U.S. patent application number 14/767351 was filed with the patent office on 2015-12-24 for well injection and production method and system.
This patent application is currently assigned to DEVON CANADA CORPORATION. The applicant listed for this patent is DEVON CANADA CORPORATION. Invention is credited to WARREN FOSTER PETER MacPHAIL, JERRY CHIN SHAW.
Application Number | 20150369023 14/767351 |
Document ID | / |
Family ID | 51353457 |
Filed Date | 2015-12-24 |
United States Patent
Application |
20150369023 |
Kind Code |
A1 |
MacPHAIL; WARREN FOSTER PETER ;
et al. |
December 24, 2015 |
WELL INJECTION AND PRODUCTION METHOD AND SYSTEM
Abstract
A method and system for enhancing petroleum production are
provided, in which petroleum is displaced from a fractured
formation by selectively injecting fluid into selected fractures in
the formation without injecting into the other non-selected
fractures. The injected fluid flows out into the fractured
formation and enhances recovery from the non-selected fractures.
Petroleum is selectively collected from the non-selected
fractures.
Inventors: |
MacPHAIL; WARREN FOSTER PETER;
(Calgary, CA) ; SHAW; JERRY CHIN; (Calgary,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
DEVON CANADA CORPORATION |
Calgary |
|
CA |
|
|
Assignee: |
DEVON CANADA CORPORATION
Calgary
AB
|
Family ID: |
51353457 |
Appl. No.: |
14/767351 |
Filed: |
February 12, 2014 |
PCT Filed: |
February 12, 2014 |
PCT NO: |
PCT/CA2014/050095 |
371 Date: |
August 12, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61763743 |
Feb 12, 2013 |
|
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|
Current U.S.
Class: |
166/269 ;
166/185; 166/305.1; 166/316 |
Current CPC
Class: |
E21B 33/124 20130101;
E21B 43/122 20130101; E21B 43/12 20130101; E21B 34/06 20130101;
E21B 43/14 20130101; E21B 43/16 20130101; E21B 43/121 20130101 |
International
Class: |
E21B 43/14 20060101
E21B043/14; E21B 33/124 20060101 E21B033/124; E21B 43/12 20060101
E21B043/12; E21B 43/16 20060101 E21B043/16; E21B 34/06 20060101
E21B034/06 |
Claims
1. A method for petroleum production from a well having a well
section with a wellbore inner surface in communication with a
plurality of fractures in a formation containing reservoir fluid,
the method comprising: creating a first set and a second set of
zones in the well section, each zone for communicating with at
least one of the plurality of fractures, and the first set of zones
being fluidly sealed from the second set of zones in the well
section; and selectively injecting injection fluid into the
formation via at least one zone in the first set of zones.
2. The method of claim 1 further comprising: selectively collecting
reservoir fluid from the formation via at least one zone in the
second set of zones; and transporting the collected reservoir fluid
to surface.
3. The method of claim 2, wherein each zone is associated with a
flow regulator, the flow regulator having an open position which
allows fluid flow therethrough and a closed position which blocks
fluid flow therethrough, for controlling one or both of: (i) flow
of fluid into the zone; and (ii) flow of fluid out of the zone.
4. The method of claim 3, wherein the flow regulator associated
with the at least one zone in the first set of zones is in
communication with a supply of injection fluid, and further
comprising selectively injecting injection fluid by selectively
opening the flow regulator associated with the at least one zone in
the first set of zones.
5. The method of claim 3, wherein the flow regulator associated
with the at least one zone in the second set of zones allows at
least some of the reservoir fluid to pass therethrough in the open
position, and further comprising selectively collecting reservoir
fluid by selectively opening the flow regulator associated with the
at least one zone in the second set of zones.
6. The method of claim 2, wherein the collected reservoir fluid is
transported to surface by one or more of: pumping and
gas-lifting.
7. The method of claim 3, wherein the flow regulator preferentially
allows the flow of petroleum therethrough.
8. The method of claim 4, wherein the supply of injection fluid
flows through a conduit extending along the well section.
9. The method of claim 5, wherein the flow regulator is in
communication with a conduit extending from surface into the well
section, and further comprising permitting reservoir fluid in the
at least one zone in the second set to flow into the conduit and
transporting the collected reservoir within the conduit.
10. The method of claim 3, wherein the flow regulator is in
communication with a conduit extending from surface into the well
section, further comprising supplying injection fluid through the
conduit; and selectively injecting injection fluid by selectively
opening the flow regulator associated with the at least one zone in
the first set of zones.
11. The method of claim 10, further comprising ceasing the supply
of injection fluid; selectively collecting reservoir fluid by
selectively opening the flow regulator associated with the at least
one zone in the second set of zones; permitting reservoir fluid in
the at least one zone in the second set to flow into the conduit
and transporting the collected reservoir within the conduit.
12. The method of claim 1, wherein packers are used to fluidly seal
the zones from one another.
13. The method of claim 2, wherein injecting injection fluid and
collecting reservoir fluid occur simultaneously.
14. The method of claim 2, wherein injecting injection fluid and
collecting reservoir fluid occur asynchronously.
15. The method of claim 2, wherein a portion of the injection fluid
is recovered from the collected reservoir fluid.
16. A method for hydrocarbon production from a well having a well
section with a wellbore inner surface in communication with a first
set and a second set of fractures in a formation containing
reservoir fluid, the method comprising: creating a plurality of
injection zones in the well section, each injection zone for
communicating with at least one fracture in the first set of
fractures at the wellbore inner surface; creating a plurality of
production zones in the well section, each production zone for
communicating with at least one fracture in the second set of
fractures at the wellbore inner surface and for receiving reservoir
fluid from the formation via the at least one fracture in the
second set of fractures, each production zone being fluidly sealed
from the injection zones inside the well section; selectively
injecting injection fluid into the formation via at least one of
the injection zones; selectively collecting reservoir fluid from
the formation via at least one of the production zones; and
transporting the collected reservoir fluid to surface.
17. The method of claim 16, wherein each injection zone is in
communication with an injection flow regulator, the injection flow
regulator being in communication with a supply of injection fluid,
and further comprising selectively injecting injection fluid by
selectively opening the injection flow regulator in communication
with the at least one of the injection zones.
18. The method of claim 16, wherein each production zone is in
communication with a production flow regulator, and further
comprising selectively collecting reservoir fluid by selectively
opening the production flow regulator in communication with the at
least one of the production zones and allowing at least some of the
reservoir fluid to pass through the production flow regulator.
19. The method of claim 17, wherein the supply of injection fluid
flows through an injection conduit extending along the well
section.
20. The method of claim 18, wherein the production flow regulator
is in communication with a production conduit extending from the
well section to surface, and the collected reservoir fluid is
transported within the production conduit.
21. The method of claim 16, wherein injecting injection fluid and
collecting reservoir fluid occur simultaneously.
22. The method of claim 16, wherein injecting injection fluid and
collecting reservoir fluid occur asynchronously.
23. A method for petroleum production involving a first well having
a first well section with a first wellbore inner surface in
communication with a first set of fractures in a formation
containing reservoir fluid and a second well having a second well
section with a second wellbore inner surface in communication with
a second set of fractures in the formation, wherein some of the
fractures in the first set are in close proximity to some of the
fractures in the second set, the method comprising: creating a
plurality of injection zones in the first well section, each
injection zone for communicating with at least one of the fractures
in the first set that are in close proximity to some of the
fractures in the second set, via the first wellbore inner surface;
creating a plurality of production zones in the second well
section, each production zone for communicating with at least one
of the fractures in the second set that are in close proximity to
some of the fractures in the first set, via the second wellbore
inner surface, the plurality of production zones configured to
receive reservoir fluid from the formation; selectively injecting
injection fluid into the formation via at least one of the
injection zones; selectively collecting reservoir fluid from the
formation via at least one of the production zones; and
transporting the collected reservoir fluid to surface.
24. The method of claim 23, wherein some of the fractures in the
first set that are in close proximity to some of the fractures in
the second set extend between some of the fractures in the second
set.
25. The method of claim 23, wherein each injection zone is in
communication with an injection flow regulator having an open
position which allows fluid flow therethrough and a closed position
which blocks fluid flow therethrough, the injection flow regulator
being in communication with a supply of injection fluid, and
further comprising selectively injecting injection fluid by
selectively opening the injection flow regulator in communication
with the at least one of the injection zones.
26. The method of claim 23, wherein each production zone is in
communication with a production flow regulator having an open
position which allows at least some reservoir fluid to flow
therethrough and a closed position which blocks fluid flow
therethrough, and further comprising selectively collecting
reservoir fluid by selectively opening the production flow
regulator in communication with the at least one of the production
zones.
27. The method of claim 23, wherein the collected reservoir fluid
is transported to surface by one or more of: pumping and
gas-lifting.
28. The method of claim 26, wherein the production flow regulator
preferentially allows the flow of petroleum therethrough.
29. The method of claim 25, wherein the supply of injection fluid
flows through a conduit extending along the first well section.
30. The method of claim 26, wherein the production flow regulator
is in communication with a conduit extending from the second well
section to surface, and further comprising collecting reservoir
fluid from the at least one of the production zones into the
conduit and transporting the collected reservoir fluid within the
conduit.
31. The method of claim 23, wherein injecting injection fluid and
collecting reservoir fluid occur simultaneously.
32. The method of claim 23, wherein injecting injection fluid and
collecting reservoir fluid occur asynchronously.
33. The method of claim 23, wherein a portion of the injection
fluid is recovered from the collected reservoir fluid.
34. A system for petroleum production from a well having an inner
bore and a well section with a wellbore inner surface in
communication with a first set and a second set of fractures in a
formation containing reservoir fluid, the system comprising: an
injection conduit extending inside the inner bore and along at
least part of the well section; a production conduit extending
inside the inner bore and along at least part of the well section;
at least one injection zone in the well section for communicating
with at least one fracture in the first set of fractures at the
wellbore inner surface; at least one production zone in the well
section for communicating with at least one fracture in the second
set of fractures at the wellbore inner surface, the at least one
production zone being fluidly sealed from the at least one
injection zone inside the well section; at least one injection flow
regulator in association with the at least one injection zone, the
at least one injection flow regulator having an open position which
allows fluid communication between the injection conduit and the at
least one fracture in the first set of fractures via the at least
one injection zone, and a closed position which blocks fluid
communication between the injection conduit and the at least one
fracture in the first set of fractures; and at least one production
flow regulator in association with the at least one production
zone, the at least one production flow regulator having an open
position which allows fluid communication between the production
conduit and the at least one fracture in the second set of
fractures via the at least one production zone, and a closed
position which blocks fluid communication between the injection
conduit and the at least one fracture in the second set of
fractures.
35. The system of claim 34 wherein the production conduit and the
injection conduit are positioned side-by-side axially in the well
section.
36. The system of claim 34 wherein one of the production and
injection conduits is inside the other conduit in the well section,
the conduit on the inside being an inside conduit and the conduit
on the outside being an outside conduit.
37. The system of claim 34 wherein the at least one injection flow
regulator is connected to the injection conduit.
38. The system of claim 34 wherein the at least one production flow
regulator is connected to the production conduit.
39. The system of claim 34 further comprising packers for fluidly
sealing the at least one production zone from the at least one
injection zone.
40. The system of claim 34 wherein the well section includes a
casing with an outer surface and an inner surface, the inner
surface being the wellbore inner surface, and wherein the at least
one production flow regulator and the at least one injection flow
regulator are installed on the outer surface of the casing or
outside of the casing adjacent the outer surface thereof.
41. The system of claim 36 further comprising a bypass tube
extending through and bypassing the at least one production zone,
and fluidly connecting the at least one injection zone with another
injection zone.
42. The system of claim 36 further comprising a bypass tube
extending through and bypassing the at least one injection zone,
and fluidly connecting the at least one production zone with
another production zone.
43. The system of claim 36 wherein the wellbore inner surface in
the well section defines the outside conduit.
44. The system of claim 40 further comprising measurement and
control system instrumentation which is installed outside of the
casing adjacent the outer surface thereof.
45. The system of claim 36 further comprising a seal and a bypass
tube, the bypass tube extending through the seal between a first
end and a second end of the seal, the seal allowing fluid
communication between the inner conduit and a zone, and the bypass
tube bypassing the zone and fluidly connecting sections of the
outer conduit adjacent to the first and second ends of the
seal.
46. The system of claim 34 wherein the production conduit and the
injection conduit are one and the same.
47. A method for producing petroleum from a well having a wellbore
with a wellbore inner surface, the wellbore communicable via the
wellbore inner surface with a first set and a second set of
fractures in a formation containing reservoir fluid, the method
comprising: supplying injection fluid to the wellbore via a
conduit; injecting injection fluid from the wellbore to the
formation through the first set of fractures, while blocking fluid
flow to and from the second set of fractures; ceasing the supply of
injection fluid; blocking fluid flow to and from the first set of
fractures; permitting flow of reservoir fluid from the formation
through the second set of fractures into the wellbore; and
collecting reservoir fluid from the wellbore via the conduit.
48. The method of claim 47, wherein the first set of fractures and
the wellbore is fluidly communicable through at least one flow
regulator having an open position which allows fluid flow
therethrough and a closed position which blocks fluid flow
therethrough, and further comprising opening the at least one flow
regulator to inject injection fluid to the formation through the
first set of fractures; and closing the at least one flow regulator
to block fluid flow to and from the first set of fractures.
49. The method claim 47, wherein the second set of fractures and
the wellbore is fluidly communicable through at least one flow
regulator having an open position which allows fluid flow
therethrough and a closed position which blocks fluid flow
therethrough, and further comprising closing the at least one flow
regulator to block fluid flow to and from the second set of
fractures; and opening the at least one flow regulator to permit
flow of reservoir fluid from the formation through the second set
of fractures into the wellbore.
50. The method of claim 47, wherein the collected reservoir fluid
is transported to surface by one or more of: pumping and
gas-lifting.
51. The method of claim 47, wherein a portion of the injection
fluid is recovered from the collected reservoir fluid.
52. A system for petroleum production from a well having a well
section with a wellbore inner surface and an inner bore, the inner
bore being communicable with fractures in a formation via the
wellbore inner surface, the system comprising: a conduit extending
down the well, the conduit having a lower end in or near the well
section and being in fluid communication with the inner bore of the
well section; and a plurality of flow regulators at or near the
wellbore inner surface, each being connected to at least one of the
fractures and being selectively openable and closeable for allowing
and blocking, respectively, fluid communication between the inner
bore and the at least one of the fractures.
53. The system of claim 52 wherein the well section includes a
casing with an outer surface and an inner surface, the inner
surface being the wellbore inner surface, and the plurality of flow
regulators are installed on the outer surface of the casing or
outside of the casing adjacent the outer surface thereof.
54. The system of claim 53 further comprising measurement and
control system instrumentation which is installed outside of the
casing adjacent the outer surface thereof.
55. A method for petroleum production from a well having a well
section with a wellbore inner surface in communication with a
plurality of fractures in a formation containing reservoir fluid,
the method comprising: creating a plurality of zones in the well
section, each zone for communicating with at least one of the
plurality of fractures and each zone being fluidly sealed from
adjacent zones in the well section, and two or more zones are
fluidly connectable via a conduit extending through the plurality
of zones; selectively supplying injection fluid from the conduit to
at least one of the zones and injecting the injection fluid into
the formation via the at least one of the zones; selectively
collecting reservoir fluid into the conduit from the formation via
at least one of the zones, and the injection of injection fluid and
the collection of reservoir fluid occurring asynchronously;
transporting the collected reservoir fluid to surface.
56. The method of claim 55, wherein each zone is associated with a
flow regulator connected to the conduit, the flow regulator having
an open position which allows fluid flow therethrough and a closed
position which blocks fluid flow therethrough, for controlling one
or both of: (i) flow of fluid into the zone; and (ii) flow of fluid
out of the zone.
Description
PRIORITY APPLICATION
[0001] This application claims priority to U.S. provisional
application Ser. No. 61/763,743, filed Feb. 12, 2013.
FIELD
[0002] The invention relates to a method and a system for petroleum
production, and more specifically to a method and a system for
enhancing petroleum production in a well.
BACKGROUND
[0003] Petroleum recovery from subterranean formations (sometimes
also referred to as "reservoirs") typically commences with primary
production (i.e. use of initial reservoir energy to recover
petroleum). Since reservoir pressure depletes through primary
production, primary production is sometimes followed by the
injection of fluids, including for example water, hydrocarbons,
chemicals, etc., into a wellbore in communication with the
reservoir to maintain the reservoir pressure and to displace
(sometimes also referred to as "sweep") petroleum out of the
reservoir. One issue with injecting fluids to enhance petroleum
recovery is how to efficiently sweep the reservoir fluids and
expedite production.
[0004] In general, petroleum produces from a well due to the
presence of a differential pressure gradient between the far field
reservoir pressure and the pressure inside the wellbore. As the
well produces, the reservoir pressure gradually decreases and the
pressure gradient diminishes over time. This reduction in reservoir
pressure usually causes a decline in production rates from the
well.
[0005] Further, the permeability of the desired production fluid
(i.e. liquid petroleum) within the reservoir rock reduces in the
presence of another phase (e.g. gas phase). The presence of another
phase has the effect of reducing the flow rate of the desired
production fluid from the reservoir to the wellbore. In general,
the reservoir fluid comprises a mixture of several types of
hydrocarbons and other constituents. The phase of many of the
constituents is dependent on the pressure and temperature of the
reservoir. As the pressure of the reservoir reduces through
production, some of the dissolved constituents may come out of
solution and become a free gas phase. These gas-phase constituents
may collect near the well in any region of the reservoir where the
pressure has reduced to below the bubble point, which may block
liquid petroleum from producing into the wellbore. This problem of
two-phase flow resulting from reservoir pressure depletion may be
prevented or minimized by injecting fluid into the wellbore to
maintain reservoir pressure.
[0006] The oil and gas industry has progressed from producing
petroleum using vertical wells to horizontal wells which are
hydraulically stimulated creating transverse fractures that are
typically perpendicular but sometimes are at oblique angles to the
horizontal wellbore. These multi-fractured horizontal wells (MFHW)
are typically used in tight or shale gas and/or oil formations to
improve well productivity. However, the decline rates of these MFHW
may be very severe, which provides an opportunity for using a
method for enhancing petroleum recovery.
SUMMARY OF THE INVENTION
[0007] According to a broad aspect of the invention, there is
provided a method for petroleum production from a well having a
well section with a wellbore inner surface in communication with a
plurality of fractures in a formation containing reservoir fluid,
the method comprising: creating a first set and a second set of
zones in the well section, each zone for communicating with at
least one of the plurality of fractures, and the first set of zones
being fluidly sealed from the second set of zones in the well
section; and selectively injecting injection fluid into the
formation via at least one zone in the first set of zones.
[0008] According to another broad aspect of the invention, there is
provided a method for hydrocarbon production from a well having a
well section with a wellbore inner surface in communication with a
first set and a second set of fractures in a formation containing
reservoir fluid, the method comprising: creating a plurality of
injection zones in the well section, each injection zone for
communicating with at least one fracture in the first set of
fractures at the wellbore inner surface; creating a plurality of
production zones in the well section, each production zone for
communicating with at least one fracture in the second set of
fractures at the wellbore inner surface and for receiving reservoir
fluid from the formation via the at least one fracture in the
second set of fractures, each production zone being fluidly sealed
from the injection zones inside the well section; selectively
injecting injection fluid into the formation via at least one of
the injection zones; selectively collecting reservoir fluid from
the formation via at least one of the production zones; and
transporting the collected reservoir fluid to surface.
[0009] According to yet another aspect of the present invention,
there is provided a method for petroleum production involving a
first well having a first well section with a first wellbore inner
surface in communication with a first set of fractures in a
formation containing reservoir fluid and a second well having a
second well section with a second wellbore inner surface in
communication with a second set of fractures in the formation,
wherein some of the fractures in the first set are in close
proximity to some of the fractures in the second set, the method
comprising: creating a plurality of injection zones in the first
well section, each injection zone for communicating with at least
one of the fractures in the first set that are in close proximity
to some of the fractures in the second set, via the first wellbore
inner surface; creating a plurality of production zones in the
second well section, each production zone for communicating with at
least one of the fractures in the second set that are in close
proximity to some of the fractures in the first set, via the second
wellbore inner surface, the plurality of production zones
configured to receive reservoir fluid from the formation;
selectively injecting injection fluid into the formation via at
least one of the injection zones; selectively collecting reservoir
fluid from the formation via at least one of the production zones;
and transporting the collected reservoir fluid to surface.
[0010] According to another broad aspect of the invention, there is
provided a system for petroleum production from a well having an
inner bore and a well section with a wellbore inner surface in
communication with a first set and a second set of fractures in a
formation containing reservoir fluid, the system comprising: an
injection conduit extending inside the inner bore and along at
least part of the well section; a production conduit extending
inside the inner bore and along at least part of the well section;
at least one injection zone in the well section for communicating
with at least one fracture in the first set of fractures at the
wellbore inner surface; at least one production zone in the well
section for communicating with at least one fracture in the second
set of fractures at the wellbore inner surface, the at least one
production zone being fluidly sealed from the at least one
injection zone inside the well section; at least one injection flow
regulator in association with the at least one injection zone, the
at least one injection flow regulator having an open position which
allows fluid communication between the injection conduit and the at
least one fracture in the first set of fractures via the at least
one injection zone, and a closed position which blocks fluid
communication between the injection conduit and the at least one
fracture in the first set of fractures; and at least one production
flow regulator in association with the at least one production
zone, the at least one production flow regulator having an open
position which allows fluid communication between the production
conduit and the at least one fracture in the second set of
fractures via the at least one production zone, and a closed
position which blocks fluid communication between the injection
conduit and the at least one fracture in the second set of
fractures.
[0011] According to yet another broad aspect of the invention,
there is provided a method for producing petroleum from a well
having a wellbore with a wellbore inner surface, the wellbore
communicable via the wellbore inner surface with a first set and a
second set of fractures in a formation containing reservoir fluid,
the method comprising: supplying injection fluid to the wellbore
via a conduit; injecting injection fluid from the wellbore to the
formation through the first set of fractures, while blocking fluid
flow to and from the second set of fractures; ceasing the supply of
injection fluid; blocking fluid flow to and from the first set of
fractures; permitting flow of reservoir fluid from the formation
through the second set of fractures into the wellbore; and
collecting reservoir fluid from the wellbore via the conduit.
[0012] According to another broad aspect of the invention, there is
provided a system for petroleum production from a well having a
well section with a wellbore inner surface and an iimer bore, the
inner bore being communicable with fractures in a formation via the
wellbore inner surface, the system comprising: a conduit extending
down the well, the conduit having a lower end in or near the well
section and being in fluid communication with the inner bore of the
well section; and a plurality of flow regulators at or near the
wellbore inner surface, each being connected to at least one of the
fractures and being selectively openable and closeable for allowing
and blocking, respectively, fluid communication between the inner
bore and the at least one of the fractures.
[0013] According to another broad aspect of the invention, there is
provided a method for petroleum production from a well having a
well section with a wellbore inner surface in communication with a
plurality of fractures in a formation containing reservoir fluid,
the method comprising: creating a plurality of zones in the well
section, each zone for communicating with at least one of the
plurality of fractures and each zone being fluidly sealed from
adjacent zones in the well section, and two or more zones are
fluidly connectable via a conduit extending through the plurality
of zones; selectively supplying injection fluid from the conduit to
at least one of the zones and injecting the injection fluid into
the formation via the at least one of the zones; selectively
collecting reservoir fluid into the conduit from the formation via
at least one of the zones, and the injection of injection fluid and
the collection of reservoir fluid occurring asynchronously;
transporting the collected reservoir fluid to surface.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] Drawings are included for the purpose of illustrating
certain aspects of the invention. Such drawings and the description
thereof are intended to facilitate understanding and should not be
considered limiting of the invention. Drawings are included, in
which:
[0015] FIG. 1 is a schematic diagram illustrating one embodiment of
the invention;
[0016] FIG. 2 is a cross-sectional view of one embodiment of the
invention, where the system is installed in a cased and cemented
horizontal well section;
[0017] FIG. 3 is a cross-sectional view of another embodiment of
the invention, where the system is installed in an unlined openhole
horizontal well section;
[0018] FIG. 4 is a cross-sectional view of yet another embodiment
of the invention, where one conduit is inside the other
conduit;
[0019] FIG. 5 is a cross-sectional view of another embodiment of
the invention, where one conduit is inside the other conduit;
[0020] FIG. 6 is a cross-sectional view of still another embodiment
of the invention, where one conduit is inside the other
conduit;
[0021] FIG. 7 is a schematic diagram illustrating another
embodiment of the invention, which involves two adjacent
wellbores;
[0022] FIG. 8 is a cross-sectional view of another embodiment of
the invention, where one conduit is used for both injection and
production;
[0023] FIG. 9 is a cross-sectional view of yet another embodiment
of the invention, where one conduit is used for both injection and
production;
[0024] FIGS. 10a and 10b are a perspective view and a cross-section
view, respectively, showing an embodiment of a bypass tube usable
with the present invention; and
[0025] FIGS. 11a and 11b are a perspective view and a cross-section
view, respectively, showing another embodiment of a bypass tube
usable with the present invention.
DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS
[0026] The detailed description set forth below in connection with
the appended drawings is intended as a description of various
embodiments of the present invention and is not intended to
represent the only embodiments contemplated by the inventor. The
detailed description includes specific details for the purpose of
providing a comprehensive understanding of the present invention.
However, it will be apparent to those skilled in the art that the
present invention may be practiced without these specific
details.
[0027] An aspect of the present invention is to provide a scheme
and a system for use with a horizontal wellbore to allow
simultaneous injection of fluid(s) for pressure maintenance and
effective sweeping and production of petroleum out of the
formation.
[0028] In one aspect, a method is described herein for enhancing
petroleum production from a well having alternating injection and
production pattern through the induced transverse fracture network
so the injected fluid(s) may effectively sweep hydrocarbons
linearly from one stage of induced fracture(s) (e.g. an injection
stage) into an adjacent stage of induced fracture(s) (e.g. a
production stage). This pattern can be repeated as many times as
required depending on the number of fracture stages in the
wellbore. This well injection and production method may be used for
each well in a reservoir having multiple horizontal spaced-apart
wells so that the effects of this method may be multiplied. The
spacing between the injection and production interval can be
adjusted to account for the formation permeability (i.e. tighter
spacing for lower permeability formation).
[0029] In one broad aspect of the present invention, petroleum is
displaced from a fractured wellbore by creating a plurality of
zones, each in conununication with at least a fracture in the
wellbore, and selectively injecting a fluid into selected zones
without injecting into the other non-selected zones. The selected
zones and non-selected zones are fluidly sealed from one another in
the wellbore. The injection fluid flows out into the fractured
formation and enhances recovery in the non-selected zones. The
non-selected zones are selectively allowed or not allowed to
produce, depending on the circumstances. A sample method and system
of the invention are disclosed herein.
[0030] Referring to FIGS. 1 to 6, a well has a heel transitioning
from a substantially vertical section to a substantially horizontal
section. The well may or may not be cased. The substantially
horizontal section of the well is in communication with a plurality
of fractures F in a formation 8 adjacent to the well, via a
wellbore inner surface 11, at various locations along the length of
the horizontal section.
[0031] In the illustrated embodiment in FIG. 2, at least a portion
of the horizontal section of the well is lined with a casing string
14. The casing string 14 may be cemented to a wellbore wall 10 by a
layer of concrete 15 formed in the annulus between the wellbore
wall 10 and casing string 14. The casing string and concrete has
intermittent perforations 13 along a lengthwise portion of the
horizontal section which provide passage ways connecting the inner
surface of the casing string and fractures F. For a cased well, the
wellbore inner surface 11 of the horizontal section is the inner
surface of the casing string 14. In one embodiment, a system of
openhole packers (not shown) is provided on the outer surface of
the casing string with valves placed therebetween, whereby the
annular space between adjacent openhole packers can be
hydraulically accessed via the valves.
[0032] In an embodiment as illustrated in FIG. 3, the well is
uncased so the wellbore is in direct communication with the
fractures F via wellbore wall 10. For an uncased well, the wellbore
inner surface 11 of the horizontal section is the wellbore wall 10.
A person of ordinary skill in the art would know whether it would
be beneficial to case the wellbore and/or to cement the casing 14
to the formation.
[0033] Fractures F may be natural fractures occurring in the
formation, fractures that are formed by hydraulic fracturing, or a
combination thereof. While fractures F are shown in the Figures to
extend substantially perpendicular to the lengthwise axis of the
horizontal section, fractures F may extend away from the wellbore
at any angle relative to the lengthwise axis.
[0034] There are a number of ways to initiate hydraulic fractures
at specific locations in the wellbore, including for example by
hydra jet, by staged hydraulic fracturing using various mechanical
diversion tools and methods applicable to open wells or cased
wells, by using a limited entry perforation and hydraulic fracture
technique (which is generally applicable to cased cemented wells),
etc. Other techniques for placing multiple hydraulic fractures in a
horizontal well section include for example: a multiple repeated
sequence of jet perforating the cased cemented hole followed by
hydraulic fracturing with temporary isolation inside the wellbore
using mechanical bridge plugs; wireline jet perforating the cased
and cemented hole to initiate the hydraulic fracture at a specific
interval while preventing the fracture treatment from re-entering
previously fractured intervals using perforation ball sealers
and/or other methods of diversion; hydra jet perforating with
either mechanical packer or sand plug diversion; various open-hole
packer and valve systems; and manipulating valves installed with
the cemented casing using coiled tubing or jointed tubing deployed
tools.
[0035] With reference to FIGS. 1 to 4, a system is shown for
facilitating petroleum production from the formation 8. The system
comprises an injection conduit 18 and a production conduit 20, both
of which extend into the horizontal section of the wellbore. The
injection conduit 18 supports injection flow regulators 22 at
intermittent locations along a lengthwise section thereof to allow
fluids inside the conduit to flow out via the flow regulators 22.
The production conduit 20 supports production flow regulators 24 at
intermittent locations along a lengthwise section thereof to allow
fluids from outside the conduit to flow into the conduit via the
flow regulators 24. One or both of conduits 18 and 20 may also
include packers 16 that are positioned intermittently along a
lengthwise portion thereof. Regulators 22 and 24 and packers 16
will be described in more detail hereinbelow.
[0036] Injection conduit 18 and production conduit 20 are separate
flow channels such that the flow of fluids in one conduit is
independent of the other. In one embodiment, as illustrated in
FIGS. 1, 2 and 3, injection conduit 18 is positioned side-by-side
with and substantially parallel to production conduit 20. In an
alternative embodiment, one of the conduits may be inside the
other. For example, as shown in FIGS. 4 to 6, the production
conduit 20 is placed inside injection conduit 18, and is optionally
substantially concentric with injection conduit 18. Further, the
position of one conduit relative to the other may vary along the
length of the well. For example, as shown in FIG. 5, the production
conduit 20' is inside injection conduit 18' above the horizontal
section of the well, and the injection conduit 18'' becomes the
inside conduit along the horizontal section through the use of
bypass tubes at or near the heel of the well. However the conduits
are positioned relative to one another, the operation of each of
the conduits is independent from one another so the flow of fluids
in each conduit can be separately controlled.
[0037] In whichever configuration, the diameters of the conduits
are sized such that: (i) the conduits can be easily run into the
wellbore; (ii) the conduits allow for the flow of either production
or injection fluids at suitable flow rates; and (iii) when the
conduits are in a desired position downhole, there is at least some
space between the wellbore inner surface 11 and the outer surface
of at least one of the conduits.
[0038] In one embodiment, the production conduit comprises jointed
tubing, the length and quantity of which may depend on the measured
depth of the well and/or the length of the fractured portion of the
well. In a further embodiment, the production conduit is closed at
one end (i.e. the lower end) and may have a substantially uniform
diameter throughout its length. In another embodiment, the
production conduit has a graduated diameter along its length, with
the larger diameter portion above the uppermost packer or above a
pump, if one is included for transporting the petroleum from the
production conduit.
[0039] Tubing that meets American Petroleum Institute (API)
standards and specifications ("API tubing") may be used for the
production conduit and/or the injection conduit. Proprietary
connection tubing and/or tubing that has a smaller outside diameter
at the connections than specified by API may also be used.
Alternatively, non-API tube sizes may be used for all or a portion
of the production conduit and/or the injection conduit.
[0040] In a sample embodiment, the production conduit tubing for
installation in the fractured section of the well has an outer
diameter ranging between about 52.4 mm and about 114.3 mm,
preferably with API or proprietary connections and a joint length
of approximately 9.6 in, for a well wherein at least a portion of
the fractured section is cased, and wherein the casing string has
an outer diameter ranging between about 114.3 and about 193.6 mm.
In another sample embodiment, a production conduit tubing having
the above-mentioned characteristics may also be used in an uncased
well, wherein the open-hole diameter in the fractured section
ranges between about 155.6 and about 244.5 mm.
[0041] In one embodiment, the injection conduit comprises coiled
tubing, API jointed tubing, or proprietary tubing. The length and
quantity of the injection conduit tubing may depend on the measured
depth of the well and/or the length of the fractured portion of the
well. In a further embodiment, the injection conduit is closed at
one end (i.e. the lower end) and may have a substantially uniform
diameter throughout its length. If coiled tubing is used for the
injection conduit, the outer diameter of the injection conduit
tubing may range from about 19 mm to about 50.8 mm. In a preferred
embodiment, the coiled tubing for the injection conduit has an
outer diameter of approximately 25.4 mm. If jointed tubing is used
for the injection conduit, the outer diameter of the injection
conduit tubing may range from about 26.67 mm to about 101.6 mm. In
another sample embodiment, a production conduit tubing having the
above-mentioned characteristics may also be used in an uncased
well, wherein the open-hole diameter in the fractured section
ranges between about 155.6 and about 244.5 mm.
[0042] In a side-by-side configuration as illustrated in FIGS. 1 to
3, the jointed tubing for the injection conduit, for example, has
an outer diameter of approximately 26.67 mm, and the production
conduit tubing has an outer diameter of approximately 60.3 mm. In a
system configuration wherein one conduit is disposed inside the
other, as illustrated in FIGS. 4 to 5, the outer conduit for
example has an outer diameter of approximately 101.6 mm and the
inner conduit has an outer diameter of approximately 52.4 mm. In
another sample system configuration wherein one conduit is placed
inside the other as illustrated in FIG. 6, the outer conduit's
outside diameter is approximately 114.3 mm and the inner conduit's
outer diameter is approximately 60.3 mm.
[0043] In one embodiment, both the injection and production
conduits along with any downhole sensors, instruments, electric
conductor lines and hydraulic control lines are housed inside a
single encapsulated cable. The type of encapsulated cable produced
by Teclmip Umbilical Systems may be used but modifications may be
required to accommodate packers and valves thereon.
[0044] The production conduit is for transporting fluids from the
wellbore to the surface of the wellbore opening. The fluids
received by the production conduit are referred to as "produced
fluids". The injection conduit is for transporting injection fluid
from at least the wellbore opening into the wellbore.
[0045] Injection fluid (sometimes also referred to as "injectant")
includes for example water, gas (e.g. nitrogen, and carbon
dioxide), and/or petroleum solvent (e.g. methane, ethane, propane,
carbon dioxide, or a mixture thereof), with or without chemical
additives. However, any fluid that can become miscible to the
petroleum in-situ may be used as the injectant since miscible
floods have shown to produce superior hydrocarbon recovery factors
over immiscible floods.
[0046] The injection fluid may be supplied to the injection conduit
from a supply source at surface. Alternatively or additionally,
injection fluid may be recovered and separated from the produced
fluids, and then compressed and re-injected into the injection
conduit. In one embodiment, any or all of the recovering,
separating, compressing, and re-injecting of injection fluid may be
performed downhole.
[0047] In one embodiment, the composition of the injection fluid
may be selected based on its solubility in the reservoir petroleum.
The process of using a dissolvable injection fluid to sweep
reservoir petroleum is sometimes referred to as "hydrocarbon
miscible solvent flood," or HCMF. Examples of hydrocarbon miscible
solvents include for example methane, ethane, propane and carbon
dioxide. The dissolution of certain soluble injection fluids into
the reservoir petroleum generally lowers the viscosity of the
latter and reduces interfacial tension, thereby increasing the
mobility of the petroleum within the reservoir. This process may
improve the rate of production and increase the recovery factor of
petroleum recoverable from the reservoir.
[0048] Packers are usually used to divide a wellbore into sections
and are usually placed downhole with or as a component of a
downhole tool. Packers 16 may include various types of mechanisms,
such as swellable rubber packer elements, mechanical set packer
elements and slips, cups, hydraulic set mechanical packer elements
and slips, inflatable packer elements, seal bore, seal combination,
or a combination thereof.
[0049] Packers are generally transformable from a retracted
position (sometimes also referred to as a "running position") to an
expanded position (sometimes also referred to as a "set position").
The packers are in the retracted position when the downhole tool is
run into the wellbore, such that the packers do not engage the
inner surface of the wellbore to cause interference during the
running in. Once the downhole tool is positioned at a desired
location in the wellbore, the packers are converted to the expanded
position. In the expanded position, the packers engage the wellbore
wall if the well is uncased or the casing string if the well is
cased (collectively referred to herein as the "wellbore inner
surface") and may function to fluidly seal the annulus between the
downhole tool and the wellbore inner surface, and may also function
to anchor the downhole tool (or a tubing string connected thereto)
to the wellbore inner surface.
[0050] In one embodiment, as shown for example in FIGS. 1 to 3,
packers 16 are connected to both conduits. In the sample
embodiments shown in FIGS. 4 to 6, packers 16 are connected to one
of the conduits. Packers 16 may be connected to one or both of the
conduits in various ways, including for example, by threaded
connection, friction fitting, bonding, welding, adhesives, etc. In
one embodiment, packers 16 are configured to be expandable from the
outer surface of at least one of the conduits. The packers are
spaced apart along the length of the conduits such that adjacent
flow regulators 22 and 24 are separated by at least one packer.
Alternatively or additionally, adjacent packers may have one or
more injection flow regulators 22 or production flow regulators 24
positioned therebetween.
[0051] In a preferred embodiment, packers 16 are mechanical
feedthrough-type packers having a hydraulic-setting mechanism.
Generally, feedthrough-type packers allow the passage of
conduit(s), electrical conductor line(s), and/or communication
line(s) therethrough. In a further preferred embodiment, packers 16
are feedthrough-type swellable packers (sometimes also referred to
as cable swellable packers) that allow at least one of the conduits
to connect thereto and extend therethrough. In one embodiment, the
packers are attached in the retracted position to the production
conduit pre-run in and are expanded after the conduits are at a
desired location downhole. In the expanded position, the packers
engage the wellbore and fill a portion of the annulus between the
inner surface of the wellbore and the outer surfaces of the
conduits. In one embodiment, packers 16 are configured to expand
radially outwardly from the outer surfaces of the conduits. Once
expanded, each packer creates a seal with the wellbore inner
surface such that fluid can only flow from one side of the packer
to the other side through the conduits.
[0052] In a sample embodiment, one or more of the packers may be
manufactured on or connected to a section of tubing, which may
range from about 3 m to about 9.6 m in length, and the tubing
having a packer thereon is connected at both ends to production
conduit tubings. In a further embodiment, the packer has a length
ranging from about 1 m to about 5 m. The connection between the
packer tubing and the production conduit tubing may be an API
specification or proprietary design threaded connection. In a
sample embodiment, packers 16 are made of an elastomeric polymer
bladder that is inflatable upon injection of a fluid therein. The
types of fluid that may be used to inflate the packers include for
example oil and water.
[0053] Preferably, packers 16 are positioned in between fractures
or perforations 13 (if the well is cased). The locations of the
fractures may be determined by the location of the perforations in
the casing according to the executed completion plan, or by
microseismic monitoring or logging. Logging methods may include
radioactive tracer, temperature survey, fiber optic distributed
temperature sensor survey, or production logging. Generally,
adjacent hydraulic fractures are spaced apart by approximately 100
m, but sometimes the distance between adjacent hydraulic fractures
in a horizontal well may range from about 20 to about 200 m. In one
embodiment, packers 16 are positioned in the wellbore such that
there are one or more fractures between adjacent packers. It is not
necessary that the packers 16 are evenly spaced along the
horizontal section of the well. The distance between adjacent
packers may vary.
[0054] Preferably, each packer 16 creates a seal with the wellbore
inner surface 11 such that fluid can only flow from one side of the
packer to the other side through one of the conduits. The space
defined by the wellbore inner surface 11 and the outer surface of
one or both of the conduits, in between two adjacent packers, and
in communication with at least one fracture, is referred to
hereinafter as a "zone." Adjacent zones are fluidly sealed from one
another. Preferably, each zone permits the flow of fluids thereto
from one or more fractures F and/or from the injection conduit
18.
[0055] Referring to FIGS. 2 to 5, flow regulators 22 of the
injection conduit allow selective introduction of injection fluid
from the conduit into the wellbore. More specifically, flow
regulators 22 help distribute and control the flow of injection
fluid into selected zones. Preferably, the flow regulator 22 has at
least an open position and a closed position. In the open position,
the regulator 22 allows fluid flow therethrough. In the closed
position, the regulator 22 blocks fluid flow. The open position may
include one or more partially open positions, including choked,
screened, etc., such that the rate of fluid flow therethrough may
be selectively controlled.
[0056] A number of devices may be used for flow regulators 22,
including for example sliding sleeves, tubing valves, chokes,
remotely operated valves, and interval control valves. Remotely
operated valves are valves that can be hydraulically, electrically,
or otherwise controlled from a downhole location and/or the surface
of the well opening. However, other devices that function in a
similar manner as the aforementioned examples may also be used. In
one embodiment, flow regulators 22 are controllable with
radio-frequency identification (RFID).
[0057] In a sample embodiment, the injection flow regulators 22 are
chokes, each with a throat diameter configured to generate
sufficient pressure resistance to limit the rate at which injection
fluid is supplied to the injection zone downstream of the flow
regulator, thereby distributing the injection fluid in a controlled
manner. The chokes may be incorporated into valves to allow
"choking" to help control the distribution of the injection fluid
when the valves are in an open position. In a preferred embodiment,
the injection flow regulator 22 also comprises a mechanism (for
example, a sliding sleeve) that can be selectively closed to
prevent substantially all fluid from flowing therethrough.
[0058] In the sample embodiments shown in FIGS. 2 to 5, there is an
injection flow regulator in every other zone, thereby allowing
fluid communication between these zones and the injection conduit
through the injection flow regulator. A zone that can receive
injection fluids from the injection conduit (for example, through
an injection flow regulator) is referred to as an "injection
zone".
[0059] Referring to FIGS. 2 to 5, flow regulators 24 of the
production conduit allow selective intake of petroleum and/or other
fluids from the formation to the production conduit. Preferably,
flow regulators 24 control when fluids can flow into and/or the
types of fluids that can flow into the production conduit. In one
embodiment, the flow regulator 24 has at least an open position and
a closed position. In the open position, the regulator 24 allows
fluid flow therethrough. In the closed position, the regulator 24
blocks fluid flow. The open position may include one or more
partially open positions, including choked, screened, etc., such
that the rate of fluid flow therethrough may be selectively
controlled.
[0060] Additionally or alternatively, the flow regulators 24 may be
configured to have a customized fluid flow path that selectively
allows the passage of fluids based on viscosity, density, fluid
phase, or a combination of these properties. In one embodiment, the
flow regulator 24 restricts the flow of fluids having a lower
viscosity and/or density than the desired petroleum such that
fluids with a viscosity and/or density similar to the desired
petroleum flow through the regulator 24 preferentially and into the
production conduit. Flow regulators 24 may therefore restrict
undesirable fluids (e.g. water, and gas, such as for example
methane, ethane, carbon dioxide, and propane) from flowing into the
production conduit. In a preferred embodiment, flow regulators 24
allow the flow of liquid petroleum therethrough while limiting the
passage of undesired gas and/or water.
[0061] Any device that can selectively allow and/or restrict the
flow of certain fluids therethrough may be used for flow regulators
24, including for example orifice style chokes, tubes; sliding
sleeve valves, remotely operated valves, and autonomously
functioning flow control devices. Other devices that function in a
similar manner as the aforementioned examples may also be used. In
one embodiment, flow regulators 24 are controllable with
radio-frequency identification (RFID).
[0062] In a sample embodiment, the production flow regulators 24
are autonomously functioning flow regulators, which are
self-adjusting in-flow control devices, whereby fluid flow is
autonomously controlled in response to changes in a fluid flow
characteristic, such as density or viscosity. Autonomously
functioning flow regulators are sometimes more commonly referred to
as Autonomous Inflow Control Device (AICD). The AICD has two main
functions: one is to identify the fluid based on its viscosity, and
the second in to restrict the flow when undesirable fluids are
present. Both of these functions are created by specially designed
flow channels inside the device.
[0063] AICDs generally utilize dynamic fluid technology to
differentiate between fluids flowing therethrough. For example, an
AICD may be configured to restrict the production of unwanted water
and gas at breakthrough to minimize water and gas cuts. Generally,
AICDs have no moving parts, do not require downhole orientation and
utilize the dynamic properties of the fluid to direct flow. AICDs
may work by directing fluids through different flow paths within
the device. Higher viscosity oil takes a short, direct path through
the device with lower pressure differential. Water and gas spin at
high velocities before flowing through the device, creating a large
pressure differential.
[0064] Preferably, the AICD chokes low-viscosity (undesired)
fluids, thereby significantly slowing flow from the zone producing
the undesirable fluids. This autonomous function enables the well
to continue producing the desired hydrocarbons for a longer time,
which may help maximize total production.
[0065] In another sample embodiment, the production flow regulators
24 are valves that can be remotely opened and closed, such as for
example intelligent well completion valves, which allow the
selective ceasing of petroleum flow into the production conduit
from one or more production zones. By closing the flow regulators
24 of one or more production zones for a certain period of time,
the injection fluid is allowed to penetrate deeper into the
reservoir which may help increase petroleum production. In a
further embodiment, selected production flow regulators 24 are
closed while the remaining regulators are opened to allow
production of petroleum, and the pattern or sequence of which
regulators are opened or closed at any given time may be configured
as required to optimize the performance of the system.
[0066] In the sample embodiments shown in FIGS. 2 to 5, there is a
production flow regulator 24 in each of the zones adjacent to the
injection zones, thereby allowing each adjacent zone to fluidly
communicate with the production conduit via the production flow
regulator. The zones in which petroleum and/or other reservoir
fluids can be collected therefrom (for example, by a production
conduit via a flow regulator 24) are referred to herein as
"production zones".
[0067] In one embodiment, injection flow regulators 22 are
connected to the injection conduit and/or production flow
regulators 24 are connected to the production conduit. This may be
achieved in various ways. For example, the flow regulators may be
manufactured into tools that have a similar outer diameter as the
conduit and are insertable at almost any position along the length
of the conduit by, for example, cutting the tubing of the conduit
at a desired location and inserting and connecting the flow
regulator tool at the cut. The tool may be connected to the tubing
by for example mechanical connection, threaded connection,
adhesives, bonding, welding, etc. Mechanical connections include
for example the use of external crimps and external compression
sleeves. External crimps may be used to create a seal between the
flow regulator tool and the conduit tubing by plastically deforming
the tubing on to the tool. External compression sleeves may be used
to seal the outer surface of the tubing at and near the cut. In one
embodiment, the flow regulators are made of metal, such as steel,
that can withstand wellbore conditions. In a further embodiment,
where the flow regulators are chokes, the throat is made of an
erosion wear resistant material, including for example tungsten
carbide or matrix material containing tungsten carbide, ceramic, or
an erosion wear resistant carbon nanostructure.
[0068] There are many ways to configure the system of the present
invention, for example, by varying the placement and/or location of
one or more of the production conduit, injection conduit, packers,
production flow regulators, and injection flow regulators. In a
sample embodiment, as illustrated in FIGS. 2 to 5, the injection
flow regulators 22 and production flow regulators 24 are offset
laterally along the length of the conduits such that regulators 22
are not aligned with regulators 24, and adjacent injection flow
regulators and production flow regulators are separated by a packer
16. Of course, other configurations are possible.
[0069] Further, the number of injection zones 26 and production
zones 28 in the system may be selectively varied and may depend on
the characteristics of the well, including for example the number
of fractures in the well. Each zone may be in communication with
one or more hydraulic fractures. Alternatively, there may be as
many injection and production zones in total as the number of
hydraulic fractures, but not necessarily. Preferably, the lower end
of the production conduit is in communication with the lowermost
(i.e. farthest away from the well opening) production zone via a
production flow regulator 24. Further, the lower end of the
injection conduit is preferably in communication with the lowermost
injection zone via an injection flow regulator 22.
[0070] The pattern of alternating injection and production zones
may be a regular periodic pattern or an irregular random pattern
along the length of the horizontal section of the well. Consecutive
production zones may be separated by one or more injection zones,
and vice versa. For example, in one configuration, a first
injection zone is separated from a second injection zone by one
production zone, and the second injection zone is separated from a
third injection zone by three production zones, and the third
injection zone is separated from a fourth injection zone by two
production zones.
[0071] In one embodiment, at least one production zone may also
function as an injection zone, and vice versa. This may be
accomplished, for example, by: (i) using flow regulators that can
function as both injection flow regulators and production flow
regulators; and/or (ii) using independently functioning injection
flow regulators and production flow regulators within the same
zone. In a further embodiment, all zones are configured to allow
selective injection of fluid into the reservoir.
[0072] In another sample embodiment, the production and injection
conduits are set up as shown in FIGS. 2 to 5, wherein the zones
alternate between injection zones and production zones along the
length of the horizontal section. The flow regulators 22, in the
open position, allow injection fluid to flow from the injection
conduit into the injection zones 26 and into the fractures that are
in communication with the injection zones. In the illustrated
embodiments, the general flow direction of the injection fluid is
indicated with arrows "I".
[0073] Production flow regulators 24 allow petroleum and/or other
fluids in production zones 28 to flow into the production conduit,
which may then flow to or be pumped to surface and be collected. In
the illustrated embodiments, the general flow direction of the
produced fluid is denoted by arrows "P". Various methods may be
employed to transport the petroleum in the production conduit to
surface, including for example by way of an electric submersible
pump, reciprocating subsurface pump, progressing cavity pump, gas
lift, etc. or a combination thereof.
[0074] As discussed above, flow regulators 24 may be configured to
restrict the flow of fluids other than reservoir petroleum into the
production conduit. Some injection fluid may flow into production
zones in the gaseous phase as the reservoir is being emptied of
liquid petroleum, and flow regulators 24 may prevent most or all of
such injection fluid from entering the production conduit. For
example, if the flow regulator 24 is a choking or autonomous
choking valve type flow regulator, the flow regulator may prevent
most low viscosity fluid from entering the production conduit.
However, if the flow regulator 24 is a surface or downhole actuated
valve, such as a sliding sleeve, the flow regulator may prevent all
fluids from entering the production conduit when the flow regulator
is in the closed position. In a preferred embodiment, the
production flow regulator 24 includes a mechanism (for example, a
sliding sleeve) that can be selectively closed to prevent
substantially all fluid from flowing therethrough.
[0075] There are situations where it may be desirable to include a
production flow regulator 24 that, when closed, can prevent
substantially all fluids from entering the production conduit in
the production zone. For instance, if the well is poorly cemented
such that almost all injection fluid entering a particular
injection zone travels directly from the injection zone to an
adjacent production zone rather than to the reservoir (this event
is sometimes referred to as "short circuiting" of injection fluid),
it would be desirable to have a surface or downhole actuated valve
type flow regulator in the adjacent production zone to allow that
production zone to be substantially completely shut off from the
production conduit when the flow regulator therein is in the closed
position. Shutting off the affected production zones in this manner
may help reduce the effect of short circuiting, thereby encouraging
the injection fluid to flow into the reservoir.
[0076] Another situation where it may be desirable to use surface
or downhole actuated valve type flow regulators in production zones
to allow the selective shutting off of certain production zones is
when there is massive reservoir heterogeneity within a single
horizontal well, which may be due to permeability variation or to
natural fracture or complex hydraulic fracture swarms locally
concentrated within only a part of the wellbore affected reservoir.
In this situation, temporarily shutting off certain production
zone(s), while continuing to inject fluid into injection zone(s),
may cause the injected fluid to enter the reservoir more deeply and
saturate the nearby reservoir fluid and/or cause the reservoir
pressure to increase locally. Reopening the shut off production
zone(s) after a period of time may cause any injectant-affected
reservoir fluid to drain into production zones, which may in turn
improve petroleum production. This method of temporarily shutting
off one or more production zones and reopening same may be useful
in the middle and/or later life of the well.
[0077] In embodiments where one conduit is placed inside the other,
as shown for example in FIGS. 4 to 6, the system may comprise
additional or different components and/or may be configured
differently. Referring to FIG. 4, production conduit 20 extends
axially along the length of the inner bore of injection conduit 18.
Packers 16 are intermittently positioned on the outer surface and
along the length of the injection conduit 18 in the horizontal
section of the well to fluidly seal the annulus between the
wellbore inner surface and conduit 18 to define zones, as discussed
above. At various locations along the length of both conduits,
seals 32 are provided to: (i) fluidly seal off a portion of the
annulus between the outer surface of conduit 20 and the inner
surface of conduit 18; and (ii) allow production conduit 20 to
communicate with certain zones. Seals 32 are configured to have
production conduit 20 passing therethrough.
[0078] In one embodiment, each seal 32 has a first end, a second
end, and a space is provided therebetween. Seal 32 is positioned
and installed relative to the production conduit 20 such that at
least one production flow regulator 24 is situated in the space of
the seal. Further, at least one opening is provided in the
injection conduit and the opening is in communication with the
space of seal 32. The at least one opening in the injection conduit
is preferably positioned axially between a pair of packers 16, and
thus defining a production zone 28 in the annulus between the
wellbore inner surface 11 and the outer surface of the injection
conduit and the pair of packers. The opening in the injection
conduit allows the passage of fluids between the space in seal 32
and the zone.
[0079] Since flow regulator 24 is situated in the space of the
seal, when it is in an open position, it is in fluid communication
with the space of the seal and in turn the production zone 28. Seal
32 provides a fluid seal in the annulus between the conduits,
thereby preventing any fluid in the injection conduit from entering
the space in the seal. Therefore, each seal 32 allows fluid
communication between the production zone and the production
conduit 20, when flow regulator 24 is open, while preventing fluid
communication between the injection conduit and the production
zone.
[0080] The system further comprises injection bypass tubes 30 to
allow passage of fluid in the injection conduit through the seals
32, while bypassing (i.e. being fluidly sealed from) production
zones. In a sample embodiment, the bypass tube 30 extends between
the first and second ends through each seal 32, allowing fluid
communication between the annuli adjacent to the first and second
ends while bypassing the space in seal 32. Bypass tubes 30 thereby
fluidly connect sections of the injection conduit that are
separated by seals 32 along the length of the horizontal section,
while bypassing production zones.
[0081] Accordingly, injection flow regulators 22 of the injection
conduit are situated in the zones that are not in communication
with the production conduit (i.e. zones without seals 32 positioned
therein). Injection fluid can flow past seals 32 to each flow
regulator 22 along the length of the injection conduit via bypass
tubes 30.
[0082] Seal 32 and injection bypass tube 30, together, allow fluid
communication between the production zone and the production
conduit, while allowing injection conduit fluid to bypass the
production zone.
[0083] In another embodiment, the positions of the injection and
production conduits may be reversed, such that the injection
conduit runs inside the production conduit. In this embodiment, the
fluid flow in each conduit can also fluidly communicate with
certain zones separately and independently from the other conduit,
through the use of seals 32 and injection bypass tubes 30 as
described above.
[0084] Referring to FIG. 5, the production conduit has an upper
portion 20' and a lower portion 20''. The injection conduit also
has an upper portion 18' and a lower portion 18''. The relative
position of the upper portions of the conduits to each other may be
different than the relative position of the lower portions down the
length of the well. For example, the production conduit may be
inside the injection conduit in the upper portion, while the
production conduit houses the injection conduit therein in the
lower portion.
[0085] In a sample embodiment shown in FIG. 5, the upper portion
20' of the production conduit extends axially inside the length of
the inner bore of the upper portion 18' of the injection conduit in
the substantially vertical section and the heel of the well. Below
the heel, in the substantially horizontal section, the lower
portion 18' of the injection conduit runs axially inside the lower
portion 20' of the production conduit. In other words, the
production conduit is the inner conduit in an upper part of the
well and it is the outer conduit in a lower part of the well.
[0086] In the illustrated embodiment, the upper portion 20' and
lower portion 20'' of the production conduit are connected by a
transition bypass tube 33, through which the upper portion 20' and
lower portion 20'' are in fluid communication.
[0087] Packers 16 are intermittently positioned on the outer
surface and along the length of the lower portion 20'' of the
production conduit to fluidly seal the annulus between the wellbore
inner surface and the outer surface of the production conduit to
define zones, as discussed above.
[0088] At various locations along the length of both conduits 18''
and 20'' in the horizontal section, seals 32', 32'' are provided
to: (i) fluidly seal off a portion of the annulus between the outer
surface of conduit 18'' and the inner surface of conduit 20''; (ii)
allow the lower portion 18'' of the injection conduit to
communicate with certain zones. Seals 32', 32'' are configured to
have the lower portion 18'' of the injection conduit passing
therethrough.
[0089] In one embodiment, each seal 32', 32'' has a first end, a
second end, and a space is provided therebetween. Seal 32', 32'' is
positioned and installed relative to the lower portion 18'' of the
injection conduit such that at least one injection flow regulator
22 is situated in the space of the seal. Further, at least one
opening is provided in the lower portion 20'' of the production
conduit and the opening is in communication with the space of seal
32', 32''. The at least one opening in the lower portion 20'' is
preferably positioned axially between a pair of packers 16, and
thus defining an injection zone 26 in the annulus between the
wellbore inner surface 11 and the outer surface of the lower
portion 20'' and the pair of packers. The opening in the lower
portion 20'' of the production conduit allows the passage of fluids
between the space of seal 32', 32'' and the injection zone.
[0090] Since flow regulator 22 is situated in the space of the
seal, when it is in an open position, it is in fluid communication
with the space of the seal and in turn the injection zone 26. Seal
32', 32'' provides a fluid seal in the annulus between the
conduits, thereby preventing any fluid in the lower portion 20'' of
the production conduit from entering the space in the seal 32',
32''. Therefore, each seal 32', 32'' allows fluid communication
between the injection zone and the lower portion 18'' of the
injection conduit, when flow regulator 22 is open, while preventing
fluid communication between the lower portion 20'' of production
conduit and the injection zone.
[0091] In order to transition from the upper portions 18' and 20'
to the lower portions 18'' and 20'' of the conduits, transition
bypass tube 33 fluidly connects the upper portion 20' and the lower
portion 20'' of the production conduit, to transition the
production conduit from being the inner conduit to being the outer
conduit. In one embodiment, transition bypass tube 33 allows
passage of fluid in the production conduit through the uppermost
seal 32', while bypassing the uppermost injection zone. In a sample
embodiment, the bypass tube 33 extends between the first and second
ends through the uppermost seal 32', allowing fluid communication
between the spaces adjacent to the first and second ends while
bypassing the space in the uppermost seal 32'. The upper end of
bypass tube 33 is in communication with the upper portion 20' of
the production conduit (i.e. the inner conduit) and the lower end
of bypass tube 33 is in communication with the lower portion 20''
(i.e. the outer conduit), thereby transitioning the production
conduit through the uppermost seal 32'.
[0092] The upper portion 18' of the injection conduit is in fluid
communication with the lower portion 18'', for example via an
opening in the lower portion 18'' at or near the first end of the
uppermost seal 32', above the seal 32'.
[0093] Below the uppermost seal 32', the system further comprises
production bypass tubes 34 to allow passage of fluid in the lower
portion 20'' of the production conduit through the seals 32'',
while bypassing injection zones. In one embodiment, the bypass tube
34 extends between the first and second ends through each seal
32'', allowing fluid communication between the annuli adjacent to
the first and second ends while bypassing the space in seal 32''.
Bypass tubes 34 thereby fluidly connect sections of the production
conduit that are separated by seals 32'' along the length of the
horizontal section.
[0094] Accordingly, production flow regulators 24 of the production
conduit are situated in the zones that are not in communication
with the injection conduit (i.e. zones without seals 32', 32''
positioned therein). Fluids from the reservoir can enter the
production conduit via each flow regulator 24 and flow up the
production conduit through seals 32', 32'' via bypass tubes 33 and
34.
[0095] Seal 32', 32'' and bypass tube 33, 34, together, allow fluid
communication between the injection zone and the injection conduit,
while allowing production conduit fluid to bypass the injection
zone. The conduits are transitioned using transition bypass tube 33
and uppermost seal 32', and are maintained using production bypass
tubes 34 and seals 32'', such that fluid flow in upper portion 20'
and lower portion 20'' of the production conduit is separated from
fluid flow in upper portion 18' and lower portion 18'' of the
injection conduit throughout the length of the well.
[0096] In another embodiment, the positions of the injection and
production conduits may be reversed, such that the upper portion of
the injection conduit runs inside the upper portion of the
production conduit and the lower portion of the production conduit
runs inside the lower portion of the injection conduit. In this
embodiment, the fluid flow in each conduit can also fluidly
communicate with certain zones separately and independently from
the other conduit, through the use of seals 32', 32'' and bypass
tubes 33 and 34 as described above.
[0097] In another sample embodiment, as shown in FIG. 6, a cased
well includes casing 14 which is cemented to wellbore wall 10 in at
least the horizontal section. Casing 14 may have a larger diameter
segment above the heel of the well that extends to surface, and an
uncemented tubing is placed in the larger diameter segment. The
wellbore inner surface 11 in the horizontal section is the inner
surface of casing 14 in the horizontal section. In this embodiment,
rather than providing a separate tubing for injection conduit 18,
injection conduit 18 is defined by the wellbore inner surface 11.
Instead of injection flow regulators and production flow
regulators, a plurality of casing flow regulators 23 are provided
at or near the outer surface of casing 14, intermittently
positioned along the length of the horizontal section of the well.
Each of the flow regulators 23 is in communication with at least
one fracture F in the formation 8.
[0098] In one embodiment, casing flow regulators 23 function as
both hydraulic fracture diversion valves and as injection flow
regulators (as described above) or production flow regulators (as
described above). Each casing flow regulator may be remotely and/or
independently operated. Each casing flow regulator has an open
position and a closed position, and the open position may include
one or more partially open positions (e.g. screened, choked, etc.).
In the open position, the casing flow regulator 23 permits
communication between the horizontal section of the wellbore and
the fracture through a perforation in casing 14. In the closed
position, casing flow regulator 23 blocks fluid flow
therethrough.
[0099] Production conduit 20 extends axially along the length of
the inner bore of injection conduit 18, which is in the horizontal
section of the wellbore defined by wellbore inner surface 11.
Packers 16' are intermittently positioned on the outer surface and
along the length of the production conduit 20 in the horizontal
section of the well to fluidly seal the annulus between the
wellbore inner surface and conduit 20 to define zones, as discussed
above. In this embodiment, packers 16' are also provided to allow
production conduit 20 to communicate with certain zones, while
allowing fluid in the injection conduit 18 to bypass these
zones.
[0100] In one embodiment, each packer 16' has a first end packer, a
second end packer. The end packers ate separated by a space
therebetween. Packer 16' is positioned and expanded (i.e.
installed) relative to casing 14 in the horizontal section such
that at least one casing flow regulator 23 is situated in the space
in between the end packers of the packer 16'. The at least one
casing flow regulator 23 therefore allows fluid communication
between the fracture(s) connected thereto and the space in packer
16', when the casing flow regulator is in an open position.
[0101] Further, at least one opening is provided in the production
conduit 20 and the at least one opening is in fluid communication
with the space of packer 16'. Thus, the space in packer 16' defines
a production zone 28, in which reservoir fluids may be collected
when the at least one casing flow regulator 23 in the production
zone is open or partially open. Any fluid collected in the
production zone 28 can flow into the production conduit 20 through
the at least one opening therein. Packer 16' provides a fluid seal
in the annulus between the conduits, thereby preventing any fluid
in the injection conduit from entering the production zone.
Therefore, each packer 16' allows fluid communication between at
least one fracture and the production conduit 20, when the casing
flow regulator in the production zone is open or partially open,
while preventing fluid communication between the injection conduit
and the production zone.
[0102] Packers 16' are also spaced apart along the production
conduit 20, and positioned and expanded relative to casing 14 in
the horizontal section, such that at least one casing flow
regulator 23 is situated between at least a pair of adjacent
packers 16', thereby defining an injection zone 26 between the pair
of packers 16' with which at least one fracture can fluidly
communicate through the at least one casing flow regulator 23 when
the regulator is open or partially open.
[0103] The system further comprises injection bypass tubes 30' to
allow passage of fluid in the injection conduit between injection
zones 26 through the packers 16', while bypassing (i.e. being
fluidly sealed from) production zones 28. In one embodiment, the
bypass tube 30' extends between the first and second ends through
each packer 16', allowing fluid communication between the injection
zone adjacent to the first end packer and the injection zone
adjacent the second end packer while bypassing the production zone
in packer 16'. Bypass tubes 30' thereby fluidly connect sections of
the injection conduit that are separated by packers 16' along the
length of the horizontal section.
[0104] Packers 16' and injection bypass tube 30', together, allow
fluid communication between the production zone and the production
conduit, while allowing injection conduit fluid to bypass the
production zone.
[0105] In another embodiment, the positions of the injection and
production conduits may be reversed, such that the injection
conduit runs inside the production conduit. In this embodiment, the
fluid flow in each conduit can also fluidly communicate with
certain zones separately and independently from the other conduit,
through the use of packers 16' and injection bypass tubes 30' as
described above.
[0106] In one embodiment, any of the above-discussed bypass tubes
with reference to FIGS. 4 to 6 may be a non-circular tube. For
example, the injection bypass tube may have a rectangular
cross-section. Other cross-sectional shapes are possible. Referring
to the sample embodiment shown FIGS. 6, 10a and 10b, the injection
bypass tube 30' is has an arc-shaped cross-section, and the bypass
tube has substantially concentric inner and outer arc segment
shaped walls with different radii. The inner and outer arc segment
shaped walls are connected at the lengthwise sides by flat walls.
In this sample embodiment, the bypass tube 30' is disposed outside
the production conduit and extends axially through the production
zone 28.
[0107] Referring to FIGS. 6, 11a and 11b, another sample embodiment
is shown wherein the bypass tube 30' is disposed eccentrically
outside the production conduit 20 and surrounds a lengthwise
portion of the production conduit. In this embodiment, a portion of
the outer surface of the production conduit 20 is in contact with
the inner surface of the bypass tube 30'. An opening extends
between the inner surface of the production conduit and the outer
surface of the bypass tube, thereby allowing fluid communication
between the inside of the production conduit and the production
zone 28. In this sample embodiment, the effective cross-sectional
shape of the bypass tube is the crescent shape of the space defined
by the outer surface of the production conduit and the inner
surface of the bypass tube where the two tubes are not in
contact.
[0108] FIG. 8 illustrates another sample embodiment for use with a
cased well having a casing 14 which is cemented to wellbore wall 10
in at least the horizontal section. The wellbore inner surface 11
is the inner surface of casing 14. In this embodiment, rather than
having two separate tubings for injection and production, one
conduit 19 is provided for transporting both injection fluid and
reservoir fluid therein. Therefore, in this embodiment, the
injection conduit and the production conduit are one and the same.
Conduit 19 extends down the well through the heel to near or past
the beginning of the horizontal section.
[0109] Further, instead of injection flow regulators and production
flow regulators, a plurality of casing flow regulators 23 are
provided at or near the outer surface of casing 14, intermittently
positioned along the length of the horizontal section of the well.
Each of the flow regulators 23 is in communication with at least
one fracture F in the formation 8.
[0110] Conduit 19 has at least one opening 42 at or near its lower
end for passage of fluids therethrough, thereby allowing fluid
communication between the conduit and the wellbore. In one
embodiment, opening 42 may include a flow regulator to allow
selective opening and closing thereof.
[0111] In one embodiment, casing flow regulators 23 function as
both hydraulic fracture diversion valves and as injection flow
regulators (as described above) or production flow regulators (as
described above). Each casing flow regulator may be remotely and/or
independently operated. Each casing flow regulator has an open
position and a closed position, and the open position may include
one or more partially open positions (e.g. screened, choked, etc.).
In the open position, the casing flow regulator 23 is in
communication with the horizontal section of the wellbore through
an opening in casing 14. In the closed position, casing flow
regulator 23 blocks fluid flow therethrough. Each casing flow
regulator 23 therefore allows fluid communication between the
fracture(s) connected thereto and the wellbore, when the casing
flow regulator is in an open position.
[0112] Accordingly, when any one of the casing flow regulators 23
is open and when the opening 42 in the conduit 19 is open, conduit
19 is in fluid communication via the wellbore with the fracture(s)
connected to the open casing flow regulator(s).
[0113] In operation, the system in the sample embodiment shown in
FIG. 8 allows asynchronous injection into and production from a
well using only one conduit. For example, injection fluid is pumped
down conduit 19 and flows through opening 42 into the wellbore.
Some of the casing flow regulators 23 are then opened, while others
are kept closed, so that the injection fluid in the wellbore can
flow through the open casing flow regulators into the fractures
connected thereto.
[0114] Once the desired amount of injection fluid has been injected
into the wellbore, the pumping of injection fluid down conduit 19
is stopped. In one embodiment, the open casing flow regulators 23
are closed and the casing flow regulators that were closed during
the injection of injection fluid are then opened to allow reservoir
fluid to flow therethrough, from the fractures connected to the
casing flow regulators into the wellbore. In another embodiment,
one or more of the previously opened flow regulators may be left
open and one or more of the previously closed flow regulators may
be opened or left closed. If the opening 42 in conduit 19 is open,
reservoir fluid in the wellbore can flow through the opening 42 and
be collected in conduit 19 for transportation to surface.
[0115] Referring to FIG. 9, a sample embodiment is shown wherein
one conduit 19' is provided for transporting both injection fluid
and reservoir fluid therein. Therefore, in this embodiment, the
injection conduit and the production conduit are one and the same.
This embodiment is usable with a cased well having a casing 14
which is cemented to wellbore wall 10 in at least the horizontal
section. Here, the wellbore inner surface 11 is the inner surface
of casing 14. Conduit 19' extends down the well through the heel
and into at least a portion of the horizontal section.
[0116] Further, instead of injection flow regulators and production
flow regulators, a plurality of flow regulators 44 are provided in
conduit 19, intermittently positioned along the length of the
conduit. Flow regulators 44 function as injection flow regulators
(as described above) and/or production flow regulators (as
described above). Each flow regulator 44 may be remotely and/or
independently operated. Each flow regulator 44 has an open position
and a closed position, and the open position may include one or
more partially open positions (e.g. screened, choked, etc.). In the
open position, the flow regulator 44 allows fluid to flow
therethrough into or out of conduit 19. In the closed position, the
flow regulator 44 blocks fluid flow therethrough.
[0117] Conduit 19' extends axially along the horizontal section of
the wellbore defined by wellbore inner surface 11. Packers 16 are
intermittently positioned on the outer surface and along the length
of the conduit 19'. Preferably, Packers 16 are positioned on
conduit 19' such that at least one flow regulator 44 is situated in
between each pair of adjacent packers 16. Further, adjacent packers
16 are positioned and expanded (i.e. installed) relative to the
perforations 13 in casing 14 in the horizontal section such that at
least one perforation 13 is situated in between at least a pair of
adjacent packers 16. In this manner, packers 16 are provided and
positioned in the horizontal section of the well to fluidly seal
the annulus between the wellbore inner surface and conduit 19 to
define zones, as discussed above. The zones are fluidly sealed from
one another inside the horizontal section but can fluidly
communicate with one another via the conduit 19'.
[0118] In this embodiment, each zone is in communication with at
least one fracture, via at least one perforation 13, and is
communicable with conduit 19 via at least one flow regulator 44.
The flow regulator 44 in each zone therefore allows fluid
communication between the fracture(s) connected to the zone and
conduit 19', when the flow regulator 44 is in an open position. In
the closed position, flow regulator 44 blocks fluid communication
between the fracture(s) connected to the zone and the conduit 19'.
One zone can fluidly communicate with another zone if the flow
regulators 44 in the zones are open.
[0119] In operation, the system in the sample embodiment shown in
FIG. 9 allows asynchronous injection into and production from a
well using only one conduit. For example, injection fluid is pumped
down conduit 19' and one or more of the flow regulators 44 are then
opened so that the injection fluid can flow out of the open flow
regulators through the zones in which the open flow regulators are
situated and into the fractures connected those zones.
[0120] Once the desired amount of injection fluid has been injected
into the formation, the pumping of injection fluid down conduit 19'
is stopped. In one embodiment, the open flow regulators are closed
and the flow regulators that were closed during the injection
process are opened. Alternatively, some of the open flow regulators
may be left open and one or more of the previously closed flow
regulators may be opened or left closed. Any reservoir fluid from
the formation flowing into the zones through the fractures is
collected in the conduit 19' via the open flow regulators 44. The
collected reservoir fluid in conduit 19' is then transported to
surface, as discussed above.
[0121] The system of the present invention may employ
instrumentation to help monitor the injection and/or production
zone environment, which allows specific controls to be applied in
order to manage the above-described injection-production method.
The instrumentation may include for example measurement devices for
monitoring fluid properties and pressure or temperature conditions
at each production or injection zone. The instrumentation may also
be used to monitor the health of the system including for example,
whether packers are sealing properly, whether the casing cement is
isolating annular injection flow into the fractures or is allowing
short-circuiting such as through an annulus cement channel between
an injection zone and an adjacent production zone, and to help
identify the location of a leak in a flow conduit or an improperly
functioning flow regulator.
[0122] In one embodiment, a device for monitoring the concentration
of the injection fluid in the petroleum being produced in the
wellbore is installed adjacent to the fractures in one or more of
the production zones. Examples of such measurement and monitoring
devices include for example fluid flow meters, electric resistivity
devices, oxygen decay monitoring devices, fluid density monitoring
devices, pressure gauge devices, and temperature monitoring devices
that obtain measurements at discrete locations, or distributed
measurement devices such as fiber optic sensors to measure
distributed temperature, distributed acoustic soundfield, chemical
composition, pressure, etc. Data from these devices can be obtained
through electric lines, fiber-optic cables, retrieval of bottom
hole sensors, in well interrogation of the devices using induction
coupling or other methods common in the industry.
[0123] In another embodiment, a sampling line is installed into the
production conduit. The sampling line may be a tubing (coiled or
jointed) that takes a sample of the fluid in one or more production
zones. In yet another embodiment, a sampling chamber is formed in
one or more production zones so that discrete samples of fluid can
be taken.
[0124] With the above-described devices and monitoring techniques,
the proportion of injection fluid in reservoir petroleum can be
estimated or measured for any particular production zone to help
with determining, for example: (i) when to stop injecting fluid
into the well; (ii) when to stop injecting fluid into one or more
zones of the well; and/or (iii) when to stop producing one or more
zones of the well.
[0125] The system may also be in communication with well logging
devices, and seismic or active sonar imaging devices for measuring
the progress of sweeping by, for example, fiber optic acoustic
detection of the echo produced by a sound pulse originating at the
wellbore and analysis of the returned echo waveform properties to
infer distance to reservoir boundaries or heterogeneities including
natural or hydraulic fractures or the general fluid composition in
the reservoir through which the sound pulse traveled.
[0126] Instrumentation that may be used with the system includes
for example, fiber optic distributed temperature sensors (DTS),
fiber optic distributed acoustic sensors (DAS), fiber optic
distributed pressure sensors (DPS), fiber optic distributed
chemical sensors (DCS), and permanent downhole gauges (PDGs).
[0127] A DTS may be used with the system to measure the temperature
inside or outside the casing string at along its length in real
time. Additionally or alternatively, a DAS may be used to measure
the sound environment inside the horizontal wellbore section along
its length in real time. Additionally or alternatively, a DPS may
be used to measure the pressure inside the horizontal wellbore
section continuously or pseudo-continuously at a multitude of
discrete points along its length in real time. In a sample
embodiment, both DTS and DAS are housed together in a separate
stainless steel control line running substantially the full length
of the production conduit.
[0128] In a further embodiment, PDGs are used at each injection
and/or production zone to electronically measure the pressure and
temperature therein, and an electric cable is used to provide power
to each gauge and/or to transmit signal data to the surface. In a
sample embodiment, the PDGs are fiber optic devices which optically
measure both temperature and pressure at discrete points within the
well and may use an optic fiber to optically convey the measurement
signal to surface. A single cable may be used for each gauge or for
a plurality of gauges.
[0129] Downhole separation of gas from the produced petroleum may
be accomplished using a downhole separator to separate the gas from
the produced petroleum in the production conduit. The separator may
be, for example, a cyclone-type or hydrocyclone-type separator. The
separation may be followed by compression of the collected gas to
the pressure of the injection fluid in the injection conduit, and
the compression may be achieved by a centrifugal compressor or a
reciprocating compressor. The compressed collected gas may be
supplied to the injection conduit as injection fluid. The separator
may include an electric submersible or progressing cavity pump,
which may be used to impart energy into the produced fluid to help
lift the fluid to surface.
[0130] Referring to the sample embodiments shown in FIGS. 6 and 8,
measurement and control system instrumentation including for
example pressure gauges, fiber optic sensors, and hydraulic and
electric control lines 39, etc. may be installed outside casing 14
(i.e. between wellbore inner surface 11 and wellbore wall 10).
Alternatively or additionally, the flow regulators 23 may be
controlled with radio-frequency identification (RFID).
Alternatively or additionally, measurement system components
including gauges and fiber optic sensors may be installed on or
near the outer surface of the production conduit 20. The placement
of the casing flow regulators and/or instrumentation outside the
casing may help reduce the complexity of the required downhole
tubing equipment for the conduits.
[0131] With respect to the above-described injection-production
system, there is provided a method of enhancing petroleum
production from a well having a well section with a wellbore inner
surface in communication with a plurality of fractures in a
formation containing reservoir fluid, the method comprising:
creating a first set and a second set of zones in the well section,
each zone for communicating with at least one of the plurality of
fractures, and the first set of zones being fluidly sealed from the
second set of zones in the well section; and selectively injecting
injection fluid into the formation via at least one zone in the
first set of zones. The method further comprises selectively
collecting reservoir fluid from the formation via at least one zone
in the second set of zones; and transporting the collected
reservoir fluid to surface.
[0132] At least some of the fractures associated with the first set
of zones are in direct or indirect fluid communication with at
least some of the fractures associated with the second set of
zones. The fractures communicable with the first set of zones are
not necessarily distinct from the fractures communicable with the
second set. Also, the zones in the first set are not necessarily
distinct from the zones in the second set. There may be overlaps in
the two sets of zones, such that any one zone can be in both the
first set and the second set. In other words, any one zone of
either set may function as one or both of an injection zone and a
production zone. Further, each set of zones may contain one or more
zones.
[0133] In one embodiment, the method comprises: running a
production conduit and an injection conduit down the well, the
production conduit or the injection conduit having installed
thereon packers in the retracted position; expanding the packers to
engage the wellbore inner surface to fluidly seal the annulus
between the outer surface of the conduits and the wellbore inner
surface to define at least one injection zone between a pair of
adjacent packers and at least one production zone between another
pair of adjacent packers. The at least one injection zone is in
communication with at least one fracture and the at least one
production zone is also in communication with at least one
fracture.
[0134] The method further comprises supplying injection fluid to
the injection conduit. The injection fluid may be supplied from a
supply source at surface. Alternatively or additionally, injection
fluid may be recovered and separated from the produced fluids in
the production conduit, compressed, and then re-injected into the
injection conduit. In one embodiment, any or all of the recovering,
separating, compressing, and re-injecting of injection fluid may be
performed downhole.
[0135] The method further comprises selectively injecting injection
fluid into one of the at least one injection zone. In one
embodiment, the pressure at which injection fluid is injected into
the injection zones ranges between the minimum miscibility pressure
of the target reservoir fluid and the minimum hydraulic fracture
propagating pressure of the target reservoir formation. Minimum
miscibility pressure may be determined in a lab by re-pressurizing
a sample of the reservoir fluid. The sample is obtained and
analyzed using a specific process known as PVT testing. As the
injection fluid is pumped into the reservoir via the fractures in
the injection zones, a pressure gradient is created in the
reservoir between the injection and production zones, resulting in
flow in the direction of the pressure gradient from the injection
zones to the production zones. The flood of injection fluid into
the reservoir causes the pressure of the reservoir to rise to at
least above the minimum miscibility pressure of the petroleum in
the reservoir, thereby trapping otherwise free gas in solution,
which results in a higher relative permeability of the petroleum in
the formation. In one embodiment, a dissolvable injection fluid is
injected into the fractures to increase the mobility of the
reservoir petroleum in order to help improve the production rate.
Petroleum in the reservoir moves through the fractures and into the
production zones.
[0136] The method further comprises selectively collecting
reservoir fluid (including petroleum) from one of the at least one
production zone into the production conduit. The method may further
comprise transporting the reservoir fluid in the production conduit
to surface. As discussed above, the reservoir fluid may be
transported by pumping and/or gas lifting.
[0137] The selective injection of injection fluid may be
accomplished by opening or closing at least one injection flow
regulator of the injection conduit in the one of the at least one
injection zone. The selective collection of reservoir fluid may be
accomplished by opening or closing at least one production flow
regulator of the production conduit in the one of the at least one
production zone.
[0138] In one embodiment, the injection of injection fluid into the
at least one injection zone occurs substantially simultaneously as
the collection of reservoir fluid from the at least one production
zone. In another embodiment, the injection of injection fluid and
the collection of reservoir fluid occur asynchronously, such that
there is substantially no simultaneous flow in both conduits.
Injection fluid may be continuously, periodically, or sporadically
pumped into the reservoir via the injection zones.
[0139] The production zones may or may not all flow at the same
time. For example, one or more production zones may be selectively
shut off from collecting reservoir fluid temporarily or
permanently. As mentioned above, by shutting off one or more
production zones for a certain period of time, the injection fluid
is allowed to penetrate deeper into the reservoir which may help
increase petroleum production. In a further embodiment, selected
production zones may be shut off while the remaining production
zones are open and allowed to produce petroleum, and the pattern or
sequence of which production zones are opened or shut off at any
given time may be configured as required to optimize the
performance of the system.
[0140] In another embodiment, a method for enhancing petroleum
production from a well having a wellbore with a wellbore inner
surface, the wellbore communicable via the wellbore inner surface
with a first set and a second set of fractures in a formation
containing reservoir fluid, the method comprising: supplying
injection fluid to the wellbore via a conduit; injecting injection
fluid from the wellbore to the formation through the first set of
fractures, while blocking fluid flow to and from the second set of
fractures; ceasing the supply of injection fluid; blocking fluid
flow to and from the first set of fractures; permitting flow of
reservoir fluid from the formation through the second set of
fractures into the wellbore; and collecting reservoir fluid from
the wellbore via the conduit.
[0141] At least some of the fractures of the first set are in
direct or indirect fluid communication with at least some of the
fractures of the second set through the formation. The fractures in
the first set are not necessary distinct from the fractures in the
second set. There may be overlaps in the fractures of the two sets.
Also, each set of fractures contains one or more fractures.
[0142] Another method for producing petroleum involves using a
plurality of injection-production systems together to influence
inter-well reservoir regions to allow sweeping between fractures
that originate from different wellbores. For example, the
injection-production system may be used for separate wells with
alternating fracture positions, as illustrated in FIG. 7. A
fractured well 40a is near at least one other fractured well 40b.
Well 40b may be spaced apart from well 40a in any direction,
including for example lateral, diagonal, above, below, or a
combination thereof. The long axes of the wells may or may not be
parallel to each other, and may or may not share the same plane.
Each of the wells 40a and 40b has the above described
injection-production system installed therein.
[0143] Some of the fractures of well 40a may be in close proximity
to some of the fractures of well 40b and may extend between some of
the fractures of well 40b, and vice versa. Because of the proximity
of some of the fractures between the two wells, cross flows may
occur therebetween, as indicated by the arrows "C". More
specifically, for example, some of the injection fluid injected
into well 40b may flow out of the fractures toward the fractures of
well 40a, which may sweep petroleum in the reservoir to flow into
the production zones of well 40a. Similarly, some of the injection
fluid injected into well 40a may flow out of the fractures toward
the fractures of well 40b, which may sweep petroleum in the
reservoir to flow into the production zones of well 40b. These
cross flows C may enhance petroleum production by allowing more
extensive sweeping of the reservoir, which might not be possible
with only one fractured well.
[0144] In one embodiment, injection fluid is injected into both
wells 40a and 40b in order to produce reservoir petroleum from both
wells. In another embodiment, injection fluid is injected into only
one well and petroleum is produced from both wells. In yet another
embodiment, injection fluid is injected into only one well and
petroleum is produced from the other well. In a further embodiment,
the injection of injection fluid into the wells and/or the
production of petroleum from the wells may be selectively turned on
and off to alternate the pattern of injection and/or production
between the wells. Of course, other injection and/or production
patterns and sequences are also possible.
[0145] In addition, there may be more than two adjacent fractured
wells having the injection-production system, such that one well
may provide cross flows to one or more adjacent wells. The
plurality of wells may be oriented in many different directions
relative to one another and the injection and/or production
patterns and sequences of the plurality of wells can be selectively
modified and controlled, as described above with respect to wells
40a and 40b.
[0146] While the above description refers to wells with a
substantially horizontal section, the present invention may be
applied to vertical wells and/or deviated wells.
[0147] The above described intra-well enhanced recovery methods and
systems may have advantages over a conventional inter-well line
drive scheme. For example, the present invention may lead to rapid
response to fluid injection due to smaller spacing between
injection and production zones. In addition, the present invention
may allow simultaneous injection and production in the same
wellbore without the need of converting the entire wellbore for
only injection. Therefore, the present invention may lead to
greater hydrocarbon recovery due to a combination of high
microscopic sweep efficiency particularly with the injection of a
miscible solvent gas and high areal sweep efficiency of a line
drive pattern. Additional advantages may include pressure
maintenance to lessen reservoir pressure decline and resulting gas
lift of liquid hydrocarbon in the wellbore due to solvent gas
injection which typically commences after a short period of primary
recovery to allow for high initial production and better
injectivity with some reservoir pressure depletion.
[0148] The previous description of the disclosed embodiments is
provided to enable any person skilled in the art to make or use the
present invention. Various modifications to those embodiments will
be readily apparent to those skilled in the art, and the generic
principles defined herein may be applied to other embodiments
without departing from the spirit or scope of the invention. Thus,
the present invention is not intended to be limited to the
embodiments shown herein, but is to be accorded the full scope
consistent with the claims, wherein reference to an element in the
singular, such as by use of the article "a" or "an" is not intended
to mean "one and only one" unless specifically so stated, but
rather "one or more". All structural and functional equivalents to
the elements of the various embodiments described throughout the
disclosure that are known or later come to be known to those of
ordinary skill in the art are intended to be encompassed by the
elements of the claims. Moreover, nothing disclosed herein is
intended to be dedicated to the public regardless of whether such
disclosure is explicitly recited in the claims. For US patent
properties, it is noted that no claim element is to be construed
under the provisions of 35 USC 112, sixth paragraph, unless the
element is expressly recited using the phrase "means for" or "step
for".
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