CA3043954A1 - Bitumen storage in situ - Google Patents

Abstract

Processes are provided for operating a well pair in a heavy oil reservoir to facilitate dynamic bitumen storage and production, including methods that involve the use of a solvent in the mobilizing injection fluid so as to adjust the composition of a stored emulsion. Exemplary methods involve monitoring fluid levels in the storage chamber using a variety of indicators for assessing, and managing, the level and composition of stored bitumen in situ.

Description

BITUMEN STORAGE IN SITU
FIELD
[0001] The present disclosure relates to in situ methods for recovering hydrocarbons from subterranean reservoirs. In particular, the present disclosure relates to solvent-aided methods that facilitate the dynamic storage of variable amounts of bitumen in situ.
BACKGROUND

[0002] Hydrocarbons in some subterranean deposits of viscous hydrocarbons, can be .. extracted in situ by lowering the viscosity of the hydrocarbons to mobilize them so that they can be moved to, and recovered from, a production well. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbons, heavy oil, bitumen, or oil sands. 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 and/or solvent based recovery techniques, such as injecting a heated fluid, typically steam, solvent or a combination thereof, into the reservoir from an injection well. Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are representative thermal-recovery processes that use steam to mobilize hydrocarbons in situ.
Solvent-aided processes (SAP) and solvent-driven processes (SDP) are representative thermal-recovery processes that use both steam and solvent to mobilize hydrocarbons in situ.

[0003] 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 mobilizes the in-place hydrocarbons to create a steam or production chamber in the reservoir around and above the horizontal segment of the injection and production wells.

[0004] A wide variety of alternative processes have been proposed for in situ hydrocarbon recovery aided by fluids or treatments other than steam, including a variety of process that make use of hydrocarbon solvents. Recovery processes that are aided in any way by one or more solvents are referred to herein as solvent-aided processes (SAP). In some embodiments of SAP, the injection fluid may include less than about 20 A solvent and greater than about 80%
steam on a mass basis. Such processes may be referred to as "steam-driven solvent-aided processes". In some embodiments of SAP, the injection fluid may include between about 20 %
and about 80% solvent on a mass basis. Such processes may be referred to as "hybrid solvent-assisted processes". In some SAP embodiments, the injection fluid may include greater than about 80% solvent and less than about 20% steam on a mass basis. Such processes may be referred to as "substantially solvent driven or in some cases solvent-only processes". In the present disclosure, the term "solvent driven process (SDP)" is used to refer to both hybrid solvent-assisted processes and substantially solvent-only processes.
Accordingly, the injection fluid used in a SDP typically includes greater than about 20% solvent on a mass basis, and SAP
includes processes that make use of any amount of solvent.

[0005] The terms "steam chamber" or "production chamber" accordingly refer to the volume of the reservoir which is saturated with injected fluids and from which mobilized oil has at least partially drained. Mobilized viscous hydrocarbons are typically recovered continuously through one or more production wells. The conditions of mobilizing fluid injection and of hydrocarbon production may be modulated to control the growth of the production chamber, for example to maximize oil production at the production well. There are, however, circumstances in which maximum oil production may not be the paramount commercial operational imperative.
SUMMARY

[0006] Methods are disclosed for operating a well pair in a heavy oil reservoir to facilitate dynamic bitumen storage and production. The methods optionally involve the use of a solvent in the mobilizing injection fluid, with the attendant effect of varying the composition of the stored bitumen emulsion. Methods are provided to facilitate monitoring of stored fluid levels and thereby managing the level and composition of stored bitumen. The stored bitumen is typically in the form of a reservoir of mobilized fluids within the production chamber, with the stored fluids in the form of an emulsion having a controlled and variable composition. The present processes accordingly provide for solvent aided variable emulsion bitumen ("SAVEBit") storage in situ.

[0007] In various aspects of SAVEBit storage, production and injection wells are provided for accessing the heavy oil reservoir. The production well may include a production well surface facility in fluid communication through a heel segment of the production well with a generally horizontal longitudinal production well segment within a heavy oil zone in the reservoir, at a production well level in the reservoir, the production well comprising a production well casing.
Similarly, the injection well may include an injection well surface facility in fluid communication with a generally horizontal longitudinal injection well segment within the heavy oil zone in the reservoir at an injection well level in the reservoir. The longitudinal injection well segment will generally be parallel to and vertically spaced apart above the longitudinal production well segment.

[0008] SAVEBit methods involve operating a well pair under a substantially gravity-dominated recovery process, such as a SAGD or SAP process, to form a production chamber in the heavy oil zone, the production chamber forming a bottom production zone in proximity to the horizontal longitudinal production well segment. A mobilizing injection fluid comprising a solvent may be injected into the heavy oil zone through the injection well to expand the production zone and thereby define a top of the production zone. A production fluid that includes solvent in the oleic phase of an emulsion may then be produced from the heavy oil zone, through the production well.

[0009] One or more operational parameters of the well pair may be monitored, as an indicator of fluid level in the production chamber, the operational parameters for example comprising: a heel temperature in the heel segment of the production well, a casing gas flow through the production well casing of the production well, a bottom hole pressure in the production or the injection well, and/or an oleic phase solvent measurement reflecting relative proportions of bitumen and solvent in the oleic phase of the production fluid.
The injecting and producing of injection and production fluids may be adjusted based on one or more of these operational parameters, optionally in combination with other operational parameters. In this way, the SAVEBit process allows an operator to maintain a variable reservoir of mobilized fluids in the production chamber in fluid communication with the production well, the reservoir of mobilized fluids having an upper level and a lower level. Concomitantly, the operator can maintain a production pressure in the production chamber that supports production of fluids through the production well. In addition, the operator may adjust the amount of bitumen in the reservoir of mobilized fluids between a maximum amount of stored bitumen and a minimum amount of stored bitumen. The minimum amount of stored bitumen corresponding generally to reservoir conditions wherein the relative proportion of bitumen in the production fluid is minimized and the upper level of the reservoir of mobilized fluids approaches but does not descend below the level of the production well. The maximum amount of stored bitumen corresponding to reservoir conditions wherein the relative proportion of bitumen in the production fluid is maximized and the upper level of the mobilized fluids approaches the top of the production zone, or optionally does not override the level of the injection well,.

[0010] In accordance with the foregoing approach, the well pair may for example be operated so as to achieve a very wide variety of alternative operational objectives, such as to:
increase the amount of bitumen in the reservoir of mobilized fluids; decrease the amount of bitumen in the reservoir of mobilized fluids; maintain the maximum amount of stored bitumen;
maintain the minimum amount of stored bitumen; maximize the production of bitumen; or minimize the production of bitumen.

[0011] The parameters that trigger adjustments in the SAVEBit operations may, for example, include indicators of the market price for bitumen, and/or a regulatory limit on an amount of bitumen to be produced from the heavy oil reservoir.
BRIEF DESCRIPTION OF THE DRAWINGS

[0012] FIG. 1 schematically illustrates a typical well pair in a hydrocarbon reservoir, which can be operated to implement embodiments of the presently disclosed methods for solvent aided mobilized bitumen ("SAVEBit") storage in situ.

[0013] FIG. 2 schematically illustrates aspects of the well pair of FIG.
1, contacting a hydrocarbon depleted production chamber formed within the reservoir.

[0014] FIGs. 3A and 3B illustrate exemplary process flows for SAVEBit storage processes in the context of a broader recovery process, that in FIG. 3A includes a SAGD
stage.

[0015] FIG. 4 is a line graph illustrating fluid flows in an exemplary embodiment of a SAVEBit storage process.
DETAILED DESCRIPTION

[0016] SAGD processes may be adapted for dynamic bitumen storage in situ, by modulating injection and production flows to store more or less emulsion at the bottom of the production chamber. In addition, SAGD production fluids may be stored in depleted steam chambers to capitalize on any residual heat in the depleted chamber. In both cases, however, the mobilized fluids produced by a typical SAGD process comprise a substantial proportion of condensed aqueous fluids, and as such the volume of bitumen in the stored mobilized fluids is necessarily limited.

[0017] Processes of dynamic bitumen storage involving the solvent aided mobilized bitumen (SAVEBit) storage methods disclosed herein overcome the storage capacity limitations associated with dynamic storage under SAGD conditions. The SAVEBit approach provides substantially more dynamic range in the available in situ storage capacity of a given reservoir, as solvent-aided processes produce less aqueous condensate per unit of produced fluid.

[0018] In the SAVEBit storage methods disclosed herein, the operator may adjust the amount of bitumen in the reservoir of mobilized fluids between a maximum amount of stored bitumen and a minimum amount of stored bitumen. The minimum amount of stored bitumen corresponds generally to reservoir conditions wherein the relative proportion of bitumen in the production fluid is minimized and the upper level of the reservoir of mobilized fluids approaches but does not descend below the level of the production well. The relative proportion of bitumen in the production fluid may for example be minimized by returning to a steam driven production process, thereby diluting a reservoir of relatively concentrated stored bitumen that has been generated by a SAP or SDP production process. The maximum amount of stored bitumen corresponds to reservoir conditions wherein the relative proportion of bitumen in the production fluid is maximized and the upper level of the mobilized fluids approaches the top of the production chamber. In some circumstances, operators may also elect to limit the upper level of the mobilized fluids to a level that approaches but does not override the level of the injection well. The heel or bottom hole temperature of the injection and/or production wells provides an indication of stored fluid levels, with the stored fluid in effect providing a variable degree of insulation between the well and the heated production chamber ¨ a rising temperature being an indication of falling stored fluid levels and vice versa. The amount of production well casing gas provides an indication of the relative extent of the gas phase in the production fluids, and this in turn reflects the proximity of the gas phase of the production chamber to the production well.
Increasing casing gas production accordingly correlates with falling fluid storage levels. An increasing proportion of solvent in the oleic phase of the production fluid provides an additional indication that the upper level of the mobilized fluids is approaching the injection well. The bottom hole pressures of the injection and/or production wells similarly provide an indication of stored fluid levels, with falling bottom hole pressure being an indication that the production chamber is being depressurized, for example when injected solvent short circuits to production fluids.
[001 9] In accordance with the foregoing approach, the well pair may for example be operated so as to achieve a very wide variety of alternative operational objectives, such as to:
increase the amount of bitumen in the reservoir of mobilized fluids; decrease the amount of bitumen in the reservoir of mobilized fluids; maintain the maximum amount of stored bitumen;
maintain the minimum amount of stored bitumen; maximize the production of bitumen; or minimize the production of bitumen. In some instances, the stored fluid levels may be allowed to rise towards the top of the production chamber, overriding the injection well.
This is made possible by the fact that solvent may be injected at temperatures and pressures that are well into the gas phase of the solvent, so that the solvent can move as a gas through the stored fluid into the upper portions of the production chamber (in a way that steam cannot). In such embodiments, solvent is injected into the stored fluids and then moves into the pressurized production chamber.
[0020] The parameters that trigger adjustments in the SAVEBit operations may, for example, include indicators of the market price for bitumen, and/or a regulatory limit on an amount of bitumen to be produced from the heavy oil reservoir. For example, one approach may involve reducing injection and produced emulsion flow, for example by 50-99%, thereby switching to an operational strategy of very low level "trickling" solvent-steam injection and very low level "dribble" solvent-steam-NCG production. In alternative embodiments, the accumulation of stored fluids may be monitored by a reduction in the production casing gas flow and a corresponding drop in production well temperature, such as the production heel temperature. In various embodiments, the bottom hole pressure (BHP) and/or casing gas production may be monitored, and in such circumstances when the production well is entirely flooded the mobilized fluids the casing gas flow should trend towards 0 and the production heel temperature will start to decline. If BHP substantially declines, it may be advantageous to increase solvent-steam injection to maintain conditions suitable for ongoing production, this may for example be evident by a BHP drop of 20, 30, 40 or 50 kPa over a 1 week period, for example from 3200 kPa to 3150 kPa. In some embodiments, an increase in the intermittent solvent content in the oleic phase of the production fluids may be used as an indication of solvent being injected directly into the stored fluids, in effect an indication that the stored fluid levels are approaching or overriding the injector. For example, an increase in the intermittent solvent content in the oleic phase of >5% may provide such an indicator, for example with propane in oil going from 50 mol /0 to 55 mol /0. The volume and level of stored fluids may alternatively be modeled, for example with the volume under the injection well being determined according to the following formula: V=0.5*a*c*h*p*s.
Where V-is the volume able to store emulsion under the injecting well a = height from the injecting well to the lowest point of the emulsion buildup (e.g. 5m) c = the width of steam or steam- solvent chamber developed laterally to the injector h = length of the injection well p = local porosity s = subcool coefficient [0021] 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 located above the production well elevation.
[0022] 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 1,000 kg/m3 and a viscosity greater than 10,000 centipoise (cP; or 10 Pas) 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.
[0023] 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 characterized by some distinctive property. Zones may exist in a reservoir within or across strata or fades, 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.
[0024] "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.
[0025] 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 of hydrocarbons, often by gravity drainage, into a production well.
[0026] As used herein, the term "about", in the context of a numerically definable parameter, refers to an approximately +/-10% variation from a given value. Where numerical values are recited herein and these values are necessarily an approximation, for example to a given decimal point, it is to be understood that the recital of the values imputes the exercise of approximation.
[0027] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the illustrated embodiments. It will nevertheless be understood that these illustrated embodiments exemplify rather than limit the generality of the present disclosure.
[0028] FIG. 1 schematically illustrates a typical well pair in a heavy oil hydrocarbon reservoir, which can be operated to implement embodiments of the presently disclosed methods for solvent aided mobilized bitumen ("SAVEBit") storage in situ. A wide variety of alternative configurations of injection and production wells may be adapted for alternative implementations of SAVEBit storage processes, for example involving production wells that are infill wells, which may in turn be wedgewells, and where steam or production chambers served by particular injection and/or production wells are distinct or have merged.
[0029] As illustrated, a reservoir 100 containing heavy hydrocarbons is below an overburden 110, which may also be referred to as a cap layer or cap rock. The overburden 110 may be formed of a layer of impermeable material such as clay or shale. A
region in the reservoir 100 just below and near the overburden 110 may be considered as an interface region 115. Under natural conditions (e.g. prior to the application of a recovery process), the reservoir 100 is at a relatively low temperature, such as about 12 C, and the formation pressure may be from about 0.1 to about 4 MPa (1 MPa = 1,000 Pa), depending on the location and other characteristics of the reservoir. A pair of SAGD wells, including an injection well 120 and a production well 130, are drilled into and extend substantially horizontally in the reservoir 100 for producing hydrocarbons from the reservoir 100. The well pair is typically positioned away from the top of the reservoir 100 which, as depicted in FIG. 1, is defined by the lower edge of the overburden 110, and positioned near the bottom of a pay zone or geological stratum in the reservoir 100.
[0030] As is typical of such SAGD configurations, the injection well 120 may be vertically spaced from the production well 130, such as at a distance of about 5 m. The distance between the injection well 120 and the production well 130 in a SAGD well pair may vary and may be selected to optimize the SAGD operation performance, or to optimize anticipated SAVEBit storage operations. In this context, the inter-well distance represents a parameter relevant the volume of stored mobilized bitumen, so that a larger inter-well spacing may be implemented to maximize SAVEBit storage capacity within the inter-well space.
[0031] In select embodiments, the horizontal sections of the injection well 120 and the production well 130 may have be about 800-1000 m in length. In other embodiments, these lengths may be varied and the overall pattern of well pairs may vary widely.
The injection well 120 and the production well 130 may each be configured and completed according to a wide variety of suitable techniques available in the art. The injection well 120 and the production well 130 may also be referred to as the "injector" and "producer", respectively.
[0032] As illustrated, the injection well 120 and the production well 130 are connected to respective corresponding surface facilities, which typically include an injection surface facility 140 and a production surface facility 150. The injection surface facility 140 is configured and operated to supply injection fluids, such as steam, solvent or combinations thereof into the injection well 120. The production surface facility 150 is configured and operated to produce fluids collected in the production well 130 to the surface. Each of the injection surface facility140 and the production surface facility150 includes one or more fluid pipes or tubing for fluid communication with their respective wells. As depicted for illustration, surface facility 140 may have a supply line connected to a steam generation plant for supplying steam for injection and a supply connected to a solvent source for supplying the solvent for injection.
Optionally, one or more additional supply lines may be provided for supplying other fluids, additives or the like for co-injection with the steam, the solvent or combinations thereof. Each supply line may be connected to an appropriate source of supply, which may include, for example, a steam generation plant, a boiler, a fluid mixing plant, a fluid treatment plant, a truck, or a fluid tank. In select embodiments, co-injected fluids or materials may be pre-mixed before injection. In other embodiments, co-injected fluids may be separately supplied into the injection well 120. In particular, the injection surface facility 140 may be used to supply steam into the injection well 120 in a first phase, and a mixture of steam and solvent into the injection well 120 in a second phase. In the second phase, the solvent may be pre-mixed with steam at surface before co-injection. Alternatively, the solvent and steam may be separately fed into the injection well 120 for injection into the reservoir 100. Optionally, the injection surface facility 140 may include a heating facility (not separately shown) for pre-heating the solvent before injection.
[0033] As illustrated, the production surface facility 150 includes a fluid transport pipeline for conveying produced fluids to a downstream facility (not shown) for processing or treatment. The production surface facility 150 includes equipment for producing fluids from the production well 130. Other surface facilities 160 may also be provided, for example the surface facilities 160 may include one or more of a pre-injection treatment facility for treating a material to be injected into the formation, a post-production treatment facility for treating a produced material, a control or data processing system for controlling the production operation or for processing collected operational data.
[0034] FIG. 2 is a schematic perspective view of the injection well 120 and the production well 130 in the reservoir 100 during a recovery process where a vapor or production chamber has formed. As illustrated, the injection well 120 has an injector casing 220 and the production well 130 has a production casing 230. An injector tubing 225 is positioned in the injector casing 220. For schematic simplicity, other necessary or optional components, tools or equipment that are installed in the injection well 120 and the production well 130 are not shown in the drawings.
[0035] As depicted in FIG. 2, the injector casing 220 includes a slotted liner along the horizontal section of well 120 for injecting fluids into the reservoir 100.
Production casing 230 is also completed with a slotted liner along the horizontal section of well 130 for collecting fluids drained from the reservoir 100 by gravity (i.e. in a gravity-dominated process). In select embodiments, the production well 130 may be configured and completed similarly to the injection well 120. In select embodiments, each of the injection well 120 and the production well 130 may be configured and completed for both injection and production, which can be useful in some applications as can be understood by those skilled in the art.
[0036] FIGs. 3A and 3B illustrate exemplary process flows for aspects of SAVEBit storage in the context of a broader recovery process. At S300, the reservoir 100 is subjected to an initial phase, for example as part of a SAGD process, referred to as the "start-up"
phase or stage.
Typically, start-up involves establishing fluid communication between the injection well 120 and the production well 130. To permit drainage of mobilized hydrocarbons and condensate to the production well 130, fluid communication between the injection well 120 and the production well 130 must be established. Fluid communication in this context refers to fluid flow between the injection and production wells. Establishment of such fluid communication typically involves mobilizing viscous hydrocarbons in the reservoir to form a mobilized reservoir fluid and removing the mobilized reservoir fluid to create a porous pathway between the wells. Viscous hydrocarbons may be mobilized by heating such as by injecting or circulating pressurized steam or hot water through the injection well 120 or the production well 130. In some cases, steam may be injected into, or circulated in, both the injection well 120 and the production well 130 for faster start-up. A pressure differential may be applied between the injection well 120 and the production well 130 to promote steam/hot water penetration into the porous geological formation that lies between the wells of the well pair. The pressure differential promotes fluid flow and convective heat transfer to facilitate communication between the wells.
[0037] Additionally or alternatively, other techniques may be employed during the start-up stage S300. For example, to facilitate fluid communication, a solvent may be injected into the reservoir region around and between the injection well 120 and the production well 130. The region may be soaked with a solvent before or after steam injection. An example of start-up using solvent injection is disclosed in CA 2,698,898. In further examples, the start-up phase S300 may include one or more start-up processes or techniques disclosed in CA
2,886,934, CA
2,757,125, or CA 2,831,928.
[0038] Once fluid communication between the injection well 120 and the production well 130 has been achieved, oil production or recovery may commence during stage S305.
As the oil production rate is typically low initially and will increase as the production/vapor chamber develops, this early production phase is known as the "ramp-up" phase or stage. During the ramp-up stage S305, steam is typically injected continuously into injection well 120, at constant or varying injection pressure and temperature. At the same time, mobilized heavy hydrocarbons and aqueous condensate are continuously removed from the production well 130, typically in the form of an emulsion having oleic and aqueous phases. During the ramp-up stage S305, the zone of communication between the injection well 120 and the production well 130 may continue to expand axially along the full length of the horizontal portions thereof. In alternative aspects of the SAVEBit storage process, these operations may be conducted so as to maximize the available inter-well volume available for bitumen storage.

[0039] As injected steam heats up the reservoir 100, heavy hydrocarbons in the heated region are softened, resulting in reduced viscosity. Further, as heat is transferred from steam to the reservoir 100, steam condenses. The aqueous condensate and mobilized hydrocarbons will drain downward due to gravity, in a gravity-dominated process. As a result of depletion of the .. heavy hydrocarbons, a porous region 260 is formed in the reservoir 100, which is referred to as a vapor or production chamber. When the void space in a production chamber is filled with mainly steam, it is commonly referred to as a "steam chamber." The aqueous condensate and hydrocarbons drained towards the production well 130 and collected in the production well 130 are then produced (transferred to the surface, typically as an oil in water emulsion), such as by .. gas lifting or through pumping as is known to those skilled in the art.
[0040] As alluded to above, the production chamber 260 is formed and expands due to depletion of hydrocarbons and other in situ materials from regions of the reservoir 100 above the injection well 120. Injected steam tends to rise up to reach the top of the vapor chamber 260 before it condenses, and steam can also spread laterally as it travels upward.
Therefore, during early stages of chamber development, the vapor chamber 260 expands upwardly and laterally from the injection well 120. During the ramp-up stage S305, vapor chamber 260 can grow vertically towards the overburden 110.
[0041] Depending on the size of the reservoir 100 (and the pay therein) and the distance between the injection well 120 and the overburden 110, it can take a long time, such as many months and up to two years, for the vapor chamber 260 to reach the overburden 110 especially when the pay zone is relative thick as is typically found in some operating oil sands reservoirs.
However, in a thinner pay zone the vapor chamber 260 can reach the overburden 110 sooner.
The time to reach the vertical expansion limit can also be longer in cases where the pay zone is higher or highly heterogeneous, or the reservoir 100 has complex overburden geologies such as with inclined heterolithic stratification, top water, top gas, or other stratigraphic complexities.
[0042] In the next stage, the reservoir 100 may be subject to a conventional SAGD
production process S310, where the oil production rate is sufficiently high for economic recovery of hydrocarbons and the cumulative steam oil ratio (CSOR) continues to decrease or remain relatively stable. During the conventional SAGD production process S310 (or a similar but modified steam-driven recovery process), one or more chemical additives may be added to steam or co-injected with steam to enhance hydrocarbon recovery. For example, a surfactant, which lowers the surface tension of a liquid, the interfacial tension (IFT) between two liquids, or the IFT between a liquid and a solid, may be added. The surfactant may act, for example, as a detergent, a wetting agent, an emulsifier, a foaming agent, or a dispersant to facilitate the drainage of the softened hydrocarbons to the production well 130. An organic solvent, such as an alkane or alkene, may also be added to dilute the mobilized hydrocarbons so as to increase the mobility and flow of the diluted hydrocarbon fluid to the production well 130 for improved recovery. Other materials in liquid or gas form may also be added to enhance recovery performance.
[0043] The start-up stage S300, the ramp-up stage S305, and the SAGD
production process stage S310 described above are non-limiting examples, and there are numerous conventional and innovative techniques known to those skilled in the art that result in the formation of a production chamber. In alternative embodiments, rather than using a well pair, one or more single horizontal or vertical wells may be used for providing a production chamber.
For example, CA 2,844,345 discloses a process that provides a production chamber using a single vertical or inclined well. The process may be preceded by start-up acceleration techniques to establish communication in the formation between an injection means and a production means within the single well.
[0044] When the vapor chamber 260 grows vertically, oil production rates normally continue to increase, and the CSOR normally continues to decrease. Steam utilization during such chamber growth is relatively efficient. However, when the top front of the vapor chamber 260 approaches or reaches the overburden 110 or the transition region 115, vertical growth of the vapor chamber 260 will slow down and eventually stop. While the vapor chamber 260 may continue to grow or expand laterally, which may be at a slower pace, steam utilization during slow lateral growth may be less efficient. As a result, oil production rate may reach a peak value or plateau, and then start to decline. The CSOR may bottom out and start to increase. Thus, such changes in chamber growth, oil production rate and CSOR may be used as a production threshold for transitioning from the steam-driven process to a solvent-aided process (SAP), such as a solvent-driven process (SDP).
[0045] SAGD processes may be adapted for variable dynamic bitumen storage in situ, by modulating injection and production flows to store more or less emulsion at the bottom of the production chamber. In addition, oil may advantageously be stored in depleted steam chambers, thereby capitalizing on any residual heat ion the depleted chamber.
However, the mobilized fluids produced by a typical SAGD process comprise a substantial proportion of condensed aqueous fluids, so that the volume of bitumen in the stored mobilized fluids is necessarily limited. Processes of dynamic bitumen storage involving SAGD
operations may accordingly proceed or alternate with the solvent aided mobilized bitumen (SAVEBit) storage methods disclosed herein, with the SAVEBit approach providing substantially more dynamic range in the available in situ storage capacity in a given reservoir.
[0046] To initiate conditions suitable for SAVEBit storage operations, at S315 a suitable solvent and transition condition are selected (according to various factors and considerations for example as set out in CA 2,956,771) at S320 and S325 respectively. As can be appreciated by those skilled in the art, the selection at S320 and S325 may be performed at any time prior to solvent injection, and may be performed in any order depending on the particular situation and application.
[0047] At S320, the solvent for use in the SAP or SDP is selected or determined based on a number of considerations and factors, for example as set out in CA2,956,771.
The solvent may be injectable as a vapor, and may be selected on the basis of being suitable for dissolving at least one of the heavy hydrocarbons to be recovered from the reservoir 100.
The solvent may be a viscosity-reducing solvent, which reduces the viscosity of the heavy hydrocarbons in the reservoir 100. Suitable solvents may include C2 to Clo linear, branched, or cyclic alkanes, alkenes, or alkynes, in substituted or unsubstituted form, or other aliphatic or aromatic compounds. Select embodiments may for example use an n-alkane as the dominant solvent, for example propane, butane, pentane or mixtures thereof. For a given selected solvent, the corresponding operating parameters during co-injection of the solvent with steam may also be selected or determined in view the properties and characteristics of the selected solvent. The mass fraction of the solvent may for example be greater than 20% and enough steam may be added to ensure that the injected solvent is substantially in the vapor phase.
In a given application, the solvent may be selected based on its volatility and solubility in the reservoir fluid.
[0048] Transitioning to the SAP or SDP process at an early stage in a SAGD process may be possible in some cases, but such early transition before the vapor chamber has fully developed vertically may limit the overall chamber growth or slow down the initial chamber growth. Further, when the transition occurs too early, the reservoir formation generally contains less heat transferred from steam and the heated region in the formation may be relatively small.
In some embodiments, when the vapor chamber is fully developed vertically, the amount of heat transferred to the reservoir formation and the large region of heated area can be quite beneficial to the subsequent solvent-driven process. The heat, or higher formation temperature in a large region in the formation, can help to maintain the solvent in the vapor phase and assist dispersion of the solvent to the chamber front or edges. The heat from steam can also by itself assist reduction of viscosity of the hydrocarbons.

[0049] At S330, it is determined whether the transition condition selected at S325 has been met. This determination may be made based on a pre-set timing or based on measured and predicted operational parameters and current reservoir conditions. The determination may involve monitoring certain selected parameters, for example, monitoring of injection, production, downhole parameters, or parameters of the geological formation. For example, parameters such as CSOR, temperatures, pressures, or the like may be monitored. Such parameters may be measured at, for example, the injection well 120 and/or the production well 130. Additionally or alternatively, determining when a transition condition has been met may involve prediction based on indirect indicators that the condition has been met, such as based on assumptions derived from a model and informed by the aforementioned monitoring. In select embodiments, the determination may involve a consideration of the prospective timing of future SAVEBit storage operations, for example an indication that increased bitumen storage may be desirable in the future may give rise to a determination that solvent use should begin, in order to set the stage for future SAVEBit storage operations.
[0050] When the transition condition has been met, the initial production process, such as a steam-driven SAGD process, S310 is terminated and process amenable to modulating storage of bitumen is initiated, such as a SAP or SDP process, at S335. When the storage-driven process is a solvent-driven process, S335, injection of the selected solvent into the reservoir 100 is initiated through the injection well 120. The solvent is generally injected into the reservoir .. 100 in a vapor phase. Injection of the solvent in the vapor phase allows solvent vapor to rise in the vapor chamber 260 and condense at a region away from the injection well 120. Allowing solvent to rise in the vapor chamber 260 before condensing may achieve beneficial effects. For example, when solvent vapor is delivered to the vapor chamber 260 and then allowed to condense and disperse near the edges of the vapor chamber 260, oil production performance, such as indicated by one or more of oil production rate, cumulative steam to oil ratio (CSOR), and overall efficiency, may be improved. Injection of solvent in the gaseous phase, rather than a liquid phase, may allow vapor to rise in the vapor chamber 260 before condensing so that condensation occurs away from the injection well 120. It is noted that injecting solvent vapor into the vapor chamber does not necessarily require solvent be fed into the injection well 120 in vapor form. For example, the solvent may be heated downhole and vaporized in the injection well 120.
[0051] The total injection pressure for solvent and steam co-injection during stage S335 may be the same or different than the injection pressure during the SAGD
production stage S310. For example, the injection pressure may be maintained at between 2 MPa and 3.5 MPa, or up to 4 MPa. Alternatively, steam may be injected at a pressure of about 3 MPa in the SAGD
process S310, while steam and solvent are co-injected at a pressure of about 2 MPa to about 3.5 MPa in the SAP or SDP process S335.
[0052] In S335, the solvent may be heated to vaporize the solvent. For example, when the solvent is propane, it may be heated with hot water at a selected temperature such as, for example, about 100 C. Additionally or alternatively, solvent may be mixed or co-injected with steam to heat the solvent to vaporize it and to maintain the solvent in vapor phase. Depending on whether the solvent is pre-heated at surface, the weight ratio of steam in the injection stream should be high enough to provide sufficient heat to the co-injected solvent to maintain the injected solvent in the vapor phase. If the feed solvent from surface is in the liquid phase, more steam may be required to both vaporize the solvent and maintain the solvent in the vapor phase as the solvent travels through the vapor chamber 260. For example, where the selected solvent is propane, a solvent-steam mixture containing about 90 % propane and about 10 % steam on a mass basis may be injected at a suitable temperature, such as about 75 C to about 100 C.
Such a suitable steam temperature may be determined, for example, through techniques as known to persons of skill in the art based on parameters of the mixture components. For example, the enthalpy per unit mass of the aforementioned steam-propane mixture may be about 557 kJ/kg.
[0053] The total volume of the solvent injected during the SAP or SDP
process S335 may be lower than the total volume of steam injected during SAGD. In S335, co-injection of steam and the solvent may be carried out in a number of different ways. For example, co-injection of the solvent and steam into the vapor chamber may include gradually increasing the weight ratio of the solvent in the co-injected solvent and steam, and gradually decreasing the weight ratio of steam in the co-injected solvent and steam. At a later time within S335, the solvent content in the co-injected solvent and steam may be gradually decreased, and the steam content in the co-injected solvent and steam may be gradually increased. For example, depending on market factors, the cost of solvent may change over the life of such a process.
During or after the solvent-driven process S335, it may be of economic benefit to gradually decrease the solvent content and gradually increase the steam content.
[0054] In the context of the present disclosure, at various times, the produced-fluid stream may have an oil:water ratio of between about 20:80 and about 90:10, or any ratio between these values. In a SAGD phase, this ratio may for example be from about 20:80 to about 35:65.
Following the initiation of solvent use, in a SAP phase, this ratio may for example be from about 60:40 to about 90:10, or for example alternatively about 75:25 to about 90:10, depending on the amount of solvent injected.
[0055] The initiation of solvent use gives rise to a surprising bitumen-concentrating effect in the mobilized fluid zone at the bottom of the production chamber. As illustrated in FIG. 4, during an exemplary SAGD operation, the initial drainage of the overall emulsion (mainly condensed steam and bitumen) was at about 350-500 T/d. Following the initiation of solvent use, when moving from a steam driven phase to a solvent driven phase, a gradual but significant reduction in the water cut (WC) in the produced fluids was evident, falling over time from about 80% to 25%. After approximately 1 year of operating the SDP, the emulsion rate was at the range of 75-100 m3/d with a bitumen production rate of about 50-75 m3/d. These daily production figures are similarly reflected in hourly production figures, where the overall emulsion production rate was reduced from 20 m3/hr to about 4 m3/hr, with a surprisingly small decline in the oil production rate. As a result of this effect, with significantly less emulsion being drained to maintain a variable reservoir of mobilized fluids at the bottom of the production chamber, a SAVEBit storage process may be implemented to store a variable amount of bitumen in situ, with the corollary of enabling a wider dynamic range of production rates (in comparison to a SAGD
process). In contrast, in a typical SAGD operation, when fluid production rates are reduced, within a relatively short period of time the limit of bitumen storage is reached as the mobilized fluid level rises towards the level of the injection, with the attendant risk of quickly flooding the injector. In a SAVEBit storage process, operations may for example be carried out with the production of dramatically less fluid, for example multiples of 2, 3, 4 or 5 times less production fluid. The concentration of the bitumen in the mobilized fluid thereby facilitates much larger storage volumes of bitumen, for example greater than 2, 3, 4 or 5 times the bitumen that could be stored in a SAGD process.
[0056] An attendant advantage of the SAVEBit storage process is the ability to maintain production pressures within the production chamber. In a typical SAGD
operation, it is necessary to continue pressurizing the reservoir with relatively high steam rates. In contrast, in a SAVEBit storage process, it is possible to maintain bottom hole pressure (BHP) with relatively low solvent + steam injection rates, and the attendant minimal water drainage within the produced emulsion.
[0057] An aspect of SAVEBit processes includes the ability to modulate the bitumen concentration of the stored mobilized fluids. As discussed above, transitioning from a steam driven process such as SAGD to a SAP or SDP process has a bitumen-concentrating effect on the composition of the stored mobilized fluids, as the relative amount of water in the emulsion falls. Conversely, following a period SAP or SDP production, operations may transition to a steam driven process such as SAGD to dilute the stored mobilized fluids with water, for example to minimize the amount of stored bitumen.
[0058] As illustrated in FIG. 4, in the summer of 2018 an operational shut-in period was .. initiated, and this was followed by a period of "flush" production and then a return to previous production rates by mid-September. The 30 day moving average oil production shows SAGD-like oil production rates. SAVEBit storage processes accordingly accommodate shut-in and flush production operations that modulate bitumen production dramatically, while maintaining overall oil production capacity (as evident from the area under the curve in FIG. 4). The operational parameter that acts as a trigger for the overall SAVEBit storage operational strategy may for example be market pricing for oil or regulatory restrictions on bitumen production.
[0059] 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. Terms such as "exemplary" or "exemplified" are used herein to mean "serving as an example, instance, or illustration." Any implementation described herein as "exemplary" or "exemplified" is accordingly not to be construed as necessarily preferred or advantageous over other implementations, all such implementations being .. independent embodiments. Unless otherwise stated, numeric ranges are inclusive of the numbers defining the range, and numbers are necessarily approximations to the given decimal.
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, and all documents cited in such documents and publications, are hereby 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.

Claims (20)

1. A
method of operating a well pair in a heavy oil reservoir to facilitate dynamic bitumen storage and production, wherein the well pair comprises:
a production well accessing the heavy oil reservoir, comprising a production well surface facility in fluid communication through a heel segment of the production well with a generally horizontal longitudinal production well segment within a heavy oil zone in the reservoir at a production well level in the reservoir, the production well comprising a production well casing; and, an injection well accessing the heavy oil reservoir comprising an injection well surface facility in fluid communication through a heel segment of the injection well with a generally horizontal longitudinal injection well segment within the heavy oil zone in the reservoir at an injection well level in the reservoir, the longitudinal injection well segment being generally parallel to and vertically spaced apart above the longitudinal production well segment;
wherein the method comprises:
operating the well pair under a substantially gravity-dominated recovery process to form a production chamber in the heavy oil zone, the production chamber forming a bottom production zone in proximity to the horizontal longitudinal production well segment;
injecting a mobilizing injection fluid comprising a solvent into the heavy oil zone through the injection well to expand the production zone and thereby define a top of the production zone;
producing a production fluid comprising the solvent in an oleic phase of an emulsion from the heavy oil zone through the production well; and, monitoring one or more operational parameters of the well pair as an indicator of fluid level in the production chamber, and adjusting the injecting and producing of injection and production fluids based on the operational parameters, so as to:
maintain a variable reservoir of mobilized fluids in the production chamber in fluid communication with the production well, the reservoir of mobilized fluids having an upper level and a lower level;
maintain a production pressure in the production chamber that supports production of fluids through the production well; and, adjust the amount of bitumen in the reservoir of mobilized fluids between a maximum amount of stored bitumen and a minimum amount of stored bitumen, the minimum amount of stored bitumen corresponding to reservoir conditions wherein the relative proportion of bitumen in the production fluids is minimized and the upper level of the reservoir of mobilized fluids approaches but does not descend below the level of the production well, the maximum amount of stored bitumen corresponding to reservoir conditions wherein the relative proportion of bitumen in the production fluid is maximized and the upper level of the mobilized fluids approaches the top of the production zone.

2. The method of claim 1, wherein the operational parameter of the well pair that is an indicator of fluid level in the production chamber comprises: a production heel temperature in the heel segment of the production well, an injection heel temperature in the heel segment of the injection well, a bottom hole temperature in the injection or production well, a casing gas flow through the production well casing of the production well, a bottom hole pressure in the production or the injection well, and/or an oleic phase solvent measurement reflecting the relative proportions of bitumen and solvent in the oleic phase of the production fluid.

3. The method of claim 1 or 2, comprising operating the well pair so as to increase the amount of bitumen in the reservoir of mobilized fluids.

4. The method of claim 1 or 2, comprising operating the well pair so as to decrease the amount of bitumen in the reservoir of mobilized fluids.

5. The method of claim 1 or 2, comprising operating the well pair so as to maintain the maximum amount of stored bitumen.

6. The method of claim 1 or 2, comprising operating the well pair so as to maintain the minimum amount of stored bitumen.

7. The method of claim 1 or 2, comprising operating the well pair so as to maximize the production of bitumen.

8. The method of claim 1 or 2, comprising operating the well pair so as to minimize the production of bitumen.

9. The method of any one of claims 1 to 8, wherein the operational parameters comprise an indicator of a market price for bitumen in the production fluid.

10. The method of any one of claims 1 to 9, wherein the operational parameters comprise a regulatory limit on an amount of bitumen to be produced from the heavy oil reservoir.

11. The method of any one of claims 1 to 10, comprising monitoring the bottom-hole pressure at the production well.

12. The method of any one of claims 1 to 11, wherein the substantially gravity-dominated recovery process is a SAP or a SAGD process.

13. The method of any one of claims 1 to 12, wherein the solvent comprises C2 to C10 linear, branched, or cyclic alkanes, alkenes, or alkynes, substituted or unsubstituted.

14. The method of claim 13, wherein the solvent predominantly comprises one or more n-alkane.

15. The method of claim 14, wherein the n-alkane is propane, butane or pentane.

16. The method of any one of claims 1 to 15, wherein the injection fluid comprises steam and solvent, and the solvent comprises at least 20, 30, 40, 50, 60, 70, 80 or 90 wt% of the injection fluid.

17. The method of any one of claims 1 to 16, wherein the proportion of solvent in the injection fluid is increased so as to increase the proportion of bitumen in the reservoir of mobilized fluid.

18. The method of any one of claims 1 to 17, further comprising operating two or more well pairs in the heavy oil reservoir, coordinating coincident bitumen storage or production by the well pairs, thereby increasing either total bitumen storage or total bitumen production from the heavy oil reservoir.

19. The method of any one of claims 1 to 18, wherein the step of adjusting the injecting and producing of injection and production fluids so as to adjust the amount of bitumen in the reservoir of mobilized fluids comprises, increasing the amount of steam in the injection fluids so as to dilute the reservoir of stored fluids with water and thereby reduce the relative proportion of bitumen in the production fluids.

20. A method of operating a well pair in a heavy oil reservoir to facilitate dynamic bitumen storage and production, wherein the well pair comprises:
a production well accessing the heavy oil reservoir, comprising a production well surface facility in fluid communication through a heel segment of the production well with a generally horizontal longitudinal production well segment within a heavy oil zone in the reservoir at a production well level in the reservoir, the production well comprising a production well casing; and, an injection well accessing the heavy oil reservoir comprising an injection well surface facility in fluid communication through a heel segment of the injection well with a generally horizontal longitudinal injection well segment within the heavy oil zone in the reservoir at an injection well level in the reservoir, the longitudinal injection well segment being generally parallel to and vertically spaced apart above the longitudinal production well segment;
wherein the method comprises:

operating the well pair under a substantially gravity-dominated recovery process to form a production chamber in the heavy oil zone, the production chamber forming a bottom production zone in proximity to the horizontal longitudinal production well segment;
injecting a mobilizing injection fluid into the heavy oil zone through the injection well to expand the production zone and thereby define a top of the production zone;
producing a production fluid as an emulsion from the heavy oil zone through the production well; and, monitoring one or more operational parameters of the well pair as an indicator of fluid level in the production chamber, and adjusting the injecting and producing of injection and production fluids based on the operational parameters, so as to:
maintain a variable reservoir of mobilized fluids in the production chamber in fluid communication with the production well, the reservoir of mobilized fluids having an upper level and a lower level;
maintain a production pressure in the production chamber that supports production of fluids through the production well; and, adjust the amount of bitumen in the reservoir of mobilized fluids between a maximum amount of stored bitumen and a minimum amount of stored bitumen, the minimum amount of stored bitumen corresponding to reservoir conditions wherein the relative proportion of bitumen in the production fluids is minimized and the upper level of the reservoir of mobilized fluids approaches but does not descend below the level of the production well, the maximum amount of stored bitumen corresponding to reservoir conditions wherein the relative proportion of bitumen in the production fluid is maximized and the upper level of the mobilized fluids approaches the top of the production zone.