Dense aqueous gravity displacement of heavy oil

Abstract

Methods are provided that facilitate the production of hydrocarbons from subterranean formations, involving the mobilization of an immobile heavy oil in situ by gravity displacement. In effect, heavy oil is mobilized by dense aqueous gravity displacement (DAGD), in a process that generally involves injecting a dense, heated aqueous injection fluid into the formation into an injection zone that is in fluid communication with immobile heavy oil. The injection well is operated so that the injection fluid mobilizes and displaces the immobile heavy oil, to produce an expanding upper zone of mobilized heavy oil amenable to production.

Claims

1. A method for mobilizing an immobile heavy oil in situ within a reservoir by gravity displacement in a subterranean formation, comprising: injecting an aqueous injection fluid into the formation through an injection well into an injection zone that is in fluid communication with the immobile heavy oil, the aqueous injection fluid having a density greater than the density of the immobile heavy oil and a temperature greater than the temperature of the immobile heavy oil, wherein the aqueous injection fluid comprises a produced formation water recovered from an aquifer that is below the injection zone, wherein the produced formation water has a temperature greater than the temperature of the immobile heavy oil in situ; and, operating the injection well so that the injection fluid mobilizes and displaces a displaced fraction of the immobile heavy oil, to provide an upwardly mobile heavy oil that rises by gravity displacement above a descending fraction of the aqueous injection fluid, such that an expanding upper zone of mobilized heavy oil is created in the formation above the injection zone.

2. The method of claim 1, further comprising producing the mobilized heavy oil from the upper zone of mobile heavy oil in a production fluid produced through a production well.

3. The method of claim 2, wherein producing the mobilized heavy oil comprises operating a flow control device so as to preferentially produce a hydrocarbon phase in the production fluid.

4. The method of claim 2, further comprising separating an aqueous fraction of the production fluid from an oil fraction of the production fluid, and further comprising recirculating and injecting at least a portion of the aqueous fraction of the production fluid through the injection well.

5. The method of claim 2, wherein: the injection well comprises a substantially horizontal injection well segment and the aqueous injection fluid is injected into the formation through the substantially horizontal injection well segment; and, the production well comprises a substantially horizontal production well segment, and the mobilized heavy oil is collected for production through the substantially horizontal production well segment.

6. The method of claim 5, wherein the substantially horizontal production well segment is vertically offset above the substantially horizontal injection well segment.

7. The method of claim 1, wherein the immobile heavy oil reservoir is a bituminous oil sand reservoir.

8. The method of claim 1, wherein the density of the aqueous injection fluid is increased over time.

9. The method of claim 1, wherein the aqueous injection fluid is heated prior to or following injection.

10. The method of claim 1, wherein the reservoir comprises a thief zone and the average fluid mobility, transmissibility or flow capacity of the thief zone is greater than the average fluid mobility, transmissibility or flow capacity of an adjoining heavy-oil-bearing reservoir zone.

11. The method of claim 1, wherein the viscosity of the upwardly mobilized heavy oil is greater than the viscosity of the descending fraction of the injection fluid, so that the mobility ratio there between is greater than 1.

12. The method of claim 1, wherein the immobile heavy oil has a mass density under native reservoir conditions of greater than about 900 kg/m.sup.3.

13. The method of claim 1, further comprising injecting an additive into the formation with or in addition to the aqueous injection fluid, wherein the additive is a steam, solvent, polymer, surfactant or densifier, and wherein, the additive increases mobility of the upwardly mobile heavy oil.

14. The method of claim 1, wherein the aqueous injection fluid has a density greater than the density of the immobile heavy oil under native reservoir conditions and a temperature greater than the temperature of the immobile heavy oil under the native reservoir conditions.

15. A method for mobilizing an immobile heavy oil in situ within a bituminous oil sand reservoir by gravity displacement in a subterranean formation, wherein the immobile heavy oil has a mass density under native reservoir conditions of greater than about 900 kg/m.sup.3, comprising: injecting an aqueous injection fluid into the formation through an injection well into an injection zone that is in fluid communication with the immobile heavy oil, the aqueous injection fluid having a density greater than the density of the immobile heavy oil and a temperature greater than the temperature of the immobile heavy oil, wherein the aqueous injection fluid comprises a produced formation water recovered from an aquifer that is below the injection zone, wherein the produced formation water has a temperature greater than the temperature of the immobile heavy oil in situ; and, operating the injection well so that the injection fluid mobilizes and displaces a displaced fraction of the immobile heavy oil, to provide an upwardly mobile heavy oil that rises by gravity displacement above a descending fraction of the aqueous injection fluid, such that an expanding upper zone of mobilized heavy oil is created in the formation above the injection zone; producing the mobilized heavy oil from the upper zone of mobile heavy oil in a production fluid produced through a production well; and, separating an aqueous fraction of the production fluid from an oil fraction of the production fluid, and recirculating and injecting at least a portion of the aqueous fraction of the production fluid through the injection well.

16. The method of claim 15, wherein the viscosity of the upwardly mobilized heavy oil is greater than the viscosity of the descending fraction of the injection fluid, so that the mobility ratio there between is greater than 1.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 is a line graph, showing fluid density vs temperature for bitumen, “standard” water (of low salinity) and “low quality” (1% salinity) water.

(2) FIG. 2 is a schematic illustration of a reservoir simulation set up, showing a top water zone, three injection wells and an underlying heavy oil reservoir.

(3) FIG. 3 is a schematic illustration of simulated reservoir conditions, showing temperature profile at time =0 years.

(4) FIG. 4 is a schematic illustration of simulated reservoir conditions, showing temperature profile at time =2 years.

(5) FIG. 5 is a schematic illustration of simulated reservoir conditions, showing temperature profile at time =4 years.

(6) FIG. 6 is a schematic illustration of simulated reservoir conditions, showing temperature profile at time =8 years.

(7) FIG. 7 is a schematic illustration of simulated reservoir conditions, showing oil saturation profile at time =0 years.

(8) FIG. 8 is a schematic illustration of simulated reservoir conditions, showing oil saturation profile at time =2 years.

(9) FIG. 9 is a schematic illustration of simulated reservoir conditions, showing oil saturation profile at time =4 years.

(10) FIG. 10 is a schematic illustration of simulated reservoir conditions, showing oil saturation profile at time =8 years.

(11) FIG. 11 is a line graph showing a change in simulated oil saturation over time, with the average oil saturation (S.sub.o) in the reservoir decreasing over time and the average S.sub.o of the transition zone increasing over time, providing an oil migration profile over time.

(12) FIG. 12 is a line graph illustrating a change in simulated oil (bitumen) migration volumes over time, showing a decrease in cumulative reservoir bitumen over time and an increase in cumulative transition zone bitumen over time, providing a profile of simulated oil volume migration between the reservoir and transition zone over time.

(13) FIG. 13 is a line graph showing the change in cumulative stream oil ratio (CSOR) over time for the simulated transition zone.

(14) FIG. 14 is a line graph showing the change in CSOR over time for the simulated reservoir.

(15) FIG. 15 is s schematic illustration of one prospective well configuration for production and injection wells in a reservoir in which heavy oil has been mobilized by dense aqueous gravity displacement (DAGD).

(16) FIG. 16 is a schematic illustration of a modeled well configuration for 13 production and 6 injection wells in a reservoir in which heavy oil is to be mobilized by dense aqueous gravity displacement (DAGD).

DETAILED DESCRIPTION OF THE INVENTION

(17) In the context of the present application, various terms are used in accordance with what is understood to be the ordinary meaning of those terms. For example, “petroleum” is a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid or solid phase. In the context of the present application, the words “petroleum” and “hydrocarbon” are used to refer to mixtures of widely varying composition. The production of petroleum from a reservoir necessarily involves the production of hydrocarbons, but is not limited to hydrocarbon production and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu, V). Similarly, processes that produce hydrocarbons from a well will generally also produce petroleum fluids that are not hydrocarbons. In accordance with this usage, a process for producing petroleum or hydrocarbons is not necessarily a process that produces exclusively petroleum or hydrocarbons, respectively. “Fluids”, such as petroleum fluids, include both liquids and gases. Natural gas is the portion of petroleum that exists either in the gaseous phase or in solution in crude oil in natural underground reservoirs, and which is gaseous at atmospheric conditions of pressure and temperature. Natural gas may include amounts of non-hydrocarbons. The abbreviation POIP stands for “producible oil in place” and in the context of the methods disclosed herein is generally defined as the exploitable or producible oil structurally located above the production well elevation.

(18) It is common practice to segregate petroleum substances of high viscosity and density into two categories, “heavy oil” and “bitumen”. For example, some sources define “heavy oil” as a petroleum that has a mass density of greater than about 900 kg/m.sup.3. Bitumen is sometimes described as that portion of petroleum that exists in the semi-solid or solid phase in natural deposits under native reservoir conditions, with a mass density greater than about 1,000 kg/m.sup.3 and a viscosity greater than 10,000 centipoise (cP; or 10 Pa.s) measured at original temperature in the deposit and atmospheric pressure, on a gas-free basis. Under reservoir conditions associated with recovery operations, for example when reservoir temperatures are elevated above native reservoir conditions, the density and viscosity of heavy oil and bitumen may fall significantly below these values. Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the two substances. In particular, the term “heavy oil” includes within its scope all “bitumen” including hydrocarbons that are present in semi-solid or solid form.

(19) A “reservoir” is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock. An “oil sand” or “oil sands” reservoir is generally comprised of strata of sand or sandstone containing petroleum. A “zone” in a reservoir is an arbitrarily defined volume of the reservoir, typically characterised by some distinctive property. Zones may exist in a reservoir within or across strata or facies, and may extend into adjoining strata or facies. In some cases, reservoirs containing zones having a preponderance of heavy oil are associated with zones containing a preponderance of natural gas. This “associated gas” is gas that is in pressure communication with the heavy oil within the reservoir, either directly or indirectly, for example through a connecting water zone. A pay zone is a reservoir volume having hydrocarbons that can be recovered economically.

(20) “Thermal recovery” or “thermal stimulation” refers to enhanced oil recovery techniques that involve delivering thermal energy to a petroleum resource, for example to a heavy oil reservoir. There are a significant number of thermal recovery techniques other than SAGD, such as cyclic steam stimulation (CSS), in-situ combustion, hot water flooding, steam flooding and electrical heating. In general, thermal energy is provided to reduce the viscosity of the petroleum to facilitate production.

(21) A “chamber” within a reservoir or formation is a region that is in fluid/pressure communication with a particular well or wells, such as an injection or production well. For example, in a SAGD process, a steam chamber is the region of the reservoir in fluid communication with a steam injection well, which is also the region that is subject to depletion, primarily by gravity drainage, into a production well.

(22) “Reservoir compartmentalization” is a term used to describe the segregation of a petroleum accumulation into a number of distinct fluid/pressure compartments. In general, this segregation takes place when fluid flow is prevented across sealed boundaries in the reservoir. These boundaries may for example be caused by a variety of geological and fluid dynamic factors, involving: static seals that are completely sealed and capable of withholding (trapping) petroleum deposits, or other fluids, over geological time; and dynamic seals that are low to very low permeability flow barriers that significantly reduce fluid cross-flow to rates that are sufficiently slow to cause the segregated chambers to have independent fluid pressure dynamics, although fluids and pressures may equilibrate across a dynamic seal over geological time-scales (Reservoir compartmentalization: an introduction, Jolley et al., Geological Society, London, Special Publications 2010, v. 347, p. 1-8). A reservoir compartment may be hydraulically confined, so that fluids are prevented from moving beyond the compartment by sealed boundaries confining the compartment.

(23) A hydrocarbon reservoir may for example have a heavy oil compartment hydraulically separated from a secondary zone by an artificial permeability barrier, for example made up of a functional composite seal provided by an injected blocking agent, so that under oil recovery conditions the flow of an injected fluid across the permeability barrier is restricted.

(24) Secondary zones of potential concern may for example include top water zones, which give rise to the potential for fluid communication between the secondary zone and the underlying bitumen zone as a consequence of a recovery operation. During recovery operations, a buoyant mobilized heavy oil, being less dense than the dense injection fluids, will rise in the recovery chamber and may have a tendency to spread laterally. In this circumstance, it may be desirable to hydraulically isolate a top mobilized oil recovery zone from the surrounding secondary zone. Hydraulic isolation may for example involve creating an artificially segregated zone by injecting blocking agents to confine the artificially segregated zone. For example, a segregated zone of top or bottom water may be defined by a circumferential fence comprised of injected blocking agent. In this way, a secondary zone of potential concern, such as a thief zone, may be effectively sealed to prevent the migration of mobilized hydrocarbons away from the recovery zone.

(25) Blocking agents may for example include resins, namely epoxy resins, phenolic resins, or furans. Epoxy resins are almost exclusively thermoset. Phenolic resins have been used extensively in steam flooding applications and are generally not, or moderately, sensitive to water. Phenolic resins are generally activated in the reservoir by an acidic or basic chemical activating agent. Furans may be chemically set with an acid. Certain phenolic resins and furans may set without secondary zone pre-heating. An alternative blocking agent may comprise an ultra-high melting point petroleum wax, or a wax based on another substance, and the wax may for example be heated to lower the viscosity of the wax and then injected into the reservoir to the desired location in the secondary zone. The wax may then “set-up” at the native temperature of the secondary zone.

(26) Although various embodiments of the invention are disclosed herein, many adaptations and modifications may be made within the scope of the invention in accordance with the common general knowledge of those skilled in this art. Such modifications include the substitution of known equivalents for any aspect of the invention in order to achieve the same result in substantially the same way. Numeric ranges are inclusive of the numbers defining the range. The word “comprising” is used herein as an open-ended term, substantially equivalent to the phrase “including, but not limited to”, and the word “comprises” has a corresponding meaning. As used herein, the singular forms “a”, “an” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a thing” includes more than one such thing. Citation of references herein is not an admission that such references are prior art to the present invention. Any priority document(s) and all publications, including but not limited to patents and patent applications, cited in this specification are incorporated herein by reference as if each individual publication were specifically and individually indicated to be incorporated by reference herein and as though fully set forth herein. The invention includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings.

EXAMPLE

(27) Detailed computational simulations of reservoir behavior have been carried out to exemplify various aspects of the processes disclosed herein, illustrating that dense aqueous fluids may be injected so as to heat, mobilize and displace a relatively less-dense heavy oil in situ.

(28) The reservoir characteristics of the simulated 2D reservoir are as follows, using a conventional homogenous simulation comprised of a 10 m thick water zone (S.sub.w=80% and S.sub.o=20%) overlaying 20 m thick reservoir (S.sub.w=20% and S.sub.o=80%). Grids for reservoir and transition zone (top water zone) were defined as follows: Reservoir grid 500m x 1m x 20m; X: 500×2 m; Y: 1×800 m ; Z: 20×1 m.

(29) Simulation properties of the reservoir are set out in Table 1.

(30) TABLE-US-00001 TABLE 1 Simulation Properties of Reservoir Property Value Units Solid sand N/A Initial Reservoir 12 C. Temperature Initial Reservoir Pressure 1300 kPa Initial Water Saturation 0.2 N/A Initial Oil Saturation 0.8 N/A Initial methane fraction in 0 Mol % oil K.sub.H 9.5 D K.sub.V 7.9 D Porosity 0.34 N/A

(31) In the simulation, the transition zone (top water zone) was defined as follows: Transition_zone grid 510 x 1 x 10; X: 64 m 32 m 16 m 4 m 2m 500×2 m 2 m 4 m 16 m 32 m 64 m; Y: 1×800 m; Z: 10×1 m.

(32) Simulation properties of the transition zone are set out in Table 2.

(33) TABLE-US-00002 TABLE 2 Simulation Properties for Transition Zone Property Value Units Solid sand N/A Initial Reservoir 12 C. Temperature Initial Reservoir Pressure 1100 kPa Initial Water Saturation 0.8 N/A Initial Oil Saturation 0.2 N/A Initial methane fraction in 0 Mol % oil K.sub.H 9.5 D K.sub.V 7.9 D Porosity 0.34 N/A

(34) Two edge blocks within the simulation have infinite porosity (1e6) to mimic a flowing aquifer and maintain 1100 KPa at all times. Three hot water injectors were placed at the bottom of the Transition Zone, simulating hot aqueous fluid injection that is in fluid communication with the heavy oil, and accordingly facilitating heat transfer to the heavy oil reservoir. The three injectors are located equidistant to each other. Hot (211° C.) low quality (1% saline) water was injected at a pressure of 2000 KPa and a rate of 3500 Sm.sup.3/d per well. The total of three wells injected 10500 Sm.sup.3/d. The simulation grid set up is shown schematically in FIG. 2, with shading illustrating relative oil saturation, 20% in the water zone (Transition Zone) and 80% in the reservoir.

(35) FIGS. 3 to 6 illustrate the evolution of the heat transfer profile for simulated injection of low quality (dense 1% saline) water compared to injection of standard (no salinity) water, over a period from 0 to 8 years. As illustrated, heated water injection at 211° C. and 2000 KPa can be seen to heat the reservoir, with distinct differences in the temperature profile over time when a dense aqueous fluids (low quality water) is used compared to standard water.

(36) FIGS. 7 to 10 illustrate the evolution of the oil saturation profile for simulated injection of low quality (dense 1% saline) water compared to injection of standard (no salinity) water, over a period from 0 to 8 years. As illustrated, heated bitumen is mobilized and, being lighter than the saline injection fluid, migrates upwardly by gravity displacement towards the transition zone, so that a portion of the mobilized heavy oil arrives in the transition zone so as to overlie the injection zone. This gravity dominated fluid inversion process, dense aqueous gravity displacement (DAGD), does not take place when the aqueous injection fluid is not saline (standard water).

(37) Consistent with the DAGD process, FIG. 11 shows the change in simulated oil saturation over time, with the average oil saturation (S.sub.o) in the reservoir decreasing over time and the average S.sub.o of the transition zone increasing over time, providing an oil migration profile over time that is ultimately favourable to production of the mobilized bitumen from the transition zone. Similarly, FIG. 12 illustrates the change in simulated oil (bitumen) migration volumes over time, showing a decrease in cumulative reservoir bitumen over time and a corresponding increase in cumulative transition zone bitumen over time, providing a profile of simulated oil volume migration from the reservoir to the transition zone over time. In terms of volume, 36% of oil in place migrates over the simulation time period from the reservoir to the transition zone.

(38) An equivalent steam to oil ratio may be calculated for the reservoir and the transition Zone, using the following equation (in which, M=mass in Kg; and H=enthalpy in J/Kg or KJ/Kg):

(39) $\text{Equivalent}\mathrm{CSOR}=\frac{\left(m_{\mathrm{steam}}*H_{\mathrm{steam}}+m_{\mathrm{solvent}}*H_{\mathrm{solvent}}\right)}{\left(m_{\mathrm{oil}}*H_{\mathrm{steam},\mathrm{ref}}\right)}$

(40) FIG. 13 illustrates the change in cumulative stream oil ratio (CSOR) over time for the simulated transition zone. FIG. 14 illustrates the corresponding change in CSOR over time for the simulated reservoir. CSOR is calculated assuming 60% oil in place at a given time can be recovered.

(41) This example illustrates the efficacy of a heavy oil mobilization and recovery scheme that makes use of hot dense fluid injection. Techniques of this kind may for example be implemented in oil sands deposits, for example in deposits that are characterized by overlying mobile transition zones (e.g. water and/or gas caps). FIG. 15 is s schematic illustration of one prospective well configuration for production and injection wells in a reservoir in which heavy oil has been mobilized by dense aqueous gravity displacement (DAGD). A very wide variety of well configurations are possible in alternative embodiments. FIG. 16 illustrates one modeled implementation, in which there are 6 injection wells at the base of a thief zone of mobile top water, and 13 production wells located approximately 3 m above the injectors. The positioning of the injection and production wells will accordingly vary widely based on the geology of the reservoir and the operating parameters of the recovery operation.