Non-Extruding Single Packer

Abstract

An inflatable packer assembly for conveyance and adjustment within a wellbore. The inflatable packer assembly includes a first end assembly, a second end assembly, and a mandrel extending between the first and second end assemblies and comprising a fluid port on an outer surface of the mandrel. The inflatable packer assembly further includes an expandable packer disposed around the mandrel and sealingly connected with one or both of the first and second end assemblies. At least a portion of the first end assembly extends around the mandrel to define an annular space between the first end assembly and the mandrel. The fluid port extends to the annular space and passes a fluid to inflate the expandable packer.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to, and the benefit of the earlier filing date of, EP Patent Application No. 17306304.1, titled “Packer Adjustment Downhole,” filed Sep. 29, 2017, the entirety of which is hereby incorporated herein by reference.

BACKGROUND OF THE DISCLOSURE

In the oil and gas industry, many downhole tools include expandable inflatable packers. For example, a dual-packer tool may be positioned at an intended location within a wellbore, and elastomeric sealing elements of the packers are radially expanded to form an annular seal with the wellbore wall or a casing lining the wellbore to fluidly isolate sections of the wellbore between the packers. Similar operations may utilize a three-dimensional radial packer having circumferentially-spaced fluid inlets integrated with the elastomeric sealing element of a single packer.

Such dual- and single-packer tools can have limited deflation efficiency, and may mostly rely on the elastomeric properties at high temperature. Rubber tends to creep when exposed to stress and high temperature, such that it can be difficult to force deflation back to the initial, unexpanded diameter without removing the tool from the wellbore. Some packer tools include retraction mechanisms and/or other devices, such as may be attached to an extremity of the packer to apply a deflation force, but such devices have had limited effectiveness.

Additionally, while deflating the packer may be achieved by pumping inflation fluid out of the packer until the packer is again compressed against the support structure of the downhole tool, this operation can be dangerous because the packer can be accidentally put in negative pressure, such that hydrostatic pressure is above inflation fluid pressure. When this situation occurs, the packer is often damaged when a rubber inner bladder of the packer is forced into or extruded through a hole, port, or an asperity on an outer surface of the support structure.

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 including an inflatable packer assembly for coupling within a tool string conveyed within a wellbore. The inflatable packer assembly includes a mandrel comprising, a first connector assembly, a second connector assembly, and an expandable packer. The mandrel includes a port in an outer surface of the mandrel, and a flowline extending within the mandrel and in fluid communication with the port. The first connector assembly is connected to the mandrel such that the port is axially disposed between opposing ends of the first connector assembly. The first connector assembly is for coupling with a first portion of the tool string such that a second flowline of the first portion is in fluid communication with the first flowline. The second connector assembly is for coupling with a second portion of the tool string. The expandable packer is disposed around the mandrel and connected with the first and second connector assemblies, such that fluid received from the first and second flowlines via the port expands the expandable packer against a sidewall of the wellbore or a casing within the wellbore.

The present disclosure also introduces an apparatus including an inflatable packer assembly for conveyance within a wellbore. The inflatable packer assembly includes a first end assembly, a second end assembly, a mandrel, and an expandable packer. The mandrel extends between the first and second end assemblies and includes a fluid port on an outer surface of the mandrel. At least a portion of the first end assembly extends around the mandrel to define an annular space between the first end assembly and the mandrel. The fluid port extends to the annular space. The expandable packer is disposed around the mandrel and sealingly connected with the first and second end assemblies. The fluid port and annular space pass a fluid to inflate the expandable packer.

The present disclosure also introduces a method including coupling an inflatable packer assembly to a tool string. The inflatable packer assembly includes a mandrel, a first connector assembly, a second connector assembly, and an expandable packer. The mandrel includes a port in an outer surface of the mandrel, and a first flowline extending within the mandrel and in fluid communication with the port. The first connector assembly is connected to the mandrel such that the port is axially disposed between opposing ends of the first connector assembly. The expandable packer is disposed around the mandrel and connected with the first and second connector assemblies. Coupling the inflatable packer assembly to the tool string includes coupling the first connector assembly with a first portion of the tool string such that a second flowline of the first portion of the tool string is in fluid communication with the first flowline, and coupling the second connector assembly with a second portion of the tool string. The method also includes conveying the inflatable packer assembly within a wellbore to a selected location along the wellbore, and inflating the expandable packer away from the mandrel to against a sidewall of the wellbore, or a casing within the wellbore, by transferring a fluid into the expandable packer through the first flowline, the second flowline, and the port.

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 material 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.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 4 is a side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 5 is a sectional view of a portion of the apparatus shown in FIG. 4 according to one or more aspects of the present disclosure.

FIG. 6 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 7 is a flow-chart diagram of at least a portion of an example implementation of a method related to one or more aspects of the present disclosure.

FIG. 8 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.

FIG. 9 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.

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. 1 is a schematic view of an example wellsite system 100 to which one or more aspects of the present disclosure may be applicable. The wellsite system 100 may be onshore or offshore. In the example wellsite system 100 shown in FIG. 1, a wellbore 104 is formed in one or more subterranean formations 102 by rotary drilling. Other example systems within the scope of the present disclosure may also or instead utilize directional drilling. While some elements of the wellsite system 100 are depicted in FIG. 1 and described below, it is to be understood that the wellsite system 100 may include other components in addition to, or instead of, those presently illustrated and described.

As shown in FIG. 1, a drillstring 112 suspended within the wellbore 104 comprises a bottom hole assembly (BHA) 140 that includes or is coupled with a drill bit 142 at its lower end. The surface system includes a platform and derrick assembly 110 positioned over the wellbore 104. The platform and derrick assembly 110 may comprise a rotary table 114, a kelly 116, a hook 118, and a rotary swivel 120. The drillstring 112 may be suspended from a lifting gear (not shown) via the hook 118, 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 hook 118 is 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 hook 118 and the drillstring 112 coupled thereto. The drillstring 112 comprises one or more types of tubular members, such as drill pipes, threadedly attached one to another, perhaps including wired drilled pipe.

The drillstring 112 may be rotated by the rotary table 114, which engages the kelly 116 at the upper end of the drillstring 112. The drillstring 112 is suspended from the hook 118 in a manner permitting rotation of the drillstring 112 relative to the hook 118. Other example wellsite systems within the scope of the present disclosure may utilize a top drive system to suspend and rotate the drillstring 112, whether in addition to or instead of the illustrated rotary table system.

The surface system may further include drilling fluid or mud 126 stored in a pit or other container 128 formed at the wellsite. The drilling fluid 126 may be oil-based mud (OBM) or water-based mud (WBM). A pump 130 delivers the drilling fluid 126 to the interior of the drillstring 112 via a hose or other conduit 122 coupled to a port in the rotary swivel 120, causing the drilling fluid to flow downward through the drillstring 112, as indicated in FIG. 1 by directional arrow 132. The drilling fluid exits the drillstring 112 via ports in the drill bit 142, and then circulates upward through the annulus region between the outside of the drillstring 112 and the wall 106 of the wellbore 104, as indicated in FIG. 1 by directional arrows 134. In this manner, the drilling fluid 126 lubricates the drill bit 142 and carries formation cuttings up to the surface as it is returned to the container 128 for recirculation.

The BHA 140 may comprise one or more specially made drill collars near the drill bit 142. Each such drill collar may comprise one or more devices permitting measurement of downhole drilling conditions and/or various characteristic properties of the subterranean formation 102 intersected by the wellbore 104. For example, the BHA 140 may comprise one or more logging-while-drilling (LWD) modules 144, one or more measurement-while-drilling (MWD) modules 146, a rotary-steerable system and motor 148, and perhaps the drill bit 142. 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 BHA 140 than as depicted in FIG. 1.

The LWD modules 144 may comprise one or more devices for measuring characteristics of the formation 102, including for obtaining a sample of fluid from the formation 102. The MWD modules 146 may comprise one or more devices for measuring characteristics of the drillstring 112 and/or the drill bit 142, such as for measuring weight-on-bit, torque, vibration, shock, stick slip, tool face direction, and/or inclination, among other examples. The MWD modules 146 may further comprise an apparatus 147 for generating electrical power to be utilized by the downhole system, such as a mud turbine generator powered by the flow of the drilling fluid 126. Other power and/or battery systems may also or instead be employed. One or more of the LWD modules 144 and/or the MWD modules 146 may be or comprise at least a portion of a packer tool as described below.

The wellsite system 100 also includes a data processing system that can include one or more, or portions thereof, of the following: the surface equipment 190, control devices and electronics in one or more modules of the BHA 140 (such as a downhole controller 150), 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 BHA 140 and/or the surface equipment 190. Such programs may utilize data received from the BHA 140 via mud-pulse telemetry and/or other telemetry means, and/or may transmit control signals to operative elements of the BHA 140. The programs may be stored on a tangible, non-transitory, computer-usable storage medium associated with the one or more processors of the BHA 140 and/or surface equipment 190, 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. 2 is a schematic view of another example wellsite system 200 to which one or more aspects of the present disclosure may be applicable. The wellsite system 200 may be onshore or offshore. In the example wellsite system 200 shown in FIG. 2, a tool string 204 is conveyed into the wellbore 104 via a conveyance means 208, which may be or comprise a wireline, a slickline, or a fluid conduit, such as coiled tubing, completion tubing, a liner, or a casing. As with the wellsite system 100 shown in FIG. 1, the example wellsite system 200 of FIG. 2 may be utilized for evaluation of the wellbore 104 and/or the formation 102 penetrated by the wellbore 104.

The tool string 204 is suspended in the wellbore 104 from the lower end of the conveyance means 208, which may be a multi-conductor logging cable spooled on a surface winch (not shown). The conveyance means 208 may include at least one conductor that facilitates data communication between the tool string 204 and surface equipment 290 disposed on the surface. The surface equipment 290 may have one or more aspects in common with the surface equipment 190 shown in FIG. 1.

The tool string 204 and conveyance means 208 may be structured and arranged with respect to a service vehicle (not shown) at the wellsite. For example, the conveyance means 208 may be connected to a drum (not shown) at the wellsite surface, such that rotation of the drum may raise and lower the tool string 204. The drum may be disposed on a service vehicle or a stationary platform. The service vehicle or stationary platform may further contain the surface equipment 290.

The tool string 204 comprises one or more elongated housings encasing various electronic components and modules schematically represented in FIG. 2. For example, the illustrated tool string 204 includes several modules 212, 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 string 204 within the scope of the present disclosure may include additional or fewer components or modules relative to the example implementation depicted in FIG. 2.

The wellsite system 200 also includes a data processing system that can include one or more, or portions thereof, of the following: the surface equipment 290, control devices and electronics in one or more modules of the tool string 204 (such as a downhole controller 216), 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 modules 212 of the tool string 204 and/or the surface equipment 290. Such programs may utilize data received from the downhole controller 216 and/or other modules 212 via the conveyance means 208, and may transmit control signals to operative elements of the tool string 204. The programs may be stored on a tangible, non-transitory, computer-usable storage medium associated with the one or more processors of the downhole controller 216, other modules 212 of the tool string 204, and/or the surface equipment 290, 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.

While FIGS. 1 and 2 illustrate example wellsite systems 100 and 200, respectively, that convey a downhole tool/string into the wellbore 104, other example implementations consistent with the scope of this disclosure may utilize other conveyance means to convey tools/strings into the wellbore 104. 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.

FIG. 3 is a schematic view of at least a portion of an example implementation of an inflatable packer tool 300 configured to be conveyed within a wellbore according to one or more aspects of the present disclosure. The packer tool 300 may be implemented as one or more of the LWD modules 144 or MWD modules 146 shown in FIG. 1, and/or one or more of the modules 212 shown in FIG. 2, and may thus be conveyed within the wellbore 104 via a wireline, a slickline, a drillstring, coiled tubing, completion tubing, a liner, a casing, and/or other conveyance means. As described below, the packer tool 300 is 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 inflatable packer tool 300 comprises a first end assembly 310 at a first end of the packer tool 300, and a second end assembly 312 at an opposing second end of the packer tool 300. The end assemblies 310, 312 may be or comprise connector assemblies, such as may be configured to couple the packer tool 300 within a tool string. For example, the end assembly 310 may be coupled with a first (e.g., uphole) portion 302 of the tool string, and the end assembly 312 may be coupled with a second (e.g., downhole) portion 304 of the tool string. The tool string may be the BHA 140 shown in FIG. 1, the tool string 204 shown in FIG. 2, and/or other tool strings within the scope of the present disclosure.

A mandrel 314 (e.g., a tube) extends between the end assemblies 310, 312. The first and/or second end assembly 310, 312 may be connected (e.g., fixedly, slidably) with the mandrel 314, and at least a portion of the first and/or second end assembly 310, 312 may extend around the mandrel 314. An inflatable (e.g., flexible, elastic) packer 316 is disposed around the mandrel 314, and may be sealingly connected with one or both of the end assemblies 310, 312. In a fully deflated (i.e., retracted) state of the packer 316, an inner surface of the packer 316 may be disposed against and/or in contact with an outer profile (e.g., surface) of the mandrel 314. In an inflated (i.e., expanded) state of the packer 316, the inner surface of the packer 316 may be disposed away from the outer profile of the mandrel 314 and an outer surface of the packer 316 may be disposed against a sidewall of the wellbore or a casing within the wellbore to fluidly seal a portion of the wellbore and/or to maintain the packer tool 300 in position within the wellbore.

The mandrel 314 comprises a fluid port 318 on an outer surface of the mandrel 314, and a flowline 320 extending within the mandrel 314 and in fluid communication with the port 318. The port 318 may be axially disposed between opposing axial ends 320, 322 of the end assembly 310 such that at least a portion of the end assembly 310 extends around or covers the port 318.

The outer profile of the mandrel 314, including one or more outer surfaces of the mandrel 314, may be substantially smooth along a length of the mandrel 314 extending between the end assemblies 310, 312. For example, a length of the mandrel 314 that is not surrounded by the end assemblies 310, 312 may be substantially cylindrical and not include additional ports, depressions, holes, asperities, protrusions, and/or other irregularities. The outer profile of the mandrel 314 may also or instead be substantially smooth along a length of the mandrel 314 between the port 318 and the end assembly 312. Thus, the outer profile of the mandrel 314 may be substantially smooth along a length of the mandrel 314 that is directly surrounded by, disposed against, or contacts the packer 316 when the packer 316 is deflated.

The portion 302 of the tool string may comprise a fluid pump 306 fluidly connected with a flowline 308 extending axially along the portion 302 of the tool string. When the end assembly 310 is coupled with the portion 302 of the tool string, the flowlines 308, 320 are fluidly connected to fluidly connect the pump 306 with the flowline 320 and the port 318. Accordingly, during downhole operations (e.g., fluid sampling operations), the pump 306 may pump (i.e., discharge) a fluid (e.g., inflation fluid) into the packer 316 via the flowlines 308, 320 and the port 318 to expand the packer 316 away from the mandrel 314 to against the sidewall of the wellbore or the casing within the wellbore. The pump 306 may also pump (i.e., draw) the fluid out of the packer 316 via the flowlines 308, 320 and the port 318 to retract the packer 316 away from the sidewall of the wellbore or the casing toward and into contact with the mandrel 314.

Although not shown, the packer tool 300 may comprise multiple instances of the port 318 distributed circumferentially around the mandrel 314 (i.e., along an outer surface of the mandrel 314), each located between the opposing ends 320, 322 of the end assembly 310 and connected with the flowline 320. Although not shown, the packer tool 300 may also or instead comprise one or more fluid ports located between the opposing ends of the end assembly 312, each connected with the flowline 320 or another flowline extending through the mandrel 314. Accordingly, the packer 316 may be inflated and deflated from one or both ends of the packer 316.

FIG. 3 further shows a port 319 (drawn in phantom lines) on an outer surface of the mandrel 314 and a flowline 321 (drawn in phantom lines) extending within the mandrel 314 and in fluid communication with the port 319. The port 319 and the flowline 321 are not part of the packer tool 300, but are shown in FIG. 3 to indicate the location of the port 319 in conventional packer tools. Namely, the port 319 is located along the mandrel 314 adjacent to the packer 316, such that when the packer 316 is fully deflated (i.e., retracted), the inner surface of the packer 316 is disposed against and/or in contact with the port 319. Such location of the port 319 may cause an inner layer (e.g., a rubber layer) of the packer 316 to be forced into and/or extruded through the port 319, damaging the inner layer. Such situation may take place when the hydrostatic pressure within the wellbore is greater than the pressure within the packer 316, for example, when the hydrostatic pressure is greater than the pressure of the fluid within the flowline 321.

FIG. 4 is a side view of at least a portion of an example implementation of a packer tool 400 according to one or more aspects of the present disclosure. The packer tool 400 may be implemented as one or more of the LWD modules 144 or MWD modules 146 shown in FIG. 1, one or more of the modules 212 shown in FIG. 2, and/or the packer tool 300 shown in FIG. 3, and may thus be conveyed within the wellbore 104 via a conveyance means described in association with FIGS. 1-3. An uphole portion of the packer tool 400 includes an uphole connector assembly 402 comprising a nipple 410, a lock ring 412, and a retainer 414, which collectively retain an uphole portion of an expandable packer 416. A downhole portion of the packer tool 400 may similarly include a downhole connector assembly 404 comprising a nipple 418, a lock ring 420, and a retainer 422 collectively retaining a downhole portion of the packer 416. The uphole connector assembly 402 may be configured to couple the packer tool 400 to an uphole portion 406 (shown in FIG. 5) of a tool string, and the downhole connector assembly 404 may be configured to couple the packer tool 400 to a downhole portion (not shown) of the tool string. Such means retaining the uphole and/or downhole portions of the packer 416 may move axially relative to a mandrel 424 (e.g., a tube) (shown in FIG. 5) of the packer tool 400. However, the scope of the present disclosure also includes impementations in which means other than as described above are utilized to retain the packer 416.

FIG. 5 is a sectional view of an uphole portion of the packer tool 400 shown in FIG. 4 according to one or more aspects of the present disclosure. The nipple 410 may be coupled with the mandrel 424 via threads, fasteners, interference/press fit, and/or other means. The nipple 410 may instead also be slidably coupled with the mandrel 424, such as may permit the nipple 410 and, thus, the connector assembly 402 to slide axially along the mandrel 424 in an axially inward direction 426 when the packer 416 is being inflated, and in an axially outward direction 428 when the packer 416 is being deflated. The nipple 410 may partially extend into an uphole end 430 of the packer 416. For example, the uphole end 430 of the packer 416 may abut a downhole-facing shoulder 432 of the nipple 410. A crimped skirt 434 and the nipple 410 may cooperatively secure an uphole portion of the packer 416, such as via corresponding external undulations 436 of the nipple 410 and internal undulations 438 of the crimped skirt 434. The retainer 414 may secure the crimped skirt 434 in the position depicted in FIG. 5, and the lock ring 412 may threadedly or otherwise couple the retainer 414 to the nipple 410.

The packer 416 is disposed around the mandrel 424 and may comprise one or more of an inner elastic layer 440, an inner support layer 442, an outer elastic layer 444, an outer support layer 446, and an intermediate layer 448. The inner elastic layer 440 may be formed of rubber and/or other elastic materials. The inner support layer 442 may be at least partially adhered to the inner elastic layer 440, and may be formed of rubber, metal, and/or other materials. The outer elastic layer 444 may be formed of rubber and/or other elastic materials that may be utilized to sealingly engage a wellbore or casing sidewall. The outer support layer 446 may be at least partially adhered to the outer elastic layer 444 and/or the inner support layer 442, and may be formed of rubber, metal, and/or other materials. The intermediate layer 448 is retained between the inner and outer support layers 442, 446, and at least a portion of the intermediate layer 448 may be adhered to the inner and/or outer support layers 442, 446. The intermediate layer 448 may comprise cables made of metal and/or other materials.

The mandrel 424 extends between the connector assemblies 402, 404, and at least a portion of the uphole and/or downhole connector assembly 402, 404 may extend around the mandrel 424. In a fully deflated (i.e., retracted) state of the packer 416, an inner surface 450 of the packer 416 (i.e., inner surface of the inner elastic layer 440) may be disposed against and/or in contact with an outer profile 452 (e.g., outer surface) of the mandrel 424. In an inflated (i.e., expanded) state of the packer 416, the inner surface 450 of the packer 416 may be disposed away from the outer profile 452 of the mandrel 424, forming an internal space (i.e., volume) (not shown) between the mandrel 424 and the packer 416. In the inflated state, an outer surface 454 of the packer 416 (i.e., outer surface of the outer elastic layer 444) may be disposed against a sidewall of the wellbore or a casing within the wellbore to fluidly seal a portion of the wellbore and/or to maintain the packer tool 400 in position within the wellbore.

The mandrel 424 has a fluid port 456 on an outer surface of the outer profile 452 of the mandrel 424, and a flowline 458 (e.g., a fluid passage) extending longitudinally within the mandrel 424 and in fluid communication with the port 456. As further described below, the flowline 458 may be configured to transfer a fluid from an uphole portion 406 of the tool string to inflate the packer 416. The mandrel 424 may also have an axial passage 460 extending longitudinally within the mandrel 424. The axial passage 460 may be configured to transfer a fluid through the packer tool 400 between the opposing ends of the tool string connected with the packer tool 400. The port 456 may be axially disposed between opposing axial ends 462, 464 of the connector assembly 402, such that at least a portion of the connector assembly 402 extends around or covers the port 456. For example, the nipple 410 of the connector assembly 410 may comprise an elongated collar or sleeve 411 extending around or covering the port 456. A portion of the nipple 410, including the sleeve 411, may have an inner profile 465 (e.g., an inner surface) with an inner diameter 466 that is larger than an outer diameter 468 of the outer profile 452 of the mandrel 424 and, thus, may not be in contact with the mandrel 424. Thus, the nipple 410 and the mandrel 424 may define an annular space 470 (e.g., an annular gap or volume) between the nipple 410 and the mandrel 424. The port 456 may extend to or otherwise be fluidly connected (e.g., in fluid communication) with the annular space 470. The annular space 470 may extend to or otherwise be fluidly connected with the internal space of the packer 416 between the mandrel 424 and the packer 416. The annular space 470 between a radially and axially inward edge (e.g., the axial end 464) of the connector assembly 402 and the outer profile 452 of the mandrel 424 may have a thickness ranging, for example, between about three millimeters (mm) and about one mm or less.

The outer profile 452 of the mandrel 424, including one or more outer surfaces of the mandrel 424, may be substantially smooth (i.e., substantially cylindrical and not include additional ports, depressions, holes, asperities, protrusions, and/or other irregularities) along a length of the mandrel 424 extending between the connector assemblies 402, 404 (i.e., along a length of the mandrel 424 that is not surrounded by the connector assemblies 402, 404). The outer profile 452 of the mandrel 424 may also or instead be substantially smooth along a length of the mandrel 424 between the port 456 and the connector assembly 404. Thus, the outer profile 452 of the mandrel 424 may be substantially smooth along a length of the mandrel 424 that is directly surrounded by, disposed against, or contacts moving portions of the packer 416.

The uphole portion 406 of the tool string may comprise a fluid pump 306 (shown in FIG. 3) fluidly connected with a flowline 472 extending axially along the uphole portion 406 of the tool string. When the connector assembly 402 is coupled with the uphole portion 406 of the tool string, the flowlines 458, 472 are fluidly connected to fluidly connect the pump 306 with the flowline 458 and the port 456. Accordingly, during downhole operations (e.g., fluid sampling operations), the pump 306 may pump (i.e., discharge) an inflation fluid into the packer 416 via the flowlines 472, 458, the port 456, and the annular space 470 to expand the packer 416 away from the mandrel 424 against a sidewall of the wellbore or the casing within the wellbore. The pump 306 may also pump (i.e., draw) the inflation fluid out of the packer 416 via the flowlines 472, 458, the port 456, and the annular space 470 to retract the packer 416 away from the sidewall of the wellbore or the casing toward and/or into contact with the mandrel 424.

An anti-extrusion layer 474 may be disposed at an interface between the annular space 470 and the internal space of the packer 416. The anti-extrusion layer 474 may be configured to prevent an inner layer (i.e., the elastic inner layer 440) of the packer 416 from being forced into and/or extruded through the annular space 470, which could damage the inner layer when, for example, the hydrostatic pressure within the wellbore is greater than the pressure within the internal space of the packer 416. The anti-extrusion layer 474 may surround the axially inward end 464 of the connector assembly 402, including over the radially and axially inward edge of the connector assembly 402, and a portion of the outer profile 452 of the mandrel 424 adjacent the end 464. The anti-extrusion layer 474 may comprise a fluid permeable material, such as a mesh, which may permit the inflation fluid to flow through the anti-extrusion layer 474, but prevent the elastic inner layer 440 from entering the annular space 470. The anti-extrusion layer 474 may be or comprise carbon fibers, KEVLAR fibers, and/or other fibers. The anti-extrusion layer 474 may also or instead be or comprise a metallic tube or sleeve. When comprising a non-permeable material, the anti-extrusion layer 474 may form a thin (e.g., thinner than the annular space 470) annular gap or space between the anti-extrusion layer 474 and the mandrel 424, such as may permit transfer of the inflation fluid into and out of the internal space of the packer 416.

Although not shown, the packer tool 400 may comprise multiple instances of the port 456 distributed circumferentially around the mandrel 424 (i.e., along the surface of the mandrel 424), each located between the opposing ends 462, 464 of the connector assembly 402 and connected with the flowline 458. Although not shown in detail, the downhole connector assembly 404 may comprise a substantially similar configuration to the uphole connector assembly 402, comprising one or more ports, each fluidly connected with the flowline 458 or another flowline extending through the mandrel 424.

FIG. 5 further shows a port 476 (drawn in phantom lines) on an outer surface of the mandrel 424 and a flowline 478 (drawn in phantom lines) extending within the mandrel 424 and in fluid communication with the port 476. The port 476 and the flowline 478 are not part of the packer tool 400, but are shown in FIG. 5 to indicate the location of the port 476 in conventional packer tools. Namely, the port 476 is located along the mandrel 424 adjacent to the packer 416 such that when the packer 416 is in the fully deflated (i.e., retracted) state, an inner surface of the packer 416 is disposed against and/or in contact with the port 476. Such location of the port 476 may cause the inner layer (e.g., the elastic inner layer 440) of the packer 416 to be forced into and/or extruded through the port 476, damaging the inner layer. Such situation may take place when the hydrostatic pressure within the wellbore is greater than the pressure within the internal space of the packer 416, for example, when the hydrostatic pressure is greater than the pressure of the inflation fluid within the flowline 478.

FIG. 6 is a schematic view of at least a portion of an example implementation of a processing device 500 according to one or more aspects of the present disclosure. The processing device 500 may form at least a portion of one or more electronic devices utilized at the wellsite systems 100, 200. For example, the processing device 500 may be or form at least a portion of the surface equipment 190, 290 and/or the downhole controller 150, 216. The processing device 500 may be in communication with various sensors (e.g., pressure sensors, position sensors, depth sensors), actuators (e.g., rotary table, top drive, pumps), local controllers, and other devices of the wellsite systems 100, 200. The processing device 500 may be operable to receive coded instructions 532 from human wellsite operators and sensor data generated by the sensors, process the coded instructions 532 and the sensor data, and communicate control data to the actuators to execute the coded instructions 532 to implement at least a portion of one or more example methods and/or operations described herein, and/or to implement at least a portion of one or more of the example systems described herein.

The processing device 500 may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, internet appliances, and/or other types of computing devices. The processing device 500 may comprise a processor 512, such as a general-purpose programmable processor. The processor 512 may comprise a local memory 514, and may execute coded instructions 532 present in the local memory 514 and/or another memory device. The processor 512 may execute, among other things, the machine-readable coded instructions 532 and/or other instructions and/or programs to implement the example methods and/or operations described herein. The programs stored in the local memory 514 may include program instructions or computer program code that, when executed by the processor 512 of the processing device 500, may cause the wellsite systems 100, 200, including the packer tools 300, 400, to perform the example methods and/or operations described herein. The processor 512 may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Of course, other processors from other families are also appropriate.

The processor 512 may be in communication with a main memory 516, such as may include a volatile memory 518 and a non-volatile memory 520, perhaps via a bus 522 and/or other communication means. The volatile memory 518 may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory 520 may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 518 and/or non-volatile memory 520.

The processing device 500 may also comprise an interface circuit 524. The interface circuit 524 may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others. The interface circuit 524 may also comprise a graphics driver card. The interface circuit 524 may also comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.). One or more of the local controllers, the sensors, and the actuators may be communicatively connected with the processing device 500 via the interface circuit 524, such as may facilitate communication between the processing device 500 and the local controllers, the sensors, and/or the actuators.

One or more input devices 526 may also be connected to the interface circuit 524. The input devices 526 may permit the wellsite operators to enter the coded instructions 532, such as control commands, processing routines, and/or operational set-points. The input devices 526 may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples. One or more output devices 528 may also be connected to the interface circuit 524. The output devices 528 may be, comprise, or be implemented by video output devices (e.g., an LCD, an LED display, or a CRT display), printers, and/or speakers, among other examples. The processing device 500 may also communicate with one or more mass storage devices 530 and/or a removable storage medium 534, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.

The coded instructions 532 may be stored in the mass storage device 530, the main memory 516, the local memory 514, and/or the removable storage medium 534. Thus, the processing device 500 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor 512. In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor 512. The coded instructions 532 may include program instructions or computer program code that, when executed by the processor 512, may cause the wellsite systems 100, 200, including the packer tools 300, 400, to perform intended methods, processes, and/or operations disclosed herein.

FIG. 7 is a flow-chart diagram of at least a portion of an example implementation of a method (600) for use of a conventional packer tool without the possibility of applying negative pressure. If packer deflation is not efficient, there can be risks of sticking, or wasting time in the wellbore. Moreover, there is no indication or sensor showing that the packer deflation is sufficient.

The method (600) comprises running (610) (i.e., conveying) a tool string with an inflatable packer tool within a wellbore to a selected location along the wellbore, and then inflating (630) the packer tool against a sidewall of the wellbore or a casing within the wellbore. A fluid sampling operation is then performed (640), after which the packer tool is deflated (650) by opening a relief valve to evacuate inflation fluid from the packer tool. The tool string is then moved (660) to the next station within the wellbore. This may be repeated 670 for multiple fluid sampling stations along the wellbore.

The present disclosure is further 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 of FIGS. 1-6 and/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 in FIGS. 1-6 that 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, at least partially, by the processing device 500 executing the coded instructions 532 according to one or more aspects of the present disclosure. For example, the processing device 500 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 500 based on sensor signals displayed.

FIGS. 8 and 9 are flow-chart diagrams of at least a portion of example implementations of methods (700, 800) according to one or more aspects of the present disclosure. With the aspects introduced above with regard FIGS. 1-6, forced deflation may be used to recover the initial outer diameter of the expandable packers 316, 416 and ensure the toolstring is free to be moved to the next station. During the deflation process, inner pressure within the packer 316, 416 may be similar to (e.g., the same as or less than) the hydrostatic pressure within the wellbore.

The method (700) comprises running (710) a tool string with an inflatable packer tool 400 within a wellbore to a selected location along the wellbore. The packer 416 is then inflated (730) against a sidewall of the wellbore or a casing within the wellbore by pumping or otherwise transferring an inflation fluid into the internal space of the packer 416 through the flowlines 458, 472, the port 456, and the annular space 470. After the packer 416 is inflated (730), a fluid sampling operation may be performed (740). The packer 416 may then be deflated (750) such that the packer 416 fully retracts away from the sidewall to against the mandrel 424 by transferring substantially all of the fluid contained within the packer 416 through the flowline 458, the port 456, and the annular space 470. The packer 416 may be deflated (750) by pumping out substantially all of the fluid contained within the packer 416 with the pump 306. During deflation (750), the pressure of the fluid being pumped out of the packer 416 may be monitored or checked (760), and a drop in the pressure may be indicative that the packer 416 fully deflated. After the packer tool has fully deflated (750), the tool string may be moved (770) to the next station within the wellbore. The above may be repeated 780 for multiple fluid sampling stations along the wellbore.

It is noted that a full inflation/deflation cycle can lead to wasting time in the wellbore, as well as additional rubber aging due to multiple elongation/compression cycles. Thus, for moving between stations but not running out of hole, the packer 416 may be partially deflated by, for example, one third of inflation volume or otherwise sufficiently to ensure that the packer tool 400 is free. This also decreases inflation time at the following station. In order to recover the fully retracted outside diameter before pulling the tool string out of hole, the packer 416 may be fully deflated after the last station. In such implementations, the method (800) shown in FIG. 9 may be utilized. However, there would remain the possibility that partial deflation is not sufficient to free the packer tool 400 between two stations, in which case full deflation of the packer 416 may be performed.

The method (800) comprises running (810) a tool string with an inflatable packer tool 400 within a wellbore to a selected location along the wellbore. After the packer tool 400 arrives at the selected location along the wellbore, the packer 416 is inflated against a sidewall of the wellbore or a casing within the wellbore by pumping an inflation fluid into the internal space of the packer 416 through the flowlines 458, 472, the port 456, and the annular space 470. A fluid sampling operation may then be performed. After the sampling operation is performed, the packer 416 may be partially deflated (820) such that the packer 416 partially retracts away (i.e., disengages) from the sidewall toward the mandrel 424. Such partial deflation (820) may be by pumping out a portion of the fluid contained within the packer 416 through the flowlines 458, 472, the port 456, and the annular space 470. However, the packer 416 may be partially deflated (820) by opening a fluid relief valve, whether instead of or in addition to pumping fluid out of the packer 416. After the packer tool is partially deflated (820), the tool string with the packer tool 400 may be moved to the next station within the wellbore. This may be repeated (830) for multiple fluid sampling stations along the wellbore.

The packer 416 may then be fully deflated (840) such that the packer 416 fully retracts away from the sidewall to against the mandrel 424, whether by pumping and/or otherwise transferring substantially all of the fluid out of the packer 416 through the flowlines 458, 472, the port 456, and the annular space 470. After the packer 416 is fully deflated (840), the tool string with the packer tool 400 may be pulled out of the hole (850).

During full deflation (750), (840), or otherwise when the pressure of the fluid within the packer 416 becomes less than the hydrostatic pressure within the wellbore, a portion (e.g., the sleeve 411 of the nipple 410) of the connector assembly 402 disposed over the port 456 may prevent an inner layer (e.g., elastic inner layer 440) of the packer 416 from being forced into and/or extruded through the port 456.

In view of the entirety of the present disclosure, including the claims and the figures, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising an inflatable packer assembly for coupling within a tool string conveyed within a wellbore, wherein the inflatable packer assembly comprises: (A) a mandrel comprising: (1) a port in an outer surface of the mandrel; and (2) a flowline extending within the mandrel and in fluid communication with the port; (B) a first connector assembly connected to the mandrel such that the port is axially disposed between opposing ends of the first connector assembly, wherein the first connector assembly is for coupling with a first portion of the tool string such that a second flowline of the first portion is in fluid communication with the first flowline; (C) a second connector assembly for coupling with a second portion of the tool string; and (D) an expandable packer disposed around the mandrel and connected with the first and second connector assemblies, such that fluid received from the first and second flowlines via the port expands the expandable packer against a sidewall of the wellbore or a casing within the wellbore.

The port may be a first port of a plurality of ports distributed circumferentially around the mandrel.

An outer profile of the mandrel may be substantially smooth along a length extending between the port and the second connector assembly. No additional ports may exist along the length.

An outer profile of the mandrel may be substantially smooth along a length that contacts moving portions of the expandable packer.

An annular gap between a radially and axially inward edge of the first connector assembly and an outer profile of the mandrel may have a thickness not greater than about three millimeters. An annular volume between an inner profile of the first connector assembly and the outer profile of the mandrel may include the annular gap and may be in fluid communication with the port. The inflatable packer assembly may further comprise an anti-extrusion layer surrounding: an axially inward end of the first connector assembly, including over the radially and axially inward edge of the first connector assembly; and a portion of the outer profile of the mandrel. The anti-extrusion layer may comprise a fluid permeable material, carbon fibers, and/or KEVLAR fibers, and/or may be a metallic sleeve.

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 first end assembly; a second end assembly; a mandrel extending between the first and second end assemblies and comprising a fluid port on an outer surface of the mandrel, wherein at least a portion of the first end assembly extends around the mandrel to define an annular space between the first end assembly and the mandrel, and wherein the fluid port extends to the annular space; and an expandable packer disposed around the mandrel and sealingly connected with the first and second end assemblies, wherein the fluid port and annular space are configured to pass a fluid to inflate the expandable packer.

The fluid port may be a first fluid port of a plurality of fluid ports distributed circumferentially around the outer surface of the mandrel.

A portion of an outer profile of the mandrel that extends between the first and second end assemblies and that is not surrounded by the first end assembly may be substantially smooth and without additional ports.

A portion of an outer profile of the mandrel directly contacted by the expandable packer may be substantially smooth and without additional ports.

The at least a portion of the first end assembly extending around the mandrel may extend around the fluid port.

The annular space may have a thickness not greater than about three millimeters.

An annular volume between an inner profile of the first end assembly and an outer profile of the mandrel may include the annular space and may be in fluid communication with the fluid port.

The inflatable packer assembly may further comprise an anti-extrusion layer extending around: an axially inward end of the first end assembly, including over a radially and axially inward edge of the first end assembly; and a portion of an outer profile of the mandrel. The anti-extrusion layer may comprise a fluid permeable material, carbon fibers, and/or KEVLAR fibers, and/or may be a metallic sleeve.

The present disclosure also introduces a method comprising: (A) coupling an inflatable packer assembly to a tool string, wherein the inflatable packer assembly comprises: (1) a mandrel comprising: (a) a port in an outer surface of the mandrel; and (b) a first flowline extending within the mandrel and in fluid communication with the port; (2) a first connector assembly connected to the mandrel such that the port is axially disposed between opposing ends of the first connector assembly; (3) a second connector assembly; and (4) an expandable packer disposed around the mandrel and connected with the first and second connector assemblies, wherein coupling the inflatable packer assembly to the tool string comprises: (A1) coupling the first connector assembly with a first portion of the tool string such that a second flowline of the first portion of the tool string is in fluid communication with the first flowline; and (A2) coupling the second connector assembly with a second portion of the tool string; (B) conveying the inflatable packer assembly within a wellbore to a selected location along the wellbore; and (C) inflating the expandable packer away from the mandrel to against a sidewall of the wellbore or a casing within the wellbore by transferring a fluid into the expandable packer through the first flowline, the second flowline, and the port.

The method may comprise performing a fluid sampling operation after inflating the expandable packer against the sidewall.

The method may comprise partially deflating the expandable packer such that the expandable packer partially retracts away from the sidewall toward the mandrel by transferring out of the expandable packer a portion the fluid contained by the expandable packer through the first flowline and the port. In such implementations, among others within the scope of the present disclosure, the selected location may be a selected first location, and the method may comprise, after partially deflating the expandable packer, conveying the inflatable packer assembly within the wellbore to a selected second location along the wellbore.

The method may comprise fully deflating the expandable packer such that the expandable packer fully retracts away from the sidewall to against the mandrel by transferring out of the expandable packer substantially all of the fluid contained by the expandable packer through the first flowline and the port. In such implementations, among others within the scope of the present disclosure, fully deflating the expandable packer such that the expandable packer fully retracts away from the sidewall to against the mandrel may comprise pumping out of the expandable packer substantially all of the fluid contained by the expandable packer. In such implementations, among others within the scope of the present disclosure, the method may comprise monitoring pressure of the fluid being pumped out of the expandable packer, wherein a drop in the monitored pressure may be indicative that the expandable packer fully deflated. A portion of the first connector assembly may be disposed over the port, and during deflation of the expandable packer, when pressure of the fluid within the packer becomes less than hydrostatic pressure within the wellbore, the portion of the first connector assembly disposed over the port may prevent an inner layer of the expandable packer from being forced into the port.

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.

Claims

1. An apparatus comprising:

an inflatable packer assembly for coupling within a tool string conveyed within a wellbore, wherein the inflatable packer assembly comprises: a mandrel comprising: a port in an outer surface of the mandrel; and a flowline extending within the mandrel and in fluid communication with the port; a first connector assembly connected to the mandrel such that the port is axially disposed between opposing ends of the first connector assembly, wherein the first connector assembly is for coupling with a first portion of the tool string such that a second flowline of the first portion is in fluid communication with the first flowline; a second connector assembly for coupling with a second portion of the tool string; and an expandable packer disposed around the mandrel and connected with the first and second connector assemblies, such that fluid received from the first and second flowlines via the port expands the expandable packer against a sidewall of the wellbore or a casing within the wellbore.

2. The apparatus of claim 1 wherein an outer profile of the mandrel is substantially smooth along a length extending between the port and the second connector assembly.

3. The apparatus of claim 2 wherein no additional ports exist along the length.

4. The apparatus of claim 1 wherein an outer profile of the mandrel is substantially smooth along a length that contacts moving portions of the expandable packer.

5. The apparatus of claim 1 wherein an annular gap between a radially and axially inward edge of the first connector assembly and an outer profile of the mandrel has a thickness not greater than about three millimeters.

6. The apparatus of claim 5 wherein an annular volume between an inner profile of the first connector assembly and the outer profile of the mandrel includes the annular gap and is in fluid communication with the port.

7. The apparatus of claim 5 wherein the inflatable packer assembly further comprises an anti-extrusion layer surrounding:

an axially inward end of the first connector assembly, including over the radially and axially inward edge of the first connector assembly; and

a portion of the outer profile of the mandrel.

8. The apparatus of claim 7 wherein the anti-extrusion layer comprises a fluid permeable material.

9. The apparatus of claim 7 wherein the anti-extrusion layer comprises carbon and/or KEVLAR fibers.

10. The apparatus of claim 7 wherein the anti-extrusion layer is a metallic sleeve.

11. An apparatus comprising:

an inflatable packer assembly configured to be conveyed within a wellbore, wherein the inflatable packer assembly comprises: a first end assembly; a second end assembly; a mandrel extending between the first and second end assemblies and comprising a fluid port on an outer surface of the mandrel, wherein at least a portion of the first end assembly extends around the mandrel to define an annular space between the first end assembly and the mandrel, and wherein the fluid port extends to the annular space; and an expandable packer disposed around the mandrel and sealingly connected with the first and second end assemblies, wherein the fluid port and annular space are configured to pass a fluid to inflate the expandable packer.

12. The apparatus of claim 11 wherein the inflatable packer assembly further comprises an anti-extrusion layer extending around:

an axially inward end of the first end assembly, including over a radially and axially inward edge of the first end assembly; and

a portion of an outer profile of the mandrel.

13. A method comprising:

coupling an inflatable packer assembly to a tool string, wherein the inflatable packer assembly comprises: a mandrel comprising: a port in an outer surface of the mandrel; and a first flowline extending within the mandrel and in fluid communication with the port; a first connector assembly connected to the mandrel such that the port is axially disposed between opposing ends of the first connector assembly; a second connector assembly; and an expandable packer disposed around the mandrel and connected with the first and second connector assemblies, wherein coupling the inflatable packer assembly to the tool string comprises: coupling the first connector assembly with a first portion of the tool string such that a second flowline of the first portion of the tool string is in fluid communication with the first flowline; and coupling the second connector assembly with a second portion of the tool string;

conveying the inflatable packer assembly within a wellbore to a selected location along the wellbore; and

inflating the expandable packer away from the mandrel to against a sidewall of the wellbore or a casing within the wellbore by transferring a fluid into the expandable packer through the first flowline, the second flowline, and the port.

14. The method of claim 13 further comprising performing a fluid sampling operation after inflating the expandable packer against the sidewall.

15. The method of claim 13 further comprising partially deflating the expandable packer such that the expandable packer partially retracts away from the sidewall toward the mandrel by transferring out of the expandable packer a portion the fluid contained by the expandable packer through the first flowline and the port.

16. The method of claim 15 wherein the selected location is a selected first location, and wherein the method further comprises, after partially deflating the expandable packer, conveying the inflatable packer assembly within the wellbore to a selected second location along the wellbore.

17. The method of claim 13 further comprising fully deflating the expandable packer such that the expandable packer fully retracts away from the sidewall to against the mandrel by transferring out of the expandable packer substantially all of the fluid contained by the expandable packer through the first flowline and the port.

18. The method of claim 17 wherein fully deflating the expandable packer such that the expandable packer fully retracts away from the sidewall to against the mandrel comprises pumping out of the expandable packer substantially all of the fluid contained by the expandable packer.

19. The method of claim 18 further comprising monitoring pressure of the fluid being pumped out of the expandable packer, wherein a drop in the monitored pressure is indicative that the expandable packer fully deflated.

20. The method of claim 18 wherein a portion of the first connector assembly is disposed over the port, and wherein during deflation of the expandable packer, when pressure of the fluid within the packer becomes less than hydrostatic pressure within the wellbore, the portion of the first connector assembly disposed over the port prevents an inner layer of the expandable packer from being forced into the port.