US20140251608A1

US20140251608A1 - Single vertical or inclined well thermal recovery process

Info

Publication number: US20140251608A1
Application number: US14/195,518
Authority: US
Inventors: Simon D. Gittins; Subodh Gupta; Arun Sood
Original assignee: Cenovus Energy Inc
Current assignee: Cenovus Energy Inc
Priority date: 2013-03-05
Filing date: 2014-03-03
Publication date: 2014-09-11

Abstract

The present disclosure describes a single well predominantly gravity-dominated recovery process for producing viscous hydrocarbons from a subterranean oil sands formation. The process operates a single vertical or inclined well within a formation, the wellbore having an injection means and a production means, the injection means being positioned in the wellbore closer to the surface than the production means. The process provides an area of high mobility adjacent the production means. A mobilizing fluid is injected through the injection means into the formation to mobilize the viscous hydrocarbons in the formation while substantially concurrently producing hydrocarbons through the production means. The gravity dominated process may be SAGD and the present process may be a single vertical or inclined well SAGD process.

Description

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.

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 that is a concomitant of the SAGD process is the SAGD well pair, which 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.
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. 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 gravity-dominated processes such as SAGD which use gravity as the key mechanism in the production of the hydrocarbons. 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 but the vertical wellbore hydraulics are modified somewhat. 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 gravity-based recovery 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 a cyclic steam stimulation (CSS) operation, and involves alternating periods of steam injection into upper perforations followed by hydrocarbon production from lower perforations. There is no mention or implication of a gravity-dominated recovery process.
In 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, a field experiment involving a single vertical well SAGD-type operation is described. The reservoir in which the experiment was conducted involved a 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 flow of heated fluids to the well during the production cycle takes advantage of gravity drainage to a limited degree, the principal means of bringing the fluids to the wellbore at commercial flow rates during the production phase of the cycle is the imposition of a pressure gradient (i.e., the creation of a pressure sink at the wellbore during its production phase). Thus, while the recovery process employed by Imperial Oil at Cold Lake requires vertical fractures and, as such, includes an element of gravity drainage, flow and displacement via an imposed pressure gradient is the dominant recovery mechanism.
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.
There therefore remains a need in the industry for an effective oil recovery process using a single vertical or inclined well and a gravity dominated recovery process such as SAGD.

SUMMARY

It is an object of the present disclosure to obviate or mitigate at least one disadvantage of previous systems.
In one aspect, the present disclosure provides a method of producing viscous hydrocarbons from a subterranean oil sands formation using a single well gravity-dominated process, comprising the steps of operating a single vertical or inclined well, the wellbore having an injection means and a production means, the injection means being positioned in the wellbore closer to the surface than the production means; providing an area of high mobility adjacent the production means; injecting a mobilizing fluid through the injection means into the formation to mobilize the viscous hydrocarbons in the formation; and substantially concurrently producing hydrocarbons through the production means; wherein the viscous hydrocarbons are produced using a predominantly gravity-dominated process. In one aspect, the injection and/or production operations may be continuous. In one aspect, the injection and/or production operations may proceed on an interrupted basis. In one aspect, the injection and production means are isolated from each other in the wellbore. In one aspect, the area in the formation adjacent the injection means is absent an induced fracture.
In a further aspect, the step of providing an area of high mobility may comprise mobilizing the hydrocarbons around the production means to form the area of high mobility. Mobilizing the hydrocarbons may include introducing heat into the area. This may be done by electric or electromagnetic heating or by injecting heated fluids into the area. Alternatively, providing the area of high mobility may comprise altering the matrix structure of the area such as through dilation of the formation area. Alternatively, providing an area of high mobility may comprise replacing native fluids in this area with high mobility fluids such as water, light hydrocarbons, non-condensing gases and combinations thereof. Alternatively, providing an area of high mobility comprises removing reservoir material in the area and filling the area with high permeability material such as gravel. In a further alternative, the area of high mobility may comprise a naturally occurring or pre-existing area of high mobility.
In a further aspect, the gravity-dominated recovery process is steam-assisted gravity drainage (SAGD). In a further aspect, the gravity-dominated recovery process is a solvent or solvent-assisted process. In a further aspect, the single well is a vertical or substantially vertical well or an inclined well.
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 figure.

BRIEF DESCRIPTION OF DRAWINGS

Aspects of the present disclosure will be described by way of example only with reference to the attached figure.

FIG. 1 is a depiction of one example of a single well completion of the present disclosure.

DETAILED DESCRIPTION

The present disclosure provides a method or process for the recovery of viscous hydrocarbons from a subterranean reservoir using a single vertical or inclined well, the performance of which is improved by the inclusion of certain features as described herein. The recovery process is a gravity-dominated process but may also include drive or displacement mechanisms to a lesser degree.
The hydrocarbons produced using the single well gravity dominated recovery process described herein are immobile hydrocarbons or mobile hydrocarbons which benefit from a thermal recovery process, i.e. 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 to improve production. In one aspect, the hydrocarbons are heavy oil and/or bitumen.
In one aspect, the recovery process is a gravity dominated process. By gravity dominated process 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. It is understood by those ordinarily skilled in the art that a gravity dominated process, while relying principally on a gravity drainage mechanism to govern fluid displacement, does not preclude the use of subsidiary fluid flow processes, such as convective displacement. One example of a gravity dominated process is steam assisted gravity drainage (SAGD).
In a further 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 C₃to C₁₀hydrocarbons such as propane, butane, pentane, and hexane. The light hydrocarbon may be a solvent, or solvent mixture, which will exist substantially in liquid form at recovery process conditions within the reservoir, thereby facilitating its eventual drainage by gravity, along with mobilized oil, to the basal region of the vertical well. In other words, a substantial portion of the solvent, or solvent mixture, will possess a vapor pressure which is lower than that of the steam with which it is co-injected or within whose environment it is introduced, thereby substantially behaving as a less volatile fluid than the steam. In one embodiment, the injected fluid includes an amount of solvent, or solvent mixture, of up to 12 wt %. In another embodiment, the amount of injected solvent is up to 5 wt % and in the alternative, in the range of 4 to 10 wt %.
The method uses a single vertical or inclined well. In one aspect, a vertical well implies a well that is substantially or predominantly vertical, but may include sections or segments that are not vertical. Analogously, reference to an inclined well implies a well that is substantially or predominantly inclined to the vertical at an angle less than 90 degrees, but which is not either substantially vertical or substantially horizontal, yet may include sections or segments that are vertical or horizontal.
Further, a single well may include an individual wellbore whose openings to the reservoir have been configured to allow for both injection and production, as would be contemplated in a gravity-dominated recovery process, such as a SAGD operation.
The single vertical or inclined well may also include equipment, such as multiple strings of tubulars, as well as packers, valves and pumps, which may be necessary to operate the well in this mode.
In the case of a horizontal well SAGD process, it is well known that, because of the low density of steam relative to the other fluids in its environment, the growth of the SAGD chamber is upward and eventually outward. That is, given a sufficiently thick reservoir, the steam chamber grows and ascends dramatically beyond the vertical elevation of the injector. However, in the downward direction, there is little significant growth of the chamber below the horizontal producer, and modest outward growth of the chamber at the level of the producer when compared to the growth at or near the top of the chamber. As a consequence, for the fluids flowing downward in the SAGD process, the chamber shape is such that there is convergence of flow in the vicinity of the producer. In principle, this convergent flow geometry tends to restrict flux rates into the producer and reduce productivity. However, in the case of a horizontal well process, this convergence, and the concomitant flow restriction is compensated for by the extended length of the well (e.g., 800m). Thus, flux rates over any unit length interval along the horizontal well may be small whereas the overall well production rate may nevertheless be significant over the active length of wellbore, so that the horizontal well SAGD process is commercially feasible.
In the case of a single vertical well employing a gravity-dominated process, such as SAGD, where steam is injected through an upper open interval in the wellbore and fluids are produced from a lower open interval in that same wellbore, there is a strong three-dimensional convergence of the flow toward and into the bottom producing interval. This convergent flow geometry encircles the entire vertical wellbore in the vicinity of the producing interval, forming a cone-like shape and thereby markedly restricting productivity. This contrasts with a horizontal producing well configuration in which the convergence of stream lines is only two-dimensional (i.e., trough-like along the length of the horizontal well) so that the relative productivity loss is less.
A highly convergent flow geometry, and its restriction on flow, is particularly harmful to a gravity drainage process such as SAGD. Specifically, in the case of a single vertical well, it will result in an accumulation of liquids in or around the lower regions of the well. That accumulation is capable of quenching or killing the steam chamber.
This disclosure, an aspect of which is illustrated schematically in FIG. 1, provides a method for altering the abovementioned conical convergent flow geometry in the case of a single vertical or inclined well being used to carry out a gravity-dominated recovery process, such as SAGD, so that the flow restriction, and its attendant high pressure losses and deleterious effects on the steam chamber, are ameliorated. Furthermore, it does so without requiring vertical fractures, multi-azimuth vertical planes, or induced fractures adjacent the injection means, such as those described in the prior art.
As shown in FIG. 1, a well is provided in a subterranean formation having an overburden 1, a pay zone 2 with viscous hydrocarbons to be produced, and an underburden 3. A first upper set of perforations 4 are positioned near the top of the pay zone 2 and a second lower set of perforations 6 are positioned near the bottom of the pay zone. Within a single well, a conduit 7 for injecting fluids, such as steam, into the formation extends to the upper set of perforations 4. A conduit 8 for producing fluids from the formation extends to the lower set of perforations 6. The conduits 7 and 8 may be tubing or other means known in the art. The conduits 7 and 8 (and appropriate perforations) are positioned within the well and/operated under conditions so that injected fluids from conduit 7 are not produced directly from conduit 8 through the wellbore rather than injected into the formation. This may require, for example, that conduit 7 and 8 be positioned a suitable distance apart or they may be isolated within the well by means known in the art, such as a packer 5 shown in FIG. 1. The positioning of conduit 7 and 8 or use of other means to isolate them will depend on the particular well and formation and is within the knowledge of the skilled person.
The present method is a method of recovering hydrocarbons from a reservoir using a single well gravity-dominated recovery process in the presence of a high mobility zone 9. The high mobility zone 9 is located substantially opposite the producing interval of the single vertical or inclined well. The high mobility zone 9 may be either pre-existing or artificially established. Operation of the recovery process occurs at a single well and, as illustrated in this aspect, involves injecting steam into the reservoir through the upper set of perforations 4 and producing mobile and mobilized fluids from the reservoir through the lower set of perforations 6, all under conditions that allow gravity drainage to predominate.
The operation of the recovery process at the single well includes injecting steam through the upper set of perforations 4 while substantially concurrently producing mobile hydrocarbons from the producer at the lower set of perforations 6. Substantially concurrently means that while it is preferred that the hydrocarbons will be produced at the same time that steam or other fluids are injected into the formation, it is recognized that this is not always possible. Therefore, the injecting and producing may be sequential or alternating, and may be continuous or interrupted, during part of the recovery process. However, it is preferred that the injection and production will operated mainly on a concurrent basis.
Reference is made to a high mobility zone as a feature of the present method. Mobility, as used here, accords with traditional reservoir engineering usage and as such is defined as the permeability of a porous medium to a resident fluid divided by the resident fluid viscosity. The high mobility zone that is a feature of the present method involves a zone that is substantially horizontal in orientation (e.g., a layer or a pancake-like structure) located in the generally lower portion of the reservoir, preferably opposite the producing perforations, where those perforations will be typically located in the lower portion of the reservoir. The shape of the high mobility zone can be irregular so long as it functionally mimics or approximates a layer or pancake-like structure, as one ordinarily skilled in the art would understand. Thus, the present method avoids not only the installation of multi-azimuth vertical planes, as specified in the X-Drain technology, but also eliminates the need for high pressure vertical fracturing, such as that utilized by Imperial Oil at Cold Lake. It further avoids the requirement for an induced fracture adjacent the injection means, as described by Shuxing.
If a basal high mobility zone is not already present, it can be artificially induced or created. The exact means of creating this zone will depend on a number of factors including the specific formation and viscosity of the hydrocarbons. It is well within the knowledge of the skilled person to select an appropriate method to create the high mobility zone. For example, the high mobility zone can be created by removing the reservoir material, as for example by mining or by drilling and under-reaming, and filling the cavity thus created with high permeability material such as, for example, gravel. If the basal portion of the reservoir initially contains, as its native fluid, a high saturation of relatively immobile bitumen, then a basal high mobility zone can be created using known techniques for increasing the mobility of resident bitumen, such as for example by heating or solvent addition. For example, the formation may be heated using electric heating, electromagnetic heating, or injecting heated fluids into the formation. The high mobility zone can be created by dilation of the reservoir or other such techniques which alter matrix structure. The high mobility zone can also be created by replacing native fluids in this lower region with high mobility fluids, such as water, light hydrocarbons or non-condensing gases, or combinations thereof. Any one or more of these methods as well as other known methods can be used by a skilled person to create the high mobility zone as required in a particular formation.
More specifically, in a further aspect, a horizontally oriented pancake-like high mobility zone that surrounds a vertical well is to be emplaced within the reservoir, using techniques such as those recited above, at a level that is opposite the producing interval. The dimensions of this high mobility zone, and the make-up of the fluids which reside in its pores, can be selected by those ordinarily skilled in the art by means of simulation or developed guidelines. Subsequently, when a gravity-dominated recovery process, such as SAGD, is employed, steam enters the reservoir from the wellbore through an upper open interval of the single vertical well. In the present method, as the SAGD chamber is established, the tendency of the mobilized bitumen to flow along a downward convergent path to the producing interval and thereby be subjected to excessive pressure loss will be countered by the presence of the basal high mobility zone, which will provide a more energy efficient conduit for the mobilized bitumen to reach the producing interval at the wellbore. In so doing, the presence of the basal high mobility zone either eliminates or mitigates the tendency of the converging fluids to quench or otherwise impede the progress of the steam chamber.
Prior art recovery methods may use a naturally occurring basal high mobility zone, such as a basal water zone, as a means of injecting or introducing heat into the reservoir. However, the prior art methods do not utilize a high mobility feature, whether natural or created, for purposes of production or for purposes of enhancing the operation of the overlying gravity drainage mechanism.
If a naturally occurring high mobility zone is present at or near the base of the reservoir, then certain characteristics of that zone will determine whether there is a need for alterations to the geometry or state of that zone so that it may be used as the high mobility zone in the present recovery process. For example, to ensure that hot downward-draining bitumen from the SAGD process does not cool excessively when it encounters a naturally occurring basal high mobility zone, it may be desirable to replace some portion of a native fluid, or the native fluids, resident in this basal high mobility zone with one or more different fluids. These replacing fluids can be selected for reasons of inherent properties, such as heat capacity, density, viscosity or miscibility with bitumen. Alternatively, they can be selected for reasons of fluid state, such as would be the case if it was desired to replace a cold native fluid with a similar or alternative fluid, or fluids, that will impose a higher temperature on the high mobility zone and thence on the downward-draining bitumen.
When a gravity drainage process is operated using a single vertical or inclined well process, the presence of a high mobility zone, as described above in various aspects, will prevent or ameliorate flow effects that are deleterious to productivity. Specifically, in the case of SAGD recovery process, the presence of a high mobility zone will facilitate the drainage of oil and water to the producing interval of the well. Correspondingly, in the absence of such a high mobility zone, the highly convergent flow patterns associated with a single vertical or inclined well process will result in hold up of the oil and water, and consequent quenching or reduction in size of the steam chamber.
CA 2,732,198 requires the use of two fractured zones, one adjacent to the injector and one adjacent to the producer. However, it has been found by the present inventors that two high mobility zones are not necessary. Having only one high mobility zone adjacent the producer is sufficient to aid in hydrocarbon production using the vertical well as disclosed herein. Further, it is not necessary to fracture the formation. A high mobility zone adjacent to the producer can be created using other methods and still produce beneficial results in recovering hydrocarbons.
The present disclosure requires only a single high mobility feature, either created or naturally present, opposite the producing interval. The additional required feature in CA 2,723,198 (Shuxing) of a fracture created opposite an upper set of perforations would allow steam injected at these upper perforations to move some lateral distance outward from the wellbore. However, it is believed that the present disclosure achieves this same lateral spreading without need of an additional fracture, as required by Shuxing. Specifically, as observed in numerous SAGD field operations within the oil sands, and as demonstrated in simulations, steam injected at a set of perforations with no associated fracture will not only move upwards, but will also flare laterally outwards, thereby providing a broad region within which bitumen can be mobilized. Accordingly, it is believed that, through the development of a mobilized zone or steam chamber at, above and laterally outward from the upper perforations at the wellbore, the present disclosure achieves lateral extension of mobility within the reservoir without need of a fracture opposite the upper perforations.
Furthermore, in the event that the present disclosure is preceded by a start-up acceleration technique known within the industry, such as for example xylene injection or dilation, a zone of enhanced mobility surrounding the well between the upper and lower openings or perforations will be created. With this zone of enhanced mobility in place in the present invention, it is believed that the already superfluous or marginal value of the upper fracture in CA 2,723,198 will be accentuated.
As already noted above, the disclosed recovery process may also be applied at an inclined well. In the case of an inclined well configuration, it may be desirable to modify, especially in a horizontal aspect, the geometry of the high mobility zone, firstly with respect to the concentricity or eccentricity of its placement relative to the point or region over which it intersects the wellbore, and secondly with respect to its compass orientation. Thus, in the case of an inclined well, it may be advantageous to ensure that horizontal placement of the high mobility zone is eccentric with respect to its intersection with the well and that the high mobility zone is oriented along a compass direction such that the high mobility zone is underneath, and can serve as a catchment for, the downward draining fluids from the overlying active zone or chamber created by the thermal recovery process, (e.g., SAGD or a Solvent Aided Process).
Of course, the decision to employ, and the manner in which one employs, a vertical or inclined well in a single well SAGD process may be influenced by local lithology, as well as by operating considerations. This would include the inclination of the well itself with respect to the vertical, the placement of the injection and production openings along the wellbore and the geographic placement and horizontal extent of the basal high mobility zone. With respect to the placement of the injection and production openings, it should be clearly understood that the present process contemplates the possibility of not just a single set of injection openings and a single set of production openings. Rather, a multiplicity of sets of injection and of production openings is also contemplated, as dictated by needs recognizable to those ordinarily skilled in the art, including but not limited to needs associated with equipment, operations or lithology as well as considerations associated with fluid flow and displacement.
It is noteworthy that the present process reflects a well configuration, whether vertical or inclined, wherein the producing interval is substantially opposite the basal high mobility zone. As such, the open or completion interval at the producer is at or below the base of the pay, so that the gravity mechanism can be operative vertically throughout the pay. This is in contrast to the situation in horizontal well SAGD where the horizontal producer is not situated at the very base of the pay but rather is typically located some distance above the base of pay and, as such, may not recover substantial amounts of underlying oil.
The foregoing description has been presented in terms of gravity-dominated thermally based recovery processes, such as SAGD. However, it should be understood that gravity-dominated solvent-assisted processes, such as for example the Solvent Aided Process (SAP), which employs a suitable hydrocarbon solvent, or combinations thereof, in conjunction with steam, will also function beneficially with the present process. Still another gravity-dominated recovery process alternative involves introducing a suitable solvent and water into the reservoir and heating the mixture as appropriate.
Other additives that may also be employed in the practice of the present method include non-condensing gases and surfactants.
Also, with a gravity-dominated process, such as SAGD, a start-up process is required to established communication between the injector and producer wells. A skilled person is aware of various techniques for start-up processes, such as for example hot fluid wellbore circulation, the use of selected solvents such as xylene, or the application of geomechanical techniques such as dilation. Techniques such as these can also be employed as a means of accelerating start-up in the present recovery process.
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 embodiments 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 oil sands formation, comprising the steps of:

i. operating a vertical or inclined well within a formation, the well having an injection means and a production means, the injection means being positioned in the well closer to the surface than the production means, and wherein the injection means is positioned in the wellbore in the absence of an induced fracture in the formation adjacent the injection means;

ii. providing an area of high mobility in the formation adjacent the production means;

iii. injecting a mobilizing fluid through the injection means into the formation, to mobilize the viscous hydrocarbons in the formation; and

iv. substantially concurrently producing the viscous hydrocarbons through the production means;

v. wherein the viscous hydrocarbons are produced using a predominantly gravity-dominated process.

2. The method of claim 1 wherein the formation adjacent the injection means has an absence of an area of high mobility.

3. The method of claim 1 wherein the injection and production means are isolated from each other within the well.

4. The method of claim 1 wherein the injecting and/or producing is done on a continuous or an interrupted basis.

5. The method of claim 1 wherein providing an area of high mobility comprises mobilizing the hydrocarbons in the formation in an area adjacent the production means to form the area of high mobility.

6. The method of claim 5 wherein mobilizing the hydrocarbons comprises introducing heat into the area.

7. The method of claim 6 wherein introducing heat into the area comprises using electric heating, electromagnetic heating, or injecting heated fluids into the area.

8. The method of claim 7 wherein the heated fluids comprise steam, hot water, solvent, and a combination thereof.

9. The method of claim 1 wherein providing an area of high mobility comprises altering the matrix structure of the area.

10. The method of claim 9 wherein altering the matrix structure comprises dilation of the formation area.

11. The method of claim 1 wherein providing the area of high mobility comprises replacing native fluids in the area with high mobility fluids.

12. The method of claim 11 wherein high mobility fluids comprise water, light hydrocarbons, non-condensing gases and combinations thereof.

13. The method of claim 1 wherein providing the area of high mobility comprises removing formation material in the area and filling the area with high permeability material.

14. The method of claim 13 wherein removing formation material comprises mining, drilling or under-reaming the formation to create a cavity.

15. The method of claim 13 wherein the high permeability material comprises gravel.

16. The method of claim 1 wherein the area having high mobility is a pre-existing area of high mobility.

17. The method of claim 1 wherein the injected mobilizing fluid is steam, light hydrocarbon, hot water, or a mixture thereof.

18. The method of claim 1 wherein the gravity-dominated recovery process is steam-assisted gravity drainage (SAGD).

19. The method of claim 1 further comprising maintaining a liquid level in the formation to avoid introduction of uncondensed injected mobilizing fluids into the production means.

20. The method of claim 1 wherein steam is initially injected through both the injection and production means to mobilize the viscous hydrocarbons and establish communication in the formation between the injection and production means.

21. The method of claim 1 wherein the mobilizing fluid is circulated through the well to mobilize the viscous hydrocarbons and establish communication in the formation between the injection and production means.

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

23. The method of claim 8 wherein the solvent comprises one or more of a C₃to C₁₀solvent.

24. The method of claim 23 wherein the solvent is hexane.

25. The method of claim 23 wherein the heated fluids comprise up to 12 wt % solvent.

26. The method of claim 23 wherein the heated fluids comprise the steam and the solvent which are injected substantially simultaneously or alternating.

27. The method of claim 12 wherein the high mobility fluids comprise one or more of a C₃to C₁₀solvent.

28. The method of claim 27 wherein the solvent is hexane.

29. The method of claim 27 wherein the high mobility fluids comprise up to 12 wt % solvent.

30. The method of claim 29 wherein the high mobility fluids comprise the steam and solvent which are injected substantially simultaneously or alternating.

31. The method of claim 1 wherein the mobilizing fluid further comprises one or more of surfactants and non-condensing gases.