RELEASABLE DOWNHOLE COMPONENT FOR SUBTERRANEAN DEPLOYMENT ALONG A WELLBORE STRING
20240151118 ยท 2024-05-09
Inventors
Cpc classification
E21B34/106
FIXED CONSTRUCTIONS
E21B34/14
FIXED CONSTRUCTIONS
International classification
Abstract
A downhole component for integration in wellbore string is provided. The downhole component includes fluid conduits enabling fluid flow therethrough and a sealing element connected to the fluid conduits and operable between a disengaged configuration, where the sealing element is disengaged from an inner surface of the wellbore, and an engaged configuration. The downhole component also includes an actuation assembly having a blocking member releasably secured to the fluid conduits and a fluid-pressure operable actuation member slidably connected to the fluid conduits adapted to engage and operate the sealing element from the disengaged configuration to the engaged configuration. The downhole component has a release mechanism operable to release the blocking member to enable the sealing element to revert to the disengaged configuration, wherein the release mechanism is adapted to be selectively and independently operated relative to additional release mechanisms associated with adjacent downhole components along the wellbore string.
Claims
1. A downhole component for integration along a wellbore string extending along a wellbore, comprising: one or more fluid conduits connectable to the wellbore string and defining a conduit passage enabling fluid flow therethrough; a sealing element connected to the one or more fluid conduits, the sealing element being operable between a disengaged configuration, where the sealing element is disengaged from an inner surface of the wellbore, and an engaged configuration, where the sealing element is engaged with the inner surface of the wellbore and seals portions of the wellbore on either side thereof; an actuation assembly comprising: a blocking member releasably secured to the one or more fluid conduits on a first side of the sealing element; and an actuation member slidably connected to the one or more fluid conduits on a second side of the sealing element, the actuation member being fluid-pressure operable to engage and operate the sealing element from the disengaged configuration to the engaged configuration; and a release mechanism operatively connected to the blocking member and being operable to release the blocking member to enable movement thereof away from the actuation member to enable the sealing element to revert to the disengaged configuration, wherein the release mechanism is adapted to be selectively and independently operated relative to additional release mechanisms associated with adjacent downhole components along the wellbore string.
2. The downhole component of claim 1, wherein the actuation member comprises a piston assembly having a tubular wall slidably coupled to the fluid conduits and a piston head connected to the tubular wall adjacent the sealing element, the piston head defining radial surfaces adapted to have fluid exert pressure thereon to fluid-pressure operate the actuation member.
3. The downhole component of claim 1, further comprising a locking mechanism operatively connected to the actuation member and configurable in a locked configuration to prevent disengagement of the actuation member from the sealing element.
4. The downhole component of claim 3, wherein the locking mechanism comprises a ratcheting system configured to enable movement of the actuation member toward the sealing element and prevent movement of the actuation member away from the sealing element.
5. The downhole component of claim 4, wherein the ratcheting system comprises a lock ring provided between at least one of the fluid conduits and the actuation member, the lock ring being configured to at least partially control relative movement between the fluid conduits and the actuation member.
6. The downhole component of claim 4, wherein the lock ring is secured to the fluid conduits and comprises an outer ring surface provided with first set of angled teeth, and wherein the actuation member comprises an inner surface provided with a second set of angled teeth adapted to cooperate with the first set of angled teeth to enable ratcheting the actuation member toward the sealing element.
7. The downhole component of claim 1, wherein the release mechanism comprises a release member connected to the fluid conduits and adapted to engage the blocking member, and further comprises a biasing member adapted to releasably secure the release member in engagement with the blocking member to prevent movement thereof.
8. The downhole component of claim 7, wherein, upon operation of the release mechanism, the blocking member is allowed to axially slide along the fluid conduit away from the actuation member to enable the sealing element to revert to the disengaged configuration.
9. The downhole component of claim 7, wherein the blocking member is releasably secured about a portion of one of the fluid conduits, and wherein the release member extends radially through a thickness of the fluid conduit to engage the blocking member, and wherein the biasing member is operatively coupled within the fluid conduit to bias the release member outwardly from within the conduit passage.
10. The downhole component of claim 7, wherein the biasing member comprises a release sleeve slidably coupled to the fluid conduit along the conduit passage, the release sleeve being adapted to engage the release member from within the conduit passage, and is further adapted to be shifted along the conduit passage to disengage the release member and enable disengagement of the release member from the blocking member.
11. The downhole component of claim 10, wherein the release mechanism comprises a defeatable member configured to releasably secure to the release sleeve within the fluid conduit in a desired position.
12. The downhole component of claim 10, wherein the defeatable member is configured to releasably secure to the release sleeve within the fluid conduit in general alignment with the release member to bias same in engagement with the blocking member.
13. The downhole component of claim 11, wherein the defeatable member comprises at least one shear pin.
14. The downhole component of claim 10, wherein the release sleeve is selectively shiftable within the fluid conduit using a shifting tool deployed on a coiled tubing, a wireline, a slickline, a tubing or a dart.
15. The downhole component of claim 14, wherein the release sleeve is shiftable in a downhole direction.
16. The downhole component claim 7, wherein the fluid conduit comprises a plurality of slots extending through a thickness thereof, and wherein the release member comprises a plurality of pegs positioned in respective slots and having a bottom end communicating with the conduit passage for engagement with the biasing member, and a top end adapted to engage the blocking member.
17. The downhole component of claim 16, wherein the pegs are adapted to move radially outwardly within respective slots when the release mechanism is in the secured position, and are adapted to move radially inwardly within respective slots when the release mechanism is in the released position.
18. The downhole component of claim 2, wherein operating the release mechanism deactivates the piston assembly to prevent engagement of the actuation member with the sealing element.
19.-133. (canceled)
134. The downhole component of claim 1, wherein at least one of the one or more fluid conduits comprises a conduit port defined through a thickness thereof for establishing fluid communication between a surrounding reservoir and the conduit passage.
135. The downhole component of claim 134, further comprising a breakable barrier installed within the conduit port, the breakable barrier being fluid pressure-activated to operate the at least one of the one or more fluid conduits between a closed configuration where the breakable barrier occludes the conduit port for preventing fluid flow into the surrounding reservoir, and an open configuration where the breakable barrier is removed from within the conduit port for allowing fluid flow into the surrounding reservoir.
Description
BRIEF DESCRIPTION OF DRAWINGS
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DETAILED DESCRIPTION
[0164] 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.
[0165] More particularly, the present disclosure describes a valve assembly for downhole deployment within a wellbore extending into the subterranean reservoir. The valve assembly can be deployed in a well in a run-in configuration, such as a closed configuration, and is converted to an operational configuration, such as an open configuration, using fluid pressure for operation of a sealing mechanism (e.g., packer) adapted to set the valve assembly in place in the wellbore in a sealed arrangement, and to subsequently defeat a barrier (e.g., burst disk) blocking a port to enable injection into the reservoir. The fluid pressure can thus set the packer within the annulus of the wellbore and then create fluid communication between the inside and outside of the valve by defeating the burst disk.
[0166] The valve assembly is shaped, sized and adapted to be integrated as part of a wellbore string, with the sealing mechanism being further adapted to separate the well into stages, such as injection and production stages, for example. The sealing mechanism includes fluid-activatable sealing elements configured to use fluid flow, such as injection fluid flow, to engage the wellbore and set the position of the valve assembly. It should thus be understood that the valve assembly can be generally secured within the wellbore via the injection of fluids down the wellbore string. As will be described further below, the valve assembly is operable between various configurations for allowing fluid to be injected within the reservoir, and reservoir fluid to be produced from the reservoir into the valve assembly for recovery to surface.
[0167] In example implementations, the valve assembly is operable to inject fluid (e.g., a fluid for stimulating hydrocarbon production via a drive process, such as waterflooding, or via a cyclic process, such as huff and puff) into the subterranean formation, and to produce reservoir fluids containing hydrocarbons. In other words, the valve assembly can be configured to allow both injection and production operations within the reservoir. The valve assembly can be operated using various fluids, such as liquids, gases, or mixtures of liquids and gases. For instance, in some implementations, the injection fluid can include water, steam, solvent (propane, LPG, xylene, etc.) or a combination thereof. In some implementations, the injection fluid can include CO 2 gas and/or supercritical CO 2. Further, in some implementations, the injection fluid may include polymers, surfactants, and the like.
[0168] As will be described further below, the valve assembly and corresponding structural features of the completion system can be operated for the injection and/or recovery of fluids via the wellbore. The valve assembly can include an injection segment provided with a flow restriction component, such as a tortuous path, in fluid communication with the port of the valve assembly such that fluid injection via the port is restricted once the barrier is defeated. The valve assembly can also include a production segment configured to enable production of fluid from the reservoir via the valve assembly. In addition, the sealing mechanism can include a fluid-activatable actuation assembly adapted to cooperate with the sealing element, whereby operation of the actuation assembly engages the sealing element to set the valve assembly within the well and/or define two or more stages of the well.
[0169] In some implementations, the sealing mechanism can be integrated as part of the valve assembly, and is thus adapted to be displaced along with it. The valve assembly can further be provided with a locking mechanism configured to lock the sealing mechanism when engaging the wellbore, thereby securing the valve assembly in position and allowing fluid flow to be decreased or halted without unsetting the valve assembly from within the well. In addition, the valve assembly can include a release mechanism configured to selectively unlock the valve assembly and enable retrieval of the valve assembly from the wellbore.
[0170] It is noted that the various implementations of the valve assembly described herein can be implemented in various wellbores, formations, and for various applications such as hydrocarbon recovery and geothermal applications. In some implementations, the wellbore can be straight, curved, or branched, and can have various wellbore sections. A wellbore section should be considered to be 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, or can tend to undulate or 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 a wellbore section having a longitudinal axis that is between 70 and 110 degrees from vertical. For simplicity, it is noted that 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 it should be appreciated that other shapes are also possible.
[0171] 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 the injection segment of the valve assembly. In some applications, the injection fluid is adapted to mobilize hydrocarbons contained in the reservoir and drive the hydrocarbons towards the production segment, or towards a production well for recovery of the hydrocarbons. In hydrocarbon recovery operations, the production segments 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. In some implementations, the valve assembly is toollessly operable, i.e., does not require the intervention of downhole tools, such as shifting tools deployed on coiled tubing, to open the valve assembly and enable fluid communication with the surrounding formation. Such a toollessly-operable valve assembly can be fluid pressure activated, as will be described in further detail below.
[0172] With reference to
[0173] As seen in
[0174] With reference to
[0175] In the illustrated implementation, the coupling element 112 includes a generally cylindrical body 114 connected to the tubular wall 103. As seen in
[0176] In the illustrated implementation, the coupling element 112 has an outer surface, part of which is complementarily shaped with respect to an inner surface of the tubular wall 103. As such, engagement of the coupling element 112 within the tubular wall 103 can lock the coupling element 112 in place via the engagement of the complementarily shaped surfaces with one another. For example, in this implementation, the inner surface of the tubular wall 103 is provided with a wall slot 105 extending circumferentially thereabout, while the outer surface of the coupling element 112 (e.g., of the downhole portion 116) includes a coupling protrusion 115 shaped and sized to key into the wall slot 105 to block axial and/or radial movement of the coupling element 112 relative to the tubular wall 103. The coupling element 112 can be further provided with one or more seals 119 (e.g., O-rings) for preventing fluid flow into the annular gap between the coupling element 112 and tubular wall 103, or between the coupling element 112 and the uphole component connected thereto. For example, the coupling element 112 can include a first seal, such as an external seal 119a, positioned around the downhole portion 116 for engaging the inner surface of the tubular wall 103; and a second seal, such as an internal seal 119b, positioned within the uphole portion 118 for engaging the component extending into the valve housing 102 through the coupling element 112, as will be described below.
[0177] Now referring to
[0178] In some implementations, the injection head 122 can correspond to the upholemost component of the valve assembly 100, and is thereby adapted to be connected to an uphole component of the wellbore string. For example, in this implementation, the injection head 122 can be shaped and adapted to receive a conduit 31 therein, as shown in
[0179] In the illustrated implementation, the injection segment mandrel 124 is adapted to extend within the valve housing 102 and be coupled thereto. More specifically, the injection segment mandrel 124 engages and extends through the coupling element 112 to connect the injection segment 120 to the valve housing 102. In this implementation, the injection segment 120 is slidably connected to the valve housing 102 such that axial movement of the injection segment 120 relative to the valve housing 102 is possible. As seen in
[0180] With reference to
[0181] For example, the injection segment 120 can be operated in the first operational configuration, such as a closed configuration, where the injection ports 125 are occluded, therefore preventing fluid flow into the reservoir. In addition, the injection segment 120 can be operated from the closed configuration to the second operational configuration, such as an open configuration, where one or more of the injection ports 125 are at least partially open or fully open. It is appreciated that in the open configuration, the injection segment 120 enables fluid to flow through the one or more injection ports 125 and into the reservoir. As will be described further below, the injection segment 120 can be operable from the closed configuration to the open configuration using fluid flow. As such, the injection segment 120 can be toollessly operated from the closed configuration to the open configuration, for example, via an increase in the fluid pressure within the valve assembly 100. It is noted that, once a flow of injection fluid is initiated along the wellbore, the injection segment 120 does not require intervention from downhole tools, such as shifting tools deployed on coiled tubing to transition the valve to the open configuration. Nevertheless, it is noted that certain other implementations of the valve assembly can be provided such that downhole tools can actuate or shift certain components.
[0182] In some implementations, the valve assembly 100 can include one or more tubing string segments 50 adapted to be coupled to the injection segment 120 and extend through the valve housing 102. As seen in
[0183] Referring back to
[0184] It can be desirable to seal an annulus formed within the wellbore between the casing string 250 and the reservoir 14. 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, this annulus can be filled with an isolation material, such as cement, thereby cementing the casing to the reservoir 14. 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.
[0185] It is further noted that the casing 250 includes a plurality of casing outlets 255 for allowing fluid flow between the wellbore string 30 and the reservoir (e.g., via injection and production segments of the valve assembly 100). In some implementations, in order to facilitate fluid communication between the wellbore string 30 and the reservoir 14, each of the casing outlets 255 can be substantially aligned with, or at least proximate to, a corresponding one of the injection or production segments of the valve assembly 100. In this respect, in implementations where the wellbore 10 includes the casing 250, injection fluid is injected from the surface down the wellbore string 30 in order to reach the injection segments 120 of the valve assembly 100. Injection fluid then flows through the open injection ports 125 of the corresponding valve assemblies and into an annular space 245 (see
[0186] Referring now to
[0187] In the illustrated implementation, the sealing element 155 is coupled about the injection segment mandrel 124 in between the coupling element 112 and the protruding portion 123;
[0188] while the actuation assembly 160 is positioned within the valve housing 102 and is connected to the injection segment 120. As will be described further below, the actuation assembly 160 is generally secured to the injection segment mandrel 124 and is adapted to prevent disengagement of the injection segment 120 from the valve housing 102. With reference to
[0189] As described above, the injection segment mandrel 124 has a smaller outer diameter relative to the injection head 122 (e.g., relative to the protruding portion 123) and the valve housing 102. Therefore, when the injection segment mandrel 124 is coupled to the valve housing 102 (e.g., via the coupling element 112), an intermediate section of the injection segment mandrel 124 extends between the protruding portion 123 and the coupling element 112, and defines an inset region 152. More specifically, the inset region 152 is defined by the portion of the injection segment mandrel 124 located between the abutment surface 117 of the coupling element 112 and the abutment surface 127 of the protruding portion 123. In this implementation, and as seen in
[0190] In the illustrated implementation, the actuation assembly 160 is adapted to displace the housing 102 relative to the injection segment 120, enabling compression of the sealing element 155. It is noted that the displacement of the housing 102 axially compresses the sealing element 155 and thus urges the sealing element 155 toward the casing 250 surrounding the valve assembly 100 in order to create an annular seal between the valve assembly 100 and the wellbore, and to set the position of the valve assembly 100 in the wellbore. More specifically, operation of the actuation assembly 160 displaces the housing 102 uphole relative to the injection segment 120, thereby moving the abutment surface 127 of the protruding portion 123 toward the abutment surface 117 of the coupling element 112 (or vice versa). It is appreciated that the abutment surfaces 117, 127 engage the sealing element 155 positioned therebetween, and that operating the actuation assembly 160 causes the sealing element 155 to be actuated and arranged in the operational configuration (seen in
[0191] It is therefore appreciated that the sealing element 155 is configured to extend within the annular space 245 and seal a section thereof for defining two separate zones, or intervals, on either side thereof. As described above, the sealing element 155 is adapted to extend outwardly from the rest of the valve assembly to engage the inner surface of the wellbore. It should be understood that, in implementations where the wellbore includes the casing 250, the inner surface of the wellbore corresponds to the inner surface of the casing string 250, and that, in implementations where the wellbore does not include the casing string 250, the sealing element 155 can engage the inner surface of the wellbore that is part of the reservoir itself.
[0192] In some implementations, the sealing element 155 can be configured for isolating a section of the wellbore. More specifically, a pair of adjacent valve assemblies 100, each having a sealing element 155 engaging the wellbore, define a generally isolated section therebetween (i.e., between the pair of sealing elements). It should be thus understood that a pair of sealing elements 155 can be adapted to define a corresponding operational zone of the well completion system 20 therebetween for injection-only or production-only operation. For example, a pair of sealing elements 155 installed on either side of an injection segment effectively defines an injection zone of the well therebetween. Similarly, a pair of sealing element 155 installed on either side of a production segment effectively defines a production zone therebetween. It should be noted that the well completion system can define a plurality of subsequent injection zones, followed by a plurality of production zones. Alternatively, the well completion system can define alternating injection and production zones along the wellbore. In such implementations, it should be understood that a sealing element is installed between each injection and production zone. The well completion system can also include further independent sealing elements (e.g., not associated with a valve assembly) provided uphole, downhole or between a pair of valve assemblies.
[0193] It should be understood that, as used herein, the expression injection zone can refer to a section of the well where injection fluid is injected into the reservoir. Similarly, the expression production zone can refer to a section of the well where production fluid is recovered from the reservoir. It is appreciated that more than one sealing element 155 can be installed between adjacent production and/or injection segments, thereby defining blank zones in which no injection or production operations are being performed. It is also appreciated that more than one injection or production segment could be installed for a given injection or production zone, respectively. In a well that includes a casing string 250, each zone can include one or more casing outlets 255 for fluid communication with the reservoir.
[0194] As seen in
[0195] It is noted that if the sealing element 155 reverts back to its initial configuration, the sealing element 155 disengages the casing, and enables movement of the valve assembly within the wellbore, e.g., for retrieval and/or repositioning of the valve assembly 100. In some implementations, the valve assembly 100 can be retrieved from downhole once the sealing element 155 disengages the casing 250, such as via a suitable downhole tool, or during retrieval of the tubing string up to surface. The sealing element 155 can be additionally, or alternatively, provided with mechanical structures, such as resilient components (e.g., the garter springs), facilitating reversion of the sealing element to the initial run-in configuration to facilitate retrieval of the valve assembly 100.
[0196] With reference to
[0197] Referring back to
[0198] It is noted that the tubing string segments 50a, 50b define a string fluid passage 165 adapted to be fluidly connected with the fluid passageway 126 of the injection segment 120 for allowing fluid flow through the valve assembly 100 and along the wellbore string. The internal diameters of the passageways 165, 126 can be substantially the same to define a generally continuous central passage the length of the valve assembly, as shown for example in
[0199] In addition, the first segment head 166a can be provided with one or more seals 119 (e.g., O-rings) arranged between the first segment head 166a and the valve housing 102 such that fluid flow is prevented therebetween, and thereby promoting fluid pressure against the actuation assembly 160.
[0200] In this implementation, the coupling element 112 is part of the actuation assembly 160 and is adapted to have pressure exerted on a surface area of a portion thereof, such as a downhole surface 201a, thereby urging the coupling element 112 uphole. Therefore, the tubular wall 103 is correspondingly urged uphole and toward the injection segment 120. It is appreciated that at least a portion of the downhole surface 201a of the coupling element 112 is preferably transverse relative to the string fluid passage 165 such that fluid pressure within the string fluid passage can exert pressure thereon to urge the coupling element 112 uphole. For example, the downhole surface 201a can include an annular surface area, shown in
[0201] It is noted that the injection segment 120 remains axially aligned with the valve housing 102 due to its connection with the first tubing segment 50a. More specifically, the first segment head 166a is shaped and sized to block rotation of the longitudinal axis thereof such that the tubing string segments 50a, 50b, the injection segment 120 and the tubular wall 103 remain substantially parallel to one another during operation of the valve assembly 100.
[0202] Still referring to
[0203] In this implementation, the first segment mandrel 168a is slidably mounted within the partition ring 170 such that axial movement of the valve housing is permitted (e.g., the first segment mandrel 168a slides through the central aperture 172 during axial displacement of the valve housing 102). In addition, a seal 119 can be arranged between the partition ring 170 and the first segment mandrel 168a such that fluid flow between the partition ring 170 and first segment mandrel 168a is prevented. The partition ring 170 can include a groove into which the seal 119 is inserted. It is appreciated that the first segment head 166a is provided on a first side 171, such as an uphole side, of the partition ring 170, and that the first segment mandrel 168a extends through the central aperture 172 and beyond a second side 173, such as a downhole side, of the partition ring 170.
[0204] In some implementations, the second tubing segment 50b is positioned on the second side 173 of the partition ring 170 and is connected to the first tubing segment 50a. As will be described below, the second tubing segment 50b is secured to the first tubing segment 50a and configured to facilitate uphole movement of the valve housing 102, via the actuation assembly 160, in order to actuate the sealing element 155. In this implementation, the second tubing segment 50b includes the second segment head 166b slidably mounted within the valve housing 102 (e.g., on the second side 173 of the partition ring 170) such that axial movement of the valve housing 102 relative to the second segment head 166b is enabled. Moreover, the second tubing segment 50b can be provided with one or more seals 119 (e.g., O-rings) arranged between the second segment head 166b and the valve housing 102 such that fluid flow is prevented therebetween, and thereby promoting fluid pressure against the downhole surface 201b of the partition ring 170.
[0205] As previously mentioned, the partition ring 170 is adapted to abut against the first segment head 166a to limit the range of motion of the valve housing 102, which in turn limits the range of motion of the coupling element 112 (e.g., due to its connection to the tubular wall 103). It is further noted that exerting pressure on both the coupling element 112 (e.g., on the downhole surface 201a) and the partition ring 170 (e.g., on the downhole surface 201b) facilitates uphole movement of the valve housing 102. More specifically, increasing the surface area on which fluid pressure can be applied correspondingly increases the overall force applied on the actuation mechanism 160 and promotes uphole movement of the valve housing 102 to actuate the sealing element 155. In the illustrated implementation, fluid flowing along the valve assembly 100 can exert pressure on the downhole-facing surfaces 201a, 201b (see
[0206] In some implementations, the valve assembly 100 comprises fluid compartments 180 defined within the valve housing 102 and being in fluid communication with the fluid passages of the valve assembly (e.g., the injection segment passageway 126, the string fluid passage 165 and/or the valve housing fluid passage 106) and the surrounding reservoir. Fluids can thus flow into, or from, these fluid compartments to create a pressure differential on one or more components positioned within the housing 102. In this implementation, the valve assembly 100 includes one or more pressurizing compartments 182 configured to receive fluid being injected (e.g., pumped) within the well, thereby creating fluid pressure within these compartments 182. At least one component of the actuation assembly 160 communicates with the pressurizing compartment 182 such that the pressure within the compartment exerts a force on the corresponding portion of the actuation assembly 160 to move it downhole and/or uphole, for example. The portion of the actuation assembly 160 that is in contact with the pressurized fluid can be the downhole-facing surfaces 210a, 201b, which can define an uphole side wall of the compartment 182.
[0207] As seen in
[0208] More particularly, the sealing engagement between the injection segment mandrel 124 and the coupling element 112 prevents fluid within the first pressurizing compartment 184 from flowing in the uphole direction, and the first segment head 166a is illustratively coupled between the injection segment mandrel and the tubular wall, thereby creating a seal and preventing fluid within the first pressurizing compartment 184 from flowing in the downhole direction. As illustrated, the injection segment mandrel 124 can be provided with one or more openings 128 (also seen in
[0209] Still referring to
[0210] In some implementations, the valve assembly 100 includes a second pressurizing compartment 188 configured to receive fluid to increase the pressure therein and exert a force on the partition ring 170 (e.g., on the downhole surface 201b thereof). In this implementation, and with reference to
[0211] It is appreciated that moving the valve housing 102 uphole increases the volume of the second pressurizing compartment 188. It is also noted that the openings 169 of the first segment mandrel 168a remain in fluid communication with the second pressurizing compartment 188 due to the connection between the first segment mandrel 168a and the second segment head 166b. Moreover, in this implementation, the second segment head 166b can be relatively tubular, and provided with an annular projection 177 extending radially outwardly therefrom, and therefore having a greater outer diameter than the other portions of the second segment head 166b. More specifically, the annular projection 177 can have an outer diameter which is substantially the same as the tubular wall 103 of the valve housing 102, thereby preventing entry of the annular projection 177 within the valve housing 102 and limiting axial movement of the valve housing 102 in the downhole direction.
[0212] In this implementation, the annular projection 177 has an abutment surface adapted to have the downhole end of the tubular housing 103 abut thereon. In this implementation, the second segment mandrel 168b corresponds to the downholemost component of the valve assembly 100, and is thereby adapted to be connected to a separate component of the wellbore string. For example, in this implementation, the second segment mandrel 168b can be shaped and adapted to receive a conduit therein, or extend into the separate conduit, although it is appreciated that other components can be connected to the second segment mandrel 168b, such as another valve assembly 100. The conduit can be connected to the second segment mandrel 168b via any suitable method, such as via threaded connectors, via interference fit, via slots and key connection or via fasteners, for example)
[0213] In some implementations, the valve housing 102 can be releasably secured to the tubing string segments 50 prior to a fluid pressure threshold being reached for displacing the valve housing 102 uphole. For example, in the present implementation, the tubular wall 103 can be releasably secured to the first segment head 166a via one or more shear pins 190. It is appreciated that the shear pins 190 are configured to break once a predetermined force is applied thereto (i.e., to the piston head). As such, the valve assembly 100 can be run downhole without having its position be set along the wellbore as soon as fluid flows into the pressurizing compartments 182, and can thus be positioned in the desired location and subsequently set. In some implementations, the actuation assembly operation pressure, i.e., the pressure required to displace the valve housing 102 uphole to actuate the sealing element 155 can be between about 250 psi and 5000 psi, for example. It is appreciated that shear pins 190 can be additionally, or alternatively, connected to the second segment head 166b, or that other mechanisms for releasably connecting the valve housing can be used.
[0214] In some implementations, once the tubular wall 103 is released (e.g., once the shear pins break), the valve housing 102 can be moved axially. As described above, fluid can flow into the pressurizing compartments such that fluid pressure along the fluid passage (and within the fluid compartments) is greater than the pressure within the surrounding reservoir, thereby moving the housing uphole. However, if fluid pressure within the reservoir and/or within the outlet compartment becomes greater than the fluid pressure within the fluid passage (e.g., within the pressurizing compartments), the valve housing 102 can revert back to the run-in position, seen in
[0215] It is noted that providing a substantially constant fluid flow along the wellbore can imply having a substantially constant flow of fluids being injected into the reservoir through the injection port 125. This configuration can be useful in various operations, such as in waterflooding operations for hydrocarbon recovery, geothermal circulation of a working fluid, solvent injection into a reservoir (e.g. to facilitate dissolution of reservoir minerals in production fluid), subsurface disposal of waste fluids or CO2, in situ mining, CO2 flooding, water alternating gas flooding, polymer flooding, straddle stimulation, acidizing, among other applications. It is further noted that, as described above, ceasing injection of fluid can cause the valve housing 102 to at least partially revert to the run-in position, thereby disengaging the sealing element 155 from the casing. Therefore, it is appreciated that the valve assembly 100 can be retrieved from down the wellbore once the sealing element 155 has disengaged the casing. It should thus be understood that the actuation assembly 160 can be configured to set the position of the valve assembly down the well (e.g., via fluid-pressure activation of the sealing element), and also enable recovery of the valve assembly 100 by allowing the sealing element to disengage the casing and unset the position of the valve assembly 100. It should further be noted that, if the sealing element disengages the casing (e.g., unintentionally or accidentally), the pressure within the wellbore can be increased in order to re-engage the sealing element and continue downhole operations.
[0216] As seen in
[0217] It is also noted that, when the breakable barrier 130 is present, the valve assembly 100 is initially in the closed configuration. Once the predetermined pressure threshold is reached, the breakable barrier 130 is defeated and collapses, bursts, is removed, or otherwise breaks, thus operating the valve in the open configuration. It is appreciated that the breakable barrier 130 can be fully broken or removed from the injection port 125 to provide a fully opened port. However, in some implementations, the breakable barrier 130 can be configured to partially collapse in order to have a portion thereof remain within the injection port 125 to at least partially obstruct fluid flow between the passage 126 and the reservoir. As such, the valve assembly 100 can be toollessly operated from the closed configuration to the open configuration via an increase in the fluid pressure within the valve. It is noted that, once a flow of fluid is initiated along the wellbore, the valve does not require intervention from downhole tools, such as shifting tools deployed on coiled tubing to transition the valve to the open configuration. In other words, the valve is fluid pressure-activated from the closed configuration to the open configuration.
[0218] In some implementations, the breakable barrier 130 can include a burst disc 132 shaped and configured to cover or occlude the injection port 125, although other configurations are possible. For example, one or more plugs can be installed within the injection port 125 and retained therein using shear pins or any other similar and suitable device for retaining the plug in place. The breakable barrier 130 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 injection port 125 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 injection port 125. It is appreciated that each valve assembly 100 can be provided with the same type and design of breakable barrier 130, or with different types or designs of breakable barriers depending, for example, on the location of the valve along the wellbore. Each injection port 125 and barrier 130 can be identical for each valve provided along the well, or one or more of the ports and/or barrier 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.
[0219] As seen in
[0220] The breakable barrier 130 can be provided with one or more seals 136 configured to prevent fluid from flowing through the injection port 120 when operating the valve in the closed configuration. In this implementation, the seal 136 can include an O-ring configured to be installed within the injection port 125. However, it is appreciated that other types of seals are possible and may be used, such as welding the barrier 130 within the port, installing the barrier 130 via compression fit, using shim stocks or any other suitable seal or sealing method. It is noted that interstices may be present between the burst disc 132, barrier body 134 and/or an inner surface of the injection port 125. In this implementation, the seal 136 (e.g., the O-ring) is provided on an inner side of the burst disc 132 (i.e., on the side of the fluid passage 126), although it is appreciated that seals can alternatively, or additionally, be provided on an outer side of the barrier 130.
[0221] In addition, still referring to
[0222] In addition, the injection segment 120 can further comprise a flow restriction component 140 provided in between the port 125 and the fluid passage 126 to restrict the flowrate from the passage 126 through the port 125 when the valve is in the open configuration. The flow restriction component 140 can take various forms. For example, the injection segment 120 can include a valve sleeve 142 with a restricted passage configured to control the flowrate of injection fluid being injected into the surrounding reservoir. In this implementation, the valve sleeve 142 is provided with a fluid channel 144 allowing fluid flow therethrough, and thus fluidly connecting the fluid passage 126 and the injection port 125. The fluid channel 144 can be 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 channel 144 can be elongated and configured such that the open configuration of the valve 100 corresponds to a choked configuration, where the fluid flowrate from the fluid passage 126 into the reservoir is restricted. The fluid channel 144 can take the form of a tortuous path that winds boustrophedonically across a portion of the valve sleeve 142. The tortuous path can have various other configurations.
[0223] Furthermore, in this implementation, the fluid channel 144 can be defined between an outer surface of the valve sleeve 142 and an inner surface of the injection segment 120 overlaying the valve sleeve 142. It should also be noted that, in this implementation, the valve sleeve 142 is securely connected within the injection segment 120 (e.g., via press-fitting) such that the fluid channel 144 remains aligned with the injection port 125 before, during and after injection fluid has effectively been injected into the reservoir. However, it is appreciated that other configurations are possible and may be used, such as slidably connecting the valve sleeve 142 within the injection segment 120 such that the valve sleeve can be shifted between two or more positions for selectively aligning the fluid channel 144 with the injection port 125 (e.g., the proximal portion 125C).
[0224] In the present implementation, referring to
[0225] In some implementations, the port 125 and the breakable barrier 130 can also be configured to provide little to no flow restriction to injection fluids, while the flow restriction component (e.g., elongated fluid channel having a tortuous path) provides flow restriction through that valve. This arrangement can facilitate fluid pressure activation of the valves at reasonable flowrates in a well completion system with multiple valve assemblies 100 arranged along its length. Once a first breakable barrier is ruptured due to fluid pressures, the port 125 can allow full flow of the injection fluid into the reservoir at that open valve which could hamper fluid activation of the other valve assemblies. However, the flow restriction component controls the fluid injection rate through the open valve assembly and thereby enables the fluid pressure to be maintained at sufficient levels to rupture the breakable barriers of the other valve assemblies at reasonable flowrates. The flow resistance therefore prevents over-injection of the fluid via the early activated valve assemblies and enables pressure to be maintained along the wellbore. The flow restriction component can thus be designed to provide the desired flow restriction during the initial valve opening phase of the process to enable flowrates to be kept within a certain range.
[0226] In addition, since the flow restriction component can cause a pressure drop, e.g., across the length of the tortuous path, this pressure drop can be taken into account when designing the system and when providing the fluid pressure, e.g., using pumps at surface. For example, the fluid channel 144 can be designed and tested in order to determine the flowrate restriction and the pressure drop across the channel at different potential conditions such as fluid types, flow rates, temperatures, pump types, pressure drops in upstream conduits, and the like. Thus, the adequate fluid pressure and flow rates can be delivered in order set the position of the valve assembly (e.g., via actuation of the sealing element) and/or break the barrier 130 of each of the desired injection valves. It should be noted that providing the adequate fluid pressure can be further based on various characteristics of the reservoir, such as the reservoir pressure and the reservoir permeability. For example, the lower the reservoir pressure, the higher the flowrate will be through the injection ports for the same restriction.
[0227] In addition, it is possible to provide a well completion system where some valve assemblies are different from others in terms of the flow restriction and pressure at which the barrier breaks. For instance, one or more valves near the toe of the wellbore may have a lower breakage pressure compared to one or more valves as the heel, to account for pressure drop effects along the wellbore. This could be done by providing different burst discs for different valves. In another example, one or more valves near the toe could have flow restriction components that provide lower flow restriction (e.g., via shorter or less tortuous paths) compared to those closer to the heel. It is also possible to provide valves with particular flow restriction and fluid breakage pressures at particular locations along the wellbore as per the well operator's specifications to account for certain geological or well characteristics (e.g., thief zone, water-bearing zone, natural fracture(s)).
[0228] In some implementations, different burst discs 132 and/or different types of breakable barriers 130 can be installed for each injection segment 120. For example, valves installed further downhole (e.g., closer to the toe of the wellbore) can be provided with burst discs configured to break at lower pressures than burst discs of valves installed proximate the heel of the wellbore. As such, surface injection pressures can be maintained at reasonable levels, since the pressure required to open the valves proximate the toe of the wellbore is not required to be the same as the pressure required to open the valves proximate the heel.
[0229] In addition, the flow restriction component can have a different configuration for each or some of the valve assemblies along the wellbore. For example, the valves proximate the heel can be provided with a flow restriction component configured to cause a predetermined pressure drop, whereas the valves further downhole can have flow restriction components configured to cause a lower pressure drop (e.g., with a shorter channel or a larger orifice), and where the valves furthest downhole can be provided with an even lower pressure drop or possibly a straight opening extending between the wellbore passage and the reservoir. It is also appreciated that a nozzle, such as a carbide nozzle, can be installed within one or more of the injection ports 125 to create a pressure drop, which may be in addition to or as an alternative to the flow restriction component. Moreover, it is noted that a single valve can be provided with two or more injection ports 125 with respective breakable barriers 130, therefore increasing the injection rate into the reservoir of that valve. In a multi-port injection valve, there may be a distinct flow restriction component for each port or a flow restriction component that feeds into multiple ports.
[0230] Now referring to
[0231] With reference to
[0232] In this implementation, the ratcheting mandrel 212 is slidably mounted within the valve housing 102 and coupled to the second segment mandrel 168b in a manner such that uphole movement of one of the valve housing 102 is enabled as the ratcheting mandrel 212 engages the tubular wall 103. In other words, the valve housing 102 (e.g., the tubular wall 103, the coupling element 112 and the partition ring 170) can be moved uphole using fluid pressure to actuate the sealing element, while the ratcheting mandrel 212 prevents downhole movement of the valve housing 102, for example, when the fluid pressure within the valve assembly is reduced and/or during production operations. As seen in
[0233] In some implementations, the uphole end of the ratcheting mandrel 212 can be coupled between the second segment mandrel 168b and the tubular wall 103, such as via compression fit. Therefore, it is noted that the outer surface of the ratcheting mandrel 212 engages the inner surface of the tubular wall 103, and that the inner surface of the ratcheting mandrel 212 engages the second segment mandrel 168b. The uphole end of the ratcheting mandrel 212 is therefore in sealing engagement with the tubular wall 103 and the second segment mandrel 168b such that fluid flow between these components is prevented. As seen in
[0234] Still referring to
[0235] Referring to
[0236] In some implementations, the pegs 232 can be disengaged, via movement of the release sleeve 236, and allowed to move (e.g., fall) into the string fluid passage 165 and flow along the wellbore. Alternatively, a portion of the pegs 232 can abut against a portion of the second segment mandrel 168b when disengaged from the ratcheting mandrel 212, thereby releasing the ratcheting mandrel 212 and maintaining the pegs 232 in position around the second segment mandrel 168b. As seen in
[0237] Referring to
[0238] Referring now to
[0239] In addition, the implementations of the release mechanism 230 shown in
[0240] Referring now to
[0241] In some embodiments, the release mechanism 530 of a given valve assembly is selectively and independently operable relative to the release mechanism of another valve assembly positioned along the wellbore string. As such, each valve assembly can be disengaged from the wellbore independently, which can prevent sealing elements from one or many valve assemblies from getting stuck or dragging along the inner surface of the wellbore, thus facilitating retrieval of the wellbore string from the wellbore. Using a downhole shifting tool, for example, each release sleeve 536 can be independently shifted from a secured position (
[0242] In some implementations, the sealing element 155 can remain at least partially engaged with the wellbore after operation of the release mechanism. As such, it may be required to assist in unsetting the sealing element, to unset the valve assembly. In an exemplary implementation, the sealing element can be bonded to a tubing string segment 50, such as to the injection segment 120, thereby defining a bonded tubing string. Once the release mechanism 530 has been operated to unlock the locking assembly 500, the bonded tubing string can be shifted (e.g., pulled uphole), which in turn pulls on the sealing element, to assist in unsetting the sealing element from the wellbore. In other words, the sealing element can be manipulated, directly or indirectly, to be moved away from the actuation assembly, such as by pulling on the bonded tubing string.
[0243] In some implementations, the release sleeve 536 is sheared from within the tubing string element 50 using a shifting tool (e.g., deployed on coiled tubing, wireline, slickline, tubing or a dart) to enable sliding movement therealong. Once sheared and moved to the released position, the shifting tool is adapted to travel along the wellbore string to any subsequent valve assembly to shear and move respective release sleeves 536. The valve assemblies can therefore be selectively (e.g., via operation via the shifting tool) and independently (e.g., one by one without affecting the other valve assemblies) disengaged from the wellbore to enable retrieval of the wellbore string. It is appreciated that using a shifting tool to operate the release mechanisms 530 enables operators at surface to know when a valve assembly has been released from the wellbore, which can increase accuracy and efficiency of downhole operations, such as during retrieval of the wellbore string and valve assemblies.
[0244] In order to prevent the sealing element from reengaging the wellbore, the valve assembly can include an isolation device configured to isolate fluid access to the actuation assembly, thereby preventing fluid-pressure operation thereof. For example, the actuation assembly can include a piston assembly, which defines pressure chambers or compartments 582 in which fluid flows to exert pressure on surfaces of the piston(s) for operation thereof. In such implementations, the isolation device can be adapted to deactivate the piston assembly by blocking access to these pressure compartments 582. The isolation device can include a sliding sleeve adapted to be shifted to isolate the pressure access to the piston assembly such that tubing pressure cannot apply force to the piston. This can enable fluid circulation along the tubing string without having to provide fluid pressure to the sealing elements of the valve assemblies.
[0245] In some implementations, the internal profile of the release sleeve 536 can be customized from one valve assembly to another such that a first type of shifting tool can be deployed to shear and move a select number of release sleeves, while another type of shifting tool can be deployed to move other release sleeves, as so on. It should also be noted that the release sleeves can be positioned and adapted to be sheared and shifted in either the downhole direction, the uphole direction, or both.
[0246] With reference to
[0247] The sealing element 655 is operatively connected to the fluid conduits and is operable between a run-in configuration (
[0248] As mentioned, the actuation member 662 can be connected to the housing 604 such that the housing is also slidably coupled to the fluid conduits. In this implementation, the housing can include an internal projection 606 defining a second radial surface 606a on which fluid can exert pressure to move the actuation member toward the sealing element for engagement therewith. As such, it is noted that the housing and actuation assembly can define a double-piston assembly, where two radial surfaces enable fluid to exert pressure thereon. However, it is appreciated that a single-piston assembly can be used to enable movement of the actuation member toward the sealing element for engagement therewith.
[0249] In this implementation, the actuation assembly 660 further comprises a blocking member, or gauge ring 666 releasably secured to the fluid conduits and adapted to engage the sealing element 655 opposite the actuation member 662. In other words, the sealing element is positioned between the blocking member and the actuation member, and as the actuation member 662 is moved toward the sealing element 655, the blocking member prevents movement of the sealing element, thereby squeezing the sealing element therebetween. The sealing element then extends outwardly under the squeezing pressure to engage the inner surface of the wellbore, which corresponds to operating the sealing element from the run-in configuration to the operational configuration.
[0250] The downhole component 600 also includes a locking mechanism 670 operatively connected to the actuation member 662 and configurable in a locked configuration to prevent disengagement of the actuation member from the sealing element, and a release mechanism 680 operatively connected to the blocking member 666 and being operable to release the blocking member from the fluid conduits to enable movement thereof away from the actuation member to enable configuration of the sealing element from the operational configuration to the release configuration. It should therefore be understood that the actuation member is adapted to move toward the sealing element while the blocking member is secured on the other side of the sealing element for configuration thereof in the operational configuration. Moreover, the blocking member is releasable from the fluid conduits and adapted to move away from the actuation member to enable the sealing element to relax and disengage the inner surface of the wellbore, which corresponds to operating the sealing element from the operational configuration to the released configuration).
[0251] Still referring to
[0252] The blocking member 666 is adapted to remain secured to the fluid conduits, thereby preventing the sealing element from sliding along the fluid conduits, thereby forcing it to extend outwardly as the actuation member is in engagement therewith. Upon operation of the release mechanism 680, the blocking member 666 is released from the fluid conduit and is allowed to slide therealong. As such, the sealing element can relax and push against the blocking member (e.g., in the downhole direction) as it moves to the released configuration to disengage the wellbore. It is noted that the actuation member 662 remains locked in place via the locking mechanism 670 (e.g., the ratcheting system 672), thereby preventing uphole movement of the sealing element when moving to the released configuration.
[0253] In this implementation, the release mechanism 680 includes a release member 682 provided about at least one of the fluid conduits and adapted to engage and secure the blocking member 666. The release mechanism 680 further includes a biasing member 684 adapted to bias the release member 682 in engagement with the blocking member 666 to maintain the blocking member in position prior to operation of the release mechanism. In this implementation, the release member 682 includes pegs 683 extending through a thickness of the fluid conduit to communicate with the conduit passage. Each peg 683 having an outer engagement profile 685 configured to extend into a complementarily-shaped recess 686 defined along an inner surface of the blocking member 666. The outer engagement profile 685 being adapted to prevent movement of the blocking member when engaged with the complementarily shaped recess 686. The biasing member 684 is slidably coupled within the fluid conduit and is adapted to overlay, bias and support the pegs 683 in engagement with the complementarily shaped recess from within the conduit passage.
[0254] As seen in
[0255] In this implementation, the release sleeve 688 includes an inset region 690 defined along the outer surface thereof. As seen in
[0256] In some implementations, once the release element 655 has relaxed and disengaged the wellbore following the operation of the release mechanism, the actuation member 662 is no longer capable of engaging the sealing element. Therefore, normal operations can be conducted along the wellbore string, such as fluid injection, and the actuation member will no longer be fluid-pressure activated to engage the sealing element. In this implementation, the internal projection 606 of the tubular wall 605 is adapted to abut against a fluid conduit head portion which extends radially outwardly to contact the inner surface of the tubular wall 605. It is thus noted that downhole movement of the tubular wall 605, and therefore of the actuation member 662, is prevented (e.g., the piston assembly bottoms out). In other words, the fluid conduits can include structural components which define a stop against which the actuation assembly is adapted to abut to prevent further engagement of the sealing element.
[0257] It should be noted that the downhole component 600 is illustratively not provided with a port or a valve enabling fluid communication between the fluid passage and the reservoir, although alternate implementations can include one or more ports. The downhole component can be used to seal desired sections of the wellbore to define intervals therealong, and can be used in cooperation with the valve assemblies described herein. For example, the wellbore string can include downhole components and valve assemblies provided in alternance along the wellbore string. Any other configurations of the wellbore string using any one of the described implementations (downhole components and/or valve assemblies), or combination thereof, are also possible.
[0258] While some possible implementations of locking and release mechanisms have been described herein, it is noted that various changes and alternative implementations could also be used. For instance, the locking mechanism can be removed from the downhole component and/or valve assembly, with the actuation assembly being held in engagement with the sealing element via continuous pressure exerted on the actuation member, such as via a generally continuous injection of fluid down the wellbore string. The release mechanism described herein is mechanically operated via a shifting tool. However, it is appreciated that the release sleeve can be designed to define radial surfaces adapted to have fluid exert pressure thereon such that the release sleeves are fluid-pressure operable. It should be noted that fluid-pressure operable release sleeves can be operated generally simultaneously along the entire wellbore as the wellbore pressure is increased. Alternate implementations of the release mechanism are also possible, such as releasing the blocking member via a rotational movement. For example, the blocking member can be at least partially threaded onto the fluid conduits, and can therefore be rotated (e.g., unscrewed) along the fluid conduits to move away from the sealing element.
[0259] In addition, while the locking and release mechanisms described herein have been shown associated with valve assemblies or downhole components having various other features, such as injection segments, actuation assemblies, and various other components, it is noted that implementations of the locking and release mechanisms can be incorporated into other valves or downhole tools where such axial locking and release may be used, e.g., for setting and then releasing a sealing element such as a packer.
[0260] It should also be noted that the position of the various components can vary from one implementation to another. For instance, the release mechanism shown in
[0261] Referring more specifically to
[0262] It is noted that the teeth of the third and fourth sets of angled teeth 217, 218 are illustratively larger than the teeth of the first and second sets of angled teeth 214, 216 such that movement and/or disconnection of the ratcheting ring 250 relative to the ratcheting mandrel 212 is easier than movement and/or disconnection of the ratcheting ring 250 from the tubular wall 103. In other words, the smaller set of teeth (e.g., the first and second sets of angled teeth 214, 216) requires a smaller range of motion to disengage the teeth from one another, relative to the larger set of teeth (e.g., the third and fourth sets of angled teeth 217, 218), which requires a larger range of motion. As such, the smaller set of teeth facilitate uphole movement of the ratcheting ring 250 and valve housing 102 relative to the ratcheting mandrel 212, while the larger set of angled teeth are adapted to maintain the ratcheting ring 250 in position relative to the tubular wall 103. In addition, the larger set of angled teeth (e.g., the third and fourth sets of angled teeth 217, 218) can be adapted to cooperate to together to push the second set of teeth 216 downward and into the first set of teeth 214, thereby further securing the teeth together, and preventing downhole movement of the valve housing 102.
[0263] Referring to
[0264] As seen in
[0265] In this implementation, the production port 265 includes a plurality of openings, such as slits 270, defined through the tubular wall 103. In some implementations, the slits 270 are provided at regular intervals around the tubular wall, although other configurations are possible. As seen in
[0266] With reference to
[0267] Referring back to
[0268] It should be noted that the check valve 282 enables for both injection and production operations to be accomplished using the valve assembly 100. More specifically, once the valve assembly is installed downhole, injection operations can be initiated via the injection segment, as described above. Injection of fluids into the reservoir can then be halted, with the valve housing 102 being locked in place via the locking assembly 200, and production operations can be initiated via the production segment. In the present implementations, it is noted that injection fluid and production fluid alternatively flow along the same fluid passage through the valve assembly 100. As such, it should be understood that the valve assembly 100 is configured to enable asynchronous injection and production operations, such as asynchronous frac-to-frac operations, for example although other operational configurations and processes are possible. For example, the valve assembly can be used for geothermal applications. It is also noted that the valve assembly can be used in relation to applications where the formation (e.g., the reservoir) is not required to be fractured but has a permeability that enables fluid injection or includes naturally formed fractured.
[0269] It should be appreciated from the present disclosure that the various implementations of the valve assembly and related components enable the valve assembly to be positioned at a desired location along the wellbore prior to operating the sealing element via the fluid pressure-activated actuation system. The flow restriction component of the injection segment delays the flow of fluid into the reservoir and enables the sealing elements of each valve assembly to be operated prior to injection operations being initiated. The sealing elements are selectively operable to engage the wellbore surface, and independently and selectively operable to disengage the wellbore surface such that the downhole component (e.g., a packer assembly and/or a valve assembly), along with the sealing element, are retrievable from down the wellbore. Moreover, the dual-piston assembly of the actuation assembly allows the sealing element to be operated at lower operational fluid pressures due to the additional surface area of the second piston (e.g., when compared to single-piston assemblies). The present valve assembly facilitates the deployment of wellbore systems due to the combination of the sealing element within the structure of the valve used to inject and/or produce fluids.
[0270] The present disclosure may be embodied in other specific forms. 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 sealing elements installed on the valve assemblies are typically hydraulically set and are configured to set at a pressure below the threshold pressure of the burst discs of the injection segments. However, it is noted that other types of sealing elements can be used, such as swellable sealing elements configured to be set via absorption of fluids, and are therefore not dependent on fluid pressure. Using swellable sealing elements can enable installation of the valve assemblies downhole in the open configuration (e.g., without the breakable barrier) since fluids being pumped downhole would be initially absorbed by the swellable sealing elements. The valve assembly described herein can also be used for various downhole operations. In some implementations, the valve assembly is used as part of hydrocarbons recovery operations, where injection fluids are injected to enable the production of fluids including hydrocarbons. It should however be noted that the valve assembly can be used as part of other operations, such as gas flooding operations (e.g., using CO2), waterflooding operations, geothermal operations and acid solution mining operations, for example.
[0271] 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.
[0272] 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.
[0273] 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.
[0274] In addition, although the optional configurations as illustrated in the accompanying drawings comprises various components and although the optional configurations of the valve assembly 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 valve assembly, and corresponding parts, as briefly explained and as can be easily inferred herefrom, without departing from the scope of the disclosure.