SINGLE HORIZONTAL WELL THERMAL RECOVERY PROCESS

Abstract

The present disclosure describes a method for the recovery of hydrocarbons using a single horizontal well having both injection and production means. The well has a means for increasing fluid flow resistance in the wellbore. The injection and production means are operated so as to increase the fluid flow into the reservoir and reduce the fluid flow in the well. The means to increase fluid flow includes a constriction in the wellbore between the injection and production means, flow conditioners placed along a portion of the well between the injection and production means, and sealing elements placed in the well between the injection and production means. The production and injection openings are also positioned relative to the flow conditioners and sealing elements.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. Provisional Patent Application No. 61/894,809, entitled “SINGLE HORIZONTAL WELL THERMAL RECOVERY PROCESS” filed Oct. 23, 2013, which is hereby incorporated by reference in its entirety.

FIELD

The present disclosure relates generally to oil recovery processes and particularly to thermal recovery and thermal/solvent recovery processes that may be applied in viscous hydrocarbon reservoirs, and specifically in oil sands reservoirs. More specifically, the disclosure describes the use of a single horizontal well for injection and production in thermal and/or solvent recovery processes.

BACKGROUND

Among the deeper, non-minable deposits of hydrocarbons throughout the world are extensive accumulations of viscous hydrocarbons. In some instances, the viscosity of these hydrocarbons, while elevated, is still sufficiently low to permit their flow or displacement without the need for extraordinary means, such as the introduction of heat or solvents. In other instances, such as in Canada's bitumen-containing oil sands, the hydrocarbon accumulations are so viscous as to be practically immobile at native reservoir conditions. As a result, external means, such as the introduction of heat or solvents, or both, are required to mobilize the resident bitumen and subsequently harvest it.

A number of different techniques have been used to recover these hydrocarbons. These techniques include steam flood, (i.e., displacement), cyclic steam stimulation, steam assisted gravity drainage, and in situ combustion, to name a few. These techniques use different key mechanisms to produce hydrocarbons.

Commercially, the most successful recovery technique to date in Canada's oil sands is Steam Assisted Gravity Drainage (SAGD), which creates and then takes advantage of a highly efficient fluid density segregation, or gravity drainage, mechanism in the reservoir to produce oil. A traditional system which is a concomitant of the SAGD process is the SAGD well pair. It typically consists of two generally parallel horizontal wells, with the injector vertically offset from and above the producer.

SAGD was described by Roger Butler in his patent CA 1,130,201 issued Aug. 24, 1982 and assigned to Esso Resources Canada Limited. Since that time, numerous other patents pertaining to aspects and variations of SAGD have been issued. Also, many technical papers have been published on this topic.

The SAGD process, as embodied in the operation of a well pair, and as applied in an oil sand, typically involves first establishing communication between the upper and lower horizontal wells. There are both thermal and non-thermal techniques for establishing this inter-well communication. Subsequently, steam is injected into the overlying horizontal well on an ongoing basis. Due to density difference, the steam tends to rise and heat the oil sand, and thereby mobilizes the resident bitumen. The mobilized bitumen is denser than the steam, and tends to move downward towards the underlying horizontal well from which it is produced. By operating the injector and the producer under appropriately governed conditions, it is possible to use the density difference to counteract the tendency of more mobile fluids to channel or finger through the less mobile fluids and overwhelm the producing well. Thus, in traditional SAGD operations, each well in the well pair has a specific and distinctive role in ensuring that the efficiencies which can be achieved with a gravity-dominated process are realized.

Not long after the patenting of SAGD, various investigators began to examine the feasibility of operating a process which, like SAGD, is gravity-dominated, but which is operable with a single well rather than a well pair. The early concepts involved a single vertical well and represent a different configuration than that described in the present disclosure.

In U.S. Pat. No. 5,014,787 filed Aug. 16, 1989, Duerksen of Chevron describes a single vertical well system, with detailed focus on the tubing-casing-packer configuration within the wellbore. Packers are installed to confine and direct flow within the wellbore and to segregate within the wellbore the injection and production intervals. This system utilizes a “drive fluid”. Generally drive fluids are used in non-SAGD systems to drive or “push” the hydrocarbons to a producer well. This is in contrast to recovery processes in which a gravity drainage mechanism is either dominant or operative. Duerksen's system and associated method utilize a “drive fluid” to establish near-wellbore communication within the reservoir between an upper set of injection perforations and a lower set of production perforations and does not mention gravity drainage or a gravity-dominated process.

In U.S. Pat. No. 5,024,275 filed Dec. 8, 1989, to Anderson et al, assignee Chevron, a similar system is described as that in U.S. Pat. No. 5,014,787 to Duerksen, but with somewhat modified vertical wellbore hydraulics. Also, mention is made of maintaining a liquid level within the reservoir such that uncondensed fluids are not inadvertently produced. However, as with U.S. Pat. No. 5,014,787, reference is made to a “drive fluid”. There is no mention of a recovery process which includes gravity drainage as an operative mechanism.

U.S. Pat. No. 5,238,066 filed Mar. 24, 1992 to Beattie et al., assignee Exxon, pertains to a method introduced in the later stages of cyclic steam stimulation (CSS) operation, and involves alternating periods of steam injection into upper perforations in a vertical well followed by hydrocarbon production from lower perforations. There is no mention or implication of a gravity-dominated recovery process or a process in which gravity drainage plays a role.

The paper titled “Lloydminster, Saskatchewan Vertical Well SAGD Field Test Results”, published in the Journal of Canadian Petroleum Technology, November 2010, Volume 49, No. 11, by Miller & Xiao of Husky Energy, describes a field experiment involving a single vertical well SAGD-type operation. The reservoir in which the experiment was conducted involved viscous oil, but with considerably lower native viscosity (i.e., higher mobility) than the types of bitumen present in the oil sands. The authors indicated that the test “demonstrated that a single vertical well SAGD configuration could be successfully completed and operated”. For reasons that the authors attributed to geology and initial fluid distribution within the reservoir setting, the authors noted that “Field performance of single vertical SAGD Well 4C11-1 was not as good as expected”, and suggested that single vertical well SAGD methodology could be “used to help determine if sufficient vertical permeability exists for the low-pressure gravity-based horizontal well SAGD process to be successful”. That is, the authors proposed that their single vertical well SAGD methodology could be applied as a diagnostic technique for determining vertical permeability within the reservoir rather than as an effective recovery process.

Other vertical well configurations have been proposed. For example, X-Drain™, a trademarked and patented concept by GeoSierra/Halliburton involves a single vertical well that employs a SAGD-type process. Emanating from the vertical well are a number of highly permeable vertical planes, similar to vertical hydraulic fractures, with the fractures propped or held open by a permeable propping agent. Each such plane has its own azimuth so that the effect, when viewed from above, is geometrically similar to a hub (the vertical well) and spokes (the induced multi-azimuth vertical planes). Steam is injected into the upper portion of the well and moves outward through the highly permeable propping agent contained within these multi-azimuth vertical planes to mobilize the bitumen at the faces of each plane.

For many decades, Imperial Oil has practiced a cyclic steam stimulation process at their Cold Lake oil sands operation using vertical and inclined wells. The viability of the recovery process depends on the use of formation fracturing during the injection cycle to create a largely vertical fracture that spans a significant vertical portion of the formation. While this is a single-well process, the perforations or wellbore openings for injection are the same as those used for production. Thus, the recovery mechanism relies on a production flow path that is fundamentally the same as, and indeed largely created by, the preceding injection flow path.

Canadian patent application CA 2,723,198 filed Nov. 30, 2010 to Shuxing, assignee ConocoPhillips, describes a vertical well recovery process which can include a gravity-dominated mechanism. The patent application describes a well configuration involving a single well with an upper and a lower set of openings or perforations. It further requires the creation of two horizontal fractures—one opposite the upper injection interval and one opposite the lower producing interval. However, there are additional costs and other disadvantages to fracturing so it may not be feasible or desirable for a particular formation.

Because of their vertical well orientation, none of the foregoing single-well techniques enjoys the inherent advantage offered by horizontally oriented wells, which can traverse and access a large portion of reservoir. The obvious advantage of a horizontally oriented single well was recognized by various investigators, and concepts for a single horizontal well recovery system and process were put forward.

One such approach is described in U.S. Pat. No. 5,167,280 to Sanchez et al, assignee Mobil, issued Dec. 1, 1992. This patent discusses the circulation within the wellbore of a solvent which is capable of rendering the viscous oil more mobile. A process is employed in which the pressure gradient and the fluid concentration gradient are opposed. That is, the pressure gradient is maintained so that flow is inward from the reservoir to the well. At the same time, the viscous oil reservoir is exposed to the solvent via diffusion. The aim is to obtain simultaneous outward stimulation of the reservoir by the solvent and inward flow of mobilized viscous oil to the well. The practicality of maintaining the operating conditions necessary to achieve opposing gradients is highly questionable, as an inordinate degree of monitoring and control would be required.

Canadian Patent 2,162,741 to Nzekwu et al, assignee CNRL, and filed Dec. 20, 2005, describes a single horizontal well recovery process that includes both gravity drainage and steam flooding. The patent describes a process whereby steam is directed to the distal end of the single horizontal well via insulated tubing, making its return toward the proximal end of the well in the annular region between tubing and liner such that a portion of the returning steam migrates through the slotted liner into the reservoir and mobilizes oil. A problem with this type of configuration is that the resistance to fluid flow along the path from the well into the reservoir is very much greater than the fluid resistance along the annulus between the outer surface of the tubing and the inner surface of the liner. Accordingly, only a small portion of the overall injected fluids will enter the reservoir and mobilize oil. In a low pressure operation mode, Nzekwu restricts the injection and production rates to such an extent that a liquid level builds in the vertical part of the primarily horizontal well, which hydrostatically supports the steam chamber pressure. That is, the liquid head is equal to the steam chamber pressure. There is a low pressure drop in the annulus from the distal end to the proximal end. Using this system, the longitudinal growth of the steam chamber in the reservoir, i.e. from the toe towards the heel, is promoted by the small pressure drop that exists along the horizontal well and would be extremely slow and result in very low production rates. In a high pressure mode, Nzekwu describes a preferred configuration in which a packer is placed near the distal end of the well to isolate the injection and production zones in an attempt to direct more of the steam into the reservoir. As described by Nzekwu, the packer is set over a blanked-off interval of the liner that is approximately one metre in length. Thus the interval of isolation is extremely small relative to the length of a typical horizontal well, and the ability of that isolation interval to cause a diversion of injected fluids into the reservoir before they ultimately flow back into the wellbore will be very limited in space and time. That is, as some of the reservoir on the downstream side of the packer is heated, and the hydrocarbons mobilized and produced, the injected steam will enter the reservoir on the upstream side of the packer and exit the reservoir shortly thereafter on the downstream side of the packer, where it will re-enter the wellbore and flow to the proximal end with little or no further effect in mobilizing oil.

A paper by Elliot and Kovscek prepared for the U.S. Department of Energy, dated June 2001, and titled “A Numerical Analysis of Single-Well Steam Assisted Gravity Drainage (SW-SAGD) Process” describes simulations carried out in which the horizontal well is subdivided into two equal lengths, with the injection interval occupying the distal half and the production interval occupying the proximal half of the wellbore length. The distal and proximal segments can be demarcated within the wellbore by a single intervening packer, or packer assembly, and open intervals for injection and production are separated from each other by a distance of 30 metres. Relative to the 800 metre length of the well represented in their simulations, which is a typical length for a SAGD well, this is a very small separation interval, so that fluids injected into the reservoir on the upstream side of the packer will short-circuit back into the wellbore after a relatively short traverse within the reservoir. However, the authors comment that while their work involved maintaining this equal-length configuration, it is not necessary to do so. The authors also limit the effectiveness of their method by noting that “application of SWSAGD to exceptionally viscous oils will be difficult”. The authors suggest an upper limit of 10 Pa-s. This is in contrast to the invention to be described herein, which includes devices, well configurations and techniques that promote or maximize exposure of the reservoir to mobilizing fluids. A further contrast between the present invention and that of Elliot and Kovscek is the applicability of the present invention in oil sands where the native bitumen may be 100 times more viscous than the limit set by Elliot and Kovscek on the applicability of their method.

A paper by Marin et al of PDVSA, presented at the World Heavy Oil Congress in Edmonton Alberta in 2008 (Paper 2008-348), and titled “SW-SAGD Pilot Project in the Well MFB-617, TL Sands, MFB-15 Reservoir, Bare Field, Eastern Basin of Venezuela” discloses a single horizontal well configuration for SAGD operation. The wellbore contains two strings—one for injection and the other for production. However, while the injection string traverses the length of the horizontal wellbore, the production string is confined to the vertical portion of the wellbore. FIG. 4 of the paper clearly illustrates the verticality of the production tubing and this is re-enforced within the text which describes the tubing as having been set 650 ft. above the top of the reservoir.

This same well (MFB-617) is the subject of a paper by Mago et al of PDVSA, presented at the World Heavy Oil Congress in Aberdeen Scotland in 2012 (Paper 2012-348). There are no indicated completion changes for the well, so that the basic configuration teaches away from that taught in the present disclosure. However, the authors conducted simulation studies involving alternative configurations for steam injection. In those simulations, steam is injected along a horizontal well that involve configurations with one, two and three steam injection points along the length of the well. However, there are no teachings in this paper that pertain to management of the resistances to flow as is the case with the present disclosure.

Canadian Patent 2,752,059 to Kjorholt, assignee Statoil, describes a single horizontal well whose wellbore contains a production conduit and an injection conduit, with openings in each conduit that are distributed along the horizontal length of the wellbore. The openings in the production conduit may be staggered laterally with respect to the openings in the injection conduit. No packers or other flow restraints, or flow conditioners, as will be described in the case of the present invention, are employed to determine, or assist in the determination of, the flow distribution along the wellbore.

A single horizontal well recovery process is disclosed by Laricina in their update of Oct. 31, 2012 to the Alberta Energy Resources Conservation Board, and titled “Saleski Phase 1 Project Update”. Laricina describe their proposed single well recovery process as follows: “The recovery process that has been selected is single well cyclic SAGD process with the use of solvent technology. This process varies the rates and compositions of solvent and steam injected over the life of the wells. The process alternates between injecting steam/solvent and producing water and mobile oil from the well bore. The injection cycle consists of injecting steam/solvent above reservoir pressure at 1,600 kPa to 5,100 kPa to heat the reservoir and reduce the viscosity of the bitumen. The reservoir is then allowed to absorb the heat from the injected steam/solvent, condense and subcool before a production cycle starts. The production cycle is continued until bitumen rate reaches a minimum threshold.” As described in their update, Laricina's recovery process involves variations in procedure that incorporate Cyclic Steam Stimulation as well as SAGD, but does not include any management of flow along the length of a horizontal well.

The foregoing single horizontal well inventions fall into five approaches to single horizontal well SAGD. The patent to Sanchez et al constitutes one approach wherein opposing gradients are operative. This approach differs profoundly from the teachings of the present invention.

The second approach, including Nzekwu and Elliot, relies on a fixed-position wellbore impediment, such as a packer, to divert flow from the injection perforations outward into the reservoir so that heating and chamber formation can occur. However, once heating and mobilization of oil occurs within the reservoir in the vicinity of the packer, the opportunity for steam to flow around the packer and back into the wellbore is provided, instead of continuing to enter the reservoir beneficially. Specifically, because of the very high virgin viscosity of bitumen, the initial path of least resistance for the injected mobilizing fluids in a single horizontal well configuration will involve relatively shallow penetration by the mobilizing fluids into the reservoir, and a tendency thereafter to move longitudinally along the outside of the liner and thence into the production means located along that same wellbore, whereupon it will enter the wellbore, and will be minimally effective or ineffective from that point onward in mobilizing bitumen within the reservoir.

The third approach, described in the paper by Marin et al., involves a production string that is exclusively vertical and, as such, teaches away from the method and system of the present disclosure. The follow-up paper by Mago et al discusses this same well, and includes simulations of proposed steam injection configurations and methods. However, these configurations and methods are fundamentally different from those of the present disclosure.

The fourth approach, disclosed by Kjorholt, involves horizontal injection and production strings that traverse the wellbore, with openings at discrete intervals along each that distribute injection and production respectively. However, the invention does not otherwise take steps, or employs devices, which will alter the flow and displacement patterns beneficially as does the present disclosure.

The fifth approach, disclosed by Laricina, includes the combination of Cyclic Steam Stimulation (CSS) and SAGD, but offers no description of well completion configuration, nor does it specify any associated methods to manage flow into the reservoir and along the wellbore as does the present disclosure.

Having regard to these limitations in the prior art, it is an object of the present disclosure to provide a single horizontal well recovery process whose efficiency is enhanced by incorporating methods and systems to mitigate the steam short-circuiting tendencies associated with this type of operation and, correspondingly, will extend the region within the reservoir over which the viscous hydrocarbons are contacted by mobilizing fluids. The recovery process will utilize gravity drainage and for convective flow mechanisms to varying degrees, depending upon the stage of the process, the well configuration and the reservoir properties.

In addition to the foregoing five approaches to single horizontal well processes that encompass both injection and production functions, prior systems also include horizontal wells with injection only.

U.S. Pat. No. 8,196,661 to Trent et al, assignee Noetic Technologies Inc., and titled “Method for Providing a Preferential Specific Injection Distribution from a Horizontal Injection Well”, describes a concept that involves an injection well only. As such, the tubing that is within the casing has openings along its entire length so that injected fluids, such as steam, may be injected radially outward through the tubing, and thence radially outward through the casing or liner, thereby entering the reservoir with substantially radial flow geometry. U.S. Pat. No. 8,196,661, in describing means to control the distribution of fluids injected radially along the length of the wellbore, makes reference to devices which provide means of increasing friction within the wellbore so as to govern the flow.

CA 2,769,044 to Butland et al, assignee Alberta Flux Solutions Ltd., and titled “Fluid Injection Device”, describes a device or system for distributing fluids, including steam, along an injection-only wellbore with radially outward flow into the formation. Also, it references devices or approaches which modify the flow resistance within the wellbore to assist in the distribution of injected fluids.

These systems with injection only from the horizontal wellbore are concerned with a flow geometry of only the injected fluids into the reservoir without any concern for production from the same horizontal wellbore. This requires a different flow geometry and the flow of different fluids than those required in a horizontal well with both production and injection capabilities.

There is therefore a need for increasing the flow resistance of injected fluids in a horizontal well having both injection and production capabilities, for the increased flow of injected fluids into the reservoir and improved production of mobilized hydrocarbons from the horizontal well.

SUMMARY

The present disclosure is a method and system for a recovery process for recovering hydrocarbons from a reservoir using a single horizontal well for both injection and production. The recovery process may utilize gravity drainage or convective flow, or both. The recovery process is preferably a thermal or solvent recovery process. The system and process has an injection tubing string which has openings only at or towards one end of the horizontal well, preferably its toe end, to permit egress of injected fluids, and openings or perforations along the liner or outer casing of the wellbore to permit injection into the reservoir of mobilizing fluids over a selected interval of the wellbore. Positioned downstream therefrom along the casing or liner of that same wellbore, are openings to permit production from the reservoir of mobile and mobilized fluids.

The present disclosure minimizes or markedly reduces the shortcutting or short-circuiting tendency of the injected fluid as it moves outward into the reservoir along one interval of the wellbore and returns further downstream into appropriate production tubulars within that same horizontal wellbore. That is, the present system and method utilizes procedures or equipment configurations, or combinations thereof, to govern the resistance to fluid flow of the injected fluids from the well outward into the reservoir relative to the resistance to fluid flow of the injected fluids along the various tubular conduits within the wellbore. This approach results in an efficient recovery process for viscous hydrocarbons, such as bitumen, while using only a single horizontal well to accomplish both the injection and production functions.

When implemented, the present invention allows mobilizing fluid to exit the wellbore and enter the reservoir, and thence traverse a significant portion of the reservoir where it mobilizes viscous hydrocarbons. The resulting mobile stream then re-enters a portion of the wellbore downstream and moves to a production means, such as a pump. To achieve this flow configuration, which permits injection and production operations along the same wellbore, flow gradients into and out of the reservoir must be governed while maintaining a sufficiently long open interval that will serve as an effective production means.

In one aspect, the present disclosure provides a method of producing viscous hydrocarbons from subterranean bituminous formations, such as oil sands formations, using a single horizontal well process. The method includes providing a single horizontal well within the subterranean formation wherein the horizontal well has at least one injection means and at least one production means, spaced axially along the well and apart from the at least one injection means. Preferably the at least one injection means are positioned at or near the toe of the well and the at least one injection means are positioned at or near the heel of the well. The well may also have a casing or liner which includes openings to the formation to allow injected fluids to flow into the formation and mobilized hydrocarbons, as well as other fluids, to flow into the well for production. The method also includes providing a means for substantially increasing resistance to axial fluid flow of mobile and mobilized fluids in the wellbore annulus, between the tubing and the liner or outer wellbore wall, along a length of the horizontal well between the at least one injection means and the at least one production means. A mobilizing fluid is injected through the injection means. The injection and production means are operated to control the ratio of the flow resistance in the wellbore annulus to the flow resistance in the formation, thereby reducing the amount of the injected mobilizing fluid that is moving along the wellbore annulus from the injection means to the production means and increasing the amount of the injected mobilizing fluid entering and moving through the formation before being displaced into the well to the at least one production means. Viscous hydrocarbons are produced using the production means.

Other aspects and features of the present disclosure will become apparent to those ordinarily skilled in the art upon review of the following description of specific examples in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF DRAWINGS

The present recovery processes disclosed herein will be described with reference to the following drawings, which are illustrative and not limiting:

FIG. 1 shows a prior art use of a horizontal well with both injection and production means to recover hydrocarbons.

FIGS. 2a and 2b show horizontal wells with a constriction and/or flow conditioner along the annulus of the wellbore.

FIGS. 3a to 3c show examples of flow conditioners.

FIG. 4 shows a wellbore with a constriction along its length and identifies the corresponding change in pressure gradient.

FIG. 5 is a graph showing the percent oil recovery of a method according to the present disclosure and conventional SAGD.

FIGS. 6a and 6b show a series of packers positioned in the wellbore to restrict the flow of the injected fluid.

FIGS. 7a-7d show four examples of the configuration for the well components using the method set out in the present disclosure.

DETAILED DESCRIPTION

The present disclosure provides a process for the recovery of viscous hydrocarbons from a subterranean reservoir using a single horizontal well. The hydrocarbons produced using the single horizontal well recovery process described herein are immobile hydrocarbons or mobile hydrocarbons which benefit from a mobilizing method, such as, for example, a thermal recovery process. That is, while the hydrocarbons may have some mobility, it may not be sufficient to be commercially effective for production, or the mobility may be increased with a thermal recovery process, or other mobilizing method, so as to improve production. In one aspect, the hydrocarbons are heavy oil and/or bitumen. The recovery process includes to varying degrees, depending upon the reservoir and wellbore characteristics, gravity drainage, as well as convective flow mechanisms. By gravity drainage is meant a process whose flow mechanisms are predominantly gravity controlled and whose techniques of operation are largely oriented toward ultimately maximizing the influence of gravity control because of its inherent efficiency. By convective flow mechanisms is meant flow and displacement mechanisms, such as continuous or cyclic convective displacement.

In one aspect, the recovery process is a thermal or thermal and solvent process. In such a process, steam, light hydrocarbons, hot water, or suitable combinations thereof may be used as the injection fluid. Further, these injection fluids, such as steam and light hydrocarbons, may be injected as a mixture or as a succession or alternation of fluids. Examples of light hydrocarbons include C₃ to C₁₀ hydrocarbons such as propane, butane and pentane.

Although the present disclosure refers to recovery processes such as thermal or solvent recovery processes, it will be understood by a skilled person that the present system and method will function beneficially for a broad range of in situ recovery processes including both thermal and non-thermal processes. Examples of in situ recovery processes which may be used with the present system and method and in which these fluid re-distribution principles may be beneficially applied include those which rely, either singly or in combination, on the injection of steam, solvents, water, surfactants, and non-condensing gases including both oxidizing and non-oxidizing gases.

The method uses a single horizontal well. In one aspect, a horizontal well implies a well that is substantially or predominantly horizontal, but may include sections or segments that are not horizontal. The lack of horizontality over portions or segments of the well length may occur as a result of technology limitations, or may be intentional, for example when steering the well path so that it avoids a particular geological feature, or so that it creates a structural low point for fluid accumulation, such as a sump. This characterization of a well as horizontal, notwithstanding possible deviations from horizontality over segments or portions of the well length, is well known to those skilled in the art.

Further, a single horizontal well may include an individual wellbore whose openings to the reservoir have been configured to allow for both injection and production.

The single horizontal well may also include equipment, such as multiple strings of tubulars, centralizers, packers, bridge plugs, sliding seal assemblies, valves, pumps, and liners which may be necessary to operate the well in this mode. In addition, the tubulars may include features, such as slots or perforations, or other types of opening, which provide means of egress from and ingress into those tubulars. Although reference may be made herein to wellbores, liners, or other components of a well, these references are not limiting and will be understood by a person skilled in the art to be applicable to wellbore construction and equipment as may be appropriate for a particular reservoir.

The horizontal well used in the present recovery process includes an injection means such as, for example, an interval along the horizontal liner which is open to injection into the reservoir of a fluid or fluids that are capable of mobilizing, or enhancing the mobility of, a viscous hydrocarbon, such as bitumen, upon contact. The recovery process also includes a production means such as, for example, a separate interval along the horizontal liner which is open to production from the reservoir into the wellbore of mobile or mobilized fluids. Although described in the singular for purposes of simplicity, there may in fact be a plurality of injection means and a plurality of production means along the wellbore. The injection and production means are spaced apart from each other along the length of the well. In one aspect, they are positioned at or near opposite ends of the well. In an alternative aspect, they are positioned along the length of the well at closer positions. Their distance is determined by a number of factors including the reservoir characteristics, mobility of the hydrocarbons, possibility for short circuiting of the injected fluids from the injection means to the production means, and the extent of recovery within the wellbore. Examples are discussed below.

In one aspect, the injection and/or production operations may be continuous and/or simultaneous. In a further aspect, the injection and/or production operations may proceed concurrently. In a further aspect, the injection and/or production operations may proceed on an interrupted basis, including a cyclic basis. In a further one aspect, the injection and production means are isolated from each other in the wellbore. In a further aspect, the area in the formation adjacent an injection means is absent an induced fracture.

In one aspect, the injection operation may involve the injection of a single fluid or fluid type. In one aspect, the injection operation may involve two or more fluids or fluid types. Where two or more fluids, or fluid types, are being injected, their injection may occur concurrently or sequentially.

In a single horizontal well operation for the recovery of a high viscosity hydrocarbons, it is necessary to mitigate the tendency of injected fluids to preferentially move along the wellbore annulus instead of entering the reservoir. This entails modification of the axial fluid resistance path, primarily within the wellbore annulus, although it can also include modification of the fluid resistance path within the reservoir itself in the immediate vicinity of the wellbore. Modification of fluid resistance within the wellbore can entail the configuration and deployment of wellbore features and equipment, as will be described subsequently. Modification of fluid resistance within the reservoir will inevitably occur as a result of operations that are implemented following modifications to fluid resistance within the wellbore. In addition, however, modifications to the reservoir may be implemented independently. For example, recovery process start-up may be accelerated and early performance efficiency of the recovery process may be enhanced by introducing one or more mobilizing fluids, such as steam or solvent, along a substantial portion or the entire open length of the horizontal well.

The process for a single horizontal well is intended to ensure that mobilizing fluids, while traversing the path of egress from the wellbore into the reservoir via the injection means to ingress into the wellbore from the reservoir via the production means, enter the reservoir in significant quantities during the course of that traverse and mobilize viscous hydrocarbons, such as bitumen. Thus, the fluid resistance within the wellbore is increased so that a greater percentage of the mobilizing fluid is directed or diverted into the reservoir rather than along the wellbore. In certain aspects, the present disclosure provides means of increasing the fluid resistance within the wellbore by using either a medium that behaves as a continuum within and along the wellbore annulus or, alternatively, an impediment or a series of discrete wellbore impediments, including sealing elements, that are located in specific relation to openings along the wellbore and that can be activated either concurrently or sequentially, or a combination of both alternatives. Within the context of this disclosure, use of terms such as “impediment” or “sealing element” can imply a means that creates a complete restriction to flow or a partial restriction to flow.

In one aspect, the means of increasing the fluid flow resistance, namely the primarily axial flow in the annulus of the injected fluids and of the mixture of mobile and mobilized fluids, traverses a length of the wellbore and engenders a variable frictional energy loss along that length, so that a greater percentage of the injected fluids is diverted away from flow in the wellbore annulus and instead flows into the reservoir. The device is of substantial length compared with, for example, the effective length of a packer, and is instrumental in inhibiting the fluid's re-entry into the wellbore from the reservoir after traversing the reservoir for only a short distance. One example is a flow conditioner. The flow conditioner extends along the longitudinal axis of the wellbore. It is positioned in the wellbore annulus between the tubing and the liner. It may taper from one end to the other providing a constriction in the wellbore annulus and/or it may have externally extending projections that will interfere with fluid flow and provide resistance to the flow path of a fluid in the wellbore annulus. Due to the frictional energy loss, this flow path resistance will cause the fluid to flow into the reservoir rather than through the wellbore annulus. As a result, a greater amount of injected fluid will enter the reservoir than in systems where no impediment is placed in the wellbore annulus or where only a single packer located between proximate injection and production intervals is used as an impediment.

Because of the length of the flow conditioner, the injected fluids, along with mobile and mobilized hydrocarbons and associated reservoir fluids, will re-enter the wellbore further downstream after the flow conditioner, which therefore reduces or prevents short circuiting of the injected fluid from the injection means to the production means of the wellbore.

In a further aspect, increasing fluid resistance in the wellbore involves reducing the size of the annular space between the outside of the tubing and the inside of the casing or liner so that fluids flowing in this reduced annular space will experience an increased resistance to fluid flow. This reduced annular space may be achieved, for example, by increasing the diameter of the tubing, decreasing the diameter of the casing or both. Preferably the reduced annular space is used in combination with a sealing element such as a packer positioned between the injection and production means or a constriction element in the annulus which may include a sealing element that is not fully deployed.

In a further aspect, the means of increasing the flow resistance is a series of impediments placed in the wellbore. These may be operated concurrently or sequentially. For example, the impediments may be a series of sealing elements such as packers placed along the wellbore at selected distances. In one aspect, production openings are open along the wellbore situated in the intervening distances between the sealing elements. The sealing elements may be operated in series, with the first set before the initial injection of fluid. Once the injected fluid short circuits the first sealing element, the second sealing element is set. As hydrocarbons in the reservoir are produced and the injected fluids, along with mobile and mobilized hydrocarbons and associated reservoir fluids, short circuit the sealing elements, further sealing elements are set, again forcing the injected fluids and mobile or mobilized fluids to traverse a greater portion of its flow path within the reservoir and re-enter the wellbore further downstream. Any number of sealing elements can be used and can be set in series or concurrently, until either the desired flow configuration is established or until physical or other limitations are encountered and preclude further deployment.

In one aspect, the sequential deployment of sealing elements, such as packers, may involve the activation of successive sealing elements, each of which is situated at a particular fixed location along the tubing, and such that the tubing itself is stationary within the well throughout this operation. In one aspect, one may employ as few as two packers to accomplish a similar effect by carrying out a number of sequential withdrawals or re-positionings of the tubing, each time disengaging and then re-engaging the packers in their new positions within the wellbore. In this aspect, when the tubing is re-positioned within the wellbore, the packers may remain in their current positions along the tubing string, or may be re-positioned relative to the tubing string itself.

The staging of the sequence of packers, whether as stationary sealing elements along a stationary tubing string, or as stationary or moveable sealing elements along a tubing string that is successively re-positioned, as described above, may be guided by the mobility of the hydrocarbons in the vicinity of the packer. Specifically, a packer is activated, or re-positioned and activated, at a particular location along the wellbore only after the hydrocarbons in the reservoir corresponding to a location immediately downstream of the packer (i.e., between the packer and the proximal end of the horizontal well) have become mobile. Absent that hydrocarbon mobility, the heating fluids which advance in the proximal direction through the reservoir, over the interval of wellbore occupied by the packer, may lack a means of displacing the hydrocarbons into the wellbore downstream of the packer.

Alternatively, the impediments may be set simultaneously so that the flow resistance in the wellbore forces the injected fluid into the reservoir for the length of the wellbore containing the sealing elements.

In one aspect, the wellbore configuration may include constrictions within the wellbore, allowing some injected fluid to pass. This may be achieved in one example by partially setting the sealing elements, rather than full sealing elements. Constrictions in the wellbore may also be used with flow conditioners to further increase the fluid flow resistance in the wellbore. Further, the wellbore may include a combination of flow conditioners with packers or other sealing elements.

In a further aspect, the wellbore may be equipped with one or more spaced apart devices located along the length of the horizontal tubing which modify or impede, but do not altogether prevent, axial flow along and within the annulus. For example, the wellbore may include a number of spaced apart devices such as packers which may seal off the annulus at the location of those devices or fracture cups which may largely cover the cross-section of the annular area by means of frictional contact with the interior of the liner or casing rather than a seal. Irrespective of the particular device selected, the device may be equipped with axially oriented flow conduits, such as nozzles, one or more of which may penetrate the device so that, notwithstanding the tendency of the device to impede or prevent axial flow, a measure of flow will occur through the axially oriented flow conduit(s) embedded within that device.

In one example, injected fluids may exit the tubing near the toe of the well and may tend to flow back along the annulus towards the heel. A series of spaced apart devices, such as packers or fracture cups, are located within the annulus, with each such device having embedded within it one or more axially oriented nozzles. The geometry of the nozzle(s), and in particular their diameter, may be designed so that the nozzle(s) presents a major restriction to flow along the annulus, thereby diverting a major portion of the injected fluid upward or outward into the reservoir. The nozzles' geometry may be selected so as to create the conditions for sonic (i.e., critical) flow within the nozzle. Fluids which pass through these nozzles may merge on the downstream side of the nozzles with fluids that had been diverted into the reservoir on the upstream side of the nozzles and which subsequently entered the annulus from the reservoir on the downstream side of the nozzles, bringing with them reservoir fluids which have been mobilized. The resulting fluid mixture on the downstream side of the first set of nozzles will move towards the second device within which one or more nozzles are embedded. Again, a portion of the fluids approaching the second set of nozzles may be diverted into the reservoir while a portion flows through the nozzle(s) in the second device. The nozzles embedded in the second device may differ in geometry and number from the nozzles embedded in the first device. The nozzle(s) embedded in the second device may be configured so as to offer less resistance to fluid flow than the nozzle(s) in the first device. The nozzles in the second device may be configured so that flow of fluids through them is sub-critical. Additional sealing or frictional devices may be located along the length of the annulus with embedded nozzles.

In a further aspect, the frictional devices may be designed and configured so that the geometry and size of the gap or aperture between the device and the surrounding casing or liner will impede or restrict flow in a specific manner, thereby acting in place of, or in addition to, embedded nozzles.

In a further aspect, the wellbore may be configured so that steam is injected into the annulus and reservoir at a multiplicity of locations. For example, steam may be injected into two tubing strings, each positioned with its toe at a different location within the wellbore. Thus, in one example, steam is injected into a first tubing string which terminates in the region of the wellbore closer to the heel, while steam injection in a second tubing string exits the tubing closer to the toe of the well. For each such string of tubing, a series of devices as described herein are placed so as to both encourage flow of injected steam into the reservoir and allow return of mobile and mobilized fluids into the wellbore for subsequent production.

The means of increasing the flow resistance in the wellbore may consist of one of the options set out herein or a combination of them. For example, in further aspects, the present method provides a constriction element and a flow conditioner; a sealing element and a flow conditioner; or a series of sealing elements acting as impediments within the wellbore. These combinations provide an increase in the frictional energy loss within the wellbore annulus. The result is redirecting more of the injected fluid into the reservoir rather than through the wellbore annulus, increasing the recovery of the hydrocarbons, and improving the steam oil ratio.

In a further aspect, no openings are positioned in the wellbore between the sealing elements. The casing or liner will have wall openings, or groups of wall openings with intervening intervals containing no wall openings. The blanked off intervals between groups of casing or liner openings provide interior casing or liner wall locations against which sealing elements, such as packers, may be inflated or deployed.

The design of the casing or liner in respect of the locations of its openings, or groups of openings, can involve considerations not only of the implementation of the present system and method, but also of the use of techniques employed prior to the implementation of the present system and method to condition the near-wellbore vicinity by enhancing mobility. One such technique to enhance mobility in the near-wellbore region involves injection of a solvent, such as xylene. An alternative technique for enhancing near-wellbore mobility involves a geomechanical approach whereby applied pressure causes a re-orientation of the sand grains and consequent mobility improvement. A traditional technique for enhancing mobility in the near-wellbore vicinity employs heat transfer primarily by conduction and involves injecting a hot fluid, such as steam, down to the toe of the tubing and thence back around through the annulus and ultimately to the surface, the reservoir in the near-wellbore vicinity being heated thereby as a consequence of the circulating wellbore fluids. Such techniques, often referred to as accelerated start-up techniques, may entail injection into the reservoir of limited fluid volumes, and may employ openings along a substantial length of the casing or liner. Those skilled in the art will be capable of situating the groups of wall openings in the casing or liner so that both the step of increasing mobility in the near-wellbore vicinity and the subsequent step of practicing the methods and systems of the present disclosure are accomplished.

The present method with its governance of friction in the annular region of the wellbore as described herein permits injection and production at high rates. This is in contrast to Nzekwu, which requires that production is confined to low rates so as to avoid low pressures in the vicinity of the pump, with consequent flashing of steam, and reduction in pump efficiency. Specifically, Nzekwu requires this restriction so that a liquid level can build in the vicinity of the pump in the vertical part of the primarily horizontal well.

FIG. 1 shows a prior system for a single horizontal well 1 in a viscous hydrocarbon reservoir. In attempting to mitigate the problem of short-circuiting of the injected fluid, such as steam, into and along the wellbore, the well 1 uses a single packer 7 placed near the distal end 5 (i.e. toe) of the well in the annular region between the tubing 2 and the casing or liner 3. The packer is used as a sealing element, providing an impediment to the injected fluid. In this example, steam is injected down the tubing 2 to the distal end 5 of the well where it exits the tubing upstream of the packer 7. There, openings in the casing or liner are provided so that the steam, prevented from moving downstream within the annular region by the presence of the packer 7, will enter the reservoir. However, as explained above, placement of a single packer provides only a localized and temporary mitigation of the short-circuiting problem inasmuch as the steam, after a brief sojourn in the reservoir, and after limited contact with and mobilization of viscous hydrocarbons, can re-enter the wellbore through openings located in the casing or liner downstream of the packer, whence it will be produced without having maximized its mobilization potential within the reservoir.

In contrast to this prior system, in the present disclosure, the process in one aspect uses a means for increasing flow resistance in the wellbore annulus to prevent or minimize short circuiting of the injected fluid and allows it to stay in contact with the reservoir for a longer period of time to improve mobilization of the fluids. In another aspect, the process increases flow resistance in the wellbore annulus by using impediments or sealing elements, such as packers, to prevent or minimize these short-circuiting tendencies.

FIGS. 2a and 2b illustrate specific aspects of the present invention where, instead of a single discrete impediment to flow within the wellbore, a flow conditioner is placed in the wellbore which traverses a substantial length of the wellbore and which engenders a variable frictional energy loss along that length. As a result, a greater percentage of the injected fluids are diverted away from the wellbore and into the reservoir. FIGS. 2a and 2b illustrate some examples of a flow conditioner 9. As shown in FIG. 2a, the device can be tapered to increase the frictional resistance as the injected fluid moves toward the impediment, i.e. the packer 7. Alternatively, as shown in FIG. 2b, the device may be finned, with multiple ribs extending into the annulus area to provide increased friction to the flow of the injected fluid. Flow conditioners may have a series of ribs or suitable other structures positioned perpendicular to the longitudinal axis of the wellbore or may have multiple ribs extending along the longitudinal axis of the wellbore. Further, the multiple ribs may be continuous, segmented, or divided into bristle-like formations. FIGS. 3a to 3c show some examples of commercially available flow conditioners. The multiple ribs or other suitable structures along the flow conditioner interfere with the flow of the injected fluid through the wellbore annulus between the tubing and the casing. FIG. 2B also uses a packer with the flow conditioner to further increase the flow resistance in the wellbore. Packers or other sealing elements may be used with the flow conditioners or they may be used on their own. Since the frictional energy loss is increased, the injected fluid will be diverted into the reservoir. This increases the amount of injected fluid that enters the reservoir and results in an increase in the mobilization of hydrocarbons in the reservoir.

One or more flow conditioners may be positioned in the wellbore annulus, between the tubing and the liner, at the injection end of the casing, upstream of the packer. Alternatively or in addition thereto, one or more flow conditioners may be positioned in the wellbore annulus on the production end of the wellbore downstream of the packer. FIGS. 2a and 2b show flow conditioners 9 positioned on both the upstream and downstream sides of the packer in the annulus in the wellbore. By providing the flow conditioners downstream of the packer 7, less injected fluid will enter the wellbore downstream on the production side near the packer. Instead, the injected fluid will stay in the reservoir where the frictional energy loss is less, and the injected fluid will enter the production side of the casing further downstream from the packer. This reduces and/or prevents short circuiting of the injected fluid and increases the amount of the reservoir in contact with the injected fluid.

As shown in FIG. 4, the flow conditioners 9 are positioned within the wellbore upstream and downstream of the injection and production means. They are tapered along the longitudinal wellbore axis so that the upstream flow conditioner increases in diameter as it extends towards the heel of the wellbore. An adjacent flow conditioner is positioned downstream of the upstream flow conditioner and its diameter decreases as it extends along the longitudinal axis of the wellbore. These flow conditioners provide a constriction point in the wellbore limiting the flow of injected fluid through the annulus in the wellbore. The flow conditioners moderate the pressure drop across the constriction. The pressure drop is higher than the pressure drop across the sand face. As a result, the injected fluid will spread into the reservoir rather than flow along the wellbore annulus. The injected fluid will not reenter the wellbore until the flow resistance in the wellbore decreases, becoming less than that in the reservoir, near the downstream end of the downstream flow conditioner. This also prevents short circuiting of the injected fluid from the injection side to the production side.

The use of flow conditioners within the wellbore may also allow for a reversible recovery process without reconfiguration of the wellbore flow conditioners. For example, the injected fluid may be injected at the toe end of the wellbore initially with production of the hydrocarbons near the heel of the wellbore. However, in a later stage, this may be reversed and the fluid may be injected near the heel of the wellbore and produced from the toe end of the wellbore. As shown in FIGS. 2a and 4, the flow conditioners are positioned so that a taper occurs on both the upstream and downstream ends of the wellbore. In FIG. 2b, the flow conditioners are present on both sides of the packer providing multiple ribs or other structures which extend into the wellbore on either side of the packer. This allows the flow conditioners to provide an impediment to the flow of the injected fluid regardless of whether it is injected near the toe of the well with production near the heel of the well or whether injection occurs near the heel of the wellbore with production near its toe. It is contemplated that the process may be initiated in one direction and then reversed after a period of hydrocarbon recovery has occurred.

A further example of means of increasing the flow resistance in the wellbore is shown in FIGS. 6A and 6B. These figures show a series of sealing elements such as packers between which are openings to the reservoir at selected intervals along the length of the wellbore. A first packer is set as a sealing element, creating an impediment to the flow of injected fluid through the wellbore. The remaining sealing elements are not set and do not form impediments to fluid flow in the wellbore. The injected fluid will enter the wellbore, preferably at or near the distal end, and be forced into the reservoir. As hydrocarbon recovery occurs, the injected fluid will short circuit and re-enter the wellbore immediately downstream of the packer as shown in FIG. 6A. To improve hydrocarbon recovery and lengthen the time that the steam stays in the reservoir, a second packer, further along the wellbore from the first packer, and towards the proximal end, is now set as a sealing element, as shown in FIG. 6B. This provides a longer length of the wellbore where the injected fluid cannot travel. As a result, the fluid will remain in the reservoir until it reaches downstream of the second set packer, improving hydrocarbon recovery. Once the hydrocarbon recovery progresses and injected fluid begins to short circuit this second packer, a third packer will be set as a sealing element, again limiting the section of the wellbore where the injected fluid can travel. Any number of packers or other sealing elements can be used along the length of the wellbore. Although FIGS. 6A and 6B show the packers being set in series as hydrocarbon recovery progresses, they can also be set simultaneously. Further, although FIGS. 6A and 6B do not show the use of flow conditioners, they may be used in conjunction with one or more of the sealing elements. For clarity, FIG. 7 shows four of the earlier described examples for the well components configuration using the present method. FIG. 7A shows a system using sequentially deployed packers within the wellbore annulus. FIG. 7B shows a system using one packer and a constricted annulus. FIG. 7C shows a system using nozzles of varying sizes within the packer/sealing elements and where the fluid is injected at a single point. FIG. 7D shows a system using nozzles of varying sizes within the packer/sealing elements and where the fluid is injected at two points.

The above approach involving sealing elements may be modified to accomplish the same objective but in examples involving as few as two sealing elements. In one aspect, described with respect to packers as the sealing elements, a first packer is set, mobilizing fluids are injected into the reservoir, those fluids eventually short circuit the first packer and re-enter the wellbore, whereupon a second packer further along the wellbore from the first packer, and directionally closer to the heel, is deployed. However, beyond this point, instead of deploying successive packers, as described in the above approach, the entire assembly involving the tubing string, and the two packers, is moved axially so that the end of the tubing is now displaced from its original position along the length of the wellbore and is located further away from the toe. In this example, subsequent engagement of the first and thence the second packer will allow the axial progress of the heated front from the toe towards the heel, both in the reservoir and in the wellbore. As a further variation of this approach, when the tubing is re-located to a new position along the wellbore, it may be opportune to actually re-position the two packers relative to the tubing string itself. This may involve removing the tubing string from the well, re-positioning the packers relative to the toe of the tubing string, and possibly relative to each other, and then re-installing the tubing within the well and positioning it at its new location.

In one aspect, the injection and production steps in the recovery process of the present disclosure may entail the imposition of a higher pressure differential between injection and production means than would be the case for gravity thermal recovery processes, such as SAGD. This would provide a convective recovery mechanism, in addition to gravity drainage.

The discussion herein is concentrated on a single horizontal well in isolation. The present disclosure also includes the use of laterally adjacent single horizontal wells, with appropriate well spacing between them, so that each effectively recovers viscous hydrocarbons from its region. Mathematical modeling has demonstrated that further efficiencies can be realized by aligning these adjacent wells appropriately. In one example, if two laterally adjacent wells are aligned in parallel so that the toe end of one well is closest to the heel end of its neighbor, then concurrent operation of the two wells in accordance with the principles of this disclosure will further improve performance because of increased volumetric sweep efficiency, or conformance.

Further, although the above discussion refers to the injection means being positioned at the toe of the horizontal well and the production means positioned at the heel of the well, these positions may be reversed or altered for recovery of the hydrocarbons.

In a comparison of the present method with conventional SAGD, 800 m long wells were used. The SAGD well pairs were spaced 100 m apart while the single horizontal wells of the present method were spaced 50 m apart, providing the same effective spacing. Using a thin pay of 10 m, simulations were run to show the percent oil recovery. The processes were optimized with solvent addition. The results are shown in FIG. 5. For optimization, in the single well using the present method, 5% hexane was added for 1 year while in the SAGD process, 1.5% hexane was added for 1 year. While these amounts of hexane differ, they represent equivalent amounts of injected hexane using the two processes. The example using the single well in the present method injects only at the toe end of the well while the SAGD process injects along the length of the well. As a result, the higher concentration of the injected hexane in the single well example is an equivalent amount as compared to the lower concentration of the injected hexane in the SAGD example. The graph shows that the present method provides for an increased oil recovery over time as compared to a conventional SAGD process. Recovery can be further improved by using accelerated start up process, examples of which are known in the art.

The methods and systems described in this disclosure are intended to be capable of operating independently of any adjacent or neighboring wells or well groups. As such, the methods and systems of the present disclosure are applicable in a virgin reservoir. However, it will be readily understood by those skilled in the art that single wells may be strategically located, and single well recovery processes may be operated within a reservoir to harvest hydrocarbons which have been or would otherwise be bypassed by nearby or surrounding in situ recovery operations. Wells employed in this capacity are sometimes referred to as infill wells. The methods and systems of the present disclosure may be used in that capacity.

Reference is made to exemplary aspects and specific language is used herein. It will nevertheless be understood that no limitation of the scope of the disclosure is intended. Alterations and further modifications of the features described herein, and additional applications of the principles described herein, which would occur to one skilled in the relevant art and having possession of this disclosure, are to be considered within the scope of this disclosure. Further, the terminology used herein is used for the purpose of describing particular aspects only and is not intended to be limiting, as the scope of the disclosure will be defined by the appended claims and equivalents thereof. All publications, patents, and patent applications mentioned in this specification are herein incorporated by reference to the same extent as if each individual publication, patent or patent application were each specifically and individually indicated to be incorporated by reference.

Claims

1. A method of producing viscous hydrocarbons from a subterranean formation, comprising:

providing a single horizontal well within the subterranean formation wherein the horizontal well comprises an outer wall, at least one injector for injecting a mobilizing fluid into the reservoir, the at least one injector comprising a conduit within the well to inject the mobilizing fluid to the distal end of the conduit, an annulus extending along the longitudinal axis of the well, and at least one producing component, positioned apart from the at least one injector, for producing hydrocarbons from the reservoir;

providing, within the annulus, a flow conditioner for substantially increasing axial fluid flow resistance within the annulus along a length of the horizontal well between the at least one injector and the at least one producing component;

injecting the mobilizing fluid through the at least one injector;

operating the at least one injector and the at least one producing component to control the ratio of the flow resistance in the well to the flow resistance in the formation, thereby reducing the amount of the injected mobilizing fluid moving through the annulus from the at least one injector to the at least one producing component and increasing the amount of the injected mobilizing fluid entering and moving through the formation before being displaced into the well to the at least one producing component; and

producing viscous hydrocarbons through the at least one producing component.

2. The method of claim 1 wherein the method uses:

a gravity-dominated fluid flow or displacement mechanism to recover the viscous hydrocarbons;

a convectively dominated fluid flow or displacement mechanism to recover the viscous hydrocarbons; or

a combination of convective and gravity fluid flow and displacement mechanisms to recover the viscous hydrocarbons.

3. The method of claim 1 wherein the flow conditioner for increasing fluid flow resistance provides a constriction in the annulus to increase the fluid flow resistance of the injected mobilizing fluid as the fluid re-enters the annulus from the reservoir.

4. The method of claim 1 wherein the flow conditioner for increasing fluid flow resistance is selected from the group consisting of:

one or more flow constrictors positioned in the annulus;

one or more partial sealing elements positioned in the annulus; and

two or more sealing elements positioned in the annulus of the well between the at least one injector and the at least one producing component.

5. The method of claim 4 wherein the one or more flow constrictors extend along a portion of the length of the annulus between the injector and the producing component.

6. The method of claim 4 wherein the two or more sealing elements are operated in series or simultaneously.

7. The method of claim 4 further comprising operating the two or more sealing elements in a staged manner by activating sealing elements in a staged manner in a direction from the at least one injector to the at least one producing component.

8. The method of claim 4 wherein, following an initial activation of the two or more sealing elements, the sealing elements are deactivated, moved longitudinally through the annulus and reactivated in a new position relative to the at least one injector portion and the at least one producing component.

9. The method of claim 4 wherein prior to one of the sealing elements being activated, the viscous hydrocarbons in the formation immediately downstream of the one of the sealing elements are sufficiently mobile to undergo displacement by the injected mobilizing fluid once the one of the sealing elements has been activated.

10. The method of claim 4 wherein, in the interval(s) between the two or more sealing elements, the outer wall of the well, contains openings, or groups of openings, to allow hydraulic communication between the well and the formation.

11. The method of claim 4 wherein the portion of the outer wall of the well between the two or more sealing elements does not have openings into the reservoir.

12. The method of claim 4, wherein the one or more partial sealing elements comprises a sealing element with one or more flow conduits extending through the sealing element for allowing a desired flow of the mobilizing fluid.

13. The method of claim 12 wherein the one or more partial sealing elements comprises more than one sealing element with one or more flow conduits extending through each of the more than one sealing element, wherein the flow conduits in each sealing element allow for a different mobilizing fluid flow rate than the fluid flow rate in at least one other of the sealing elements.

14. The method of claim 12 where the flow velocity in one or more of the flow conduits is sonic flow and critical flow.

15. The method of claim 1 wherein the step of producing the viscous hydrocarbons comprises pumping the hydrocarbons to the surface without maintaining a substantial liquid level in the horizontal well.

16. The method of claim 1 wherein the viscous hydrocarbons are selected from the group consisting of bitumen, heavy oil, and unmobilized hydrocarbons.

17. The method of claim 1 wherein the injected fluid comprises steam, hot water, light hydrocarbons, or mixtures thereof or one or more of non-condensing gases and surfactants.

18. The method of claim 1 wherein:

the injector injects fluids at or near a toe of the horizontal well and the producing component produces viscous hydrocarbons at or near a heel of the horizontal well; or

the injector injects fluids at or near a heel of the well and the producing component produces the viscous hydrocarbons at or near a toe of the well.

19. The method of claim 1 wherein the at least one injector includes two injector, each injector injecting the mobilizing fluid at a different section in the well and each of the two injector having flow conditioners for substantially increasing axial fluid flow resistance within the annulus along the length of the horizontal well.

20. The method of claim 1 wherein a plurality of single horizontal wells is employed.