U.S. patent application number 14/406008 was filed with the patent office on 2015-06-04 for method of producing viscous hydrocarbons by steam-assisted gravity drainage.
The applicant listed for this patent is Maersk Olie og Gas A/S. Invention is credited to Jens Henrik Hansen, Kristian Mogensen.
Application Number | 20150152720 14/406008 |
Document ID | / |
Family ID | 46762772 |
Filed Date | 2015-06-04 |
United States Patent
Application |
20150152720 |
Kind Code |
A1 |
Mogensen; Kristian ; et
al. |
June 4, 2015 |
METHOD OF PRODUCING VISCOUS HYDROCARBONS BY STEAM-ASSISTED GRAVITY
DRAINAGE
Abstract
A non-cemented liner (20) is introduced into an injection bore
(21), steam is fed into the liner at a first bore part (24) and
injected into the reservoir through holes (22, 23) in the liner
distributed so that the total hole area per length unit of the
liner is greater at a second part (25) than at the first part of
the bore. Steam enters an annular space between liner and bore only
through holes near first part of the bore and subsequently
gradually travels inside the liner in direction of second bore part
and gradually enters the annular space through holes nearer and
nearer second bore part. Gradually liquid is displaced away from an
upper liner part and an upper part of the annular space, so that
steam contacts the bore along substantially the entire length of
the liner in the upper part of the annular space.
Inventors: |
Mogensen; Kristian;
(Kobenhavn K, DK) ; Hansen; Jens Henrik;
(Kobenhavn K, DK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Maersk Olie og Gas A/S |
Kobenhavn K |
|
DK |
|
|
Family ID: |
46762772 |
Appl. No.: |
14/406008 |
Filed: |
June 6, 2013 |
PCT Filed: |
June 6, 2013 |
PCT NO: |
PCT/EP2013/061668 |
371 Date: |
December 5, 2014 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61656156 |
Jun 6, 2012 |
|
|
|
Current U.S.
Class: |
166/400 |
Current CPC
Class: |
E21B 43/2408 20130101;
E21B 43/10 20130101; E21B 43/2406 20130101 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/10 20060101 E21B043/10 |
Foreign Application Data
Date |
Code |
Application Number |
Jun 6, 2012 |
DK |
PA 201270302 |
Claims
1. A method of producing viscous hydrocarbons by steam-assisted
gravity drainage (SAGD), comprising: injecting steam into a
hydrocarbon reservoir via an injection well bore placed above a
production well bore, so that heat is transferred from the steam to
the reservoir fluids and thereby reduces the viscosity of
hydrocarbons of the reservoir, thereby facilitating recovery of
hydrocarbons via the production well bore, wherein a liner is
introduced into the injection well bore so that it extends from a
first part of the injection well bore to a second part of the
injection well bore as a non-cemented liner, and wherein the steam
is fed into the liner at the first part of the injection well bore
and is injected into the hydrocarbon reservoir through a number of
holes formed in a wall of the liner, wherein an annular space is
formed between the liner and the injection well bore in which
annular space steam injected through the liner may travel along the
outside of the liner and contact the injection well bore along the
entire length of the liner, and wherein the holes are distributed
so that the total hole area per length unit of the liner is greater
at the second part of the injection well bore than at the first
part of the injection well bore and so that, during a start-up
phase, initially, the steam enters the annular space only through
holes near the first part of the injection well bore, and
subsequently the steam gradually travels inside the liner in the
direction of the second part of the injection well bore and thereby
gradually enters the annular space through holes nearer and nearer
the second part of the injection well bore, thereby gradually
displacing liquid away from an upper part of the liner and away
from an upper part of the annular space, so that, during the
start-up phase, finally, steam contacts the injection well bore
along at least substantially the entire length of the liner in the
upper part of the annular space; and injecting acid into the
hydrocarbon reservoir via the injection well bore before that steam
is injected into the hydrocarbon reservoir via the injection well
bore.
2. The method according to claim 1, wherein an end opening of the
liner located at the second part of the injection well bore is
closed or at least substantially closed against the injection well
bore, preferably via an end cap or the like.
3. The method according to claim 1, wherein steam is introduced
into the liner only from the end at the first part of the injection
well bore.
4. The method according to claim 1, wherein the first part of the
injection well bore is the inner part at the heel of the injection
well bore, and wherein the second part of the injection well bore
is the outer part at the toe of the injection well bore.
5. The method according to claim 1, wherein the liner includes top
holes pointing upwards for diverting the steam into the reservoir
and bottom holes pointing downwards in order for condensed water
and initial well bore fluids to escape from the liner.
6. The method according to claim 1, wherein the liner is inserted
into the injection well bore by connecting a number of liner
sections at random angular rotation in relation to each other, and
wherein each liner section includes at least one set of at least
two holes arranged with a regular spacing in the circumferential
direction of the liner section.
7. The method according to claim 6, wherein each liner section
includes at least one set of two holes arranged with a spacing of
approximately 180 degrees in the circumferential direction of the
liner section.
8. The method according to claim 6, wherein the holes of the at
least one set of at least two holes have corresponding or equal
cross-sectional area.
9. The method according to claim 6, wherein all the holes included
by each set of holes are arranged at the same length position of
the liner section.
10. The method according to claim 1, wherein the total hole area
per length unit of the liner gradually increases from the first
part of the injection well bore to the second part of the injection
well bore.
11. The method according to claim 1, wherein the total hole area
per length unit of the liner at a part of the second part of the
injection well bore is at least 2 times, preferably at least 3
times and most preferred at least or about 4 times the total hole
area per length unit of the liner at a part of the first part of
the injection well bore.
12. The method according to claim 1, wherein the holes in the liner
has a diameter in the interval from about 0.5 mm to about 8 mm, and
wherein the distance between holes in the liner at the second part
of the injection well bore is less than 12 meters, preferably less
than 9 meters and most preferred about 7.5 meters, and the distance
between holes in the liner at the first part of the injection well
bore is more than 24 meters, preferably more than 27 meters meters
and most preferred about 30 meters meters.
13. The method according to claim 1, wherein the liner has a
diameter of between about 2.5 cm to about 18 cm.
14. The method according to claim 1, wherein, over a length of the
liner of not more than 20 metersmeters, preferably not more than 30
metersmeters and most preferred not more than 35 metersmeters, at
least one hole is positioned at a top position of the liner, and at
least one hole is positioned at a bottom position of the liner.
15. The method according to claim 2, wherein steam is introduced
into the liner only from the end at the first part of the injection
well bore.
16. The method according to claim 7, wherein the holes of the at
least one set of at least two holes have corresponding or equal
cross-sectional area.
17. The method according to claim 7, wherein all the holes included
by each set of holes are arranged at the same length position of
the liner section.
18. The method according to claim 2, wherein the first part of the
injection well bore is the inner part at the heel of the injection
well bore, and wherein the second part of the injection well bore
is the outer part at the toe of the injection well bore.
19. The method according to claim 2, wherein the liner includes top
holes pointing upwards for diverting the steam into the reservoir
and bottom holes pointing downwards in order for condensed water
and initial well bore fluids to escape from the liner.
20. The method according to claim 2, wherein the liner is inserted
into the injection well bore by connecting a number of liner
sections at random angular rotation in relation to each other, and
wherein each liner section includes at least one set of at least
two holes arranged with a regular spacing in the circumferential
direction of the liner section.
Description
[0001] The present invention relates to a method of producing
viscous hydrocarbons by steam-assisted gravity drainage (SAGD),
whereby steam is injected into a hydrocarbon reservoir by means of
an injection well bore placed above a production well bore, so that
heat is transferred from the steam to the reservoir fluids and
thereby reduces the viscosity of hydrocarbons of the reservoir,
thereby facilitating recovery of hydrocarbons by means of the
production well bore, whereby a liner is introduced into the
injection well bore so that it extends from a first part of the
injection well bore to a second part of the injection well bore as
a non-cemented liner, and whereby the steam is fed into the liner
at the first part of the injection well bore and is injected into
the hydrocarbon reservoir through a number of holes formed in a
wall of the liner.
[0002] Steam injection is a common thermal recovery technique for
heavy oils, particularly in Canada, Venezuela, and in Oman. The
main idea is that steam injected into the well bore condenses in
the reservoir and transfers its heat of vaporization to the
reservoir fluids. This results in a dramatic reduction in viscosity
of the reservoir oil and makes economic recovery of even
extra-heavy oil like bitumen possible.
[0003] GB 2 053 328 discloses a thermal method for recovering
normally immobile oil from a tar sand deposit, in which two wells
are drilled horizontally into the deposit, an upper well for
injection of heated fluid and a lower well for production of
liquids. The injection well includes a casing having perforations
along the horizontal section which are in communication with the
tar sand deposit. Thermal communication is established between the
wells. The wells are operated such that heated mobilized oil and
steam flow without substantially mixing. Oil drains continuously by
gravity to the production well where it is recovered.
[0004] According to SPE 50429, Society of Petroleum Engineers, some
operators in California have tried a different completion strategy
where they cement the liner and then perforate the well to provide
access to the reservoir through multiple zones. In an attempt to
ensure that steam is distributed to all the zones and not just the
first zone, a limited-entry technique has been used, implying that
the size or area of the perforations has been specifically selected
to limit the flow rate into a zone at a given injection pressure.
However, as most of the annulus is now covered with cement, this
design provides very little access to the reservoir.
[0005] According to SPE 97922, Society of Petroleum Engineers, some
operators choose a slotted liner for both oil producer and steam
injector. A slot can be thought of as a rectangular hole, which
does not impose any significant pressure drop. Hence, its purpose
is not to divert steam but merely to provide access for the steam
to reach the reservoir. Unsurprisingly, most of the heat transfer
takes place at the heel of the well bore.
[0006] A common problem with the above-mentioned completion
techniques is that steam distribution along the injection wells is
poor. Uniform development of the steam chamber remains one of the
most critical challenges of the SAGD process because of its direct
impact on heavy oil recovery. This means that the wells must be
short and oil recovery suffers from inadequate transfer of heat
from the steam to the heavy oil.
[0007] The object of the present invention is to provide improved
steam distribution even along very long injection well bores.
[0008] In view of this object, an annular space is formed between
the liner and the injection well bore in which annular space steam
injected through the liner may travel along the outside of the
liner and contact the injection well bore along the entire length
of the liner, and the holes are distributed so that the total hole
area per length unit of the liner is greater at the second part of
the injection well bore than at the first part of the injection
well bore and so that, during a start-up phase, initially, the
steam enters the annular space only through holes near the first
part of the injection well bore, and subsequently the steam
gradually travels inside the liner in the direction of the second
part of the injection well bore and thereby gradually enters the
annular space through holes nearer and nearer the second part of
the injection well bore, thereby gradually displacing liquid away
from an upper part of the liner and away from an upper part of the
annular space, so that, during the start-up phase, finally, steam
contacts the injection well bore along at least substantially the
entire length of the liner in the upper part of the annular
space.
[0009] Thereby, it may be ensured that liquid is eventually
displaced entirely from even the second part of the injection well
bore and at the same time it may be avoided that excessive
quantities of steam is injected into the hydrocarbon reservoir at
the first part of the injection well bore during the start-up
phase, and consequently an improved steam distribution along the
length of the injection well bore may eventually be achieved during
the entire normal operation phase during which production of
hydrocarbon takes place. Consequently, oil recovery may be
increased as a result of improved transfer of heat from the steam
to the heavy oil over the entire length of the well bore.
[0010] In an embodiment, an end opening of the liner located at the
second part of the injection well bore is closed or at least
substantially closed against the injection well bore, preferably by
means of an end cap or the like. Thereby, it may better be ensured
that steam exits the liner through the holes as desired. However,
the end cap may itself be provided with holes for steam injection
or drainage of well bore liquids. The end opening of the liner may
alternatively be pressed against the end of the injection well
bore, thereby at least substantially closing the end opening.
[0011] In an embodiment, steam is introduced into the liner only
from the end at the first part of the injection well bore. Due to
an improved steam distribution along the length of the injection
well bore achieved during the start-up phase, it may be unnecessary
to introduce steam from more than one end of the liner even during
the entire normal operation phase, whereby complex tubing may be
avoided.
[0012] In an embodiment, the first part of the injection well bore
is the inner part at the heel of the injection well bore, and the
second part of the injection well bore is the outer part at the toe
of the injection well bore. Thereby, steam may enter the liner at
the inner part of the injection well bore, whereby auxiliary tubing
inside the liner for the introduction of steam at the outer part of
the injection well bore may be avoided.
[0013] In an embodiment, the liner includes top holes pointing
upwards for diverting the steam into the reservoir and bottom holes
pointing downwards in order for condensed water and initial well
bore liquids to escape from the liner. Thereby, a better separation
between steam and well bore liquids may be achieved.
[0014] In an embodiment, the liner is inserted into the injection
well bore by connecting a number of liner sections at random
angular rotations in relation to each other, and each liner section
includes at least one set of at least two holes arranged with a
regular spacing in the circumferential direction of the liner
section. Thereby, as a large number of liner sections may be
connected, it may be ensured that generally, over the length of the
liner, some of the holes will point in more or less upward
direction, and some of the holes will point in more or less
downward direction, so that both steam diversion into the reservoir
and drainage of liquids out of the liner may be facilitated.
[0015] In a structurally advantageous embodiment, each liner
section includes at least one set of two holes arranged with a
spacing of approximately 180 degrees in the circumferential
direction of the liner section.
[0016] In an embodiment, the holes of the at least one set of at
least two holes have corresponding or equal cross-sectional area.
Thereby, the cross-sectional area of the holes per length unit of
the liner for top holes as well as for bottom holes may be
well-controlled, even if the holes are pre-drilled before insertion
of the liner sections into the injection well bore.
[0017] In an embodiment, all the holes included by each set of
holes are arranged at the same length position of the liner
section. This may further facilitate controlling the
cross-sectional area of the holes per length unit of the liner for
top holes as well as for bottom holes.
[0018] In an embodiment, the total hole area per length unit of the
liner gradually increases from the first part of the injection well
bore to the second part of the injection well bore. Thereby, an
even better improved steam distribution along the length of the
injection well bore may be achieved.
[0019] In an embodiment, the total hole area per length unit of the
liner at a part of the second part of the injection well bore is at
least 2 times, preferably at least 3 times and most preferred at
least or about 4 times the total hole area per length unit of the
liner at a part of the first part of the injection well bore.
Thereby, a particular good steam distribution along the length of
the injection well bore may be achieved.
[0020] In an embodiment, the holes in the liner has a diameter in
the interval from about 0.5 mm to about 8 mm, and the distance
between holes in the liner at the second part of the injection well
bore is less than 12 metres (approximately 40 feet), preferably
less than 9 metres (approximately 30 feet) and most preferred about
7.5 metres (approximately 25 feet), and the distance between holes
in the liner at the first part of the injection well bore is more
than 24 metres (approximately 80 feet), preferably more than 27
metres (approximately 90 feet) and most preferred about 30 metres
(approximately 100 feet). Thereby, an even better steam
distribution along the length of the injection well bore may be
achieved.
[0021] In an embodiment, the liner has a diameter of between about
2.5 cm (approximately 1 inch) to about 18 cm (approximately 7
inches).
[0022] In an embodiment, over a length of the liner of not more
than 20 metres, preferably not more than 30 metres and most
preferred not more than 35 metres, at least one hole is positioned
at a top position of the liner, and at least one hole is positioned
at a bottom position of the liner. This may further facilitate
controlling the cross-sectional area of the holes per length unit
of the liner for top holes as well as for bottom holes.
[0023] In an embodiment, acid is injected into the hydrocarbon
reservoir by means of the injection well bore before that steam is
injected into the hydrocarbon reservoir by means of the injection
well bore. Thereby, a significant advantage may be obtained, as the
acid may generate long wormholes along the reservoir section of the
well and thereby subsequently promote improved steam
distribution.
[0024] The invention will now be explained in more detail below by
means of examples of embodiments with reference to the very
schematic drawing, in which
[0025] FIG. 1 is a side view illustration of a general well
configuration for the known steam-assisted gravity drainage
recovery technique,
[0026] FIG. 2 is an end view of the well configuration shown in
FIG. 1,
[0027] FIG. 3 illustrates a side view of a prior art SAGD injection
well,
[0028] FIG. 4 is an illustration including a side view of an SAGD
injection well according to the invention at initial conditions
prior to steam injection at a point in time, t=t.sub.0, together
with a curve showing viscosity of the oil along the length of the
wellbore,
[0029] FIG. 5 is an illustration corresponding to that of FIG. 4
illustrating conditions at a point in time, t=t.sub.1,
[0030] FIG. 6 is an illustration corresponding to that of FIG. 4
illustrating conditions at a point in time, t=t.sub.2,
[0031] FIG. 7 is an illustration corresponding to that of FIG. 4
illustrating conditions at a point in time, t=t.sub.3, and
[0032] FIG. 8 is an illustration corresponding to that of FIG. 4
illustrating conditions at a point in time,
t=t.sub.4>>t.sub.3.
[0033] FIGS. 1 and 2 generally illustrate the well-known method of
steam-assisted gravity drainage, whereby a production well bore 1
is placed just above the contact area 2 between the oil reservoir 3
and the aquifer 4, and an injection well bore 5 is placed above the
production well bore 1. The production well bore 1 may be placed
for instance 5 to 10 metres above the contact area 2 between the
oil reservoir 3 and the aquifer 4. The injection well bore 5 may
for instance be placed 4 to 6 metres above the production well bore
1. The steam travels upwards and forms a steam chamber 6, so that
heat is transferred to the oil reservoir 3, thereby lowering the
oil viscosity. The oil with resulting lowered viscosity can then
more easily be produced by the production well bore 1.
[0034] Accurate well placement is important for the success of this
method. If the wells are too close to the oil-water contact, the
oil production well bore will produce more water from the aquifer.
On the other hand, if the well bores are positioned higher up in
the reservoir, oil below the well bores will not be contacted with
the steam and will therefore not be produced.
[0035] FIG. 3 illustrates a prior art SAGD injection well bore 7
forming a heel 10 (at the inner part of the bore) and a toe 11 (at
outer part of the bore). The heel 10 forms the bend between a
vertical part 12 and a horizontal part 13 of the well bore 7.
Steam, represented by the arrows, travels down the well bore 7
inside an open-ended tubing 8 and enters an open annulus 9 formed
between the tubing 8 and the well bore 7 to contact the reservoir
fluids. Most of the heat will be used when steam contacts reservoir
fluids at the toe 11 of the well bore 7, and gradually less heat
will be available as the steam travels in the annulus 9 back
towards the heel 10. Ensuring that steam reaches the heel 10 of the
well bore before condensing may limit the current completion length
to about 1500 metres. If sufficient displacement of the fluids in
the heel 10 of the well bore is not obtained, then the surrounding
reservoir volumes will only be heated by conductance from the
heated wellbore which reduces the economic value of the recovery
project.
[0036] The SAGD process generally takes place in three distinct
phases: start-up, or circulation; normal SAGD operation; and wind
down. The start-up is aimed at mobilizing the heavy oil close to
and between the injection well bore 5 and the production well bore
1 to establish communication between the well bores. The most
widely used method for start-up is circulating steam in both
injection well bore and production well bore for as long as 90
days. Normal operation involves injecting steam and producing heavy
oil to form the steam chamber 6 above the pair of well bores. This
phase provides access to the maximum amount of resources within the
drainage area and lasts as many years as necessary, so that the
maximum amount of oil is recovered from the drainage volume.
Finally, the wind down includes a series of operations aimed at
reducing the amount of steam injected and using auxiliary operating
patterns to maximize recovery.
[0037] If the steam condenses before contacting the reservoir 3,
the released heat will not lead to the desired oil viscosity
reduction; instead it will be absorbed by the tubing steel of the
open-ended tubing 8. Effective development of areally extensive
reservoirs requires long horizontal well bores, and the ability to
deliver steam across the entire reservoir interval is of great
importance for economic development of such reservoirs. The uniform
distribution of steam is a challenge because of the large mobility
contrast between the injected steam and the reservoir fluid having
viscosity in the range of 0.1 to 1.0 million cP. Failure to fully
displace the open annulus 9 to steam will prevent a uniform SAGD
process across the exposed reservoir section and the contrast will
grow with time as the injected steam provide even higher mobility
in the better exposed areas. Therefore, the prior art SAGD
injection well bore 7 illustrated in FIG. 3 may suffer from poor
steam distribution along the horizontal part 13 of the well bore 7,
in particular if said horizontal part 13 is relatively long.
[0038] FIGS. 4 to 8 illustrate the start-up phase of the method of
producing viscous hydrocarbons by steam-assisted gravity drainage
(SAGD) according to the present invention at different time
steps.
[0039] The method according to the present invention seeks to
achieve a controlled steam distribution along the entire well bore
length (the length of the injection well bore as well as the length
of the production well bore) by means of a non-cemented liner 20
inserted into an injection well bore 21. The wall of the
non-cemented liner 20 is provided with a limited number of holes
22, 23 for steam injection from the liner 20 into the reservoir as
well as escape of condensed water and the initial wellbore fluids
from the liner 20. The holes may be pre-drilled before insertion of
the liner 20 into the well bore. Preferably, the well bore 21 is
configured as an open hole completion; however, if special demands
may occur, the wall of the bore could be provided with a slotted
liner, screen or similar in order to strengthen the bore, but still
providing substantially free access to the wall of the bore.
[0040] The holes 22, 23 are distributed over the length of the
liner 20 so that the total hole area per length unit of the liner
20 is greater at a second part 25 of the injection well bore 21
than at a first part 24 of the injection well bore 21. This may be
achieved either by providing holes regularly along the length of
the liner, but larger holes at the second part 25 than at the first
part 24, or by providing holes of equal size along the liner, but
more holes per length unit of the liner 20 at the second part 25
than at the first part 24. The latter configuration is the one that
is illustrated in FIGS. 4 to 8. Furthermore, a combination of these
configurations is possible. It may be preferred that the total hole
area per length unit of the liner gradually increases from the
first part 24 of the injection well bore 21 to the second part 25
of the injection well bore 21.
[0041] The holes 22, 23 may be drilled in pairs of two, whereby a
top hole 22 pointing upwards serves to divert the steam by imposing
a pressure drop whereby a choke effect is created, and whereby a
bottom hole 23 drilled oppositely and pointing downwards serves to
enable condensed water and initial well bore fluids to escape from
the liner 20 into the reservoir. However, although the figures
illustrate holes 22, 23 only at the top and bottom positions of the
liner 20, holes may also be positioned at other positions.
Preferably, at least some of the holes 22, 23 are positioned at the
top position of the liner 20, and, preferably, at least some of the
holes are positioned at the bottom position of the liner 20.
Furthermore, this should preferably be the case over a reasonable
length of the liner, for instance such as 30 metres, in order to
ensure regular steam diversion to the top of the injection well
bore along the length of the bore as well as regular drainage of
the bottom of the liner 20 along the length of the bore.
[0042] The liner 20 is preferably inserted into the newly drilled
injection well bore 21 by connecting a number of liner sections at
random angular rotations in relation to each other. Each liner
section may include at least one set of at least two pre-drilled
holes arranged with a regular spacing in the circumferential
direction of the liner section. Thereby, it may generally be
ensured that, over a certain length of the liner, at least some
holes will be positioned more or less at the top position of the
liner, and that, over a certain length of the liner, at least some
holes will be positioned more or less at the bottom position of the
liner.
[0043] In order to control the distribution of the hole area per
length unit of the injection liner, both for top holes 22 directed
upwards and intended for steam diversion and for bottom holes 23
directed downwards and intended for drainage, it may in the case of
pre-drilled holes be preferred that the holes are arranged in sets
of holes positioned at the same length position of the liner 20,
whereby all holes of a set have corresponding cross-sectional
area.
[0044] On the other hand, if the holes 22, 23 would be drilled
after insertion of the liner 20 into the injection well bore 21,
all of the holes 22 could just as well be drilled at least
substantially at a top position of the liner 20, and similarly, all
of the holes 23 could just as well be drilled at least
substantially at a bottom position of the liner 20. Furthermore, in
this case, top holes 22 and bottom holes 23 could have different
cross-sectional area.
[0045] FIG. 4 illustrates an SAGD injection well bore 21 according
to the present invention at a point in time, t=t.sub.0. The
injection well bore 21 may be arranged in an oil reservoir above a
production well bore in the same way as the injection well bore 5
illustrated in FIGS. 1 and 2. The injection well bore 21 is in FIG.
4 shown at initial conditions prior to steam injection, whereby the
injection well bore 21 is filled with liquids from the drilling
process with a temperature approximately equal to the reservoir
temperature. The upper circles symbolize the top holes 22 to be
used for steam to exit the liner 20, whereas the lower circles
represent bottom holes 23 to be used by the condensed water as well
as the initial wellbore fluids.
[0046] In FIGS. 4 to 8, the curve shown below the injection well
bore 21 illustrates the viscosity, .mu..sub.oil, of the oil in the
immediate vicinity of the injection well bore 21 as a function of
the length along the well bore, L, measured from a first end 29 of
the injection well bore 21 in the direction of a second end 30 of
the injection well bore 21. The first end 29 of the injection well
bore 21 is located at the first part 24 of the injection well bore
21, and the second end 30 of the injection well bore 21 is located
at the second part 25 of the injection well bore 21. Dotted parts
of the curve illustrate the oil viscosity from the previous time
step shown in the previous figure.
[0047] It is noted that the first end 29 of the substantially
horizontal injection well bore 21 is connected to a not shown
substantially vertical well bore leading to the surface of the
reservoir, corresponding to the prior art arrangement illustrated
in FIG. 3. Thereby, a heel of the well bore is formed at the the
first end 29, and the first part 24 of the injection well bore 21
forms the inner part and the second part 25 forms the outer part.
According to the present invention, steam is preferably introduced
into the liner 20 at the first end 29 of the well bore, however, by
means of auxiliary tubing inside the liner 20 leading from the heel
at the first part 24 to the second part 25, steam could in fact be
introduced at the second end 30 of the injection well bore instead
of at the first end 29.
[0048] It is noted that in FIGS. 5 to 8, the direction of the flow
of steam is illustrated by means of arrows.
[0049] FIG. 5 depicts a snapshot in time during the start-up of the
injection well bore 21 at a point in time, t=The steam (illustrated
by less dense hatching) has traveled a certain distance into the
liner from the first end 29 of the injection well bore 21 and into
the first part 24 of the injection well bore 21. Due to a small
hole size, a significant pressure drop is imposed across each hole,
and critical flow governed by the speed of sound may develop across
the hole. Therefore, regardless of possibly increased pump
pressure, the same amount of flow will pass through the hole to an
annular space 26 is formed between the liner 20 and the injection
well bore 21. The remainder of the steam will stay inside the liner
20 and displace the liquid well bore fluids (illustrated by dense
hatching) further towards an end 27 of the liner at the second part
25 of the injection well bore 21, whereby it exits the liner 20 out
through the top holes 22 further towards the end 27 and out through
the bottom holes 23 along the entire length of the injection well
bore 21. A certain amount of steam will condense inside the well
bore; this condensed water will also escape into the reservoir
primarily through the bottom holes 23.
[0050] The oil viscosity in the near well bore region will decrease
in the area contacted by the steam as the steam transfers its
latent heat of vaporization to the heavy oil.
[0051] In FIGS. 6 and 7, the steam front has moved further down the
liner 20 towards the end 27. The portion of steam which has entered
the annular space 26 through the top holes 22 will propagate into
the reservoir, but some of the steam will displace the liquids from
the top to the bottom of the annular space 26. Therefore, with
time, the top of the annular space 26 will be filled with steam,
whereas the bottom of the annular space 26 will be filled with
condensed water.
[0052] After sufficient time, as illustrated in FIG. 8, an
equilibrium situation has been established. The original well bore
fluids have been fully displaced from the liner 20, but two-phase
flow will prevail; steam, with gas-phase properties will occupy the
top part of the cross-sectional area of the line 20, whereas
condensing vapor, with liquid-like properties will occupy the
bottom of the liner 20, exiting the liner through the bottom holes
23 at a rate equal to the condensation rate. By now, the heat
profile along the well may be as uniform as it can be and the oil
viscosity near the well bore has been significantly reduced.
[0053] The steam distribution along the liner during the start-up
phase as illustrated in FIGS. 4 to 8 is a result of the
above-described distribution of the total hole area pr. length unit
of the liner 20 and may be fine-tuned by adjusting the rate with
which the total hole area pr. length unit is increased along the
length of the liner 20. For instance, the holes 22, 23 in the liner
20 may have a diameter in the interval from about 0.5 mm to about 8
mm, and the distance between holes 22, 23 in the liner 20 at the
second part 25 of the injection well bore 21 may be less than 12
metres (approximately 40 feet), preferably less than 9 metres
(approximately 30 feet) and most preferred about 7.5 metres
(approximately 25 feet), and the distance between holes 22, 23 in
the liner 20 at the first part 24 of the injection well bore 21 is
more than 24 metres (approximately 80 feet), preferably more than
27 metres (approximately 90 feet) and most preferred about 30
metres (approximately 100 feet). Thereby, the holes may have a
constant diameter over the entire length of the liner 20 and the
spacing between the holes in the longitudinal direction of the
liner may vary. Alternatively, the diameter of the holes may vary
over the length of the liner 20 and the spacing between the holes
in the longitudinal direction of the liner may be constant. It is
even possibly that both the diameter of the holes and said spacing
between the holes vary over the length of the liner 20. In any
case, the hole diameter and the spacing between holes may be
adjusted so that the total hole area per length unit of the liner
at a part of the second part 25 of the injection well bore 21 may
be at least 2 times, preferably at least 3 times and most preferred
at least or about 4 times the total hole area per length unit of
the liner at a part of the first part 24 of the injection well bore
21.
[0054] The liner 20 may typically have a diameter of between about
2.5 cm (approximately 1 inch) to about 18 cm (approximately 7
inches). For instance, coiled tubing may be used, and for instance
of a diameter of approximately 4.4 cm (1.75 inches).
[0055] An average hole area per length unit of the liner may be
about 2.0 mm.sup.2/m for a length of the liner of approximately
1000 metres. For a longer liner, the average hole area per length
unit of the liner may be smaller, probably around 0.5-1.0
mm.sup.2/m.
[0056] The hole area per length unit of the liner may be from
60-70% of the average hole area per length unit of the liner at the
heel (inner part) of the well to 130-140% of said average hole area
at the toe (outer part) of the well. Regarding the length of the
wells allowed by means of the invention, an increase from about
1,000 metres to some 2,000-3,000 metres per well is envisaged.
[0057] The above-described distribution of the total hole area pr.
length unit of the liner 20 in fact results in that, during a
start-up phase, initially, the steam enters the annular space 26
only through holes 22 near the first part 24 of the injection well
bore 21, and subsequently the steam gradually travels inside the
liner 20 in the direction of the second part 25 of the injection
well bore 21 and thereby gradually enters the annular space 26
through holes 22 nearer and nearer the second part 25 of the
injection well bore 21, thereby gradually displacing liquid away
from an upper part of the liner 20 and away from an upper part of
the annular space 26, so that, during the start-up phase, finally,
steam contacts the injection well bore 21 along at least
substantially the entire length of the liner 20 in the upper part
of the annular space 26.
[0058] An end opening of the liner 20 located at the second part 25
of the injection well bore 21 is preferably closed against the
injection well bore 21 by means of an end cap 28 or the like. The
end cap 28 could be provided with upper and/or lower holes for
steam injection.
[0059] According to the present invention, it is preferred that
steam is introduced into the liner 20 only from the first end 29 at
the first part 24 of the injection well bore 21, at least during
the start-up phase. However, at least during the entire normal
operation phase, steam could possibly also be introduced from the
second end 30 of the injection well bore 21.
[0060] Acid may be injected into the hydrocarbon reservoir by means
of the injection well bore 21 before that steam is injected into
the hydrocarbon reservoir by means of the injection well bore 21.
Thereby, a significant advantage may be obtained, as the acid may
generate long wormholes along the reservoir section of the well and
thereby subsequently promote improved steam distribution.
* * * * *