CA2884968A1 - System and method for producing oil from oil sands reservoirs with low overburden or permeable caprock and heavy oil reservoirs - Google Patents

Abstract

A subterranean hydrocarbon reservoir is heated by providing a plurality of heating wellbores through the reservoir. Each heating wellbore includes an outer casing which is sealed with respect to the reservoir and a tubing string in the outer casing to permit a heated fluid to be circulated in a closed loop through the tubing string and the annulus between the tubing string and the outer casing. A
separate production wellbore below the heating wellbores permits extraction of the heated hydrocarbons from the reservoir. A replacement fluid may be injected into the reservoir through a separate injection wellbore to drive the hydrocarbons to the production wellbore. Initially all wellbores in the reservoir may be configured as heating wellbores, but subsequent to initial heating, lowermost heating wellbores may be converted to production wellbores and uppermost heating wellbores may be converted to injection wellbores while intermediate wellbores remains as heating wellbores.

Description

SYSTEM AND METHOD FOR PRODUCING OIL FROM OIL SANDS
RESERVOIRS WITH LOW OVERBURDEN OR PERMEABLE
CAPROCK AND HEAVY OIL RESERVOIRS
FIELD OF THE INVENTION
The present invention relates to the production of hydrocarbons from a formation using a production well and a separate heater well, and more particularly, the present invention relates to use of a heater assembly in which a heat transfer fluid is circulated in a closed loop through the full cross section of the outer casing of the heater well or production well within which the heater assembly is used.
BACKGROUND
Currently within the Canadian oil sands industry, there are three leading methods of producing the oil sands: surface mining, cyclic steam and SAGD
(Steam Assisted Gravity Drainage). Unfortunately, there are vast amounts of hydrocarbons in oil sands resources which are considered unrecoverable because they are either too deep for strip mining or too shallow or devoid of caprock to ensure steam does not negatively impact the environment at the surface.
Another known process for recovering oil from oil sands or heavy oil reservoirs involves the use of an electrical resistance heater placed in a heater wellbore to heat the surrounding formation. Production in this instance occurs by gravity drainage to a separate production wellbore similar to SAGD. Electrical systems provide intense localized heat in various sections, but uniform distribution of the heat over larger areas is difficult to achieve.
SUMMARY OF THE INVENTION
According to one aspect of the invention there is provided a heating assembly for heating hydrocarbons in a subterranean reservoir using a heating

2 wellbore extending generally horizontally through the reservoir, the assembly comprising:
an outer casing string for lining the wellbore;
a tubing string arranged to be received within the outer casing string to define a first passage extending longitudinally through the tubing string and to define a second passage comprising an annulus space between the tubing string and the outer casing string;
a pump arranged for communication with the first and second passages so as to be arranged to circulate a heat transfer fluid therethrough in a closed loop;
and a heating unit arranged to heat the heat transfer fluid.
According to a second aspect of the present invention there is provided a method of heating hydrocarbons in a subterranean reservoir using a heating wellbore extending generally horizontally through the reservoir, the method comprising:
providing an outer casing string lining the heating wellbore;
providing a tubing string within the outer casing string to define a first passage extending longitudinally through the tubing string and to define a second passage comprising an annulus space between the tubing string and the outer casing string; and circulating a heated heat transfer fluid through the first and second passages in a closed loop configuration.
Preferably the outer casing string is arranged to be sealed relative to the surrounding reservoir such that the reservoir is arranged to be isolated from a pressure of the heat transfer fluid while permitting the heat transfer fluid to be in direct

3 heat exchanging relationship with the outermost casing in direct contact with the surrounding reservoir.
As described herein, the use of the casing of the wellbores as a heater within a closed hydraulic circuit uses heat transfer fluid within the casing to heat up the formation/reservoir for lowering viscosity of the oil to a degree which improves flow of oil under gravity forces for production. The system and method described herein involves minimal environmental impact so as to be well suited for use with oil sands reservoirs with low overburden or permeable caprock thereabove. The use of the wellbore casing to distribute the heat in the formation has the advantage of an unrestricted, very large area of heat distribution without the use of water and without any increased pressure on the surrounding formation. The heat can thus be distributed more evenly across the full length of the horizontal working leg of the heater wellbore, as compared to the localized heating accomplished using electrical systems for example. Furthermore, the heat transfer fluid is circulated in a closed loop so that none of the heat transfer fluid is introduced into the reservoir.
Accordingly the heat transfer fluid does not have to be collected again via a production pump, which otherwise makes pumping of the oil less efficient. The oil from oil sands is produced by gravity drainage to production wells distributed at the bottom of the oil bearing formation.
Preferably the outer casing string is arranged to be sealed relative to the surrounding reservoir such that the heating fluid is isolated from the reservoir and the reservoir is arranged to be isolated from a pressure of the heat transfer fluid.
The outer casing string preferably further comprises a plurality of ports formed therein for communication between an interior of the outer casing and the reservoir, each port being closed by a respective sealing member which is actuatable

4 from a closed sealing condition to an open condition.
The tubing string preferably includes longitudinally spaced apart openings formed therein so as to be arranged to communicate between the first and second passages. The openings may vary in size along the tubing string. A
check valve may be supported within each opening so as to be arranged to allow flow from the first passage to the second passage and to prevent flow from the second passage to the first passage therethrough. Additionally, a flow restrictor may span a bottom end of the inner tubing string.
When the tubing string includes a working section arranged to extend through the reservoir and an upper section arranged to communicate between a wellhead at surface and the working section, and preferably the assembly further comprises: i) an isolation plug arranged to span an interior of the outer casing string between the upper section and the working section of the tubing string; and ii) an outer tubing member arranged to surround the upper section of the tubing string between the wellhead and the isolation plug to define a third passage between the outer tubing member and the tubing string which is in open communication with the second passage.
The pump may be arranged to communicate with the first and second passages so as to be arranged to pump the heat transfer fluid down the first passage of the tubing string and up the second passage of the outer casing string in a first mode, and in the reverse orientation in a second mode.
A cross sectional area of the second passage may be greater than a cross sectional area of the'first passage.
When provided in combination with a monitoring string arranged to be received in a separate monitoring wellbore extending through the reservoir for monitoring temperature in the reservoir, the assembly may further comprise a heater controller arranged to controllably vary a heating temperature of the heating fluid and a flow rate of the heating unit responsive to the temperature monitored by the temperature monitoring string.

5 When provided in combination with a surface monitoring system arranged to monitor temperature in proximity to a surface of the ground above the reservoir, the assembly may further comprise a heater controller arranged to controllably vary a heating temperature of the heating fluid and a flow rate of the heating unit responsive to the temperature monitored by the surface monitoring system.
When provided in combination with an injection string arranged to be received in a separate injector wellbore in communication with the reservoir, a monitoring system may be arranged to monitor at least one characteristic relating to production of fluid from the reservoir, and an injection controller may be further provided to inject a replacement fluid into the reservoir through the injection string responsive to said at least one characteristic monitored by the monitor.
The assembly may further include spiral fins supported along an outer side of the tubing string so as to be arranged to interact with a flow of heat transfer fluid in the second passage between the tubing string and the outer casing.
The method may further include i) providing a separate production wellbore extending through the reservoir; ii) providing an outer casing string lining the production wellbore; and iii) providing a production tubing string in the production wellbore.
In preferred embodiments, the method further comprises:
i) prior to locating the production tubing string in the production wellbore,

6 providing a heating tubing string within the outer casing string of the production wellbore to define a first passage extending longitudinally through the heating tubing string and to define a second passage comprising an annulus space between the heating tubing string and the outer casing string of the production wellbore;
ii) circulating a heated heat transfer fluid through the first and second passages of the production wellbore in a closed loop configuration;
iii) removing the heating tubing string from the production wellbore when a minimum threshold temperature is reached within the reservoir;
iv) opening the outer casing string of the production wellbore to communicate with the reservoir subsequent to the removal of the heating tubing string from the production wellbore; and v) inserting the production tubing string and a downhole pump in the outer casing string of the production wellbore.
The method may further comprise: i) providing a separate injection wellbore extending into the reservoir having an outer casing string lining the injection wellbore and an injection tubing string extending through the outer casing string; and ii) injecting fluid into the reservoir through the injecting tubing string. In this instance, the method may yet further include:
i) prior to locating the injection tubing string in the injection wellbore, providing a heating tubing string within the outer casing string of the injection wellbore to define a first passage extending longitudinally through the heating tubing string and to define a second passage comprising an annulus space between the heating tubing string and the outer casing string of the injection wellbore;
ii) circulating a heated heat transfer fluid through the first and second passages of the injection wellbore in a closed loop configuration;

7 iii) removing the heating tubing string from the injection wellbore when a minimum threshold temperature is reached within the reservoir;
iv) opening the outer casing string of the injection wellbore to communicate with the reservoir subsequent to the removal of the heating tubing string from the injection wellbore; and v) inserting the injection tubing string into the outer casing string of the injection wellbore.
Preferably the injection wellbore is above heating wellbore.
The method may further comprise: i) providing at least one heating wellbore at each one of a plurality of different elevations in the reservoir, each heating wellbore having an outer casing string lining the heating wellbore and a heating tubing string within the outer casing string to define a first passage extending longitudinally through the tubing string and to define a second passage comprising an annulus space between the heating tubing string and the outer casing string for circulating a heated heat transfer fluid through the first and second passages in a closed loop configuration; and ii) opening the outer casing string in said at least one heating wellbore of an uppermost one of the different elevations in the reservoir and injecting a production stimulating fluid into said at least one heating wellbore of said uppermost one of the different elevations in the reservoir when a level of hydrocarbons in the reservoir falls below said uppermost one of the different elevations.
The tubing string in the heating wellbore preferably includes a working section extending through the reservoir and an upper section in communication between the working section and a wellhead at surface, such that the method may involve circulating the heated heat transfer fluid in communication with the outer casing string only along the working section of the tubing string.

8 Preferably the method includes circulating the heated heat transfer fluid in communication with the outer casing string such that the reservoir remains isolated from a pressure of the heat transfer fluid.
Preferably the method includes orienting the heating wellbore to extend generally horizontally through the reservoir above a separate production wellbore.
Preferably the method includes orienting the heating wellbore to extend generally horizontally through the reservoir in proximity to a plurality of spaced apart production wellbores.
Preferably the method includes controlling a rate of heat delivery to the reservoir by the heated heat transfer fluid responsive to a monitored temperature of the reservoir to maintain temperature above a minimum reservoir temperature limit.
Preferably the method includes providing the tubing string in the heating wellbore with a working section extending through the reservoir and an upper section in communication between the working section and a wellhead at surface, and monitoring the reservoir temperature near a toe end of the working section opposite from the upper section.
Preferably the method includes providing the tubing string in the heating wellbore with a working section extending through the reservoir and an upper section in communication between the working section and a wellhead at surface, and monitoring the reservoir temperature near a heel end of the working section in proximity to the upper section.
Preferably the method includes providing the tubing string in the heating wellbore with a working section extending through the reservoir and an upper section in communication between the working section and a wellhead at surface, and monitoring the reservoir temperature at a plurality of longitudinally spaced positions

9 along the working section.
Preferably the method includes controlling a rate of heat delivery to the reservoir by the heated heat transfer fluid responsive to a monitored temperature in proximity to a surface of the ground above the reservoir to maintain temperature below a maximum surface temperature limit.
Preferably the method includes controllably varying a rate of heat delivery to the reservoir by enabling a flow rate of the heat transfer fluid to be adjusted.
Preferably the method includes heating the heat transfer fluid using a heater unit and controllably varying a rate of heat delivery to the reservoir by enabling a heating rate of the heater unit to be adjusted.
Preferably the method includes using a plurality of heating wellbores extending through the reservoir of the same configuration relative to one another, and controllably varying a rate of heat delivery to the reservoir by varying a number of the heating wellbores which are active.
The method may include monitoring a pressure of the reservoir using a separate monitoring wellbore.
The method may include i) monitoring a temperature or a pressure of the reservoir using a separate monitoring wellbore; and ii) injecting a replacement fluid into the reservoir through the monitoring wellbore to compensate for produced fluid removed from the reservoir.
The method may include monitoring a pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain a constant reservoir pressure.
The method may include monitoring a pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain a pre-production equilibrium pressure within the reservoir.
The method may include monitoring a pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain pressure within the 5 reservoir above a lower pressure limit.
The method may include monitoring a pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain pressure within the reservoir below an upper pressure limit.
According to another aspect of the present invention there is provided a

10 method of producing oil from a reservoir comprising:
providing at least one heating wellbore extending through the reservoir so as to be arranged to heat the reservoir;
providing at least one production wellbore extending through the reservoir so as to be arranged to remove produced fluids from the reservoir;
monitoring temperature in proximity to a surface of the ground above the reservoir;
controlling a heat rate of said at least one heating wellbore responsive to the temperature monitored in proximity to the surface so as to maintain temperature at the surface of the ground below an upper temperature limit.
According to yet another aspect of the present invention there is provided a method of producing oil from a reservoir comprising:
providing at least one production wellbore extending through the reservoir so as to be arranged to remove produced fluids from the reservoir;
providing at least one injection wellbore extending through the reservoir independently of said at least one production wellbore; and

11 injecting a replacement fluid into the reservoir through said at least one injection wellbore to compensate for produced fluid removed from the reservoir.
Various embodiments of the invention will now be described in conjunction with the accompanying drawings in which:
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a perspective view of an oil bearing reservoir to which the present invention has been applied;
Figure 2 is an end elevational view of the reservoir according to Figure 1;
Figure 3 is a partly sectional perspective view of reservoir illustrating a relationship between the heating wellbores, the production wellbores and one monitoring wellbore;
Figure 4 is a top plan view of the reservoir according to Figure 1;
Figure 5 is a sectional side elevational view of the reservoir according to Figure 1;
Figure 6 is a schematic representation of the reservoir for use in geothermal modelling;
Figure 7 is a graphical representation of a temperature profile at the lateral boundaries (edges) between exemplary heating wellbores within the formation according to geothermal modelling;
Figure 8 is a graphical representation of a temperature profile between different exemplary heating wellbores within the formation according to geothermal modelling;
Figure 9 is a graphical representation of a temperature profile at the center of the formation between yet further exemplary heating wellbores within the

12 formation according to geothermal modelling;
Figure 10 is a graphical representation of heating energy requirements to heat the reservoir over time according to the geothermal modelling;
Figure 11 is another graphical representation of heating energy requirements to heat the formation up to 7 meters outside of the exemplary cluster of wells over time according to the geothermal modelling;
Figure 12 is a flow chart representing various steps of the method according to the present invention;
Figure 13 is a sectional elevational view of an initial heating cycle using a heating assembly in both a heating wellbore and a production wellbore;
Figure 14 is a sectional elevational view of a production cycle subsequent to the initial heating cycle using a heating assembly in the heating wellbore and a production assembly in the production wellbore;
Figure 15 is an enlarged sectional elevational view of the isolation plug, expansion joint, and flow cross over;
Figure 16 is a sectional elevational view of the working section of the heating assembly in a first flow direction of the heat transfer fluid in which the check valves are open;
Figure 17 is an enlarged sectional view of one of the open check valves according to Figure 16;
Figure 18 is a sectional elevational view of the working section of the heating assembly in a reverse second flow direction of the heat transfer fluid in which the check valves are closed;
Figure 19 is an enlarged sectional view of one of the closed check valves according to Figure 18; and

13 Figure 20 is a perspective view of an alternate configuration of the system using a single heating wellbore extending horizontally through the reservoir with four production wellbores extending vertically through the reservoir.
In the drawings like characters of reference indicate corresponding parts in the different figures.
DETAILED DESCRIPTION
Referring to the accompanying figures, there is illustrated a system and method for producing hydrocarbons from a reservoir or formation in instances where heating of the hydrocarbons may be advantageous. Some examples of suitable applications of the present invention include heavy oil and oil sands reservoirs with low over burden and/or permeable caprock; however, the invention is also suitable for any other reservoir where heating of the hydrocarbons to lower viscosity thereof is advantageous, for example mature reservoirs, tight oil reservoirs and others.
The system is particularly distinguished from the prior art by the use of a novel heating assembly 10.
The system generally involves forming a plurality of wellbores within a prescribed reservoir or formation in which one or more of the wellbores are designated as production wells 12, one or more of the wellbores are designated as heater wells 14, and one or more of the wellbores are designated as monitoring wells 16.
The wellbore of each production well is arranged such that the production zone 18 (or working section) of the wellbore extends generally horizontally through the reservoir in proximity to the bottom end thereof. The working sections of the three production wells of the illustrated embodiment are at laterally spaced apart positions relative to one another in a generally common horizontal plane.

14 An outer casing string 20 is provided within each of the production wellbores to extend along the full length thereof including the production zone 18 within the reservoir and the upper portion 22 extending between the production zone 18 and a suitable well head 24 at the surface. The casing is typically initially formed to be fully sealed along the length thereof relative to the wellbore including at the terminal end of the wellbore defining the toe end 26 of the wellbore opposite from the upper portion 22 for initial use as a heating well prior to a perforating or otherwise opening of flow ports in the outer casing as described in further detail bellow.
Each of the heater wellbores 14 is similarly formed to include a working section 28 extending generally horizontally through the formation at an intermediate location above the production zones of the production wellbores, and an upper portion 30 extending between the working section 28 and the surface where a suitable wellhead 32 is provided. Each heater wellbore 14 locates one of the heating assemblies 10 according to the present invention therein.
Each heating assembly generally comprises an outer casing string 34 which spans the full diameter of the wellbore and extends along both the upper portion and working section thereof. The outer casing is sealed with respect to the surrounding reservoir along the full length of the wellbore from the surface to the toe end 36 defining the bottom end of the wellbore. The outer casing 34 is typically initially formed with ports for communicating between the interior of the outer casing and the formation surrounding the wellbore with seals closing the ports initially such that the outer casing is fully sealed along the length thereof relative to the wellbore including at the terminal end oi the wellbore defining the toe end 26 of the wellbore opposite from the upper portion 22. The ports are initially sealed closed for initial use as a heating well. In some instances, the seals of the ports in the outer casing 34 may be subsequently opened using appropriate tools which are actuatable from the wellhead for opening the flow ports in the outer casing 34 to subsequently use the heating well for the injection of production stimulating fluids as described in further detail bellow.
5 An inner tubing string 38 is mounted within the outer casing 34 to span substantially the full length of the wellbore from the wellhead 32 to the toe end 36.
The bottom end of the inner tubing string remains open and spaced from the toe end 36 of the wellbore such that any fluids pumped down through the inner tubing string 38 readily flow out of the bottom end of the inner tubing string into the surrounding 10 annulus between the inner tubing string and the outer casing.
Perforations or any other suitable type of openings or ports are provided at longitudinally spaced positions along the inner tubing string 38 at the working section 28 of the heater wellbore to permit fluids pumped down through the inner tubing string to be injected into the annulus between the inner tubing string and the outer casing at various longitudinal

15 positions along the working section 28.
Various controls are employed, for example sliding sleeves and the like which are known to be employed in fracturing operations, to control the amount of heating fluid being distributed from the inner tubing string to the outer casing at the intermediate openings along the tubing string. In the illustrated embodiment, check valves 39 are provided in the ports respectively to permit fluid flow from the interior of the inner tubing string 38 to the outer casing, while restricting the reverse flow from the outer casing annulus to the inner tubing string 38 through the longitudinally spaced apart ports as described in further detail below.
Alternatively, the perforations or flow ports can be arranged to vary in size to accommodate even heat distribution and pressure losses in the inner tubing

16 string. The perforation sizes can be calculated by pressure differential between the heel and toe of the horizontal working section of the tubing. In either instance, the openings are typically arranged such that most of the heat transfer fluid is not released at the beginning of the openings, but rather the majority of the heat transfer fluid escapes the inner tubing string to the outer casing through the open bottom end of the inner tubing string.
The heating assembly further includes an outer tubing member 40 which surrounds an upper portion of the inner tubing string 38 along the full length of the upper portion 30 of the wellbore. The outer tubing member 40 is thus concentrically received within the outer casing 34 while concentrically receiving the inner tubing 38 therein. The outer tubing member 40 may be single wall or dual wall tubing which is arranged to minimize the heat loss through conduction into the overburden. The outer tubing member 40 is thus heat insulated to target the heat distribution to the working section of the wellbore which extends through the reservoir.
An isolation plug 42 and expansion joint 43 are mounted to span the full interior diameter of the outer casing 34 at the bottom of the outer tubing member 40 in proximity to a heel section of the heating wellbore between the upper portion 30 and the working section 28. The isolation plug 42 and expansion joint 43 is sealed with respect to the outer casing 34 and is suitably arranged to receive the outer tubing member 40 and the inner tubing string 38 communicating therethrough.
In this manner, a first passage is defined in communication between the well head 32 and the toe end of the outer casing 34 through the interior of the inner tubing string 38 through which fluid may be pumped down from the well head into the annulus between the outer casing 34 and the inner tubing string 38 within the working section 28 of the wellbore. The annulus between the outer casing 34 and the inner

17 tubing string 38 within the working section 28 of the wellbore defines a second passage for communicating back up towards the wellhead. The outer tubing member 40 defines a third passage as a longitudinally extending annular space between the upper portion of the inner tubing string and the outer tubing member.
As described herein, the first passage, the second passage and the third passage collectively form a closed loop which permits the heat transfer fluid to be pumped in either direction of the loop to permit the heat distribution to be optimally balanced along the formation. The reversing of the flow should be done cyclically. The temperature sensors in the monitoring wells, at the heel and at the toe of the horizontal wells, will determine the frequency of the flow reversing cycles.
A flow crossover 44 communicates with the bottom end of the outer tubing member 40 immediately below the isolation plug 42 to provide communication between the second passage within the working section of the outer casing 34 therebelow and the third passage within the outer tubing member 40 thereabove.
The third passage communicates between the top end of the second passage of the working section 28 and the wellhead at surface.
In this manner, any fluid pumped downwardly through the inner tubing string (the first passage) is in turn received within the surrounding annulus (the second passage) within the working section 28. Fluid passes from the first passage to the second passage primarily through the bottom end of the inner tubing string 38, but also through the various perforations or ports at spaced positions along the working section of the inner tubing string 38. The fluid can be pumped down through the inner tubing string 38 with sufficient pressure to produce an upward return flow through the second passage and subsequently upwardly through the third passage between the outer tubing member 40 and the upper portion 30 of the inner tubing

18 string 38. In this manner, fluid is circulated through the entire inner diameter of the working section 28 of the outer casing 34 in a first direction of the closed looped configuration due to the sealed arrangement of the outer casing 34 relative to the wellbore.
When the flow direction is cyclically reversed in a second direction of the closed loop, the flow of heat transfer fluid is instead pumped down the third passage and the second passage therebelow with sufficient pressure to cause a return flow up the first passage within the inner tubing string. In this instance, flow through the intermediate openings in the inner tubing string is preferably minimized by closing any ports which can be operated between open and closed states, or more preferably by the use of the check valves 39 which permit the openings to be closed automatically in response to a change in flow direction.
A flow restrictor 45 is mounted at the bottom free end of the inner tubing string 38. The flow restrictor 45 can be fixed, be adjustable, or be operable in the form of a check valve which restricts flow in the first flow direction of Figure 16, but which opens to a full flow area in the reverse second flow direction of Figure 18.
In the instance of a fixed restrictor as shown in the illustrated embodiment, the restrictor is in the form of a body which spans the internal diameter of inner tubing string 38 and defines a restricted orifice therein having an internal diameter which is reduced relative to the internal diameter of the inner tubing string 38. The flow restrictor 45 thus reduces the cross sectional flow area through the bottom end of the inner tubing string relative to the remainder of the inner tubing string. The flow restrictor may thus provide some back pressure to encourage a controlled amount of flow through the ports locating the check valves 39 therein when the heat transfer fluid flows in the first direction shown in Figures 16 and 17. When

19 flow is reversed into the second direction shown in Figures 18 and 19, the flow restrictor 45 may provide a slight negative pressure to the fluid within the inner tubing string 38 as compared to the fluid in the surrounding annulus between the inner tubing string 38 and the outer casing 34 so as to encourage closure of the check valves 39.
Spiral fins can further be installed along the outer side of the inner tubing string so as to interact with flow of heat transfer fluid within the second passage and so as to maintain uniform heat distribution inside the second passage defined between the inner tubing string and the outer casing, thus avoiding temperature layering of the heat transfer fluid and improving the heat transfer efficiency.
The heater wellbores 14 are typically arranged in groups in which the working sections 28 of all heater wells within one group are typically located at a common prescribed depth at laterally spaced apart positions relative to one another within the reservoir. In alternative arrangements however, depending upon the configuration of the reservoir, a different grouping of heater wells may be desired.
Within the illustrated embodiment, a single heating unit 50 is associated with each group of heater wellbores for heating a heat transfer fluid which is circulated in closed loop through the heating assemblies as described above. The heating units may be of various configurations for consuming various fuel types. Each heating unit can be arranged to be cycled on and off for different durations or be operated at a variable BTU rate to adjust the overall rate that heat is delivered to the heat transfer fluid circulated therethrough.
Each heating unit 50 is also associated with a respective pump for pumping the fluid from the heating unit to the well head in a first direction of the closed loop resulting in fluid being pumped down the first passage defined within the inner tubing string with sufficient pressure to cause a return flow of the heat transfer fluid from the working section of the outer casing, back up the third passage within the outer tubing member 40 in the upper portion of the wellbore, to be returned to the heating unit 50. Using a suitable switching arrangement of valves, the pump can also be used to pump the heat transfer fluid in the second direction of the closed loop 5 heating assembly described above.
A manifold 52 is associated with each heating unit for redirecting the pumped heating fluid to each of the heating assemblies associated with that heating unit. Adjustable valves are provided which can be controlled to adjust the proportion of the flow rate distributed among all of the heating assemblies of one group of 10 heating assemblies associated with one heating unit 50. The pumping rate can also be variably adjusted such that the overall rate of heat delivered to the formation can also be adjusted by adjusting -le flow rate of the heat transfer fluid in addition to adjusting various parameters relating to the heating rate of the heating unit.
In the illustrated embodiment, each monitoring well 16 comprises a 15 generally vertical wellbore extending through the reservoir. An outer casing 60 is provided within the monitoring wellbore 16 with perforations or other openings therein in open communication with the surrounding reservoir at a plurality of different elevations along the length of the wellbore.
A monitoring string 62 is received within the outer casing 60 of each

20 monitoring wellbore to communicate along the length of the wellbore back up to a suitable wellhead 64 at the surface in connection with the top end of the outer casing 60. The monitoring string in the preferred embodiment comprises an electrical or fibre optic line with a plurality of sensing modules 68 at longitudinally spaced positions therealong. Each sensor module 68 comprises either a pressure sensor or a temperature sensor and is located in proximity to respective perforations in the outer

21 casing 60 for monitoring the respective pressure and/or temperature of the surrounding formation at each respective elevation.
The formation temperature and pressure are monitored at all times to make sure that the reservoir is not being over-heated or over-pressured. This could occur from the expansion of fluids in the reservoir, from the generation of steam by the heating of the formation water, or injection of fluids at a higher rate than required.
The balance of pressure should be maintained during the heating cycle or the production cycle. If overpressure occurs, the monitoring wells can be used to bleed/relief the over-pressure. These reservoirs are usually at the normal pressure gradient condition.
Each monitoring well 16 may additionally be associated with an injector unit in communication with the outer casing 60 of the monitoring well through the well head 64. The injection unit is arranged for injecting a replacement fluid into the formation by pumping the replacement fluid into the outer casing of the monitoring well for subsequent dispersion through the reservoir through the perforations in the outer casing 60 to prevent subsidence.
The injection unit operates in conjunction with suitable monitoring equipment at the production wells which monitor the amount of fluid being removed from the reservoir. Pressure sensors within each monitoring well may also monitor the resulting downhole pressure as the produced fluids are removed. The injection unit operates in response to the monitoring equipment to inject a corresponding volume of replacement fluid which either matches the produced volume removed from the reservoir or which maintains pressure within the formation at an initial pre-production equilibrium pressure. The injection unit avoids injecting any additional fluids which would result in an excess pressure within the formation in the range

22 typically used for stimulation of formations in other production environments.
The system further includes a surface temperature monitor in the form of an array of sensor modules 70 spaced apart laterally and longitudinally relative to one another substantially at the surface above the reservoir. More particularly, the sensor modules can be located in wells within the overburden or caprock above a formation such that the sensor modules are able to monitor temperature at or near the surface within the overburden. The array of modules is arranged to substantially fully span the entire area above the reservoir being heated by the heater assemblies 10 described above.
The system further includes a control system which is arranged to receive temperature data from all of the monitoring wells and the surface temperature monitor. The control system further receives temperature data corresponding to a measured temperature of the heat transfer fluid of each heating assembly as the fluid is both injected into the corresponding heater wellbore and is withdrawn from the respective heater wellbore. Various pressure conditions throughout the system can also be monitored. At a minimum, one monitoring well should be used and is typically located in proximity to the toe ends of the heater wells. A monitoring well can be placed at the heel of the heater wells to monitor the even distribution of heat in the formation.
The control system is used to evaluate the various collected temperature and pressure data to enable the optimal control of various parameters relating to the heating of the reservoir by the various heating assemblies 10.
Various parameters include the flow rate of the heat transfer fluid, the heating rate of the heating units, the number of active heating units, and the initial use of production wells as heater wells for example. The various parameters are controlled to maintain

23 temperature throughout the reservoir above a minimum threshold temperature suitable for production while maintaining temperature in the overburden or caprock above the reservoir and adjacent to the surface below a prescribed threshold temperature which would negatively affect vegetation at the surface.
The present invention initially involves some preliminary exploration of a reservoir using conventional techniques to map the boundaries of the formation.
Geothermal modeling of oil sand temperature as described in further detail below is then performed. The resulting heat transfer simulations dictate an optimal distribution of heating wellbores throughout the reservoir to uniformly heat the oil sands therein.
The simulation ensures that a certain level of temperature has to be reached throughout the reservoir to reduce the viscosity of the oil and to allow the downward migration of the oil under gravity forces towards production wellbores therebelow along the bottom of the reservoir for optimum production.
Other factors which are considered include the rock's formation properties so that the amount of heat required to heat the reservoir can be calculated and the length of time required for the initial heating cycle before production can start can also be determined. Also, prior analysis of the oil is required to determine the level of temperature that needs to be reached for the oil to flow easily through the reservoir and achieve efficient flow rates. For each heating well bore, the location of perforations or ports along the inner tubing string at longitudinally spaced positions along the working section of the wellbore are also determined for optimal distribution of the heated heat transfer fluid into the surrounding outer casing for optimal heat distribution along the length thereof.
In addition to the heating wellbores and the production wellbores being provided, one or more temperature monitoring wells are located to extend through the

24 reservoir at various locations. When the production and heating wellbores include horizontal working sections extending through the reservoir from a heel end joined to an upper section of the wellbore extending to surface, to a toe end opposite the upper section, temperature monitoring wells are preferably provided, at least at the toe end, and additionally at longitudinally spaced positions along the working section to be located at one or more intermediate locations as well as adjacent the heel end.
The surface temperature monitors are located in respective shallow wells within the overburden above the reservoir in proximity to the surface for measuring the temperature of the ground along a grid pattern encompassing substantially the entire area above the reservoir.
Initially, the production wellbores and the heater wellbores are all provided with an outer casing string lining the wellbore. The outer casing is sealed along the length thereof, including at the toe end, relative to the surrounding reservoir.
Heating assemblies as described above can then be provided.
In the exemplary embodiment, heating assemblies at a common elevation are grouped together as a single group associated with a single dedicated heater unit supplying heated heat transfer fluid to all of the heater assemblies within that group through an appropriate manifold. Heat is initially provided to the formation through all of the production anG heating wellbores using the heating assemblies until a minimum reservoir temperature is reached throughout the reservoir in a substantially uniform manner. Once the minimum temperature is reached within the formation, typically the heating assemblies within the production wellbores are removed so that the production wellbores can be subsequently used for production.
Prior to insertion of a production tubing string, the outer casing strings of the production wellbores must be perforated or ports opened at longitudinally spaced positions along the working sections thereof. The perforations may occur by various conventional means including use of sliding sleeves to open ports, use of burst pressure to open ports, or any other comparable means which are known in the industry for example.
5 In addition to removal of heating assemblies from the production wellbores after the initial heating cycle, some of the additional heating assemblies in respective heating wellbores may be turned off or removed from one or more of the groups as determined by the heat transfer simulations so that only a minimum number of heating assemblies remain operational to maintain desired formation temperature.

Turning off the heating assemblies in heating wellbores where heating is no longer required may involve closing the valves to specific heating assemblies to cease circulation of heat transfer fluid therethrough, while maintaining circulation of heat transfer fluid in other heating assemblies where heating is still desired. The heating unit together with the associated heating assemblies within any groups which are no 15 longer in use can be moved to another site to begin the initial start-up heating stage at a different area of the reservoir, if required.
With the remaining heating assemblies operating to maintain the temperature of the reservoir near or above a minimum production temperature, production through the production wellbores can then begin using suitable production equipment placed in the production wellbores. In addition to monitoring temperature through the temperature monitoring wellbores, the pressure can also be monitored.
Monitoring the pressure within the reservoir together and/or monitoring the volume of fluid being produced, a prescribed amount of replacement fluid can be determined and injected through the monitoring wells using suitable injection

25 equipment as described above. The replacement fluid is injected to make up for lost

26 pressure and/or volume within the reservoir so as to maintain pressure within the reservoir substantially at an equilibrium pressure range which prevents subsidence.
Typically, the injected fluids are also used to stimulate the flow of hydrocarbons towards the production wells. Sufficient fluids are typically injected to make up for the volume of produced oil, without creating significant pressure in the reservoir.
In the initial phase of oil production, the flow of oil is stimulated by injecting fluids (liquids or gases) through the monitoring and injection wells 16 to make up for the volume of oil produced and drive down the oil front towards the producing wells, by creating a differential pressure from the top of the reservoir, towards the bottom where the production wells 12 are located.
In subsequent stages or phases of oil production, when the oil level drops under the top row of heating wells 14, flow ports in the upper level of heating wells 14 will be opened and they will become injection wells by removing the heating tubing string 38 are replacing it with an injection string connected to injection equipment at the wellhead for injecting fluids into the formation through the converted wells. This will create a more evenly distributed drive front. The same process can continue with the next row of heating wells, as the oil level drops in the reservoir below that respective row in elevation.
The ports in the heating wells will be opened after the oil level will drop under the first top row of heating wells, as these wells don't need to heat the reservoir anymore. These wells will continue to be used as injection wells. The opening of flow ports in these injection wells, is the same process that we would use to open the flow ports in the production wells, after the initial phase of heating the reservoir.

27 The injection of fluids is typically done continuously throughout the various stages or phases of production, to make up for the volume of produced oil.
Injecting through the heater wells will distribute the injected fluid more evenly through the reservoir, compared with only injecting through the monitoring and injection wells.
Accordingly, the system typically involves providing one or more heating wellbores at each one of a plurality of different elevations in the reservoir, in which each heating wellbore includes an outer casing string and a heating tubing string for closed loop circulation of the heated heat transfer fluid therethrough. When a level of hydrocarbons in the reservoir falls below the uppermost row of heating wellbores in elevation, the outer casing string of the one or more heating wellbores are converted to injection wellbore, but opening the ports in the outer casing, following by injection of a production stimulating fluid into the converted wellbores.
Throughout the operation of the heating assemblies during either the initial start-up stage or at a subsequent maintenance stage, an overall controller can be used to record the variaus temperature and pressure monitoring data.
Temperature of the heat transfer fluid entering and exiting each heating wellbore can be monitored in addition to the surface temperature of the ground and the internal temperature of the reservoir at various elevations therein.
The various heat rate parameters which can be controlled by the controller include varying the number of heating units and heating assemblies which are operational and varying the flow rate to one or more groups of heating assemblies by varying the pumping rate or varying the proportional flow rate between heating assemblies within one group associated with a common pumping assembly by controlling the flow distributed through the manifold among the various heating assemblies. Furthermore, the heating rate of the heating units can be adjusted by

28 various means, for example including the cycling on and off times of the heater, the number of burners activated within a given heater and the like.
Using the system and method described herein, the present invention is particularly suited for recovery of oil from reservoirs with low over burden and/or permeable caprock which are otherwise relatively inaccessible using existing techniques. The technology utilizes the well casing with closed loop heating fluid to create an effective downhole heater.
The outer casing is generally understood to comprise the outermost layer of the wellbore which is the most efficient form of heating using conduction.
Typically there are two phases of heating. This includes the initial start-up heating phase of the oil reservoir where heat is applied through the heating wellbores and through the producer wellbores. This is followed by maintenance of the reservoir temperature once the target reservoir temperature is achieved to ensure continued production of oil from the oil sands. The heating assemblies are accordingly pulled from the producing wells at this point and pumps are installed in the producing wells to pump the oil which has been heated and drains downward, towards the production wells by gravity. The remaining heater wells remain operational but only at a maintenance temperature which may be lower than the initial temperature needed to heat up the formation.
The use of any heat transfer fluid which remains in a liquid phase throughout the close loop circulation provides optimal accuracy in control of temperature with less energy consumption to heat and maintain the desired temperature within the reservoir.
In the illustrated embodiment the working sections of the production wellbores extend horizontally below the working sections of the heating wellbores. In

29 yet further embodiments, one or more heater wells may span horizontally across a plurality of vertical production wellbores extending downwardly through the reservoir such that each heating well spans in proximity across a plurality of production wells.
Throughout operation, the array of thermal sensors at the surface monitors the change in temperature caused by the downhole heaters and the heat transfer ratio will be adjusted to avoid the rise of surface soil temperature and the destruction of vegetation. Unlike SAGD, the present invention prevents any heat transfer fluid pressure from escaping the sealed outer casings such that the surrounding reservoirs are isolated from the pressure of the heat transfer fluid being pumped in a closed loop configuration.
As previously described above, replacement fluids are injected to compensate for the loss of volume resulting from the production of the oil.
This avoids subsidence and provides pressure maintenance and pressure control. If various types of fluids (e.g. Nitrogen, CO2, etc.) are injected, it will promote further oil production because expansion of fluids in a heated formation would force the oil downward towards the production wells.
Fluid injection would be especially useful towards the end of the production cycle, to force the remaining oil towards the production wells thus increasing oil recovery factor.
With reference to Figures 6 through 11, an example of the geothermal modeling of oil sand temperature will now be described. The purpose of the geothermal modeling was to predict the oil sand temperature in the area around the heating pipes. Thirteen heating pipes, 7 inches in diameter, were incorporated in the geothermal model. The pipes were positioned in a checker pattern at a distance of 7 m across the oil sand layer and at a distance of 3.5 m along the oil sand layer. Figure 6 shows locations of the heating pipes within the geothermal model mesh. The analyses were carried out using a 12 month timeline simulation.
Geothermal modeling: For the current study, a two-dimensional version of the heat transfer software was used to predict the oil sand temperature.
The 5 program uses the finite element method to compute a numerical solution for the heat transfer problem. The general form of two-dimensional equation for transient heat transfer is written:
,527, C(T, x, y)¨dT = k(T, x, y) ,327,+ x, y) __ ; (1) dt ax2 ay 2 where:
10 C(T,x,y) ¨ volumetric heat capacity;
k(T,x,y) ¨ thermal conductivity;
T ¨ temperature;
t time.
Using well-known Goodman's and Kirchoff's substitutes to the left and 15 right portions of Equation 1 respectively, the non-linear equation is transformed to a quasi-linear equation which was solved numerically using the finite element method.
Boundary and Initial Conditions of Model: The model used for the analysis was 134 m wide, 500 m deep and contained 12699 nodes and 24928 finite elements. The initial soil temperature throughout the model mesh was gradually 20 increased with depth from 5 C on the ground surface to 15 C at the 500 m depth.
The constant temperature of 4.7 C was used as the upper boundary temperature on the ground surface of the model mesh, roughly corresponding to the mean annual soil temperature within the Fort McMurray area.
At the model lateral boundaries, a zero heat flux condition was applied.
25 Such boundary condition means that the heat influence does not spread at a distance of 60 m from the heating pipes (see Figure 6). A heat flux corresponding to the geothermal gradient of 0.02 C/m was introduced at the bottom boundary of the model mesh.
The constant temperature of 350 C was used as the boundary temperature for all of the 13 heating pipes during the simulation time of 12 months.
Soil Thermal Properties: The analyses were carried out for a soil profile consisting of overburden, oil sand, and underlying McMurray Formation rock.
Table 1 provides thermal properties of the modeled soils.
Table 1: Thermal Properties of Soils Soil Thermal conductivity, Heat capacity, kJ/rn'irK
W/mrK
Overburden 2.73 2679.7 Oil Sand 1.60 1947.0 Rock 2.33 2093.5 Results: Figures 7, 8 and 9 demonstrate temperature profiles across the oil sand layer for cross sections passing through heating pipes 1-6-11, 4-9, and 2-7-12, respectively. The temperature profile passing through pipes 1-6-11 (Figure 7) corresponds to the edge of the heated zone. However, it can be seen (Figure 7) that after 6 months of the heating, the oil sand temperature at elevations 363 m and 371 m (middle between the heating pipes) will be approximately 180 C, in this particular example, which is required for successful draining and pumping of oil.
Figure 8 shows the temperature profile along the second row (from the edge) of the heating pipes. It can be seen that the oil sand temperature at the middle between the heating pipes approaches to 180 C after 4 months (2 months faster than for the edge row of the heating pipes). A similar temperature profile is observed at Figure 9 (the third row of the heating pipes from the edge). Again, it can be seen the oil sand temperature at the middle between the heating pipes approaches to 180 C
after 4 months of the heating pipe operation.

Figure 10 demonstrates the total required energy for a 1 m thick slice of various widths of the heated zone during the 12 months of the heating operation. The total required energy includes the energy required for heating the central zone (the majority of the heated zone between the second rows of the heating pipes), and the heated zone edges. It can be seen that the first months of the heating operation will require a considerable amount of energy ranging from 125 ¨ 375 M-Btu (for the first month) to 75 ¨ 175 M-Btu (for the fourth month). At the end of the twelfth month, the total required energy will be considerably less, in the order of 25-70 M-Btu.
Figure 11 shows that for a pilot project, if the width of the heated edges will be 7m, the amount of the required energy for the first month of heating may be in a range of 42 M-Btu. More than 50% of the energy (approximately 26 M-Btu) will be required for heating of the edges. It should be clear that the percentage of energy required for heating edges decreases with decrease of the width of the heating zone as shown at Figure 10.
The method steps of the preferred embodiment of the present invention are summarized in Figure 12 generally as follows: i) Drill exploration wells and collect core samples from the formation; ii) Perform analysis of the rock formation and of the hydrocarbons in the formation; iii) Establish the temperature level required to heat the formation to achieve proper viscosity for flow; iv) Engineering design and simulation to determine well spacing and optimal heat transfer; v) Drill and case production, heater and monitoring wells; vi) Install heating flow loop into production and heating wells and pressure and temperature sensors into monitoring wells; vii) Install surface heat exchangers, manifolds, pumps and PLC controllers; viii) Heat production and heater wells while monitoring temperature and pressure on surface and in reservoir through surface sensor and monitoring wells; ix) Once the desired production temperature is achieved in the reservoir, the thermal fluid is circulated out and the heater equipment is removed from the production well; x) The heating fluid flow controller also monitors surface temperature to make sure limits are not exceeded; xi) If the reservoir temperature is hotter at the toe or heel; flow is reversed automatically via the flow controller to obtain even heat distribution; xii) Control system will automatically control the temperature and flow rate of the heat transfer fluid to achieve desired reservoir temperature via information from the monitoring wells; xiii) Ports or perforations are opened in the production well outer casing to access the reservoir and the well is equipped with a pump and put on production; xiv) As the reservoir heats up the amount of heat exchangers can be reduced at the surface to maintain the temperature and moved to other projects to maximize efficient use of the equipment;
and xv) Throughout the process, the reservoir pressure is continuously monitored. As the reservoir is depleted, fluid is injected to maintain the reservoir pressure.
Since various modifications can be made in my invention as herein above described, and many apparently widely different embodiments of same made within the spirit and scope of the claims without departing from such spirit and scope, it is intended that all matter contained in the accompanying specification shall be interpreted as illustrative only and not in a limiting sense.

Claims (47)

CLAIMS:

1. A heating assembly for heating hydrocarbons in a subterranean reservoir using a wellbore extending through the reservoir, the assembly comprising:
an outer casing string for lining the wellbore;
a tubing string arranged to be received within the outer casing string to define a first passage extending longitudinally through the tubing string and to define a second passage comprising an annulus space between the tubing string and the outer casing string;
a pump arranged for communication with the first and second passages so as to be arranged to circulate a heat transfer fluid therethrough in a closed loop, and a heating unit arranged to heat the heat transfer fluid.

2. The assembly according to claim 1 wherein the outer casing string is arranged to be sealed relative to the surrounding reservoir such that the heating fluid is isolated from the reservoir and the reservoir is arranged to be isolated from a pressure of the heat transfer fluid.

3. The assembly according to claim 2 wherein the outer casing string further comprises a plurality of ports formed therein for communication between an interior of the outer casing and the reservoir, each port being closed by a respective sealing member which is actuatable from a closed sealing condition to an open condition.

4. The assembly according to any one of claims 1 through 3 wherein the tubing string includes longitudinally spaced apart openings formed therein so as to be arranged to communicate between the first and second passages.

5. The assembly according to claim 4 wherein the openings vary in size along the tubing string.

6. The assembly according to either one of claims 4 or 5 further comprising a check valve supported within each opening so as to be arranged to allow flow from the first passage to the second passage and to prevent flow from the second passage to the first passage therethrough.

7. The assembly according to any one of claims 4 through 6 including a flow restrictor spanning a bottom end of the inner tubing string.

8. The assembly according to any one of claims 1 through 7 wherein the tubing string includes a working section arranged to extend through the reservoir and an upper section arranged to communicate between a wellhead at surface and the working section, and wherein the assembly further comprises:
an isolation plug arranged to span an interior of the outer casing string between the upper section and the working section of the tubing string, and an outer tubing member arranged to surround the upper section of the tubing string between the wellhead and the isolation plug to define a third passage between the outer tubing member and the tubing string which is in open communication with the second passage.

9. The assembly according to any one of claims 1 through 8 wherein the pump is arranged to communicate with the first and second passages so as to be arranged to pump the heat transfer fluid down the first passage of the tubing string and up the second passage of the outer casing string.

10. The assembly according to any one of claims 1 through 9 wherein a cross sectional area of the second passage is greater than a cross sectional area of the first passage.

11. The assembly according to any one of claims 1 through 10 in combination with a monitoring string arranged to be received in a separate monitoring wellbore extending through the reservoir for monitoring temperature in the reservoir, the assembly further comprising a heater controller arranged to controllably vary a heating temperature of the heating fluid and a flow rate of the heating unit responsive to the temperature monitored by the temperature monitoring string

12. The assembly according to any one of claims 1 through 11 in combination with a surface monitoring system arranged to monitor temperature in proximity to a surface of the ground above the reservoir, the assembly further comprising a heater controller arranged to controllably vary a heating temperature of the heating fluid and a flow rate of the heating unit responsive to the temperature monitored by the surface monitoring system.

13. The assembly according to any one of claims 1 through 12 in combination with an injection string arranged to be received in a separate injector wellbore in communication with the reservoir, a monitoring system arranged to monitor at least one characteristic relating to production of fluid from the reservoir, and an injection controller arranged to inject a replacement fluid into the reservoir through the injection string responsive to said at least one characteristic monitored by the monitor.

14. The assembly according to any one of claims 1 through 13 further comprising spiral fins supported along an outer side of the tubing string so as to be arranged to interact with a flow of heat transfer fluid in the second passage between the tubing string and the outer casing.

15. A method of heating hydrocarbons in a subterranean reservoir using a heating wellbore extending through the reservoir, the method comprising:
providing an outer casing string lining the heating wellbore;

providing a tubing string within the outer casing string to define a first passage extending longitudinally through the tubing string and to define a second passage comprising an annulus space between the tubing string and the outer casing string; and circulating a heated heat transfer fluid through the first and second passages in a closed loop configuration.

16. The method according to Claim 15 further comprising:
providing a separate production wellbore extending through the reservoir;
providing an outer casing string lining the production wellbore;
providing a production tubing string in the production wellbore.

17. The method according to Claim 16 including:
i) prior to locating the production tubing string in the production wellbore, providing a heating tubing string within the outer casing string of the production wellbore to define a first passage extending longitudinally through the heating tubing string and to define a second passage comprising an annulus space between the heating tubing string and the outer casing string of the production wellbore;
ii) circulating a heated heat transfer fluid through the first and second passages of the production wellbore in a closed loop configuration;
iii) removing the heating tubing string from the production wellbore when a minimum threshold temperature is reached within the reservoir;
iv) opening the outer casing string of the production wellbore to communicate with the reservoir subsequent to the removal of the heating tubing string from the production wellbore; and v) inserting the production tubing string and a production pump in the outer casing string of the production wellbore.

18. The method according to any one of Claims 15 through 17 further comprising:
providing a separate injection wellbore extending into the reservoir having an outer casing string lining the injection wellbore and an injection tubing string extending through the outer casing string; and injecting fluid into the reservoir through the injecting tubing string.

19. The method according to Claim 18 including:
i) prior to locating the injection tubing string in the injection wellbore, providing a heating tubing string within the outer casing string of the injection wellbore to define a first passage extending longitudinally through the heating tubing string and to define a second passage comprising an annulus space between the heating tubing string and the outer casing string of the injection wellbore;
ii) circulating a heated heat transfer fluid through the first and second passages of the injection wellbore in a closed loop configuration;
iii) removing the heating tubing string from the injection wellbore when a minimum threshold temperature is reached within the reservoir;
iv) opening the outer casing string of the injection wellbore to communicate with the reservoir subsequent to the removal of the heating tubing string from the injection wellbore; and v) inserting the injection tubing string into the outer casing string of the injection wellbore.

20. The method according to either one of Claim 19 or 20 wherein the injection wellbore is above heating wellbore.

21. The method according to any one of Claims 15 through 17 further comprising:
providing at least one heating wellbore at each one of a plurality of different elevations in the reservoir, each heating wellbore having an outer casing string lining the heating wellbore and a heating tubing string within the outer casing string to define a first passage extending longitudinally through the tubing string and to define a second passage comprising an annulus space between the heating tubing string and the outer casing string for circulating a heated heat transfer fluid through the first and second passages in a closed loop configuration;
opening the outer casing string in said at least one heating wellbore of an uppermost one of the different elevations in the reservoir and injecting a production stimulating fluid into said at least one heating wellbore of said uppermost one of the different elevations in the reservoir when a level of hydrocarbons in the reservoir falls below said uppermost one of the different elevations.

22. The method according to any one of claims 15 through 21 including providing the tubing string in the heating wellbore with a working section extending through the reservoir and an upper section in communication between the working section and a wellhead at surface, and circulating the heated heat transfer fluid in communication with the outer casing string only along the working section of the tubing string.

23. The method according to any one of claims 15 through 22 including circulating the heated heat transfer fluid in communication with the outer casing string such that the reservoir remains isolated from a pressure of the heat transfer fluid.

24. The method according to any one of claims 15 through 23 including orienting the heating wellbore to extend generally horizontally through the reservoir above a separate production wellbore.

25. The method according to any one of claims 15 through 24 including orienting the heating wellbore to extend generally horizontally through the reservoir in proximity to a plurality of spaced apart production wellbores.

26. The method according to any one of claims 15 through 25 including controlling a rate of heat delivery to the reservoir by the heated heat transfer fluid responsive to a monitored temperature of the reservoir to maintain temperature above a minimum reservoir temperature limit.

27. The method according to Claim 26 including providing the tubing string in the heating wellbore with a working section extending through the reservoir and an upper section in communication between the working section and a wellhead at surface, and monitoring the reservoir temperature near a toe end of the working section opposite from the upper section.

28. The method according to Claim 27 including providing the tubing string in the heating wellbore with a working section extending through the reservoir and an upper section in communication between the working section and a wellhead at surface, and monitoring the reservoir temperature near a heel end of the working section in proximity to the upper section.

29. The method according to Claim 28 including providing the tubing string in the heating wellbore with a working section extending through the reservoir and an upper section in communication between the working section and a wellhead at surface, and monitoring the reservoir temperature at a plurality of longitudinally spaced positions along the working section.

30. The method according to any one of claims 15 through 29 including controlling a rate of heat delivery to the reservoir by the heated heat transfer fluid responsive to a monitored temperature in proximity to a surface of the ground above the reservoir to maintain temperature below a maximum surface temperature limit.

31. The method according to any one of claims 15 through 30 including controllably varying a rate of heat delivery to the reservoir by enabling a flow rate of the heat transfer fluid to be adjusted.

32. The method according to any one of claims 15 through 31 including heating the heat transfer fluid using a heater unit and controllably varying a rate of heat delivery to the reservoir by enabling a heating rate of the heater unit to be adjusted.

33. The method according to any one of claims 15 through 32 including using a plurality of heating wellbores extending through the reservoir of the same configuration relative to one another, and controllably varying a rate of heat delivery to the reservoir by varying a number of the heating wellbores which are active.

34. The method according to any one of claims 15 through 33 including:
monitoring a pressure of the reservoir using a separate monitoring wellbore.

35. The method according to any one of claims 15 through 34 including:
monitoring a temperature or a pressure of the reservoir using a separate monitoring wellbore; and injecting a replacement fluid into the reservoir through the monitoring wellbore to compensate for produced fluid removed from the reservoir.

36. The method according claim 35 including monitoring a pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain a constant reservoir pressure.

37. The method according either one of claims 35 or 36 including monitoring a pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain a pre-production equilibrium pressure within the reservoir.

38. The method according any one of claims 35 through 37 including monitoring a pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain pressure within the reservoir above a lower pressure limit.

39. The method according any one of claims 35 to 38 including monitoring a pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain pressure within the reservoir below an upper pressure limit.

40. A method of producing oil from a reservoir comprising:
providing at least one heating wellbore extending through the reservoir so as to be arranged to heat the reservoir;
providing at least one production wellbore extending through the reservoir so as to be arranged to remove produced fluids from the reservoir;
monitoring temperature in proximity to a surface of the ground above the reservoir;
controlling a heat rate of said at least one heating wellbore responsive to the temperature monitored in proximity to the surface so as to maintain temperature at the surface of the ground below an upper temperature limit.

41. The method according to Claim 40 including providing an array of temperature sensors at the surface of the ground and maintaining temperature below the upper temperature limit at each of the temperature sensors.

42. A method of producing oil from a reservoir comprising:
providing at least one production wellbore extending through the reservoir so as to be arranged to remove produced fluids from the reservoir;
providing at least one injection wellbore extending through the reservoir independently of said at least one production wellbore; and injecting a replacement fluid into the reservoir through said at least one injection wellbore to compensate for produced fluid removed from the reservoir.

43. The method according claim 42 including monitoring pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain a reservoir pressure within a prescribed pressure range for maintaining reservoir integrity.

44. The method according either one of claims 42 or 43 including monitoring pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain a pre-production equilibrium pressure within the reservoir.

45. The method according any one of claims 42 through 44 including monitoring pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain pressure within the reservoir above a lower pressure limit.

46. The method according any one of claims 42 through 45 including monitoring pressure within the reservoir and injecting the replacement fluid into the reservoir so as to maintain pressure within the reservoir below an upper pressure limit.

47. The method according any one of claims 42 through 46 further comprising:
monitoring a temperature of the reservoir using a separate monitoring wellbore;
providing at least one heating wellbore extending through the reservoir;
heating the reservoir using said at least one heating wellbore responsive to a temperature monitored by the monitoring wellbore; and injecting the replacement fluid into the reservoir through said monitoring wellbore.