Inflatable downhole packer tool

An inflatable packer assembly configured to be conveyed within a wellbore. The inflatable packer assembly includes a mandrel having a flowline, a first packer ring slidably connected with the mandrel, a second packer ring fixedly connected with the mandrel, a latching mechanism fluidly connected with the flowline, and an inflatable packer fluidly connected with the flowline. The inflatable packer may be disposed around the mandrel and sealingly connected with the first and second packer rings. The inflatable packer may be operable to expand against a sidewall of the wellbore upon receiving a fluid from the flowline. The latching mechanism may be operable to limit movement of the first packer ring with respect to the mandrel, and permit the movement of the first packer ring with respect to the mandrel upon being actuated by the fluid from the flowline.

BACKGROUND OF THE DISCLOSURE

In the oil and gas industry, downhole tool strings include inflatable packer tools. For example, a dual-packer tool may be positioned at an intended location within a wellbore and expandable packer elements of the packer tool may be radially expanded to form an annular seal against the wellbore wall or a casing lining the wellbore to fluidly isolate an interval (i.e., section) of the wellbore between the packer elements.

A typical inflatable dual-packer tool comprises upper (i.e., uphole) packer rings that are fixedly connected with corresponding mandrels, and lower (i.e., downhole) packer rings that are slidably connected with the corresponding mandrels. Such relative locations of the fixed and slidable packer rings reduce the risk of expandable packer elements sticking when conveying the packer tool upwards (i.e., uphole) out of the wellbore. Namely, during upward conveyance, axial movement (i.e., sliding) of the lower packer rings permits the packer elements to slim down when passing a restriction within the wellbore. From an operational perspective, the risk of not being able to convey the packer tool into the wellbore is deemed less than not being able to convey the packer tool out of the wellbore.

However, mounting the packer rings on the mandrels in such manner results in one of the sliding rings facing the isolated wellbore interval. Dynamic downhole conditions, such as differential between fluid pressure within the isolated interval and hydrostatic wellbore pressure external to the expanded packer elements, may cause the sliding ring to move during downhole operations, causing length and volume of the isolated wellbore interval to vary during downhole measuring operations. Such interval variations can introduce artifacts in the pressure readings and impact the ability to interpret measurement data. Having one of the sliding packer rings facing the isolated wellbore interval also reduces the maximum pressure differential limit of the dual-packer tool. Namely, mounting one of the sliding packer rings in such orientation requires that both the fixed and slidable packer rings first pass over an end connector (e.g., threads) of the corresponding mandrel, thereby limiting the size and the strength of such end connector. From an operational perspective, the potential for increased differential pressure rating and better quality pressure data is deemed less imperative than the ability to convey the packer tool out of the wellbore.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

The present disclosure introduces an apparatus that includes a dual packer assembly for conveyance within a wellbore. The dual packer assembly includes an upper packer assembly and a lower packer assembly. The upper packer assembly includes an upper mandrel, a first upper packer ring axially movable with respect to the upper mandrel, a first lower packer ring fixedly connected with the upper mandrel, and an upper inflatable packer disposed around the upper mandrel and sealingly connected with the first upper and first lower packer rings. The upper inflatable packer is operable to expand against a sidewall of the wellbore. The lower packer assembly includes a lower mandrel coupled with the upper mandrel, a second upper packer ring fixedly connected with the lower mandrel, a second lower packer ring axially movable with respect to the lower mandrel, and a lower inflatable packer disposed around the lower mandrel and sealingly connected with the second upper and second lower packer rings. The lower inflatable packer is operable to expand against the sidewall of the wellbore, and the upper and lower inflatable packers are collectively operable to isolate a section of the wellbore when expanded.

The present disclosure also introduces an apparatus that includes an inflatable packer assembly for conveyance within a wellbore, the inflatable packer assembly includes a mandrel, a first packer ring, a second packer ring, a latching mechanism, and an inflatable packer. The mandrel includes a flowline. The first packer ring is slidably connected with the mandrel. The second packer ring is fixedly connected with the mandrel. The latching mechanism is fluidly connected with the flowline, and is operable to limit movement of the first packer ring with respect to the mandrel, and to permit the movement of the first packer ring with respect to the mandrel upon being actuated by a fluid from the flowline. The inflatable packer is disposed around the mandrel, and is sealingly connected with the first and second packer rings. The inflatable packer is fluidly connected with the flowline, and is operable to expand against a sidewall of the wellbore upon receiving the fluid from the flowline.

The present disclosure also introduces a method that includes coupling an inflatable packer assembly to a tool string. The inflatable packer assembly includes a mandrel, an upper packer ring, a lower packer ring, a latching mechanism, and an inflatable packer. The mandrel includes a flowline extending within the mandrel. The upper packer ring is selectively axially movable with respect to the mandrel. The lower packer ring is fixedly connected with the mandrel. The latching mechanism is fluidly connected with the flowline. The inflatable packer is disposed around the mandrel and sealingly connected with the upper and lower packer rings. The inflatable packer is fluidly connected with the flowline. The method also includes conveying the tool string in a downhole direction within a wellbore, and pumping a fluid into the flowline. The pumped fluid expands the inflatable packer away from the mandrel and against a sidewall of the wellbore, and also operates the latching mechanism to permit the axial movement of the upper packer ring with respect to the mandrel. The method also includes conveying the tool string in an uphole direction within the wellbore while the latching mechanism is limiting the axial movement of the upper packer ring with respect to the mandrel.

These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different examples for different features and other aspects of various implementations. Specific examples of components and arrangements are described below to simplify the present disclosure. These are merely examples, and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various implementations described below.

FIG. 1is a schematic view of an example wellsite system100to which one or more aspects of the present disclosure may be applicable. The wellsite system100may be onshore or offshore. In the example wellsite system100shown inFIG. 1, a wellbore104is formed in one or more subterranean formations102by rotary drilling. Other example systems within the scope of the present disclosure may also or instead utilize directional drilling. Although some elements of the wellsite system100are depicted inFIG. 1and described below, it is to be understood that the wellsite system100may include other components in addition to, or instead of, those presently illustrated and described.

As shown inFIG. 1, a drillstring112suspended within the wellbore104comprises a bottom hole assembly (BHA)140that includes or is coupled with a drill bit142at its lower end. The surface system includes a platform and derrick assembly110positioned over the wellbore104. The platform and derrick assembly110may comprise a rotary table114, a kelly116, a hook118, and a rotary swivel120. The drillstring112may be suspended from a lifting gear (not shown) via the hook118, with the lifting gear being coupled to a mast (not shown) rising above the surface. An example lifting gear includes a crown block affixed to the top of the mast, a vertically traveling block to which the hook118is attached, and a cable passing through the crown block and the vertically traveling block. In such an example, one end of the cable is affixed to an anchor point, whereas the other end is affixed to a winch to raise and lower the hook118and the drillstring112coupled thereto. The drillstring112comprises one or more types of tubular members, such as drill pipes, threadedly attached one to another, perhaps including wired drilled pipe.

The drillstring112may be rotated by the rotary table114, which engages the kelly116at the upper end of the drillstring112. The drillstring112is suspended from the hook118in a manner permitting rotation of the drillstring112relative to the hook118. Other example wellsite systems within the scope of the present disclosure may utilize a top drive system to suspend and rotate the drillstring112, whether in addition to or instead of the illustrated rotary table system.

The surface system may further include drilling fluid or mud126stored in a pit or other container128formed at the wellsite. The drilling fluid126may be oil-based mud (OBM) or water-based mud (WBM). A pump130delivers the drilling fluid126to the interior of the drillstring112via a hose or other conduit122coupled to a port in the rotary swivel120, causing the drilling fluid to flow downward through the drillstring112, as indicated inFIG. 1by directional arrow132. The drilling fluid exits the drillstring112via ports in the drill bit142, and then circulates upward through the annulus region between the outside of the drillstring112and the wall106of the wellbore104, as indicated inFIG. 1by directional arrows134. In this manner, the drilling fluid126lubricates the drill bit142and carries formation cuttings up to the surface while it is returned to the container128for recirculation.

The BHA140may comprise one or more specially made drill collars near the drill bit142. Each such drill collar may comprise one or more devices permitting measurement of downhole drilling conditions and/or various characteristic properties of the subterranean formation102intersected by the wellbore104. For example, the BHA140may comprise one or more logging-while-drilling (LWD) modules144, one or more measurement-while-drilling (MWD) modules146, a rotary-steerable system and motor148, and perhaps the drill bit142. Other BHA components, modules, and/or tools are also within the scope of the present disclosure, and such other BHA components, modules, and/or tools may be positioned differently in the BHA140than as depicted inFIG. 1.

The LWD modules144may comprise one or more devices for measuring characteristics of the formation102, including for obtaining a sample of fluid from the formation102. The MWD modules146may comprise one or more devices for measuring characteristics of the drillstring112and/or the drill bit142, such as for measuring weight-on-bit, torque, vibration, shock, stick slip, tool face direction, and/or inclination, among other examples. The MWD modules146may further comprise an apparatus147for generating electrical power to be utilized by the downhole system, such as a mud turbine generator powered by the flow of the drilling fluid126. Other power and/or battery systems may also or instead be employed. One or more of the LWD modules144, the MWD modules146, and/or another drill pipe conveyed tool or module may be or comprise at least a portion of a packer tool as described below.

The wellsite system100also includes a data processing system that can include one or more, or portions thereof, of the following: the surface equipment190, control devices and electronics in one or more modules of the BHA140(such as a downhole controller150), a remote computer system (not shown), communication equipment, and other equipment. The data processing system may include one or more computer systems or devices and/or may be a distributed computer system. For example, collected data or information may be stored, distributed, communicated to a human wellsite operator, and/or processed locally or remotely.

The data processing system may, individually or in combination with other system components, perform the methods and/or processes described below, or portions thereof. Methods and/or processes within the scope of the present disclosure may be implemented by one or more computer programs that run in a processor located, for example, in one or more modules of the BHA140and/or the surface equipment190. Such programs may utilize data received from the BHA140via mud-pulse telemetry and/or other telemetry means, and/or may transmit control signals to operative elements of the BHA140. The programs may be stored on a tangible, non-transitory, computer-usable storage medium associated with the one or more processors of the BHA140and/or surface equipment190, or may be stored on an external, tangible, non-transitory, computer-usable storage medium that is electronically coupled to such processor(s). The storage medium may be one or more known or future-developed storage media, such as a magnetic disk, an optically readable disk, flash memory, or a readable device of another kind, including a remote storage device coupled over a communication link, among other examples.

FIG. 2is a schematic view of another example wellsite system200to which one or more aspects of the present disclosure may be applicable. The wellsite system200may be onshore or offshore. In the example wellsite system200shown inFIG. 2, a tool string204is conveyed into the wellbore104via a conveyance means208, which may be or comprise a wireline, a slickline, or a fluid conduit, such as coiled tubing, completion tubing, a liner, or a casing. Similarly to the wellsite system100shown inFIG. 1, the example wellsite system200ofFIG. 2may be utilized for evaluation of the wellbore104and/or the formation102penetrated by the wellbore104.

The tool string204is suspended in the wellbore104from the lower end of the conveyance means208, which may be a multi-conductor logging cable spooled on a surface winch (not shown). The conveyance means208may include at least one conductor that facilitates data communication between the tool string204and surface equipment290disposed on the surface. The surface equipment290may have one or more aspects in common with the surface equipment190shown inFIG. 1.

The tool string204and conveyance means208may be structured and arranged with respect to a service vehicle (not shown) at the wellsite. For example, the conveyance means208may be connected to a drum (not shown) at the wellsite surface, such that rotation of the drum may raise and lower the tool string204. The drum may be disposed on a service vehicle or a stationary platform. The service vehicle or stationary platform may further contain the surface equipment290.

The tool string204comprises one or more elongated housings encasing various electronic components and modules schematically represented inFIG. 2. For example, the illustrated tool string204includes several modules212, at least one of which may be or comprise at least a portion of a packer tool as described below. Other implementations of the downhole tool string204within the scope of the present disclosure may include additional or fewer components or modules relative to the example implementation depicted inFIG. 2.

The wellsite system200also includes a data processing system that can include one or more, or portions thereof, of the following: the surface equipment290, control devices and electronics in one or more modules of the tool string204(such as a downhole controller216), a remote computer system (not shown), communication equipment, and other equipment. The data processing system may include one or more computer systems or devices and/or may be a distributed computer system. For example, collected data or information may be stored, distributed, communicated to a human wellsite operator, and/or processed locally or remotely.

The data processing system may, whether individually or in combination with other system components, perform the methods and/or processes described below, or portions thereof. Methods and/or processes within the scope of the present disclosure may be implemented by one or more computer programs that run in a processor located, for example, in one or more modules212of the tool string204and/or the surface equipment290. Such programs may utilize data received from the downhole controller216and/or other modules212via the conveyance means208, and may transmit control signals to operative elements of the tool string204. The programs may be stored on a tangible, non-transitory, computer-usable storage medium associated with the one or more processors of the downhole controller216, other modules212of the tool string204, and/or the surface equipment290, or may be stored on an external, tangible, non-transitory, computer-usable storage medium that is electronically coupled to such processor(s). The storage medium may be one or more known or future-developed storage media, such as a magnetic disk, an optically readable disk, flash memory, or a readable device of another kind, including a remote storage device coupled over a communication link, among other examples.

AlthoughFIGS. 1 and 2illustrate example wellsite systems100and200, respectively, that convey a downhole tool/string into the wellbore104, other example implementations consistent with the scope of this disclosure may utilize other conveyance means to convey tools/strings into the wellbore104. Additionally, other downhole tools within the scope of the present disclosure may comprise components in a non-modular construction also consistent with the scope of this disclosure.

The present disclosure is further directed to an apparatus operable to increase differential pressure limit between an isolated wellbore interval formed by packer elements of a dual-packer tool and the wellbore external to packer elements, and may reduce artificially induced pressure fluctuations by fixing the volume of the wellbore interval. The dual-packer tool may comprise an upper and a lower mandrel. Connection between the upper and the lower mandrel is located in the isolated interval formed between the upper and lower packer elements. This connection bears the forces introduced by the differential pressure between the wellbore interval and the wellbore external to packer elements. During formation testing operations, the isolated interval is either at a lower differential pressure or at a higher differential pressure than the wellbore above or below the packer elements. This permits fluid flow from the formation into the wellbore interval or from the wellbore interval into the formation. The dual-packer tool may comprise dual fluid inlets within the isolated interval, wherein each inlet is fluidly connected to a corresponding independent pressure gauge and/or fluid analyzer. The dual inlets may be utilized when multiphase fluids are present within the isolated interval. The dynamic pressure measurement in the wellbore interval is one of the primary data streams of the formation testing tool. The magnitude of the allowable differential pressure defines the operating envelope of formation tests. The allowable differential pressure is limited, at least in part, by the design and materials of the mandrels. The apparatus within the scope of the present disclosure may permit the packer elements to slide onto the mandrels inwardly from opposing ends of the mandrels (i.e., opposite side of the connection), posing no restriction on outer diameter of the connection, hence increasing the strength of the connection.

An upper packer element of a dual-packer tool may be connected to an upper sliding ring. The sliding ring may cause complications when conveying the packer tool upwards out of the wellbore, for example, when the upper ring is caused to slide downwards (i.e., downhole) with respect to the mandrel and increase the outside diameter of the packer element when the packer element catches an obstruction in the wellbore. To mitigate risk of sticking within the wellbore, the apparatus within the scope of the present disclosure further comprises a latching mechanism operable to lock the sliding ring in place with respect to the mandrel when the packer tool is conveyed upwards. The latching mechanism may release the sliding ring during inflation and lock the sliding ring in place during deflation of the packer elements. Accordingly, when the packer tool is conveyed upwards, downward movement of the sliding ring of the upper packer element will be limited such that the upper packer element will not deform (i.e., expand) uncontrollably when pulled through the restriction in the wellbore.

FIG. 3is a schematic view of at least a portion of an example implementation of a conventional dual-packer tool300configured to be conveyed within a wellbore. The dual-packer tool300comprises an upper packer tool310having an upper mandrel312, an upper packer ring314fixedly connected with the upper mandrel312, and a lower packer ring316slidably connected to and, thus, axially movable with respect to the upper mandrel312. The upper packer ring314is fixedly connected with the upper mandrel312via an external coupling means (e.g., threads, a shoulder, a ring, etc.) (not shown) along an outer profile313(e.g., surface) of the upper mandrel312. An inflatable (e.g., flexible, elastic) packer318(i.e., packer element) operable to expand against a sidewall of the wellbore is sealingly connected with the upper and lower packer rings314,316. The upper packer ring314, the lower packer ring316, and the inflatable packer318each comprise an axial opening or bore (not shown) configured to accommodate the upper mandrel312therethrough. Accordingly, the upper packer ring314, the lower packer ring316, and the inflatable packer318are each disposed around the outer profile313(e.g., surface) of the upper mandrel312.

The dual-packer tool300further comprises a lower packer tool320having a lower mandrel322, an upper packer ring324fixedly connected with the lower mandrel322, and a lower packer ring326slidably connected to and, thus, axially movable with respect to the lower mandrel322. The upper packer ring324is fixedly connected with the lower mandrel322via an external coupling means (not shown) along an outer profile323of the lower mandrel322. An inflatable packer328operable to expand against the sidewall of the wellbore is sealingly connected with the upper and lower packer rings324,326. The upper packer ring324, the lower packer ring326, and the inflatable packer328each comprise an axial opening or bore (not shown) configured to accommodate the lower mandrel322therethrough. Accordingly, the upper packer ring324, the lower packer ring326, and the inflatable packer328are each disposed around the outer profile323of the lower mandrel322.

In a deflated (i.e., retracted) state of each packer318,328, an inner surface of each packer318,328may be disposed against and/or in contact with the outer profile313,323of the corresponding mandrel312,322. In an inflated (i.e., expanded) state of each packer318,328, the inner surface of each packer318,328may be disposed away from the outer profile318,328of the corresponding mandrel312,322and an outer surface of each packer318,328may be disposed against the sidewall of the wellbore to fluidly isolate an interval (i.e., section) of the wellbore extending between the upper and lower packers318,328and/or to maintain the dual-packer tool300in position within the wellbore. The slidable connection between the lower packer rings316,326and the corresponding mandrels312,322permit the lower packer rings316,326to slide axially along the corresponding mandrels312,322in an upward direction, as indicated by arrow336, when the packers318,328are being inflated, and in a downward direction, as indicated by arrow338, when the packers318,328are being deflated.

The upper and lower mandrels312,322may be coupled together at a coupling joint330. For example, a lower end of the upper mandrel312comprises a lower coupler332and an upper end of the lower mandrel322comprises an upper coupler334. The lower and upper couplers332,334are configured to engage each other to couple together the upper and lower mandrels312,322and, thus, couple together the upper and lower packer tools310,320.

During assembly of the upper packer tool310, an upper packer subassembly comprising the upper packer ring314, the inflatable packer318, and the lower packer ring316is inserted onto the outer profile313of the upper mandrel312from the lower end of the upper mandrel312, as indicated by the arrow336. Insertion from the lower end of the upper mandrel312permits the upper packer ring314to be fixedly coupled with the external coupling means of the upper mandrel312and the lower packer ring316to be slidably connected with (i.e., disposed around) the upper mandrel312. Insertion from an upper end of the upper mandrel312, as indicated by the arrow338, is not possible because the inner opening of the lower packer ring316is sized to closely match the outer profile313of the upper mandrel312and will not pass the external coupling means of the upper mandrel312. Accordingly, diameter340of the lower coupler332is limited to smallest diameter of the axial openings of the upper packer ring314, the lower packer ring316, and the inflatable packer318and, thus, the diameter340has to be substantially equal to or smaller than diameter342of the outer profile313. The limited diameter340of the lower coupler332also limits diameter344of the upper coupler334, limiting axial strength of the coupling joint330and, thus, maximum pressure differential between fluid pressure within the isolated interval and hydrostatic wellbore pressure external to the isolated interval that the dual-packer assembly300can safely withstand.

The dual-packer assembly300further comprises or is coupled with a lower (i.e., downhole) portion348of the tool string, which may be coupled with or below the lower mandrel322of the lower packer tool320. A fluid pump350is disposed within the lower portion348. A flowline352extends axially within the mandrels312,322and the lower portion348. The flowline352is fluidly connected with the pump350and with the inflatable packers318,328, such as to permit the pump350to selectively inflate and/or deflate the inflatable packers318,328. Each mandrel312,322comprises a fluid port354,356(i.e., inflation/deflation port) fluidly connected with the flowline352and extending to an outer surface of each mandrel312,322to fluidly connect the flowline352and, thus the pump350, with an internal space or volume of each inflatable packer318,328. Each of the upper mandrel312, the lower mandrel322, and the lower portion348of the tool string comprises one or more corresponding flowline segments that are connected together to form the flowline352when the packer assembly300is assembled to fluidly connect the pump350with the inflatable packers318,328.

During downhole operations (e.g., fluid sampling operations), the pump350may pump (i.e., discharge) a fluid (e.g., an inflation fluid) into the inflatable packers318,328via the flowline352and the ports354,356to expand the packers318,328away from the corresponding mandrels312,322to against the sidewall of the wellbore. The pump350may also pump (i.e., draw) the fluid out of the packers318,328via the flowline352and the ports354,356to retract the packers318,328away from the sidewall of the wellbore toward and into contact with the corresponding mandrels312,322.

FIG. 4is a schematic view of at least a portion of an example implementation of an inflatable dual-packer tool400configured to be conveyed within a wellbore according to one or more aspects of the present disclosure. The dual-packer tool400may be conveyed within a wellbore as part of a tool string, such as the BHA140shown inFIG. 1, the tool string204shown inFIG. 2, and/or other tool strings within the scope of the present disclosure. The dual-packer tool400may be implemented as one or more of the LWD modules144or MWD modules146shown inFIG. 1, and/or one or more of the modules212shown inFIG. 2, and may thus be conveyed within the wellbore104via a wireline, a slickline, a drillstring, coiled tubing, completion tubing, a liner, a casing, and/or other conveyance means. As described below, the dual-packer tool400is an assembly of a plurality of components operating together in a coordinated manner and, thus, may also be referred to as a packer assembly.

The dual-packer tool400comprises an upper packer tool410having an upper mandrel412, a lower packer ring416fixedly connected with the upper mandrel412, and an upper packer ring414slidably connected to and, thus, axially movable with respect to the upper mandrel412. The lower packer ring416may be fixedly connected with the upper mandrel412via an external coupling means (e.g., threads, shoulder, ring, etc.) (not shown) along an outer profile413(e.g., surface) of the upper mandrel412. An upper inflatable (e.g., flexible, elastic) packer418(i.e., packer element) operable to expand against a sidewall of the wellbore may be sealingly connected with the upper and lower packer rings414,416. The upper packer ring414, the lower packer ring416, and the upper inflatable packer418may each comprise an axial opening or bore (not shown) configured to accommodate the upper mandrel412therethrough. Accordingly, the upper packer ring414, the lower packer ring416, and the upper inflatable packer418may each be disposed around the outer profile413of the upper mandrel412.

The dual-packer tool400further comprises a latching mechanism408selectively operable to limit the axial movement of the upper packer ring414with respect to the upper mandrel412and permit the axial movement of the upper packer ring414with respect to the upper mandrel412. For example, the latching mechanism408may be selectively operable to connect the upper packer ring414with the upper mandrel412to limit the axial movement of the upper packer ring414with respect to the upper mandrel412and disconnect the upper packer ring414from the upper mandrel412to permit the axial movement of the upper packer ring414with respect to the upper mandrel412. Selectivity in the operation of the latching mechanism408may be associated with the unlatching function where a minimum amount of inflate pressure in an inflate flowline is utilized to energize the latching mechanism408to the unlatched configuration. The upper packer ring414may be in the latched configuration when no pressure is applied and, thus, operate as a fail proof feature permitting the dual-packer tool400to be pulled out of the wellbore when, for example, power is lost downhole.

The dual-packer tool400also comprises a lower packer tool420having a lower mandrel422, an upper packer ring424fixedly connected with the lower mandrel422, and a lower packer ring426slidably connected to and, thus, axially movable with respect to the lower mandrel422. The lower packer ring424may be fixedly connected with the lower mandrel422via an external coupling means (not shown) along an outer profile423of the lower mandrel422. A lower inflatable packer428operable to expand against the sidewall of the wellbore may be sealingly connected with the upper and lower packer rings424,426. The upper packer ring424, the lower packer ring426, and the lower inflatable packer428may each comprise an axial opening or bore (not shown) configured to accommodate the lower mandrel422therethrough. Accordingly, the upper packer ring424, the lower packer ring426, and the lower inflatable packer428may beach be disposed around the outer profile423of the lower mandrel422.

In a deflated (i.e., retracted) state of each packer418,428, an inner surface of each packer418,428may be disposed against and/or in contact with the outer profile413,423of the corresponding mandrel412,422. In an inflated (i.e., expanded) state of each packer418,428, the inner surface of each packer418,428may be disposed away from the outer profile413,423of the corresponding mandrel412,422and an outer surface of each packer418,428may be disposed against the sidewall of the wellbore to fluidly isolate an interval of the wellbore extending between the upper and lower packers418,428and/or to maintain the dual-packer tool400in position within the wellbore. The slidable connection between the upper packer ring414and the corresponding mandrel412permits the upper packer ring414to slide axially along the corresponding mandrel412in a downward direction, as indicated by arrow438when the packer418is being inflated, wherein the slidable connection between the lower packer ring426and the corresponding mandrel422permits the lower packer ring426to slide axially along the corresponding mandrel422in an upward direction, as indicated by arrow436, when the packer428is being inflated. The slidable connection also permits the packer rings414,426to slide axially in the opposing directions when the packers418,428are being deflated.

The upper and lower mandrels412,422may be coupled together at a coupling joint430. For example, a lower end of the upper mandrel412may comprise a lower coupler432and an upper end of the lower mandrel422may comprise an upper coupler434. The lower and upper couplers432,434may be configured to engage each other to couple together the upper and lower mandrels412,422and, thus, couple together the upper and lower packer tools410,420. In an example implementation, the lower coupler432may be or comprise a box connector and the upper coupler434may be or comprise a pin connector.

During assembly of the upper packer tool410, an upper packer subassembly comprising the upper packer ring414, the upper inflatable packer418, and the lower packer ring416may be inserted onto the outer profile413of the upper mandrel412from the upper end of the upper mandrel412, as indicated by the arrow438. Furthermore, the upper packer subassembly may be inserted onto the outer profile413of the upper mandrel412with the fixed packer ring416directed (i.e., oriented) downwardly and the slidable ring414directed upwardly. Thus, unlike with the upper packer subassembly of the dual-packer tool300, the sliding ring414, which may be sized to closely match the outer profile413of the upper mandrel412, will not have to pass the external coupling means of the upper mandrel412to be mounted on the mandrel412. Accordingly, insertion from the upper end of the upper mandrel412permits the lower packer ring416to be fixedly coupled with the external coupling means of the upper mandrel412and the upper packer ring414to be slidably connected with (i.e., disposed around) the upper mandrel412. Similarly, a lower packer subassembly comprising the upper packer ring424, the lower inflatable packer428, and the lower packer ring426may be inserted onto the outer profile423of the lower mandrel412from a lower end of the lower mandrel422, as indicated by the arrow436, and with the fixed packer ring424directed upwardly.

Because the upper packer subassembly is insertable onto the upper mandrel412from the upper end of the upper mandrel412and the lower packer subassembly is insertable onto the lower mandrel422from the lower end of the lower mandrel422, the size of the lower and upper couplers432,434may not be limited by diameters of the axial openings of the upper packer ring424, the lower packer ring426, and the lower inflatable packer428. Accordingly, diameter440of the lower coupler432may be substantially larger than diameter442of the outer profile413. The larger diameter440of the lower coupler432permits a larger diameter444of the upper coupler434. The larger couplers432,434increase axial strength of the coupling joint430and, thus, maximum pressure differential between fluid pressure within the isolated interval and hydrostatic wellbore pressure external to the isolated interval that the dual-packer assembly400can safely withstand. Furthermore, because the sliding rings414,426and the inflatable packers418,428do not have to pass over or around the external coupling means of the upper and lower mandrels412,422during assembly, the external coupling means may also be physically larger and, thus, stronger, such as to increase the maximum pressure differential.

The dual-packer assembly400may further comprise or be coupled with a lower (i.e., downhole) portion448of the tool string, which may be coupled with or below the lower mandrel422of the lower packer tool420. A fluid pump450may be disposed within the lower portion448and a flowline452may extend axially within the mandrels412,422and the lower portion448. The flowline452may be fluidly connected with the pump450and with the inflatable packers418,428, such as may permit the pump450to selectively inflate and/or deflate the inflatable packers418,428. Each mandrel412,422may comprise a fluid port454,456(i.e., an inflation/deflation port) fluidly connected with the flowline452and extending to an outer surface (i.e., outer profile413,423) of each mandrel412,422to fluidly connect the flowline452and, thus the pump450, with an internal space or volume of each of the inflatable packer418,428. The upper mandrel412may further comprise fluid port458fluidly connected with the flowline452and extending to the outer surface of the upper mandrel412to fluidly connect the flowline452and, thus the pump450, with the latching mechanism408. The flowline452may comprise a plurality of flowline segments, each associated with a corresponding one of the upper mandrel412, the lower mandrel422, and the lower portion448of the tool string, which when coupled together, form the flowline452.

During downhole operations (e.g., formation testing), the pump450may be operable to pump (i.e., discharge) a fluid (e.g., an inflation fluid) into the inflatable packers418,428via the flowline452and the ports454,456to expand the packers418,428away from the corresponding mandrels412,422to against the sidewall of the wellbore. The fluid pumped by the pump450may also be directed to the latching mechanism408via the flowline452and the port458to operate (i.e., actuate) the latching mechanism408. For example, in its normal (i.e., not actuated) state, the latching mechanism408may limit the downward axial movement of the upper packer ring414with respect to the upper mandrel412and when operated (i.e., actuated) by the fluid, the latching mechanism408may permit the downward axial movement of the upper packer ring414with respect to the upper mandrel412. Accordingly, the pump450may be operable to simultaneously inflate the packers418,428and actuate the latching mechanism408to permit the axial movement of the upper packer ring414while the packers418,428are being inflated.

The pump450may be further operable to pump (i.e., draw) the fluid out of the packers418,428via the flowline452and the ports454,456to retract the packers418,428away from the sidewall of the wellbore toward and into contact with the corresponding mandrels412,422. The pump450may also pump the fluid out of or away from the latching mechanism408via the flowline452and the port458to permit the latching mechanism408to return to its normal state in which the latching mechanism408limits the downward axial movement of the upper packer ring414with respect to the upper mandrel412. However, instead of utilizing the pump450to transfer the fluid from the packers418,428and/or the latching mechanism408, a fluid valve460(e.g., fluid relief valve) may be opened to permit the fluid to flow out of the packers418,428and/or the latching mechanism408. For example, pressure differential between hydrostatic wellbore pressure external to the packers418,428and fluid pressure inside the inflatable packers418,428may cause the fluid to be evacuated out of the packers418,428via the fluid valve460. The packer tool500may also or instead comprise an automatic retraction mechanism (ARM) (not shown) operably connected with and operable to move (e.g., slide) the upper packer ring414in the upward axial direction to stretch and, thus, retract the packer418sufficiently to permit the latching mechanism408to its normal (i.e., locked) state.

FIGS. 5-9are side sectional views of a portion of an example implementation of a packer tool500during different stages of operation according to one or more aspects of the present disclosure. The packer tool500may be conveyed within a wellbore as part of a tool string, such as the BHA140shown inFIG. 1, the tool string204shown inFIG. 2, and/or other tool strings within the scope of the present disclosure. The packer tool500may be or comprise an example implementation of one or more of the LWD modules144or MWD modules146shown inFIG. 1, one or more of the modules212shown inFIG. 2, and/or the dual-packer tool400shown inFIG. 4, and may thus comprise one or more features and/or modes of operation described above in association with the modules144,146,212and the dual-packer tool400. As described below, the packer tool500is an assembly of a plurality of components operating together in a coordinated manner and, thus, may also be referred to as a packer assembly.

The packer tool500comprises a mandrel512, a lower packer ring (not shown) fixedly connected with the mandrel512, and an upper packer ring (not shown) slidably connected to and, thus, axially movable with respect to the mandrel512. An inflatable (e.g., flexible, elastic) packer (i.e., packer element) (not shown) operable to expand against a sidewall of the wellbore may be sealingly connected with the upper and lower packer rings. The upper packer ring, the lower packer ring, and the inflatable packer may be installed or otherwise disposed around an outer profile518, including one or more outer surfaces, of the mandrel512. A flowline514(e.g., a fluid passage) may extend axially within the mandrel512. The flowline514may be fluidly connected with a pump (not shown) located in another portion of the tool string. The mandrel512may comprise a fluid port (not shown) fluidly connected with the flowline514and with an internal space or volume of the inflatable packer. Accordingly, an inflation fluid (e.g., hydraulic fluid, oil) may be transferred via the flowline514to inflate and deflate the inflatable packer. The mandrel512may further comprise a fluid port516fluidly connected with the flowline514and extending to the outer surface (i.e., outer profile518) of the mandrel512. The mandrel512may also comprise one or more passages519extending longitudinally within the mandrel512. The passage519may be configured to transfer a fluid between opposing ends of the mandrel512.

The packer tool500may be or comprise a dual-packer tool, wherein the mandrel512is an upper mandrel and the packer is an upper packer. The packer tool500may thus further comprise a lower mandrel (not shown) coupled with the upper mandrel and a lower packer (not shown) sealingly connected with the lower mandrel via corresponding upper and lower packer rings (not shown). Similarly to the upper packer, the lower packer may be selectively operable to expand against the sidewall of the wellbore.

The packer tool500further comprises a latching mechanism520selectively operable to limit the axial movement of the slidable upper packer ring with respect to the mandrel512and permit the axial movement of the upper packer ring with respect to the mandrel512. For example, the latching mechanism520may be selectively operable to connect the upper packer ring with the mandrel512to limit the axial movement of the upper packer ring with respect to the mandrel512and disconnect the upper packer ring from the mandrel512to permit the axial movement of the upper packer ring with respect to the mandrel512.

The latching mechanism520may comprise a collar or sleeve522disposed around the mandrel512. The sleeve522may be coupled directly with the upper packer ring or indirectly via one or more intermediate collars, sleeves, or other member524,526connected between the sleeve522and the upper packer ring. One or both of the members524,526may be or form at least a portion of the ARM described above. The sleeve522may be a ratchet sleeve, wherein at least a portion of the sleeve522comprises teeth, splines, castellations, alternating slots and protrusions, or another profile528. The latching mechanism520may further comprise a collet530disposed around and connected with the mandrel512. The collet530may comprise a base532slidably disposed within a channel534extending circumferentially around the mandrel512, which permits the collet530limited axial movement with respect to the mandrel512between opposing upper and lower shoulders (i.e., ends)533,535of the channel534. The collet530may further comprise a plurality of elastically flexible fingers536extending from the base532and distributed circumferentially around the mandrel512. The collet530may be a ratcheting collet, wherein each finger536comprises teeth, splines, castellations, alternating slots and protrusions, or other profiles538configured to engage (i.e., lock with) the profile528of the sleeve522. When engaged together, as shown inFIG. 5, the profiles528,538prevent the sleeve522from moving with respect to the collet530and, thus, prevent the slidable upper ring connected with the sleeve522from moving axially downwards with respect to the mandrel512. Although the profile528of the sleeve522is shown as an internal (i.e., inwardly extending) profile and the profile538of the collet530is shown as an external (i.e., outwardly extending) profile, the sleeve522may be implemented as a collet connected with the upper packer ring and comprising fingers with external profiles and the collet530may be implemented as a sleeve connected with the mandrel512and comprising an internal profile.

The latching mechanism520may further comprise a latching ring, collar, or sleeve540disposed around the mandrel512and operable to move axially with respect to the mandrel512between a first position, in which the latching sleeve540prevents the profiles528,538(and thus the sleeve522and collet530) from disengaging, and a second position, in which the latching sleeve540permits the profiles528,538(and thus the sleeve522and collet530) to disengage.FIG. 5shows the latching sleeve540in the first position with the latching sleeve540positioned between the fingers536and the mandrel512and disposed against an inner profile of the fingers536, such as may prevent or otherwise limit radially inward movement (e.g., elastic bending) of the fingers536and the profile538to prevent the profiles528,538from disengaging.FIG. 6shows the latching sleeve540in the second position with the latching sleeve540at least partially removed from between the fingers536and the mandrel512and not disposed against the inner profile of the fingers536, such as may permit the radially inward movement of the fingers536and the profile538to permit the profiles528,538to disengage.

The latching mechanism520may also comprise an actuation sleeve542operable to move the latching sleeve540between the first and second positions. The actuation sleeve542may be slidably disposed around the mandrel512and connected with the latching sleeve540. The actuation sleeve542may comprise a circumferential inwardly extending shoulder544slidably engaging the outer profile518of the mandrel512. An inner profile of the actuation sleeve542may also slidably engage a circumferential outwardly extending shoulder546fixedly connected with or forming the outer profile518of the mandrel512. Each shoulder544,546may comprise a corresponding fluid seal (not shown), such as may permit the shoulders544,546to sealingly engage the outer profile518of the mandrel512and the inner profile of the actuation sleeve540, respectively, while the actuation sleeve542moves axially along the mandrel512. The actuation sleeve542, the shoulders544,546, and the mandrel512may define an annular volume or space548. The space548may be fluidly connected with the port516such as may permit the space548to receive and discharge the inflation fluid via the flowline514. When the inflation fluid is pumped or otherwise introduced into the space548, the space548expands causing (i.e., actuating) the actuation sleeve542to move downwards with respect to the mandrel512to move the latching sleeve542from the first position to the second position, as indicated by arrow550.

A biasing member552(e.g., a spring) may be operatively connected with the actuation sleeve542and the mandrel512and operable to bias the actuation sleeve542from the second position toward the first position, as indicated by arrow554. The biasing member552may be disposed around the mandrel512, with one end of the biasing member552disposed against a shoulder556fixedly connected with the mandrel512and an opposing end of the biasing member552disposed against the actuation sleeve542. Accordingly, the biasing member552may maintain the latching sleeve540in the first position and/or move the latching sleeve540from the second position to the first position when the inflation fluid is not being pumped into the space548via the flowline514.

As described above, during downhole operation, the latching mechanism408,520of the packer tools400,500may be selectively operable to limit the downward axial movement of the slidable upper packer ring414with respect to the upper mandrel412,512and permit the axial movement of the upper packer ring414with respect to the upper mandrel412,512. The following description describes the operation of the latching mechanism408,520during a typical downhole operation.

Referring toFIGS. 4 and 5, when the dual-packer tool400,500is conveyed downwards within a wellbore, the biasing member552may maintain the latching sleeve540in the first position, limiting downward axial movement of the upper packer ring414with respect to the mandrel412,512. If a portion of the upper packer418is caught against or otherwise contacts a sidewall of the wellbore, the upper packer ring414and portions of the latching mechanism408,520, such as the sleeve522and the collet530, may move axially with respect to the mandrel412,512in the upward direction, as indicated by arrow436, perhaps stretching the packer418to permit the packer418to pass through the wellbore. However, such upward movement may be limited to a distance between the base532of the collet530and the upper shoulder533of the circumferential channel534.

After the packer tool400,500is conveyed within the wellbore to a predetermined location along the wellbore, the pump450may be operated to transfer the inflation fluid to the packers418,428and the latching mechanism408,520via the flowline452,514and the corresponding ports454,456,458,516. The inflation fluid may simultaneously expand the inflatable packers418,428away from the corresponding mandrels412,422,512against the sidewall of the wellbore and operate the latching mechanism408,520to permit the axial movement of the upper packer ring414with respect to the corresponding mandrels412,422,512. A sequencing valve (not shown) may be fluidly connected along the flowline452,514to permit operation of the latching mechanism408,520before expansion of the inflatable packers418,428. Furthermore, although a single flowline452,514is shown fluidly connected with the latching mechanism408,520and the inflatable packers418,428, the latching mechanism408,520and the inflatable packers418,428may each be fluidly connected with the pump450or another fluid source via separate (i.e., fluidly isolated) flowlines, such as may permit independent operation of the latching mechanism408,520and inflation of the inflatable packers418,428. Accordingly, the packer tool400,500may comprise a plurality of flowlines (e.g., a flowline system) fluidly connecting the pump450with the latching mechanism408,520and the inflatable packers418,428independently of each other.

As shown inFIGS. 4 and 6, the inflation fluid pumped into the space548actuates the actuating sleeve542in a downward direction, as indicated by the arrow550, to move the latching sleeve540from the first position to the second position while compressing the biasing member552. The expanding packers418,428narrow (i.e., decrease) in height, pulling the upper packer ring414of the upper packer assembly410in the downward direction, as indicated by arrow438, and the lower packer ring426of the lower packer assembly420in the upward direction, as indicated by arrow436.

As shown inFIGS. 4 and 7, downward tension applied by the upper packer418to the upper packer ring414by the expanding upper packer418is transmitted to the sleeve522and the corresponding profile528causing the fingers536to elastically bend radially inwards, as indicated by arrows558. Such bending of the fingers536permits the profiles528,538to disengage and, thus, permits the sleeve522and the upper packer ring414to move axially with respect to the mandrel512in a downward direction, as indicated by arrow560. When the upper and lower packers418,428fully engage the sidewall, the downhole operations (e.g., formation evaluation) may commence. Because the lower packer ring416of the upper packer assembly410and the upper packer ring424of the lower packer assembly420are fixedly connected with the corresponding mandrels412,422, the volume of the isolated annular wellbore interval between the upper and lower packers418,428may be maintained substantially constant during the subsequent downhole operations.

Referring now toFIGS. 4 and 8, when it is intended to convey the packer tool400,500upwards, such as to move the packer tool400,500to another location within the wellbore or to convey the packer tool400,500to the wellsite surface after completing the downhole operations, the inflation fluid within the packers418,428and the space548of the latching mechanism408,520may be discharged via the flowline452,514and the corresponding ports454,456,458,516. For example, the inflation fluid may be pumped out of the packers418,428and the space548with the pump450or the inflation fluid may be relieved from the packers418,428and the space548with the fluid valve460to retract the packers418,428. The biasing member522may then move the latching sleeve540to the first position and the packers418,428may retract away from the sidewall toward the corresponding mandrels412,422,512. The retracting packers418,428may then increase in height, pushing the upper packer ring414of the upper packer assembly410and the sleeve522in the upward direction, as indicated by the arrow436, and pushing the lower packer ring426of the lower packer assembly420in the downward direction, as indicated by the arrow438. When the sleeve522contacts the fingers536of the collet530, the sleeve522pushes the collet530in the upward direction, as indicated by the arrow562, until the base532of the collet530contacts the upper shoulder533of the circumferential channel534. In such position, the latching sleeve540is not disposed against the fingers536, permitting the fingers536to bend radially inwards.

As shown inFIGS. 4 and 9, while the upper packer ring414and the sleeve522continue to move in the upward direction, as indicated by the arrow562, the moving sleeve522forces the fingers536to bend radially inwards, as indicated by the arrow564, causing the profiles528,538to reengage. After the profiles528,538fully reengage, the packer tool400,500may be conveyed upwards along the wellbore while the biasing member552maintains the latching sleeve540in the first position.

During the upward conveyance, if a portion of the latching mechanism408,520and/or the upper packer418is caught against an obstruction within the wellbore or otherwise contacts the sidewall of the wellbore, the upper packer ring414and portions of the latching mechanism520, such as the sleeve522and the collet530, may move in the downward direction with respect to the upper mandrel512, as indicated by arrow438, until the base532of the collet530contacts the lower shoulder535of the circumferential channel534, preventing further downward movement of the collet530, the sleeve522, and the upper packer ring414. In such position, shown inFIG. 5, the fingers536of the collet530are disposed against the latching sleeve540, which prevents the fingers536from bending radially inwards and, thus, prevents the profiles528,538from disengaging. Therefore, if a portion of the upper packer418is caught against an obstruction or otherwise contacts the sidewall of the wellbore during the upward conveyance, the upper packer ring414will not be permitted to slide downwards and permit the upper packer418to expand, which may cause the packer tool400,500to become stuck within the wellbore. Because the upper packer418will not be permitted to expand, the packer tool400,500may be pulled through the obstruction within the wellbore to be repositioned at a different depth or returned to the surface.

The present disclosure is also directed to one or more methods according to one or more aspects of the present disclosure. The methods described below and/or other operations described herein may be performed utilizing or otherwise in conjunction with at least a portion of one or more implementations of one or more instances of the apparatus shown in one or more ofFIGS. 1, 2, and 4-9and/or otherwise within the scope of the present disclosure. However, the methods and operations described herein may be performed in conjunction with implementations of apparatus other than those depicted inFIGS. 1, 2, and 4-9that are also within the scope of the present disclosure. The methods and operations may be performed manually by one or more human operators, and/or may be performed or caused to be performed automatically by the apparatus described herein and/or by a processing device executing the coded instructions according to one or more aspects of the present disclosure. For example, the processing device may receive input signals and automatically generate and transmit output signals to operate or cause a change in an operational parameter of one or more pieces of the wellsite equipment described above. However, the human operator may also or instead manually operate the one or more pieces of wellsite equipment via the processing device based on sensor signals displayed.

FIG. 10is a flow-chart diagram of at least a portion of an example implementation of a method (600) according to one or more aspects of the present disclosure. The method (600) may comprise coupling (605) an inflatable packer assembly400,500to a tool string140,204. The inflatable packer assembly400,500may comprise a mandrel412,512comprising a flowline452,514extending within the mandrel412,512, an upper packer ring414selectively axially movable with respect to the mandrel412,512, a lower packer ring416fixedly connected with the mandrel412,512, a latching mechanism408,520fluidly connected with the flowline452,514, and an inflatable packer418disposed around the mandrel412,512and sealingly connected with the upper and lower packer rings414,416. The inflatable packer418may be fluidly connected with the flowline452,514.

The method (600) may further comprise conveying (610) the tool string140,204in a downhole direction within a wellbore. After the inflatable packer assembly400,500is conveyed (610) within the wellbore, a fluid may be pumped (615) into the flowline452,514to expand (620) the inflatable packer418away from the mandrel412,512and against a sidewall of the wellbore and operate (625) the latching mechanism408,520to permit the downward axial movement of the upper packer ring414with respect to the mandrel412,512. The mandrel412,512may further comprise an upper port458,516fluidly connecting the flowline452,514with the latching mechanism408,520and a lower port454fluidly connecting the flowline452,514with the inflatable packer418. Accordingly, pumping (615) the fluid into the flowline452,514may transfer the fluid to the latching mechanism408,520via the upper port458,516, and into the inflatable packer418via the lower port454.

The method (600) may also comprise conveying (630) the tool string140,204in an uphole direction within the wellbore while the latching mechanism408,520is limiting (635) the downward axial movement of the upper packer ring414with respect to the mandrel412,512. Limiting (635) the downward axial movement of the upper packer ring414with respect to the mandrel412,512may comprise connecting the upper packer ring414with the mandrel412,512via the latching mechanism408,520. Furthermore, pumping (615) the fluid into the flowline452,514may cause the latching mechanism408,520to disconnect the upper packer ring414from the mandrel412,512to permit the downward axial movement of the upper packer ring414with respect to the mandrel412,512.

The latching mechanism408,520may comprise a first member522connected with the upper packer ring414, a second member530connected with the mandrel412,512, and a third member540. Thus, limiting (635) the downward axial movement of the upper packer ring414with respect to the mandrel412,512may comprise engaging (640) the first and second members522,530with each other to limit axial movement of the first member522with respect to the second member530, and maintaining (645) the third member540in a first position in which at least a portion of the third member540prevents the first and second members522,530from disengaging. Operating (625) the latching mechanism408,520may comprise moving (650) the third member540to a second position in which at least a portion of the third member540permits the first and second members522,530to disengage to permit the downward axial movement of the upper packer ring414with respect to the mandrel412,512. In the first position, at least a portion of the third member540may be disposed against the second member530to prevent the second member530from elastically bending to prevent the first and second members522,530from disengaging, and in the second position, at least a portion of the third member540may not be disposed against the second member530to permit the second member530to elastically bend to permit the first and second members522,530to disengage.

The first member522may comprise an internal profile528and the second member530may comprise an external profile538. Thus, engaging (640) the first and second members522,530with each other comprises engaging the first and second profiles528,538with each other to limit axial movement of the first member522with respect to the second member530, maintaining (645) the third member540in the first position may comprise maintaining the third member540disposed between the mandrel412,512and the second member530to limit radially inward movement of the second member530to prevent the internal and external profiles528,538from disengaging, and operating (625) the latching mechanism408,520to move the third member540to the second position may comprise operating the latching mechanism408,520to move at least a portion of the third member540such that the third member540is not disposed between the mandrel412,512and the second member530to permit the radially inward movement of the second member530to permit the internal and external profiles528,538to disengage. Maintaining (645) the third member540in the first position may further comprise biasing the third member540toward the first position via a biasing member552.

The third member540may comprise a latching sleeve540and an actuation sleeve542. The latching sleeve540may be disposed around the mandrel412,512and configured to prevent the first and second members522,530from disengaging when in the first position and permit the first and second members522,530to disengage when in the second position. The actuation sleeve542may be disposed around the mandrel412,512and connected with the latching sleeve540. The actuation sleeve542may define an annular space548between the actuation sleeve542and the mandrel412,512, and the flowline452,514may be fluidly connected with the annular space548. Accordingly, pumping (615) the fluid into the flowline452,514may transfer the fluid into the annular space548causing the actuation sleeve542to move axially with respect to the mandrel412,512to axially move the latching sleeve540from the first position to the second position.

The inflatable packer assembly400,500may be an inflatable dual-packer assembly, wherein the inflatable packer418is an upper inflatable packer418and the inflatable packer assembly400,500further comprises a lower inflatable packer428. Thus, pumping (615) the fluid into the flowline452,514also expands (655) the lower inflatable packer428to isolate a section of the wellbore between the upper and lower inflatable packers418,428, and the method (600) may further comprise, after conveying the tool string140,204in the downhole direction within the wellbore and before conveying the tool string140,204in the uphole direction within the wellbore, performing (660) formation evaluation operation within the isolated section.

After conveying (610) the tool string140,204in the downhole direction within the wellbore and before conveying (630) the tool string140,204in the uphole direction within the wellbore, the method (600) may further comprise transferring (665) the fluid away from the inflatable packer418and the latching mechanism408,520via the flowline452,514to retract (670) the inflatable packer418toward the mandrel412,512away from the sidewall of the wellbore, and cause (675) the latching mechanism408,520to limit the downward axial movement of the upper packer ring414with respect to the mandrel412,512. Transferring (665) the fluid away from the inflatable packer418via the flowline452,514to retract the inflatable packer418may be caused by operating a fluid valve460to permit the fluid within the inflatable packer418to flow out of the inflatable packer418in response to pressure differential between hydrostatic wellbore pressure external to the inflatable packer418and fluid pressure inside the inflatable packer418.

In view of the entirety of the present application, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising a dual packer assembly for conveyance within a wellbore, wherein the dual packer assembly comprises: (A) an upper packer assembly comprising: (1) an upper mandrel; (2) a first upper packer ring axially movable with respect to the upper mandrel; (3) a first lower packer ring fixedly connected with the upper mandrel; and (4) an upper inflatable packer disposed around the upper mandrel and sealingly connected with the first upper and first lower packer rings, wherein the upper inflatable packer is operable to expand against a sidewall of the wellbore; and (B) a lower packer assembly comprising: (1) a lower mandrel coupled with the upper mandrel; (2) a second upper packer ring fixedly connected with the lower mandrel; (3) a second lower packer ring axially movable with respect to the lower mandrel; and (4) a lower inflatable packer disposed around the lower mandrel and sealingly connected with the second upper and second lower packer rings, wherein the lower inflatable packer is operable to expand against the sidewall of the wellbore, and wherein the upper and lower inflatable packers are collectively operable to isolate a section of the wellbore when expanded.

The upper packer assembly may further comprise a latching mechanism selectively operable to: limit the axial movement of the first upper packer ring with respect to the upper mandrel; and permit the axial movement of the first upper packer ring with respect to the upper mandrel. In such implementations, among others within the scope of the present disclosure, the latching mechanism may be selectively operable to: connect the first upper packer ring with the upper mandrel to limit the axial movement of the first upper packer ring with respect to the upper mandrel; and disconnect the first upper packer ring from the upper mandrel to permit the axial movement of the first upper packer ring with respect to the upper mandrel. The dual packer assembly may further comprise a flowline extending within the upper and lower mandrels, wherein the flowline may be fluidly connected with the latching mechanism, and wherein the latching mechanism may be operable to permit the axial movement of the first upper packer ring with respect to the upper mandrel upon being actuated by a fluid from the flowline. The flowline may be fluidly connected with the upper and lower inflatable packers, the upper and lower inflatable packers may be operable to expand against the sidewall of the wellbore upon receiving the fluid from the flowline, and the latching mechanism may be operable to permit the axial movement of the first upper packer ring with respect to the upper mandrel while the upper and lower inflatable packers are being expanded against the sidewall of the wellbore.

The upper mandrel may comprise a first outer profile having a first diameter. The first upper packer ring, the first lower packer ring, and the upper inflatable packer may be disposed about the first outer profile. The upper mandrel may further comprise a lower coupler coupled with an upper coupler of the lower mandrel. The lower coupler may have a second diameter that is substantially greater than the first diameter. The lower coupler may be a box connector, and the upper coupler may be a pin connector. The lower coupler may be at a lower end of the upper mandrel opposite an upper end of the upper mandrel, and the upper mandrel may be configured to receive thereon the first upper packer ring, the first lower packer ring, and the upper inflatable packer at the upper end of the mandrel during assembly of the dual packer assembly.

The present disclosure also introduces an apparatus comprising an inflatable packer assembly configured to be conveyed within a wellbore, wherein the inflatable packer assembly comprises: (A) a mandrel comprising a flowline; (B) a first packer ring slidably connected with the mandrel; (C) a second packer ring fixedly connected with the mandrel; (D) a latching mechanism fluidly connected with the flowline, wherein the latching mechanism is operable to: (1) limit movement of the first packer ring with respect to the mandrel; and (2) permit the movement of the first packer ring with respect to the mandrel upon being actuated by a fluid from the flowline; and (E) an inflatable packer disposed around the mandrel and sealingly connected with the first and second packer rings, wherein the inflatable packer is fluidly connected with the flowline, and wherein the inflatable packer is operable to expand against a sidewall of the wellbore upon receiving the fluid from the flowline.

The first packer ring may be an upper packer ring and the second packer ring may be a lower packer ring. The inflatable packer assembly may be an upper packer assembly, the mandrel may be an upper mandrel, the inflatable packer may be an upper packer, and the apparatus may further comprise a lower packer assembly comprising: a lower mandrel coupled with the upper mandrel; and a lower packer disposed around the lower mandrel and operable to expand against the sidewall of the wellbore, wherein the upper and lower packers are collectively operable to isolate a section of the wellbore when expanded.

The flowline may extend longitudinally within the mandrel, and the mandrel may further comprise: a first port fluidly extending to an outer surface of the mandrel and fluidly connecting the flowline with the latching mechanism; and a second port fluidly extending to the outer surface of the mandrel and fluidly connecting the flowline with the inflatable packer.

The fluid transmitted via the flowline may expand the inflatable packer, and may operate the latching mechanism to permit the movement of the first packer ring with respect to the mandrel.

The latching mechanism may be operable to: connect the first packer ring with the mandrel to limit the movement of the first packer ring with respect to the mandrel; and upon being actuated by the fluid from the flowline, disconnect the first packer ring from the mandrel to permit the movement of the first packer ring with respect to the mandrel.

The latching mechanism may comprise a first member connected with the first packer ring, a second member connected with the mandrel, and a third member. The first and second members may be operable to engage each other to limit the movement of the first member with respect to the second member to limit the movement of the first packer ring with respect to the mandrel. The third member may be operable to, upon being actuated by the fluid from the flowline, move from a first position in which at least a portion of the third member prevents the first and second members from disengaging to a second position in which the at least a portion of the third member permits the first and second members to disengage to permit the movement of the first packer ring with respect to the mandrel. For example, in the first position, the at least a portion of the third member may be disposed against the second member to prevent the second member from elastically bending to prevent the first and second members from disengaging, and in the second position, the at least a portion of the third member may not be disposed against the second member to permit the first member to elastically bend to permit the first and second members to disengage. In an example implementation, the first member may comprise an internal profile, the second member may comprise an external profile, the internal and external profiles may be configured to engage to limit the movement of the first member with respect to the second member, and: in the first position, the at least a portion of the third member may be disposed between the mandrel and the second member to limit radially inward movement of the second member to prevent the internal and external profiles from disengaging; and in the second position, the at least a portion of the third member may not be disposed between the mandrel and the second member to permit the radially inward movement of the second member to permit the internal and external profiles to disengage. In an example implementation: the first member may be or comprise a sleeve disposed around the mandrel and having a first profile; the second member may be or comprise a collet disposed around the mandrel and having a second profile; the first and second profiles may be configured to engage to limit the movement of the first member with respect to the second member; the third member may comprise a ring disposed around the mandrel and operable to move between the first and second positions; in the first position, the ring may be disposed against the collet to limit radial movement of the second profile to prevent the first and second profiles from disengaging; and in the second position, the ring may not be disposed against the collet to permit the radial movement of the second profile to permit the first and second profiles to disengage. In an example implementation, the third member may comprise: (A) a latching sleeve disposed around the mandrel and operable to: (1) prevent the first and second members from disengaging when in the first position; and (2) permit the first and second members to disengage when in the second position; and (B) an actuation sleeve disposed around the mandrel and connected with the latching sleeve, wherein the actuation sleeve may define an annular space between the actuation sleeve and the mandrel, wherein the flowline may be fluidly connected with the annular space, and wherein the actuation sleeve may be operable to move axially with respect to the mandrel to move the latching sleeve from the first position to the second position upon the annular space receiving the fluid via the flowline. The apparatus may further comprise a biasing member operatively connected with the third member and the mandrel, and the biasing member may be operable to bias the third member from the second position toward the first position.

The flowline may be a flowline system comprising a first flowline and a second flowline, wherein the flowline fluidly connected with latching mechanism may be the first flowline, and wherein the flowline fluidly connected with the inflatable packer may be the second flowline.

The present disclosure also introduces a method comprising coupling an inflatable packer assembly to a tool string, wherein the inflatable packer assembly comprises: a mandrel comprising a flowline extending within the mandrel; an upper packer ring selectively axially movable with respect to the mandrel; a lower packer ring fixedly connected with the mandrel; a latching mechanism fluidly connected with the flowline; and an inflatable packer disposed around the mandrel and sealingly connected with the upper and lower packer rings, wherein the inflatable packer is fluidly connected with the flowline. The method may also comprise conveying the tool string in a downhole direction within a wellbore, and pumping a fluid into the flowline to: expand the inflatable packer away from the mandrel and against a sidewall of the wellbore; and operate the latching mechanism to permit the axial movement of the upper packer ring with respect to the mandrel. The method may also comprise conveying the tool string in an uphole direction within the wellbore while the latching mechanism is limiting the axial movement of the upper packer ring with respect to the mandrel.

The mandrel may further comprise: an upper port fluidly connecting the flowline with the latching mechanism; and a lower port fluidly connecting the flowline with the inflatable packer, wherein pumping the fluid into the flowline may transfer the fluid to the latching mechanism via the upper port and into the inflatable packer via the lower port.

Limiting the axial movement of the upper packer ring with respect to the mandrel may comprise connecting the upper packer ring with the mandrel via the latching mechanism, and pumping the fluid into the flowline may cause the latching mechanism to disconnect the upper packer ring from the mandrel to permit the axial movement of the upper packer ring with respect to the mandrel.

The latching mechanism may comprise: a first member connected with the upper packer ring; a second member connected with the mandrel; and a third member. Limiting the axial movement of the upper packer ring with respect to the mandrel may comprise: engaging the first and second members with each other to limit axial movement of the first member with respect to the second member; and maintaining the third member in a first position in which at least a portion of the third member prevents the first and second members from disengaging. Operating the latching mechanism may comprise moving the third member to a second position in which the at least a portion of the third member permits the first and second members to disengage to permit the axial movement of the upper packer ring with respect to the mandrel. In the first position, the at least a portion of the third member may be disposed against the second member to prevent the second member from elastically bending to prevent the first and second members from disengaging, and in the second position, the at least a portion of the third member may not be disposed against the second member to permit the second member to elastically bend to permit the first and second members to disengage. In an example implementation, the first member may comprise an internal profile, the second member may comprise an external profile, engaging the first and second members with each other may comprise engaging the first and second profiles with each other to limit axial movement of the first member with respect to the second member, maintaining the third member in the first position may comprise maintaining the third member disposed between the mandrel and the second member to limit radially inward movement of the second member to prevent the internal and external profiles from disengaging, and operating the latching mechanism to move the third member to the second position may comprise operating the latching mechanism to move the at least a portion of the third member such that the third member is not disposed between the mandrel and the second member to permit the radially inward movement of the second member to permit the internal and external profiles to disengage. In an example implementation: (A) the third member may comprise: (1) a latching sleeve disposed around the mandrel and configured to: (i) prevent the first and second members from disengaging when in the first position; and (ii) permit the first and second members to disengage when in the second position; and (2) an actuation sleeve disposed around the mandrel and connected with the latching sleeve, wherein the actuation sleeve may define an annular space between the actuation sleeve and the mandrel, and wherein the flowline may be fluidly connected with the annular space; and (B) pumping the fluid into the flowline may transfer the fluid into the annular space causing the actuation sleeve to move axially with respect to the mandrel to axially move the latching sleeve from the first position to the second position. Maintaining the third member in the first position may comprise biasing the third member toward the first position via a biasing member.

The inflatable packer may be an upper inflatable packer, the inflatable packer assembly may further comprise a lower inflatable packer, pumping the fluid into the flowline may expand the lower inflatable packer to isolate a section of the wellbore between the upper and lower inflatable packers, and the method may further comprise, after conveying the tool string in the downhole direction within the wellbore and before conveying the tool string in the uphole direction within the wellbore, performing a formation evaluation operation within the isolated section.

The method may further comprise, after conveying the tool string in the downhole direction within the wellbore and before conveying the tool string in the uphole direction within the wellbore, transferring the fluid away from the inflatable packer and the latching mechanism via the flowline to: retract the inflatable packer toward the mandrel away from the sidewall of the wellbore; and cause the latching mechanism to limit the axial movement of the upper packer ring with respect to the mandrel. Transferring the fluid away from the inflatable packer via the flowline to retract the inflatable packer may be caused by operating a fluid valve to permit the fluid within the inflatable packer to flow out of the inflatable packer in response to pressure differential between hydrostatic wellbore pressure external to the inflatable packer and fluid pressure inside the inflatable packer.

The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the implementations introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.