Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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HYDROC~RON REC~KY ~ THOD
U8ING ~ NV~ ~V PRODUCTION WELL8
The present invention relates to a method for
recovering hydrocarbons from a subterranean reservoir
through an inverted production well and in one of its
aspects relates to a method for recovering hydrocarbons
using an inverted production well(s) which has a non-
inverted (e.g. vertical with angle building to near 90~)
portion, a substantially horizontal portion wellbore which
extends into the reservoir, and a tail portion which curves
upwardly towards the surface to terminate at or near the
top of the reservoir.
As is well known, thermal secondary recovery
operations are routinely employed to recover heavy
hydrocarbons, e.g. heavy oil, from subterranean reservoirs
(e.g. oil sands). Due to its high viscosity, the heavy oil
must be heated in place to reduce its viscosity so it will
flow from the reservoir. Probably the most common of such
thermal recovery operations involves "steam stimulation"
wherein the heavy oil is heated in place by steam which is
injected into the reservoir. A steam stimulation or
steamflood process can be carried out by either (a)
injecting the steam into an injection well and then
producing the hydrocarbons from a separate well or (b)
injecting the steam and then producing the fluids through
the same well.
In a typical, conventional gravity-dominated
steamflood recovery operation, steam is injected into one
well while formation fluids (e.g. oil) are produced through
spaced production wells. These production wells normally
have substantially vertical wellbores which are cased to at
least a depth which lies adjacent the top of the oil sand.
The lower end of the wellbore is then completed with a
gravel pack or the like through the production interval.
Steam is injected through the injector well for an
initial period (e.g. 3 to 24 months) in order to establish
thermal communication between the injector well and the
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production wells. During this initial injection period,
each production well may either produce cold oil at a low
flow rate or be stimulated by cyclically injecting steam
into the producing well, itself. Higher production flow
rates normally occur only after thermal communication
between wells has been established.
In a steam stimulation operation such as described
above, steam is injected down the injection well and out
into the formation. Due to its relative density, the steam
tends to rise towards the top of the formation during
injection. This natural gravity segregation results in the
creation of a "steam chest" across the top of the
production formation which, in turn, results in early steam
breakthrough and less than 100% vertical sweep of steam
through the formation.
This is especially true where a production well is
completed at the top of an oil sand where steam, upon
breakthrough, will be produced into the wellbore and up
through the annulus of the producing well. This results in
a substantial loss of valuable steam and at the same time,
may create severe back pressure and pump problems which
seriously inhibit the production of oil from the reservoir.
In steamfloods of this type, it has been observed that
high oil production rates usually occur within a 1 to 3
month period just prior to steam breakthrough at a
production well. In an effort to delay steam breakthrough
and thereby contain the steam within the reservoir for a
longer period, the production wells are often cased to an
extended depth lying well within the reservoir thereby
isolating the upper portion of the reservoir behind the
casing. While delaying steam breakthrough, unfortunately,
the extended casing may also delay the production of hot
oil since the steam chest will now be located a significant
vertical distance above any openings in the casing and/or
liner thereby allowing only cold oil to enter the well.
Other techniques have been proposed for improving the
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production of heavy oil from a reservoir by improving the
sweep efficiency of the injected steam through the
reservoir. One such technique involves the injection of a
foam or other flow-blocking material into a formation to
fill previous swept and/or more permeable zones of the
reservoir before injecting the steam. Another technique
involves the drilling of horizontal wells into the
reservoir to intersect natural fracture systems of the
reservoir and to provide a long completion interval within
the reservoir. The present invention provides still
another method for producing heavy hydrocarbons from a
reservoir which use "inverted" production wells which, in
turn, provide several apparent advantages over either
vertical or horizontal production wells.
The present invention provides a method using an
"inverted" production well for recovering hydrocarbons from
a subterranean reservoir. The production well of the
present invention is "inverted" in that at least the
terminal portion thereof is inverted, i.e. the terminal end
curves upward towards the surface. More specifically, the
inverted wellbore of the present invention has a
substantially vertical (with angle building to near 90~~,
non-inverted portion which extends from the surface to a
depth substantially adjacent the top of said reservoir; an
integral, substantially horizontal portion which extends
into said reservoir; and an integral, upwardly curving tail
portion which terminates near the top of the reservoir.
Typically, the production well is cased approximately
throughout the substantially vertical, non-inverted portion
of the wellbore with the remaining wellbore being completed
in accordance with known completion procedures (e.g. cased
and perforated, open-hole completions, gravel-packed,
etc.). A string of production tubing which may include a
downhole pump (not shown) on the lower end thereof is
positioned in the wellbore and preferably terminates within
the non-inverted portion of wellbore. However, as should
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be recognized, the tubing/pump inlet can be repositioned
within the wellbore during the life of the production well
in response to the actual production of the well.
The inverted production well of the present invention
can be used in different types of steamflood recovery
operations. For example, a plurality of inverted
production wells may be spaced from a central steam
injector well in conventional steamflood patterns, e.g.
five-spot, nine-spot, in-line, etc.. Steam, when injected
lo through the injector well, will migrate upward to form a
"steam chest" across the reservoir. Preferably, in such
patterns, the tail portion of each inverted wellbore is
deviated towards the injector well and each terminates at
or near the top of the reservoir so it will lie in or near
the steam chest as it is formed.
The high-angle horizontal nature of the inverted
wellbore of the present invention greatly enhances the
length of the completed production interval within the
reservoir and can substantially reduce the bottom-water
coning within the formation. Further, since the tail or
terminus of the wellbore is located near the top of the
reservoir (i.e. in or near the steam chest) and since the
intake of the production tubing and pump (if used) is
located in the non-inverted portion of the well, hot oil
and water from the formation are forced to flow from the
tail of the wellbore downward through the entire completed
length of the wellbore before the heated fluids reach the
tubing/pump inlet. These hot fluids provide good
conductive heating along this interval thereby enhancing
oil production in what would otherwise be a cold interval.
Further, because the steam is entering at the tail of
the wellbore and condensing, it will be produced as hot
water through the tubing/pump inlet instead of being
produced through the well annulus as would be the case in
prior art systems thereby substantially eliminating any
significant back pressure against the reservoir which, in
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turn, would inhibit oil production. Further, the
production of steam through the tail portion can be
reduced, if necessary, by setting a bridge plug or the like
within the tail portion of the wellbore to block the
downward flow of steam through the tail portion. This plug
or additional plugs can be repositioned during the life of
the production well to compensate for increasing production
of steam into the tail portion of the wellbore.
In another embodiment of the present invention, a
single inverted well may be used both as the steam injector
well and the production well of a steamflood by positioning
a string of injection tubing within the wellbore and
extending the injection tubing into the tail portion of the
wellbore. The injection tubing can be run through the
production tubing or it can be run along side the
production tubing. Steam is injected through the injection
tubing into the tail portion of the wellbore to heat the
oil in the top of the reservoir so that it may flow into
the lower wellbore to then be produced through the
production tubing.
The actual operation and apparent advantages of the
present invention will be better understood by referring to
the drawings in which like numerals identify like parts and
in which:
FIG. 1 is an elevational, sectional view of the lower
end of a production well of a steamflood recovery operation
which has been completed in accordance with known, prior
art techniques;
FIG. 2 is an elevational, sectional view of the lower
end of an inverted production well which has been completed
in accordance with the present invention;
FIG. 3 is an elevational, sectional view of the lower
end of an inverted production well which has been completed
in accordance with the present invention and the lower end
of an associated, spaced steam injection well; and
FIG. 4 is a plan view of a typical steamflood pattern
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in which the present invention can be used.
There are substantial reservoirs of heavy hydrocarbons
(hereinafter collectively called "heavy oil") throughout
the world which have such a high viscosity that they can
not be economically produced by primary recovery
techniques. To produce these reservoirs, it is common to
use thermal techniques which heat the heavy oil in place to
reduce its viscosity to a level sufficient to allow it to
flow from the reservoir into a production well. One of
the best known and most commonly used of such thermal
processes is commonly referred to as "steam stimulation"
and one which involves injecting steam down the well and
into the reservoir to heat the heavy oil.
In typical, prior art steam stimulation processes
(FIG. 1), steam 12 is injected down an injection well (not
shown) and out into the production formation or reservoir
(i.e. oil sand 11) towards a production well 10 (FIG. 1).
As illustrated, well 10a has a substantially ve~tical
wellbore which has been cased (casing 13) and cemented (not
shown) to a depth approximately adjacent the top 14 of the
oil sand. The lower portion of wellbore 10a is "gravel-
packed" adjacent the production interval of oil sand 11
(i.e. completed with a slotted liner 15 which, in turn, is
surrounded by a pack of gravel 16). A production tubing 18
which may have a downhole pump (not shown) on its lower end
extends into the wellbore through which the formation
fluids are produced to the surface.
Since steam 12 is substantially in the vapor phase,
its density is substantially less than that of either the
heavy oil or the formation water which causes the steam to
rise towards the top of the reservoir as it radiates
outward from the well. This natural gravity segregation of
steam in a typical heavy oil reservoir routinely results
the establishment of a "steam chest" 17 which blankets the
top of oil sand 11. This, in turn, almost always results
in an early steam breakthrough at wellbore 10 with a less
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than 100% vertical sweep of steam through the formation.
Once breakthrough occurs, steam is produced up well
annulus 19 resulting in a substantial loss of heat input to
the reservoir. Also, this early breakthrough normally
creates a back pressure against the reservoir which may
retard oil production and can lead to severe downhole pump
problems.
In an attempt to counteract early steam breakthrough
in the prior art production wells such as vertical wellbore
10, the wellbore is sometimes cased to a lower depth (i.e.
some distance into oil sand 11). As illustrated in FIG. 1,
the top of oil sand 11 would now lie at 14a. This isolates
the upper portion of the oil sand lying behind the
additional casing from the wellbore. While this
configuration will normally delay steam breakthrough, it is
also likely to delay hot oil production since the
horizontal steam interface (dotted line 17a) will now lie a
significant vertical distance above any perforations in
casing 13 and/or the openings in liner 15 thereby allowing
only cold oil to be produced from the oil sand.
Referring now to FIGS. 2-4, the present invention will
now be fully described. In accordance with the present
invention, the production well 20 is an "inverted" well in
that at least the terminal or tail end of the wellbore is
inverted. As used throughout the present specification and
claims, "inverted well" or "inverted wellbore" is meant to
refer to and describe a wellbore which curves or deviates
from the vertical towards a horizontal direction and then
curves upwardly towards the surface (i.e. "inverted") as
the wellbore is being drilled into said reservoir.
As best seen form in FIG. 2 (not to scale), inverted
wellbore 20 curves outward from the substantially vertical,
non-inverted portion 20a towards the horizontal (e.g. 20b)
as it passes into reservoir 11 and preferably continues
through a horizontal portion 20b (length of portion 20b
depending on a particular reservoir) near the bottom of
-
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reservoir 11 before the wellbore begins to curve upward
towards the surface. The wellbore continues upward to form
a tail portion 20c which terminates near the top 14 of
reservoir or oil sand 11. As will be understood by those
skilled in the art, the drilling of such wells are well
within the present state-of -the-art and can be drilled
with presently commercially-available equipment (e.g.
whipstocks, downhole motors, bent subs, etc.).
Typically, production well 20 is cased (i.e. casing
22) and cemented (not shown) substantially through the non-
inverted portion 20a of the wellbore. The remaining
wellbore (i.e. 20b, 20c) which will form the production
interval of the well is then completed in accordance with
an appropriate, known completion technique (e.g. cased and
perforated, open-hole completions, gravel-packed, etc.). A
string of production tubing 23 which may carry a downhole
pump (not shown) on its lower end is lowered into the
wellbore with its inlet (i.e. lower end) being positioned
at or near the lower end of the non-inverted portion of
wellbore 20 (i.e. within the substantially vertical or
horizontal portion of the well).
The present inverted production well can be used in a
variety of different types of steamflood recovery
operations. One such operation is shown in FIG. 3 (not to
scale) wherein inverted production well 20 is one of a
plurality of production wells which are spaced from a steam
injector well 21. The production wells 20 may be
positioned around a central injection well 21 in a typical
5-spot pattern (FIG. 4) or they may be arranged in other
well known steamflood patterns (e.g. nine-spot, in-line,
etc.) with similar success.
As illustrated, inverted wellbore 20 is preferably
deviated inwardly towards injector well 21 with tail
portion 20c terminating at or near the top 14 of reservoir
11. Steam 12 is injected through perforations 21a in well
21 and will migrate upward to form steam chest 17 across
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the top of the formation in the same manner as in prior
steamfloods. As will be fully discussed below, the
inversion of wellbore 20 so that it terminates near the top
of the reservoir (i.e. in contact with steam chest 17)
provides several advantages over production wells
previously used in steam floods.
For example, the high-angle horizontal nature of the
inverted wellbore greatly enhances the length of the
completed production interval within the reservoir and can
substantially reduce bottom-water coning within the
formation. Further, since the tail or terminus of the
wellbore is located near the top of the oil sand and in
contact with steam chest 17 and since the intake of the
production tubing 23 and pump (if used) is located in the
non-inverted portion of the well, hot oil and water from
the formation is forced to flow downward from the tail
portion 20c of the wellbore and along the remaining
completed interval of the wellbore before they reach the
tubing/pump intake. These hot fluids provide conductive
heating along this entire interval thereby enhancing oil
production from what would otherwise be a cold interval of
reservoir.
Another advantage arising from the present inverted
well results from the fact that gravity will tend to keep
the steam at the top of the reservoir (i.e. within steam
chest 17) where the reservoir pressure is at its lowest.
This will cause the higher-pressure reservoir fluids below
the steam chest to be produced into the wellbore. Further,
where gravity and pressure differences are not enough to
keep steam from entering the wellbore, the steam will
condense into a liquid as it mixes with the higher-pressure
production fluids and will travel therewith towards the
tubing and/or pump inlet in the non-inverted portion 20a of
the wellbore.
Because the steam is entering at the tail 20c of the
wellbore and condensing, the normal steam breakthrough
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phenomenon at a production well is changed. Steam is no
longer creating back pressure against the reservoir which
can seriously inhibit the production of oil therefrom. The
condensed steam is produced as hot water through the
tubing/pump inlet instead of being produced through the
well annulus and an associated casing vapor recovery system
(CVRS) which is commonly present on most prior art
production wells which are used in typical steam floods.
Further, the higher temperature of the produced fluids
will reduce oil-treating costs at the surface by requiring
(1) less fuel for heater-treaters and/or (2) less
chemicals. The costs of processing the hot fluids through
the flowline are much lower than processing steam vapors
through a typical CVRS. Another disadvantage of producing
steam through a conventional CVRS is that when steam
breakthrough occurs at one production well, the overall
CVRS pressure for all wells can increase thereby creating a
back pressure (hence inhibit oil production) from all of
the other production wells connected to the CVRS.
Referring again to FIG. 2, production of steam from
steam chest 17 through tail portion 20c can be reduced, if
necessary, by setting a bridge plug 25 or the like (FIG. 2)
within the tail portion 20c at a point downstream of the
steam chest 17 to block downward flow of steam from the
tail portion 20c into the adjacent portions of the
wellbore. In a conventional vertical well or a true
horizontal well where the wellbore terminates at the bottom
of the reservoir and the steam chest exists at the top, a
bridge plug or the like can not be used without sealing off
both the oil zone and the steam chest which is
unacceptable.
Another advantage of using an inverted production well
is that the entire completion interval within the wellbore
is in contact with hot fluids substantially from the
beginning of the steam injection. The hot fluids produced
from the steam chest region of the wellbore allows heat to
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be transferred to the otherwise cold, near-wellbore lower
reservoir region. The heat transfer from the hot produced
fluid enhances oil production in what would otherwise be a
cold lower wellbore interval.
Further, an inverted production wellbore allows the
inlet of the production tubing/pump to be placed at
different points in the wellbore during the production life
of the well. For example, the inlet may be placed closer
to steam chest region 17 if a large volume of oil is being
produced exclusively from that zone. Likewise, the inlet
may be placed higher up in the non-inverted portion of the
wellbore to establish a fluid level in the wellbore which
will inhibit excessive steam production from the steam
chest 17. The actual position of the inlet of the
tubing/pump will be dictated by the changing steam flood
dynamics of the well, e.g. steam chest growth, water
production, etc
In another embodiment of the present invention, a
single inverted well 20 may be used both as the steam
injector well and the production well. As illustrated in
FIG. 2, a string of injection tubing (shown in dotted lines
30) is run through the production tubing 23 and extends
through the wellbore into tail portion 20c. It should be
understood that the injection tubing 30 can alternately be
ran along side production tubing 23 in the wellbore, if
preferred. A packer 31 or the like is set to isolate an
injection zone within tail portion 20c into which steam is
to be injected. The steam heats the oil in reservoir 11 in
the same manner as before with the heated fluids flowing
downward into the wellbore below the injection zone where
it is produced through production tubing 23. The injection
of steam through the long tubing string 30 will further
enhance the heating of the completed interval of the
wellbore.
The use of inverted production wells can further
enhance the steamflood economics by eliminating the lag
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time normally associated with waiting on thermal
communication or response between vertical wells. When the
inverted well is directed towards the injection well (FIG.
3), thermal communication in the lateral or horizontal
plane is also accelerated significantly.
Further, the wellbore may be plugged back to shorten
its length as the injected steam moves really across the
reservoir ll so that the wellbore remains in contact with
the steam chest in both the vertical and lateral or
horizontal planes throughout the producing life of the
well. This also places the edge of the completion interval
in continuous contact with the leading edge of the steam
chest. Still further, inverted wells should eliminate the
need for cyclic steam, which is typically injected into the
production wells of a steam flood during the first few
years to stimulate production.
An added advantage gained from an inverted wellbore is
that it provides an improvement in gravel packing
horizontal portions of the wellbore. The workstring (e.g.
drill pipe) typically used for delivering the gravel slurry
during a gravel packing operation can be seated into a shoe
on the slotted liner at the tail of the wellbore whereby
gravel can flow downward from the tail 20c and into the
horizontal portion 20b of the well thereby taking advantage
of gravity in the inverted portion to carry the gravel into
the horizontal portion of the wellbore.
To summarize, the use of inverted production wells in
a steamflood operation will increase and accelerate thermal
communication between the injection and production wells
while at the same time minimizing steam ~ ~kthrough at the
production wells. Also, inverted product ~n wells provide
those traditional benefits which are normally derived from
more conventional horizontal wells (e.g. long production
intervals and reduced bottom water coning). Further, the
cost of cyclic steam can be eliminated; the initial hot oil
production response may be accelerated by as much as two
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years in a typical steamflood; heat utilization (both in
the reservoir and along the wellbore) to increase oil
production will be improved; and steam breakthrough will be
reduced and delayed; all of which favorably affect the
economics and performance of a steamflood operation by
using inverted production wells.
