BACKGROUND

[0001] A variety of tools are used in constructing and operating oil and gas wells. For example, a well may be drilled with a drill bit at the lower end of a string of tubular drill pipe that is progressively assembled to reach the desired well depth, and then removed. During drilling, fluid is circulated through the drill pipe to lubricate the drill bit and remove cuttings. After drilling, a portion of the well is sometimes lined with a string of relatively large diameter tubular casing that may be lowered into the wellbore and secured by circulating cement downhole and through an annulus between the casing and formation. This casing string reinforces the wellbore and may be perforated at selected depths and intervals for extracting hydrocarbon fluids from a production zone(s) of the formation. Uncased portions of a well are referred to as “open hole,” and some wells are entirely open hole (no casing). An open hole portion of the well may be stimulated by sealing oft' and delivering fluid to selected production zones. Then, a production tubing string may be run into the well to the production zone, providing a flow path to a wellhead through which the oil and gas can be produced.

[0002] In many wellbore operations, it is necessary to seal between adjacent surfaces between tubular equipment and/or with the wellbore. For example, during fracturing or cementing operations various fluids are pumped into the well and hydraulically forced out into a surrounding subterranean formation. This typically requires first sealing the wellbore to provide zonal isolation. Wellbore isolation devices, such as packers, bridge plugs, and fracturing plugs (i.e., "frac" plugs) are designed for these general purposes. Such wellbore isolation devices maybe used in direct contact with the formation face of the well or with a string of casing that lines the walls of the well. A universal challenge in downhole sealing systems is to design robust mechanisms that fit within the tight downhole confines.

BRIEF DESCRIPTION OF THE DRAWINGS

[0003] These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the method.

[0004] FIG. 1 is an elevation view of a well system in which one or more well tools, such as a packer, may be deployed to seal along a wellbore. [0005] FIGS. 2A and 2B are section views of a well tool lowered into the wellbore on the tubular conveyance from the surface of the well site.

[0006] FIG. 3 is an enlarged view of the portion of well tool enclosed in FIG. 2B.

[0007] FIG. 4 is an enlarged view of the well tool further detailing an example of the actuation port and plug.

[0008] FIG. 5 is a section view of the well tool wherein a shifting tool has been run down into the through bore to sever the plug to open the actuation port.

[0009] FIG. 6 is a section view of the well tool after the plug has been sheared by the sleeve to expose the expandable material to an activation fluid.

[0010] FIG. 7 is a section view of the well tool in an alternative configuration using a burst disk instead of a plug to initially close the actuation port.

[0011] FIG. 8 is a section view of the well tool using a dissolvable plug to initially close the actuation port.

[0012] FIG. 9 illustrates a hydraulic fracturing operation using two of the disclosed packers.

DETAILED DESCRIPTION

[0013] A tool string comprising one or more well tools may be lowered into a wellbore on a tubular conveyance. The tubular conveyance may include a long tubular conduit, such as a tubing string or coiled tubing, extending from a surface of the wellsite (i.e., surface). The conveyance supports the weight of the tool string and allows fluid flow to and from the tool string. The well tool(s) each define a through bore in line with the tubular conveyance for fluid flow through the tool string, such as to deliver service fluids downhole from surface and to produce well fluids from the formation up to surface. The tool string may include a hydraulically actuatable tool feature, such as a wellbore sealing device (e.g., a packer), a sliding sleeve moveable to open or close, or any other moveable tool feature coupled to a tool body. The well tool may also include an actuating mechanism for operating the actuatable tool feature in response to fluid pressure applied to an actuation port in communication with the tool’s through bore.

[0014] In examples discussed below the actuatable tool feature is a packer, and the actuating mechanism in that context may be referred to as the setting mechanism for setting the packer. The packer includes a sealing element (e.g., packer elements) for sealing an annulus between the tool string and the wellbore. The setting mechanism may include a setting chamber for driving an actuator, such as a piston-driven sleeve. Fluid pressure may be provided to the setting chamber via the actuation port located along the through bore of the tool string to set the downhole tool(s) in the wellbore. Setting may comprise urging the sealing element into engagement with the wellbore. A service fluid may then be delivered along the through bore of the tool at a fluid pressure greater than the fluid pressure used to set the sealing element.

[0015] Aspects of this disclosure include systems and methods for closing off an actuation port with an expandable material after setting the packer or other downhole tool, to isolate the actuating mechanism from increased fluid pressures along the through bore of the tool string. For example, in certain wells, such as open hole systems with hydraulic fracturing (“fracking”) jobs, packers are sometimes required to have a relatively low setting pressure, such as on the order of 5,000 pounds per square inch (psi). The fracking pressures may be well in excess of that setting pressure, such as on the order of 15,000 psi. Closing off the actuation port after setting the packer, as taught herein, may avoid having to design and build the tool’s setting mechanism components to the higher pressure. For example, designing the setting mechanism to handle 15,000 psi of fracking pressure rather than just the 5,000 psi required to set the packer may require increasing a wall thickness and seal pressure ratings of the setting chamber, along with increasing an outer diameter (OD) of the packer. Conversely, the ability to design to a lower pressure specification may provide a range of technical benefits, such as increasing reliability and greater setting piston area to set the packer while reducing complexity, weight, external diameter and cost.

[0016] FIG. 1 is an elevation view of a well system 100 in which one or more well tools, e.g., a packer 120 with a setting mechanism, may be deployed downhole. A packer is just a non- limiting example of a hydraulically actuatable tool feature, and the setting mechanism is just a non-limiting example of a hydraulic actuating mechanism for discussion purposes. Two example locations 120a, 120b for the packer(s) 120 are shown, which may represent the same packer 120 at two different points as it is lowered into a wellbore 106, or two packers to be deployed to different locations along the wellbore 106. The wellbore 106 traverses a subterranean earth formation 108 in pursuit of hydrocarbons such as oil and gas. The well system 100 may include an oil and gas rig 102 arranged at the earth's surface 104 above the wellbore 106. The rig 102 may include a large support structure, such as a derrick 110, erected over the wellbore 106 on a support foundation or platform, such as a rig floor 112. Even though certain drawing features of FIG. 1 depict a land-based oil and gas rig 102, it will be appreciated that the embodiments of the present disclosure are useful with other types of rigs, such as offshore platforms or floating rigs used for subsea wells, and in any other geographical location. For example, in a subsea context, the earth’s surface 104 may be the floor of a seabed, and the rig floor 112 may be on the offshore platform or floating rig over the water above the seabed. A subsea wellhead may be installed on the seabed and accessed via a riser from the platform or vessel.

[0017] The wellbore 106 may extend through the various earth strata including formation 108. The wellbore 106 may be drilled according to a wellbore plan to reach one or more target formations, to avoid non-desirable formation features, to minimize footprint of the well at the surface, and to achieve any other objectives for the well. The wellbore 106 may follow a chosen path (i.e., the wellbore path) from where the wellbore 106 is initiated at the surface 104 (i.e., the “heel”) to the end of the well (i.e., the “toe”). The initial portion of the wellbore 106 is typically vertically downward as the drill string would generally be suspended vertically from the rig 102. Thereafter the wellbore 106 may deviate in any direction as measured by azimuth or inclination, which may result in sections that are vertical, horizontal, angled up or down, and/or curved. The term uphole generally refers to a direction along the wellbore path toward the surface 104 and the term downhole generally refers to a direction toward the toe at the end of the well, without regard to whether a feature is vertically upward or vertically downward with respect to a reference point. The wellbore path in FIG. 1 is simplified for ease of illustration, and is not to scale. In this example, the wellbore path includes an initial, vertical section 105, followed by at least one deviated section 115 downhole of the vertical section 105, which transitions from the vertical section 105 to a horizontal or lateral section 107 downhole of the curved section 115. Thus, the vertical section 105 is uphole of the curved section 115 and lateral section 107.

[0018] The wellbore 106 may be at least partially cased with a casing string 116 at selected locations within the wellbore 106, while other portions of the wellbore 106 may remain uncased. In FIG. 1, by way of example, the casing 116 is shown along just a portion of the vertical section 105 and the remainder of the wellbore 106 is shown as open hole. The casing string 116 may be secured within the wellbore 106 using cement. In other embodiments, the casing string 116 may be omitted entirely. [0019] The rig 102 may include a hoisting apparatus for raising and lowering equipment from the rig 102 on a tubular conveyance 114. The conveyance 114 may serve various functions, such as to lower and retrieve tools, to convey fluids, and to support electrical communication, power, and fluid transmission during wellbore operations. Conveyance 114 may include any suitable equipment for mechanically conveying tools such as the packer(s) 120. Such conveyance may include, for example, a tubular string made up of interconnected tubing segments, coiled tubing, or any combination of the foregoing. In some examples, conveyance 114 may provide mechanical suspension, as well as electrical and fluidic connectivity, for downhole tools like the packers 120a, 120b. The conveyance 114 may be used to lower one or more tools into the wellbore 106, i.e. run/tripped into the hole. When a wellbore operation is complete, or when it becomes necessary to exchange or replace tools or components of the conveyance 114, the conveyance 114 may be raised or fully removed from the wellbore 106, i.e., tripped out of the hole.

[0020] A variety of tool types may be configured according to this disclosure, including but not limited to packers. The example of packers includes production packers and service packers as non-limiting example variants. Suitable types of packers may include whether they are permanently set or retrievable, mechanically set, hydraulically set, and/or combinations thereof. As just one example, the packer(s) 120 may be production packers that will remain in the well during well production. Alternatively, the packer(s) 120 may be service packers used temporarily during well servicing, such as cementing, acidizing, or fracturing. When set, multiple packers 120 may be used to isolate zones of the annulus between wellbore 106 and a tubing string by providing a seal between production tubing and casing 116 or between production tubing and open hole. In examples, a packer may be disposed on production tubing.

[0021] FIGS. 2A and 2B are section views of an example configuration of the packer 120 as lowered into the wellbore 106 on the tubular conveyance 114 from the surface 104 of the well site. The packer 120 is split between FIGS. 2A and 2B so the bottom of FIG. 2A coincides with the top of FIG. 2B. The packer 120 includes an annular sealing section comprising a packer element 124 in FIG. 2A and a setting mechanism 140 in FIG. 2B for setting the packer 120. The packer 120 and optionally other tools supported from the conveyance 114 may be regarded as a tool string. Although only one packer 120 is shown for discussion, the tool string for some service operations may use multiple packers 120, such as on the order of between twenty and fifty packers for a hydraulic fracturing operation. The packer 120 is suspended on the tubular conveyance 114 extending from the surface 104. The packer 120 includes a tool body, which may comprise first and second mandrels 122 and 142 interconnected in this example by a section of tubing 130. The mandrels 122, 142 are used to support components of the packer 120 including its sealing element 124 and setting mechanism 140, respectively. The mandrels 122, 142 have respective through bores 121, 141 in line with the tubular conveyance 114. The tubular conveyance 114, mandrels 122, 142, and tubing section 130 cooperatively define a fluid communication pathway 125 that may extend from the surface 104 all the way down to the wellbore 106 below the packer 120. Fluids may be flowed along this fluid communication pathway 125 from surface 104 down the tubular conveyance 114 and through the packer 120 to the wellbore 106 below the packer 120. Well fluids from the wellbore 106 may alternately be flowed up the tubular conveyance 114, through the packer 120, to the surface 104.

[0022] The mandrel 122 may be directly coupled to the tubular conveyance 114. One or more packer components supported on the mandrel 122 include the sealing element 124 (which may include a plurality of individual sealing elements) disposed between upper and lower shroud portions 126, 128 that are axially spaced along the mandrel 122. The sealing element 124 is captured at opposing ends between the mandrel 122 and the respective shroud portions 126, 128, with the sealing element 124 spanning a gland opening between the shroud portions 126, 128. One or more slips or other anchoring mechanism (not shown) may be included in one or more embodiments for anchoring the packer 120 to the wellbore 106. The packer 120 is run into the wellbore 106 with the sealing element 124 (and slips, if they were included) in a run-in condition that closely conforms with an outer diameter (OD) of the packer 120 to provide clearance between the packer 120 and the wellbore 106.

[0023] The setting mechanism 140 will be used to urge the sealing element 124 and slips into engagement with the wellbore 106 at a selected wellbore depth. The setting mechanism includes an actuating sleeve 144 positioned radially outwardly of the mandrel 142, about the tubing section 130 (FIG. 2A), a piston 146 for driving the actuating sleeve 144, and a setting chamber 148 for applying fluid pressure to the piston 26. In the embodiment of FIGS. 2A-2B, a vacuum chamber 149 is included so as to prevent wellbore fluid from being able to come into contact with the expandable material. However, one skilled in the art will recognize that this is not required in all embodiments and a packer can be redesigned in many other ways without departing from the scope of the disclosure. A threshold level of fluid pressure required to set the packer (i.e., setting pressure) may be delivered to the setting chamber 148 by supplying pressurized fluid down the conveyance 114 to the internal through bore 141. The setting pressure is communicated from the through bore 141 to the setting chamber 148 via an actuation port 150. The setting pressure may thereby drive the piston 146 to urge the actuating sleeve 144 axially into engagement with the packer 120. The axially-driven actuating sleeve 144 thereby urges the sealing element 124 (and could be used to drive any slips, if included) outwardly into radial engagement with the wellbore 106.

[0024] FIG. 3 is an enlarged view of the packerenclosed by window 3 in FIG. 2B. The actuation port 150 fluidically couples the through bore 141 of the mandrel 142 with the setting chamber 148. The setting chamber 148 comprises an annular volume defined between the mandrel 142 and an outer housing 152 of the setting mechanism. Pressurized fluid may be supplied along the fluid communication pathway 125 from the surface of the well site, down the tubular conveyance and tool string, and to the setting mechanism 140. When the actuation port 150 is subsequently opened, pressurized fluid in the through bore 141 of the mandrel 142 may enter the setting chamber 148 through the actuation port 150. However, the actuation port 150 may be initially closed, such as with a plug 154, to isolate the setting chamber 148 while running into the wellbore. The plug 154 may be seated within the actuation port 150, such as with a threaded plug, a press-fit plug, or other fluid-tight plugging device or method. In another example, a burst disk may be provided to initially close the actuation port 150. The burst disk may be configured to rupture as the tubing pressure approaches the pressure rating of the burst disk. In yet another embodiment, the plug may comprise a dissolvable material that dissolves away after a certain amount of time thereby allowing tubing pressure to enter the setting chamber 148. In still another embodiment, a plug could be devised that is activated using electric signals or acoustic signals. These features may also be combined in various embodiments, e.g., a fluid capsule initially containing the activation fluid and configured to release the activation fluid to the actuation port in response to a fluid pressure applied from surface, a signal, a time delay, or combinations thereof. In an alternative embodiment, the plug may be absent altogether as the tool is run into the wellbore.

[0025] FIG. 4 is an enlarged view of the packerl20, further detailing an example of the actuation port 150 and plug 154. The plug 154 includes a plug body 155 that occupies the bulk of the volume of the actuation port 150. The plug 154 may be sealed with the actuation port 150 at seals 158 to help prevent intrusion of fluid into the setting chamber 148. The plug 154 also comprises a separable portion 156 protruding into the through bore 141. The separable portion 156 may be separated from the plug body 155, such as by shearing, breaking off, or otherwise separating the separable portion 156 from the plug body 155. In this example, a sleeve 160 is positioned within the through bore 141 about the separable portion 156 of the plug 154. To open the actuation port 150, a shifting tool (FIG. 5) may be used to shift the sleeve 160 axially upward to shear off the separable portion 156.

[0026] A quantity of expandable material 162 is disposed inside the actuation port 150, and more particularly, inside the plug body 155 in this example. The expandable material 162 may be retained within the plug body 155 or the actuation port 150 generally by any suitable structure or method, including but not limited to a cage or other fluid-permeable structure. The expandable material 162 may alternatively be welded in place or formed inside the plug or actuation port by additive manufacturing (i.e., 3D printing). In another example, the plug 154 may instead comprise a valve coupled to the actuation port 150, wherein a valve component (e.g., closure) comprises the expandable material. Once the actuation port 150 is open, an activation fluid may be supplied via the through bore 141 to react with the expandable material 162. The activation fluid may comprise any fluid to which the expandable material is configured to react. Examples of expandable materials and activation fluids are provided below. In some cases, the activation fluid may be well fluid present in the through bore 141 or entering the through bore 141 from below the tool. In other cases, the activation fluid may be a fluid delivered down through the tool string from surface. In still other cases, the activation fluid may be contained in a chamber adjacent to actuation port 150 and is contained by burst disks on either end. When the tubing pressure reaches the activation pressure of these burst disks, the activation fluid is released and comes into contact with the expandable material 162.

[0027] The expandable material 162 is configured to expand and seal off the actuation port over time when exposed to the activation fluid (which may be wellbore fluid). To close the actuation port 150, the expandable material may increase its volume, become displaced, solidify, thicken, harden, or a combination thereof. In this case, fluid pressure will initially be allowed to flow through the actuation port 150, either around or bypassing the expandable material 162, so that the setting pressure may be applied to the setting chamber 148. However, as the reaction proceeds between the expandable material 162 and activation fluid, the expandable will gradually close off the actuation port 150. Closing the actuation port 150 isolates the setting chamber 148. The expandable material, once set, may withstand pressures in excess of the setting pressure. In some examples, the expandable material may withstand pressures of at least twenty percent (20%) greater than the setting pressure. In some examples, the expandable material may withstand pressures of several times higher (e.g., up to three to five times higher) than the setting pressure, such as hydraulic fracturing pressures. Details and examples of expandable materials and activation fluids are further discussed below.

[0028] FIG. 5 is a section view of a portion of the packer 120, wherein a shifting tool 164 has been run down into the through bore 141 to sever the plug 154 to open the actuation port 150. The separable portion 156 of the plug 154 may now be sheared off by pulling up on the shifting tool 164 (to the left in FIG. 5).

[0029] FIG. 6 is a section view of a portion of the packer 120 after the plug 154 has been sheared by the sleeve 160 to expose the expandable material 162 to an activation fluid 161. The activation fluid 161 may be supplied downhole, such as from the surface of the wellsite or an intermediate location, along the through bore 141 to the actuation port 150. In one example, the activation fluid 161 may be the same pressurized fluid used to set the packer via the setting chamber 148. In another embodiment, the well completion fluid that is present in all wells may be formulated such that it already contains agents that will trigger the expansion of the expandable material 162 once plug 154 is severed and the expandable material 162 comes into contact with the fluid in the tubing. The reaction of the expandable material 162 with the activation fluid 161 may occur over a longer period of time than required to set the packer, so that the packer may be set before the expandable material 162 closes off the actuation port 150.

[0030] In another example, a first fluid may be delivered along the through bore 141 to set the packer before another fluid. The first fluid may be non-reactive with the expandable material 162 (i.e., not an activation fluid). After setting the packer with the pressurized first fluid, a second fluid comprising the activation fluid that is reactive with the expandable material may be delivered along the same through bore 141, with enough of the activation fluid entering the actuation port 150 to activate the expandable material 162.

[0031] In yet another example, an activation fluid 161 A may initially be captured for controlled release, such as in a capsule 163. The capsule 163 may be burst in response to some control action. For example, the optional capsule 163 containing the other activation fluid 161 A may be burst by applying a bursting pressure. In one example, the capsule may burst at or below the setting pressure, so that the activation fluid 161 A is released from the optional capsule 163 once sufficient fluid pressure is applied to set the packer. In another example, the bursting pressure may be at least slightly larger than the setting pressure, allowing the packer to first be set using the setting pressure before increasing pressure to release the activation fluid 161 A. The capsule 163 or other isolated activation fluid storage area may be located at any convenient location for fluid communication with the actuation port 150 and the location shown is by way of example only.

[0032] FIG. 7 is a section view of the packer 120 in an alternative configuration using a burst disk 166 instead of a plug to initially close the actuation port 150. The burst disk 166 is configured to rupture as a tubing pressure in the through bore 141 approaches a pressure rating of the burst disk 166. The pressure rating of the burst disk 166 may be selected with respect to other design pressures, such as with respect to the setting pressure of the packer. The pressure rating of the burst disk 166 may at least be set higher than pressures expected in the through bore 141 when running in hole, to help avoid inadvertently opening the actuation port 150. The pressure rating may be set equal or similar to the setting pressure, so that application of the setting pressure will rupture the burst disk and then set the packer. Once the burst disk 166 ruptures, an activation fluid may be supplied to expand the expandable material 162 and close off the actuation port 150 as described above. This has the advantage of allowing an operator to initiate the setting mechanism from surface without the need to run a setting tool downhole.

[0033] FIG. 8 is a section view of the packerusing a dissolvable plug 168 to initially close the actuation port 150. The plug 168 is made of a dissolvable material that has sufficient structural integrity to initially plug the actuation port 150 dissolves away after a certain amount of time, thereby allowing tubing pressure to enter the actuation port 150 and the setting chamber 148. Examples of a dissolvable material are further discussed below. This has the advantage of allowing an operator to initiate the setting mechanism without the use of either pressure from surface (which requires equipment) or the need to run a setting tool downhole.

[0034] The foregoing provide specific examples of initially plugging an actuation port for a hydraulically actuatable tool such as a packer, subsequently opening the actuation port for applying a setting pressure, and activating an expandable material to then close flow to the actuation port. One of ordinary skill in the art with the benefit of this disclosure will appreciate that other examples not explicitly disclosed may also be constructed within the disclosure scope. For example, a plug or other closure member may be devised within the scope of this disclosure that can be activated using electric signals or acoustic signals. In still other embodiments, the plug may be absent altogether as the tool is run into the wellbore. In such an embodiment, the expandable material will be configured to expand very slowly in response to the wellbore fluid so as to allow sufficient time to run the packer to depth and set it before the expandable material has expanded to close off the port. This has the advantage of not needing pressure applied from surface or a setting tool or the supply of an activation fluid from surface.

[0035] The above examples rely, in part, on dissolvable materials that are effective for initially closing the actuation port before being dissolved, and expandable materials effective for expanding to close or re-close the actuation port. Not every material that expands in the presence of any fluid may be capable of closing an actuation port. To be effective, an expandable material must be able to close the actuation port to seal out pressures greater than used for setting the downhole tool. The expandable material may preferably seal against pressures in excess of what other components may otherwise be configured to withstand if the actuation port were not sealed. Likewise, not every dissolvable material is suitable for initially plugging an actuation port. To be effective, the dissolvable material should be able to initially close the actuation port for a sufficient period of time to position the packer or other actuatable tool downhole, until the tool can be actuated. The following sections provide non-limiting examples of expandable materials and of dissolvable materials that may be suitable with one or more embodiments of the present disclosure. In particular, one non-limiting category of expandable materials is swellable metallic materials. Another category of materials, referred to as doped magnesium alloys, may be used either as expandable materials in some formulations and/or dissolvable materials in other formulations.

Swellable Metallic Materials

[0036] One example category of expandable materials that may be useful according to this disclosure include swellable metallic materials that react to an activation fluid to cause, induce, or otherwise participate in the reaction that causes the expandable material to close the actuation port. In one example, the swellable metallic materials may react to a brine as the activation fluid to close the flow path. Some swellable metallic materials may thicken or harden in response to physical constraints imposed by the flow path, versus in an unbounded volume (e.g. an open lab beaker) in which the thickening or hardening may not otherwise occur. The swellable metallic materials may swell in high-salinity and/or high-temperature environments where elastomeric materials, such as rubber, can perform poorly. The swellable metallic materials comprise a wide variety of metals and metal alloys and may swell by the formation of metal hydroxides. The swellable metallic materials swell by undergoing metal hydration reactions in the presence of brines to form metal hydroxides.

[0037] In one or more embodiments, the metal hydroxide occupies more space than the base metal reactant. This expansion in volume allows the swellable metallic material to form a seal at the interface of the swellable metallic material and any adjacent surfaces. For example, a mole of magnesium has a molar mass of 24 g/mol and a density of 1.74 g/cm3 which results in a volume of 13.8 cm /mol. Magnesium hydroxide has a molar mass of 60 g/mol and a density of 2.34 g/cm3 which results in a volume of 25.6 cm /mol. 25.6 cm /mol is 85% more volume than 13.8 cm /mol. As another example, a mole of calcium has a molar mass of 40 g/mol and a density of 1.54 g/cm3 which results in a volume of 26.0 cm /mol. Calcium hydroxide has a molar mass of 76 g/mol and a density of 2.21 g/cm3 which results in a volume of 34.4 cm /mol. 34.4 cm /mol is 32% more volume than 26.0 cm /mol. As yet another example, a mole of aluminum has a molar mass of 27 g/mol and a density of 2.7 g/cm3 which results in a volume of 10.0 cm /mol. Aluminum hydroxide has a molar mass of 63 g/mol and a density of 2.42 g/cm3 which results in a volume of 26 cm /mol. 26 cm /mol is 160% more volume than 10 cm /mol. The swellable metallic material comprises any metal or metal alloy that may undergo a hydration reaction to form a metal hydroxide of greater volume than the base metal or metal alloy reactant. The metal may become separate particles during the hydration reaction and these separate particles lock or bond together to form what is considered as a swellable metallic material.

[0038] Examples of suitable metals for the swellable metallic material include, but are not limited to, magnesium, calcium, aluminum, tin, zinc, beryllium, barium, manganese, or any combination thereof. Preferred metals include magnesium, calcium, and aluminum. Examples of suitable metal alloys for the swellable metallic material include, but are not limited to, any alloys of magnesium, calcium, aluminum, tin, zinc, beryllium, barium, manganese, or any combination thereof. Preferred metal alloys include alloys of magnesium-zinc, magnesium-aluminum, calcium-magnesium, or aluminum-copper. In some examples, the metal alloys may comprise alloyed elements that are not metallic. Examples of these nonmetallic elements include, but are not limited to, graphite, carbon, silicon, boron nitride, and the like. In some examples, the metal is alloyed to increase reactivity and/or to control the formation of oxides. In some examples, the metal alloy is also alloyed with a dopant metal that promotes corrosion or inhibits passivation and thus increased hydroxide formation. Examples of dopant metals include, but are not limited to nickel, iron, copper, carbon, titanium, gallium, mercury, cobalt, iridium, gold, palladium, or any combination thereof. In examples where the swellable metallic material comprises a metal alloy, the metal alloy may be produced from a solid solution process or a powder metallurgical process. The sealing element comprising the metal alloy may be formed either from the metal alloy production process or through subsequent processing of the metal alloy. As used herein, the term “solid solution” may include an alloy that is formed from a single melt where all of the components in the alloy (e.g., a magnesium alloy) are melted together in a casting. The casting can be subsequently extruded, wrought, hipped, or worked to form the desired shape for the sealing element of the swellable metallic material. Preferably, the alloying components are uniformly distributed throughout the metal alloy, although intragranular inclusions may be present, without departing from the scope of the present disclosure.

[0039] It is to be understood that some minor variations in the distribution of the alloying particles can occur, but it is preferred that the distribution is such that a homogenous solid solution of the metal alloy is produced. A solid solution is a solid-state solution of one or more solutes in a solvent. Such a mixture is considered a solution rather than a compound when the crystal structure of the solvent remains unchanged by addition of the solutes, and when the mixture remains in a single homogeneous phase. A powder metallurgy process generally comprises obtaining or producing a fusible alloy matrix in a powdered form. The powdered fusible alloy matrix is then placed in a mold or blended with at least one other type of particle and then placed into a mold. Pressure is applied to the mold to compact the powder particles together, fusing them to form a solid material which may be used as the swellable metallic material.

[0040] In some alternative examples, the swellable metallic material comprises an oxide. As an example, calcium oxide reacts with water in an energetic reaction to produce calcium hydroxide. 1 mole of calcium oxide occupies 9.5 cm ³ whereas 1 mole of calcium hydroxide occupies 34.4 cm ³ which is a 260% volumetric expansion. Examples of metal oxides include oxides of any metals disclosed herein, including, but not limited to, magnesium, calcium, aluminum, iron, nickel, copper, chromium, tin, zinc, lead, beryllium, barium, gallium, indium, bismuth, titanium, manganese, cobalt, or any combination thereof.

[0041] A swellable metallic material may be selected that does not degrade into the brine. As such, the use of metals or metal alloys for the swellable metallic material that form relatively water-insoluble hydration products may be preferred. For example, magnesium hydroxide and calcium hydroxide have low solubility in water. In some examples, the metal hydration reaction may comprise an intermediate step where the metal hydroxides are small particles. When confined, these small particles may lock together. Thus, there may be an intermediate step where the swellable metallic material forms a series of fine particles between the steps of being solid metal and forming a seal. The small particles have a maximum dimension less than 0.1 inch and generally have a maximum dimension less than 0.01 inches. In some embodiments, the small particles comprise between one and 100 grains (metallurgical grains).

[0042] In some alternative examples, the swellable metallic material is dispersed into a binder material. The binder may be degradable or non-degradable. In some examples, the binder may be hydrolytically degradable. The binder may be swellable or non-swellable. If the binder is swellable, the binder may be oil-swellable, water-swellable, or oil- and water-swellable. In some examples, the binder may be porous. In some alternative examples, the binder may not be porous. General examples of the binder include, but are not limited to, rubbers, plastics, and elastomers. Specific examples of the binder may include, but are not limited to, polyvinyl alcohol, polylactic acid, polyurethane, polyglycolic acid, nitrile rubber, isoprene rubber, PTFE, silicone, fluoroelastomers, ethylene-based rubber, and PEEK. In some embodiments, the dispersed swellable metallic material may be cuttings obtained from a machining process.

[0043] In some examples, the metal hydroxide formed from the swellable metallic material may be dehydrated under sufficient swelling pressure. For example, if the metal hydroxide resists movement from additional hydroxide formation, elevated pressure may be created which may dehydrate the metal hydroxide. This dehydration may result in the formation of the metal oxide from the swellable metallic material. As an example, magnesium hydroxide may be dehydrated under sufficient pressure to form magnesium oxide and water. As another example, calcium hydroxide may be dehydrated under sufficient pressure to form calcium oxide and water. As yet another example, aluminum hydroxide may be dehydrated under sufficient pressure to form aluminum oxide and water. The dehydration of the hydroxide forms of the swellable metallic material may allow the swellable metallic material to form additional metal hydroxide and continue to swell.

Doped Magnesium Alloys

[0044] Another example category of materials that may be useful either as expandable materials and/or as dissolvable materials include doped magnesium alloy solid solutions (also referred to herein simply as "doped magnesium alloys"), such as disclosed in U.S. Patent No. 9,702,029 to Halliburton Energy Services, Inc. Whether this kind of alloy dissolves or expands and solidifies depends on the speed of the oxidative reaction and the environment the material is subjected. The amount of dopant in the alloy may be adjusted to adjust the speed of the reaction to get the desired result. Therefore, a doped magnesium may be useful, in some formulations, as an expandable material to subsequently close off the actuation port after actuating the packer. A doped magnesium alloy may alternatively be formulated as a dissolvable material to initially plug the actuation port for running in hole prior to actuating the packer.

[0045] Generally, a doped magnesium alloy in a solid solution is capable of degradation by galvanic corrosion in the presence of an electrolyte, where the presence of the dopant accelerates the corrosion rate compared to a similar magnesium alloy without a dopant. As used herein, the term "degradable" and all of its grammatical variants (e.g., "degrade," "degradation," "degrading," and the like) refer to the dissolution, galvanic conversion, or chemical conversion of solid materials such that a reduced structural integrity results. In complete degradation, structural shape is lost. The doped magnesium alloy solid solutions described herein may degrade by galvanic corrosion in the presence of an electrolyte. As used herein, the term "electrolyte" refers to a conducting medium containing ions (e.g., a salt). The term "galvanic corrosion" refers to corrosion occurring when two different metals or metal alloys are in electrical connectivity with each other and both are in contact with an electrolyte. The term "galvanic corrosion" includes microgalvanic corrosion. As used herein, the term "electrical connectivity" means that the two different metals or metal alloys are either touching or in close proximity to each other such that when contacted with an electrolyte, the electrolyte becomes electrically conductive and ion migration occurs between one of the metals and the other metal. [0046] In some instances, the degradation of the doped magnesium alloy may be sufficient for the mechanical properties of the material to be reduced to a point that the material no longer maintains its integrity and, in essence, falls apart or sloughs off. The conditions for degradation are generally wellbore conditions in a wellbore environment where an external stimulus may be used to initiate or affect the rate of degradation. For example, a fluid comprising the electrolyte may be introduced into a wellbore to initiate degradation. In another example, the wellbore may naturally produce the electrolyte sufficient to initiate degradation. The term "wellbore environment" refers to a subterranean location within a wellbore, and includes both naturally occurring wellbore environments and materials or fluids introduced into the wellbore environment. Degradation of the degradable materials identified herein may be anywhere from about 4 hours (hrs) to about 576 hrs (or about 4 hrs to about 24 days) from first contact with the appropriate wellbore environment, encompassing any value and subset therebetween. Each of these values is critical to the embodiments of the present disclosure and may depend on a number of factors including, but not limited to, the magnesium alloy selected, the dopant selected, the amount of dopant selected, and the like. In some embodiments, the degradation rate of the doped magnesium alloys described herein may be accelerated based on conditions in the wellbore or conditions of the wellbore fluids (either natural or introduced) including temperature, pH, salinity, pressure, and the like.

[0047] In some embodiments, the electrolyte capable of degrading the doped magnesium alloys described herein may be a halide anion (i.e., fluoride, chloride, bromide, iodide, and astatide), a halide salt, an oxoanion (including monomeric oxoanions and polyoxoanions), and any combination thereof. Suitable examples of halide salts for use as the electrolytes of the present disclosure may include, but are not limited to, a potassium fluoride, a potassium chloride, a potassium bromide, a potassium iodide, a sodium chloride, a sodium bromide, a sodium iodide, a sodium fluoride, a calcium fluoride, a calcium chloride, a calcium bromide, a calcium iodide, a zinc fluoride, a zinc chloride, a zinc bromide, a zinc iodide, an ammonium fluoride, an ammonium chloride, an ammonium bromide, an ammonium iodide, a magnesium chloride, potassium carbonate, potassium nitrate, sodium nitrate, and any combination thereof. The oxyanions for use as the electrolyte of the present disclosure may be generally represented by the formula A _x O _yz -, where A represents a chemical element and O is an oxygen atom; x, y, and z are integers between the range of about 1 to about 30, and may be or may not be the same integer. Examples of suitable oxoanions may include, but are not limited to, carbonate, borate, nitrate, phosphate, sulfate, nitrite, chlorite, hypochlorite, phosphite, sulfite, hypophosphite, hyposulfite, triphosphate, and any combination thereof.

[0048] In some embodiments, the electrolyte may be present in an aqueous base fluid including, but not limited to, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, and any combination thereof. Generally, the water in the aqueous base fluid may be from any source, provided that it does not interfere with the electrolyte therein from degrading at least partially the magnesium alloy forming at least a component of the downhole tool described herein. In some embodiments, the electrolyte may be present in the aqueous base fluid for contacting the magnesium alloy in a subterranean formation up to saturation, which may vary depending on the magnesium salt and aqueous base fluid selected. In other embodiments, the electrolyte may be present in the aqueous base fluid for contacting the magnesium alloy in a subterranean formation in an amount in the range of from about 0.01% to about 30% by weight of the treatment fluid, encompassing any value and subset therebetween. Each of these values is critical to the embodiments of the present disclosure and may depend on a number of factors including, but not limited to, the composition of the doped magnesium alloy, the portion of the downhole tool composed of the doped magnesium alloy, the type of electrolyte selected, other conditions of the wellbore environment, and the like. As used herein the term "degrading at least partially" or "partially degrades" refers to the tool or component degrading at least to the point wherein about 20% or more of the mass of the tool or component degrades.

Other Swellable and/or Dissolvable Materials

[0049] Other examples of expandable materials not specifically disclosed above are considered within the scope of this disclosure so long as they can close off the actuation port sufficient to isolate and protect the actuation chamber from pressures of greater than the actuation/setting pressure.

[0050] FIG. 9 illustrates a fracking operation using the example configuration of the packer 120 generally described above. Two (“upper” and “lower”) packers I20A, I20B are shown in the figure for purpose of discussion, although any number of additional packers may be included. The packers have been set with their respective sealing elements 124 expanded against the wellbore 106. A first zone (Zone 1) is thereby isolated between the lower packer 120B and a plug 170, and a second zone (Zone 2) is isolated between the upper packer 120A and the lower packer 120B. As depicted in the figure, Zone 1 is currently being fracked, with arrows depicting the pressurized flow path. Under this situation, fracking pressure is blocked from reaching the annulus 109 around the upper packer 120 A, but does enter the annulus 111 about the lower packer 120B. A cylindrical outer housing 204 of the lower packer 120B is experiencing an external fluid pressure (the fracking pressure) in excess of the internal fluid pressure used to set the lower packer 120B (the setting pressure). For example, a fracking pressure could be 15,000 psi, while the packer setting pressure may be only 5,000 psi. The internal through bore 141 also sees the fracking pressure, but pressure inside the setting chamber 148 cannot increase due to the port being blocked as described above. Although the mandrel 140 is designed to withstand the fracking pressure, a large pressure differential (e.g., 10,000 psi) between the annulus 111 and the setting chamber 148 of the lower packer 120B may be sufficient to collapse the outer housing 204 without some sort of pressure balancing. Therefore, pressure can be balanced in any of a variety of ways to prevent the outer housing 204 of the lower packer 120B from collapsing. One approach is to use a check valve 205 on the OD of housing 204 that will open and allow pressure to enter cylindrical outer housing 204. This way, the outer housing 204 becomes pressure balanced and will maintain its integrity.

[0051] While Zone 1 is being fracked as described, the packer configuration described herein has ensured that pressurized fracking fluid does not enter the setting chamber 218 of the upper packer 120 A and burst the outer housing 206 of the upper packer 120 A. Otherwise, the setting chamber of the upper packer would have to be designed to sustain the higher pressure rating required for hydraulic fracturing. By virtue of the disclosed packer configuration, the setting chambers of the packers can be designed to withstand only the setting pressure thereby reducing cost, outer diameter and providing more setting piston area.

[0052] When Zone 2 needs to be fracked, a sleeve device (not shown) generally understood in the art may be opened so fracking pressure can enter Zone 2. Under this situation, the cylindrical housing of the upper packer 120 A sees a fracking pressure that can be balanced as it was for the lower packer 120B, such as using a check valve as described above, to prevent the cylindrical housing 204 from collapsing. [0053] This way, the cylindrical housings of all the packers are protected from bursting when zones below it are being fracked. They are also protected from collapsing when the zone adjacent to the packer is being fracked.

[0054] Though only 2 packers and 2 zones are described above, one skilled in the art will recognize that this method can be used for as many packers as needed.

[0055] Accordingly, the present disclosure may provide systems and methods for actuating a hydraulic well tool and subsequently closing an actuation port to protect the actuating mechanism. The above examples are given in the non-limiting context of a packer set with a hydraulic setting mechanism before servicing the well at pressures in excess of that setting pressure. The methods/systems/compositions/tools may include any of the various features disclosed herein, including one or more of the following statements.

[0056] Statement 1. A well tool, comprising: a tool body positionable in a wellbore on a tubular conveyance, the tool body including a through bore for fluid communication with the tubular conveyance and an actuatable tool feature moveably coupled to the tool body; an actuating mechanism including an actuation chamber and an actuation port fluidically coupling the through bore to the actuation chamber, the actuating mechanism configured for actuating the actuatable tool feature in response to an actuating pressure applied along the through bore to the actuation port; and an expandable material in proximity to the actuation port configured to seal off the actuation port in response to exposure to an activation fluid.

[0057] Statement 2. The well tool of Statement 1, wherein the actuatable tool feature comprises a sealing element carried on the tool body and the actuating mechanism is configured for urging the sealing element into engagement with the wellbore in response to the actuating pressure.

[0058] Statement 3. The well tool of any of Statements 1 to 2, further comprising: a plug initially plugging the actuation port and removeable downhole to open the actuation port.

[0059] Statement 4. The well tool of any of Statements 1 to 3, wherein the plug comprises a dissolvable material that dissolves in response to a wellbore fluid present in the through bore of the tool body.

[0060] Statement 5. The well tool of any of Statements 1 to 4, further comprising: a valve coupled to the actuation port, the valve including a component comprising the expandable material. [0061] Statement 6. The well tool of any of Statements 1 to 5, further comprising: a burst disk initially closing the actuation port, the burst disk being rupturable in response to a burst pressure in the through bore of the tool body.

[0062] Statement 7. The well tool of any of Statements 1 to 6, wherein the expandable material seals the actuation port up to at least 20% greater than the setting pressure.

[0063] Statement 8. The well tool of any of Statements 1 to 7, further comprising: a fluid capsule initially containing the activation fluid and configured to release the activation fluid to the actuation port in response to a fluid pressure applied from surface, a signal, a time delay, or combinations thereof .

[0064] Statement 9. The well tool of any of Statements 1 to 8, wherein the expandable material comprises a swellable metallic alloy.

[0065] Statement 10. The well tool of any of Statements 1 to 9, wherein the sealing element comprises a packer element configured to seal an annulus portion between the tool body and the wellbore.

[0066] Statement 11. A method, comprising: lowering a well tool into a wellbore on a tubular conveyance, the well tool including an actuatable tool feature and an actuating mechanism for actuating the actuatable tool feature; actuating the actuatable tool feature by applying fluid pressure down the tubular conveyance to the actuating mechanism via an actuation port fluidically coupling a through bore of the well tool to an actuation chamber of the actuating mechanism; after actuating the actuatable tool feature, exposing an expandable material to an activation fluid to close the actuation port and isolate the actuation chamber from the through bore; and after isolating the actuation chamber, increasing the fluid pressure in the through bore in excess of the fluid pressure used in actuating the actuatable tool feature.

[0067] Statement 12. The method of Statement 11, wherein the actuatable tool feature comprises a sealing element and actuating the actuatable tool feature comprises urging the sealing element into engagement with the wellbore in response to the actuating pressure.

[0068] Statement 13. The method of Statement 11 or 12, further comprising: lowering the well tool into the wellbore with a plug initially plugging the actuation port; and subsequently removing at least a portion of the plug to open the actuation port prior to setting the well tool.

[0069] Statement 14. The method of Statement 13, wherein the plug comprises a dissolvable material, the method further comprising delivering a wellbore fluid into the through bore of the tool body to dissolve the dissolvable material to open the setting port. Alternatively, the wellbore fluid already present in the well may itself contain the dissolving agents and hence, over a period of time, the dissolvable material of the plug will cause the plug to dissolve automatically without needing to deliver any additional fluids from surface.

[0070] Statement 15. The method of any of Statements 11 to 14, further comprising: positioning the well tool in the wellbore with a burst disk initially closing the actuation port; and delivering a fluid pressure to the through bore of the tool body to rupture the burst disk to open the actuation port prior to actuating the actuating mechanism.

[0071] Statement 16. The method of any of Statements 11 to 15, further comprising: releasing the activation fluid from a capsule initially containing the activation fluid; and delivering the released activation to the actuation port to expand the expandable material.

[0072] Statement 17. The method of any of Statements 11 to 16, wherein the expandable material comprises: a swellable metallic alloy.

[0073] Statement 18. The method of any of Statements 11 to 17, further comprising: wherein actuating the setting mechanism comprises setting a packer in response to the actuation pressure to seal an annulus between the well tool and the wellbore, the packer configured to withstand an annulus pressure of at least twice the setting pressure.

[0074] Statement 19. A method of servicing a well, comprising: lowering a packer into a wellbore on a tubular conveyance, the packer including a sealing element and a setting mechanism for setting the packer within the wellbore; setting the packer by applying a setting pressure down the tubular conveyance to the setting mechanism via an actuation port fluidically coupling a through bore of the setting mechanism to a setting chamber; exposing an expandable material in the actuation port to an activation fluid to close the actuation port and isolate the setting chamber from the through bore; and performing a wellbore service comprising delivering a service fluid down the tubular conveyance and into an annulus sealed by the set packer, wherein the service fluid is pressurized to greater than the setting pressure.

[0075] Statement 20. The method of Statement 19, wherein the expandable material comprises a swellable metallic material or a doped magnesium alloy.

[0076] To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the entire scope of the disclosure. [0077] For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

[0078] Therefore, the present embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present embodiments may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, all combinations of each embodiment are contemplated and covered by the disclosure. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure.