CA2058108C - Single well injection and production system - Google Patents

Abstract

A method is disclosed for fluid injection and oil production from a single wellbore which includes providing a path of communication between the injection and production zones.

Description

-1- 2~81 {~8 SINGLE WELL INJECTION AND PRODUCTION SYSTEM

BACKGROUND OF THE INVENTION

12 This invention relates generally to the production of 13 viscous hydrocarbons from subterranean hydrocarbon-14 containing formations. Deposits of highly viscous crude petroleum represent a major future resource in the United 16 States in California and Utah, where~estimated remaining in-17 place reserves of viscous or heavy oil are approximately 200 18 million barrels. Overwhelmingly, the largest deposits in 19 the world are located in Alberta Province Canada, where the in-place reserves approach 1,000 billion barrels from depths 21 Of about 2,000 feet to surface outcroppings and at 22 viscosities of up to 1 million c.p. at reservoir 23 temperature. Until recently, the only method of 24 commercially recovering such reserves was through surface mining at the outcrop locations. It has been estimated that 26 more than 90% of the total reserves are not recoverable 27 t~rough surface mining operations. Various attempts at 28 alternative, in-situ methods, have been made, all of which 29 have used a form of thermal steam injection. Most pilot projects have established some form of communication within 31 the formation between the injection well and the production 32 well. Controlled communication between the injector and 33 producer wells is critical to the overall success of the 34 recovery process because in the absence of control, injected ~ .
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01 steam will tend to override the oil-bearing formation in an 02 effort to reach the lower pressure area in the vicinity of 03 the production well. The result of steam override or 04 breakthrough in the formation is the inability to heat the 05 bulk of the oil within the formation, thereby leaving it in 06 place. Well-to-well communication has been established in 07 some instances by inducing a pancake fracture. However, 08 often problems arise from the healing of the fracture, both og from formation forces and the cooling of mobilized oil as it flows through a fracture towards the producer. At shallower 11 depths, hydraulic fracturing is not viable due to lack of 12 sufficient overburden. Even in the case where some amount 13 Of controlled communication is established, the production 14 response is often unacceptably slow.

17 u.s. Patent No. 4,037,658 to Ander~on teache~ a method of 18 assisting the recovery of viscous petroleum, such as from 19 tar sands, by utilizing a controlled flow of hot fluid in a flow path within the formation but out of direct contact 21 with the viscous petroleum; thus a solid-wall, hollow 22 tubular member in the formation is used for conducting hot 23 fluid to reduce the viscosity of the petroleum to develop a 24 potential passage in the formation outside the tubular member into which a fluid is injected to promote movement of 26 the petroleum to a production position.

28 The method and apparatus disclosed by the Anderson patent 29 and related applications is effective in establishing and maintaining communication within the producing formation, 31 and has been termed the Heated Annulus Steam Drive, or 32 "HASDrive", method. In the practice of HASDrive, a hole is 33 formed through the petroleum-containing formation and a 34 solid wall hollow tubular member is inserted into the hole , ..

-3- ~81~8 01 to provide a continuous, uninterrupted flow path through the 02 formation. A hot fluid is flowed through the interior of 03 the tubular member out of contact with the formation to heat 04 viscous petroleum in the formation outside the tubular o~ member thereby reducing the viscosity of at least a portion 06 of the petroleum adjacent the outside of the tubular member, 07 creating a potential passage for fluid flow through the 08 formation adjacent the outside of the tubular member. A
og drive fluid is then injected into the formation through the passage to promote movement of the petroleum for recovery 11 from the formation.

13 U.S. Patent No. 4,565,245 to Mims describes a well 14 completion for a generally horizontal well in a heavy oil or tar sand formation. The apparatus disclosed by Mims 16 includes a well liner, a single string of tubing, and an 17 inflatable packer which forms an impervious barrier and is 18 located in the annulus between the single string of tubing 19 and the well liner. A thermal drive fluid is injected down the annulus and into the formation near the packer.
21 Produced fluids enter the well liner behind the in~latable 22 packer and are conducted up the single string of tubing to 23 the wellhead. The method contemplated by the Mims patent 24 requires the hot stimulating fluid be flowed into the well annular zone formed between the single string of tubing and 26 the casing. However, such concentric injection of thermal 27 fluid, where the thermal fluid is steam, could ultimately be 28 unsatisfactory due to scale build up in the tubing or the 29 annulus. This scale comprises a deposition of solids such as sodium carbonate and sodium chloride, normally carried in 31 the liquid phase of the steam as dissolved solids, which are 32 deposited as a result of heat exchange between the fluid in 33 the tubing and the fluid in the annulus.

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-2058 ~ 08 01 Parallel tubing strings, as disclosed in U.S. Patent 02 No. 4,595,057 to Deming, is a configuration in which at 03 least two tubing strings are placed parallel in the well 04 bore casing. The use of parallel tubing has been found to 05 be superior in minimizing the scaling and heat loss suffered 06 by prior injection methods during thermal well operations.

10 Accordingly, the present invention involves a method of 11 achieving an improved heavy oil recovery from a heavy oil 12 containing formation by utilizing a multiple tubing string 13 completion in a single wellbore, said wellbore serving to 14 convey both injection fluids to the formation and produced fluids from the formation. The injection and production 16 would optimally occur simultaneously, in contrast to prior 17 cyclic steaming methods which alternated steam and 18 production ~rom a single wellbore.

In the present invention a single string packer is 21 positioned and set at a lower interval within a cased 22 wellbore, establishing as a production zone that portion of 23 the formation subjacent to the single string packer. A dual 24 string is then set within the wellbore at a sufficient 25 distance above the single string packer to traverse the 26 completion interval, the distance between the single string 27 and dual string packer, thereby defining a thermal zone.
28 Perforations are placed subjacent to the packers to 29 establish communication between the adjacent formation and the wellbore interior. A first tubing string is introduced 31 into the wellbore, terminating in the production zone. The 32 first tubing string is paralleled by a second tubing string, 33 both first and second tubing strings being physically 34 separated, with the second tubing string terminating -5_ ~0~81 ~

01 superior to the single string packer, lying at the base of 02 the thermal zone. A heated fluid is injected down the 03 second tubing string, heating the interior of the wellbore 04 as it travels from the terminus of the second tubing string 05 through the injection perforations subjacent to the dual 06 string packer. The heating by the injection fluid of the 07 wellbore casing in turn facilitates convection heating of 08 the formation adjacent to the wellbore, thereby creating a og thermal conduit between the injection perforations and the 10 production perforations subjacent to the single string 11 packer. As the heated fluid is injected down the second 12 tubing string, produced fluids from the formation are 13 contemporaneously directed up the first tubing string as 14 they traverse the thermal conduit to the production zone.

16 To realize the advantages of this invention, it is not 17 necessary the wellbore be substantially horizontal relative 18 to the surface, but may be at any orientation within the 19 formation. By forming a fluid barrier within the wellbore 20 between the terminus of the injection tubing string and the 21 ~enrinl~ of the production tubing ~tring; and exhau~ting the 22 injected fluid near the barrier while in~ection perforation~

23 are at a greater distance along the wellbore from the 24 barrier, a wellbore casing is effective in mobilizing the 25 heavy oil in the formation nearest the casing by convection 26 heat transfer, thereby establishing the thermal 27 communication path along the formation adjacent to 28 the wellbore~

30 The improved heavy oil production method disclosed herein is 31 thus effective in establishing communication between the 32 injection zone and production zone through the ability of 33 the wellbore casing to conduct heat from the interior of the 34 wellbore to the heavy oil in the formation near the ,.~

01 wellbore. At least a portion of the heavy oil in the 02 formation near the ~ellbore casing would be heated, its 03 viscosity lowered and thus have a greater tendency to flow.
04 Tlle single well method ~nd apparatus of the present 05 invention in opeLatiOn, therefore, accomplishes the 06 substantial purpose o an injection well, a production well, 07 and a means of establishing communication therebetween.
08 A heavy oil reservoir may therefore be more effectively og produced by employing the method and apparatus of the present invention in a plurality of wells, each wellbore 11 having therein a means for continuous thermal drive fluid 12 injection simultaneous with continuous produced fluid 13 production and multiple tubing strinys. As a result of 14 ut:ilizing the method of the present invention a shorter induction period is achieved, usually a few days versus 16 upward of the several weeks or more required in developing 17 communication between a separate injection and production 18 well. Additionally, the distance between the injection g point of injected fluid into the hydrocarbon-containing formation and the production point of produced fluids is 21 distinctly de~ined in the present method, whereas the 22 spacing between a separate injection and production well is 23 less certain. Through the distinct feature of the wellbore 24 casing conducting heat into at least a portion of the oil in 25 the formation outside of the casing, there is less pressure 26 and temperature drop between injection and production 27 intervals; therefore production to the surface of produced 28 fluids, which retain more formation energy, is more likely 29 accompliqhed with the pre~ent invention over prevLou~ ~eparate well technology. Additionally, in producing fluid~

31 to the surface of the formation, the production tubing 32 temperature loss is significantly reduced through its 33 location within the wellbore casing along with the injection ,.~

tubing string; therefore, bitumen and heavy oil in the produced fluids are less likely to hpcom~ immobile and inhibit flow to the surface.

S Other aspects of this invention are as follows:

A method for producing viscous hydrocarbons from a subterranean formation, comprising the steps of:
(a) drilling and casing a wellbore which transverses the formation;
(b) perforating both an upper and a lower portion of said casing to establish communication between the wellbore and the formation adjacent to said perforations, said upper perforations constituting injection perforations, said lower perforations constituting production perforations;
(c) setting a first packer at a point above said upper perforations and a second packer at a point above said lower perforations to establish a thermal zone between said first and second packer and a production zone below said second packer;
(d) introducing a first tubing string into the wellbore and terminating said first tubing string at the production zone;
(e) introducing a second tubing string into the wellbore, said second tubing paralleling the first tubing string and terminating in a lower interval of the thermal zone;
(f) injecting a drive fluid into the second tubing string, said drive fluid exiting said second string and entering the thermal zone to transfer heat to said formation adjacent to said thermal zone establishing a thermal communication path within said formation, said drive fluid exiting the injection perforations to further heat the formation, making more mobile at least a portion of ~, ~

- 7a -the viscous hydrocarbons located within the formation between the terminus of said second string and said injection perforations;
(g) simultaneously flowing a produced fluid from the production zone through the first tubing string while injecting said drive fluid into said second tubing string, said produced fluid comprising a mobilized portion of said viscous hydrocarbons.

The method of recovering viscous hydrocarbons in a subterranean formation from a single wellbore, comprising the steps of:
(a) providing a cased wellbore penetrating the formation;
(b) selecting a first zone of operation within the wellbore;
(c) perforating the wellbore casing establishing injection perforations at an upper location and production perforations at a lower location, said upper and lower locations further defining respectively an injection zone and a production zone within said zone of operation;
(d) setting a single string packer at a point just above the production perforations;
(e) setting a dual string packer at a point just above the injection perforations, said dual string packer and said single string packer cooperating to define the area therebetween as an upper and a lower boundary of the zone of operation;
(f) introducing both a steam tubing string and a production tubing string into the wellbore, said steam tubing string having its terminus at a lower most portion of the zone of operation, said production string having its terminus in the production zone below said single string packer;

~ - 7b - 2058 1 08 (g) flowing steam form the terminus of said steam tubing along the interior of the wellbore casing to the injection perforations, said flowing steam conducting heat through the casing to the adjacent formation and establishing a thermal communication path before exiting through said injection perforations into said formation;
(h) flowing produced fluids from the formation into the production tubing simultaneous with said flowing steam to said formation; and (i) selecting a second zone of operation within the wellbore and repeating steps c through h, said second zone being defined by relocating said single and dual string packers within the wellbore, said first and second zones of operation thereby defining a hydrocarbon bearing region within the subterranean formation.

The present invention, in practice along with conventional equipment of the type well known to persons experienced in heavy oil production, and the generation of thermal fluids for injection and treatment of the resulting produced fluids, presents along with the present invention, a comprehensive system for recovery of highly viscous crude oil.

DESCRIPTION OF THE DRAWINGS

FIG. 1 is an elevation view in cross section of the single well injector and producer contemplated.

FIG. 2 is an elevation view in cross section of the single well injection and production system in the initiation configuration, whereby fluid is injected through multiple tubing strings.

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- 7c 20581 08 FIG. 3 is an elevation view in cross section of the single well injection and production system in the normal operational mode.

FIG. 4 is an elevation view in cross section of the single well injection and production system with control means during normal operation.

~ESCRIPTION OF THE PREFERRED EMBODIMENTS

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01 In the exemplary apparatus for practicing the present 02 invention, as depicted by Figure 1, a subterranean earth 03 formation 10 i~ p~netrated by a welLbore having a casing 12.
04 Injection perforations 70 and production perforations 22 oS provide fluid communication from the wellbore interior to 06 the earth formation 10. A dual string packer 26 and a U7 single string packer 28 are placed above the injection 08 perforations 20 and production perforations 22 respectively.
og The distance traversed by the wellbore between single string packer 28 and dual string packer 26 establishes a thermal 11 operation zone; while the area subjacent to single string 12 packer 28 constitutes a production zone. This distance is 13 dictated by the size of the completion interval, which must 14 be of sufficient size to avoid excessive pressure drop between the formation and the wellbore.

17 A first tubing string 30 and a second tubing string 32 are 18 placed within the wellbore casiny 12, both tubing strings 19 extending through dual string packer 26, with second tubing string 32 terminating at a depth shallower in the wellbore 21 than single string packer 28. An annular-like injection 22 fluid flow path 36 is created by the space bounded by the 23 dual string packer 26, single string packer 28, and the 24 interior of wellbore casing 12. First tubing string 30 further extends through single string packer 28, terminating 26 at a depth below said packer.

28 In one embodiment of the present invention, second tubing 29 string 32 is supplied with pressured injection fluid from an injection fluid supply source (not shown). Injection fluid 31 flows down second tubing string 32, exhausting from the 32 terminus of the tubing string into the annular-like 33 injection fluid flow path 36. Continual supply of high 34 pressure injection fluid to the second tubing string 32 01 forces the injection fluid upward in the annular flow path 02 36, toward the relatively lower pressure earth formation 10, 03 through injection perforations 20. ~hile any standard 04 industry injection Eluid, such as hot water, may be used, in 05 the preferred embodiment of the present invention the 06 injection fluid is steam. When steam flows up the annular 07 flow path 36 bounded by casing 12, thermal energy is 08 conducted through the wellbore casing 12, and heating at og least a portion of the earth formation 10 near the wellbore.

11 Hydrocarbon containing fluid located within the earth 12 formation 10 near the wellbore casing, having now an 13 elevated temperature and thus a lower viscosity over that 14 naturally occurring in situ, will tend to flow along the heated flow path exterior of the casing 12. This heated 16 flow path acts as a thermal conduit formed near the wellbore 17 casing 12 by heat conducted from steam flow in the 18 annular-like ~low path 36 on the interior of the casing 12, 19 toward the relatively lower pressure region near production perforations 22. rn operation of the preferred embodiment, 21 produced fluids comprising hydrocarbons and water including 22 condensed steam enters from the earth formation 10 through 23 production perforations 22 to the interior of the wellbore 24 casing 12 below single string packer 28. Produced fluids are continuously flowed into first tubing string 30 and up 26 the tubing string to surface facilities (not shown) for 27 separation and further processing.

29 In an alternative embodiment of the present invention, as depicted in FIG. 2, a means of achieving the advantageous 31 result of quickly developing communication between the 32 portion of the formation receiving injection fluid and that 33 portion from which hydrocarbons are directed into the first 34 tubing string 30, is to flow hot injection fluid into both ~ 2~10$

01 first tubing strin~ 30 and second tubing string 32, thereby 02 pressurin~ the inje~tiOn ~luid into the formation through 03 both inj~ction and p~o~u~Lon perforations 20 and 22 04 respectively.

06 Referring to FIG. 2, tn a pte~erred method o establishing 07 this rapid communication between the portion of the 08 subterranean earth formation subjected to injection fluid, og and the lower portion from which fluids will be produced, steam from an injection fluid supply source (not shown) is 11 flowed from the surface down both the first tubing string 30 12 and the second tubing string 32. Injection fluid in the 13 second tubing string 32 flows from the terminus of second 14 tubing string 32 along the annular-like flow path 36, exhausting from the wellbore into the hydrocarbon-bearing 16 formation through injection perforations 20. For at least a 17 portion of the time during which injection fluid is flowed 18 into ~irst tubing string 30, in jection fluid is also flowed 19 into second tubing string 3~ from a surface injection fluid supply source (not shown). During this time, injection 21 fluid in the first tubing string 30 is exhausted at the 22 tubing tail and enters the hydrocarbon-bearing formation 23 through casing perforations 22. Steam injection is 24 continued down both tubing strings until injection rates drop below the values reyuired to overcome heat loss in the 26 surface lines and wellbore.

28 Referring now to FIG. 3, when sufficient injection fluid has 29 entered the hydrocarbon-bearing formation to overcome said heat losses and reduce the viscosity of at least a portion 31 of the reservoir fluid sought to be produced, and sufficient 32 energy exists in the formation, the first tubing string 30 33 is disconnected from the injection fluid supply source (not 34 shown), and fluid communication is established between the - 1 1 - 2 ~

01 first tubing string 30 and production facilities (not 02 shown). 3ue to a decreased pressure now existing in the 03 first tubing strinq 30 relative to the pressure within the 04 hydrocarbon-containing formation 10, formation 1uid will 05 tend to flow along the established thermal conduit from the 06 hydrocarbon-containinq formation 10 toward the terminus of 07 first tubing string 30 through production perforations 22.
08 It is preferred to minimize the duration of time between og cessation of injection fluid flow through first tubing string 30 and the flowing of formation fluids in a reverse 11 direction through first tubing string 30, in order to 12 minimize the loss of thermal energy and thus minimize the 13 flowing viscosity of the fluids produced from 14 hydrocarbon-containing formation 10. This time interval is determined by monitoring the production rate values for any 16 decrease, thereby signaling a lack of sufficient 17 Communication.

19 Referring now to FIG. 4, to avoid the entry of uncondensed steam into the gravel pack or wire mesh sand screen area 21 located exterior of the wellbore near production 22 perforations 22, a level of formation fluid interface 40, at 23 a sufficient distance in the hydrocarbon-bearing formation 24 above production perforations 22, is created and maintained.
The level of interface 40 above production perforations 22 26 is directly proportional to the difference in pressure 27 between the injection fluid in second tubing string 32 and 28 pressure at the bottom hole fluid inlet to first tubing 29 string 30. It is therefore possible to sense the pressure existing in first tubing string 30, compare it to the 31 injection fluid pressure existing in second tubing string 32 32, or any point along the injection fluid flow path as 33 defined by the injection fluid supply source and the 34 terminus of the second tubing string 32, and determine the Ol level of the Eormation Eluid interface 40 above production 32 perorations 22 based ~n t~ fcrence therebetween. In 03 one embodiment, bo~t~ hole ~e~ss~r~ ~n the first tubing 04 string 30 is se~4d u~ilizin~ a w~ known "bubble-tube" or a~ "capillary tube" device. ~his ~api~l~ry tUb~ comprises a 06 length of small ~ia~eteT ~etallic tublng 42 which is 07 extended from the surface to the downhole environment. The 08 pressure existing at ~he downhole terminus of the small og diameter metallic tubing ~4 is transmitted via a gas, typically an inert gas such as nitrogen, to instrumentation ll 46 placed at the surface. Based upon the indicated 12 pressure, an estimate of the height of fluid level interface 13 40 above the terminus ~4 is used to control the degree of 14 fluid restriction applied to the produced fluid stream in first tubing string ,0 through incorporation of a surface 16 control valve ~8. Thus, the liquid level interface 40 is 17 proportional to the differ~nce in pressure (~Pl) between 18 steam Injection ~ressure (~IP), and sottomhole Pressure 19 (BHP), and is represented by the equation:

21 ~Pl = BHP-SIP

23 By the method of the present invention, fluid interface is 24 maintained at sufEicient level above production perforations 22 to form a liquid seal at the fluid entrance to the 26 wellbore, thereby avoiding the contact of uncondensed 27 injection fluid with the gravel pack, wire mesh sand screen 28 or other well completion device which may be subject to 29 damage from contact with hot or high velocity injection flUid.

32 In still a further embodiment of the present invention, 33 wherein production from diatomites can be achieved, the 34 quick establishment of a thermal communication path, as -13~

01 previously described, is initiated hy injecting the 02 injection fluid, preferably steam, ahove fracture pressure.
03 In the preferred (-~mbodiment, th~ fractures from the 04 production zone to th~ injection ~one connect together 05 to make one continuous fracture system. The initial 06 injection of steam, or other drive fluid, above fracture 07 pressures forces the fractures open to facilitate imbition 08 and gravity drainage to the production zone. After og injection down the first tubing string 30 has terminated, 10 and production of fluids through production perforations 22 11 and into first tubing string 30 has been initiated, the 12 continuous injection of fluids through second tubing 13 string 32 at above fracture pressure prevents partial 14 healing of the fractures as is common in cyclic steaming L5 Operation 17 For each of the embodiments herein described, in order to 18 increase the portion of the subterranean formations from 19 which viscous hydrocarbons are produced, it may be 20 advantageous to relocate the upper dual-string packer such 21 that the distance between the packers in the wellbore is 22 increased. In this manner, steam or other drive fluid flows 23 from the interior of the wellbore through newly created 24 perforations, above previously the sole injection 25 perforations 20. As before, the passage of the steam or 26 other hot drive fluid from the terminus of the second tubing 27 string through the annular-like flow path to the injection 28 perforations conducts heat through the casing wall to heat 29 and thus make more mobile at least a portion of the viscous 30 hydrocarbons in the formation near the wellbore. Further, 31 it may be advantageous, particularly in very thick 32 hydrocarbon containing formations, to relocate both the 33 injection and production perforations, in order to recover 34 increasing amounts of hydrocarbons from the formation. By .

~ 2~8108 01 relocating the single string pac~er lower in the wellbore, 02 superior to the ne~ p~Q~Ilction perforatians, and relocating 03 the dual-strinq packer ~o a point superior to either the 04 previous product;~n per~o~ations, or, alternately new ~5 injection perforations, the location of a new zone of 06 operation is accomplished.

08 Due to continuous injection fluid entering the formation og from the wellbore in the zone of operation, an elevated pressure is maintained within the formation over that 11 pressure naturally occurring, and above that existing in the 12 production zone portion of the wellbore apparatus below the 13 lower or single-string packer. Further, due to increased 14 mobility and lowered viscosity of the viscous hydrocarbons in the formation it will be possible, at least in shallower 16 wells, (less that ~000 ft.), to flow produced fluids from 17 the production z.one to the surface for ultimate recovery by 18 maintaining a bottom hole pressure in the production zone 19 which is sufficient to accomplish the flow of produced fluid without the aid of a pump. sack-pressure is maintained, 21 thereby maintaining a liquid level in the formation in the 22 production zone by regulating the flow of produced fluids 23 within the first tubing string. In one embodiment, produced 24 fluid flow is regulated based upon the temperature of the produced fluid sensed at or near the wellhead. A valve or 26 other flow regulator device is adjusted to maintain a 27 predetermined "set-point" temperature in the produced 28 fluids. ~ the temperature is less than the predetermined 29 set-point, the valve or other regulator means is manipulated to adjust flow. In some cases, significant heat transfer 31 between the first and the second tubing strings in the 32 wellbore may occur. The direction or valve operation and 33 degree of flow regulation necessary to achieve a 34 predetermined set-point temperature often varies from well ~ - 15 - 2058108 to well, and thus the above described flow control scheme would be determined on an individual well-to-well basis. In order to min;m; ze the effect of heat transfer between the separate strings of tubing in the wellbore, in the practice of the present invention it is desirable to provide a thermally insulated section of tubing between the upper and lower packers where heat transfer potential is more prevalent. However, in one preferred embodiment of the present invention, steam is exhausted from the tail of the second tubing string and travels in the annular-like section in direct contact with the first tubing string, thereby heating the lower temperature fluids produced therein to enhance recovering of said fluids to the surface.

Although the present invention has been described with preferred embodiments, it is to be understood that modifications and variations may be resorted to without departing from the spirit and scope of the present invention, as those skilled in the art will readily understand. Such modifications and variations are considered to be within the purview and scope of the appended claims.

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Claims (11)

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

(a) drilling and casing a wellbore which traverses the formation;

(b) perforating both an upper and a lower portion of said casing to establish communication between the wellbore and the formation adjacent to said perforations, said upper perforations constituting injection perforations, said lower perforations constituting production perforations;

(c) setting a first packer at a point above said upper perforations and a second packer at a point above said lower perforations to establish a thermal zone between said first and second packer and a production zone below said second packer;

(d) introducing a first tubing string into the wellbore and terminating said first tubing string at the production zone;

(e) introducing a second tubing string into the wellbore, said second tubing paralleling the first tubing string and terminating in a lower interval of the thermal zone;

(f) injecting a drive fluid into the second tubing string, said drive fluid exiting said second string and entering the thermal zone to transfer heat to said formation adjacent to said thermal zone establishing a thermal communication path within said formation, said drive fluid exiting the injection perforations to further heat the formation, making more mobile at least a portion of the viscous hydrocarbons located within the formation between the terminus of said second string and said injection perforations;

(g) simultaneously flowing a produced fluid from the production zone through the first tubing string while injecting said drive fluid into said second tubing string, said produced fluid comprising a mobilized portion of said viscous hydrocarbons.

2. The method according to Claim 1 wherein the second tubing string is terminated at a lower most portion of the thermal zone maximizing the physical distance between an exhaust port at the terminus of said second string and said injection perforations.

3. The method according to Claim 1 wherein the drive fluid is steam.

4. The method according to Claim 1 wherein the drive fluid is hot water.

5. The method according to Claim 2 wherein the flow of produced fluids from the production zone requires no artificial lift means, said flow accomplished by a sufficient bottomhole pressure to force said fluids up said wellbore to the surface.

6. The method according to Claim 1 further comprising the step of insulating the second tubing string between said first and second packer to packer to minimize heat transfer between fluid in said first tubing string and fluid in the second tubing string.

7. The method according to Claim 1 further comprising the step of quickly developing said thermal communication path and initiating fracturing of the adjacent formation by initially injecting said drive fluid down both the first and second tubing strings at above fracture pressure to heat and establish a continuous fracture system in both the thermal zone and the production zone, said flow within the first tubing string reversed after sufficient heating and fracturing of the formation to produce fluids from the formation while said second string prevents healing of the fracture system by continuing injection of said drive fluid at above fracture pressure.

8. The method of recovering viscous hydrocarbons in a subterranean formation from a single wellbore, comprising the steps of:
(a) providing a cased wellbore penetrating the formation;
(b) selecting a first zone of operation within the wellbore;
(c) perforating the wellbore casing establishing injection perforations at an upper location and production perforations at a lower location, said upper and lower locations further defining respectively an injection zone and a production zone within said zone of operation;
(d) setting a single string packer at a point just above the production perforations;
(e) setting a dual string packer at a point just above the injection perforations, said dual string packer and said single string packer cooperating to define the area therebetween as an upper and a lower boundary of the zone of operation;
(f) introducing both a steam tubing string and a production tubing string into the wellbore, said steam tubing string having its terminus at a lower most portion of the zone of operation, said production string having its terminus in the production zone below said single string packer;
(g) flowing steam form the terminus of said steam tubing along the interior of the wellbore casing to the injection perforations, said flowing steam conducting heat through the casing to the adjacent formation and establishing a thermal communication path before exiting through said injection perforations into said formation;
(h) flowing produced fluids from the formation into the production tubing simultaneous with said flowing steam to said formation; and (i) selecting a second zone of operation within the wellbore and repeating steps c through h, said second zone being defined by relocating said single and dual string packers within the wellbore, said first and second zones of operation thereby defining a hydrocarbon bearing region within the subterranean formation.

9. The method according to Claim 8 wherein the physical distance between an exhaust port at the terminus of the steam tubing string and the injection perforations is maximized.

10. The method according to Claim 9 wherein the flow of produced fluids from the production zone requires no artificial lift means, said flow accomplished by a sufficient bottomhole pressure to force said fluids up the wellbore to the surface.

11. The method according to Claim 8 further comprising the step of quickly developing the thermal communication path and initiating fracturing of the adjacent formation by initially injecting said steam down both the steam tubing string and production tubing string at above fracture pressure to heat and establish a continuous fracture system in both the thermal zone and the production zone, said steam flow within the production tubing string halted after sufficient heating and fracturing of the formation and said production tubing converted to produce fluids from the formation while said steam tubing prevents healing of the fracture system by continuing injection of said steam at above fracture pressure.