CA3008545A1

CA3008545A1 - Heavy oil solvent recovery processes using artificially injected composite barriers

Info

Publication number: CA3008545A1
Application number: CA3008545A
Authority: CA
Inventors: Amos Ben-Zvi; Brent Donald Seib; Harbir Singh Chhina
Original assignee: Cenovus Energy Inc
Current assignee: Cenovus Energy Inc
Priority date: 2017-06-27
Filing date: 2018-06-15
Publication date: 2018-12-27

Abstract

Processes are provided that involve the production of hydrocarbons using a buoyant solvent, from a reservoir compartment that has been sealed from a thief zone with an artificial composite seal made up of an injected blocking agent cooperating with an adjacent bitumen layer. The buoyant solvent may for example be a light hydrocarbon solvent.

Description

HEAVY OIL SOLVENT RECOVERY PROCESSES USING ARTIFICIALLY INJECTED
COMPOSITE BARRIERS
FIELD OF THE INVENTION
[0001] The invention is in the field of hydrocarbon reservoir engineering, particularly recovery processes that make use of solvents in heavy oil reservoirs.
BACKGROUND OF THE INVENTION

[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 hydrocarbon, heavy oil, bitumen, oil sands, or (previously) tar 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), involving a horizontal well pair to facilitate steam injection and oil production.

[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. The geology of this region is emblematic of the geological complexities associated with many heavy oil bearing formations. In general terms, 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, and includes zones disposed towards the top or bottom of heavy oil deposits that have distinct fluid mobility characteristics. These zones include, for example, top water zones, bottom water zones, gas caps (including top gas zones that have been produced, and therefore have reduced pressure), neighbouring chambers depleted of oil, and lower permeability fades that present significant vertical and/or horizontal fluid flow barriers.
Collectively these zones may be called "lean" or "thief' zones, reflecting the effect of these zones on hydrocarbon recovery processes that use an injected fluid to improve mobility of the oil. In some cases, more than one such secondary zone may be present.

[0004] Atypical 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 chamber" in the reservoir around and above the horizontal segment of the 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 and to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.

[0005] A wide variety of alternative enhanced or in-situ recovery processes may be used that employ thermal and non-thermal components to mobilize oil. For example, a wide variety of processes have been described that use hydrocarbon solvents in addition to steam, or in place of steam, in processes analogous to conventional SAGD, or in processes that are alternatives to SAGD. For example, Canadian Patent No.
2,299,790 describes methods for stimulating heavy oil production using a propane vapor. Canadian Patent No. 2,323,029 describes an in situ recovery process involving injection of steam and a non-aqueous solvent. Unheated hydrocarbon vapours have been proposed for use to dissolve and displace heavy oils in a process known as VAPEX (Butler and Mokrys, J. Can. Petro. Tech. 1991, 30; U.S. Pat. No.
5,407,009).
VAPEX, warm VAPEX and hybrid VAPEX approaches have been addressed in a technology brief (James, L. A., et al. J. Can. Petro. Tech., Vol. 47, No. 4, pp. 1-7, 2008).
Processes for cyclic steam stimulation of vertical wells using hydrocarbon solvents have been described (Leaute and Carey, J. Can. Petro. Tech., Vol. 46, No. 9, pp. 22-30, 2007). Field trials have also been reported for solvent assisted processes that involve the use of solvent, such as butane, as an addition or aid to injected steam in improving the performance of conventional SAGD (Gupta et al., Paper 2001-126, Can. Intl.
Pet.
Conf., Calgary, Alberta, June 12-14, 2001; Gupta et al., Paper No. 2002-299, Can. Intl.
Pet. Conf., Calgary, Alberta, June 11-13, 2002; Gupta and Gittins, Paper No.
2005-190, Can. Intl. Pet. Conf., Calgary, Alberta, June 7-9, 2005). Solvent assisted processes characterized as Liquid Assisted Steam Enhanced Recovery (LASER) have been described, in which solvents are used in conjunction with steam to enhance performance of Cyclic Steam Stimulation (CSS).

[0006] The complexities associated with heavy oil recovery processes involving solvents are considerable, as for example, illustrated by Canadian Patent Application No. 2,660,227, which describes numerical simulations of alternative solvent processes.
Numerical studies have suggested that simple addition of propane to steam may be ineffective, with the propane failing to condense and thereby acting as a noncondensable gas (Zhao, SPE 86957 presented at the SPE International Thermal Operations and Heavy Oil Symposium, Bakersfield, California, 2004). Further complications may be introduced in methods that involve varying solvent compositions over time (Gupta and Gittins, J. Can. Petro. Tech. September 2007, Vol. 46, No 9; and, Canadian Patent No. 2,462,359). These considerable solvent flow complexities are further exacerbated by geological features such as lean zones or thief zones towards the top or bottom of the reservoir, which provide avenues for solvent to dissipate away from a recovery zone, or otherwise impede the effective flow of solvents and mobilized hydrocarbons.

[0007] In the context of the present application, various terms are used in accordance with what is understood to be the ordinary meaning of those terms.
For example, "petroleum" is a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid or solid phase. In the context of the present application, the words "petroleum" and "hydrocarbon" are used to refer to mixtures of widely varying composition. The production of petroleum from a reservoir necessarily involves the production of hydrocarbons, but is not limited to hydrocarbon production and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu, V).
Similarly, processes that produce hydrocarbons from a well will generally also produce petroleum fluids that are not hydrocarbons. In accordance with this usage, a process for producing petroleum or hydrocarbons is not necessarily a process that produces exclusively petroleum or hydrocarbons, respectively. "Fluids", such as petroleum fluids, include both liquids and gases. Natural gas is the portion of petroleum that exists either in the gaseous phase or in solution in crude oil in natural underground reservoirs, and which is gaseous at atmospheric conditions of pressure and temperature. Natural gas may include amounts of non-hydrocarbons. The abbreviation POIP stands for "producible oil in place" and in the context of the methods disclosed herein is generally defined as the exploitable or producible oil structurally located above the production well elevation.

[0008] 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 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.

[0009] A "reservoir" is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock. An "oil sand" or "oil sands" reservoir is generally comprised of strata of sand or sandstone containing petroleum. A "zone" in a reservoir is an arbitrarily defined volume of the reservoir, typically characterised by some distinctive property.
Zones may exist in a reservoir within or across strata or facies, and may extend into adjoining strata or facies. In some cases, reservoirs containing zones having a preponderance of heavy oil are associated with zones containing a preponderance of natural gas. This "associated gas" is gas that is in pressure communication with the heavy oil within the reservoir, either directly or indirectly, for example through a connecting water zone. A pay zone is a reservoir volume having hydrocarbons that can be recovered economically.

[0010] "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.

[0011] A "chamber" within a reservoir or formation is a region that is in fluid/pressure communication with a particular well or wells, such as an injection or production well.
For example, in a SAGD process, a steam chamber is the region of the reservoir in fluid communication with a steam injection well, which is also the region that is subject to depletion, primarily by gravity drainage, into a production well.

[0012] "Reservoir compartmentalization" is a term used to describe the segregation of a petroleum accumulation into a number of distinct fluid/pressure compartments. In general, this segregation takes place when fluid flow is prevented across sealed boundaries in the reservoir. These boundaries may for example be caused by a variety of geological and fluid dynamic factors, involving: static seals that are completely sealed and capable of withholding (trapping) petroleum deposits, or other fluids, over geological time; and dynamic seals that are low to very low permeability flow barriers that significantly reduce fluid cross-flow to rates that are sufficiently slow to cause the segregated chambers to have independent fluid pressure dynamics, although fluids and pressures may equilibrate across a dynamic seal over geological time-scales (Reservoir compartmentalization: an introduction, Jolley et al., Geological Society, London, Special Publications 2010, v. 347, p. 1-8). A reservoir compartment may be hydraulically confined, so that fluids are prevented from moving beyond the compartment by sealed boundaries confining the compartment.

SUMMARY OF THE INVENTION

[0013] The present disclosure involves the production of hydrocarbons, using a buoyant solvent, from a reservoir compartment that has been sealed with an artificial composite seal, the artificial composite seal being formed by the combined effect of an injected blocking agent and in-situ bitumen, so that the barrier is a functional composite of blocking agent and bitumen. The buoyant solvent may for example be a light hydrocarbon solvent, and is selected on the basis that it is miscible with, and capable of enhancing the mobility of, the reservoir hydrocarbons. As such, the solvent is deployed as a mobilizing fluid, comprising for example one or more C3 through C10 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, for example n-propane or n-butane. The mobilizing fluid comprising the buoyant solvent may be injected at a relatively low temperature, for example at or below 140 C.
The use of relatively low mobilization temperatures is advantageous because it reduces the need for thermal resiliency in the barrier, thereby facilitating the composite seal that is necessary to contain the relatively buoyant solvent.

[0014] In select embodiments, processes are provided for mobilizing fluids in a subterranean formation that includes a hydrocarbon reservoir bearing heavy oil, the reservoir having a primary heavy oil compartment hydraulically connected to (in fluid communication with) an overlying secondary zone of reduced (for example substantially lacking) heavy oil saturation compared to the primary compartment, such as a gas zone, a water zone, a neighbouring chamber depleted of oil, or a zone including lower permeability facies that present significant vertical and/or horizontal fluid flow barriers. A
blocking agent may be injected, for example as a fluid, so that it hardens to form a laterally disposed composite seal juxtaposed to a heavy oil saturated top portion of the primary heavy oil compartment. The blocking agent may for example be a polymeric resin, such as an epoxy resin, a phenolic resin, or a furan resin, and may also be formed with gels or waxes. The blocking agent may include a polymeric resin, a gel, a wax, or a combination thereof. The secondary zone may have a sufficient mobility to allow the blocking agent to be injected, for example, the blocking agent may have an injected viscosity of about 100 cP - 800 cP The blocking agent may be injected through one or more blocking agent injection (or injector) wells, which may for example include sidetracks or laterals, so that the composite seal circumferentially engages with underlying adjacent heavy oil in the primary heavy oil compartment. The circumferential engagement may have a wide variety of geometries, each reflecting a pattern in which the perimeter of the composite seal is positioned with respect to an underlying layer of bitumen so as to contain a buoyant solvent from migrating into the secondary zone. In effect, the composite seal and the underlying adjacent heavy oil together form an at least partially solvent-resistant permeability barrier in the reservoir (being partially solvent-resistant in that the permeability barrier enhances the retention of solvent in the primary compartment during recovery operations, compared to a degree of solvent loss that would be experienced in the absence of the barrier). In this way, the artificial barrier acts to hydraulically confine the primary heavy oil compartment.

[0015] Before or after injecting the blocking agent, a solvent-based recovery technique may be applied to the primary heavy oil compartment to mobilize heavy oil therein and form a recovery zone depleted of heavy oil. In the course of recovery operations, a mobilizing fluid is applied to the primary heavy oil compartment to deliver a buoyant solvent to the primary heavy oil compartment. Subsequently, the buoyant solvent rises within the primary heavy oil compartment as the recovery zone expands, the buoyant solvent being confined at the top of the primary heavy oil compartment by the composite seal.

[0016] The integrity of the composite seal and permeability barrier may be monitored, for example by measuring conditions in the blocking agent injection well that reflect the hydraulic isolation of the primary heavy oil compartment from the secondary zone. Monitoring of this kind may disclose a breach in the integrity of the composite seal or the permeability barrier, and in that circumstance further steps of injecting blocking agent may be undertaken to augment the composite seal and the permeability barrier.
There may be other reasons for injecting additional blocking agent from time to time, so that the process may involve multiple temporally discrete injection steps.

[0017] The solvent-based recovery technique may for example be a solvent-only recovery technique, or may include a staged hybrid recovery technique comprising a thermal recovery stage, such as SAGD, and a solvent recovery stage. The solvent-based recovery technique may for example involve a reduced-temperature solvent recovery stage, for example being carried out below a temperature of at or below about 140 C.
BRIEF DESCRIPTION OF THE DRAWINGS

[0018] Figure 1 is a schematic illustration of a typical heavy oil recovery well pattern, showing paired injector (injection) and producer (production) wells (well pairs), each well having a heel and a toe within the hydrocarbon rich pay zone of the formation.

[0019] Figure 2 is schematic illustration of Cretaceous stratigraphy of the Athabasca oil sands.

[0020] Figures 3A and 3B are schematic illustrations of artificially compartmentalized heavy oil reservoirs.

[0021] Figure 4 is a longitudinal cross section through a modeled reservoir.

[0022] Figure 5 is a close-up view of a portion of the modeled reservoir of Figure 4.

[0023] Figure 6 is a graph showing the oil production rate for two simulated recovery conditions, with and without an artificial permeability barrier installed.

[0024] Figure 7 is a graph showing the cumulative oil production comparison for two simulated recovery conditions, with and without an artificial permeability barrier installed.

[0025] Figure 8 is a graph showing the cumulative solvent (denoted as "gas"
in the Figure) injection comparison for two simulated recovery conditions, with and without an artificial permeability barrier installed.

[0026] Figure 9 is a graph showing the cumulative solvent (denoted as "gas"
in the Figure) production comparison for two simulated recovery conditions, with and without an artificial permeability barrier installed.

[0027] Figure 10 is a graph showing the net solvent to oil ratio comparison for two simulated recovery conditions, with and without an artificial permeability barrier installed.

[0028] Figure 11 is a schematic illustration showing a top plan view of an artificial barrier injection well configuration, with laterals, for example spaced 10-15m apart. The solvent injection and production wells are not shown, being beneath the central blocking agent injector well.

[0029] Figure 12 is a schematic illustration showing a top plan view of an artificial barrier injection well configuration, with sidetracks, for example spaced 20-50m apart and 35-50m in length. The solvent injection and production wells are not shown, being beneath the central blocking agent injector well.

[0030] Figure 13 is a schematic illustration showing a top plan view of an artificial barrier injection well configuration, with a plurality of injectors positioned about a circumference of a primary heavy oil compartment of a reservoir. The solvent injection and production wells are not shown, being beneath the central blocking agent injector well.

[0031] Figure 14 is a particle size analysis plot for a sample of sand used for cementitious material injection testing.
DETAILED DESCRIPTION OF THE INVENTION

[0032] Various aspects of the invention may involve the drilling of well pairs within a reservoir 11, as illustrated in Figure 1, with each injector well 13, 19, 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 well pair may for example average approximately 800 m in horizontal length. The lower production well profile may generally be targeted so that it is approximately 1 to 2 m above the heavy oil reservoir 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 3A is a cross sectional view along axis 24 of Figure 1, illustrating a hydrocarbon reservoir in which a primary heavy oil compartment 30 is hydraulically separated from a secondary zone 40 by an artificial permeability barrier 32, made up of a functional composite seal of the injected blocking agent in sealing engagement with underlying bitumen, so that under oil recovery conditions the flow of an injected buoyant solvent across the permeability barrier is restricted. An overlying natural top seal is not shown, but typically present, being in place prior to setting the blocking agent at the thief/bitumen zone interface and initiating hydrocarbon recovery operations. The natural top seal typically defines the top of the top thief or secondary zone.

[0034] In some embodiments, during a hydrocarbon recovery operation, oil may be depleted from a bitumen zone, including oil from a portion of a bitumen zone that is associated with an artificial permeability barrier. In effect, this means that the artificial permeability barrier may be modified over time. For example, at first the permeability barrier may be formed from the composite seal and top portions of the underlying bitumen zone that are then subject to recovery; as the hydrocarbon recovery operation progresses, the barrier may remain in place, formed from the composite seal and the sands/residual oil remaining in the top portion of the underlying bitumen zone.
Alternatively, if blocking agent is injected some time after the commencement of the hydrocarbon recovery process, the initial artificial permeability barrier may be formed between the composite seal and a somewhat depleted top portion of the underlying bitumen zone. Similarly, there are circumstances where there is a risk of solvent losses into an adjacent steam chamber/solvent chamber depleted of oil. In such circumstances, the blocking agent may be injected into the depleted area at the interface with the bitumen. Alternatively, for example in the case of lower permeability facies with fluid flow barriers, the blocking agent may be injected into a region of the bitumen zone if the lean zone (being part of the bitumen zone) has sufficient mobility (beyond the cold in-situ bitumen zone), the mobility being sufficient to allow the injection of a blocking agent, for example a blocking agent having a viscosity of about 100 cP ¨
800 cP.

[0035] In the embodiment illustrated in Figure 3A, a solvent-based recovery technique is applied to the primary heavy oil compartment 30, forming recovery chamber 28 around injection well 19, to mobilize heavy oil for production through production well 17. Solvent applied to the primary heavy oil compartment 30 by way of recovery chamber 28 is prevented from entering the secondary zone 40 by the artificial permeability barrier 32, which is formed by injection of blocking agent through blocking agent injection wells 35.

[0036] Figure 3B is a schematic cross sectional view of a hydrocarbon reservoir in which a buoyant solvent is injected into a primary heavy oil compartment 50 from an injection well 66 forming a recovery chamber 70 by mobilizing heavy oil for production through a production well 68. The primary heavy oil compartment 50 is overlaid by a secondary zone 52 which is capped by a natural top seal 56. The primary heavy oil compartment 50 contacts the secondary zone 52 at an interface 54. As indicated by the dashed lines at the periphery of Figure 3B, the secondary zone 52 expands laterally beyond the primary heavy oil compartment 50 such that, absent the presence of an artificial barrier, loss of buoyant solvent to the secondary zone 52 may be substantial.
To mitigate such a loss, the secondary zone 52 is partitioned into a proximal portion 72 and a distal portion 74 by a first artificial permeability barrier 58 and a second artificial permeability barrier 62. Having regard to the three-dimensional nature of the reservoir shown in cross section in Figure 3B, the artificial barriers 58 and 62 may be part of a continuous barrier such that the proximal portion 72 may be segregated from, and horizontally enclosed by, the distal portion 74. The artificial permeability barriers 58 and 62 are functional composite seals formed by blocking agent injected through blocking agent injection wells 60 and 64, respectively, such that the blocking agent is in sealing engagement with underlying heavy oil and the overlying natural top seal 56.
One example of well configuration which may be suitable for such an application is schematically depicted in Figure 13. Under oil recovery conditions, the flow of an injected buoyant solvent is not restricted across the interface 54 but is restricted across artificial permeability barriers 58 and 62 such that injected buoyant solvent is substantially retained within the primary heavy oil compartment 50 and the proximal portion 72 of the secondary zone 52. As such, loss of buoyant solvent to the distal portion 74 of the secondary zone 52 is reduced. Those skilled in the art will appreciate that reducing loss of the buoyant solvent to the distal portion 74 of the second zone 52 is in comparison to a degree of solvent loss that would be experienced in the absence of an artificial permeability barrier.

[0037] In alternative embodiments, the relative positions of primary and secondary zones may be varied. In practice, these adjoining compartments will typically have a complex geometric relationship, with at least some vertical and horizontal components offset. The artificial barrier may accordingly assume a variety of alternative geometries, all of which serve the functional requirement of providing a composite bitumen-blocking agent seal that serves to confine a buoyant solvent at the top of a primary recovery zone.

[0038] An alternative geometry of primary and secondary zones relates to the existence of bottom zones, such as bottom water. This may be of particular relevance in "thin" primary recovery zones, for example less than 15 m thick (for example 5-15 m or 5-12 m thick), in which solvent losses to either or both a top and bottom thief zone may be anticipated due to the confined area of primary recovery. In the case of a top thief/secondary zone, the blocking agent (having one or more components) can spread and descend within the formation primarily under the impetus of gravity, to form a composite seal engaged with the underlying bitumen zone (ultimately creating the artificial permeability barrier). In the case of a bottom thief/secondary zone, similar approaches may be taken that do not rely on gravity in the same way. For example, similar blocking agents may be adapted to create the artificial permeability barrier in a bottom thief zone scenario. For example, a carrier gas (such as nitrogen) may be used as a component of the injected blocking agent (either entrained with the blocking agent or injected separately) to provide buoyancy to the blocking agent. The blocking agent injection well or wells may similarly be adapted for a bottom thief/secondary zone, for example being positioned as close as possible to the overlying bitumen zone, which may for example involve the increased use of blocking agent injector well laterals or sidetracks, so as to ameliorate the loss of blocking agent to the base of the bottom water zone. In some bottom thief/secondary zone embodiments, even a partial permeability barrier between the bitumen and the bottom thief zone may be used to reduce solvent losses. In some embodiments, an artificial permeability barrier may reduce heat loss to the lean zone, may reduce the loss of bitumen to the lean zone, or a combination thereof. Accordingly, embodiments are provided in which a composite seal and permeability barrier are placed between a primary recovery compartment and one or both of an adjoining upper and lower secondary zone.

[0039] The present recovery processes may be initiated by delineating the characteristics of a subsurface bitumen reservoir, for example using observation wells and seismic survey information. This delineation will identify secondary zones that may interfere with the efficiency of a solvent-based recovery operation in an adjoining primary heavy oil compartment.

[0040] Secondary zones of potential concern may for example include top water zones, which give rise to the potential for fluid communication between the secondary zone and the underlying bitumen zone as a consequence of a recovery operation.

During recovery operations, an injected buoyant solvent, being less dense than the reservoir fluids, will rise in the recovery chamber (and spread laterally to an extent). In this circumstance, it is desirable to hydraulically isolate the top water zone from the lower bitumen zone where the recovery process is taking place. In the absence of a composite seal, the top water may drain towards the bitumen recovery zone, particularly if the recovery zone is operated at a lower reservoir pressure than the secondary zone.
This draining of top water towards the well pair will cool the reservoir and make the solvent-based recovery process significantly less efficient.

[0041] If the bitumen recovery zone is being operated at a higher pressure than the top water secondary zone during the recovery process, the injected solvent may rise into the top water zone and increase the reservoir pressure, filling the available pore space until the top water zone is in pressure equilibrium with the bitumen zone. The volume of solvent required to reach pressure equilibrium represents an inefficient solvent loss, reducing the efficiency of the solvent-based bitumen recovery process.

[0042] In alternative embodiments, the secondary zone may be a "lean" zone at the top of the reservoir, for example being devoid of appreciable amounts of recoverable bitumen. The pore space of a lean zone may contain connate reservoir water (for example on the order of 20% v/v), residual bitumen (for example 20% v/v) and a significant concentration of natural gas (for example 60% v/v). The exact concentrations of the lean zone may of course vary significantly. The lean zone may for example be in pressure equilibrium with the underlying bitumen zone (i.e. at the same reservoir pressure) during the start of the recovery process. Alternatively, the lean zone may have been pressure depleted, and it may therefore be at a significantly lower pressure than the heavy oil zone. In both cases, the injected solvent from the recovery process can rise into the lean zone, in which case the efficiency of the solvent-based recovery process is reduced due to these losses. In the case where the lean zone has been pressure depleted prior to the recovery process, the solvent losses may be significant.

[0043] Alternatively, the offending secondary zone may include fluid flow barriers, including but not limited to clasts, bridges, baffles, low permeability regions and barriers that may cause the solvent to become trapped above barriers, between barriers, or a combination thereof, making the solvent unable to drain mobilized oil towards the production well of the recovery process. This "trapping" of the solvent with respect to these barriers and in these low permeability regions causes the efficiency of the solvent-based recovery process to be significantly reduced, as the solvent and mobilized oil is lost to these barrier zones.

[0044] An aspect of some of the processes described herein is the drilling and completion of a recovery well pair, as for example shown in Figure 1, for example with well pairs drilled approximately 800 to 1,000 m long, with approximately 5 m in vertical separation.

[0045] In addition to the recovery well pair, the aspects of the processes disclosed herein involve the use of a blocking agent injector well. The blocking agent injector well may be a vertical well or a horizontal well. A horizontal blocking agent injector well may for example be drilled in the same vertical plane above the recovery well pair. In terms of vertical placement, the blocking agent injector may be drilled at the start of the offending secondary zone, i.e. the depth/height in the formation at which the zone begins/interfaces with the bitumen zone. The blocking agent injector may be advantageously placed as close as possible to the bitumen zone, while still being in the offending secondary zone. In this way, the blocking agent injector may be placed in a zone that has sufficient mobility for a blocking agent to be injected, whereas the underlying bitumen zone may not have sufficient mobility (e.g. prior to the hydrocarbon recovery process) to allow for the injection of the blocking agent. Placement of the blocking agent injector just above the bitumen zone in a top thief zone scenario allows the underlying bitumen zone (which has no practical mobility to fluids injected at pressures below the formation fracture pressure) to act as a barrier that prevents the blocking agent from dropping in the reservoir when the blocking agent is injected. In select embodiments, the blocking agent may for example be placed within 40cm to lm of the bitumen zone. The blocking agent may accordingly tend to spread out laterally when injected adjacent to the bitumen zone, for example at the top of the bitumen recovery zone, forming a seal. The blocking agent thickness may for example be about cm to 50 cm, and may be thinner or thicker at certain points depending on the reservoir geology or how the blocking agent is injected. The blocking agent injector may for example be completed either open hole, if the secondary zone is competent, or with a liner to prevent the hole from sluffing in during blocking agent injection or hydrocarbon recovery operations. The blocking agent may for example be injected in a variety of scenarios, which may be combined: (1) inject blocking agent prior to initiating hydrocarbon recovery; (2) initiate hydrocarbon recovery and at a later time inject blocking agent; (3) inject blocking agent before or after hydrocarbon recovery is initiated and then re-inject the blocking agent later as needed. In select embodiments, the well pair may be operated without an artificial barrier in place, while monitoring the influence of the secondary zone on recovery operations, for example to determine the extent to which solvent is lost. This may for example take place for 3 to 6 months, or to a point at which losses of the solvent are meaningful, for example if the solvent to oil ratio rises significantly, or above a desired threshold (such as > 4), at which point the injection of the blocking agent may be undertaken.

[0046] An aspect of some of the present processes involves drilling and completion of blocking agent lateral wells or sidetrack wells. In some embodiments, the lateral wells may be drilled on either side of the blocking agent injector, e.g. in the form of a multi-lateral horizontal blocking agent injector well, before the recovery process begins. In alternative embodiments, the sidetrack wells may be drilled from and incrementally spaced along the horizontal segment of the blocking agent injector well at an angle from the blocking agent injector well. These or other blocking agent injector well configurations and associated completions may be implemented so as to ensure a composite seal prior to the commencement of the recovery process.
Alternatively, the laterals or sidetracks may be added to the blocking agent injector well when required during hydrocarbon recovery operations as the recovery chamber grows laterally.
Changes to the blocking agent injector well(s), injection of blocking agent, or both, may be included in an iterative process that takes place throughout oil recovery operations.
The laterals may for example be approximately the same length as the blocking agent injector well. The horizontal (lateral) spacing between the blocking agent injector well and the first lateral and all subsequent lateral injectors may be determined by how far the blocking agent spreads laterally. For example, if the injected blocking agent travels approximately 5 m laterally from the blocking agent injector (in a horizontal direction) before hardening, the first lateral may be drilled 10 m away from the central blocking injector. In practice, the distance of blocking agent travel may be assessed empirically.
The total number of laterals required may be determined based on the spacing between recovery well pairs. For example, if the spacing between recovery well pairs is 100 m, then four to five laterals, spaced 10 m apart may be required on either side of the blocking agent injector. Alternatively, in some embodiments, only the blocking agent injector may be required. In alternative embodiments, other injector well configurations may be used. As a first example, an injector well configuration may comprise a vertically spaced, perpendicular injector (with respect to the well pair), with or without sidetracks.
As a second example, a plurality of blocking agent injector wells may be provided around a circumference of a primary heavy oil compartment of a reservoir. One example of such a well configuration is schematically depicted in Figure 13 where blocking agent injector wells 80, 81, 82, and 83 are provided around a circumference of primary heavy oil compartment. As Figure 13 is shown in plan view, only the lateral sections of the wells 80, 81, 82, and 83 are depicted. Such a well configuration may be utilized for applications where it is desirable to isolate the primary heavy oil compartment from part, but not all, of a secondary zone of reduced heavy oil saturation.
A reservoir comprising a primary heavy oil compartment overlaid by a shallow but horizontally-expansive gas cap is one instance where such a well configuration may be utilized. In such a reservoir, hydraulic isolation may be substantially achieved by forming a composite seal that creates a substantially horizontal perimeter around the primary heavy oil compartment and that penetrates up to a ceiling of the shallow gas cap. The composite seal may substantially partition the gas cap into a proximal portion and a distal portion, wherein the proximal portion of the gas cap is hydraulically connected to the primary heavy oil compartment and wherein the distal portion is hydraulically isolated from the proximal portion of the gas cap and the primary heavy oil compartment. In such instances, a buoyant solvent may be substantially retained within the primary heavy oil compartment and the proximal portion of the gas cap.
This may reduce the amount of blocking agent required to provide for hydraulic isolation. Of course, in embodiments wherein a plurality of blocking agent injector wells are provided around a circumference of a primary heavy oil compartment, the dimensions of the blocking agent injector wells may vary. For example, in an embodiment where a single well pad comprises eight wells that are 1000 m long and spaced 100 m apart, the plurality of blocking agent injector wells may form a generally rectangular circumference with a length of about 1050 m and a width of 900 m. As a further example, in an embodiment where four well pads, each comprising ten wells that are 1000 m long and spaced 100 m apart, are situated as quadrants of a square, the plurality of blocking agent injector wells may form a generally square circumference with a length (width) of about 2200 m. Configuration of the blocking agent injector will generally be selected so as to generate a large enough barrier to prevent significant solvent losses during the hydrocarbon recovery operation.

[0047] Aspects of the processes described herein involve the initial injection of blocking agent into a secondary zone from a blocking agent injector well. The initial injection may for example take place prior to the commencement of the solvent-based recovery process in the bitumen zone. The blocking agent may for example be delivered to the blocking agent injector well at pressures below the reservoir fracture pressure, so as not to induce additional pathways for solvent to escape in the offending secondary zone once the blocking agent is injected into the secondary zone. In select embodiments, this pressure is designated the "maximum blocking agent injection pressure". In select embodiments, as much blocking agent as possible may be injected into the reservoir until the maximum blocking agent injection pressure is reached. In embodiments in which the blocking agent injector is a horizontal well, the blocking agent may be distributed to the secondary zone with coil tubing or an alternative tubing deployment mechanism (e.g. a jointed tubing string). Such tubing deployment mechanisms may also be employed in embodiments in which the blocking agent injector is a vertical well. Injection may accordingly commence at the toe of the horizontal blocking agent injector, and as the pressure in the near wellbore area increases from the injection, the coil (or other) tubing may be pulled back as injection continues until the heel of the horizontal well is reached. Following injection of the blocking agent, material in the horizontal wellbore of the blocking agent injector may be displaced with a suitable completion fluid that will not degrade the blocking agent.

[0048] Monitoring equipment, such as one or more bottomhole pressure recorders, may then be placed in the blocking agent injector, and/or in one or more of the lateral or sidetrack wells. The bottomhole pressure recorders may also advantageously have a temperature gauge.

[0049] Aspects of the processes disclosed herein involve the injection of blocking agent through lateral and/or sidetrack wells. The blocking agent may for example be delivered to and injected through each lateral and/or sidetrack well using the same methodology and approach disclosed above. A mud motor equipped with a gyro type location identification device may for example be used to steer the coil tubing into each lateral well and/or sidetrack well to place the blocking agent. Again, the blocking agent may be distributed from toe to heel in each lateral well and/or sidetrack well. As discussed above, one or more bottomhole pressure recorders may be provided in one or more lateral wells and/or sidetrack wells, just as in the blocking agent injector. The measurements, such as pressure and temperature, from the blocking agent injector, laterals and/or sidetracks may for example be transmitted to the surface, in real time or otherwise. In addition, the blocking agent injector well and/or the lateral or sidetrack wells may be completed so as to remain open to reservoir flow, such that a sample of what is in the wellbore may be produced to surface and analyzed.

[0050] The operation of the recovery well pair may for example include initial start-up steps of solvent circulation or pre-heating of the reservoir, transitioning to a gravity dominated solvent-based recovery process. The bottomhole pressure recorders and temperature gauges in the blocking agent injection wells may then be monitored. An increase or decrease in pressure or temperature may provide an indication, for example in a top thief zone scenario, of solvent flow from below (pressure and temperature may increase) or flow from the offending secondary zone into the bitumen zone (pressure may remain constant or decrease and temperature may decrease). Fluid samples may be periodically obtained from the surface wellhead or downhole from the blocking agent injector wells to verify the composition of the fluids in the region of the composite seal.
For example, detection of an increase in solvent concentration may indicate that the injected seal has been breached and remediation may be required. The blocking agent may be periodically re-injected through the blocking agent injectors to re-establish a seal that may have been breached or to strengthen selected areas of the composite seal.

[0051] In some embodiments, it may be desirable to drill only the blocking agent injector initially. With monitoring, any loss in efficiency of the recovery operations may then be taken as an indication to re-enter the blocking injector and add laterals and/or sidetracks.

[0052] The blocking agent may be tailored to specific conditions of heavy oil recovery. For example, the solvent-based recovery process may advantageously be carried out at a selected maximum temperature, for example of at most 140 C.
This maximum temperature reflects a range of possible reservoir pressures, for example from 2,000-3,500 kPa, or from 500-7,500 kPa, thereby creating conditions at which a buoyant solvent can be injected in the vapour phase. A relatively low temperature solvent-based recovery process may be advantageous in order to preserve the integrity of the composite seal. The integrity of the seal relies as well on the placement of the blocking agent as close as possible to the underlying bitumen reservoir. This is particularly important because when solvent escapes from the underlying or overlying bitumen reservoir into a lean or secondary zone, the mobility of the solvent may significantly increase. In an embodiment, due to the low mobility of the bitumen reservoir to the injected blocking agents, at least prior to initiating hydrocarbon recovery, the underlying bitumen layer acts as a floor on which the blocking agent can spread out and then provide a seal against solvent permeability from the underlying bitumen reservoir or fluid permeability from the offending secondary zone.

[0053] Specific conditions of heavy oil recovery may involve the use of particular solvents. The buoyant solvent may for example be a light hydrocarbon solvent, and may be selected on the basis that it is miscible with, and capable of enhancing the mobility of, the reservoir hydrocarbons. As such, the solvent may be deployed as a mobilizing fluid, comprising for example one or more, polar or non-polar, C3 through C10 linear, branched, or cyclic alkanes, alkenes, or alkynes, in substituted or unsubstituted form, or other aliphatic or aromatic compounds (alternatively 03-C7). Select embodiments may for example use an n-alkane, for example n-propane or n-butane. The mobilizing fluid comprising the buoyant solvent may be injected as a vapour, for example at a relatively low temperature, for example at or below 140 C. In select embodiments, a polar solvent-based or a heavier solvent-based hydrocarbon recovery process may be used with selected blocking agents.
Aspects of the present processes may use blocking agents that are resins that can be thermally set or chemically set.

[0054] In practice, the deployment of the blocking agent may involve the following aspects. A fluid feed rate may be established into the reservoir with either a hot water that has been viscosified with a polymer or any other viscous heated fluid, such as a mineral oil. This pre-heating fluid may advantageously have some viscosity (for example 100+ cP) to prevent it from leaking into the bitumen reservoir. Sufficient heated fluid is injected into the secondary zone to establish a high enough temperature to thermoset the resin after it is injected. For some resins, a target temperature may for example be 40 C ¨ 45 C. The resin or another blocking agent may then be injected into the heated secondary zone. The viscosity of the blocking agent may be selected or adjusted to be sufficiency low for it to be injected at pressures below reservoir fracture pressures. The blocking agent may then be thermoset in the pre-heated area of the secondary zone, for example within a time period such as 60 minutes. The time frame for thermosetting and further hardening of the resin may be shorter or longer depending on the particular blocking agent and reservoir conditions.

[0055] For a chemically set resin, a pre-heating fluid may also be injected into the secondary zone to provide sufficient heat for the chemical reaction to take place within a selected period of time, for example within 12-24 hours or 1-7 days. The resin or another blocking agent may then be injected into the heated secondary zone.
The viscosity of the blocking agent may be selected or adjusted to be sufficiency low for it to be injected at pressures below reservoir fracture pressures. A chemical activating agent may then be injected to cure the resin. The time frame for setting or curing and further hardening may be shorter or longer depending on the particular blocking agent and reservoir conditions.

[0056] Injection of the blocking agent may not require pre-heating of the secondary zone. Injection of the blocking agent may involve combining the blocking agent with a carrier fluid at surface or prior to delivering the combination to the surface facilities or wellhead. Examples of carrier fluids may include water or a polar or non-polar hydrocarbon solvent (e.g. a lighter alkane solvent or heavier alkane solvent mixture such as a natural gas condensate), or a combination thereof.

[0057] Blocking agents may for example include resins, namely epoxy resins, phenolic resins, or furans. Epoxy resins are almost exclusively thermoset.
Phenolic resins have been used extensively in steam flooding applications and are generally not, or moderately, sensitive to water. Phenolic resins are generally activated in the reservoir by an acidic or basic chemical activating agent. Furans may be chemically set with an acid. Certain phenolic resins and furans may set without secondary zone pre-heating.

[0058] Resins, once set, may harden through a marked increase in viscosity and preserve this rigidity at temperatures that are relevant for solvent-based recovery operations, for example remaining thermally stable up to 140 C. Blocking agents may be selected so as to be solvent resistant when hardened, in particular being resistant to breaking down in the presence of the solvents used in low temperature solvent-based hydrocarbon recovery processes.

[0059] The blocking agent may for example be oleophobic to repel the injected solvent (in liquid or gas phase) and other gases (e.g., methane) from entering the secondary zone. Where the offending secondary zone is a top water zone, a blocking agent may be used that resists both solvents and water infiltration. For example, the blocking agent may be formed from a mixture of a binary resin containing both oleophobic and hydrophobic components to repel both solvent invasion from the underlying bitumen zone and water invasion from the top water zone, respectively. Such a binary blocking agent may also be suitable for a bottom water zone with an overlying bitumen zone. Other blocking agents that may be employed include oilfield cements, waxes and crosslinked gels. Oilfield cements (e.g. micro cements) may be injected into pore systems and are thermally stable up to about 140 C. Oilfield cements may include cementitious materials having a variety of viscosities, densities, pH values, and SiO2 contents. For example, the cementitious material may have a viscosity of between about 7 mPa.s and about 13 mPa-s, a density of between about 0.7 kg/L and about 1.3 kg/L, a pH value of between about 8 and about 12, and a SiO2 content of between about 12 wt.% and about 18 wt.%. MasterRoc MP 325 is an example of a cementitious material that may be included as a component of a blocking agent composition that comprises an oilfield cement (MasterRoc is a registered trademark of Construction Research & Technology GmbH, Trostberg, Germany).

[0060] Epoxy resins are generally based on a phenolic chemical structure; a common epoxy resin is bisphenol A epoxy resin and is a product of the reaction between epichlorohydrin and bisphenol A. The bisphenol A epoxy resin or other blocking agents may be obtained commercially. One or more chemical activating agents (sometimes referred to as curing agents, hardeners, catalysts, or cross-linkers depending on the intended physical or chemical reactivity) may be added to the epoxy resin or another blocking agent before it is pumped into the blocking agent injection well. When the resin and chemical activating agent are exposed in the blocking agent injection well to the heat from pre-heating the well and secondary zone, the resin may start to cure and harden. A typical hardener is diethylenetriamine, and a catalyst such as an amine or carboxylic acid may further be added. After the one or more chemical activating agents are added the resin may further be cut with a mutual solvent, such as ethyleneglycolmonobutyl ether (EGMBE) to lower the viscosity of the resin to allow it to be pumped down hole at low pressure and enter the pre-heated formation. The solvent generally does not affect the curing and hardening of the resin, and may be selected so that it allows the resin to be injected and appropriately placed. Other suitable epoxy resins may for example include bisphenol F epoxy resins or aliphatic epoxy resins, including high temperature resistant resins.

[0061] Two common phenolic resins include novolac resins and resol resins.
A
novolac resin involves an acid catalyst to cure and harden the resin while a resol resin involves an alkaline (or basic) catalyst to cure and harden the resin.
Novolacs are soluble in organic solvents like alcohols and acetone, but not in water, which make them particularly useful in top or bottom water zones to prevent top or bottom water from invading the bitumen zone. Resols on the other hand have at least partial solubility in water.

[0062] Furan resins, more properly called furyl alcohol resins, are almost exclusively cured and hardened through the use of an acid catalyst. At very high temperatures the polymerization reaction may be explosive and control of the reaction is accordingly important in oilfield applications.

[0063] As described above, blocking agents such as resins that are thermoset or chemically set may involve the addition of an acid or alkali curing agent (which acts as a catalyst to start the curing and hardening reaction) and this addition may occur at surface prior to delivering the blocking agent to the blocking agent injector well. The resin and the one or more chemical activating agents may be shipped separately to the surface facilities or wellhead. The resin and the one or more chemical activating agents may be mixed at surface and then immediately injected into the pre-heated secondary zone via the blocking agent injector well. Injecting the mixture quickly may be helpful so as to avoid the final product setting-up at surface or in, for example, injection tubing in the injection well. The injection tubing may be pre-heated to assist in delivery of the mixture to the secondary zone. In an alternative embodiment, a resin or other blocking agent may be injected into the secondary zone, followed by injection of one or more suitable chemical activating agents as a mixture or by injection in series.
Where a physical change, a chemical reaction, or both, are required to form the composite seal, such a change and/or reaction may be delayed until the blocking agent has at least partially spread out in the secondary zone by adjusting the timing and/or sequence of injection of one or more blocking agent components.

[0064] Crosslinked gels are generally based on acrylates or acrylamides. In terms of acryalmides, hydrolyzed polyacrylamides are often used. Crosslinks may for example be formed by metals like aluminum citrates, or other organic crosslinkers such as phenol, hydroquinone, or phenyl acetate.

[0065] In the case of a gel or acrylamide system, the cross-linker may be mixed with the hydrated gel or acrylamide at surface prior to injection downhole. The cross-linking reaction generally starts immediately and some cross-linking as the mixture is injected is acceptable; however, waiting for too long before injection of the mixture may lead to undesirable reactions with oxygen and free radical degradation.

[0066] A crosslinked gel that is temperature resistant to 140 C may for example be made from both inorganic and organic gels, such as partially hydrolyzed polyacrylamide (HPAM, anionic), crosslinked with either a metal (chromium or aluminum, such as in the form of aluminum citrate) or an organic crosslinker (such as an aldehyde).
Gels may for example be periodically re-applied through the blocking agent injector(s), as gels tend not to be as rigid and long lasting as resins.

[0067] An aflernative blocking agent may comprise an ultra-high melting point petroleum wax, or a wax based on another substance, and the wax may for example be heated to lower the viscosity of the wax and then injected into the reservoir to the desired location in the secondary zone. The wax may then "set-up" at the native temperature of the secondary zone.

[0068] Relatively hard microcrystalline synthetic waxes, for example derived from a Fisher-Tropsch process may be useful. These are synthetic waxes produced from the polymerization of carbon monoxide at high temperatures. The melting point (the point at which the wax would lose its effectiveness as a blocking agent) may for example be in the 115-120 C range. These waxes may be suitable as part of a binary mixture, injected along with other blocking agents such as resins, in embodiments in which these waxes are provided so as to repel water. The combination of a wax and a resin may for example be adapted to yield both oleophobic and hydrophobic properties.

[0069] In an embodiment, the composite seal may for example be a polymer generated by injecting a blocking agent comprising a monomer and an initiator either as a monomer-initiator mixture or sequentially. In an alternative embodiment, the composite seal may be generated by making use of the constituents of the thief zone itself, for example by relying on reactivity of the blocking agent with water in a water zone to aid in generating the composite seal. For example, if stock acrylamide is the monomer, the polymerization reaction may be initiated by a reduction-oxidation initiator such as AMPS (ammonium persulphate) or TEMED (tetramethylethylene diamine). In such embodiments, when used in small batches, heat may not be required. The reaction is typically a free radical polymerization via the AMPS or TEMED of stock acrylamide, to make polyacrylamide. In some embodiments, a select degree of hydrolysis may be achieved, for example 20-40%, to provide a selected HPAM
(hydrolyzed polyacrylamide). The HPAM may optionally be cross-linked, for example with aluminum citrate. For this reaction to occur, free water must generally be present, as would be the case for example in a top water or bottom water situation. In effect, the HPAM acts as a thickener. In a gas lean zone, water may be injected before the blocking agent to provide any necessary free water for this reaction, before injecting the acrylamide followed by the free radical initiator AMPS or TEMED.

[0070] In accordance with the foregoing discussion of alternative blocking agents, suitable resins and gels are generally compounds that require curing (involving a second chemical agent, heat, or both), which reflects a chemical reaction (usually polymer crosslinking) that takes place when two or more components are combined to form the composite seal and create a permeability barrier where the thief/secondary zone meets the bitumen zone. For example, a resin combined with one or more chemical activating agents generates the blocking agent.

[0071] Resins not only cure, but harden (become more solid) and may continue to harden further in the presence of heat during the solvent-based hydrocarbon recovery process in the bitumen zone. Gels are different from resins, and may or may not harden along with curing, typically they will not harden to the same extent as resins (and are accordingly typically less solid when formed into a composite seal). Waxes do not require curing; rather, they are melted by heating and injected into the thief/secondary zone, and then allowed to cool to solidify (freeze). As used herein, the terms "set", "setting" or "setting-up", as in "thermosetting" or "chemical setting" of a polymer or compound, have a functional meaning to the effect that the injected blocking agent undergoes changes in some physical or chemical characteristic as it forms the material that makes up the composite seal as part of the permeability barrier. For example, a blocking agent may set (stiffen) before it fully hardens.

[0072] Selecting a suitable blocking agent having one or more components may include testing or evaluating compounds that undergo a change in viscosity, density or solidity at native thief zone or reservoir conditions, post pre-heating of the thief zone, or at the conditions of a solvent-based recovery process occurring in the underlying bitumen zone at a temperature up to 140 C. Suitable blocking agents may be selected based on characteristics including thermal stability, chemical stability, strength, permeability, or a combination thereof. Suitable blocking agents may be stable under a range of pressures, e.g. 500 ¨ 7,500 kPa. Suitable blocking agents may be selected based on an understanding of chemical thermodynamic and transport mechanisms and how a particular blocking agent may be expected to disperse after it is injected into the secondary zone. Suitable blocking agents may be selected based on how the blocking agent(s) will function within a porous geological formation.

[0073] Testing the characteristics of potential blocking agents may include tests conducted at different temperature and pressure conditions to establish suitable reaction kinetic parameters; assessing compatibility, resistance, or permeability to water, solvents, hydrocarbons, or solution gas; testing time frames for setting, curing, or hardening; or a combination thereof. The characteristics of potential blocking agents may be tested to understand the effect of reservoir impurities (e.g. dissolved solids in the reservoir formation water or clay minerals that may be present in the quartz reservoir matrix) on the physical or chemical reactions involved in creating a composite seal.

[0074] Suitable blocking agents may be selected based on compatibility of the composite seal with the solvent(s) for hydrocarbon recovery, formation water and solution gas. Suitable blocking agents may have an appropriate setting, curing, or hardening time such that premature setting, curing, or hardening around the blocking agent injector well is minimized or prevented.

[0075] Tests may be carried out to select appropriate blocking agents for particular embodiments. For example, tests may establish the set-up (or setting) time of a selected blocking agent, being the length of time that it takes the material to set-up after the hardener or curing agent is added at a given temperature. Similarly, the set-up temperature of a selected blocking agent may be established as the temperature needed for the selected material to set-up. Tests may similarly establish how the concentration of the material impacts the set-up temperature and/or time.
Accelerants or delayers may be tested to demonstrate a desired effect, such as delaying the set-up until the material is sufficiently transported into the reservoir. Gel or resin strength may be established in assays that may be characterized as a gel yield test. For example, in a pressurized test apparatus, assays may be conducted to determine the compressive strength of the gel or resin, i.e. the degree of compression before yielding.
Tests of this kind may for example take place at room temperature for screening purposes, and then at blocking agent injection temperatures and pressures. In these tests, two fluids may be used, one on either side of the gel, one side being at higher pressure than the other side.

[0076] Gel or resin strength may for example be tested in porous media, for example using conditions that mirror the lean zone reservoir conditions. In tests of this kind, the blocking agent may be injected and allowed to cure and harden within a similar time frame as to what would be used in the field at reservoir conditions. The volume of barrier material may for example fill approximately 1/2 to 2/3 of the pore volume of a test core. The solvent may then be injected into the core at pressure (at the injection side) and the amount of solvent that leaks through the barrier may be measured on the production side of the core. The pressure may for example be ramped up on the injection side until the barrier eventually yields.

[0077] A 3D physical model test may be used to assess blocking agents, and which mimics the reservoir recovery process on a very small scale, for example a 1/32 or a 1/64 scale. Some or all of the intended blocking agent injection wells, for example including laterals or sidetracks, may be added to a model that includes a solvent injector and producer well pair. Parameters that may be modeled in this way include comparisons of the solvent to oil ratio with the barrier in place versus not having the barrier in place.
Examples

[0078] Detailed computational simulations of reservoir behaviour have been carried out to exemplify various aspects of composite seal performance, illustrating that an artificial permeability barrier may be used in conjunction with buoyant solvents to recover heavy oil while avoiding the loss of solvent to a thief zone. A 3D
reservoir simulation model was used to simulate the effects of the solvent loss prevention performance of the composite seal. A horizontal well pair of 800 m in horizontal length was constructed in a simulated reservoir having 15 m of thickness from the under burden to the over burden. The vertical separation between the lower horizontal production well and the upper horizontal injection well was 5 m. Horizontal permeability in all cells in the model was set to 10,000 md while vertical permeability was set to 7,000 md. Porosity was 33%. A well pair configuration using 4 outflow control devices in the injection well was used. The depth of the reservoir was approximately 475 m below surface. The reservoir pressure in both the underlying bitumen zone and the top lean gas (thief) zone was 2,800 kPa. Live oil Athabasca bitumen properties for the subsurface McMurray formation were used. The solvent that was injected in the simulation was pure propane; standard propane properties from the Gas Processors Suppliers Association Engineering Data Book were used. The simulated reservoir is illustrated in Figures 4 and 5, in which:
1 = horizontal production well, directed into the page 2 = horizontal injection well, directed into the page 3 = underlying bitumen formation:
permeability X,Y,Z = 10,000 md porosity = 33%
oil saturation = 80%
water saturation = 20%
gas saturation = 0%
4 = top lean gas zone:
permeability X,Y,Z = 7,000 md porosity = 33%
oil saturation = 20%
water saturation = 20%
gas saturation = 60%
= location of blocking agent in permeability barrier permeability X,Y,Z = 50 md porosity = 12%

[0079] In a first set of reservoir simulations, communication between the injector and producer was established via steam circulation. Communication could also be established, for example, by solvent circulation, by downhole electrical heaters, or by other methods of well start-up as would be understood by a person of skill in the art.
Following the establishment of communication between the injector and producer, the well pair was then placed on operation; heated propane was injected at 100 C
and approximately 4,200 kPa. A maximum gas phase injection rate of 63,200 m3/d of propane was set at surface. At the production well, a constraint of 2,800 kPa was set.
Produced gas was not constrained. In Figures 6-10, this simulation is referred to as "No Barrier".

[0080] A further simulation model included the effects of injection of a blocking agent. The blocking agent was modelled as a 10 cm thick interval lying at the base of the top lean gas zone as shown in Figure 5. The blocking agent interval (composite seal) was introduced in the simulation model prior to the commencement of hydrocarbon recovery operations, and the interval had a permeability of 50 md in the x, y and z directions and a porosity of 12%. The simulation with the blocking agent interval present is designated as the "50 md Barrier" case in Figures 6-10. The blocking agent interval was modelled with some permeability (albeit 200 times less than the surrounding matrix) to allow for some fluid flux through the artificial permeability barrier.
Although a substantially complete seal between the top lean zone and the underlying (or overlying) bitumen reservoir may be provided, this may not always be feasible due to local reservoir heterogeneity, imperfect placement of the blocking agent and local significant pressure gradients which may cause the blocking agent interval to yield. The present simulations illustrate that even an imperfect artificial permeability barrier provides substantial benefits.

[0081] Figure 6 illustrates that early in the life of the hydrocarbon recovery operation (up to about 200 days in this simulation), the presence of the artificial permeability barrier significantly enhanced the oil rate. In the modelled reservoir, the thief zone was confined, so that it became saturated with solvent during this early time frame and thereafter the secondary zone no longer acted as a thief zone. In practice, thief zones may not be constrained in this way, and the advantages of the composite seal may be therefore be prolonged. In the constrained environment of the model, overall oil production was ultimately the same between the case with the barrier and the case with no barrier, as shown in Figure 7, although slightly better with the barrier up to about 1,500 days.

[0082] The amount of solvent (propane) injected into the reservoir and then produced back is shown in Figures 8 and 9. Again, in the constrained thief zone model, there was minimal difference between the case with the artificial barrier interval and the case with no barrier. Somewhat more solvent was injected and produced overall in the case with the barrier compared to the case with no barrier; however, this additional solvent requirement was offset by the reduction in net solvent to oil ratio, as shown in Figure 10.

[0083] Figure 10 dramatically illustrates the efficiency of the barrier.
The net solvent to oil ratio is defined as the (Cumulative Gas (Solvent) Injected - Cumulative Gas (Solvent) Produced) divided by the Cumulative Volume of Oil Produced. A low solvent to oil ratio reflects a more efficient solvent-based hydrocarbon recovery process. As illustrated, in the absence of the barrier, the presence of a top lean gas zone caused the solvent to oil ratio to increase, reflecting an inefficient use of the buoyant solvent due to secondary zone losses. The blocking agent injection well or wells may accordingly be utilized for monitoring undesirable migration of fluids across the artificial permeability barrier and the integrity of the composite seal. If fluid migration is detected, additional blocking agent (e.g., resin, gel, wax, chemical activating agent, or a combination thereof) may be introduced to replenish the composite seal and/or to re-seal the artificial permeability barrier and this replenishing and/or re-sealing process may be repeated multiple times.

[0084] Laboratory-scale tests were completed to evaluate physical characteristics (e.g. dispersability and compressive strength after setting) of blocking agents comprising cementitous materials. A one-gallon sample of dry sand was analyzed to determine particle size distribution. Results from the analysis are shown in Figure 14.
The sand was mixed with a 1 wt. % brine solution (NaCI) in a sand:brine ratio of about 4.9:1.0 in order to simulate the expected density of the sand under reservoir conditions.
The sand/brine composition was packed into two 38 mm diameter PVC tubes each measuring approximately 1 m in length. MasterRoc MP 325 was injected into the tubes at pressures between 1.5 bar (21.76 psi) and 3.5 bar (50.76 psi). The MasterRoc MP
325 was allowed to penetrate the sample until it began to exhibit gelation at which point the injection was stopped and the sample was left to cure for 28 days. After this period, the MasterRoc MP 325 was determined to have penetrated approximately 80% of the length of the PCV tubes and the compressive strength was determined to be 263 kPa.
After 56 days, the compressive strength of the sample was reevaluated and found to be 347 kPa. After 84 days, the compressive strength of the sample was reevaluated and found to be 379 kPa. Additional tests demonstrated that the 1% brine solution served as an accelerator for the MasterRoc MP 325.

[0085] 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. For example, any one or more of the injection or production 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 invention, including for example the use of multilateral or single injection-production wells as injection and/or production wells. For instance, in some embodiments a hydrocarbon recovery production well drilled into a bottom water zone may be utilized as a blocking agent injector well. Such modifications include the substitution of known equivalents for any aspect of the invention in order to achieve the same result in substantially the same way. Numeric ranges are inclusive of the numbers defining the range. The word "comprising" is used herein as an open-ended term, substantially equivalent to the phrase "including, but not limited to", and the word "comprises" has a corresponding meaning. As used herein, the singular forms "a", "an" and "the" include plural referents unless the context clearly dictates otherwise.
Thus, for example, reference to "a thing" includes more than one such thing.
Citation of references herein is not an admission that such references are prior art to the present invention. Any priority document(s) and all publications, including but not limited to patents and patent applications, cited in this specification are incorporated herein by reference as if each individual publication were specifically and individually indicated to be incorporated by reference herein and as though fully set forth herein. The invention includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings.

Claims

1. A process for mobilizing fluids in a subterranean formation, the process comprising:
selecting a hydrocarbon reservoir in the formation bearing heavy oil, the reservoir having a primary heavy oil compartment hydraulically connected to a secondary zone of reduced heavy oil saturation compared to the primary compartment;
injecting a blocking agent to form a composite seal juxtaposed to a portion of the primary heavy oil compartment through a blocking agent injection well, wherein the composite seal circumferentially engages with adjacent heavy oil in the primary heavy oil compartment so that the composite seal and the adjacent heavy oil together form an at least partially solvent-resistant permeability barrier in the reservoir, at least partially hydraulically confining the primary heavy oil compartment;
applying a solvent-based recovery technique to the primary heavy oil compartment to mobilize heavy oil therein and form a recovery zone depleted of heavy oil, wherein a buoyant solvent is delivered to the primary heavy oil compartment, and the buoyant solvent rises within the primary heavy oil compartment as the recovery zone expands, the buoyant solvent being at least partially confined in the primary heavy oil compartment by the composite seal; and monitoring the integrity of the composite seal and permeability barrier by measuring conditions in the blocking agent injection well that reflect the extent of hydraulic isolation of the primary heavy oil compartment from the secondary zone.

2. The process of claim 1, wherein the permeability barrier hydraulically confines the primary heavy oil compartment from the secondary zone.

3. The process of claim 1 or 2, wherein the portion of the primary heavy oil compartment juxtaposed to the composite seal is a heavy oil saturated portion, wherein the composite seal is laterally disposed juxtaposed to a top portion of the heavy oil saturated portion of the primary heavy oil compartment, and wherein the composite seal circumferentially engages with underlying adjacent heavy oil in the primary heavy oil compartment so that the composite seal and the underlying adjacent heavy oil together form the permeability barrier.

4. The process of claim 1 or 2, wherein the portion of the primary heavy oil compartment juxtaposed to the composite seal is a heavy oil saturated portion, wherein the composite seal is laterally disposed juxtaposed to a bottom portion of the heavy oil saturated portion of the primary heavy oil compartment, and wherein the composite seal circumferentially engages with overlying adjacent heavy oil in the primary heavy oil compartment so that the composite seal and the overlying adjacent heavy oil together form the permeability barrier.

5. The process of claim 1, wherein the composite seal partitions the secondary zone into a proximal portion and a distal portion such that the permeability barrier hydraulically confines the primary heavy oil compartment and the proximal portion of the secondary zone from the distal portion of the secondary zone.

6. The process of any one of claims 1 to 5, wherein the solvent-based recovery technique comprises a solvent-only recovery technique.

7. The process of any one of claims 1 to 6, wherein a mobilizing fluid delivers the buoyant solvent to the primary heavy oil compartment.

8. The process of claim 7, wherein the mobilizing fluid comprises steam.

9. The process of any one of claims 1 to 8, wherein the solvent-based recovery technique comprises a staged hybrid recovery technique comprising a thermal recovery stage and a solvent recovery stage.

10. The process of claim 9, wherein the thermal recovery stage comprises a SAGD
recovery technique.

11. The process of any one of claims 1 to 10, wherein the solvent-based recovery technique comprises a reduced-temperature solvent recovery stage.

12. The process of claim 11, wherein the reduced-temperature solvent recovery stage is carried out at or below a temperature of about 140°C.

13. The process of any one of claims 1 to 12, wherein the secondary zone comprises a water zone.

14. The process of any one of claims 1 to 13, wherein the secondary zone comprises a gas zone.

15. The process of any one of claim 1 to 14, wherein the secondary zone comprises a vertical fluid flow barrier, a horizontal fluid flow barrier, or a combination thereof.

16. The process of any one of claims 1 to 15, wherein the secondary zone comprises a depleted recovery chamber.

17. The process of any one of claims 1 to 16, wherein the secondary zone comprises a heavy oil zone that is mobile to displacement with the blocking agent.

18. The process of any one of claims 1 to 17, wherein the blocking agent has a viscosity of from about 100 cP to 800 cP.

19. The process of any one of claims 1 to 18, wherein the blocking agent hardens to form the composite seal.

20. The process of any one of claims 1 to 19, wherein the blocking agent comprises a cementitious material.

21. The process of any one of claims 1 to 19, wherein the blocking agent comprises a thermally set blocking agent, a chemically set blocking agent, or a combination thereof.

22. The process of any one of claims 1 to 19, wherein the blocking agent comprises a polymeric resin.

23. The process of claim 22, wherein the polymeric resin comprises an epoxy resin, a phenolic resin, or a furan resin.

24. The process of any one of claims 1 to 23, wherein the blocking agent comprises a gel.

25. The process of any one of claims 1 to 24, wherein the blocking agent comprises a wax.

26. The process of any one of claims 1 to 25, wherein the blocking agent comprises a mixture of blocking agent components.

27. The process of claim 26, wherein at least two blocking agent components are injected in series.

28. The process of claim 26, wherein at least two blocking agent components are injected in combination.

29. The process of any one of claims 26 to 28, wherein the blocking agent components comprise a chemical activating agent.

30. The process of claim 29, wherein the chemical activating agent comprises a curing agent, a hardener, a catalyst, a crosslinker, or a combination thereof.

31. The process of any one of claims 1 to 30, wherein the blocking agent injection well comprises a lateral well.

32. The process of any one of claims 1 to 31, wherein the blocking agent injection well is a plurality of blocking agent injections wells, and wherein the blocking agent injection wells comprise lateral wells which are positioned about a circumference of the primary heavy oil compartment.

33. The process of any one of claims 1 to 31, wherein the blocking agent injection well comprises a sidetrack well.

34. The process of any one of claims 1 to 33, wherein the solvent-based recovery technique is applied after injecting the blocking agent.

35. The process of any one of claims 1 to 34, wherein the solvent-based recovery technique is applied before injecting the blocking agent.

36. The process of any one of claims 1 to 35, wherein the solvent-based recovery technique is applied during injecting the blocking agent.

37. The process of any one of claims 1 to 36, wherein injecting the blocking agent comprises multiple temporally discrete injection steps.

38. The process of any one of claims 1 to 37, wherein monitoring discloses a breach in the integrity of the composite seal or the permeability barrier, further comprising a step of injecting blocking agent to augment the composite seal and the permeability barrier.

39. The process of any one of claims 1 to 38, wherein the primary heavy oil compartment is a thin primary recovery zone.