IN SITU INJECTION OR PRODUCTION VIA A WELL USING DART-ACTUATED VALVE ASSEMBLIES AND RELATED SYSTEM AND METHOD

Abstract

An actuation dart for deployment down a tubing string installed within a wellbore and provided with one or more valve assemblies is provided. The actuation dart includes a dart body adapted to be carried down the tubing string to the valve assembly via fluid flow. The dart body has a shifting head provided at a first end of the dart body, the shifting head being configured to engage and shift the valve assembly in the open configuration to enable fluid injection in a reservoir surrounding the wellbore. A method for hydrocarbon recovery from a wellbore using the actuation dart is also provided, along with a wellbore system adapted to receive the actuation dart.

Description

TECHNICAL FIELD

The technical field generally relates to apparatuses, systems and methods for producing hydrocarbon material or other fluids from a subterranean formation.

BACKGROUND

Reservoirs can be difficult to characterize and it would be useful to provide some flexibility in the hardware used for injecting or producing fluids to optimize flow of material into and/or out of the reservoir. Although electrically-actuatable tools can be useful for optimization, such tools can also have challenges such as reliability due to unexpected loss of electrical communication with the surface. It can also be challenging to provide fluid flow into or out of different locations along a well in order to promote efficient hydrocarbon recovery operations. There are various challenges in terms of hydrocarbon recovery operations from reservoirs, for example reservoirs that have undergone fracturing operations.

SUMMARY

According to an aspect, there is provided a method for treating a hydrocarbon bearing reservoir. The method includes the steps of running a tubing string into an existing well previously operated for primary production to define an annulus between the tubing string and a wellbore, and defining a plurality of wellbore intervals isolated from one another along the well defined by isolation devices deployed in spaced-apart relation to each other within the annulus; for multiple wellbore intervals, installing a corresponding valve assembly along the tubing string, the valve assembly comprising at least one valve, each valve being operable in at least one of a closed configuration for preventing fluid flow into the surrounding reservoir and an open configuration for establishing fluid communication between the tubing string and the surrounding reservoir via respective fluid passages, the fluid passage of at least one valve being elongated and configured such that the open configuration of the corresponding valve is a flow restricted configuration where fluid flowrate from the tubing string into the reservoir is restricted; deploying an actuation dart within the tubing string; and injecting at least one fluid down the tubing string to carry the actuation dart along the tubing string via fluid flow so as to pass through the wellbore intervals and operate the valves in the open configuration for allowing the at least one fluid to flow along the fluid passage and enter the reservoir at the corresponding wellbore interval.

According to a possible implementation, each valve includes a corresponding valve housing provided with a valve sleeve slidably mounted therein, the valve housing comprising a fluid outlet communicating with the fluid passage of the valve for allowing injection fluid to flow from the tubing string to the surrounding reservoir.

According to a possible implementation, each valve sleeve is operable in a central position, an uphole position and a downhole position, the position of the valve sleeves within their respective valve housings corresponding to an operational configuration of the respective valves.

According to a possible implementation, each valve sleeve is initially in the central position when the valves are installed along the tubing string and while the tubing string is run into the wellbore, and wherein the actuation dart is configured to shift the valve sleeve downhole and into the open configuration.

According to a possible implementation, the valve sleeve includes a fluid passage inlet communicating with the fluid passage, and wherein the fluid passage is defined by a channel in an outer surface of the valve sleeve and an inner surface of the housing that overlays the channel.

According to a possible implementation, the injected fluid used to carry the actuation dart includes water, diesel, drilling mud, produced water, produced gas, methane, CO2, nitrogen or a combination thereof.

According to a possible implementation, the fluid used to carry the actuation dart is injected within the tubing string via a pump.

According to a possible implementation, the pump is located at surface.

According to a possible implementation, the pump is adapted to generate fluid flow between about 20 L/min and about 1200 L/min.

According to a possible implementation, the injected fluid is adapted to exert a pressure between about 20 psi and about 3000 psi on the actuation dart.

According to a possible implementation, the actuation dart comprises a dart head having an outer surface with a portion thereof being configured to engage a complementarily shaped portion of an inner surface of the valve sleeve and shift the valve sleeve in the open configuration.

According to a possible implementation, the injected fluid is adapted to exert a pressure between about 100 psi and 3000 psi on the valve sleeve via the actuation dart to shift the valve sleeve in the open configuration.

According to a possible implementation, the actuation dart comprises a dart tail connected to the dart head, the dart tail comprising an engagement surface for engaging an inner surface of the tubing string in order to guide the actuation dart as it is carried down the wellbore.

According to another aspect, there is provided an actuation dart for deployment down a tubing string installed within a wellbore and provided with one or more valve assemblies. The actuation dart includes a dart body adapted to be carried down the tubing string to the valve assembly via fluid flow, the dart body having a shifting head provided at a first end of the dart body, the shifting head being configured to engage and shift the valve assembly in an open configuration to enable fluid injection in a reservoir surrounding the wellbore.

According to a possible implementation, the shifting head comprises an abutment portion shaped and sized to engage a complementarily shaped portion of the valve assembly and shift the valve assembly in the open configuration.

According to a possible implementation, the abutment portion is configured to compress inwardly when engaged with the valve assembly via pressure exerted on the actuation dart via fluid flow, thereby enabling the actuation dart to disengage from the valve assembly and allow the actuation dart to flow further downhole along the tubing string.

According to a possible implementation, the dart body further comprises a dart tail connected to the shifting head, the dart tail comprising an engagement surface adapted to engage an inner surface of the tubing string in order to guide the actuation dart as it is carried down the wellbore.

According to a possible implementation, the dart body comprises a crossover segment extending between and connecting the dart tail and the shifting head together.

According to a possible implementation, the dart tail comprises a tubing cup connected to an uphole end of the crossover segment and having an uphole rim extending outwardly therefrom, and wherein the uphole rim includes the engagement surface for engaging the inner surface of the tubing string.

According to a possible implementation, the dart body comprises a plurality of tubing cups connected together in an end-to-end manner.

According to a possible implementation, the tubing cup comprises a cupped region extending generally transversely with respect to a passage of the tubing string, the cupped region being shaped and adapted to have fluid exert pressure thereon to push the actuation dart downhole.

According to a possible implementation, the uphole rim substantially surrounds the cupped region of the tubing cup.

According to another aspect, there is provided a well system. The well system includes a tubing string installed in a wellbore; a valve assembly provided along the tubing string, the valve assembly comprising at least one valve, each valve being operable in at least one of a closed configuration for preventing fluid flow into the surrounding reservoir and an open configuration for establishing fluid communication between the tubing string and the surrounding reservoir via respective fluid passages, the fluid passage of the at least one valve being elongated and configured such that the open configuration of the valve is a flow restricted configuration where fluid flowrate from the tubing string into the reservoir is restricted; an actuation device adapted for deployment down the tubing string via fluid flow for engaging the valve assembly and shifting each valve in the open configuration; and a pump for pumping fluid down the tubing string to carry the actuation device via fluid flow toward the valve assembly, the actuation device being configured to engage and shift each valve of the valve assembly subsequently.

According to a possible implementation, each valve comprises a corresponding valve housing provided with a valve sleeve slidably mounted therein, the valve housing comprising a fluid outlet communicating with the fluid passage of the valve for allowing injection fluid to flow from the tubing string to the surrounding reservoir.

According to a possible implementation, each valve sleeve is operable in a central position, an uphole position and a downhole position, the position of the valve sleeves within their respective valve housings corresponding to an operational configuration of the respective valves.

According to a possible implementation, each valve sleeve is initially in the central position when the valves are installed along the tubing string and while the tubing string is run into the wellbore, and wherein the actuation dart is configured to shift the valve sleeve downhole.

According to a possible implementation, the central position corresponds to a first open configuration of the valve assembly defining a first fluid flowrate through the fluid outlet, and wherein shifting the valve sleeve in the downhole position operates the valve assembly in a second open configuration defining a second fluid flowrate through the fluid outlet.

According to a possible implementation, the first fluid flowrate is greater than the second fluid flowrate.

According to a possible implementation, when in the first open configuration, the fluid outlet is provided with a breakable barrier adapted to occlude the fluid outlet and prevent fluid communication between the fluid passage and the surrounding reservoir

According to a possible implementation, the valve sleeve comprises a fluid passage inlet communicating with the fluid passage, and wherein the fluid passage is defined by a channel in an outer surface of the valve sleeve and an inner surface of the housing that overlays the channel.

According to a possible implementation, the pumped fluid used to carry the actuation dart includes water, diesel, drilling mud, produced water, produced gas, methane, CO2, or nitrogen or a combination thereof.

According to a possible implementation, the pump is located at surface.

According to a possible implementation, the pump is adapted to generate fluid flow between about 20 L/min and about 1200 L/min.

According to a possible implementation, the injected fluid is adapted to exert a pressure between about 20 psi and about 3000 psi on the actuation dart.

According to a possible implementation, the injected fluid is adapted to exert a pressure between about 100 psi and 3000 psi on the valve sleeve via the actuation dart to shift the valve sleeve in the open configuration.

According to a possible implementation, the actuation device comprises an actuation dart as defined in claims 14 to 22.

According to a possible implementation, the wellbore is provided in a geothermal reservoir, and wherein fluids are produced as part of geothermal operations.

According to another aspect, there is provided a method for injecting fluids into a reservoir via a well system as defined above. The method includes the steps of: deploying the actuation dart within the tubing string; pumping fluid within the tubing string for carrying the actuation dart toward the valve assembly via fluid flow; engaging the actuation dart with the valve assembly; and pumping additional fluid within the tubing string for exerting pressure on the actuation dart and shifting the valve assembly in the open configuration.

According to another aspect, there is provided a method for injecting fluids into a reservoir via a well system comprising a wellbore provided with a tubing string, the tubing string including one or more valve assemblies operable between a closed configuration for preventing fluid flow into the surrounding reservoir and an open configuration for establishing fluid communication between the tubing string and the surrounding reservoir via respective fluid passages, the fluid passage of at least one valve assembly being elongated and configured such that the open configuration of the corresponding valve is a flow restricted configuration where fluid flowrate from the tubing string into the reservoir is restricted, the method comprising the steps of: deploying an actuation dart within the tubing string; pumping fluid within the tubing string for carrying the actuation dart toward the valve assembly via fluid flow; engaging the actuation dart with the valve assembly; and pumping additional fluid within the tubing string for exerting pressure on the actuation dart and shifting the valve assembly in the open configuration.

According to a possible implementation, wherein the actuation dart is as defined above.

According to a possible implementation, the method further includes the step of monitoring a tubing string pressure to determine when a shifting pressure profile is recorded indicative of a shifted valve assembly in the open configuration.

According to a possible implementation, monitoring the tubing string pressure comprises recording pressure samples at a predetermined sample frequency to enable the collection of pressure data and the creation of a pressure graph.

According to a possible implementation, the creation of the pressure graph is facilitated by at least one of increasing the predetermined sample frequency at which the tubing string pressure is recorded, and lowering a rate at which fluids are pumped downhole.

According to a possible implementation, the predetermined sample frequency is between about 10 and 100 pressure samples per second.

According to a possible implementation, the method further includes the step of analyzing the pressure data and/or pressure graph to determine a number of times the shifting pressure profile is recorded, indicative of a number of shifted valve assemblies in the open configuration.

According to a possible implementation, the shifting pressure profile comprises a pressure build up to a shifting pressure threshold, followed by a pressure drop indicative of the actuation dart releasing from the valve assembly following a shift in the open configuration.

According to a possible implementation, the tubing string pressure is monitored using a pressure sensor located at surface.

According to a possible implementation, fluids are injected into the reservoir as part of a waterflooding operation.

According to a possible implementation, fluids are injected into the reservoir as part of a CO2 flooding operation.

According to a possible implementation, fluids are injected into and produced from the reservoir as part of acid solution mining operations.

According to another aspect, there is provided a method of injecting fluids into a reservoir via a well system comprising a wellbore provided with a tubing string. The tubing string includes one or more valve assemblies operable between a closed configuration for preventing fluid flow into the surrounding reservoir and an open configuration for establishing fluid communication between the tubing string and the surrounding reservoir via respective fluid passages. The method includes the steps of deploying an actuation dart within the tubing string; pumping fluid within the tubing string for carrying the actuation dart toward the valve assembly via fluid flow; engaging the actuation dart with a valve sleeve of the valve assembly; continuing pumping fluid to build tubing string pressure for exerting pressure on the actuation dart up to a shifting pressure threshold adapted to shift the valve sleeve for operating the valve assembly in the open configuration; monitoring the tubing string pressure to determine when the tubing string pressure reaches the shifting pressure threshold indicative of a shifted valve sleeve to operate the valve assembly in the open configuration; and pumping additional fluid in the tubing string for injection into the reservoir via the valve assembly.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic illustration of a well system including a pair of wells, according to an implementation.

FIG. 2 is a transverse cut view of a wellbore with a horizontal section extending in a reservoir.

FIG. 3 is a transverse cut view of a section of a well according to an implementation, showing a valve assembly installed therein.

FIG. 4 is a perspective view of an implementation of a valve assembly.

FIGS. 5 and 6 are sectional views of the implementation of the valve assembly shown in FIG. 4, illustrated in a first configuration (FIG. 5), and in a second configuration (FIG. 6).

FIG. 7 is a perspective view of another implementation of the valve assembly, showing a single housing outlet.

FIGS. 8 and 9 are sectional views of the implementation of the valve assembly shown in FIG. 7, illustrated in a first configuration (FIG. 8), and in a second configuration (FIG. 9).

FIG. 10 is a sectional view of another possible implementation of the valve assembly, showing different outlets provided on a valve sleeve.

FIG. 11 is a side view of an actuation device configured to engage a valve assembly, according to an implementation.

FIG. 12 is a perspective view of the actuation device shown in FIG. 11, showing a dart tail comprising a cupped region, according to an implementation.

FIG. 13 is a perspective exploded view of the actuation device shown in FIG. 11, showing a shifting head and the dart tail connectable to opposite ends of a crossover segment, according to an implementation.

FIG. 14 is an enlarged view of the dart tail shown in FIG. 13, showing the various components of the dart tail, according to an implementation.

FIG. 15 is a sectional view of the valve assembly shown in FIG. 10, showing the actuation device of FIG. 11 engaged therein, according to an implementation.

FIG. 16 is a side view of another possible implementation of the actuation device, showing a different dart tail configuration.

FIG. 17 is a perspective view of the actuation device shown in FIG. 16.

FIG. 18 is a perspective exploded view of the actuation device shown in FIG. 16, showing the various components of the dart tail, according to an implementation.

FIG. 19 is a graph representing tubing string pressure variations within a tubing string as the actuation device travels downhole.

DETAILED DESCRIPTION

As will be explained below in relation to various implementations, the present disclosure describes apparatuses, systems and methods for various operations, such as the recovery of hydrocarbon material from a subterranean formation are disclosed. The present disclosure describes an actuation device for a valve assembly, and to a method for recovering hydrocarbon from a reservoir using the actuated valve assembly. The method includes injecting fluid and the actuation device down a wellbore provided with one or more valve assemblies. The actuation device is shaped and configured to be carried down the wellbore by the fluid in order to engage and open the valve assembly for enabling fluid communication between the wellbore and the surrounding reservoir. As will be described further below, the fluid can be injected via a pump to generate and exert pressure on the actuation device to carry the actuation device downhole and facilitate operation of the valve assembly. In other words, the actuation device can be adapted to be pumped down the wellbore via fluid flow to operate the valve assembly to establish fluid communication with the reservoir.

The present disclosure also describes a valve assembly which can be adapted for downhole deployment within a wellbore extending into the hydrocarbon-containing reservoir, with the actuation device being deployed to operate the valve assembly. The valve assembly is shaped, sized and adapted to be integrated as part of a wellbore string and is operable between various configurations for allowing fluids to be injected within the reservoir, and fluids to be produced from the reservoir. In exemplary implementations, the actuation device is deployed downhole to operate the valve assembly from a closed configuration to an open configuration, and enable injection of fluid (e.g., a fluid for stimulating hydrocarbon production via a drive process, such as, for example, waterflooding, or via a cyclic process, such as “huff and puff”) into the subterranean formation, and/or production of reservoir fluids. The valve assembly is useable for conducting all forms of fluid, such as, for example, liquids, gases, or mixtures of liquids and gases.

It is noted that the valve assemblies can be implemented in various wellbores, formations, and applications including hydrocarbon recovery operations, for example. In some implementations, the wellbore can be straight, curved, or branched and can have various wellbore sections. A wellbore section is an axial length of a wellbore. A wellbore section 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 section, refers to a horizontal or highly deviated wellbore section as understood in the art, such as, for example, a wellbore section having a longitudinal axis that is between 70 and 110 degrees from vertical. It will be appreciated that the actuation device may be used to operate valve assemblies from various well assemblies, including vertical wells, horizontal wells, slanted wells and/or wells that have various structure features, such as casings and tubulars. For simplicity, it is noted that most of the conduits, channels, passageways, pipes, tubes and/or other similar components referred to in the present disclosure have a cross-section that is preferably circular or annular, although other shapes are also possible.

In some implementations, reservoir fluids are recovered from the reservoir by initially injecting a fluid (which can be referred to as a mobilizing fluid or an injection fluid) within the reservoir via a plurality of valve assemblies of a first well (e.g., injection well), which have been opened using the actuation device. In some applications, the injection fluid is adapted to mobilize hydrocarbons contained in the reservoir and drive the hydrocarbons towards a second well (e.g., production well) similarly provided with a plurality of valve assemblies adapted for fluid production for recovery of the hydrocarbons. In other applications, injection fluids can be injected into the reservoir as part of solution mining operations. In hydrocarbon recovery operations, the valve assemblies of the production well can be opened using the actuation device, and are adapted for receiving fluid that can include mobilized hydrocarbons from the reservoir and for producing the mobilized hydrocarbons to ultimately recover the hydrocarbons at surface. The actuation device can also be used to open valve assemblies used as part of geothermal applications.

With reference to FIGS. 1 and 2, a well system can include one or more wells 100, such as an injection well 120 and a production well 122, illustrated in FIG. 1, which extend from the surface 102 and into a wellbore 103 in a subterranean reservoir 101. In some implementations, for example, hydrocarbon production can be carried out via the well system, and, in this respect, to carry out the displacement process, fluid (e.g. water) is injected via the injection well 120, resulting in displacement of hydrocarbon material from the reservoir 101 and into the production well 120, and flow of the displaced hydrocarbon material to the surface 102 is carried out via the production well 120.

Now referring to FIGS. 3 to 5, in addition to FIGS. 1 and 2, in some implementations, one or more valve assemblies 400 can be integrated as part of a wellbore string 200 extending within the wellbore 103 of a given one of the wells 100. The wellbore string 200 defines a wellbore string passage 200A for conducting fluid between the surface 102 and the reservoir 101. More specifically, and as will be described below, the valve assemblies 400 can be provided with one or more ports at respective locations along the wellbore for establishing fluid communication between the wellbore string and the reservoir.

The valve assembly 400 includes a housing 402 having a tubular wall 403 defining a central passage 406 for enabling fluid communication through the housing 402. In other words, the central passage can act as a fluid passage 406 configured to allow a flow of fluid therethrough and along the wellbore string. The valve housing 402 has an uphole end and a downhole end adapted to be connected between lengths of conduits in order to integrate the valve assembly within the wellbore string. It is noted that the conduits are not illustrated in the figures, but would be located on either end of the valve assembly 400 and can be coupled to respective ends of the valve housing 402 by various methods. As previously described, the valve assembly 400 can be adapted to be integrated into the wellbore string 200, and, in this respect, the fluid passage 406 forms part of the wellbore string passage 200A.

The housing 402 also defines a housing outlet 404, through which fluid communication between the passage 406 and an environment external to the housing 402 (e.g., the reservoir 101) is established. In some implementations, the housing outlet 404 includes one or more ports 405 defined through the tubular wall 403 of the housing 402. For example, the implementation illustrated in FIG. 4 includes a plurality of ports 405 extending radially around the valve housing 402, whereas the implementation illustrated in FIG. 5 is provided with a single port 405. The ports 405 can be formed as generally circular openings through the valve housing 402, although it is appreciated that other configurations are possible. In some implementations, each valve assembly 400 is configurable in a plurality of operational configurations, and each one of the operational configurations, independently, corresponds to a state of fluid communication, via the ports 405, between the passage 406 and the surrounding reservoir. In other words, fluid flow through the housing outlet 404 can be at least partially controlled via a change in the operational configuration of the valve assembly 400 (e.g., a change from a first operational configuration to a second operational configuration).

In this implementation, the valve assembly 400 can be operated in a first operational configuration, such as a closed configuration, where the ports 405 are occluded, therefore preventing fluid flow between the fluid passage 406 and the reservoir. In addition, the valve assembly 400 can be operated from the closed configuration to the second operational configuration, such as an open configuration, where one ore more of the ports 405 is at least partially open, or fully open. It is appreciated that in the open configuration, the valve assembly 400 enables fluid to flow through the one or more injection ports 405 (e.g., into or from the reservoir).

Now referring to FIGS. 4 to 8, in addition to FIGS. 1 to 3, it is appreciated that the valve assembly 400 is configured for controlling fluid communication between the central passage 406 and the surrounding reservoir 101. In this implementation, the valve assembly 400 includes a valve sleeve 408 operatively mounted within the valve housing 402 for selectively closing and opening the housing outlet 404. The valve sleeve 408 can be slidably mounted within the housing 402 for moving axially therealong, e.g., along a longitudinal axis A (FIGS. 5 and 8). It should thus be understood that the valve sleeve 408 is adapted to be displaced along the passage 406 in various positions in order to direct fluid flow into predetermined fluid pathways of the valve assembly 400. In this implementation, the valve sleeve 408 is displaceable between a closed position (seen in FIG. 5) and an open position (seen in FIG. 6). The open position corresponds to the open configuration of the valve assembly 400, while the closed position corresponds to the closed configuration of the valve assembly 400.

The valve sleeve 408 can be mounted within the housing 402 in a manner allowing the sleeve to slide, or shift, from one position to another. It should be understood that the expression “shift” can refer to the displacement of the valve sleeve 408 using a shifting tool, for example, or a self-shifting mechanism provided as part of the valve assembly. The valve sleeve 408 can be held in place within the valve housing 402 using any suitable method or component, such as retaining rings (e.g., O-rings disposed about the valve sleeves), shear pins, a piston actuated mechanism or a combination thereof, for example.

In this implementation, the closed position of the valve sleeve 408 corresponds to an alignment of a portion of the valve sleeve 408 with the housing outlet 404 to occlude the housing outlet 404, thus preventing fluid flow between the passage 406 and the reservoir. As described above, the open configuration of the valve assembly 400 can be achieved by moving the valve sleeve 408 along the passage 406 so as to no longer occlude the housing outlet 404. In some implementations, the valve sleeve 408 can include one or more sleeve outlets 410 adapted to generally align with the housing outlet 404 to define a fluid flowpath between the fluid passage 406 and the reservoir. The housing 402 and the valve sleeve 408 can be cooperatively configured such that, while the sleeve outlets 410 are aligned with the housing outlet 404, fluid communication between the fluid passage 406 and the reservoir is established via the defined fluid flowpath. In some implementations, the fluid flowpath defined via the alignment of the sleeve outlets 410 has a predetermined resistance to material flow such that the flowrate of fluid through the housing outlet 404 is restricted. It is appreciated that the open configuration of the valve assembly 400 can be achieved by moving the valve sleeve 408 away from the housing outlet 404 so as to no longer occlude the outlet, or by aligning the sleeve outlets 410 with the housing outlet 404.

As described above, the open configuration of the valve assembly 400 can be achieved by moving the valve sleeve 408 along the passage within the housing 402 such that the sleeve outlet is aligned with the housing outlet 404, as seen in FIGS. 6, 8 and 9. In some implementations, the sleeve outlet 410 can include a fluid passage 414 allowing fluid flow therethrough. The housing 402 and the valve sleeve 408 can be cooperatively configured such that, while the fluid passage 414 is aligned with the housing outlet 404, fluid communication between the central passage 406 and the surrounding reservoir is established. In some implementations, the fluid passage 414 is shaped and configured to provide a resistance to fluid flow, therefore providing additional control on the flowrate of fluid being injected into the surrounding reservoir. For example, the fluid passage 414 can be elongated, tortuous and configured such that the open configuration of the valve assembly 400 corresponds to a flow restricted configuration where fluid flowrate from the tubing string into the reservoir is restricted. Furthermore, in this implementation, the fluid passage 414 includes a channel 414A defined in an outer surface of the valve sleeve 408 and covered by an inner surface of the valve housing 402 overlaying the channel 414A. It should be understood that the fluid flowrate through the housing outlet 404 is greater when the valve assembly is operated in the fully open configuration than when operated in the flow restricted configuration. For example, the fully open configuration can be useful for operating the valve assembly as a fill valve, such as those used in waterflood applications.

In some implementations, and with reference to FIGS. 8 to 9, the valve assembly 400 can be operated from a first open configuration (FIG. 8) to a second open configuration (FIG. 9) via movement of the valve sleeve 408. In this implementation, it is appreciated that the valve sleeve 408 can include a second sleeve outlet 416 adapted to be aligned with the housing outlet 404 to define a second fluid passage 418 between the fluid passage 406 and the reservoir 101. The housing 402 and the valve sleeve 408 can be cooperatively configured such that, while the second sleeve outlet 416 is aligned with the housing outlet 404, flow communication between the fluid conducting passage 406 and the environment external to the housing is established via the second fluid passage 418. In some implementations, the second fluid passage 418 has a predetermined resistance to material flow which is different from the resistance to material flow of the first fluid passage 414. For example, the resistance to material flow of the second fluid passage 418 can be lower than the resistance to material flow of the fluid passage 414, i.e., the flowrate of fluid through the second fluid passage 418 is greater than the flowrate of fluid through the fluid passage 414. Additionally, the second fluid passage 418 can include a second channel 418A defined in a similar fashion as the channel 414, i.e., defined in the outer surface of the valve sleeve 408, although other configurations are possible.

With reference to FIGS. 7 to 9, it is appreciated that the housing outlet 404 can be provided with a frangible, or breakable barrier 420 adapted to occlude the outlet and prevent fluid communication between the central passage 406 and the surrounding reservoir. The breakable barrier 420 can be configured to maintain the housing outlet 404 occluded when fluid pressure within the central passage 406 (or within the corresponding fluid passage 414, 418) is below a predetermined pressure threshold, such as below about 5000 psi, below about 3000 psi, or below about 500 psi.

The threshold can be defined based on other fluid pressures that may be used in the wellbore, such as a packer setting pressure. In this implementation, the breakable barrier 420 includes a burst disc 422 shaped and configured to cover or occlude the housing outlet 404, although other configurations are possible. The burst discs 422 are configured to rupture at about 3000 psi, whereas packers installed within the wellbore can be adapted to be hydraulically set (i.e., actuated) at lower pressures. As such, the packers are installed in the desired locations and hydraulically actuated prior to the burst discs rupturing and allowing fluid communication between the tubing string and the reservoir. For example, the packers can be configured to set in their respective positions at between about 1200 psi and 2500 psi such that the burst discs 422 of the initial valve assemblies 400 remain unruptured, therefore allowing fluid to flow downhole and set subsequent packers along the wellbore.

It is appreciated that if the valve sleeve 408 malfunctions, such as shifting prematurely into the open position, the breakable barrier 420 can prevent fluid from being injected into the reservoir. Once the predetermined pressure is reached, the breakable barrier 420 is defeated and collapses (e.g., bursts), thus enabling fluid communication between the passage 406 and the reservoir. The valve assembly 400 can include more than one breakable barrier 420, therefore reducing the risk of accidentally injecting fluid into the reservoir. The breakable barriers could thus be arranged in series within the housing outlet 404 (e.g., within each individual port 405).

Alternatively, or additionally, the breakable barrier 420 can include one or more plugs installed within respective ports 405 and retained therein using shear pins or any other similar and suitable device for retaining the plug in place. The breakable barrier 420 can alternatively include dissolvable components, such as a dissolvable plug, dissolvable retaining pins or rings, or a combination thereof. It is appreciated that the dissolvable components define a time-based mechanism and do not require predetermined pressures (e.g., via pump rates) to actuate the valves. Alternatively, the housing outlet 404 can be occluded using a piston-activated mechanism, such as a piston configured to be fluid-pressure activated (e.g., using differential pressure) to open the one or more ports 405. It is appreciated that each valve assembly 400 can be provided with the same type and design of breakable barrier 420, or with different types or designs of breakable barriers depending, for example, on the location of the valve assembly 400 along the wellbore. Each port 405 and barrier 420 can be identical for each valve assembly 400 provided along the well, or one or more of the ports and/or barriers can be different to provide a different function, such as rupturing at a different fluid pressure, being activated in a different manner, providing a different flow area, and so on.

With reference to FIG. 10, in some implementations, the valve assembly 400 can be run downhole (e.g., down the wellbore) as part of the wellbore string in a preliminary open configuration. The valve sleeve 408 can be provided with central valve outlets 418 adapted to be aligned with the housing outlet 404 when in the preliminary open configuration, and thus when the valve assembly 400 is run downhole. In this implementation, central valve outlets 418 enable fluid communication between the central passage 406 and the breakable barrier 420 for exerting pressure on the barrier. Therefore, fluid pressure can increase within the central passage 406 until the breakable barrier 420 breaks, opening the housing outlet 404. The central valve outlets 418 can be generally straight orifices designed to allow fluid to reach the breakable barrier 420. As such, once the housing outlet is open, fluid communication is established between the central passage 406 and the reservoir at a given fluid flowrate. The valve sleeve 408 can then be shifted downhole to align the fluid passage 414 with the housing outlet 404, and operating the valve assembly 400 in the flow restricted configuration to restrict fluid flowrate into the reservoir.

In some implementations, and as will be described further below, the displacement of the valve sleeve, relative to the housing, can be accomplished mechanically, for example, via an actuation device. In those implementations, the valve sleeve 408 is shaped and configured for mating with the actuation device. In some implementations, the valve sleeve 408 and actuation device can be provided with complementary profiles configured to engage one another for shifting the valve sleeve 408 in the open configuration. The actuation device can be deployed via the wellbore string 200 for disposition relative to the valve assemblies 400, such that the actuation device becomes disposed for shifting the valve sleeves 408. In some implementations, for example, deployment of the actuation device can be done via a conveyance system (e.g. workstring) that is run into the wellbore string 200. Suitable conveyance systems include a tubing string or wireline, for example, although other methods of conveyance are possible and may be used.

Alternatively, or additionally, the actuation device can be deployed and conveyed along the wellbore string via fluid flow. It should be understood that gravity can assist the flow of fluid in carrying the actuation device down the wellbore. It should be noted that the actuation device can be deployed using a combination of a mechanical conveyance system and fluid flow. For example, the actuation device can be deployed via workstring within the wellbore string at a predetermined location, then released from the workstring and carried downhole via fluid flow. In this implementation, the actuating device is inserted within the wellbore at the wellhead, and then simply pumped downhole via fluid flow.

Referring to FIGS. 11 to 18, different implementations of an actuation device 500 are illustrated and includes an actuation dart 510 for deployment down the wellbore. As previously mentioned, the actuation dart 510 is configured to be conveyed down a wellbore tubing string and carried along the tubing string until it reaches and engages a valve assembly. More specifically, in this implementation, the actuation dart 510 has a substantially elongated dart body 512 shaped and configured to be conveyed down a wellbore via fluid flow. The actuation dart 510 can thus be conveyed as a free unit that is not connected to a mechanical deployment structure, such as wireline or coiled tubing or the like.

Fluid can be injected into the wellbore string in order to carry the actuation dart 510 along the string in order to reach the valve assemblies 400 installed therealong. Various fluids can be used to carry the actuating dart 510 downhole, such as water, diesel, drilling mud, produced water, produced gas, methane, CO2, nitrogen, any derivative or combination thereof. The fluid can also be in liquid form (e.g., liquid water) or in vapour form (e.g., steam), or a combination thereof. In some implementations, and as illustrated in FIG. 2, the wellbore system can be provided with a pump 105 configured to effectively inject fluid into the wellbore at a desired flowrate to carry the actuation dart 510. It should be understood that the pump can be configured to generate fluid flow (i.e., inject fluid) at a sufficient rate to have the injected fluid generate pressure onto the actuation dart 510 to carry the dart downhole. In some implementations, the pump can generate fluid flow at a rate between about 20 L/min and 1200 L/min, although other rates are possible.

In the illustrated implementation, the pump 105 is located at surface for pumping fluids down the wellbore. However, it is appreciated that other configurations are possible, such as installing a pump downhole as an alternative, or as an addition to the surface pump 105. As will be described further below, the actuation dart 510 can be configured as a fluid-operated system for shifting the valve sleeves of each valve assembly 400 in the open position. It should therefore be understood that the valve assemblies can be fluid pressure-activated from the closed configuration to the open configuration.

The dart body 512 includes a shifting head 514 at a first end thereof adapted to engage and shift the valve sleeve 408 downhole, effectively configuring the valve assembly in the open configuration. As previously described, the shifting head 514 is adapted to shift the valve sleeve in the open position using fluid flow. In other words, fluid flow is used to carry the actuation dart 510 to the valve assembly 400 such that the shifting head 514 extends into the central passage 406 and engages the valve sleeve 408. Then, fluid flow exerts pressure onto the actuation dart 510, effectively shifting the valve sleeve 408 downhole in the open position.

Referring to FIG. 15, in addition to FIGS. 10 and 11, the actuation dart 510 is positioned in a manner such that the dart body 512 extends into the passage of the valve sleeve 408 and the shifting head 514 is in the engaged position. In some implementations, the valve sleeve 408 includes a complementary profile to at least a portion of the shifting head 514. For example, in this implementation, the valve sleeve 408 includes a rabbeted edge, such as a downhole shoulder 425 (illustrated in FIG. 10), shaped and sized to receive the complementarily-shaped portion of the shifting head 514 thereon. The complementarily-shaped portion of the shifting head 514 can include an abutment portion 516 protruding outwardly therefrom (e.g., radially or at an angle), and the downhole shoulder 425 can protrude inwardly (e.g., within the fluid conducting passage 406) to effectively have the abutment portion 516 abut thereon, thus preventing further downhole movement of the actuation dart 510. As such, the dart body 512 can be arranged in a desired position with respect to the valve assembly 400. It should be understood that the desired position can differ depending on the design of the valve assembly and/or the method used to operate the valve assembly (e.g., the method of shifting the valve sleeve 408).

The shifting head 514 can be configured to release itself after the valve sleeve is shifted in the open position. In some implementations, at least one of the abutment portion 516 and downhole shoulder 425 can be provided with resilient elements (not shown) configured to compress once the valve sleeve has reached the open position. It should be noted that the abutment portion 516 can be adapted to compress inwardly in order to clear the downhole shoulder 425, or that the downhole shoulder 425 can be compressed outwardly to release the abutment portion 516 and allow the actuation dart to flow further downhole. In this implementation, it should be noted that pumping additional fluids downhole exerts pressure onto the actuation dart 510 in order to disengage the shifting head 514 from the valve sleeve. In some implementations, the fluid being pumped downhole can be adapted to exert a pressure between about 20 psi and about 3000 psi on the actuation dart. In some implementations, the pressure required to shift the valve sleeves in the open configuration can be between 100 psi and about 3000 psi, such as between 200 psi and 1000 psi, such as between about 500 psi and about 750 psi, although other range of values are possible and may be used. Thereby, it is noted that the pressure exerted on the actuation dart by the pumped fluids can be transferred onto the valve sleeve, via engagement of the actuation dart with the valve sleeve, to shift the sleeve open. As will be described below, a method of operating each valve assembly 400 installed along the wellbore can be enabled via the use of a single actuation dart 510. More specifically, the actuation dart 510 is configured the engage a valve sleeve of a first valve assembly 400, shift the valve sleeve in the open position, disengage the valve sleeve and flow downhole towards a second valve assembly, and so on.

In this implementation, the dart body 512 further includes a crossover segment 518 and a dart tail 520. The crossover segment 518 is positioned between the shifting head 514 and dart tail 520 and effectively connects these components together. However, it is appreciated that other configurations of the dart body 512 are possible. Still referring to FIG. 11, the dart tail 520 can include one or more components connected thereto and extending therefrom to maintain, or increase, the efficiency of the fluids being pumped down the well and/or stabilize the actuation dart 510 as it is carried downhole via fluid flow. In some implementations, the dart tail 520 includes at least one tubing cup 522 connected at an uphole end of the crossover segment 518.

In some implementations, the tubing cup 522 can have an uphole rim 524 extending outwardly therefrom for engaging a portion of the inner surface of the tubing string and/or valve sleeve to help guide the actuation dart 510 as it is carried downhole. As such, the dart body 512 can remain substantially aligned with a central axis of the wellbore in order to facilitate at least partial entry of the dart body 512 within the valve assembly 400 (e.g., through the central passage 406). In some implementations, the tubing cup 522, or at least a portion thereof, is made of flexible material such as nitrile rubber, urethane, or foam for example, although it is appreciated that other materials are possible. It is appreciated that the flexible material can allow the tubing cup 522 to at least partially compress inwardly when passing through the valve sleeve 408 in order to avoid abutting against the downhole shoulder 425 of the valve sleeve. Alternatively, or additionally, the uphole rim 524 can have a sloped surface 526 adapted to facilitate the compression of the tubing cup 522 (or of the downhole shoulder 425) when passing through the valve sleeve.

It should be noted that the uphole rim 524 includes an engagement surface 525 configured to effectively engage the inner surface of the tubing string or valve sleeve. In this implementation, the engagement surface 525 is substantially planar (i.e., adapted to engage the wellbore surface over a 2D surface), although it is appreciated that any other suitable configurations are possible. For example, the engagement surface 525 can be generally linear (i.e., adapted to engage the wellbore surface along a 1D surface), or a combination of planar and linear engagements. As seen in FIG. 11, in this implementation, the uphole rim 524 extends outwardly therefrom on all sides (e.g., around 360 degrees) in order to substantially cover the cross-sectional area of the wellbore. Alternatively, the tubing cup 522 may include a plurality of separate portions extending in different directions to engage the inner surface of the tubing string.

In some implementations, the dart tail 520 can include a plurality of tubing cups 522 extending from the uphole end of the crossover segment 518. In this implementation, a first tubing cup 522 is connected to the crossover segment 518, and a second tubing cup 522 is connected to the first tubing cup 522 in an end-to-end manner. It is appreciated that additional tubing cups 522 can be provided and connected together in an end-to-end manner at the uphole end of the dart body 512. The tubing cup 522 can have a cupped region 528 at an uphole end thereof having a surface area shaped and sized to at least partially block fluid flow down the wellbore such that the fluid effectively pushes the actuation dart 510 by exerting pressure on the cupped region 528. In other words, the tubing cup 522 is shaped and configured to have fluid exert pressure thereon, thus carrying and accelerating the actuation dart 510 along the wellbore. It should be noted that the design of the actuation dart 510, e.g., the shape and size of the components of the dart, can be chosen based on the characteristics of the injection fluid being pumped down to carry the actuation dart. Alternatively, or additionally, the design of the actuation dart can be chosen based on the number of valve assemblies to be shifted in the open configuration along the wellbore. For example, a wellbore provided with a large number of valve assemblies can require an actuation dart configured to withstand sustained pressure, e.g., from fluid flow and from engaging the valve assemblies, for a greater amount of time.

In some implementations, the cupped region can be a solid surface to promote fluid pressure applied thereon, although it is appreciated that the cupped region 528 can alternatively be defined as a hollow region within tubing cup 522 for allowing fluid to flow therein to push the dart along the wellbore. In some implementations, the dart tail 520 can be shaped, sized and adapted to allow fluid to generate pressure on the actuation dart 510 and flow downhole along the wellbore to provide fluid flow through subsequent valve assemblies 400 and prevent over-pressurization of the wellbore uphole of the dart tail 520. For example, the dart tail 520 can be provided with openings extending therethrough (e.g., through the cupped region 528) to allow fluid to flow axially along the valve assembly 400 (e.g., from the tail toward the head) to prevent accumulation of fluids proximate the dart tail 520. Alternatively, or additionally, the dart tail 520 can be spaced from the inner surface of the valve assembly 400 (and/or connected conduits) such that fluid can flow around the actuation dart 510, while also exerting pressure on the cupped region 528.

Referring broadly to FIGS. 11 to 18, it should be noted that in the above described implementations, the dart body 512 can be formed as a one-piece unit (e.g., via moulding). Alternatively, the components of the dart body 512 can be separately formed and connected to one another via any suitable method, such as fasteners, threaded connections, press-fit connections, or a combination thereof. For example, and as seen in FIGS. 13, 14 and 18, the shifting head 514, crossover segment 518 and dart tail 520 can be separate components configured to be connected to one another. Each portion of the actuation dart 510 can include connectors configured to engage (or be engaged) by an adjacent portion of the dart.

In some implementations, the dart tail 520 includes a plurality of components engaged with one another and connected to the crossover segments 518. More specifically, the dart tail 520 includes coupling components, such as cup spacers 530, 532 configured to separate the tubing cups 522 from one another along the dart tail 520. In some implementations, the cup spacers 530, 532 can be adapted to retain the tubing cups 522 in position while the actuation dart 510 is pumped downhole. More specifically, the cup spacers 530, 532 can prevent the cups from being pushed into one another, which can reduce the efficiency of the dart tail 520 (e.g., reduce the surface area against which pressure can be exerted). In this implementation, each component of the dart tail 520 is configured to connect to the crossover segment 518. As seen in FIGS. 13 and 14, the tubing cups 522 and coupling components 530, 532 are provided with a central bore 534 shaped and sized to slide onto a connection rod 536 of the crossover segment 518. Alternatively, and as illustrated in FIGS. 17 and 18, the connection rod 536 can be a separate component (i.e., independent from the crossover segment 518) configured to engage each component of the dart tail 520 (e.g., extend through the central bore of each component) and to engage the crossover segment 518. Therefore, the dart tail, and thus each of its components are connected to the crossover segment 518. In some implementations, the connection rod 536 can be shaped and sized to enable retrieval of the actuation dart 520 from the wellbore. For example, a downhole tool can be run downhole (e.g., via coiled tubing) to engage and/or connect to the uphole end of the connection rod 536, thereby allowing the actuation dart 510 to be pulled out from the wellbore. The actuation dart 510 can then be reused to open valve assemblies in a separate well.

At this point, using the above-described actuation dart 510, and associated system, a method for oil recovery will now be described. First, the method includes the step of running a tubing string into an existing well previously operated for primary production, therefore defining a plurality of wellbore intervals isolated form one another along the well defined by isolation devices (e.g., packers) deployed in spaced-apart relation to each other within the annulus. Then, for one or more of the wellbore intervals, installing a valve assembly, such as the valve assembly described above, along the tubing string. Once the valve assemblies are installed, an actuation device, such as the actuation dart described above, is deployed within the wellbore and injection fluid is effectively injected (i.e., pumped) down the tubing string to carry the actuation device towards the valve assembly. The actuation dart is configured to travel along the tubing string via fluid flow so as to pass through the wellbore intervals and position (e.g., shift) the valve sleeves into the open configuration. When the valves are positioned in the open configuration, oil recovery can be initiated via at least one adjacent production well, for example. It is appreciated that the fluid used to carry the actuation dart downhole and to each valve assembly can be injected into the reservoir once the valve assemblies have been opened. Alternatively, the fluid can be recovered at surface via a predetermined pathway within the wellbore to be used to pump another actuation dart down the wellbore, or down a separate well.

As the actuation dart passes through each valve, the shifting head effectively engages each respective valve sleeve to shift the valve sleeve in the open position. Once open, additional fluids can be pumped down the wellbore for exerting pressure on the actuation dart and disengaging the shifting head from the valve sleeve, thereby allowing the actuation dart to flow through the valve and travel towards the subsequent valve or valve assembly along the tubing string. Once the final valve assembly (e.g., the most downhole valve assembly) is shifted in the open configuration, the actuation dart can be simply left within the tubing string, for example, past the final valve assembly so as to not hinder fluid injection through said valve assembly. Alternatively, the actuation dart 510 can be recovered using any suitable method, such as by engaging the connection rod 536 (seen in FIGS. 16 to 18) from surface to pull the dart uphole and out of the wellbore.

In some implementations, each valve is initially in a central position when the tubing string is run into the wellbore and are adapted to be shifted downhole (i.e., in the downhole position) by the actuation dart. It should be noted that the central position can correspond to a closed configuration, as seen in FIG. 4, or an open configuration, as seen in FIG. 8, for example. Moreover, the open configuration can be a fully open configuration, or a flow restricted configuration, for example.

In an exemplary implementation, and with reference to FIG. 8, the initial position of the valve sleeve 408 (e.g., the central position) corresponds to a first open configuration adapted to enable fluid flow towards the burst disc 422 covering the housing outlet 404 to rupture the burst disc 422 and enable injection into the reservoir. Once the burst disc 422 is defeated, the valve sleeve can be shifted in the downhole position, corresponding to a second open configuration adapted to restrict fluid flow between the tubing string and the reservoir. Alternatively, the downhole position can correspond to the closed configuration to prevent fluid from being injected into the reservoir.

It should be noted that example implementations of the valve sleeve of the valve assembly 400 can have up to three operational positions, i.e., the uphole position, the downhole position and the central position. Moreover, it is noted that each operational position of the valve sleeve can correspond to one of a given number of configurations of the valve assembly, such as the closed configuration and the open configuration. In some implementations, the open configuration can correspond to the fully open configuration or one or more flow restricted configurations where the flowrate of fluids through the housing outlet is restricted to a predetermined, desired and/or controlled flowrate. For example, a valve assembly can include a plurality of open configurations, such as three, where each open configuration defines a corresponding flowrate through the housing outlet by being either fully open or flow restricted to a certain degree. Alternatively, the valve assembly can include two open configurations and a closed configuration, and the closed configuration can be either of the uphole, downhole or central position.

It should thus be understood that the valve assembly can have any suitable number of operational positions (e.g., three) corresponding to respective configurations for operating the valve assembly, and that the valve assembly can have any suitable combination of configurations (e.g., closed, fully open, one or more flow restricted). Furthermore, the valve assembly can be adapted to be run downhole within the wellbore with the valve sleeve being in any one of the operational positions (e.g., uphole, downhole or central any of which can be closed, fully open or flow restricted).

It is noted that the wellbore pressure (or tubing string pressure) can be monitored at surface using any suitable and/or known method. For example, pressure sensors, pressure gauges abd/or pressure transducers can be provided at surface and/or deployed downhole to provide downhole pressures in real-time (or almost real-time), thereby enabling the collection of pressure data for the creation of corresponding pressure graphs for further analysis. In some implementations, the actuation dart can be deployed to operate the various valve assemblies along the wellbore, and used as a diagnostic tool to determine when and/or if a valve sleeve has shifted, e.g., from the central position to the downhole position. As the actuation dart flows downhole, each actuation of a valve sleeve will translate to a shift in the monitored wellbore pressure. As such, the actuation dart can provide interventionless stage counting and valve shifting confirmation capabilities, where operators can determine when a valve sleeve has shifted using the actuation dart and the monitored pressures. Moreover, the actuation dart flows downhole and can thus actuate the valve assemblies one by one (e.g., in a heel-to-toe direction) such that operators can determine which of the valve assemblies have been actuated.

In this implementation, the actuation dart provides the ability to observe (e.g., using the pressure data and/or pressure graphs) each shift that occurs along the wellbore, since the shifts generally occur in order as the dart travels along the wellbore. In other words, the actuation dart can leave “fingerprints” on the pressure data, and therefore on the created graphs, for enabling operators to confirm when and which valve has shifted to the open configuration. More particularly, as the dart travels down the tubing string, the tubing string pressure can be monitored at surface using any suitable pressure sensor(s). For example, a high sample frequency speed sensor can be connected to the tubing string to monitor the pressure therein and enable observation of pressure variations as the dart travels along the tubing string. In some implementations, when each valve assembly is in the closed configuration, the dart is injected into the tubing string with the tubing pressure being at an initial tubing string pressure (e.g., about 0 psi, as fluid is initially injected into the tubing string). It is noted that the tubing string can be provided with at least one opening, for example proximate the toe of the string, when initially injecting the actuation dart downhole to provide a preliminary flow path enabling fluid flow to carry the dart along the string (e.g., toward the toe). The at least one opening can remain open throughout the various downhole operations, or can be made to be subsequently and/or selectively closed, after a given downhole operation and/or when desired, for example.

Once the dart engages a valve assembly (e.g., the first valve assembly positioned along the tubing string), the tubing string pressure increases as fluid exerts pressure on the dart, which in turn exerts pressure on the valve sleeve. The tubing string pressure increases in this manner until it reaches a shifting threshold adapted to shift the valve sleeve for operating the valve assembly in the open configuration (e.g., about 500 psi). Once the valve sleeve has shifted, the dart releases from the valve assembly and continues to travel downhole toward subsequent valve assemblies. Once released and free to travel, the tubing string pressure drops back down to approximately the initial tubing string pressure as fluids are allowed to flow into the reservoir through the opened valve assembly, for example.

With reference to FIG. 19, it is noted that the monitored tubing string pressure data can be translated into corresponding pressure graphs, which can be used to observe when a shift occurs. More specifically, the tubing string pressure buildup (e.g., when the dart engages a valve sleeve) followed by a subsequent tubing string pressure drop (e.g., when the dart releases from the valve sleeve following the shift) can form a pressure profile (P) or a “pressure signature”, such as peaks, on the pressure graph/data. Each peak can thus be indicative of a shifting event, where a valve sleeve is shifted to operate the valve assembly in the open configuration. As such, additional fluid can be pumped downhole to flow into the reservoir once at least one of the valve assemblies has been observed to have been actuated in the open configuration. It should be noted that the peaks of a given pressure graph/data can be counted to determine the number of shifting events that occurred, and thus confirm the number of open valve assemblies. It is noted that the required pressure to actuate subsequent valve assemblies can increase (as seen in FIG. 19) as more and more valve assemblies are open, thereby enabling injection of fluids into the reservoir. In other implementations, such as the one illustrated in FIG. 15, the valve assemblies include burst discs, such that fluids are not allowed into the reservoir even after having shift the valve sleeve. In such implementations, the pressure required to shift each valve assembly can be generally the same.

In some implementations, one or more operating parameters can be adjusted to facilitate monitoring the tubing string pressure, the creation of the pressure graphs and/or the observation of successful shifting events. For example, the rate at which fluid is pumped (i.e., injected) downhole can be decreased, since the slower you pump, the slower the dart will travel downhole, and the more gradual the tubing string pressure buildup will occur once the dart engages the valve sleeve. As such, the pressure peaks will be spread over longer periods of time on the pressure graphs, thereby facilitating their observation.

Similarly, the frequency at which the tubing string pressure is recorded can be increased to better define the pressure graphs (e.g., better define the pressure peaks), and thereby facilitate observation of each shifting event. Traditional pressure sensors, gauges and/or transducers are configured to record one (1) sample per second, whereas the valve sleeves can be shifted in less than 1 to 2 seconds. As such, it is possible that, by recording at a rate of one sample per second, one or more shifting events may be missed. Thus, by increasing the sample frequency of the pressure gauge/recorder, for example, to between about 10 to 100 samples per second, the probability of missing a shifting event is considerably reduced, and the pressure graphs correspondingly provide improved observation of the shifting events. It should be noted that the frequency at which pressures are recorded can be less than 10 samples per second, and can similarly be more than 100 samples per second.

In the event that one or more valve sleeves fail to shift open, the stabilized injection rates can be observed to see if they match up with the number of valves we presume to be open (e.g., with the number of peaks counted on the pressure graph). If the injection rates are acceptable, the well can be operated “as is” and fluid injected through the open valve(s). Otherwise, a bottomhole assembly (BHA) can be run in hole to confirm the valve positions, and shift any valves to the desired position. It is noted that, in the event that a valve fails to open, the pressure graph(s) would not indicate a similar pressure profile as those for previously shifted valve assemblies. In some implementations, the dart can remain stuck in engagement with a valve sleeve, and a continuous pressure rise would occur until the well reaches equilibrium with any open valve assemblies. Otherwise, it is possible that the dart fails to shift a given valve sleeve, and simply skips the valve assembly. In such cases, no pressure indication would be seen on the recorded data and created graph(s).

Referring back to FIGS. 1 to 3, in some implementations, the wellbore 103 includes a casing 250 lining an inner surface of the wellbore 103. The casing 250 can be adapted to contribute to the stabilization of the reservoir 101 after the wellbore 103 has been drilled, e.g., by contributing to the prevention of the collapse of the walls of the wellbore 103. In some implementations, the casing 250 includes one or more successively deployed concentric casing strings, each one of which is positioned within the wellbore 103. In some implementations, each casing string includes a plurality of jointed segments of pipe. The jointed segments of pipe typically have threaded connections although other configurations are possible and may be used.

It can be desirable to seal an annulus formed within the wellbore between the casing string 250 and the reservoir 101. Sealing of the annulus can be desirable for preventing injection fluid from flowing into remote zones of the reservoir, thereby providing greater assurance that the injected fluid is directed to the intended zones of the reservoir. To prevent, or at least interfere with injecting fluid into an unintended zone of the reservoir, or to the surface, the annulus can be filled with an isolation material, such as cement, thereby cementing the casing to the reservoir 101. It should be noted that the cement can also provide one or more of the following functions: (a) strengthens and reinforces the structural integrity of the wellbore, (b) prevents, or substantially prevents, produced fluids of one zone from being diluted by water from other zones. (c) mitigates corrosion of the casing 250, and (d) at least contributes to the support of the casing 250.

It is further noted that, the casing 250 includes a plurality of casing outlets 255 for allowing fluid flow from the wellbore string into and from the reservoir (e.g., via injection and production segments respectively). In some implementations, in order to facilitate fluid communication between the wellbore string and the reservoir 101, each one of the casing outlets 255 can be substantially aligned with, or at least proximate to the housing outlet 404 of a corresponding valve assembly 400. In this respect, in implementations where the wellbore 103 includes the casing 250, injection fluid is injected from the surface down the wellbore string and through the various valve assemblies in order to flow through the housing outlet 404 of the corresponding valve assembly 400 and into an annular space 245 (seen in FIG. 3) defined between certain portions of the wellbore string (e.g., the valve assemblies 400) and the casing string 250, and finally into the reservoir 101 via the casing outlets 255.

The present disclosure may be embodied in other specific forms without departing from the subject matter of the claims. The described example implementations are to be considered in all respects as being only illustrative and not restrictive. For example, in the implementations described herein, the dart is configured to engage complementary shifting profiles or structural features within the valve assemblies (e.g., on the valve sleeves) to enable engagement and shifting of the valve sleeves. Each valve sleeve can be provided with identical shifting profiles enabling shifting each valve sleeve with the same, single dart. In alternate implementations, different shifting profiles (e.g., two or more) and corresponding darts can be used to shift some valve sleeves and not others. In another implementation, the shift/initial position of the sleeve can be different, e.g., reversed, so that a dart can shift some sleeves open (as described above), others closed and others in a restricted configuration. In such implementations where the dart is used to close the valve assemblies, the required pressure to shift/close each subsequent valve assembly can decrease as more and more valve assemblies are closed, thereby preventing fluid flow into the reservoir. In yet another implementation, the dart can be used to shift sleeves, or other downhole components, open, closed or used to unset the packers installed along the wellbore.

It should also be noted that the dart itself can be provided with structural features and/or downhole capabilities configured to provide information indicative of a successful shifting event. For example, the dart can be provided with a memory gauge with one or more sensors for measuring various parameters, such as pressure sensor(s), temperature sensor(s), force sensor(s), accelerometer(s), etc.

The present disclosure intends to cover and embrace all suitable changes in technology. The scope of the present disclosure is, therefore, described by the appended claims rather than by the foregoing description. The scope of the claims should not be limited by the implementations set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.

As used herein, the terms “coupled”, “coupling”, “attached”, “connected” or variants thereof as used herein can have several different meanings depending in the context in which these terms are used. For example, the terms coupled, coupling, connected or attached can have a mechanical connotation. For example, as used herein, the terms coupled, coupling or attached can indicate that two elements or devices are directly connected to one another or connected to one another through one or more intermediate elements or devices via a mechanical element depending on the particular context.

In the present disclosure, an implementation is an example or embodiment of the described features. The various appearances of “one implementation,” “an implementation” or “some implementations” do not necessarily all refer to the same implementations. Although various features may be described in the context of a single implementation, the features may also be provided separately or in any suitable combination. Conversely, although the valve assemblies and/or the actuation dart may be described herein in the context of separate implementations for clarity, it may also be embodied in a single implementation. Reference in the specification to “some implementations”, “an implementation”, “one implementation”, or “other implementations”, means that a particular feature, structure, or characteristic described in connection with the implementations is included in at least some implementations, but not necessarily in all implementations.

In the above description, the same numerical references refer to similar elements. Furthermore, for the sake of simplicity and clarity, namely so as to not unduly burden the figures with several references numbers, not all figures contain references to all the components and features, and references to some components and features may be found in only one figure, and components and features of the present disclosure which are illustrated in other figures can be easily inferred therefrom. The implementations, geometrical configurations, materials mentioned and/or dimensions shown in the figures are optional, and are given for exemplification purposes only.

In addition, although the optional configurations as illustrated in the accompanying drawings comprises various components and although the optional configurations of the actuation dart as shown may consist of certain geometrical configurations as explained and illustrated herein, not all of these components and geometries are essential and thus should not be taken in their restrictive sense, i.e. should not be taken as to limit the scope of the present disclosure. It is to be understood that other suitable components and cooperations thereinbetween, as well as other suitable geometrical configurations may be used for the implementation and use of the actuation dart, and corresponding parts, as briefly explained and as can be easily inferred herefrom, without departing from the scope of the disclosure.

Claims

1. A method for treating a hydrocarbon bearing reservoir, comprising:

running a tubing string into an existing well previously operated for primary production to define an annulus between the tubing string and a wellbore, and defining a plurality of wellbore intervals isolated from one another along the well defined by isolation devices deployed in spaced-apart relation to each other within the annulus;

for multiple wellbore intervals, installing a corresponding valve assembly along the tubing string, the valve assembly comprising at least one valve, each valve being operable in at least one of a closed configuration for preventing fluid flow into the surrounding reservoir and an open configuration for establishing fluid communication between the tubing string and the surrounding reservoir via respective fluid passages, the fluid passage of at least one valve being elongated and configured such that the open configuration of the corresponding valve is a flow restricted configuration where fluid flowrate from the tubing string into the reservoir is restricted;

deploying an actuation dart within the tubing string; and

injecting at least one fluid down the tubing string to carry the actuation dart along the tubing string via fluid flow so as to pass through the wellbore intervals and operate the valves in the open configuration for allowing the at least one fluid to flow along the fluid passage and enter the reservoir at the corresponding wellbore interval.

2. The method of claim 1, wherein each valve comprises a corresponding valve housing provided with a valve sleeve slidably mounted therein, the valve housing comprising a fluid outlet communicating with the fluid passage of the valve for allowing injection fluid to flow from the tubing string to the surrounding reservoir.

3. The method of claim 2, wherein each valve sleeve is operable in a central position, an uphole position and a downhole position, the position of the valve sleeves within their respective valve housings corresponding to an operational configuration of the respective valves.

4. The method of claim 3, wherein each valve sleeve is initially in the central position when the valves are installed along the tubing string and while the tubing string is run into the wellbore, and wherein the actuation dart is configured to shift the valve sleeve downhole and into the open configuration.

5. The method of any one of claims 2 to 4, wherein the valve sleeve comprises a fluid passage inlet communicating with the fluid passage, and wherein the fluid passage is defined by a channel in an outer surface of the valve sleeve and an inner surface of the housing that overlays the channel.

6. The method of any one of claims 1 to 5, wherein the injected fluid used to carry the actuation dart includes water, diesel, drilling mud, produced water, produced gas, methane, CO2, nitrogen or a combination thereof.

7. The method of any one of claims 1 to 6, wherein the fluid used to carry the actuation dart is injected within the tubing string via a pump.

8. The method of claim 7, wherein the pump is located at surface.

9. The method of claim 7 or 8, wherein the pump is adapted to generate fluid flow between about 20 L/min and about 1200 L/min.

10. The method of claim 9, wherein the injected fluid is adapted to exert a pressure between about 20 psi and about 3000 psi on the actuation dart.

11. The method of any one of claims 2 to 10, wherein the actuation dart comprises a dart head having an outer surface with a portion thereof being configured to engage a complementarily shaped portion of an inner surface of the valve sleeve and shift the valve sleeve in the open configuration.

12. The method of claim 11, wherein the injected fluid is adapted to exert a pressure between about 100 psi and 3000 psi on the valve sleeve via the actuation dart to shift the valve sleeve in the open configuration.

13. The method of claim 11 or 12, wherein the actuation dart comprises a dart tail connected to the dart head, the dart tail comprising an engagement surface for engaging an inner surface of the tubing string in order to guide the actuation dart as it is carried down the wellbore.

14. An actuation dart for deployment down a tubing string installed within a wellbore and provided with one or more valve assemblies, comprising:

a dart body adapted to be carried down the tubing string to the valve assembly via fluid flow, the dart body comprising: a shifting head provided at a first end of the dart body, the shifting head being configured to engage and shift the valve assembly in an open configuration to enable fluid injection in a reservoir surrounding the wellbore.

15. The actuation dart of claim 14, wherein the shifting head comprises an abutment portion shaped and sized to engage a complementarily shaped portion of the valve assembly and shift the valve assembly in the open configuration.

16. The actuation dart of claim 15, wherein the abutment portion is configured to compress inwardly when engaged with the valve assembly via pressure exerted on the actuation dart via fluid flow, thereby enabling the actuation dart to disengage from the valve assembly and allow the actuation dart to flow further downhole along the tubing string.

17. The actuation dart of claim 15, wherein the dart body further comprises a dart tail connected to the shifting head, the dart tail comprising an engagement surface adapted to engage an inner surface of the tubing string in order to guide the actuation dart as it is carried down the wellbore.

18. The actuation dart of claim 16, wherein the dart body comprises a crossover segment extending between and connecting the dart tail and the shifting head together.

19. The actuation dart of claim 17, wherein the dart tail comprises a tubing cup connected to an uphole end of the crossover segment and having an uphole rim extending outwardly therefrom, and wherein the uphole rim includes the engagement surface for engaging the inner surface of the tubing string.

20. The actuation dart of claim 18, wherein the dart body comprises a plurality of tubing cups connected together in an end-to-end manner.

21. The actuation dart of claim 18 or 19, wherein the tubing cup comprises a cupped region extending generally transversely with respect to a passage of the tubing string, the cupped region being shaped and adapted to have fluid exert pressure thereon to push the actuation dart downhole.

22. The actuation dart of claim 21, wherein the uphole rim substantially surrounds the cupped region of the tubing cup.

23. A well system comprising: the actuation device being configured to engage and shift each valve of the valve assembly subsequently.

a tubing string installed in a wellbore;

a valve assembly provided along the tubing string, the valve assembly comprising at least one valve, each valve being operable in at least one of a closed configuration for preventing fluid flow into the surrounding reservoir and an open configuration for establishing fluid communication between the tubing string and the surrounding reservoir via respective fluid passages, the fluid passage of the at least one valve being elongated and configured such that the open configuration of the valve is a flow restricted configuration where fluid flowrate from the tubing string into the reservoir is restricted;

an actuation device adapted for deployment down the tubing string via fluid flow for engaging the valve assembly and shifting each valve in the open configuration; and

a pump for pumping fluid down the tubing string to carry the actuation device via fluid flow toward the valve assembly,

24. The well system of claim 23, wherein each valve comprises a corresponding valve housing provided with a valve sleeve slidably mounted therein, the valve housing comprising a fluid outlet communicating with the fluid passage of the valve for allowing injection fluid to flow from the tubing string to the surrounding reservoir.

25. The well system of claim 24, wherein each valve sleeve is operable in a central position, an uphole position and a downhole position, the position of the valve sleeves within their respective valve housings corresponding to an operational configuration of the respective valves.

26. The well system of claim 25, wherein each valve sleeve is initially in the central position when the valves are installed along the tubing string and while the tubing string is run into the wellbore, and wherein the actuation dart is configured to shift the valve sleeve downhole.

27. The well system of claim 26, wherein the central position corresponds to a first open configuration of the valve assembly defining a first fluid flowrate through the fluid outlet, and wherein shifting the valve sleeve in the downhole position operates the valve assembly in a second open configuration defining a second fluid flowrate through the fluid outlet.

28. The well system of claim 27, wherein the first fluid flowrate is greater than the second fluid flowrate.

29. The well system of claim 27 or 28, wherein when in the first open configuration, the fluid outlet is provided with a breakable barrier adapted to occlude the fluid outlet and prevent fluid communication between the fluid passage and the surrounding reservoir

30. The well system of any one of claims 25 to 29, wherein the valve sleeve comprises a fluid passage inlet communicating with the fluid passage, and wherein the fluid passage is defined by a channel in an outer surface of the valve sleeve and an inner surface of the housing that overlays the channel.

31. The well system of any one of claims 23 to 30, wherein the pumped fluid used to carry the actuation dart includes water, diesel, drilling mud, produced water, produced gas, methane, CO2, or nitrogen or a combination thereof.

32. The well system of any one of claims 23 to 31, wherein the pump is located at surface.

33. The well system of any one of claims 23 to 32, wherein the pump is adapted to generate fluid flow between about 20 L/min and about 1200 L/min.

34. The well system of any one of claims 23 to 33, wherein the injected fluid is adapted to exert a pressure between about 20 psi and about 3000 psi on the actuation dart.

35. The well system of any one of claims 23 to 34, wherein the injected fluid is adapted to exert a pressure between about 100 psi and 3000 psi on the valve sleeve via the actuation dart to shift the valve sleeve in the open configuration.

36. The well system of any one of claims 23 to 35, wherein the actuation device comprises an actuation dart as defined in claims 14 to 22.

37. The well system of any one of claims 23 to 36, wherein the wellbore is provided in a geothermal reservoir, and wherein fluids are produced as part of geothermal operations.

38. A method for injecting fluids into a reservoir via a well system as defined in claims 23 to 37, comprising:

deploying the actuation dart within the tubing string;

pumping fluid within the tubing string for carrying the actuation dart toward the valve assembly via fluid flow;

engaging the actuation dart with the valve assembly; and

pumping additional fluid within the tubing string for exerting pressure on the actuation dart and shifting the valve assembly in the open configuration.

39. A method for injecting fluids into a reservoir via a well system comprising a wellbore provided with a tubing string, the tubing string comprising one or more valve assemblies operable between a closed configuration for preventing fluid flow into the surrounding reservoir and an open configuration for establishing fluid communication between the tubing string and the surrounding reservoir via respective fluid passages, the fluid passage of at least one valve assembly being elongated and configured such that the open configuration of the corresponding valve is a flow restricted configuration where fluid flowrate from the tubing string into the reservoir is restricted, the method comprising the steps of:

deploying an actuation dart within the tubing string;

pumping fluid within the tubing string for carrying the actuation dart toward the valve assembly via fluid flow;

engaging the actuation dart with the valve assembly; and

pumping additional fluid within the tubing string for exerting pressure on the actuation dart and shifting the valve assembly in the open configuration.

40. The method of claim 39, wherein the actuation dart is as defined in any one of claims 14 to 22.

41. The method of claim 39 or 40, further comprising the step of monitoring a tubing string pressure to determine when a shifting pressure profile is recorded indicative of a shifted valve assembly in the open configuration.

42. The method of claim 41, wherein monitoring the tubing string pressure comprises recording pressure samples at a predetermined sample frequency to enable the collection of pressure data and the creation of a pressure graph.

43. The method of claim 42, wherein the creation of the pressure graph is facilitated by at least one of increasing the predetermined sample frequency at which the tubing string pressure is recorded, and lowering a rate at which fluids are pumped downhole.

44. The method of claim 42 or 43, wherein the predetermined sample frequency is between about 10 and 100 pressure samples per second.

45. The method of any one of claims 42 to 44, further comprising the step of analyzing the pressure data and/or pressure graph to determine a number of times the shifting pressure profile is recorded, indicative of a number of shifted valve assemblies in the open configuration.

46. The method of claim 45, wherein the shifting pressure profile comprises a pressure build up to a shifting pressure threshold, followed by a pressure drop indicative of the actuation dart releasing from the valve assembly following a shift in the open configuration.

47. The method of any one of claims 41 to 46, wherein the tubing string pressure is monitored using a pressure sensor located at surface.

48. The method of any one of claims 39 to 47, wherein fluids are injected into the reservoir as part of a waterflooding operation.

49. The method of any one of claims 39 to 47, wherein fluids are injected into the reservoir as part of a CO2 flooding operation.

50. The method of any one of claims 39 to 47, wherein fluids are injected into and produced from the reservoir as part of acid solution mining operations.

51. A method of injecting fluids into a reservoir via a well system comprising a wellbore provided with a tubing string, the tubing string comprising one or more valve assemblies operable between a closed configuration for preventing fluid flow into the surrounding reservoir and an open configuration for establishing fluid communication between the tubing string and the surrounding reservoir via respective fluid passages, the method comprising the steps of:

deploying an actuation dart within the tubing string;

pumping fluid within the tubing string for carrying the actuation dart toward the valve assembly via fluid flow;

engaging the actuation dart with a valve sleeve of the valve assembly;

continuing pumping fluid to build tubing string pressure for exerting pressure on the actuation dart up to a shifting pressure threshold adapted to shift the valve sleeve for operating the valve assembly in the open configuration;

monitoring the tubing string pressure to determine when the tubing string pressure reaches the shifting pressure threshold indicative of a shifted valve sleeve to operate the valve assembly in the open configuration; and

pumping additional fluid in the tubing string for injection into the reservoir via the valve assembly.