CA3004235A1 - Staging production well depth - Google Patents
Staging production well depth Download PDFInfo
- Publication number
- CA3004235A1 CA3004235A1 CA3004235A CA3004235A CA3004235A1 CA 3004235 A1 CA3004235 A1 CA 3004235A1 CA 3004235 A CA3004235 A CA 3004235A CA 3004235 A CA3004235 A CA 3004235A CA 3004235 A1 CA3004235 A1 CA 3004235A1
- Authority
- CA
- Canada
- Prior art keywords
- primary
- production
- well
- heavy oil
- longitudinal extension
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Pending
Links
Abstract
Aspects of the disclosure involve the production of hydrocarbons from segregated primary and secondary reservoir zones. Thermal recovery processes within the primary zone are used so as to provide thermal energy to the secondary, underlying, adjoining but distinct zone, increasing fluid mobility within the secondary zone. Switching from an upper primary to a lower secondary production well then facilitates improved recovery of hydrocarbons from both the primary and secondary zones.
Description
STAGING PRODUCTION WELL DEPTH
TECHNICAL FIELD
[0001] The invention is in the field of hydrocarbon reservoir engineering, particularly thermal recovery processes such as steam assisted gravity drainage (SAGD) systems in heavy oil reservoirs.
BACKGROUND
TECHNICAL FIELD
[0001] The invention is in the field of hydrocarbon reservoir engineering, particularly thermal recovery processes such as steam assisted gravity drainage (SAGD) systems in heavy oil reservoirs.
BACKGROUND
[0002] Some subterranean deposits of viscous hydrocarbons can be extracted in situ by lowering the viscosity of the petroleum to mobilize it so that it can be moved to, and recovered from, a production well. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbon, heavy oil, bitumen, tar sands, or oil sands. The in situ processes for recovering oil from oil sands typically involve the use of multiple wells drilled into the reservoir, and are assisted or aided by thermal recovery techniques, such as injecting a heated fluid, typically steam, into the reservoir from an injection well. One process of this kind is steam-assisted gravity drainage (SAGD).
[0003] The SAGD process is in widespread use to recover heavy hydrocarbons from the Lower Cretaceous McMurray Formation, within the Athabasca Oil Sands of northeastern Alberta, Canada. A thick sequence of marine shales and siltstones of the Clearwater Formation unconformably overlies the McMurray Formation in most areas of northeastern Alberta. In some areas, glauconitic sandstones of the Wabiskaw member are present at the base of the Clearwater. The Grand Rapids Formation overlies the Clearwater Formation, and quaternary deposits unconformably overlie the Cretaceous section. The pattern of hydrocarbon deposits within this geological context is complex and varied.
[0004] A typical SAGD process is disclosed in Canadian Patent No.
1,130,201 issued on 24 August 1982, in which the functional unit involves two wells that are drilled into the deposit, one for injection of steam and one for production of oil and water. Steam is injected via the injection well to heat the formation. The steam condenses and gives up its latent heat to the formation, heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby mobilized, and drain by gravity toward the production well with an aqueous condensate. In this way, the injected steam initially mobilises the in-place hydrocarbon to create a "steam chamber"
in the reservoir around and above the horizontal injection well. The term "steam chamber"
accordingly refers to the volume of the reservoir which is saturated with injected steam and from which mobilized oil has at least partially drained. Mobilized viscous hydrocarbons are typically recovered continuously through the production well.
The conditions of steam injection and of hydrocarbon production may be modulated to control the growth of the steam chamber, to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.
1,130,201 issued on 24 August 1982, in which the functional unit involves two wells that are drilled into the deposit, one for injection of steam and one for production of oil and water. Steam is injected via the injection well to heat the formation. The steam condenses and gives up its latent heat to the formation, heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby mobilized, and drain by gravity toward the production well with an aqueous condensate. In this way, the injected steam initially mobilises the in-place hydrocarbon to create a "steam chamber"
in the reservoir around and above the horizontal injection well. The term "steam chamber"
accordingly refers to the volume of the reservoir which is saturated with injected steam and from which mobilized oil has at least partially drained. Mobilized viscous hydrocarbons are typically recovered continuously through the production well.
The conditions of steam injection and of hydrocarbon production may be modulated to control the growth of the steam chamber, to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.
[0005] In the ramp-up stage of the SAGD process, after communication has been established between the injection and production wells during start-up, production begins from the production well. Steam is continuously injected into the injection well (usually at constant pressure) while mobilized bitumen and water are continuously removed from the production well (usually at constant temperature). During this period the zone of communication between the wells is expanded axially along the full well pair length and the steam chamber grows vertically up to the top of the reservoir. The reservoir top may be a thick shale (overburden) or some lower permeability facies that cause the steam chamber to stop rising.
[0006] 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.
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, 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.
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.
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, 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.
[0007] 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/m3. Bitumen is sometimes described as that portion of petroleum that exists in the semi-solid or solid phase in natural deposits, with a mass density greater than about 1000 kg/m3 and a viscosity greater than 10,000 centipoise (cP; or 10 Pa.$) measured at original temperature in the deposit and atmospheric pressure, on a gas-free basis.
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.
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.
[0008] 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 "tar sand" 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, and may extend into adjoining strata. 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.
Zones may exist in a reservoir within or across strata, and may extend into adjoining strata. 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.
[0009] "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, in situ combustion, hot water flooding, steam flooding, electrical heating, and solvent-aided processes (SAP). In general, thermal energy is provided to reduce the viscosity of the petroleum to facilitate production. The addition of heat may also have geophysical effects within the reservoir, for example causing the expansion of reservoir fluids, which may in turn lead to increases in pore pressures. In oil sand reservoirs, thermal expansion of bitumen within a reservoir may for example create pore pressures that are high enough to produce reservoir expansion, in effect moving sand grains apart (R.M. Butler, The expansion of tar sands during thermal recovery, Journal of Canadian Petroleum Technology, 1986, volume 25, issue 5, p. 51-56). The evolution of temperature and heat flow within a reservoir depends upon the thermal properties of the reservoir materials, including volumetric heat capacity, thermal conductivity, thermal diffusivity and the coefficients of thermal expansion.
[0010] A "chamber" or "zone" 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.
[0011] Heavy oil recovery techniques such as SAGD create mobile zones or chambers in a reservoir, for example zones from which at least some of the original oil-in-place has been recovered. However, reservoirs depleted by such processes typically contain a significant volume of residual hydrocarbons, often in reservoir zones that are geologically segregated from a mobile production zone, separated from the production zone for example by lower permeability facies such as a shale layers.
Accordingly, the term "barrier" or "baffle" may be used herein to mean a geological formation having some distinct geological characteristic that at least partially separates two or more zones in a formation, such as one or more low permeability streaks that together at least partially segregate two or more heavy oil containing strata.
A barrier may accordingly be of varying degrees of impermeability and/or continuity, for example preventing or impeding hydraulic flow between at least some portions of the reservoir under some reservoir conditions, or more typically serving as a semi-permeable barrier under select reservoir conditions that allows some degree of reservoir fluid mobility, for example discontinuous streaks of reduced permeability that act as baffles to fluid flow between reservoir zones. There remains a need for methods that may be used to recover residual hydrocarbons, particularly from formations that include barriers to fluid flow.
SUMMARY
Accordingly, the term "barrier" or "baffle" may be used herein to mean a geological formation having some distinct geological characteristic that at least partially separates two or more zones in a formation, such as one or more low permeability streaks that together at least partially segregate two or more heavy oil containing strata.
A barrier may accordingly be of varying degrees of impermeability and/or continuity, for example preventing or impeding hydraulic flow between at least some portions of the reservoir under some reservoir conditions, or more typically serving as a semi-permeable barrier under select reservoir conditions that allows some degree of reservoir fluid mobility, for example discontinuous streaks of reduced permeability that act as baffles to fluid flow between reservoir zones. There remains a need for methods that may be used to recover residual hydrocarbons, particularly from formations that include barriers to fluid flow.
SUMMARY
[0012] Various aspects of the innovations disclosed herein involve the production of hydrocarbons from reservoir zones that are initially segregated by permeability barriers, such as lower permeability facies. Thermal recovery techniques applied to a primary recovery zone are used so as to provide thermal energy to an underlying secondary recovery zone. Production from the primary recovery zone is managed in conjunction with effecting thermal communication into the secondary recovery zone.
Conductive heating of the secondary recovery zone circumvents the permeability barriers, to increase the potential for mobility of heavy oil in the secondary recovery zone. When hydrocarbon mobility has been potentiated in the secondary recovery zone in this way, the arrangement of production wells in the reservoir may be changed, dropping functional segments of the production well into the secondary recovery zone.
Once this is done, the reconfigured well pairs may be operated so as to recover hydrocarbons from both the primary and secondary recovery zones, in effect recovering what may otherwise have been a bypassed 'pay' zone. In other words, the present disclosure identifies and capitalizes on efficiencies resulting from a well configuration featuring two vertically-displaced production wells. The efficiencies are associated with the conduction of heat energy between segregated zones and the capture of hydrocarbons which may not be recoverable by either of the production wells in isolation. In some instances, processes in accordance with the present disclosure have been shown to provide increased hydrocarbon recovery volumes of greater than about 10 vol.%.
Conductive heating of the secondary recovery zone circumvents the permeability barriers, to increase the potential for mobility of heavy oil in the secondary recovery zone. When hydrocarbon mobility has been potentiated in the secondary recovery zone in this way, the arrangement of production wells in the reservoir may be changed, dropping functional segments of the production well into the secondary recovery zone.
Once this is done, the reconfigured well pairs may be operated so as to recover hydrocarbons from both the primary and secondary recovery zones, in effect recovering what may otherwise have been a bypassed 'pay' zone. In other words, the present disclosure identifies and capitalizes on efficiencies resulting from a well configuration featuring two vertically-displaced production wells. The efficiencies are associated with the conduction of heat energy between segregated zones and the capture of hydrocarbons which may not be recoverable by either of the production wells in isolation. In some instances, processes in accordance with the present disclosure have been shown to provide increased hydrocarbon recovery volumes of greater than about 10 vol.%.
[0013] Select embodiments of the present disclosure relate to a process for mobilizing fluids in a subterranean formation, the process comprising:
selecting a hydrocarbon reservoir bearing heavy oil in the formation, the reservoir having an upper primary heavy oil zone above a secondary heavy oil zone, the secondary heavy oil zone comprising barrier strata that form one or more permeability barriers;
providing an injection well within the hydrocarbon reservoir, wherein the injection well comprises an injection well surface completion in fluid communication with the hydrocarbon reservoir through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in an injection well toe;
providing a primary production well within the hydrocarbon reservoir, wherein the primary production well comprises a production well surface completion in fluid communication with the hydrocarbon reservoir through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in a production well toe, wherein the longitudinal extension segment of the production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the injection wellbore, the injection well and primary production well thereby forming an injector-primary-producer well pair having a longitudinal axial dimension within the hydrocarbon reservoir; injecting an injection fluid into the primary heavy oil recovery zone through the longitudinal extension segment of the injection well and producing fluids collected along the longitudinal extension segment of the primary production well, thereby operating the injector-primary-producer well pair under a substantially gravity-dominated recovery process to form a mobilized fluid recovery zone in the primary heavy oil zone, so that thermal energy applied to the primary heavy oil zone is communicated downwardly by conduction into the secondary heavy oil zone, heating heavy oil in the secondary heavy oil zone across at least one of the one or more permeability barriers; providing a secondary production well comprising a wellbore having a longitudinal extension segment having a generally horizontal component within the secondary heavy oil zone, wherein the longitudinal extension segment of the secondary production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the primary production wellbore, with barrier strata located between the longitudinal extension segments of the primary and secondary production wells, the injection well and the secondary production well thereby forming an injector-secondary-producer well pair along the longitudinal axial dimension of the hydrocarbon reservoir vertically spanning the secondary heavy oil zone; and producing fluids comprising hydrocarbons collected along the longitudinal extension segment of the secondary production well, in a gravity-dominated recovery process, thereby recovering hydrocarbons from the secondary heavy oil zone.
selecting a hydrocarbon reservoir bearing heavy oil in the formation, the reservoir having an upper primary heavy oil zone above a secondary heavy oil zone, the secondary heavy oil zone comprising barrier strata that form one or more permeability barriers;
providing an injection well within the hydrocarbon reservoir, wherein the injection well comprises an injection well surface completion in fluid communication with the hydrocarbon reservoir through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in an injection well toe;
providing a primary production well within the hydrocarbon reservoir, wherein the primary production well comprises a production well surface completion in fluid communication with the hydrocarbon reservoir through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in a production well toe, wherein the longitudinal extension segment of the production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the injection wellbore, the injection well and primary production well thereby forming an injector-primary-producer well pair having a longitudinal axial dimension within the hydrocarbon reservoir; injecting an injection fluid into the primary heavy oil recovery zone through the longitudinal extension segment of the injection well and producing fluids collected along the longitudinal extension segment of the primary production well, thereby operating the injector-primary-producer well pair under a substantially gravity-dominated recovery process to form a mobilized fluid recovery zone in the primary heavy oil zone, so that thermal energy applied to the primary heavy oil zone is communicated downwardly by conduction into the secondary heavy oil zone, heating heavy oil in the secondary heavy oil zone across at least one of the one or more permeability barriers; providing a secondary production well comprising a wellbore having a longitudinal extension segment having a generally horizontal component within the secondary heavy oil zone, wherein the longitudinal extension segment of the secondary production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the primary production wellbore, with barrier strata located between the longitudinal extension segments of the primary and secondary production wells, the injection well and the secondary production well thereby forming an injector-secondary-producer well pair along the longitudinal axial dimension of the hydrocarbon reservoir vertically spanning the secondary heavy oil zone; and producing fluids comprising hydrocarbons collected along the longitudinal extension segment of the secondary production well, in a gravity-dominated recovery process, thereby recovering hydrocarbons from the secondary heavy oil zone.
[0014]
Select embodiments of the present disclosure relate to a process for enhancing hydrocarbon recovery from a subterranean formation comprising an upper primary heavy oil zone above a secondary heavy oil zone, the secondary heavy oil zone including barrier strata that form one or more permeability barriers, the process comprising: providing an injection well comprising an injection well surface completion in fluid communication with the subterranean formation through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in an injection well toe; providing a primary production well comprising a production well surface completion in fluid communication with the subterranean formation through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in a production well toe, wherein the longitudinal extension segment of the production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the injection wellbore, the injection well and the primary production well thereby forming an injector-primary-producer well pair having a longitudinal axial dimension within the subterranean formation; providing a secondary production well comprising a wellbore having a longitudinal extension segment having a generally horizontal component within the secondary heavy oil zone, wherein the longitudinal extension segment of the secondary production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the primary production wellbore, with at least one of the one or more permeability barriers located between the longitudinal extension segments of the primary and secondary production wells, the injection well and the secondary production well thereby forming an injector-secondary-producer well pair along the longitudinal axial dimension of the subterranean formation vertically spanning the secondary heavy oil zone; forming a mobilized fluid recovery zone in the primary heavy oil zone through injection of an injection fluid into the primary heavy oil zone through the longitudinal extension segment of the injection well and collecting fluids along the longitudinal extension segment of the primary production well, such that the injector-primary-producer well pair is operated under a substantially gravity-dominated recovery process to form a mobilized fluid recovery zone in the primary heavy oil zone, wherein thermal energy applied to the primary heavy oil zone is communicated downwardly by conduction into the secondary heavy oil zone, heating heavy oil in the secondary heavy oil zone across the one or more permeability barriers; and producing fluids comprising hydrocarbons collected from the secondary heavy oil zone along the longitudinal extension segment of the secondary production well, such that ultimate hydrocarbon recovery is enhanced beyond that obtained from the substantially gravity-dominated recovery process in the primary production zone.
BRIEF DESCRIPTION OF THE DRAWINGS
Select embodiments of the present disclosure relate to a process for enhancing hydrocarbon recovery from a subterranean formation comprising an upper primary heavy oil zone above a secondary heavy oil zone, the secondary heavy oil zone including barrier strata that form one or more permeability barriers, the process comprising: providing an injection well comprising an injection well surface completion in fluid communication with the subterranean formation through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in an injection well toe; providing a primary production well comprising a production well surface completion in fluid communication with the subterranean formation through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in a production well toe, wherein the longitudinal extension segment of the production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the injection wellbore, the injection well and the primary production well thereby forming an injector-primary-producer well pair having a longitudinal axial dimension within the subterranean formation; providing a secondary production well comprising a wellbore having a longitudinal extension segment having a generally horizontal component within the secondary heavy oil zone, wherein the longitudinal extension segment of the secondary production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the primary production wellbore, with at least one of the one or more permeability barriers located between the longitudinal extension segments of the primary and secondary production wells, the injection well and the secondary production well thereby forming an injector-secondary-producer well pair along the longitudinal axial dimension of the subterranean formation vertically spanning the secondary heavy oil zone; forming a mobilized fluid recovery zone in the primary heavy oil zone through injection of an injection fluid into the primary heavy oil zone through the longitudinal extension segment of the injection well and collecting fluids along the longitudinal extension segment of the primary production well, such that the injector-primary-producer well pair is operated under a substantially gravity-dominated recovery process to form a mobilized fluid recovery zone in the primary heavy oil zone, wherein thermal energy applied to the primary heavy oil zone is communicated downwardly by conduction into the secondary heavy oil zone, heating heavy oil in the secondary heavy oil zone across the one or more permeability barriers; and producing fluids comprising hydrocarbons collected from the secondary heavy oil zone along the longitudinal extension segment of the secondary production well, such that ultimate hydrocarbon recovery is enhanced beyond that obtained from the substantially gravity-dominated recovery process in the primary production zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] Figure 1 is a schematic illustration of a typical SAGD well pattern, showing paired injector and producer well pairs, each have a heel and a toe within the hydrocarbon rich pay zone of the formation.
[0016] Figure 2 is schematic illustration of cretaceous stratigraphy of the Athabasca oil sands.
[0017] Figure 3 is a schematic illustration of a compartmentalized heavy oil reservoir.
[0018] Figure 4 is a cross sectional view of an exemplary completion for an injector well, referring to the use of slotted liners, as for example disclosed in Canadian Patent Application 2,616,483 of Cenovus Energy Inc. published 29 June 2008.
[0019] Figure 5 is a cross sectional view of an exemplary completion for a production well, in a start-up configuration for circulation, illustrating an embodiment employing gas lift.
[0020] Figure 6 is a cross sectional view of an exemplary completion for a production well, illustrating an embodiment employing an electric submersible pump (ESP) for production operations following start up. Typically, after circulation start-up, the 2" coiled tubing string will be removed and the well equipped with a high temperature ESP capable of pumping fluid from the well into production gathering facilities.
[0021] Figure 7 is a cross sectional view of an alternative completion for a production well.
[0022] Figure 8 is a schematic view in longitudinal cross section showing the trajectory of an exemplified well arrangement that includes an injector (top) a primary producer (middle) and a secondary producer (bottom), with arrows showing the vertical offset of the secondary producer from the primary producer (by an average of 12m).
[0023] Figure 9 is a graph showing thermocouple temperature log data in a vertical observation well positioned 2m from the horizontal well bores, with the top of the heavy oil reservoir illustrated by the top line at a depth of approximately 218m subsea, the injector well illustrated as the line at approximately 196m, the abandoned (shut in) primary producer illustrated as the line at approximately 192m and the active secondary producer well illustrated as the line at approximately 180m. The arrow indicates the increase in temperature over time over 12 months, each successive line representing one month's increase in temperature.
[0024] Figure 10 is a graph illustrating historical and projected oil production from three deepened production wells, with an arrow indicating the time at which the primary production wells were shut in and the use of the secondary production wells was initiated.
DETAILED DESCRIPTION
DETAILED DESCRIPTION
[0025] Select embodiments of the present disclosure relate to processes for mobilizing fluids in a subterranean formation, for example in a hydrocarbon reservoir bearing heavy oil. Likewise, select embodiments of the present disclosure relate to processes for enhancing hydrocarbon recovery. In select instances, the reservoir/formation may be characterized as having an upper primary heavy oil zone above a secondary heavy oil zone. The secondary heavy oil zone is defined or segregated from the primary recovery zone by the existence of barrier strata that form one or more permeability barriers.
[0026] Injection and production wells may be provided in the primary recovery zone, as for example is typical of SAGD well patterns, with the longitudinal generally horizontal segments of the injection and primary production wells being placed within the upper primary heavy oil zone, forming an injector-primary-producer well pair within the hydrocarbon reservoir. This well pair may be operated in accordance with a wide variety of approaches to steam assisted gravity drainage (SAGD) or solvent aided processes (SAP), to create a mobilized fluid recovery zone in the primary heavy oil zone, and this may be accomplished so that thermal energy applied to the primary heavy oil zone is communicated downwardly at least in part by conduction, into the secondary heavy oil zone. In this way, heavy oil in the secondary heavy oil zone is heated, and this heating takes place across the permeability barriers.
[0027] At a selected point in the mobilizing/recovery process, a secondary production well may be provided, typically generally parallel to and vertically spaced apart below the generally horizontal portion of the primary production wellbore. In this way, barrier strata may be located between the primary and secondary production wells, such that the injection and secondary production wells, which together form an injector-secondary-producer well pair, vertically span the secondary heavy oil zone. In order to determine the point at which to initiate the provision and operation of the secondary production well, a number of factors should be considered including the quality of the reservoir, the saturation of heavy oil in the secondary recovery zone, and the downward temperature gradient induced by thermal stimulation in the primary recovery zone. The downward temperature gradient induced by thermal stimulation may be of particular importance in determining the point at which to initiate the provision and operation of the secondary production well. For example, provision of/production from the secondary production well may be timed to coincide with the point at which the desired ultimate depth receives enough waste heat to reach the temperature of heavy oil mobilization.
[0028]
Fluid recovery from the primary production well may be suspended before or after the secondary production well is in place. In select embodiments, fluid recovery from the primary production well is suspended before the secondary production well is in place, and then shut in after fluid recovery from the secondary production well is established. Postponing shutting in the primary production well until after fluid recovery from the secondary production well is established may reduce the risk of reservoir-limiting production. For example, in the event that the secondary production well encounters unexpectedly poor reservoir quality that is unfavorable to production, the primary production well may be reverted to. Alternatively, production may continue for a time from both the primary and secondary production wells, for example shutting in the primary production well when the liquid levels in the primary heavy oil zone are pulled below the depth of the primary production well (i.e. when the primary producer is "steamed out").
Fluid recovery from the primary production well may be suspended before or after the secondary production well is in place. In select embodiments, fluid recovery from the primary production well is suspended before the secondary production well is in place, and then shut in after fluid recovery from the secondary production well is established. Postponing shutting in the primary production well until after fluid recovery from the secondary production well is established may reduce the risk of reservoir-limiting production. For example, in the event that the secondary production well encounters unexpectedly poor reservoir quality that is unfavorable to production, the primary production well may be reverted to. Alternatively, production may continue for a time from both the primary and secondary production wells, for example shutting in the primary production well when the liquid levels in the primary heavy oil zone are pulled below the depth of the primary production well (i.e. when the primary producer is "steamed out").
[0029] The depth at which the horizontal component of the secondary production well should be provided may be influenced by a variety of factors such as reservoir quality, underlying heavy oil saturation, heavy oil chemistry, and the downward temperature gradient induced by thermal stimulation in the primary recovery zone. In select embodiments, the secondary production well may be spaced below the primary production well by at least about 3m, 10m, 15m, or 25m. In a preferred embodiment, the secondary production well may be spaced below the primary production well by about llm as averaged along the lateral length of the primary production well.
Those skilled in the art will recognize that the horizontal components of such wells are typically non-uniform. For example, the horizontal component of the secondary production well may be spaced below the horizontal component of the primary production well by an average of about llm but have segments ranging from about 9m to about 13m below the horizontal component of primary production well.
Overall, the displacement of the horizontal component of the secondary production well from the horizontal component of the primary production well should be large enough to produce sufficient volumes of heavy oil to justify the risk and capital investment associated with the provision and operation of the secondary production well.
Those skilled in the art will recognize that the horizontal components of such wells are typically non-uniform. For example, the horizontal component of the secondary production well may be spaced below the horizontal component of the primary production well by an average of about llm but have segments ranging from about 9m to about 13m below the horizontal component of primary production well.
Overall, the displacement of the horizontal component of the secondary production well from the horizontal component of the primary production well should be large enough to produce sufficient volumes of heavy oil to justify the risk and capital investment associated with the provision and operation of the secondary production well.
[0030]
Recovery processes in accordance with the present disclosure may for example be carried out by way of a gravity-dominated recovery process, such as SAGD or SAP, thereby recovering hydrocarbons from both the primary and the secondary heavy oil zones. In particular, recovery form the secondary heavy oil zone may be facilitated by thermal stimulation of the secondary heavy oil zone by way of the secondary production well. For example, in instances where the depth of the secondary production well is selected to penetrate a section of the secondary recovery zone that is substantially below the temperature at which the heavy hydrocarbons of the secondary recovery zone are mobile, steam, solvent, or a combination thereof may be injected into the secondary recovery zone by way of the secondary production well prior to production from the secondary production well.
Recovery processes in accordance with the present disclosure may for example be carried out by way of a gravity-dominated recovery process, such as SAGD or SAP, thereby recovering hydrocarbons from both the primary and the secondary heavy oil zones. In particular, recovery form the secondary heavy oil zone may be facilitated by thermal stimulation of the secondary heavy oil zone by way of the secondary production well. For example, in instances where the depth of the secondary production well is selected to penetrate a section of the secondary recovery zone that is substantially below the temperature at which the heavy hydrocarbons of the secondary recovery zone are mobile, steam, solvent, or a combination thereof may be injected into the secondary recovery zone by way of the secondary production well prior to production from the secondary production well.
[0031] Select embodiments of the present disclosure will now be described by reference to Figures 1-10.
[0032] Various aspects of the invention may involve the drilling of SAGD
well pairs within a reservoir 11, as illustrated in Figure 1, with each injector well 13, 19, and 23, paired with a corresponding producer well 15, 17 and 21. Each well has a completion 14, 12, 16, 18, 20 and 22 on surface 10, with a generally vertical segment leading to the heel of the well, which then extends along a generally horizontal segment to the toe of the well. In very general terms, to provide a general illustration of scale in selected embodiments, these well pairs may for example be drilled in keeping with the following parameters. There may be approximately 5 m depth separation between the injection well and production well. The SAGD well pair may for example average approximately 800 m in length. The lower production well profile may generally be targeted so that it is approximately 1 to 2 m above the SAGD base. The development of steam chambers around each well pair may be illustrated in cross sectional views along axis 24, which is perpendicular to the longitudinal axial dimension of the horizontal segments of the well pairs.
well pairs within a reservoir 11, as illustrated in Figure 1, with each injector well 13, 19, and 23, paired with a corresponding producer well 15, 17 and 21. Each well has a completion 14, 12, 16, 18, 20 and 22 on surface 10, with a generally vertical segment leading to the heel of the well, which then extends along a generally horizontal segment to the toe of the well. In very general terms, to provide a general illustration of scale in selected embodiments, these well pairs may for example be drilled in keeping with the following parameters. There may be approximately 5 m depth separation between the injection well and production well. The SAGD well pair may for example average approximately 800 m in length. The lower production well profile may generally be targeted so that it is approximately 1 to 2 m above the SAGD base. The development of steam chambers around each well pair may be illustrated in cross sectional views along axis 24, which is perpendicular to the longitudinal axial dimension of the horizontal segments of the well pairs.
[0033] As illustrated in Figure 2, the stratigraphy of the Athabasca oil sands varies geographically, and in places includes oil sand deposits that are separated by distinct barrier layers, such as marine shales. Figure 3 is a cross sectional view along axis 24 of Figure 1, illustrating a hydrocarbon reservoir in which a primary heavy oil recovery zone 28 is separated from a secondary heavy oil zone 30 by one or more permeability barriers 20. The top of the primary heavy oil recovery zone 28 is hydraulically confined, for example by shale cap rock 40.
[0034] In the embodiment illustrated in Figure 3, injection 19 and primary production 17 wells are present in primary recovery zone 29, as for example is typical of SAGD well patterns as illustrated in Figure 1, with the longitudinal generally horizontal segments of the injection 19 and primary production 17 wells being placed within upper primary heavy oil zone 29, forming an injector-primary-producer well pair within the hydrocarbon reservoir. A thermal recovery technique, such as SAGD, may be applied to the primary heavy oil zone 29, for example forming steam chamber around injection well 19, to mobilize heavy oil for production through primary production well 17. Thermal energy applied to primary heavy oil zone 29 by way of steam chamber 28 is communicated across permeability barriers 20 to secondary heavy oil zone 30 to heat heavy oil in the secondary heavy oil zone 30. In this sense, the secondary heavy oil zone 30 is defined, or segregated or partially segregated from the primary recovery zone 29, by the barrier strata that form one or more permeability barriers 20, such as clasts, shale lenses, or IHS. The heating of the secondary heavy oil zone 30 may be primarily by way of conductive heating of the fluids in secondary zone 30, in contrast to the considerable degree of convective heating in the primary recovery zone 29 associated with steam chamber 28. In alternative embodiments, the injector-primary-producer well pair may be operated in accordance with a wide variety of approaches to thermal recovery, such as cyclic steam stimulation, hot water flood, steam flood, and SAGD with or without solvents, to create the mobilized fluid recovery zone 28 in the primary heavy oil zone 29. In this way, heavy oil in the secondary heavy oil zone 30 is heated to a selected point of practical mobility. This minimum temperature point may for example be determined based on a function of the vertical depth offset from the original well pair, the well length, reservoir fluid saturations, artificial lift method, and surface and downhole pressures. In select embodiments, the selected point at which there is a transition to production from the secondary heavy oil zone 30 is when the average or aggregate fluid viscosity in the secondary zone 30 is low enough that flow rates through the new producer well are stable and sustainable.
[0035] At the selected point in the recovery process, a secondary production well 27 may be provided, typically with a horizontal segment that is generally parallel to and vertically spaced apart below the generally horizontal portion of the primary production wellbore 17. In this way, barrier strata 20 are located between the primary 17 and secondary 27 production wells. The injection 19 and secondary production 27 wells accordingly together form an injector-secondary-producer well pair, vertically spanning secondary heavy oil zone 30. Once the secondary production well 27 in in place, fluid recovery from the primary production well 17 may be suspended or shut in, and the production of fluids commenced from the secondary production well 27.
This recovery process may for example be carried out by way of a gravity-dominated recovery process, such as SAGD, thereby recovering hydrocarbons from both the primary and the secondary heavy oil zones.
This recovery process may for example be carried out by way of a gravity-dominated recovery process, such as SAGD, thereby recovering hydrocarbons from both the primary and the secondary heavy oil zones.
[0036] The inventors have recognized that the abandonment of fully-functioning, high-productivity oil producer well located in the primary recovery zone in favour of a new producer well(s) with trajectories that are capable of capturing by-passed oil enable a new recovery scheme for producing oil from both the primary and secondary recovery zones. The new producer well 27 is located within the secondary recovery zone. In alternative embodiments, the secondary producer 27 may for example located at least about 1m, 2m, 3m, 4m, 5m, 6m, 7m, 8m, 9m, 10m, 11m, 12m, 13m, 14m, 15m, 20m or 25m from the primary producer 17. In general, greater offset distances will require more time for conductive heating of the secondary zone before production is initiated from the new producer 27.
[0037] Alternative aspects of the invention involve completing wells in various configurations. Exemplary completions for injector, producer on gas lift, producer on electric submersible pump (ESP) and simulated producer are shown in Figures 4, 5, 6 and 7 respectively. The selection of an appropriate set of configurations is within the purview of a person skilled in the art having the benefit of the present disclosure and having regard to the parameters of the specific formation under consideration.
[0038] In accordance with various aspects of the disclosure, detailed computational simulations of reservoir behaviour may be carried out. The thermal properties of the reservoir may for example be characterized using two rock types. Rock type one may for example represent clean sand of the McMurray formation in Alberta, Canada.
A
second rock type representing an relatively impermeably strata, such as shale, may be used to simulate a permeability barrier. Exemplary properties of the two such rock types may for example be defined with the following properties:
Rocktype 1 (Sand) Porosity Reference Pressure = 100 kPa Compressibility = le-6 1/kPa Volumetric Heat Capacity 2.39e6 J/(m3*C) Rock Thermal Conductivity = 196,820 J/(m*day*C) Water Thermal Conductivity = 552,960 J/(m*day*C) Oil Thermal Conductivity = 0 Gas Thermal Conductivity = 0 Rocktype 2 (Shale Overburden & Underburden) Porosity Reference Pressure = 100 kPa Compressibility= 1e6 1/kPa Volumetric Heat Capacity 2.39e6 J/(m3*C) Rock Thermal Conductivity = 146,880 J/(m*day*C) Water Thermal Conductivity = 0 Oil Thermal Conductivity = 0 Gas Thermal Conductivity = 0
A
second rock type representing an relatively impermeably strata, such as shale, may be used to simulate a permeability barrier. Exemplary properties of the two such rock types may for example be defined with the following properties:
Rocktype 1 (Sand) Porosity Reference Pressure = 100 kPa Compressibility = le-6 1/kPa Volumetric Heat Capacity 2.39e6 J/(m3*C) Rock Thermal Conductivity = 196,820 J/(m*day*C) Water Thermal Conductivity = 552,960 J/(m*day*C) Oil Thermal Conductivity = 0 Gas Thermal Conductivity = 0 Rocktype 2 (Shale Overburden & Underburden) Porosity Reference Pressure = 100 kPa Compressibility= 1e6 1/kPa Volumetric Heat Capacity 2.39e6 J/(m3*C) Rock Thermal Conductivity = 146,880 J/(m*day*C) Water Thermal Conductivity = 0 Oil Thermal Conductivity = 0 Gas Thermal Conductivity = 0
[0039] In an exemplary embodiment of the processes of the disclosure, carried out in the McMurray and Wabiskaw formations, typical values of the relevant formation thicknesses are as follows: McMurray Formation in which SAGD is being conducted 38 m; impermeable mudstone immediately overlying the McMurray 6 m; affected Wabiskaw zone immediately overlying the mudstone 7 m. In this embodiment, the ascent within the McMurray Formation of the SAGD steam chamber was confirmed with temperature profiles. It was also confirmed with 4D (Time Lapse) Seismic data.
Progressive heating of the overlying Wabiskaw was clearly evident in the 4D
seismic data, over time: year 1 - No seismic anomalies evident in Wabiskaw; year 2 -anomalies appear, indicating some heating of Wabiskaw; year 3 ¨ anomalies signal continued heating of Wabiskaw. In general terms, the geology of the exemplified embodiment was characterized by a large, relatively clean, bitumen saturated and high permeability sand package, with the notable exception of several known mud barriers (having virtually zero permeability) of unknown variable extent located below the primary producer, but above the secondary producer. In the exemplified implementation, had the primary producer been originally placed below these mud barriers, the steam chamber would not have properly developed as the mud barriers would have interfered with fluid communication within the recovery zone, and the overall ultimate recovery of hydrocarbons would have been far lower.
Progressive heating of the overlying Wabiskaw was clearly evident in the 4D
seismic data, over time: year 1 - No seismic anomalies evident in Wabiskaw; year 2 -anomalies appear, indicating some heating of Wabiskaw; year 3 ¨ anomalies signal continued heating of Wabiskaw. In general terms, the geology of the exemplified embodiment was characterized by a large, relatively clean, bitumen saturated and high permeability sand package, with the notable exception of several known mud barriers (having virtually zero permeability) of unknown variable extent located below the primary producer, but above the secondary producer. In the exemplified implementation, had the primary producer been originally placed below these mud barriers, the steam chamber would not have properly developed as the mud barriers would have interfered with fluid communication within the recovery zone, and the overall ultimate recovery of hydrocarbons would have been far lower.
[0040] The trajectory of the exemplified wells is illustrated in Figure 8. The conductive heating of bitumen in the secondary recovery zone is illustrated in Figure 9. This graph provides data beginning two months before the secondary producer well was drilled, then shows the jump in temperature that coincides with a 30 day steam-stimulation of the secondary producer. The continued increase in the heating of the secondary recovery zone that accompanies production of reservoir fluids through the secondary producer is also illustrated. The earliest temperature plots according illustrate the degree to which the secondary recovery zone was above the mobility threshold (defined as 60 C for this well configuration and facility operating conditions) prior to the initiation of recovery from the secondary producer. In select embodiments, secondary producers may for example be offset from a primary producer by up to 10m, 15m, 20m or 25. Primary and secondary producer offsets are possible at progressively greater distances, for example greater than 20m or 25m, provided there has been sufficient time and heat input for conductive heating to adequately increase the mobility of oil in the secondary recovery zone. The transition to production from the secondary producers may for example take place at a selected mobility threshold, such as a secondary producer well bottom temperature of approximately 50 C, 60 C
or 70 C, or any selected value within the range of 50 C to 70 C. The mobility threshold may for example be chosen in conjunction with the selection of a start up regime for the secondary producer, for example with or without an initial period of heating, for example by cycling steam through the secondary producer, and/or applying a solvent start up process. In some embodiments, recovery may be initiated from the secondary producer without any additional heat being applied, with the necessary mobility being conferred exclusively by conductive heating from the primary recovery process.
or 70 C, or any selected value within the range of 50 C to 70 C. The mobility threshold may for example be chosen in conjunction with the selection of a start up regime for the secondary producer, for example with or without an initial period of heating, for example by cycling steam through the secondary producer, and/or applying a solvent start up process. In some embodiments, recovery may be initiated from the secondary producer without any additional heat being applied, with the necessary mobility being conferred exclusively by conductive heating from the primary recovery process.
[0041] Figure 10 is a graph illustrating actual and forecast oil production rates from a set of three primary production wells, followed by the recoveries from three corresponding secondary production wells, with the arrow at the beginning of identifying the date corresponding to the initiation of processes for the recovery of hydrocarbons from the secondary zone, with the onset of production from the secondary producer wells occurring shortly thereafter. The simulated combined production from the primary and secondary zones through the secondary producers is shown as line superimposed on the initial cumulative production figures. As illustrated, following the three well redevelopment, oil rates increased by about 3600bb1/d, with one of the new secondary producers alone having a number of weeks producing above 3400bb1/d. In conjunction with the switch to the secondary production wells, the SOR for the three well-pairs dropped from 2.6 to 1.3. This is a further indication of the degree to which the primarily conductive heating of the secondary recovery zone mobilizes the oil therein during recovery from the primary recovery zone.
[0042] The present disclosure identifies and capitalizes on efficiencies resulting from a well configuration featuring two vertically-displaced production wells.
The efficiencies are associated with the conduction of heat energy between segregated zones and the capture of hydrocarbons which may not be recoverable by either of the production wells in isolation. In some instances, processes in accordance with the present disclosure have been shown to provide increased hydrocarbon recovery volumes of greater than about 10 vol.%. The potential for processes in accordance with present disclosure to increase the ultimate hydrocarbon recovery volume for a reservoir has been verified independently. In one instance, an independent qualified reservoir evaluator (IQRE) determined a reservoir to have an estimated bitumen in place (EBIP) volume of about 145 mmbbl for a first pad. This estimate is independent of the depth/number/configuration of the production wells utilized. After the provision of five secondary production wells, the IQRE increased the recoverable volumes for the pad from about 30.0 mmbbl in 2015 to about 34.1 mmbbl in 2017 ( a 4.1 mmbbl increase). The vast majority of this increase was attributed directly to the provision of the secondary production wells, and it represents an increase in ultimate recovery of the original EBIP of about 9% (from -66% to -76%), and a 14% increase in recoverable volume.
The efficiencies are associated with the conduction of heat energy between segregated zones and the capture of hydrocarbons which may not be recoverable by either of the production wells in isolation. In some instances, processes in accordance with the present disclosure have been shown to provide increased hydrocarbon recovery volumes of greater than about 10 vol.%. The potential for processes in accordance with present disclosure to increase the ultimate hydrocarbon recovery volume for a reservoir has been verified independently. In one instance, an independent qualified reservoir evaluator (IQRE) determined a reservoir to have an estimated bitumen in place (EBIP) volume of about 145 mmbbl for a first pad. This estimate is independent of the depth/number/configuration of the production wells utilized. After the provision of five secondary production wells, the IQRE increased the recoverable volumes for the pad from about 30.0 mmbbl in 2015 to about 34.1 mmbbl in 2017 ( a 4.1 mmbbl increase). The vast majority of this increase was attributed directly to the provision of the secondary production wells, and it represents an increase in ultimate recovery of the original EBIP of about 9% (from -66% to -76%), and a 14% increase in recoverable volume.
[0043]
Although various embodiments of the disclosure are provided herein, many adaptations and modifications may be made within the scope of the disclosure in accordance with the common general knowledge of those skilled in this art. For example, any one or more of the injection, production or vent wells may be adapted from well segments that have served or serve a different purpose, so that the well segment may be re-purposed to carry out aspects of the disclosure, including for example the use of multilateral wells as injection, production and/or vent wells. Such modifications include the substitution of known equivalents for any aspect of the disclosure 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 disclosure. 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 disclosure includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings.
Although various embodiments of the disclosure are provided herein, many adaptations and modifications may be made within the scope of the disclosure in accordance with the common general knowledge of those skilled in this art. For example, any one or more of the injection, production or vent wells may be adapted from well segments that have served or serve a different purpose, so that the well segment may be re-purposed to carry out aspects of the disclosure, including for example the use of multilateral wells as injection, production and/or vent wells. Such modifications include the substitution of known equivalents for any aspect of the disclosure 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 disclosure. 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 disclosure includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings.
Claims (27)
1. A process for mobilizing fluids in a subterranean formation, the process comprising:
selecting a hydrocarbon reservoir bearing heavy oil in the formation, the reservoir having an upper primary heavy oil zone above a secondary heavy oil zone, the secondary heavy oil zone comprising barrier strata that form one or more permeability barriers;
providing an injection well within the hydrocarbon reservoir, wherein the injection well comprises an injection well surface completion in fluid communication with the hydrocarbon reservoir through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in an injection well toe;
providing a primary production well within the hydrocarbon reservoir, wherein the primary production well comprises a production well surface completion in fluid communication with the hydrocarbon reservoir through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in a production well toe, wherein the longitudinal extension segment of the production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the injection wellbore, the injection well and primary production well thereby forming an injector-primary-producer well pair having a longitudinal axial dimension within the hydrocarbon reservoir;
injecting an injection fluid into the primary heavy oil recovery zone through the longitudinal extension segment of the injection well and producing fluids collected along the longitudinal extension segment of the primary production well, thereby operating the injector-primary-producer well pair under a substantially gravity-dominated recovery process to form a mobilized fluid recovery zone in the primary heavy oil zone, so that thermal energy applied to the primary heavy oil zone is communicated downwardly by conduction into the secondary heavy oil zone, heating heavy oil in the secondary heavy oil zone across at least one of the one or more permeability barriers;
providing a secondary production well comprising a wellbore having a longitudinal extension segment having a generally horizontal component within the secondary heavy oil zone, wherein the longitudinal extension segment of the secondary production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the primary production wellbore, with barrier strata located between the longitudinal extension segments of the primary and secondary production wells, the injection well and the secondary production well thereby forming an injector-secondary-producer well pair along the longitudinal axial dimension of the hydrocarbon reservoir vertically spanning the secondary heavy oil zone; and producing fluids comprising hydrocarbons collected along the longitudinal extension segment of the secondary production well, in a gravity-dominated recovery process, thereby recovering hydrocarbons from the secondary heavy oil zone.
selecting a hydrocarbon reservoir bearing heavy oil in the formation, the reservoir having an upper primary heavy oil zone above a secondary heavy oil zone, the secondary heavy oil zone comprising barrier strata that form one or more permeability barriers;
providing an injection well within the hydrocarbon reservoir, wherein the injection well comprises an injection well surface completion in fluid communication with the hydrocarbon reservoir through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in an injection well toe;
providing a primary production well within the hydrocarbon reservoir, wherein the primary production well comprises a production well surface completion in fluid communication with the hydrocarbon reservoir through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in a production well toe, wherein the longitudinal extension segment of the production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the injection wellbore, the injection well and primary production well thereby forming an injector-primary-producer well pair having a longitudinal axial dimension within the hydrocarbon reservoir;
injecting an injection fluid into the primary heavy oil recovery zone through the longitudinal extension segment of the injection well and producing fluids collected along the longitudinal extension segment of the primary production well, thereby operating the injector-primary-producer well pair under a substantially gravity-dominated recovery process to form a mobilized fluid recovery zone in the primary heavy oil zone, so that thermal energy applied to the primary heavy oil zone is communicated downwardly by conduction into the secondary heavy oil zone, heating heavy oil in the secondary heavy oil zone across at least one of the one or more permeability barriers;
providing a secondary production well comprising a wellbore having a longitudinal extension segment having a generally horizontal component within the secondary heavy oil zone, wherein the longitudinal extension segment of the secondary production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the primary production wellbore, with barrier strata located between the longitudinal extension segments of the primary and secondary production wells, the injection well and the secondary production well thereby forming an injector-secondary-producer well pair along the longitudinal axial dimension of the hydrocarbon reservoir vertically spanning the secondary heavy oil zone; and producing fluids comprising hydrocarbons collected along the longitudinal extension segment of the secondary production well, in a gravity-dominated recovery process, thereby recovering hydrocarbons from the secondary heavy oil zone.
2. The process of claim 1, wherein fluids are produced for a primary/secondary producer production period from both:
the longitudinal extension segment of the primary production well; and, the longitudinal extension segment of the primary production well.
the longitudinal extension segment of the primary production well; and, the longitudinal extension segment of the primary production well.
3. The process of claim 1 or 2, further comprising suspending or shutting in fluid recovery from the longitudinal extension segment of the primary production well.
4. The process of claim 3, wherein the primary production well is shut in when liquid levels in the primary heavy oil zone fall below the depth of the primary production well.
5. The process of any one of claims 1 to 4, wherein prior to production of fluids from the secondary production well the production well undergoes a thermal start up process.
6. The process of any one of claims 1 to 5, wherein production of fluids from the secondary production well is initiated at a selected secondary producer well bottom temperature.
7. The process of claim 6, wherein the secondary producer well bottom temperature is approximately 50°C, 60°C or 70°C.
8. The process of any one of claims 1 to 7, wherein the longitudinal extension segment of the secondary production wellbore is vertically spaced apart below the longitudinal extension segment of the primary production wellbore by at least 3m, 10m, 15m, 20m or 25m.
9. The process of any one of claims 1 to 7, wherein the longitudinal extension segment of the secondary production wellbore is vertically spaced apart below the longitudinal extension segment of the primary production wellbore by from about 3m to about 25m.
10. The process of any one of claims 1 to 9, wherein the injector-primary-producer well pair is operated in a process of steam assisted gravity drainage (SAGD) for a primary SAGD-recovery period of time.
11. The process of any one of claims 1 to 10, wherein the injector-secondary-producer well pair is operated in a process of steam assisted gravity drainage (SAGD) for a secondary SAGD-recovery period of time.
12. The process of any one of claims 1 to 11, wherein the injector-primary-producer well pair is operated in a solvent assisted process (SAP) for a primary SAP-recovery period of time.
13. The process of any one of claims 1 to 12, wherein the injector-secondary-producer well pair is operated in a solvent assisted process (SAP) for a secondary SAP-recovery period of time.
14. A process for enhancing hydrocarbon recovery from a subterranean formation comprising an upper primary heavy oil zone above a secondary heavy oil zone, the secondary heavy oil zone including barrier strata that form one or more permeability barriers, the process comprising:
providing an injection well comprising an injection well surface completion in fluid communication with the subterranean formation through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in an injection well toe;
providing a primary production well comprising a production well surface completion in fluid communication with the subterranean formation through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in a production well toe, wherein the longitudinal extension segment of the production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the injection wellbore, the injection well and the primary production well thereby forming an injector-primary-producer well pair having a longitudinal axial dimension within the subterranean formation;
providing a secondary production well comprising a wellbore having a longitudinal extension segment having a generally horizontal component within the secondary heavy oil zone, wherein the longitudinal extension segment of the secondary production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the primary production wellbore, with at least one of the one or more permeability barriers located between the longitudinal extension segments of the primary and secondary production wells, the injection well and the secondary production well thereby forming an injector-secondary-producer well pair along the longitudinal axial dimension of the subterranean formation vertically spanning the secondary heavy oil zone;
forming a mobilized fluid recovery zone in the primary heavy oil zone through injection of an injection fluid into the primary heavy oil zone through the longitudinal extension segment of the injection well and collecting fluids along the longitudinal extension segment of the primary production well, such that the injector-primary-producer well pair is operated under a substantially gravity-dominated recovery process to form a mobilized fluid recovery zone in the primary heavy oil zone, wherein thermal energy applied to the primary heavy oil zone is communicated downwardly by conduction into the secondary heavy oil zone, heating heavy oil in the secondary heavy oil zone across the one or more permeability barriers; and producing fluids comprising hydrocarbons collected from the secondary heavy oil zone along the longitudinal extension segment of the secondary production well, such that ultimate hydrocarbon recovery is enhanced beyond that obtained from the substantially gravity-dominated recovery process in the primary production zone.
providing an injection well comprising an injection well surface completion in fluid communication with the subterranean formation through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in an injection well toe;
providing a primary production well comprising a production well surface completion in fluid communication with the subterranean formation through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment having a generally horizontal component within the upper primary heavy oil zone, the longitudinal extension segment terminating in a production well toe, wherein the longitudinal extension segment of the production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the injection wellbore, the injection well and the primary production well thereby forming an injector-primary-producer well pair having a longitudinal axial dimension within the subterranean formation;
providing a secondary production well comprising a wellbore having a longitudinal extension segment having a generally horizontal component within the secondary heavy oil zone, wherein the longitudinal extension segment of the secondary production wellbore is generally parallel to and vertically spaced apart below the longitudinal extension segment of the primary production wellbore, with at least one of the one or more permeability barriers located between the longitudinal extension segments of the primary and secondary production wells, the injection well and the secondary production well thereby forming an injector-secondary-producer well pair along the longitudinal axial dimension of the subterranean formation vertically spanning the secondary heavy oil zone;
forming a mobilized fluid recovery zone in the primary heavy oil zone through injection of an injection fluid into the primary heavy oil zone through the longitudinal extension segment of the injection well and collecting fluids along the longitudinal extension segment of the primary production well, such that the injector-primary-producer well pair is operated under a substantially gravity-dominated recovery process to form a mobilized fluid recovery zone in the primary heavy oil zone, wherein thermal energy applied to the primary heavy oil zone is communicated downwardly by conduction into the secondary heavy oil zone, heating heavy oil in the secondary heavy oil zone across the one or more permeability barriers; and producing fluids comprising hydrocarbons collected from the secondary heavy oil zone along the longitudinal extension segment of the secondary production well, such that ultimate hydrocarbon recovery is enhanced beyond that obtained from the substantially gravity-dominated recovery process in the primary production zone.
15. The process of claim 14, wherein fluids are produced for a primary/secondary producer production period from both:
the longitudinal extension segment of the primary production well; and the longitudinal extension segment of the primary production well.
the longitudinal extension segment of the primary production well; and the longitudinal extension segment of the primary production well.
16. The process of claim 14 or 15, further comprising suspending or shutting in fluid recovery from the longitudinal extension segment of the primary production well.
17. The process of claim 16, wherein the primary production well is suspended or shut in when liquid levels in the primary heavy oil zone fall below the depth of the primary production well.
18. The process of any one of claims 14 to 17, wherein prior to production of fluids from the secondary production well the production well undergoes a thermal start up process.
19. The process of any one of claims 14 to 18, wherein production of fluids from the secondary production well is initiated at a selected secondary producer well bottom temperature.
20. The process of claim 19, wherein the secondary producer well bottom temperature is approximately 40°C, 50°C, 60°C or 70°C.
21. The process of any one of claims 14 to 20, wherein the longitudinal extension segment of the secondary production wellbore is vertically spaced apart below the longitudinal extension segment of the primary production wellbore by at least 3m, 10m, 15m, 20m or 25m.
22. The process of any one of claims 14 to 20, wherein the longitudinal extension segment of the secondary production wellbore is vertically spaced apart below the longitudinal extension segment of the primary production wellbore by from about 3m to about 25m.
23. The process of any one of claims 14 to 22, wherein the injector-primary-producer well pair is operated in a process of steam assisted gravity drainage (SAGD) for a primary SAGD-recovery period of time.
24. The process of any one of claims 14 to 22, wherein the injector-primary-producer well pair is operated in a solvent assisted process (SAP) for a primary SAP-recovery period of time.
25. The process of any one of claims 14 to 24, wherein the injector-secondary-producer well pair is operated in a process of steam assisted gravity drainage (SAGD) for a secondary SAGD-recovery period of time.
26. The process of any one of claims 14 to 24, wherein the injector-secondary-producer well pair is operated in a solvent assisted process (SAP) for a secondary SAP-recovery period of time.
27. The process of any one of claims 14 to 26, wherein the ultimate hydrocarbon recovery is enhanced by at least about 10 vol.%.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US201762511760P | 2017-05-26 | 2017-05-26 | |
| US62/511,760 | 2017-05-26 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA3004235A1 true CA3004235A1 (en) | 2018-11-26 |
Family
ID=64456694
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA3004235A Pending CA3004235A1 (en) | 2017-05-26 | 2018-05-08 | Staging production well depth |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA3004235A1 (en) |
-
2018
- 2018-05-08 CA CA3004235A patent/CA3004235A1/en active Pending
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US10927655B2 (en) | Pressure assisted oil recovery | |
| CA2593585C (en) | In situ heavy oil and bitumen recovery process | |
| US9091159B2 (en) | Process and well arrangement for hydrocarbon recovery from bypassed pay or a region near the reservoir base | |
| CA2847759C (en) | A method of enhancing resource recovery from subterranean reservoirs | |
| CA2928278A1 (en) | Sw-sagd with between heel and toe injection | |
| US8985231B2 (en) | Selective displacement of water in pressure communication with a hydrocarbon reservoir | |
| US20130180712A1 (en) | Method for accelerating heavy oil production | |
| CA2893170A1 (en) | Thermally induced expansion drive in heavy oil reservoirs | |
| CA2852766C (en) | Thermally induced expansion drive in heavy oil reservoirs | |
| CA3004235A1 (en) | Staging production well depth | |
| US20230051011A1 (en) | End-of-life recovery of mobilized hydrocarbons | |
| CA2968392A1 (en) | Variable pressure sagd (vp-sagd) for heavy oil recovery | |
| US11326431B2 (en) | Dense aqueous gravity displacement of heavy oil | |
| CA2957899C (en) | Systems and methods of recovering migrated hydrocarbons from bottom water zones | |
| CA2911737C (en) | Process and system for increasing mobility of a reservoir fluid in a hydrocarbon-bearing formation | |
| CA2889447C (en) | Cooperative multidirectional fluid injection and enhanced drainage length in thermal recovery of heavy oil | |
| US9562424B2 (en) | Waste heat recovery from depleted reservoir | |
| CA2937710A1 (en) | Vertical staging with horizontal production in heavy oil extraction |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request |
Effective date: 20230508 |