U.S. patent application number 14/677298 was filed with the patent office on 2016-10-06 for processes for hydraulic fracturing.
The applicant listed for this patent is NEXEN ENERGY ULC. Invention is credited to Peter CHERNIK, Jurgen LEHMANN, David MEEKS, James Frederick PYECROFT.
Application Number | 20160290112 14/677298 |
Document ID | / |
Family ID | 57003714 |
Filed Date | 2016-10-06 |
United States Patent
Application |
20160290112 |
Kind Code |
A1 |
PYECROFT; James Frederick ;
et al. |
October 6, 2016 |
PROCESSES FOR HYDRAULIC FRACTURING
Abstract
There is provided a process of stimulating a subterranean
formation via a wellbore fluid passage of a cased wellbore. The
process includes, with a perforating gun, perforating at least
casing to form at least one or more perforations effecting fluid
communication, via the wellbore fluid passage, between a first zone
of the subterranean formation and a treatment fluid source.
Treatment fluid is then injected via the wellbore fluid passage,
from the treatment fluid source to the first zone such that
fracturing of the first zone is effected. The injecting of the
treatment fluid is then suspended. A perforating gun is then
deployed within the wellbore fluid passage via wireline. The casing
is then perforated to form at least one or more perforations
effecting fluid communication, via the wellbore fluid passage,
between a second zone of the subterranean formation and the
treatment fluid source. While both of the first zone and the second
zone are disposed in fluid communication, via the wellbore fluid
passage, with the treatment fluid source, injecting treatment fluid
from the treatment fluid source and into the wellbore fluid passage
with effect that at least a fraction of the injected treatment
fluid is directed to the second zone such that fracturing of the
second zone is effected.
Inventors: |
PYECROFT; James Frederick;
(Canmore, CA) ; CHERNIK; Peter; (Calgary, CA)
; LEHMANN; Jurgen; (Calgary, CA) ; MEEKS;
David; (Cranbrook, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
NEXEN ENERGY ULC |
Calgary |
|
CA |
|
|
Family ID: |
57003714 |
Appl. No.: |
14/677298 |
Filed: |
April 2, 2015 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/14 20130101;
E21B 43/26 20130101; E21B 43/11 20130101; E21B 49/00 20130101; E21B
43/116 20130101 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 49/00 20060101 E21B049/00; E21B 43/116 20060101
E21B043/116; E21B 43/14 20060101 E21B043/14 |
Claims
1. A process of stimulating a subterranean formation via a wellbore
fluid passage of a wellbore, comprising; injecting treatment fluid,
via the wellbore fluid passage, from a treatment fluid source to a
first zone within the subterranean formation such that fracturing
of the first zone is effected; effecting fluid communication, via
the wellbore fluid passage, between a second zone within the
subterranean formation and the treatment fluid source; while both
of the first zone and the second zone are disposed in fluid
communication, via the wellbore fluid passage, with the treatment
fluid source, injecting treatment fluid from the treatment fluid
source and into the wellbore fluid passage with effect that at
least a fraction of the injected treatment fluid is directed to the
second zone such that fracturing of the second zone is
effected.
2. (canceled)
3. The process as claimed in claim 1, further comprising: prior to
the effecting fluid communication between a second zone within the
subterranean formation and the treatment fluid source, suspending
the injecting of the treatment fluid.
4. The process as claimed in claim 1; wherein the wellbore is at
least partially cased with casing, and the wellbore fluid passage
is defined within the casing; and wherein each one of: (i) the
effecting fluid communication between the first zone and the
treatment fluid source, and (ii) the effecting fluid communication
between the second zone and the treatment fluid source,
independently, includes perforating at least the casing to effect
fluid communication with the wellbore fluid passage.
5. The process as claimed in claim 4; wherein the perforating of
the casing that effects the fluid communication between the first
zone and the wellbore fluid passage is with effect that one or more
first zone perforations are created; and wherein the perforating of
the casing that effects the fluid communication between the second
zone and the wellbore fluid passage is with effect that one or more
second zone perforations are created; and wherein the minimum
distance between the set of one or more first zone perforations and
the set of one or more second zone perforations is at least five
(5) metres.
6. (canceled)
7. (canceled)
8. (canceled)
9. (canceled)
10. The process as claimed in claim 1; wherein a first interface is
disposed between the first zone and the wellbore; and wherein a
second interface is disposed between the second zone and the
wellbore; and wherein the lithology of the first zone at the first
interface is the same, or substantially the same, as the lithology
of the second zone at the second interface.
11. (canceled)
12. (canceled)
13. The process as claimed in claim 1; wherein a first interface is
disposed between the first zone and the wellbore; and wherein a
second interface is disposed between the second zone and the
wellbore; and wherein the identifiable stratigraphy of the first
zone at the first interface is the same, or substantially the same,
as the identifiable stratigraphy of the second zone at the second
interface.
14. (canceled)
15. The process as claimed in claim 1; wherein a first interface is
disposed between the first zone and the wellbore; and wherein a
second interface is disposed between the second zone and the
wellbore; and wherein the stress magnitude of the first zone at the
first interface is the same, or substantially the same, as the
stress magnitude of the second zone at the second interface.
16. The process as claimed in claim 1; wherein a first interface is
disposed between the first zone and the wellbore; and wherein a
second interface is disposed between the second zone and the
wellbore; and wherein the depth of the first interface is within a
maximum distance of less than 50 metres of the depth of the second
interface.
17. (canceled)
18. (canceled)
19. (canceled)
20. The process as claimed in claim 1; wherein the minimum distance
between the first and second zones is at least five (5) metres.
21. The process as claimed in claim 1; wherein the supplying to the
second zone is induced at least by stress that is induced within
the formation by the injecting of the treatment fluid to the first
zone.
22. The process as claimed in claim 1; wherein the first and second
zones are disposed within a shale formation.
23. The process as claimed in claim 22; wherein the injecting of
treatment fluid to the second zone is induced at least by both of:
(i) stress that is induced within the formation by the injecting of
the treatment fluid to the first zone, and (ii) stress effected by
water imbibition into the one or more fractures effected within the
first zone.
24. The process as claimed in claim 1; wherein the first zone is
not mechanically isolated from the wellbore fluid passage while the
injecting of treatment fluid to the second zone via the wellbore
fluid passage is being effected.
25. A process of stimulating a subterranean formation via a
wellbore fluid passage of a cased wellbore, comprising; with a
perforating gun, perforating at least casing to form at least one
or more perforations effecting fluid communication, via the
wellbore fluid passage, between a first zone of the subterranean
formation and a treatment fluid source; injecting treatment fluid,
via the wellbore fluid passage, from the treatment fluid source to
the first zone such that fracturing of the first zone is effected;
suspending the injecting of the treatment fluid; deploying a
perforating gun within the wellbore fluid passage; perforating at
least casing to form at least one or more perforations effecting
fluid communication, via the wellbore fluid passage, between a
second zone of the subterranean formation and the treatment fluid
source; while both of the first zone and the second zone are
disposed in fluid communication, via the wellbore fluid passage,
with the treatment fluid source, injecting treatment fluid from the
treatment fluid source and into the wellbore fluid passage with
effect that at least a fraction of the injected treatment fluid is
directed to the second zone such that fracturing of the second zone
is effected.
26. (canceled)
27. The process as claimed in claim 25; wherein the second zone is
disposed uphole relative to the first zone.
28. The process as claimed in claim 25; wherein the minimum
distance between the set of one or more first zone perforations and
the set of one or more second zone perforations is at least five
(5) metres.
29. The process as claimed in claim 25; wherein a first interface
is disposed between the first zone and the wellbore; and wherein a
second interface is disposed between the second zone and the
wellbore; and wherein the lithology of the first zone at the first
interface is the same, or substantially the same, as the lithology
of the second zone at the second interface.
30. The process as claimed in claim 29; wherein the identifiable
stratigraphy of the first zone at the first interface is the same,
or substantially the same, as the identifiable stratigraphy of the
second zone at the second interface.
31. (canceled)
32. The process as claimed in claim 25; wherein a first interface
is disposed between the first zone and the wellbore; and wherein a
second interface is disposed between the second zone and the
wellbore; and wherein the identifiable stratigraphy of the first
zone at the first interface is the same, or substantially the same,
as the identifiable stratigraphy of the second zone at the second
interface.
33. (canceled)
34. The process as claimed in claim 25; wherein a first interface
is disposed between the first zone and the wellbore; and wherein a
second interface is disposed between the second zone and the
wellbore; and wherein the stress magnitude of the first zone at the
first interface is the same, or substantially the same, as the
stress magnitude of the second zone at the second interface.
35. The process as claimed in claim 25; wherein a first interface
is disposed between the first zone and the wellbore; and wherein a
second interface is disposed between the second zone and the
wellbore; and wherein the depth of the first interface is within a
maximum distance of less than 50 metres of the depth of the second
interface.
36. (canceled)
37. (canceled)
38. (canceled)
39. The process as claimed in claim 25; wherein the minimum
distance between the first and second zones is at least five (5)
metres.
40. The process as claimed in claim 25; wherein the supplying to
the second zone is induced at least by stress that is induced
within the formation by the injecting of the treatment fluid to the
first zone.
41. The process as claimed in claim 25; wherein the first and
second zones are disposed within a shale formation.
42. The process as claimed in claim 41; wherein the injecting of
treatment fluid to the second zone is induced at least by both of:
(i) stress that is induced within the formation by the injecting of
the treatment fluid to the first zone, and (ii) stress effected by
water imbibition into the one or more fractures effected within the
first zone.
43. The process as claimed in claim 25; wherein the first zone is
not mechanically isolated from the wellbore fluid passage while the
injecting of treatment fluid to the second zone via the wellbore
fluid passage is being effected.
44. A process of stimulating a subterranean formation including a
pre-existing cased wellbore having a fluid passage that is disposed
in fluid communication with uphole and downhole zones within the
subterranean formation, wherein, for each one of the zones, one or
more openings or ports extend through the casing for effecting
fluid communication with the zone, the process comprising: sealing,
or substantially sealing fluid communication, via the wellbore
fluid passage, between a source of treatment fluid and the downhole
zone; after the fluid communication, via the wellbore fluid
passage, between the source of treatment fluid and the downhole
zone is sealed or substantially sealed, injecting treatment fluid,
via the wellbore fluid passage, from the source to the uphole zone;
suspending the injection of the treatment fluid; unsealing fluid
communication between the source and the downhole zone; and after
the unsealing of the fluid communication, and while both of the
uphole and downhole zones are disposed in fluid communication with
the source via the wellbore fluid passage, injecting treatment
fluid from the source and into the wellbore fluid passage with
effect that at least a fraction of the injected treatment fluid is
directed to the downhole zone such that fracturing of the downhole
zone is effected.
45. The process as claimed in claim 44; wherein at least the uphole
zone has been previously fracced.
46. The process as claimed in claim 44; wherein a first interface
is disposed between the uphole zone and the wellbore; and wherein a
second interface is disposed between the downhole zone and the
wellbore; and wherein the lithology of the uphole zone at the first
interface is the same, or substantially the same, as the lithology
of the downhole zone at the second interface.
47. (canceled)
48. (canceled)
49. The process as claimed in claim 44; wherein a first interface
is disposed between the uphole zone and the wellbore; and wherein a
second interface is disposed between the downhole zone and the
wellbore; and wherein the identifiable stratigraphy of the uphole
zone at the first interface is the same, or substantially the same,
as the identifiable stratigraphy of the downhole zone at the second
interface.
50. (canceled)
51. The process as claimed in claim 44; wherein a first interface
is disposed between the uphole zone and the wellbore; and wherein a
second interface is disposed between the downhole zone and the
wellbore; and wherein the stress magnitude of the uphole zone at
the first interface is the same, or substantially the same, as the
stress magnitude of the downhole zone at the second interface.
52. The process as claimed in claim 44; wherein a first interface
is disposed between the uphole zone and the wellbore; and wherein a
second interface is disposed between the downhole zone and the
wellbore; and wherein the depth of the first interface is within a
maximum distance of less than 50 metres of the depth of the second
interface.
53. (canceled)
54. (canceled)
55. (canceled)
56. The process as claimed in claim 44; wherein the minimum
distance between the uphole and downhole zones is at least five (5)
metres.
57. The process as claimed in claim 44; wherein the supplying to
the downhole zone is induced at least by stress that is induced
within the formation by the injecting of the treatment fluid to the
uphole zone.
58. The process as claimed in claim 44; wherein the uphole and
downhole zones are disposed within a shale formation.
59. The process as claimed in claim 58; wherein the injecting of
treatment fluid to the downhole zone is induced at least by both
of: (i) stress that is induced within the formation by the
injecting of the treatment fluid to the uphole zone, and (ii)
stress effected by water imbibition into the one or more fractures
effected within the uphole zone.
60. The process as claimed in claim 44; wherein the uphole zone is
not mechanically isolated from the wellbore fluid passage while the
injecting of treatment fluid to the downhole zone via the wellbore
fluid passage is being effected.
Description
FIELD
[0001] The present disclosure relates to processes for hydraulic
fracturing of wellbores to stimulate hydrocarbon production.
BACKGROUND
[0002] In order to produce hydrocarbons from within a subterranean
formation, a wellbore is drilled, penetrating the subterranean
formation. This provides a partial flow path for hydrocarbon,
received by the wellbore, to be conducted to the surface. In order
to be received by the wellbore at a sufficiently desirable rate,
there must exist a sufficiently unimpeded flow path from the
hydrocarbon-bearing formation to the wellbore through which the
hydrocarbon may be conducted to the wellbore.
[0003] In some cases, in order to establish the flow path for
conducting the hydrocarbon to the wellbore, it is necessary to
create new fractures or extend existing fractures within the
subterranean formation. Such fractures are more permeable to the
flow of hydrocarbons than the formation.
[0004] To initiate new fractures, and/or extend and interconnect
existing fractures, hydraulic fracturing fluid is injected through
wellbore into the subterranean formation at sufficient rates and
pressures for the purpose of hydrocarbon production stimulation.
The fracturing fluid injection rate exceeds the filtration rate
into the formation producing increasing hydraulic pressure at the
sand face. When the pressure exceeds a critical value, the
formation rock cracks and fractures. After this hydraulic
fracturing stage, proppant may be flowed downhole within the
wellbore and deposited in the fracture to prevent the fracture from
closing once the fluid injection is suspended, thereby helping to
preserve the integrity of the flow path.
[0005] In multistage horizontal well fracturing, multiple treatment
intervals or zones of the subterranean formation are fractured
independently. In order to direct the hydraulic fracturing fluid to
the desired zone, other zones are typically isolated from the zone
being fractured using mechanical diversion means, such as packers,
bridge plugs, multi-stage ball and baffles, or ball sealers, to
prevent the injected hydraulic fracturing fluid from entering zones
other than the desired zone. These mechanical diversion means must
be removed and replaced, or removed and repositioned, as each
additional zone is hydraulically fractured. Amongst other things,
this adds expense and delays production.
SUMMARY
[0006] In one aspect, there is provided a process of stimulating a
subterranean formation via a wellbore fluid passage of a wellbore,
comprising; injecting treatment fluid, via the wellbore fluid
passage, from a treatment fluid source to a first zone within the
subterranean formation such that fracturing of the first zone is
effected; effecting fluid communication, via the wellbore fluid
passage, between a second zone within the subterranean formation
and the treatment fluid source; while both of the first zone and
the second zone are disposed in fluid communication, via the
wellbore fluid passage, with the treatment fluid source, injecting
treatment fluid from the treatment fluid source and into the
wellbore fluid passage with effect that at least a fraction of the
injected treatment fluid is directed to the second zone such that
fracturing of the second zone is effected.
[0007] In another aspect, there is provided a process of
stimulating a subterranean formation via a wellbore fluid passage
of a cased wellbore, comprising; with a perforating gun,
perforating at least casing to form at least one or more
perforations effecting fluid communication, via the wellbore fluid
passage, between a first zone of the subterranean formation and a
treatment fluid source; injecting treatment fluid, via the wellbore
fluid passage, from the treatment fluid source to the first zone
such that fracturing of the first zone is effected; suspending the
injecting of the treatment fluid; deploying a perforating gun
within the wellbore fluid passage; perforating at least casing to
form at least one or more perforations effecting fluid
communication, via the wellbore fluid passage, between a second
zone of the subterranean formation and the treatment fluid source;
while both of the first zone and the second zone are disposed in
fluid communication, via the wellbore fluid passage, with the
treatment fluid source, injecting treatment fluid from the
treatment fluid source and into the wellbore fluid passage with
effect that at least a fraction of the injected treatment fluid is
directed to the second zone such that fracturing of the second zone
is effected.
[0008] In another aspect, there is provided a process of
stimulating a subterranean formation including a pre-existing cased
wellbore having a fluid passage that is disposed in fluid
communication with uphole and downhole zones within the
subterranean formation, wherein, for each one of the zones, one or
more openings or ports extend through the casing for effecting
fluid communication with the zone, the process comprising: sealing,
or substantially sealing fluid communication, via the wellbore
fluid passage, between a source of treatment fluid and the downhole
zone; after the fluid communication, via the wellbore fluid
passage, between the source of treatment fluid and the downhole
zone is sealed or substantially sealed, injecting treatment fluid,
via the wellbore fluid passage, from the source to the uphole zone;
suspending the injection of the treatment fluid; unsealing fluid
communication between the source and the downhole zone; and after
the unsealing of the fluid communication, and while both of the
uphole and downhole zones are disposed in fluid communication with
the source via the wellbore fluid passage, injecting treatment
fluid from the source and into the wellbore fluid passage with
effect that at least a fraction of the injected treatment fluid is
directed to the downhole zone such that fracturing of the downhole
zone is effected.
BRIEF DESCRIPTION OF DRAWINGS
[0009] In the drawings, embodiments are illustrated by way of
example. It is to be expressly understood that the description and
drawings are only for the purpose of illustration and as an aid to
understanding, and are not intended as a definition of the limits
of the invention.
[0010] Embodiments will now be described, by way of example only,
with reference to the attached figures, wherein:
[0011] FIG. 1 is a schematic illustration of a subterranean
formation within which a cased wellbore is disposed for effecting
an embodiment of a process of the present disclosure;
[0012] FIG. 2 is a schematic illustration of the subterranean
formation of FIG. 1, with the cased wellbore having been perforated
for effecting stimulation of a first zone;
[0013] FIG. 3 is a schematic illustration of the subterranean
formation of FIG. 1, with the first zone having been fractured via
the perforation illustrated in FIG. 2;
[0014] FIG. 4 is a schematic illustration of the subterranean
formation of FIG. 1, with the cased wellbore having been
perforated, uphole of the first zone, for effecting stimulation of
a first zone, after fracturing of the first zone;
[0015] FIG. 5 is a schematic illustration of the subterranean
formation of FIG. 1, with the second zone having been fractured via
the perforation illustrated in FIG. 4;
[0016] FIG. 6 is a schematic illustration of a subterranean
formation within which a cased wellbore is disposed for effecting
another embodiment of a process of the present disclosure;
[0017] FIG. 7 is a schematic illustration of a subterranean
formation within which a cased wellbore is disposed, with a first
zone of the subterranean formation receiving injection of treatment
fluid through the cased wellbore, while the second zone is isolated
with a mechanical diverter.
[0018] FIG. 8 is a schematic illustration of the system illustrated
in FIG. 7, with the injection of treatment fluid having been
suspended, and with the mechanical diverter, effecting the
isolation of the second zone from the first zone, being removed;
and
[0019] FIG. 9 is a schematic illustration of the system illustrated
in FIG. 7, with a second zone of the subterranean formation
receiving injection of treatment fluid through the cased wellbore,
after the second zone has been isolated from a downhole zone by a
mechanical diverter, and while the first zone still remains
disposed in fluid communication with the wellbore.
DETAILED DESCRIPTION
[0020] FIG. 1 illustrates an exemplary wellbore installation. A
wellbore 10 penetrates a surface 80 of, and extends through, a
subterranean formation 12. The subterranean formation 12 may be
onshore or offshore. The subterranean formation 12 includes a
plurality of zones, such as zones 14, 16. The distance across which
a zone may span is determined by the anticipated effectiveness of a
frac (or stimulation) within such zone. Amongst other things, this
is dictated by the injection rate that is available from the
pump.
[0021] The wellbore 10 can be straight, curved, or branched. The
wellbore can have various wellbore portions. A wellbore portion is
an axial length of a wellbore. A wellbore portion can be
characterized as "vertical" or "horizontal" even though the actual
axial orientation can vary from true vertical or true horizontal,
and even though the axial path can tend to "corkscrew" or otherwise
vary. The term "horizontal", when used to describe a wellbore
portion, refers to a horizontal or highly deviated wellbore portion
as understood in the art, such as, for example, a wellbore portion
having a longitudinal axis that is between 70 and 110 degrees from
vertical.
[0022] The wellbore 10 may be cased, such as with casing 20 that is
disposed within the wellbore 10. The casing 20 includes a wellbore
fluid passage 23 configured to conduct fluids to and from the zones
14, 16 of the subterranean formation 12, as is explained below. In
some embodiments, for example, the casing 20 is cemented to
formation 12 with cement 22 disposed within the annular region
between the casing 20 and the formation 12.
[0023] A wellhead 50 is coupled to and substantially encloses the
wellbore 10 at the surface 2. The wellhead 50 includes conduits and
valves to direct and control the flow of fluids to and from the
wellbore 10.
[0024] To effect hydraulic fracturing of the subterranean formation
12, treatment fluid is injected into the wellbore 10 from the
source 40 of treatment fluid, and is conducted through the fluid
passage 23 defined within the casing 20. The conducted treatment
fluid is directed into the formation 12 through ports or openings
24 that penetrate through the casing 20 (and, in some embodiments,
for example, the cement 22) and into the formation, thereby
effecting fluid communication between the fluid passage 23 and the
formation 12.
[0025] In some embodiments, for example, the treatment fluid
includes hydraulic fracturing fluid. Suitable hydraulic fracturing
fluid includes water, water with various additives for friction
reduction and viscosity such as polyacrylamide, guar, derivitized
guar, xyanthan, and crosslinked polymers using various crosslinking
agents, such as borate, metal salts of titanium, antimony, alumina,
for viscosity improvements, as well as various hydrocarbon both
volatile and non-volatile, such as lease crude, diesel, liquid
propane, ethane and compressed natural gas, and natural gas
liquids. In some embodiments, for example, various compressed
gases, such as nitrogen and/or CO.sub.2, may also be added, to
water or other liquid materials. In some embodiments, for example,
the treatment fluid may also include proppant.
[0026] In one aspect, there is provided a process of stimulating
the subterranean formation 12 via a wellbore fluid passage (such
as, for example, fluid passage 23) of the wellbore 10. The process
includes effecting fluid communication, via the wellbore fluid
passage 23, between the first zone 12 and a source 40 of treatment
fluid (see FIG. 2). After the fluid communication has become
effected, and while the first zone 14 is disposed in fluid
communication with the source 40 via wellbore fluid passage 23,
treatment fluid is injected, via the wellbore fluid passage 23,
from the source 40 to the first zone 14 within the subterranean
formation 12 such that fracturing of the first zone 14 is effected
(see FIG. 3), resulting in the formation of fractures 32. The
pressure of the treatment fluid being injected to the second zone
16 exceeds the fracture initiation pressure within the first zone
14. The injecting of the treatment fluid is then suspended. After
suspending of injection of the treatment fluid, fluid
communication, via the wellbore fluid passage 23, between the
second zone 16 and the source 40 is effected (see FIG. 4). While
both of the first zone 14 and the second zone 16 are disposed in
fluid communication, via the wellbore fluid passage 23, with the
source 40, treatment fluid is injected from the source 40 and into
the wellbore fluid passage 23 with effect that at least a fraction
of the injected treatment fluid is injected into the second zone 16
such that fracturing of the second zone 16 is effected (see FIG.
5), resulting in the formation of fractures 34. The pressure of the
treatment fluid being injected to the second zone 16 exceeds the
fracture initiation pressure of the second zone 16. The first zone
14 is not mechanically isolated from the wellbore fluid passage 23
while treatment fluid is being injected to the second zone 16 via
the wellbore fluid passage 23.
[0027] By injecting treatment fluid to the first zone 14, and then,
after such treatment of the first zone 14, creating a flow path
between the second zone 16 and the wellbore fluid passage 23, it is
believed that the treatment fluid that has been injected into the
first zone 14 induces stress within the formation 12, and this
induced stress diverts treatment fluid, that is subsequently
injected through the wellbore fluid passage 23, to the second zone
16. This may eliminate the need to use plugs or other devices for
effecting isolation of the second zone 16 from the previously
treated first zone 14 while injecting treatment fluid for treating
the second zone 16. In doing so, in some embodiments, for example,
the need for coil tubing, for drilling out of conventional plugs,
may be eliminated, thereby permitting longer horizontal wells to be
fractured and completed. In this respect, in some embodiments, for
example, the cost, time and risk associated with setting and
drilling plugs may be mitigated or eliminated. In some embodiments,
for example, production may be improved by eliminating the damage
associated drill out fluid and drill cuttings losses associated
with removing drillable bridge plugs. In some embodiments, for
example, eliminating drill outs may also reduce near wellbore
damage to conductivity. In some embodiments, for example, avoiding
the drilling out of bridge plugs may improve productivity, as the
drilling out of bridge plugs involves the injection of fluid with
additives which could otherwise compromise productivity. As well,
in some embodiments, for example, avoiding the drilling out of
bridge plugs would also eliminate the introduction of drill
cuttings into the wellbore, which may otherwise cause the plugging
of perforations in the casing. In some embodiments, for example, by
avoiding the use of coiled tubing, longer laterals, extending
beyond the reach of coil tubing, may be completed. In some
embodiments, for example, completion issues, resulting from casing
deformation, may be avoided. In some embodiments, for example, an
additional monitoring tool may be provided in terms of observing
frac hits from offset wells. In some embodiments, for example, by
eliminating the use of bridge plugs, as a necessary incident, the
well may enjoy a larger inside diameters, thereby mitigating
restriction to post completion interventions such as production
logging and scale cleanouts. In some embodiments, for example, the
avoidance of bridge plugs shortens cycle times between completion
and production.
[0028] In some embodiments, for example, the effecting fluid
communication (as between one or both of: (a) the first zone 14 and
the source 40, and (b) the second zone 16 and the source 40)
includes effecting creation of one or more ports or openings 24
through the casing 20. In some embodiments, for example, the ports
or openings 24 are created by perforating through the casing 20 to
form perforations 24A, 24B. In some embodiments, for example, the
perforating is effected by a perforating gun.
[0029] In some embodiments, for example, the perforating gun is
deployed downhole via wireline, such as by, for example, being
pumped downhole with fluid flow. In this respect, when the port or
openings 24 are perforations created by a perforating gun deployed
downhole via wireline, such as by being pumped downhole with fluid
flow, in some embodiments, for example, the perforating gun is not
capable of being deployed downhole of the first zone, as the fluid
flow which is carrying the perforating gun becomes is conducted
into the first zone through the previously created ports or
openings 24 (such as, for example, perforations), and is
unavailable to assist in deploying the perforating gun further
downhole relative to the first zone 14 such that the next zone
(i.e. second zone 16) to be treated is one that is uphole relative
to the first zone 14.
[0030] In some embodiments, for example, the perforating gun is
deployed downhole via coiled tubing. In some embodiments, for
example, the perforating gun is deployed using a tractor.
[0031] In some embodiments, for example, the lithology of both the
first and second zones 14, 16 is the same or substantially the
same. In this respect, in some embodiments, for example, a first
interface 92 is disposed between the first zone 14 and the wellbore
10, and a second interface 94 is disposed between the second zone
16 and the wellbore 10, and the lithology of the first zone 14 at
the first interface 92 is the same, or substantially the same, as
the lithology of the second zone 16 at the second interface 94.
[0032] In some embodiments, for example, the identifiable
stratigraphy of both the first and second zones 14, 16 is the same
or substantially the same. In this respect, in some embodiments,
for example, a first interface 92 is disposed between the first
zone 14 and the wellbore 10, and a second interface 94 is disposed
between the second zone 16 and the wellbore 10, and the
identifiable stratigraphy of the first zone 14 at the first
interface 92 is the same, or substantially the same, as the
identifiable stratigraphy of the second zone 16 at the second
interface 94.
[0033] In some embodiments, for example, the stress magnitude of
both the first and second zones 14, 16 is the same or substantially
the same. In this respect, in some embodiments, for example, a
first interface 92 is disposed between the first zone 14 and the
wellbore 10, and a second interface 94 is disposed between the
second zone 16 and the wellbore 10, and the stress magnitude of the
first zone 14 at the first interface 92 is the same, or
substantially the same, as the stress magnitude of the second zone
16 at the second interface 94.
[0034] In some embodiments, for example, the first and second zones
14, 16 are disposed at the same or substantially the same depth. In
this respect, in some embodiments, for example, the depth of the
first interface 92 is within a maximum distance of less than 50
metres (such as, for example, less than 20 metres, such as, for
example, less than five (5) metres) of the depth of the second
interface 94.
[0035] In some embodiments, for example, the minimum distance
between the first and second zones 14, 16 is at least five (5)
metres (such as, for example at least 25 metres). In this respect,
in some embodiments, for example, the minimum distance between the
set of one or more first zone ports or openings 24 and the set of
one or more second zone ports or openings 24 is at least five (5)
metres (such as, for example, at least 25 metres).
[0036] In some embodiments, for example, the first and second zones
14, 16, respectively, are disposed within a shale formation. In
some of these embodiments, for example, the injection of treatment
fluid to the second zone 16 is induced at least by both of: (i)
stress that is induced within the formation by the injecting of the
treatment fluid to the first zone 14, and (ii) stress effected by
water imbibition into the one or more fractures effected within the
first zone 14.
[0037] In some embodiments, for example, once the desired number of
zones is fractured, the well is flowed back such that production of
hydrocarbons from the subterranean formation 12 may be
initiated.
[0038] FIG. 6 illustrates another exemplary wellbore installation
within a subterranean formation 12 includes a plurality of zones,
such as zones 114, 116, 118, in which, in another aspect, another
process is provided for stimulating the plurality of zones within
the subterranean formation 12 by supplying treatment fluid to the
zones via a wellbore fluid passage (such as, for example, fluid
passage 23) of the cased wellbore 10. For each one of the zones,
one or more openings or ports 26 extend through the casing 20 for
effecting fluid communication with the zone. In some embodiments,
for example, the zones may be ones which have not been previously
stimulated, such that the opening or ports 126 are newly created.
In some embodiments, for example, one or more of the zones may have
been previously treated such that the process is, in effect, a
re-stimulation or a "refrac". In any case, prior to the stimulation
by supplying treatment fluid to the zones, for each one of the
zones to be stimulated, corresponding openings or ports 126, for
effecting fluid communication between the wellbore fluid passage 24
and the zone, are already provided.
[0039] In this respect, and referring to FIG. 7, a process is
provided for implementation within a subterranean formation 12
including a pre-existing cased wellbore 10 having a fluid passage
that is disposed in fluid communication with a plurality of zones
(such as, for example, in the illustrated embodiments, zones 114,
116, and 118, within the subterranean formation 12). For each one
of the zones 114, 116, and 118, one or more openings or ports 126
extend through the casing 20 for effecting fluid communication with
the zone.
[0040] Sealing, or substantial sealing, of fluid communication, via
the wellbore fluid passage 23, between a source 40 of treatment
fluid and the second zone 116 is effected. The second zone 116 is a
downhole zone disposed downhole relative to the first zone 114. In
some embodiments, for example, the sealing, or substantial sealing,
of fluid communication is effected by a mechanical diverter, such
as a ball 128. The sealing or substantial sealing is necessary in
order to effectively inject sufficient treatment fluid to an uphole
zone, such as the zone 114.
[0041] After the fluid communication, via the wellbore fluid
passage 23, between the source 40 of treatment fluid and the second
zone 116 is sealed or substantially sealed, treatment fluid is then
injected via the wellbore fluid passage 23 to the first zone 114
such that fracturing of the first zone 114 is effected. Injecting
of the treatment fluid is then suspended, and the sealing, or
substantial sealing, of fluid communication, via the wellbore
passage 23, between the second zone 116 and the source 40, becomes
unsealed (see FIG. 8) such that the second zone 116 is disposed in
fluid communication with the source 40 via the wellbore fluid
passage 23. In those embodiments where the mechanical diverter is a
ball 128A, in some of these embodiments, for example, the unsealing
of fluid communication is effected by flowing the ball 128A back to
the surface 80. In some embodiments, for example, the ball 128A is
disintegratable under wellbore conditions such that, after a time
interval, the ball 128A disintegrates such that the unsealing of
fluid communication is thereby effected.
[0042] Prior to injecting of the treatment fluid into the wellbore
10, for effecting treatment of the second zone 116, sealing, or
substantial sealing, of fluid communication, via the wellbore fluid
passage 23, between a source 40 of treatment fluid and a zone
downhole of the second zone (such as, for example, a third zone
118) is effected (see FIG. 9). In some embodiments, for example,
the sealing, or substantial sealing, of fluid communication is
effected by a mechanical diverter, such as a ball 128B (which may
be characterized by a smaller diameter than ball 128A). The sealing
or substantial sealing is necessary in order to effectively inject
sufficient treatment fluid to the zone 116.
[0043] After the effecting of the sealing, or substantial sealing,
of fluid communication between the source 40 and the third zone
118, and while both of the first zone 114 and the second zone 116
are disposed in fluid communication with the source 40 via the
wellbore fluid passage 23, treatment fluid is injected into the
wellbore fluid passage 23 with effect that at least a fraction of
the injected treatment fluid is directed to the second zone 116
such that fracturing of the second zone 116 is effected.
[0044] By injecting treatment fluid to the first zone 114, and
then, after such treatment of the first zone 114, creating a flow
path between a downhole zone, such as the second zone 116, and the
wellbore fluid passage 23, it is believed that the treatment fluid
that has been injected into the first zone 14 induces stress within
the formation 12, and this induced stress diverts treatment fluid,
that is subsequently injected through the wellbore fluid passage
23, to the second zone 116.
[0045] The process may be repeated for the zone 118, as well as,
sequentially, for any number of zones disposed downhole of the
second zone 116. In this respect, the process may be implemented
for horizontal sections of deviated wellbores for stimulating a
formation 12 from heel to toe.
[0046] In some embodiments, for example, the lithology of the first
zone 114 is the same, or substantially the same, as the lithology
of the second zone 116, and is also the same, or substantially the
same, as the lithology of the third zone 118. In this respect, in
some embodiments, for example, a first interface 192 is disposed
between the first zone 14 and the wellbore 10, a second interface
194 is disposed between the second zone 16 and the wellbore 10, and
a third interface 196 is disposed between the third zone 118 and
the wellbore 10, and the lithology of the first zone 114 at the
first interface 192 is the same, or substantially the same, as the
lithology of the second zone 116 at the second interface 194, and
is also the same, or substantially the same, as the lithology of
the third zone 118 at the third interface 196.
[0047] In some embodiments, for example, the identifiable
stratigraphy of the first zone 114 is the same, or substantially
the same, as the identifiable stratigraphy of the second zone 116,
and is also the same, or substantially the same, as the
identifiable stratigraphy of the third zone 118. In this respect,
in some embodiments, for example, a first interface 192 is disposed
between the first zone 14 and the wellbore 10, a second interface
194 is disposed between the second zone 16 and the wellbore 10, and
a third interface 196 is disposed between the third zone 118 and
the wellbore 10, and the identifiable stratigraphy of the first
zone 114 at the first interface 192 is the same, or substantially
the same, as the identifiable stratigraphy of the second zone 116
at the second interface 194, and is also the same, or substantially
the same, as the identifiable stratigraphy of the third zone 118 at
the third interface 196.
[0048] In some embodiments, for example, the stress magnitude of
the first zone 114 is the same, or substantially the same, as the
stress magnitude of the second zone 116, and is also the same, or
substantially the same, as the stress magnitude of the third zone
118. In this respect, in some embodiments, for example, a first
interface 192 is disposed between the first zone 14 and the
wellbore 10, a second interface 194 is disposed between the second
zone 16 and the wellbore 10, and a third interface 196 is disposed
between the third zone 118 and the wellbore 10, and the stress
magnitude of the first zone 114 at the first interface 192 is the
same, or substantially the same, as the stress magnitude of the
second zone 116 at the second interface 194, and is also the same,
or substantially the same, as the stress magnitude of the third
zone 118 at the third interface 196.
[0049] In some embodiments, for example, the first, second and
third zones 114, 116, 118 are disposed at the same or substantially
the same depth. In this respect, in some embodiments, for example,
the depth of the first interface 192, the depth of the second
interface 194, and the depth of the third interface 196 are within
a maximum distance of less than 50 metres (such as, for example,
less than 20 metres, such as, for example, less than five (5)
metres) of each other.
[0050] In some embodiments, for example, the minimum distance
between the first and second zones 114, 116 is at least five (5)
metres (such as, for example at least 25 metres). In this respect,
in some embodiments, for example, the minimum distance between the
set of one or more first zone ports or openings 24 and the set of
one or more second zone ports or openings 24 is at least five (5)
metres (such as, for example, at least 25 metres). Similarly, the
minimum distance between the second and third zones 116, 118 is at
least five (5) metres (such as, for example at least 25 metres). In
this respect, in some embodiments, for example, the minimum
distance between the set of one or more second zone ports or
openings 24 and the set of one or more third zone ports or openings
24 is at least five (5) metres (such as, for example, at least 25
metres).
[0051] In some embodiments, for example, each one of the first,
second and third zones 114, 116, 118 is disposed within a shale
formation. In this respect, for example, the injection of treatment
fluid to the second zone 116 is induced at least by both of: (i)
stress that is induced within the formation by the injecting of the
treatment fluid to the first zone 114, and (ii) stress effected by
water imbibition into the one or more fractures effected within the
first zone 114.
[0052] In the above description, for purposes of explanation,
numerous details are set forth in order to provide a thorough
understanding of the present disclosure. However, it will be
apparent to one skilled in the art that these specific details are
not required in order to practice the present disclosure. Although
certain dimensions and materials are described for implementing the
disclosed example embodiments, other suitable dimensions and/or
materials may be used within the scope of this disclosure. All such
modifications and variations, including all suitable current and
future changes in technology, are believed to be within the sphere
and scope of the present disclosure. All references mentioned are
hereby incorporated by reference in their entirety.
* * * * *