CA3072787A1 - Process for producing hydrocarbons from a subterranean hydrocarbon-bearing formation including a generally fluid-impermeable zone - Google Patents

Abstract

A system for recovering hydrocarbons from a hydrocarbon-bearing formation is provided. The system includes an injection well extending into the hydrocarbon-bearing formation, and a production well extending into the hydrocarbon-bearing formation and vertically offset from the injection well. A portion of the injection well is separated from a portion of the production well by a generally fluid-impermeable zone. An intermediary conduit extends through the generally fluid-impermeable zone, at a depth that varies along the length of the intermediary conduit, to provide fluid communication between fluid-permeable zones within the hydrocarbon-bearing formation separated by the fluid-impermeable zone. The intermediary conduit is unconnected to the injection well and to the production well.

Description

PROCESS FOR PRODUCING HYDROCARBONS FROM A SUBTERRANEAN
HYDROCARBON-BEARING FORMATION INCLUDING A GENERALLY FLUID-IMPERMEABLE ZONE
Technical Field [0001] The present invention relates to the production of hydrocarbons such as heavy oils and bitumen from a hydrocarbon-bearing formation including fluid-permeable and generally fluid-impermeable zones.
Background

[0002] Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the northern Alberta oil sands that are not susceptible to standard oil well production technologies. The hydrocarbons in reservoirs of such deposits are too viscous to flow at commercially relevant rates at the virgin temperatures and pressures present in the reservoir. For such reservoirs, thermal techniques may be utilized to heat the reservoir.to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells. One such technique for utilizing a horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.

[0003] One thermal method of recovering viscous hydrocarbons utilizing spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). In the SAGD process, pressurized steam is delivered through an upper, horizontal, injection well, also referred to as an injector, into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well, also referred to as a producer, that is near the injection well and is vertically spaced from the injection well. The injection and production wells are situated in the lower portion of the reservoir, with the producer located close to the base of the hydrocarbon reservoir to collect the hydrocarbons that flow toward the base of the reservoir.

[0004] The SAGD process is believed to work as follows. The injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term steam chamber is utilized to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained. As the steam chamber expands, viscous hydrocarbons in the reservoir and water originally present in the reservoir are heated and mobilized and move with aqueous condensate, under the effect of gravity, toward the bottom of the steam chamber. The hydrocarbons, the water originally present, and the aqueous condensate are typically referred to collectively as emulsion. The emulsion accumulates and is collected and produced from the production well. The produced emulsion is separated into dry oil for sales and produced water, comprising the water originally present and the aqueous condensate.
* [0005] Ideally, the steam chamber grows generally upwardly and laterally outwardly as steam injection continues. Because of the complex nature of the reservoirs, however, the steam chamber growth may not be ideal and steam may be inhibited from reaching zones within the reservoir. Thus, mobilizing of the hydrocarbons in some zones may be difficult. Indeed, reservoirs may include fluid-impermeable zones or zones with low fluid permeability, referred to generally as fluid-impermeable zones, through which steam and hydrocarbons do not flow, and such fluid-impermeable zones may inhibit the growth of the steam chamber into fluid-permeable zones.
[0006] Hydrocarbons are commonly left unrecovered, resulting in relatively low recovery. The unrecovered hydrocarbons are due, at least in part, to the fluid-impermeable zones inhibiting fluid flow into and out of fluid-permeable zones. In particular, steam chamber growth and mobilized hydrocarbon production may be inhibited by the fluid-impermeable zones.
[0007] Improvements in recovery of hydrocarbons are desirable.

Summary [0008] According to an aspect of an embodiment, a system is provided for recovering hydrocarbons from a hydrocarbon-bearing formation. The system includes an injection well extending into the hydrocarbon-bearing formation, and a production well extending into the hydrocarbon-bearing formation and vertically offset from the injection well. A portion of the injection well is separated from a portion of the production well by a generally fluid-impermeable zone. An intermediary conduit is disposed at a depth that varies along a length of the intermediary conduit and the intermediary conduit extends through the generally fluid-impermeable zone, to provide fluid communication between fluid-permeable zones within the hydrocarbon-bearing formation separated by the fluid-impermeable zone. The intermediary conduit is unconnected to the injection well and to the production well.
[0009] According to another aspect, a process is provided for recovering hydrocarbons from a hydrocarbon-bearing formation. The process includes drilling an injection well that extends into the hydrocarbon-bearing formation and a production well that extends into the hydrocarbon-bearing formation. A
portion of the injection well is separated from a portion of the production well by a generally fluid-impermeable zone. The process also includes drilling an intermediary conduit that extends at a depth that varies along a length of the intermediary conduit such that the intermediary conduit extends through the generally fluid-impermeable zone, to join fluid-permeable zones within the hydrocarbon-bearing formation. The intermediary conduit is unconnected to the injection well and to the production well. At least some of the hydrocarbons in the hydrocarbon-bearing formation are mobilized by injecting mobilizing fluid through the injection well and allowing mobilizing fluid to pass through the intermediary conduit. Fluids, including the mobilizing fluid and mobilized hydrocarbons, are produced through the production well.

[0010] According to another aspect, a process is provided for recovering hydrocarbons from a hydrocarbon-bearing formation. The process includes drilling at least one well that extends in the hydrocarbon-bearing formation, into a first fluid-permeable zone within the hydrocarbon-bearing formation, drilling an intermediary conduit via the at least one well, the intermediary conduit extending at a depth that varies along a length of the intermediary conduit such that the intermediary conduit extends through a generally fluid-impermeable zone, joining the first fluid-permeable zone into which the at least one well extends, to a second fluid-permeable zone separated from the first fluid-permeable zone by the fluid-impermeable zone, the intermediary conduit being unconnected to the at least one well by any liner or screen, mobilizing at least some of the hydrocarbons in the hydrocarbon-bearing formation by injection mobilizing fluid through the at least one well and allowing mobilizing fluid to pass through the intermediary conduit, and producing fluids, including the mobilizing fluid and mobilized hydrocarbons, through the at least one well.
[0011] According to yet another aspect, there is provided a method of improving conformance of a steam chamber in a hydrocarbon-bearing formation that includes an injection well and a production well extending into the hydrocarbon-bearing formation. A portion of the injection well is separated from a portion of the production well by a generally fluid-impermeable zone. The method includes drilling an intermediary conduit via the injection well or the production well, the intermediary conduit extending at a depth that varies along a length of the intermediary conduit such that the intermediary conduit extends through the generally fluid-impermeable zone, to join fluid-permeable zones within the hydrocarbon-bearing formation, the intermediary conduit being unconnected to the injection well and to the production well by any liner or screen, and injecting steam into the hydrocarbon-bearing formation via the injection well and allowing the steam to pass through the intermediary conduit.

Brief Description of the Drawings [0012] Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description, in which:
[0013] FIG. 1 is a schematic sectional view of a system including a single well in accordance with one example of the present invention;
[0014] FIG. 2 is a flowchart illustrating a process for producing hydrocarbons from a hydrocarbon bearing formation, in accordance with an aspect of the present invention;
[0015] FIG. 3 is a schematic diagram illustrating the horizontal permeability within a model of a hydrocarbon-bearing formation, absent an intermediary conduit;
[0016] FIG. 4 is a schematic diagram illustrating the horizontal permeability within a model of a hydrocarbon-bearing formation, including an intermediary conduit;
[0017] FIG. 5A and FIG. 58 are schematic diagrams illustrating the vertical permeability within the model of the hydrocarbon-bearing formation of FIG. 3;
[0018] FIG. 6 is a schematic diagram illustrating the vertical permeability within the model of the hydrocarbon-bearing formation of FIG. 4;
[0019] FIG. 7, FIG. 9, FIG. 11, FIG. 13, FIG. 15, and FIG. 17, illustrate temperature profiles within the formation shown. in FIG. 3 and FIG. 5, at different times after 4 years of steam injection and production in the SAGD operation, absent any intermediary conduit;
[0020] FIG. 8, FIG. 10, FIG. 12, FIG. 14, FIG. 16, and FIG. 18 show the temperature profiles at different times within the formation shown in FIG. 4 and FIG. 6, in which SAGD production is carried out for 4 years prior to drilling and completing the intermediary conduit;

- 5 -[0021] FIG. 19, FIG. 21, FIG. 23, FIG. 25, FIG. 27, and FIG. 29, illustrate oil saturation profiles within the formation shown in FIG. 3, and FIG. 5, at different times after 4 years of steam injection and production in the SAGD
operation, absent any intermediary conduit;
[0022] FIG. 20, FIG. 22, FIG. 24, FIG. 26, FIG. 28, and FIG. 30 show the oil saturation profiles at different times within the formation shown in FIG.
4 and FIG. 6, in which SAGD production is carried out for 4 years prior to drilling and completing the intermediary conduit;
[0023] FIG. 31 is a graph showing the production rates in tonnes/day over time for the example of FIG. 3 and the example of FIG. 4 for half symmetry model;
[0024] FIG. 32 is a graph showing the energy equivalent of the cumulative steam to oil ratio over time for the example of FIG. 3 and the example of FIG.

for half symmetry model;
[0025] FIG. 33 shows temperature profiles along the length of a production well separated from the injection well by a fluid-impermeable layer and a production well, absent an intermediary conduit, and along the length of a production well in the same formation and including intermediary conduits in a pilot;
[0026] FIG. 34 shows temperature profiles along the length of the production well at various intervals of production after drilling the intermediary conduits in the pilot of FIG. 33.
Detailed Description [0027] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not

- 6 -described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.
[0028] The disclosure generally relates to a system and a process for recovering hydrocarbons from a hydrocarbon-bearing formation. The system includes an injection well extending into the hydrocarbon-bearing formation, and a production well extending into the hydrocarbon-bearing formation and vertically offset from the injection well. A portion of the injection well may be separated from a portion of the production well by a generally fluid-impermeable zone. An intermediary conduit is disposed generally vertically between the injection well and the production well. A depth of the intermediary conduit varies along a length of the intermediary conduit and the intermediary conduit extends through the generally fluid-impermeable zone, to provide fluid communication between fluid-permeable zones within the hydrocarbon-bearing formation separated by the fluid-impermeable zone. The intermediary conduit is unconnected to the injection well and to the production well.
[0029] Reference is made throughout the present application to fluid-impermeable zones. The term fluid-impermeable in the present application includes zones that exhibit some fluid permeability, though generally low fluid-permeability such that the use of mobilizing fluids to pass through such zones to mobilize hydrocarbons is considered uneconomical. Thus, zones or regions in which fluids are inhibited from entering or passing through during injection to mobilize hydrocarbons, are referred to generally as fluid-impermeable. During steam injection for example, a zone in which further steam chamber growth is inhibited is referred to herein as a fluid-impermeable zone.
[0030] Referring first to FIG. 1, a schematic view of an example of a system 100 is shown, including an injection well 102 for injecting a mobilizing fluid into the formation. The injection well 102 includes a generally vertical portion that extends from a wellhead (not shown) to a heel 104 and a generally horizontal portion 106 that extends from the heel 104 to a toe 108. The

- 7 -horizontal portion 106 of the injection well 102 is lined with a suitable liner, such as a slotted liner, through which mobilizing fluid is injected into the formation.
[0031] A production well 112 is utilized for producing fluids, including the mobilizing fluid and mobilized hydrocarbons from the formation. The production well 112 includes a generally vertical portion that extends from a wellhead (not shown) to a heel 114 and a generally horizontal portion 116 that extends from the heel 114 to the toe 118. The horizontal portion 116 of the production well 112 is lined with a suitable liner, such as a slotted liner, through which mobilized fluids enter the production well 112. The horizontal portion 116 of the production well 112 is disposed generally vertically below the horizontal portion 106 of the injection well 102 and is spaced therefrom.
[0032] A portion of the injection well 102, which in the present example is the toe 108 of the injection well 102, is separated from at least a portion of the production well 112, by a fluid-impermeable zone 124. The fluid-impermeable zone 124 may be any shape and is schematically represented in FIG. 1 to illustrate that the fluid-impermeable zone 124 separates the fluid-permeable zone 126 around the toe 108 of the injection well 102 from the fluid-permeable zone 126 around the toe 118 of the production well 112. The dashed lines in FIG. 1 are utilized to illustrate that the fluid-impermeable zone 124 extends laterally in the formation, separating the toe 108 of the injection well 102 from the toe 118 of the production well 112. The fluid-impermeable zone 124 separating the fluid-permeable zones 126 inhibits mobilizing fluid injection into the formation near the toe 108 of the injection and mobilizing fluid chamber growth around the end portion, including the toe, of the injection well 102 as fluids are inhibited from flowing downwardly into the production well 118.
[0033] An intermediary conduit 122 is disposed generally vertically between the horizontal portion 106 of the injection well 102 and the horizontal portion 116 of the production well 112 and laterally offset therefrom such that the intermediary conduit 122 is not disposed directly between the injection well 102 and the production well 112. Instead, the intermediary conduit 122 is

- 8 -offset, for example, by from about 2 meters to about 40 meters depending on well geology and maturity of the well. In the schematic illustration of FIG.
1, the intermediary conduit 122 is offset from the horizontal portion 106 of the injection well 102 and the horizontal portion 116 of the production well 11.2 by about 5 meters in the X direction.
[0034] The depth of intermediary conduit 122 varies along the length.
In this particular example, portions of the intermediary conduit 122 are closer to the horizontal portion 106 of the injection well 102 and other portions of the intermediary conduit 122 are closer to the horizontal portion 116 of the production well 112. The intermediary conduit 122 extends through the fluid-impermeable zone and includes portions in fluid-permeable zones on either side of the fluid-impermeable zone. The intermediary conduit 122 may follow a wave pattern, for example, a sine or cosine wave pattern or similar pattern, as illustrated in FIG. 1, resulting in the varying depth of the intermediary conduit 122 such that the intermediary conduit 122 extends through the generally fluid-impermeable zone a plurality of times, to join the fluid-permeable zones.
Other patterns or other paths of varying depth, such as a stepped pattern or function, an S shape, a square, logarithmic, cubic, or other function, may be successfully implemented. In addition, the location of the intermediary conduit may vary, along the length of the intermediary conduit, in the x direction. Thus, the intermediary conduit may vary in more than one direction. The intermediary conduit may follow a path or pattern of any combination of the above functions or mirror images of these functions. In addition, the path can follow any direction in three dimensions x (laterally to the well pair), y (along the well pair) and z (perpendicular to the well direction), or at any angle (0 - 360 ).
[0035] The intermediary conduit is generally drilled such that the portions of the intermediary conduit 122 are closer to the horizontal portion 106 of the injection well 102 are generally sufficiently close to be within a region heated by the injection well 102.

- 9 -[0036] The intermediary conduit may be any suitable length, for example, about 5 meters to about 2000 meters and is dependent on the size of the fluid-impermeable zone. In a particular example, the intermediary conduit is about 350 to about 400 meters in length.
[0037] The intermediary conduit 122 to maintain fluid communication through the intermediary conduit 122. The intermediary conduit may be completed with a suitable liner, such as a slotted liner, a precision punched screen (PPS) liner, or wire wrap, to maintain fluid communication through the fluid-impermeable zone 124 and between the fluid-permeable zones 126. The intermediary conduit 122 may be drilled utilizing either the injection well 102 or the production well 112. The intermediary conduit 122 is completed such that the completed intermediary conduit 122 is not connected to the injection well 102 or to the production well 112 by a liner. Thus, for example, in the case in which the intermediary conduit 122 is drilled utilizing the production well, 112, a length between the production well 112 and the intermediary conduit 122 is not completed with a liner and allowed to fill back in such that the production well 112 and the intermediary conduit 122 are unconnected, i.e., not joined by a length of pipe.
[0038] Although the intermediary conduit 122 is unconnected to the injection well 102 by a lined pipe, and is unconnected to the production well by a lined pipe, the intermediary conduit 122 is in fluid communication with both the injection well 102 and the production well 112 through the fluid-permeable zones 126 in the formation.
[0039] The completed intermediary conduit 122 may be any suitable diameter up to the diameter of the well that is utilized to drill the intermediary conduit. In the example in which the production well is utilized to drill and complete the intermediary conduit 122, the liner may be any suitable diameter up to the diameter of the production well. A liner of about 4.5 inches in diameter, for example, may be utilized. In the example in which the injection

- 10 -well is utilized to drill and complete the intermediary conduit 122, the liner may be any suitable diameter up to the diameter of the injection well.
[0040] Inflow control devices may be utilized in the production well 112 to control the flow of the fluids produced from the hydrocarbon-bearing formation into the production well 112. Inflow control devices may be particularly useful in ensuring that mobilized hydrocarbons are drained from low points or specific locations along the production well, for example. In addition, flow control devices may be utilized in the injection well 102 for controlling the flow of the mobilizing fluid or fluids injected into the hydrocarbon-bearing formation.
Flow control devices may be located in the injection well 102 to reduce the chance of short-circuiting, in which the mobilizing fluid, such as steam, moves through the intermediary conduit 122 and generally directly to the production well. The flow control devices can also be moved within the injection well to reduce such short-circuiting. In addition, the intermediary conduit 122 may be located such that the portions of the intermediary conduit 122 that are closer to the horizontal portion 106 of the injection well 102, are located to reduce the chance of short-circuiting. Thus, these portions of the intermediary conduit 122 may be located away from flow control devices in the injection well 102.
[0041] The intermediary conduit 122 may be any suitable length to provide the fluid communication to provide the fluid communication between the fluid-permeable zones 126 in the formation, i.e., through the fluid-impermeable zone 124.
[0042] A flowchart illustrating a process for producing hydrocarbons from a hydrocarbon bearing formation, such as that shown in FIG. 1, is illustrated in FIG. 2. The process may contain additional or fewer subprocesses than shown or described, and parts of the process may be performed in a different order.
[0043] The injection well 102 and the production well 112 are drilled and completed with a liner at 202, as described above, such that the horizontal portion 106 of the injection well 102 is disposed generally vertically above the horizontal portion 116 of the production well 112 and is spaced therefrom.

-11 -[0044] The intermediary conduit 122 is drilled and completed at 204 utilizing, for example, the production well 112, such that the intermediary conduit is disposed generally vertically between the horizontal portion 106 of the injection well 102 and the horizontal portion 116 of the production well 112 and laterally offset from both, as described above. The intermediary conduit may be drilled in the process of drilling the initial production well and injection well and prior to carrying out any hydrocarbon recovery operation. Alternatively, the intermediary conduit may be drilled after carrying out a hydrocarbon recovery operation such as SAGD or other process for a period of time. The intermediary conduit may be drilled at a same time as redrilling a production well or may be drilled at a different time. For example, in instances in which a new production well is drilled, the intermediary conduit may be drilled from the producer in the process of redrilling the production well.
[0045] Alternatively, the intermediary conduit may be drilled and completed without utilizing the injection well 102 or the production well 112.
[0046] The intermediary conduit 122 is drilled at a depth that varies along the length of the intermediary conduit 122 such that portions of the intermediary conduit 122 extend into the fluid-permeable zone into which the horizontal portion 106 of the injection well 102 extends and other portions of the intermediary conduit extend into the fluid-permeable zone into which the horizontal portion 116 of the production well 112 extends. In the example shown in FIG. 1, portions of the intermediary conduit are closer to the horizontal portion 106 of the injection well 102 and other portions of the intermediary conduit 122 are closer to the horizontal portion 116 of the production well 112.
These portions of the intermediary conduit 122 that extend into the fluid-permeable zone into which the horizontal portion 106 of the injection well 102 extends, provide fluid communication between the injection well 102 and the intermediary conduit 122. The other portions of the intermediary conduit that extend into the fluid-permeable zone into which the horizontal portion 116 of the production well 112 extends, provide fluid communication between the production well 112 and the intermediary conduit 122. Thus, the intermediary

- 12 -conduit 122 is drilled through the generally fluid-impermeable zone 124, providing fluid communication between fluid-permeable zones 126 and through the fluid-impermeable zone 124.
[0047] As indicated above, the intermediary conduit 122 is completed with a liner, to maintain fluid communication through the fluid-impermeable zone and between the fluid-permeable zones 126 but is unconnected by any pipe or liner to the production well 112 or to the injection well 102.
[0048] A mobilizing fluid is injected at 206 via the injection well 102. The mobilizing fluid may be steam, as utilized in a SAGD operation. In addition to steam injection into the injection well 102, light hydrocarbons, such as the through C10 alkanes, either individually or in combination, may optionally be injected with the steam such that the light hydrocarbons function as solvents in aiding the mobilization of the hydrocarbons. The volume of light hydrocarbons that are injected may be relatively small compared to the volume of steam injected. The addition of light hydrocarbons is referred to as a solvent aided process (SAP). Alternatively, or in addition to the light hydrocarbons, various non-condensing gases, such as methane or carbon dioxide, may be injected.
Viscous hydrocarbons in the reservoir are heated and mobilized and the mobilized hydrocarbons drain under the effect of gravity. A solvent driven process in which a greater volume of light hydrocarbons is injected compared to the volume of steam, may alternatively be utilized to mobilize the hydrocarbons.
The mobilizing fluid utilized may be dependent on reservoir. The mobilizing fluid may further contain other additives such as surfactants, non-condensing gases, etc.
[0049] Fluids are produced at 208. The produced fluids include mobilized hydrocarbons as well as mobilizing fluid, such as water condensed from the steam, connate water, and mobilized hydrocarbons, in an emulsion.
[0050] Flow into production tubing included in the production well 112 may be controlled utilizing flow control devices at ports along the production tubing.
Optionally, flow of steam into the formation may be controlled utilizing flow

- 13 -control device along injection tubing disposed in the injection well 102.
Thus, flow control devices may be utilized to improve recovery in the reservoir. For example, mobilizing fluid, such as steam, may be directed to the toe 108 of the injection well 102. The intermediary conduit 122 provides the fluid communication between the fluid-permeable zones 126 that are separated by a general fluid-impermeable zone, such as the zone 124. In addition to inflow control devices utilized in the production well and flow control devices utilized in the injection well, packers, and upper production ports may be utilized to control the flow of fluids to improve conformance.
[0051] More than one intermediary conduit may also be utilized to provide fluid communication through a fluid-impermeable zone or zones. In the description of the system illustrated in FIG. 1 and the process illustrated in FIG.
2, a single intermediary conduit 122 is illustrated and described. Further intermediary conduits 122 may be successfully drilled, completed, and employed.
[0052] For example, a further intermediary conduit may be disposed generally vertically between the horizontal portion 106 of the injection well and the horizontal portion 116 of the production well 112 and laterally offset therefrom, on an opposite side of the injection well 102 and the production well 112. As with the intermediary conduit 122, the further intermediary conduit is not disposed directly between the injection well 102 and the production well 112. Instead, the further intermediary conduit is offset, for example, by from about 2 meters to about 40 meters depending on well geology and maturity of the well. Additionally or alternatively, vertical wells or deviated wells may be drilled at different distances and perforated above and below the fluid-impermeable zone. Such vertical wells may be utilized to provide fluid communication between fluid-permeable zones separated by a fluid-impermeable zone. Optionally, the intermediate conduit may include one or more laterals extending therefrom.
[0053] The depth of further intermediary conduit also varies along the length such that portions of the further intermediary conduit extend into the

- 14 -fluid-permeable zone into which the horizontal portion 106 of the injection well 102 extends, and other portions of the further intermediary conduit extend into the fluid permeable zone into which the horizontal portion 116 of the production well 112 extends. The further intermediary conduit may follow, for example, a sine wave pattern or similar pattern, resulting in the varying depth of the further intermediary conduit. Other patterns such as a stepped pattern or an S shape or S pattern, or other paths of varying depth may be successfully implemented.
[0054] The further intermediary conduit is also completed with a suitable liner, such as a slotted liner, a precision punched screen (PPS) liner, or wire wrap, to maintain fluid communication through the fluid-impermeable zone 124 and between the fluid-permeable zones 126. The further intermediary conduit is completed such that the completed further intermediary conduit is not connected to the injection well 102 or to the production well 112. Thus, for example, in the case in which the further intermediary conduit is drilled utilizing the production well, 112, a length between the production well 112 and the further intermediary conduit is not completed with a liner and allowed to fill back in such that the production well 112 and the further intermediary conduit are unconnected, i.e., not joined by a length of pipe.
[0055] In the description above, the production occurs as injection continues. The injection and production, however, need not be carried out simultaneously. For example, the production may be carried out after a period of injection. The injection and production therefore may be carried out alternatingly.
[0056] In the examples described above, the intermediary conduit is utilized with an injection well and a production well. In addition, the intermediary conduit may be utilized in a single well application, including a cyclic steam stimulation (CSS) in which steam is inhibited from passing into a fluid-permeable zone by a fluid-impermeable zone. In this example, a single well is utilized for both injection of steam, and production of fluids, which include hydrocarbons. The intermediary conduit is offset from the single well and

- 15 -extends at a depth that varies along a length of the intermediary conduit such that the intermediary conduit extends through a generally fluid-impermeable zone, joining the first fluid-permeable zone into which the single well extends, to a second fluid-permeable zone separated from the first fluid-permeable zone by the fluid-impermeable zone. As described above, the intermediary conduit is unconnected to the single well. At least some of the hydrocarbons in the hydrocarbon-bearing formation are mobilized by injection mobilizing fluid through the single well and allowing mobilizing fluid to pass through the intermediary conduit. Fluids are produced, including the steam and mobilized hydrocarbons, through the single well. As in the examples described above, the intermediary conduit generally follows a sine wave or stepped pattern or S-shape. The intermediary conduit is completed with a liner. Flow control devices may also be utilized to control the flow of fluids into and out of the single well.
[0057] The produced fluids may be treated at the surface to separate the hydrocarbons produced from the mobilizing fluid, in a mobilizing fluid recovery facility. The mobilizing fluid may then be recycled back by re-injecting into the reservoir for mobilizing further hydrocarbons.
[0058] In the example described above with reference to FIG. 1, the fluid-impermeable zone is disposed between the horizontal portion 106 of the injection well 102 and the horizontal portion 116 of the production well 112. The fluid-impermeable zone may also be disposed elsewhere in the reservoir, separating two fluid permeable zones, and thereby separating the injection well and production well from a portion of the reservoir. One or more intermediary conduits may be utilized to access additional hydrocarbons that are generally accessible or not financially feasible to access because the fluid-impermeable zone blocks access.
[0059] It will be appreciated that such fluid-impermeable zones may be any shape or size and may be discontinuous within the formation.
[0060] Advantageously, the use of an additional well, referred to herein as the intermediary conduit, that is laterally offset from the injection and production

- 16 -wells and thus not connected by a completed or lined pipe to either the injection well or the production well, provides fluid communication through a fluid-impermeable zone or zones. The intermediary conduit facilitates access to additional hydrocarbon formations or portions of formations that are otherwise not accessible or not financially feasible to access. Such an intermediary conduit improves conformance and accelerates production of fluids, including mobilized hydrocarbons in reservoirs that are otherwise considered poor quality or not economically viable. Steam is therefore utilized more efficiently providing improved steam to oil ratio by comparison to poor quality reservoirs that do not include such an intermediary conduit.
[0061] Hydrocarbons that are difficult to recover at least in part, to the fluid-impermeable zones inhibiting fluid flow into and out of fluid-permeable zones, and hydrocarbons in secondary pay zones that are smaller than rich pay zones, may be accessed and recovered utilizing one or more intermediary conduits.
EXAMPLES:
Modelling [0062] Reservoir simulations were performed to demonstrate the process.

Simulation parameters utilized are included in Table 1 below.
Table 1: Simulation Parameters Rich Pay thickness 22m Well Spacing 100m Well Length 900m Symmetry Half symmetry Model grid Block Dimensions 26X26X27 (2mX50mX1m) (X,Y,Z) Porosity 0 - 35%
Reservoir Temperature 12 C

- 17 -Reservoir Pressure 3 MPa Initial Oil Saturation 50-85%
Vertical Permeability 0.00 - 6 Darcy Horizontal Permeability 0.00 - 5 Darcy Methane mole fraction in Oleic 16%
Phase [0063] FIG. 3 shows the horizontal permeability within a model of a hydrocarbon-bearing formation. A horizontal portion 106 of an injection well and a horizontal portion 116 of a production well 112 are shown. The model of the hydrocarbon-bearing formation includes fluid-permeable zones 126 illustrated by the white or light regions, and a fluid-impermeable zone 124 illustrated by the darker regions. A fluid-impermeable zone 124 acts as a fluid flow barrier between the injection well 102 and the production well 112.
[0064] FIG. 4 shows the horizontal permeability within a model of a hydrocarbon-bearing formation. A horizontal portion 106 of an injection well and a horizontal portion 116 of a production well 112 are shown. The model shown in FIG. 4 is identical to that shown in FIG. 3, except that the model illustrated in FIG. 4 includes the intermediary conduit 122 that extends at a depth that varies along a length of the intermediary conduit such that the intermediary conduit 122 is disposed generally vertically between the injection well 102 and the production well 112, and laterally offset by 5 meters from the injection well 102 and the production well 112. The intermediary conduit 122 extends through the generally fluid-impermeable zone 124, to join fluid-permeable zones 126 within the hydrocarbon-bearing formation. In the present example, the intermediary conduit 122 forms a sine wave pattern.
Alternatively, the intermediary conduit may be stepped or in a step pattern, or an S-shaped pattern.
[0065] FIG. 5A shows the vertical permeability within the model of the hydrocarbon-bearing formation of FIG. 3. As with FIG. 3, the hydrocarbon-

- 18 -bearing formation includes the fluid-permeable zones 126 illustrated by the white or light regions, and the fluid-impermeable zone 124 illustrated by the dark regions. The fluid-impermeable zone 124 acts as a fluid flow barrier between the injection well 102 and the production well 112.
[0066] FIG. 58 shows the vertical permeability within the model of the hydrocarbon-bearing formation, similar to FIG. 5A, viewed from a different angle to illustrate the continuity of the fluid-impermeable zone 124.
[0067] FIG. 6 shows the vertical permeability within the model of the hydrocarbon-bearing formation of FIG. 4, including the intermediary conduit 122.
As with FIG. 4, the hydrocarbon-bearing formation includes the fluid-permeable zones 126 illustrated by the white or light regions, and the fluid-impermeable zone 124 illustrated by the dark regions. The fluid-impermeable zone 124 acts as a fluid flow barrier between the injection well 102 and the production well 112. The intermediary conduit 122 extends through the generally fluid-impermeable zone 124, to join fluid-permeable zones 126 within the hydrocarbon-bearing formation.
[0068] FIG. 7 and FIG. 8 through FIG. 17 and FIG. 18 illustrate temperature profiles within the formation shown in FIG. 3 and FIG. 4, during the injection of steam for heating and mobilizing the hydrocarbons, at different times after beginning production.
[0069] FIG. 7, FIG. 9, FIG. 11, FIG. 13, FIG. 15, and FIG. 17, illustrate temperature profiles within the formation shown in FIG. 3 and FIG. 5, at different times after 4 years of steam injection and production in the SAGD operation, absent any intermediary conduit. In particular, FIG. 7, FIG. 9, FIG. 11, FIG.
13, FIG. 15, and FIG. 17 illustrate the temperature profiles at 4 years, 5 years, years, 7 years, 8 years, and 9 years, respectively.
[0070] FIG. 8, FIG. 10, FIG. 12, FIG. 14, FIG. 16, and FIG. 18 show the temperature profiles within the formation shown in FIG. 4 and FIG. 6, in which SAGD production is carried out for 4 years prior to drilling and completing the intermediary conduit 122. In particular, FIG. 8, FIG. 10, FIG. 12, FIG. 14, FIG.

- 19 -16, and FIG. 18 illustrate the temperature profiles at 4 years (at the time the intermediary conduit 122 is drilled and completed), 5 years (1 year after completion of the intermediary conduit 122), 6 years (2 years after completion of the intermediary conduit 122), 7 years (3 years after completion of the intermediary conduit 122), 8 years (4 years after completion of the intermediary conduit 122), and 9 years (5 years after completion of the intermediary conduit 122), respectively.
[0071] Based on the temperature profiles in FIG. 7, FIG. 9, FIG. 11, FIG.
13, FIG. 15, and FIG. 17, little or no steam chamber growth occurs between the fourth and ninth years, which is a result blockage of fluid drainage to the production well 112 by the fluid-impermeable zone 124. Little or no heating of the fluid-permeable zones 126 above and below the fluid-impermeable zone 124 is observed.
[0072] Heating in the fluid-permeable zones 126 on either side of the fluid-impermeable zone 124, is markedly improved by the addition of the intermediary conduit 122. The temperature profiles in FIG. 8, FIG. 10, FIG. 12, FIG. 14, FIG.
16, and FIG. 18 show improved heating, and thus better conformance along the length of the injection well 102.
[0073] FIG. 19 and FIG. 20 through FIG. 29 and FIG. 30 illustrate oil saturation profiles within the formation shown in FIG. 3 and FIG. 4, during the injection of steam for heating and mobilizing the hydrocarbons, at different times after beginning production. The darker regions indicate regions of relatively low or no oil saturation and the light or white regions indicate higher oil saturation.
[0074] FIG. 19, FIG. 21, FIG. 23, FIG. 25, FIG. 27, and FIG. 29, illustrate oil saturation profiles within the formation shown in FIG. 3, and FIG. 5, at different times after 4 years of steam injection and production in the SAGD
operation, absent any intermediary conduit. In particular, FIG. 19, FIG. 21, FIG.
23, FIG. 25, FIG. 27, and FIG. 29 illustrate the temperature profiles at 4 years, 5 years, 6 years, 7 years, 8 years, and 9 years, respectively.

- 20 -[0075] FIG. 20, FIG. 22, FIG. 24, FIG. 26, FIG. 28, and FIG. 30 show the oil saturation profiles within the formation shown in FIG. 4 and FIG. 6, in which SAGD production is carried out for 4 years prior to drilling and completing the intermediary conduit 122. In particular, FIG. 20, FIG. 22, FIG. 24, FIG. 26, FIG.
28, and FIG. 30 illustrate the oil saturation profiles at 4 years (at the time the intermediary conduit 122 is drilled and completed), 5 years (1 year after completion of the intermediary conduit 122), 6 years (2 years after completion of the intermediary conduit 122), 7 years (3 years after completion of the intermediary conduit 122), 8 years (4 years after completion of the intermediary conduit 122), and 9 years (5 years after completion of the intermediary conduit 122), respectively.
[0076] Based on the oil saturation profiles in FIG. 19, FIG. 21, FIG.
23, FIG. 25, FIG. 27, and FIG. 29, little or no steam chamber growth occurs in the lateral direction, toward to the toe of the injection well between the fourth and ninth years, which is a result blockage of fluid drainage to the production well 112 by the fluid-impermeable zone 124. The fluid-permeable zones 126 on either side of the fluid-impermeable zone 124 remain saturated with oil.
[0077] FIG. 20, FIG. 22, FIG. 24, FIG. 26, FIG. 28, and FIG. 30, illustrate the reduction in oil saturation in the fluid-permeable zones 126 on either side of the fluid-impermeable zone 124, as conformance and oil recovery are markedly improved by the addition of the intermediary conduit 122.
[0078] FIG. 31 is a graph showing the production rates in tonnes/day over time for the example of FIG. 3 in which no intermediary conduit is utilized, and the example of FIG. 4 in which the intermediary conduit is completed after 4 years of production for half symmetry model. The rates illustrated are for the half symmetry model. For full symmetry, a second intermediary conduit would be included 5 meters laterally on the other side of the injection and production wells. The graph begins after 4 years of SAGD production. The solid line indicates production rate of bitumen beginning at 4 years. The dashed line indicates production rate of bitumen beginning immediately after completion of

-21 -the intermediary conduit, which is completed after 4 years of SAGD production.

Thus, the time scale on the graph begins after 4 years of SAGD production.
[0079] FIG. 32 is a graph showing the energy equivalent of the cumulative steam to oil ratio over time for the example of FIG. 3 in which no intermediary conduit is utilized, and the example of FIG. 4 in which the intermediary conduit is completed after 4 years of production for half symmetry model. As indicated above for FIG. 31, for full symmetry, a second intermediary conduit would be included 5 meters laterally on the other side of the injection and production wells. The graph begins after 4 years of SAGD production. The solid line indicates cumulative steam to oil ratio beginning at 4 years. The dashed line indicates cumulative steam to oil ratio beginning immediately after completion of the intermediary conduit, which is completed after 4 years of SAGD production.

Thus, the time scale on the graph begins after 4 years of SAGD production.
[0080] As illustrated by the half symmetry model of FIG. 31 and FIG.
32, the total production of bitumen increases dramatically utilizing the intermediary conduit by comparison to SAGD absent the intermediary conduit. The cumulative steam to oil ratio is also decreased, rendering the hydrocarbon recovery much more economic as hydrocarbons are recovered from areas that are otherwise inaccessible or uneconomic to access.
[0081] In the model examples described above, the intermediary conduit is drilled and completed after about 4 years of SAGD operation of the injection and production wells. Alternatively, the intermediary conduit may be drilled and completed at the time that the injection and production wells are drilled and completed. Drilling and completing prior to commencing operation is advantageous in that equipment required for such drilling and completing is available on site and downhole. Further, drilling and completing the intermediary conduit prior to commencing operation facilitates heating of the fluid-permeable zones near the toe of the injection well and the toe of the production well at an earlier stage, improving conformance.

- 22 -[0082] Inflow control devices may be utilized in the production well to control the flow of the fluids produced from the hydrocarbon-bearing formation into the production well 112. In addition, flow control devices may be utilized in the injection well for controlling the flow of the mobilizing fluid or fluids injected into the hydrocarbon-bearing formation, to further improve conformance.
[0083] As indicated above, the mobilizing fluid is not limited to steam.
In addition to steam injection, light hydrocarbons may optionally be injected with the steam such that the light hydrocarbons function as solvents in aiding the mobilization of the hydrocarbons. The volume of light hydrocarbons that are injected may be relatively small compared to the volume of steam injected.
Other additives such as surfactants or foaming agents may also be utilized. A
solvent driven process in which a greater volume of light hydrocarbons is injected compared to the volume of steam, may alternatively be utilized to mobilize the hydrocarbons.
Pilot [0084] The process was carried out for a reservoir in which a mud barrier exists between an injection well and a production well of a well pair, inhibiting the flow of fluid between the injection well and the production well.
[0085] Startup and SAGD were carried out for about four years prior to drilling of any intermediary conduit. A cumulative steam to oil ratio (CSOR) of about 5 for about a three-year period of production indicated inefficient recovery.
Seismic interpretations and log data from offset vertical wells confirmed the presence of an expansive, 800m long mud layer with the production well extending below the mud layer and the injection well intercepting the mud layer at about 400m from the heel of the injection well. Seismic acquisitions confirmed the lack of steam chamber growth within or above the mud layer.
[0086] The original production well failed and a new production well was drilled. A scab liner was installed in the production well with an upper production port (UPP) to facilitate fluid flow to the toe before entering the well to allow for heat transfer. The original production well extended from a heel

- 23 -between 800 m and 900 m along the length of the production well to about 1700 m. The new production well was drilled generally below the original production well to about 2100 m.
[0087] A Distributed Temperature Sensor (DTS) was utilized along the length of the production well to monitor temperature. Two intermediary conduits were drilled via the production well and extending through the generally fluid-impermeable mud layer, to join fluid-permeable zones at multiple locations along the length of the intermediary conduits, within the hydrocarbon-bearing formation. The intermediary conduits formed a sine wave pattern. The intermediary conduits were completed with a liner to maintain fluid communication through the fluid-impermeable mud layer and between the fluid-permeable zones. The intermediary conduits were completed such that a length between the new production well and each of the intermediary conduits was not completed with a liner and was allowed to fill back. Thus, the new production well and the intermediary conduits are unconnected, i.e., not joined by a length of pipe.
[0088] A new injection well was also drilled to establish the same lateral coverage as the new production well. SAGD was commenced again utilizing the new production well and the new injection well. The steam was injected in the new production well at 5 t/hr or 120 t/d with a pressure of 2980 Kpag.
[0089] FIG. 33 illustrates temperature profiles along the length of the original production well and the new production well. The lower temperature profile illustrates the temperature along the original production well prior to drilling the new production well, the new injection well, and the intermediary wells. The temperature profile was measured after a 24 hour shut-in period in which production was discontinued to allow stabilization of the well conditions.
The middle profile illustrates temperature along the new production well, after drilling the new production well, injection well, and intermediary wells and after production for about 4 months. The temperature profile was measured after a

24 hour shut-in period in which production was discontinued to allow stabilization of the well conditions. The upper temperature profile illustrates the temperature along the new production well during production.
[0090] FIG. 34 illustrates temperature profiles along the length of the new production well, after drilling the new production well, injection well, and intermediary wells, at intervals of about 1 month, 2 months, 3 months, and 4 months of production. The temperature profiles were measured after a 24 hour shut-in period in which production was discontinued to allow stabilization of the well conditions. The upper temperature profile illustrates the temperature along the new production well during production.
[0091] Based on the temperature profiles, the temperature across the length of the production well increased, approaching a more consistent temperature, and closer to the steam temperature. A significant rise in temperature was observed in areas in which the temperature in the original production well was lowest and in the final 400 meters of the new production well.
[0092] Steam chamber growth is expected to accompany the increase in temperature across the length of the new production well.
[0093] The use of the intermediary conduits, that are not connected by a completed or lined pipe to either the injection well or the production well, improves heating utilizing the injected mobilizing fluid. The intermediary conduits provide fluid communication through the fluid-impermeable mud layer and are expected to accelerate production of fluids, including mobilized hydrocarbons.

- 25 -

Claims (39)

Claims

1. A process for recovering hydrocarbons from a hydrocarbon-bearing formation, the process comprising:
drilling an injection well that extends into the hydrocarbon-bearing formation and a production well that extends into the hydrocarbon-bearing formation, wherein a portion of the injection well is separated from a portion of the production well by a generally fluid-impermeable zone;
drilling an intermediary conduit that extends at a depth that varies along a length of the intermediary conduit such that the intermediary conduit extends through the generally fluid-impermeable zone, to join fluid-permeable zones within the hydrocarbon-bearing formation, the intermediary conduit being unconnected to the injection well and to the production well;
mobilizing at least some of the hydrocarbons in the hydrocarbon-bearing formation by injection mobilizing fluid through the injection well and allowing mobilizing fluid to pass through the intermediary conduit;
producing fluids, including the mobilizing fluid and mobilized hydrocarbons, through the production well.

2. The process according to claim 1, comprising completing the intermediary conduit with a liner.

3. The process according to claim 1, wherein drilling the intermediary conduit comprises drilling such that the intermediary conduit is laterally offset from the injection well and the production well.

4. The process according to claim 1, wherein drilling the intermediary conduit comprises drilling such that the intermediary conduit extends at varying depth between the depth of the injection well and the depth of the production well and is laterally offset from the injection well and the production well.

5. The process according to claim 1, wherein drilling the intermediary conduit comprises drilling such that the intermediary conduit is laterally offset from the injection well and the production well by at least about 2 meters.

6. The process according to claim 1, wherein drilling the intermediary conduit comprises drilling in a generally wave pattern, stepped pattern, or S-shaped pattern such that the intermediary conduit extends through the generally fluid-impermeable zone a plurality of times, to join the fluid=permeable zones.

7. The process according to claim 1, comprising controlling the flow of the fluids produced from the hydrocarbon-bearing formation into the production well utilizing flow control devices.

8. The process according to claim 1, comprising controlling the flow of the fluids injected into the hydrocarbon-bearing formation from the injection well utilizing flow control devices.

9. The process according to claim 1, wherein drilling the intermediary conduit comprises drilling the intermediary conduit along a length of about 5 meters to about 2000 meters.

10. The process according to claim 1, comprising drilling at least one further intermediary conduit that extends at a depth that varies along a length of the intermediary conduit such that the at least one intermediary conduit extends through the generally fluid-impermeable zone, to join fluid-permeable zones within the hydrocarbon-bearing formation, the at least one further intermediary conduit being unconnected to the injection well and to the production well.

11. The process according to claim 10, comprising completing the at least one further intermediary conduit with a liner.

12. The process according to claim 10, wherein drilling the at least one further intermediary conduit comprises drilling such that the at least one further intermediary conduit is laterally offset from the injection well and the production well.

13. A system for recovering hydrocarbons from a hydrocarbon-bearing formation, the system comprising:
an injection well extending into the hydrocarbon-bearing formation;
a production well extending into the hydrocarbon-bearing formation and offset from the injection well, a portion of the injection well separated from a portion of the production well by a generally fluid-impermeable zone;
an intermediary conduit extending through the generally fluid-impermeable zone, at a depth that varies along the length of the intermediary conduit, to provide fluid communication between fluid-permeable zones within the hydrocarbon-bearing formation separated by the fluid-impermeable zone, wherein the intermediary conduit is unconnected to the injection well and to the production well.

14. The system according to claim 13, wherein the intermediary conduit is vertically between the injection well and the production well and laterally offset from the injection well and the production well.

15. The system according to claim 13, wherein the intermediary conduit is laterally offset from the injection well and the production well by at least about 2 meters.

16. The system according to claim 13, wherein the intermediary conduit is completed with a pipe liner.

17. The system according to claim 13, wherein the intermediary conduit generally follows a sine wave, or stepped pattern, or S shape.

18. The system according to claim 13, comprising flow control devices cooperating with the production well for controlling the flow of the fluids produced from the hydrocarbon-bearing formation into the production well.

19. The system according to claim 13, comprising flow control devices cooperating with the injection well for controlling the flow of the fluids injected into the hydrocarbon-bearing formation from the injection well.

20. The system according to claim 13, wherein the intermediary conduit is about meters to about 2000 meters in length.

21. The system according to claim 13, comprising at least one further intermediary conduit that extends at a depth that varies along a length of the intermediary conduit such that the at least one intermediary conduit extends through the generally fluid-impermeable zone, to join fluid-permeable zones within the hydrocarbon-bearing formation, the at least one further intermediary conduit being unconnected to the injection well and to the production well.

22. The system according to claim 13, wherein the at least one further intermediary conduit is vertically between the injection well.and the production well and laterally offset from the injection well and the production well.

23. The system according to claim 13, wherein the at least one further intermediary conduit is completed with a liner.

24. A process for recovering hydrocarbons from a hydrocarbon-bearing formation, the process comprising:
drilling at least one well that extends in the hydrocarbon-bearing formation, into a first fluid-permeable zone within the hydrocarbon-bearing formation;
drilling an intermediary conduit via the at least one well, the intermediary conduit extending at a depth that varies along a length of the intermediary conduit such that the intermediary conduit extends through a generally fluid-impermeable zone, joining the first fluid-permeable zone into which the at least one well extends, to a second fluid-permeable zone separated from the first fluid-permeable zone by the fluid-impermeable zone, the intermediary conduit being unconnected to the at least one well by any liner or screen;
mobilizing at least some of the hydrocarbons in the hydrocarbon-bearing formation by injection mobilizing fluid through the at least one well and allowing mobilizing fluid to pass through the intermediary conduit;
producing fluids, including the mobilizing fluid and mobilized hydrocarbons, through the at least one well.

25. The process according to claim 24, wherein the intermediary conduit is laterally offset from the at least one well.

26. The process according to claim 24, wherein the intermediary conduit is completed with a pipe liner.

27. The process according to claim 24, wherein the intermediary conduit generally follows a sine wave, stepped pattern, or S shape.

28. The process according to claim 24, comprising flow control devices cooperating with the at least one well for controlling the flow of the fluids produced from the hydrocarbon-bearing formation into the at least one well.

29. The process according to claim 24, comprising flow control devices cooperating with the at least one well for controlling the flow of the fluids injected into the hydrocarbon-bearing formation.

30. A method of improving conformance of a steam chamber in a hydrocarbon-bearing formation that includes an injection well and a production well extending into the hydrocarbon-bearing formation, wherein a portion of the injection well is separated from a portion of the production well by a generally fluid-impermeable zone, the method comprising:
drilling an intermediary conduit via the injection well or the production well, the intermediary conduit extending at a depth that varies along a length of the intermediary conduit such that the intermediary conduit extends through the generally fluid-impermeable zone, to join fluid-permeable zones within the hydrocarbon-bearing formation, the intermediary conduit being unconnected to the injection well and to the production well by any liner or screen; and injecting steam into the hydrocarbon-bearing formation via the injection well and allowing the steam to pass through the intermediary conduit.

31. The method according to claim 30, comprising completing the intermediary conduit with a liner.

32. The method according to claim 30, wherein drilling the intermediary conduit comprises drilling such that the intermediary conduit is laterally offset from the injection well and the production well.

33. The method according to claim 30, wherein drilling the intermediary conduit comprises drilling such that the intermediary conduit extends at varying depth between the depth of the injection well and the depth of the production well and is laterally offset from the injection well and the production well.

34. The method according to claim 30, wherein drilling the intermediary conduit comprises drilling such that the intermediary conduit is laterally offset from the injection well and the production well by at least about 2 meters.

35. The method according to claim 30, wherein drilling the intermediary conduit comprises drilling in a generally wave pattern, stepped pattern, or S-shaped pattern such that the intermediary conduit extends through the generally fluid-impermeable zone a plurality of times, to join the fluid-permeable zones.

36. The method according to claim 30, comprising controlling the flow of the steam injected into the hydrocarbon-bearing formation from the injection well utilizing flow control devices.

37. The method according to claim 30, comprising drilling at least one further intermediary conduit that extends at a depth that varies along a length of the intermediary conduit such that the at least one intermediary conduit extends through the generally fluid-impermeable zone, to join fluid-permeable zones within the hydrocarbon-bearing formation, the at least one further intermediary conduit being unconnected to the injection well and to the production well.

38. The method according to claim 37, comprising completing the at least one further intermediary conduit with a liner.

39. The method according to claim 37, wherein drilling the at least one further intermediary conduit comprises drilling such that the at least one further intermediary conduit is laterally offset from the injection well and the production well.