CA2887292A1

CA2887292A1 - Processes for hydraulic fracturing

Info

Publication number: CA2887292A1
Application number: CA2887292A
Authority: CA
Inventors: James Frederick Pyecroft; Peter Chernik; Jurgen Lehmann; David MEEKS; Douglas Bearinger
Original assignee: Nexen Energy ULC
Current assignee: CNOOC Petroleum North America ULC
Priority date: 2015-04-02
Filing date: 2015-04-02
Publication date: 2016-10-02
Also published as: WO2016154732A1; US20160290112A1

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.

Description

PROCESSES FOR HYDRAULIC FRACTURING
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 DOCSTOR: 5149994 \ 1 1 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.
DOCSTOR: 5149994 \ 1 2 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

[0008] 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.

[0009] Embodiments will now be described, by way of example only, with reference to the attached figures, wherein:

[0010] Figure 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;

[0011] Figure 2 is a schematic illustration of the subterranean formation of Figure 1, with the cased wellbore having been perforated for effecting stimulation of a first zone;

[0012] Figure 3 is a schematic illustration of the subterranean formation of Figure 1, with the first zone having been fractured via the perforation illustrated in Figure 2;
DOCSTOR: 5149994 \ 1 3 ,

[0013] Figure 4 is a schematic illustration of the subterranean formation of Figure 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;

[0014] Figure 5 is a schematic illustration of the subterranean formation of Figure 1, with the second zone having been fractured via the perforation illustrated in Figure 4;

[0015] Figure 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;

[0016] Figure 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.

[0017] Figure 8 is a schematic illustration of the system illustrated in Figure 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

[0018] Figure 9 is a schematic illustration of the system illustrated in Figure 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

[0019] Figure 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.
DOCSTOR. 5149994 \ 1 4 ,

[0020] 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.

[0021] 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.

[0022] 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.

[0023] 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.

[0024] 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 DOCSTOR: 5149994 1 1 5 nitrogen and/or CO2, may also be added, to water or other liquid materials. In some embodiments, for example, the treatment fluid may also include proppant.

[0025]
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 Figure 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 Figure 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 Figure 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 Figure 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.

[0026]
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.
DOCSTOR: 5149994 \ 1 6 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.

[0027] 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.

[0028] 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 DOCSTOR: 5149994\1 7 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.

[0029] In some embodiments, for example, the perforating gun is deployed downhole via coiled tubing. hi some embodiments, for example, the perforating gun is deployed using a tractor.

[0030] 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.

[0031] 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.

[0032] 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.
DOCSTOR: 5149994\1 8 . .

[0033] 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.

[0034] 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).

[0035] 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.

[0036] 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.

[0037] Figure 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 DOCSTOR: 5149994\1 9 . .
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.

[0038] In this respect, and referring to Figure 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.

[0039] 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.

[0040] 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 Figure 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.

[0041] 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 DOCSTOR: 5149994\1 10 . =
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 Figure 9). In some embodiments, for example, the sealing, or substantial sealing, of fluid communication is effected by a mechanical diyerter, 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.

[0042] 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.

[0043] 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.

[0044] 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.

[0045] 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 DOCSTOR: 5149994\1 11 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.

[0046] 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.

[0047] 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.

[0048] 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.
DOCSTOR: 5149994 \ 1 12

[0049]
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).
[0031] 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.

[0050]
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.
DOCSTOR: 5149994\1 13

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. The process as claimed in claim 1, further comprising:
prior to the injecting fracturing fluid, via the wellbore fluid passage, to a first zone within the subterranean formation, effecting fluid communication, via the wellbore fluid passage, between the first zone and the treatment fluid source.

3. The process as claimed in claim 1 or 2, 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 any one of claims 1 to 3;
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.

6. The process as claimed in claim 5;
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.

7. The process as claimed in any one of claims 4 to 6, further comprising:
prior to the effecting fluid communication between the first zone and the treatment fluid source, deploying a perforating gun within the wellbore fluid passage; and prior to the effecting fluid communication between the second zone and the treatment fluid source, deploying a perforating gun within the wellbore fluid passage.

8. The process as claimed in claim 7;
wherein each one of the deploying a perforating gun, independently, is effected via wireline.

9. The process as claimed in claim 7 or 8;
wherein each one of the deploying a perforating gun, independently, includes pumping the perforating gun downhole with a fluid flow;
and wherein the second zone is disposed uphole relative to the first zone.

10. The process as claimed in any one of claims 1 to 9;

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. The process as claimed in claim 10;
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.

12. The process as claimed in claim 10 or 11;
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

13. The process as claimed in any one of claims I to 9;
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. The process as claimed in claim 13;
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.

15. The process as claimed in any one of claims 1 to 9;
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 any one of claims 1 to 9;
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. The process as claimed in claim 16;
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.

18. The process as claimed in claim 16 or 17;
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.

19. The process as claimed in any one of claims 16 to 18;
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.

20. The process as claimed in any one of claims 1 to 19;
wherein the minimum distance between the first and second zones is at least five (5) metres.

21. The process as claimed in any one of claims 1 to 20;
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 any one of claims 1 to 20;

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 any one of claims 1 to 23;
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. The process as claimed in claim 25;
wherein each one of the deploying a perforating gun, independently, includes deploying via wireline.

27. The process as claimed in claim 25 or 26;
wherein the second zone is disposed uphole relative to the first zone.

28. The process as claimed in any one of claims 25 to 27;
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 any one of claims 25 to 28;
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. The process as claimed in claim 29 or 30;
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

32. The process as claimed in any one of claims 25 to 28;

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. The process as claimed in claim 32;
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.

34. The process as claimed in any one of claims 25 to 28;
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 any one of claims 25 to 28;
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. The process as claimed in claim 35;
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.

37. The process as claimed in claim 35 or 36;

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.

38. The process as claimed in any one of claims 35 to 37;
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.

39. The process as claimed in any one of claims 25 to 38;
wherein the minimum distance between the first and second zones is at least five (5) metres.

40. The process as claimed in any one of claims 25 to 39;
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 any one of claims 25 to 39;
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 any one of claims 25 to 42;
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 or 45;
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. The process as claimed in claim 46;

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.

48. The process as claimed in claim 46 or 47;
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

49. The process as claimed in claim 44 or 45;
wherein a first interface is disposed between the uphole zone and the wellbore;
and wherein a second interface is disposed between the donwhole 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. The process as claimed in claim 49;
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.

51. The process as claimed in claim 44 or 45;
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 or 45;
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. The process as claimed in claim 52;
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.

54. The process as claimed in claim 52 or 53;
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.

55. The process as claimed in any one of claims 52 to 54;
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.

56. The process as claimed in any one of claims 44 to 55;
wherein the minimum distance between the uphole and downhole zones is at least five (5) metres.

57. The process as claimed in any one of claims 44 to 56;
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 any one of claims 44 to 56;
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 any one of claims 44 to 59;
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.