Note: Descriptions are shown in the official language in which they were submitted.
-1- 2~81 {~8
SINGLE WELL INJECTION AND PRODUCTION SYSTEM
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BACKGROUND OF THE INVENTION
11
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.
16
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.
27
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
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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.
12
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.
07
08 SUMMARY OF THE INVENTION
09
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.
19
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
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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~
29
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
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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
34
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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
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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;
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(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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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.
16
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.
27
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
2058 1 08
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.
28
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
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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.
05
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.
27
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
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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.
18
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
2058108
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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
22
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.
31
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
20581 08
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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
16
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
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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.
07
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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