrocarbon formation; b) creating a chamber for increasing the mobility of hydrocarbons within the heavy hydrocarbon formation by introducing hot fluid into the injection well to facilitate mobility of the hydrocarbons towards the recovery well; c) recovering heavy hydrocarbons from the extraction well to the surface; d) performing a solvent-free deasphalting separation process with respect to hydrocarbons recovered in step c) to form a deasphalting agent and asphalt pitch; e) introducing the deasphalting agent obtained in step d) into the injection well at certain temperatures and pressures to facilitate hydrocarbon grading reactions in the hydrocarbon mobility chamber; and f) recovering co-mixed high-grade hydrocarbons from the producer well. 42. The method according to p. 41, in which part of the asphalt pitch is used as fuel to generate heat, heating the pumped fluids to perform grade-up reactions. 43. The method according to p. 42, further comprising the operation of using part of the light hydrocarbons to perform additional separation processes for commercialization. 44. A system for extracting and performing in situ upgrading of heavy hydrocarbons within a formation containing heavy hydrocarbons, the system comprising: injection well; extraction well; moreover, the injection well and the extraction well are functionally connected to the deasphalting system under the influence of a solvent to extract a fraction of the deasphalting agent for mixing with additional injection fluids for injection into the injection well. 45. A method of increasing the rating of heavy hydrocarbons during the extraction of hydrocarbons from a formation with heavy hydrocarbons, comprising the following operations: a) drilling a well into a hydrocarbon formation; b) introducing heat into the well to create a chamber for increasing the mobility of hydrocarbons within the heavy hydrocarbon formation to facilitate mobility of hydrocarbons within the well; c) recovering heavy hydrocarbons from the extraction well to the surface and initially storing the heavy hydrocarbons in a heated reservoir; d) introducing heavy hydrocarbons from the heated reservoir into the well at a certain temperature and pressure to facilitate hydrocarbon grading reactions in the hydrocarbon mobility chamber; e) compaction of the well and maintaining the pressure in the well for a time sufficient to facilitate hydrocarbon grade reactions; and f) after sufficient time has elapsed, depressurization of the well and recovery of high grade hydrocarbons from the well. 46. The method of claim 45, further comprising the step of introducing the catalyst into the well during operation d). 47. The method according to any one of paragraphs. 45 or 46, further comprising the step of introducing hydrogen into the well during step d). 48. The method according to any one of paragraphs. 45, 46, in which operations b) -f) are sequentially repeated. 49. A method for extracting and improving in situ grade of hydrocarbons in a pair of wells, consisting of an injection well and an extraction well, inside an oil reservoir with heavy hydrocarbons, the method comprising the following operations: (a) introducing a selected amount of hot injection fluid, including a heavy hydrocarbon fraction, including any material from shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof, into an injection well to facilitate hydrocarbon recovery and in situ enhancement grades; (b) recovering hydrocarbons from an extraction well; (c) performing a separation process for hydrocarbons recovered from an extraction well during which heavy and light fractions are separated to form any material from shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting agent, or a combination thereof; (d) re-introducing any material from shale oil, tar oil, atmospheric residue, vacuum residue or deasphalting fluid fraction into the well as a hot pumped fluid at certain temperature and pressure values to help increase grade and repeat steps (a) to (d ) 50. The method of claim 49, wherein the heavy hydrocarbon oil reservoir comprises tar oil, and the tar oil is recovered from the extraction well. 51. The method according to p. 49 or 50, in which the injection well and the extraction well are a pair of horizontal wells. 52. The method according to any one of paragraphs. 49, 50, in which in operation d), the fraction is a fraction of the vacuum residue. 53. The method according to any one of paragraphs. 49, 50, in which hot pumped fluid contains a viscosity reducer. 54. The method according to any one of paragraphs. 49, 50, in which the temperature and pressure of the hot pumped fluid is controlled in such a way as to promote thermal cracking grade reactions and a borehole sump temperature of 320 ± 20 ° C. 55. The method according to p. 50, in which the temperature and pressure of the hot injected fluids are controlled so that more than 30% of the residual heavy hydrocarbon in the extracted bituminous oil is converted to lighter fractions within the oil reservoir. 56. The method according to any one of paragraphs. 49, 50, 55, in which the temperature and pressure of the hot injected fluids are controlled so that the viscosity of the recovered hydrocarbons is less than 500 centipoises at a temperature of 25 ° C. 57. The method according to any one of paragraphs. 49, 50, 55, in which the temperature and pressure of the hot pumped fluids are controlled so that the recovered hydrocarbons have a viscosity of less than 250 centipoises at a temperature of 25 ° C. 58. The method according to any one of paragraphs. 49, 50, 55, further comprising the step of mixing the catalyst into the injected hot fluid prior to introducing the injected fluid into the injection well. 59. The method according to any one of paragraphs. 49, 50, 55, further comprising the step of mixing hydrogen into the injected hot fluid prior to introducing the injected hot fluid into the injection well. 60. The method according to p. 59, in which the temperatures and pressures of the injected hot fluid are controlled to facilitate any reaction from hydroprocessing, hydrocracking or steam cracking reactions, or a combination thereof. 61. The method according to p. 59, in which hydrogen is mixed with injected hot fluid to provide excess hydrogen for hydrotreatment and hydrocracking reactions. 62. The method according to any one of paragraphs. 49, 50, 55, 60, 61, in which hydrogen is injected along the length of the injection well. 63. The method according to p. 62, in which about 1/3 of the hydrogen is mixed with the injected hot fluid on the surface and about 2/3 is injected into the oil reservoir along the horizontal length of the extraction well. 64. The method according to p. 59, in which hydrogen is pumped from the extraction well through at least one casing pipe operatively connected to the producing well. 65. The method according to any one of paragraphs. 60, 61, 63, 64, in which the catalyst is any catalyst of nanocatalysts or an ultra-dispersed catalyst, or a combination of such catalysts. 66. The method according to p. 65, in which the size of the average nanocatalyst particle is less than 1 micron. 67. The method according to p. 24, in which the diameter of the middle particle of the ultrafine catalyst is less than 120 nm.

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