Title:
Packer Assembly with a Standoff
Kind Code:
A1


Abstract:
An apparatus including a downhole tool for conveyance in a wellbore extending into a subterranean formation. The downhole tool includes a mandrel, and a first packer and a second packer expandable from the mandrel into contact with a wall of the wellbore. The downhole tool includes a standoff coupled to the mandrel between the first packer and the second packer and having a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel.



Inventors:
Landsiedel, Nathan (Fresno, TX, US)
Application Number:
13/305347
Publication Date:
03/14/2013
Filing Date:
11/28/2011
Assignee:
LANDSIEDEL NATHAN
Primary Class:
Other Classes:
166/118
International Classes:
E21B33/12; E21B23/00
View Patent Images:
Related US Applications:



Primary Examiner:
HALL, KRISTYN A
Attorney, Agent or Firm:
Schlumberger Technology Corporation, HPS (Houston, TX, US)
Claims:
What is claimed is:

1. An apparatus, comprising: a downhole tool for conveyance in a wellbore extending into a subterranean formation, comprising: a mandrel; a first packer and a second packer expandable from the mandrel into contact with a wall of the wellbore; and a standoff coupled to the mandrel between the first packer and the second packer and having a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel.

2. The apparatus of claim 1 wherein the standoff comprises a plurality of first members spanning ones of a plurality of second members.

3. The apparatus of claim 2 wherein the plurality of first members and second members forms the rigid outer perimeter.

4. The apparatus of claim 1 wherein the plurality of first members is selected from the group consisting of: non-circular members; non-concentric members; and webs.

5. The apparatus of claim 1 wherein the plurality of first members is selected from the group consisting of: substantially circular members; substantially concentric ring members; and supporting rings.

6. The apparatus of claim 1 wherein the standoff comprises: a plurality of ring members each substantially coaxially aligned with a longitudinal axis of the mandrel; and a plurality of longitudinal members each extending substantially parallel to the longitudinal axis of the mandrel and coupled to ones of the plurality of ring members.

7. The apparatus of claim 1 wherein the standoff comprises stainless steel.

8. The apparatus of claim 1 wherein the standoff comprises substantially ring-shaped end members at opposing ends coupled to the mandrel.

9. The apparatus of claim 1 wherein the standoff comprises a plurality of openings through which wellbore fluid flows.

10. The apparatus of claim 1 wherein the rigid outer perimeter is approximately one inch smaller than a diameter of the wellbore.

11. The apparatus of claim 1 wherein the mandrel comprises an inlet and the standoff comprises a filter adjacent to the inlet.

12. The apparatus of claim 1 wherein the downhole tool is conveyable in the wellbore via wireline or drill pipe.

13. A method, comprising: coupling a standoff to a mandrel of a downhole tool between first and second packers of the downhole tool, wherein the first and second packers are coupled to the mandrel and the standoff has a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel; and conveying the downhole tool in a wellbore extending into a subterranean formation.

14. The method of claim 13, further comprising: isolating a portion of the wellbore by expanding the first and second packers into contact with a wall of the wellbore; and contacting the wall of the wellbore with the standoff by reducing pressure in the isolated portion of the wellbore.

15. The method of claim 13 further comprising flowing wellbore fluids through a plurality of openings in the standoff.

16. The method of claim 13 further comprising filtering samples collected from the subterranean formation.

17. A kit employable with a downhole tool conveyable in a wellbore extending into a subterranean formation and having a mandrel, and a first packer and a second packer expandable from the mandrel into contact with the wall of the wellbore, the kit, comprising: a standoff couplable to the mandrel between the first packer and the second packer and having a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel.

18. The kit of claim 17 wherein the standoff comprises a fastener to mate first and second sections of the standoff about the mandrel.

19. The kit of claim 17 wherein the standoff comprises a plurality of first members spanning ones of a plurality of second members.

20. The kit of claim 17 wherein the standoff comprises a plurality of openings through which wellbore fluid flows.

Description:

This application claims the benefit of U.S. Provisional Application No. 61/534,422, entitled “Buckling Mitigation for Packer Tools,” filed on Sep. 14, 2011, which is incorporated herein by reference in its entirety.

BACKGROUND OF THE DISCLOSURE

Once an oil well has been drilled, the operator may obtain downhole data, such as pressure measurements and downhole fluid samples for analysis. These tasks are commonly accomplished with downhole tools, such as modular wireline tools or drilling tools with evaluation capabilities, that employ probes for engaging the formation and establishing fluid communication to make the pressure measurements and acquire the fluid samples. Fluid is drawn into the downhole tool through an inlet in the probe. In some instances, such as for tight, low permeability, formations, sampling probes are often replaced by packer assemblies including multiple packers. When the packer assemblies are inflated within a wellbore, a portion or section of the wellbore is isolated to obtain information about the formation between the packers.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best 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.

FIGS. 1 to 8 are views of apparatus or portions thereof according to one or more aspects of the present disclosure; and

FIG. 9 is a flow chart of an embodiment 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 embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, 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 the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

Well logging tools are devices to move through a wellbore drilled through subterranean formations. The well logging tools include one or more devices that measure various properties of the subterranean formations and/or perform certain mechanical acts on the formations, such as drilling or percussively obtaining samples of the subterranean formations, and withdrawing samples of connate fluid from the subterranean formations. Measurements of the properties of the subterranean formations may be recorded with respect to a tool axial position (e.g., depth) within the wellbore as the tool is moved along the wellbore. Such recording is referred to as a well log as performed by well logging tools (or tools in general).

Well logging tools (or tools in general) can be conveyed along the wellbore by extending and withdrawing an armored electrical cable (“wireline”), wherein the well logging tools are coupled to the end of the wireline. Extending and withdrawing the wireline may be performed using a winch or similar spooling device. However, such conveyance relies on gravity to move the well logging tools into the wellbore, which are used on substantially vertical wellbores. Wellbores deviating from vertical may employ additional force for conveyance through the wellbore. For examples of conveyance techniques, see, e.g., U.S. Pat. No. 5,433,276, entitled “Method and System for Inserting Logging Tools into Highly Inclined or Horizontal Boreholes,” to Martain, et al., issued Jul. 18, 1995, and U.S. Pat. No. 6,092,416, entitled “Downhole System and Method for Determining Formation Properties,” to Halford, et al., issued Jul. 25, 2000, which are incorporated herein by reference in their entirety. Various other tools also exist for testing and logging while drilling such as a formation pressure while drilling tool.

To operate and perform tasks such as measuring local environmental parameters and sampling formation fluids, a downhole/wireline tool for conveyance in a wellbore may be provided with pressure measurement and sampling capabilities, and may also have pump-out capabilities. A downhole tool measures pressures and take high quality samples at high temperatures and pressures, such as 375 degrees Fahrenheit (“F”) and 20,000 pounds per square inch (“psi”). The downhole tool may employ a focused sampling technique that uses two flowlines and two probe packers. An inner packer is used with a probe to collect a clean sample from a surrounding subterranean structure, and an outer packer is used to pump mud filtrate away from the inner packer and the probe.

As mentioned above, some downhole tools may be equipped with probes and/or packer assemblies. An inflatable packer assembly which may include dual inflatable packers may be used in formation testing. Such testing may include pressurizing the packers to isolate an annular portion of a wall of a wellbore, collecting one or more samples of formation fluid via the isolated portion of the wall of the wellbore, and depressurizing the packers to permit movement of a mandrel within the wellbore. A mandrel is a portion of a tool body about which the packer is assembled. Such formation testing may include restricting deformation of the packers during inflation using an annular bracing assembly, actively retracting the packers using ambient wellbore pressure, and substantially centralizing the mandrel intermediate the packers to resist buckling of the mandrel.

Another example an adjustable downhole tool includes a plurality of packers spaced apart along the axis of the downhole tool, and at least a testing port. The downhole tool is positioned into the wellbore and packers are extended into sealing engagement with the wall of the wellbore, sealing thereby a portion (e.g., a section or an area or interval) of the wellbore. The portion of the wellbore sealed between the packers may be adjusted downhole. The location of a testing port may be adjusted between the packers. Such an arrangement may be used to reduce the contamination of the formation fluid by fluids or debris in the wellbore.

In general, for formation pressure testing, formation sampling, and other operations, the buckling limit of a packer assembly may become an issue. Due to technical reasons associated with a quad packer assembly, however, the distance achievable between the uppermost and lowermost packers may be quite large, on the order of four to six meters. For inter-packer distances of approximately three meters or greater, the buckling limit of the packer assembly, and not the pressure rating of the packers, may constrain the drawdown pressure that can be applied in the packer intervals. The inner packers located between the uppermost and lowermost packers of a quad packer assembly or tool, for example, may increase the buckling limit by providing additional support to the packer tool. The packers, however, may have a relatively low stiffness in the radial direction compared to the magnitude of the forces involved in buckling of the packer tool. As will become more evident, a standoff may be introduced between the packers to provide lateral support. The standoff may protect the inner packers against excessive deformation caused by flexion of the packer module (e.g., the flexion of a mandrel of the packer module).

Referring initially to FIG. 1, illustrated is a schematic view of an apparatus or portions thereof according to one or more aspects of the present disclosure. The apparatus includes a drilling rig 100 or similar lifting device employable to move a pipe string (e.g., a wired drill pipe string 105) within a wellbore 110 that has been drilled through subterranean formations, shown generally at 115, that provides an environment for application of one or more aspects of the present disclosure. The wired drill pipe string 105 may be extended into the wellbore 110 by threadedly coupling together end to end a number of coupled drill pipes (one of which is designated 120) of the wired drill pipe string 105. The wired drill pipe string 105 may be structurally similar to ordinary drill pipes, as illustrated for example, in U.S. Pat. No. 6,174,001, entitled “Two-Step, a Low Torque, Wedge Thread for Tubular Connector,” to Enderle, issued Aug. 7, 2001, which is incorporated herein by reference in its entirety, and includes a cable associated with each drill pipe 120 that serves as a communication channel. The cable may be any type of cable capable of transmitting data and/or signals, such as an electrically conductive wire, a coaxial cable, an optical fiber or the like.

The wired drill pipe string 105 includes some form of signal coupling to communicate signals between adjacent drill pipes when coupled end to end as illustrated. See, as a non-limiting example, the description of one type of wired drill pipe string having inductive couplers at adjacent drill pipes in U.S. Pat. No. 6,641,434, entitled “Wired Pipe Joint with Current-loop Inductive Couplers,” to Boyle, et al., issued Nov. 4, 2003, which is incorporated herein by reference in its entirety. However, one or more aspects of the present disclosure are not limited to the wired drill pipe string 105 and can include other communication or telemetry systems, including a combination of telemetry systems, such as a combination of wired drill pipe string, mud pulse telemetry, electronic pulse telemetry, acoustic telemetry, or the like.

The wired drill pipe string 105 may include one, an assembly, or a “string” of downhole tools at a lower end thereof. In the present example, the downhole tool string may include well logging tool(s) 125 coupled to a lower end thereof. As used in the present description, the term “well logging tool,” or a string of such tools, refers to, for example, one or more wireline well logging tools that are capable of being conveyed through a wellbore 110 using armored electrical cable (“wireline”), logging while drilling tools, formation evaluation tools, formation sampling tools, and/or other tools capable of measuring a characteristic of the subterranean formation 115 and/or of the wellbore 110. One or more of the well logging tool(s) 125 or downhole tools may employ a centralizing mechanism as described in more detail below.

Several of the components disposed proximate the drilling rig 100 may be used to operate components of the system. These components will be explained with respect to their uses in drilling the wellbore 110 for a better understanding thereof. The wired drill pipe string 105 may be used to turn and axially urge a drill bit into the bottom of the wellbore 110 to increase its length (depth). During drilling of the wellbore 110, a pump 130 lifts drilling fluid (“mud”) 135 from a tank 140 or pit and discharges the mud 135 under pressure through a standpipe 145 and flexible conduit 150 or hose, through a topdrive 155 and into an interior passage (not shown separately in FIG. 1) inside the wired drill pipe string 105. The mud 135, which can be water- or oil-based, exits the wired drill pipe string 105 through courses or nozzles (not shown separately) in the drill bit, where it then cools and lubricates the drill bit and lifts drill cuttings generated by the drill bit to the surface of the earth.

When the wellbore 110 has been drilled to a selected depth, the wired drill pipe string 105 may be withdrawn from the wellbore 110. An adapter sub 160 and the well logging tools 125 may then be coupled to the end of the wired drill pipe string 105, if not previously installed. The wired drill pipe string 105 may then be reinserted into the wellbore 110 so that the well logging tools 125 may be moved through, for example, a highly inclined portion 165 of the wellbore 110, which would be inaccessible using armored electrical cable to move the well logging tools 125. The well logging tools 125 may be positioned on the wired drill pipe string 105 in other manners, such as by pumping the well logging tools 125 down the wired drill pipe string 105 or otherwise moving the well logging tools 125 down the wired drill pipe string 105 while the wired drill pipe string 105 is within the wellbore 110.

During well logging operations, the pump 130 may be operated to provide fluid flow to operate one or more turbines (not shown in FIG. 1) in the well logging tools 125 to provide power to operate certain devices in the well logging tools 125. However, when tripping in or out of the wellbore 110, it may be infeasible to provide fluid flow. As a result, power may be provided to the well logging tools 125 in other ways. For example, batteries may be used to provide power to the well logging tools 125. The batteries may be rechargeable batteries that may be recharged by turbine(s) during fluid flow. The batteries may be positioned within a housing of one or more of the well logging tools 125. Other manners of powering the well logging tools 125 may be used as appreciated by those having ordinary skill in the art.

As the well logging tools 125 are moved along the wellbore 110 by moving the wired drill pipe string 105 as explained above, formation characteristics may be detected by various devices, of which non-limiting examples may include a resistivity measurement device 170, a gamma ray measurement device 175, a packer module 180 (which may include a formation fluid pressure measurement device) and a packer assembly. As will be described in more detail below, the packer assembly includes a plurality of packers 182, 184 and a standoff 186. The standoff 186 between the plurality of packers 182, 184 provides lateral support. A pumping module 188 is employed to inflate the plurality of packers 182, 184 into contact with a wall of the wellbore 110, but expansion mechanisms other than inflation may be used (e.g., compression, swelling). The pumping module 188 can also pump fluid and reduce the pressure in an area (section, portion or interval) sealed between the plurality of packers 182, 184 when they are extended. The signals, which are indicative of the formation characteristics, may be transmitted toward the surface of the earth along the wired drill pipe string 105.

When tripping in and out of the wellbore 110 or performing another process wherein drill pipe 120 is being added, removed or disconnected from the wired drill pipe string 105, an apparatus and system may be employed for communicating from the wired drill pipe string 105 to a surface computer system 190 or other component to receive, analyze, and/or transmit data. Accordingly, a second adapter sub 195 may be coupled between an end of the wired drill pipe string 105 and the topdrive 155 that may be employed to provide a wired or wireless communication channel or path with a receiving unit 197 for signals received from the well logging tools 125. The receiving unit 197 may be coupled to the surface computer system 190 to provide a data path therebetween that may be a bidirectional data path.

Turning now to FIG. 2, illustrated is a schematic view of an apparatus or portions thereof according to one or more aspects of the present disclosure. The apparatus includes a downhole tool 200 employing a packer assembly including inflatable packers 202, 204. As will be described in more detail below, the packer assembly includes a standoff 205 between the packers 202, 204 to provide lateral support. The downhole tool 200 may be deployed (e.g., lowered) into a wellbore or borehole 206 to sample a formation fluid from a subterranean formation 201. The downhole tool 200 is a wireline tool and, thus, is lowered into the wellbore 206 via a cable 208, which bears the weight of the downhole tool 200 and includes electrical wires or additional cables to convey power, control signals, information carrying signals, etc. between the downhole tool 200 and an electronics and processing unit 210 on the surface adjacent the wellbore 206. While the downhole tool 200 is depicted as being deployed in the wellbore 206 as a wireline device, the downhole tool 200 may be deployed in a drill string, using coiled tubing, or by any other method of deploying a tool into a wellbore.

The downhole tool 200 includes a packer module 212 having a sampling inlet 214. The packer module 212 may further include an extendable probe (not shown) associated with the sampling inlet 214 and an extendable anchoring member (not shown) to anchor the downhole tool 200 and the probe in position to contact the subterranean formation 201. The sampling inlet 214, as shown, is a single inlet or port. However, a second or additional inlets or ports (not shown) may operate in conjunction with the sampling inlet 214 to facilitate dual inlet (i.e., guard) sampling.

To extract wellbore fluid from the area to be isolated by one or both of the packers 202, 204, the downhole tool 200 includes a pumping module 218. The pumping module 218 may include one or more pumps, hydraulic motors, electric motors, valves, flowlines, etc. to enable the wellbore fluid to be removed from a selected area of the wellbore 206.

To convey power, communication signals, control signals, etc. between the surface (e.g., to/from the electronics and processing unit 210) and among the various sections or modules composing the downhole tool 200, the downhole tool 200 includes an electronics module 220. The electronics module 220 may, for example, be used to control the operation of the pumping module 218 in conjunction with operation of the packers 202, 204 to, for example, hydraulically isolate a portion of the wellbore 206 to facilitate sampling or testing a portion of the subterranean formation 201.

In operation, the downhole tool 200 may be lowered via the cable 208 into the wellbore 206 to a depth that aligns the packer module 212 and the sampling inlet 214 with a portion of the subterranean formation 201 to be sampled. The pumping module 218 may then be used to pump pressurized fluid (e.g., wellbore fluid) into the packers 202, 204 to inflate the same so that the outer circumferential surfaces of the packers 202, 204 sealingly engage a wall 222 of the wellbore 206. With the packers 202, 204 inflated, an area (section or portion) 224 of the wellbore 206 between the packers 202, 204 is hydraulically isolated from the remainder of the wellbore 206. The area 224 may be referred to as the interval, and the wellbore fluid contained therein could be at an interval pressure. The pumping module 218 is then used (e.g., controlled by the electronics module 220 and/or the electronics and processing unit 210) to pump wellbore fluid out of the area 224 of the wellbore 206. The pumping module 218 is then used to pump formation fluid from the subterranean formation 201 via the sampling inlet 214 and a flowline 225 into a sample chamber 227 within the downhole tool 200. The sample chamber 227 may be located in another section of the downhole tool 200 besides the packer module 212 such as in its own sample chamber module (not shown).

Following collection of a sample, the pressurized fluid within the packers 202, 204 is released (e.g., by the pumping module 218) into the wellbore 206 outside of the area 224. Even if the packers 202, 204 are deflated or the pressurized fluid within the packers 202, 204 is released, the packers 202, 204 may maintain a relatively large outer diameter (i.e., not fully contracted to their pre-inflation diameters), particularly if the area 224 of the wellbore 206 is at a relatively high temperature. If the outer diameter of one or both of the packers 202, 204 is not reduced to less than the inside diameter of the wellbore 206, withdrawal of the downhole tool 200 from the wellbore 206 may be very difficult without damage to the downhole tool 200 and/or the wellbore 206.

Turning now to FIG. 3, illustrated is a schematic view of an apparatus or portions thereof according to one or more aspects of the present disclosure. The apparatus includes a hydrocarbon recovery system (or system) 300. In an embodiment, the system 300 may combine wellbore stimulation operations with the implementation of at least one inflow control device, thereby reducing costly and time-consuming dual run-ins into the hole. For the purposes of this disclosure, a run-in can include the process of running drill pipe, coiled tubing for stimulation, production pipe, etc., into a well, and removal of the same.

As illustrated in FIG. 3, a wellbore 302 can have a substantially vertical portion 304 and a substantially horizontal portion 306 joined at a heel 308. From the heel 308, the vertical portion 304 can extend to the surface 310, while the horizontal portion 306 can extend into a heterogeneous hydrocarbon-bearing formation (or formation) 312, ultimately terminating at a toe 309. The formation 312 can include multiple zones 313, 314, 315, each having varying degrees of permeability.

In an embodiment, the wellbore 302 can be either a newly-drilled or an existing wellbore 302, wherein a completion casing 316 extends substantially the whole length of the wellbore 302. As part of the completion casing 316, at least a portion of the horizontal portion 306 can include a completion assembly 318 to allow the outflow and inflow of fluids into the wellbore 302. In an embodiment, the completion assembly 318 can include any number of horizontal completions, including, but not limited to, a perforated casing, a gravel-packed screen assembly, an open hole and screen assembly, or simply an open hole. In at least one embodiment, the completion assembly 318 can include a slotted liner, or screen assembly with an inside diameter of about 5.5 inches.

At the surface 310, the system 300 can include a coiled tubing conveyor 320 communicably coupled to a pump 322 and a fluids reservoir 324 having a fluid 332 disposed therein. In an embodiment, the coiled tubing conveyor 320 may feed a coiled tubing string 326 down the wellbore 302 and substantially into the horizontal portion 306 of the completion assembly 318.

Disposed at the end of the coiled tubing string 326, and inserted first into the wellbore 302, can be a production tubular 328 that defines a plurality of orifices 330. The production tubular 328 can be used to control the production of hydrocarbons from the wellbore 302 and/or the hydrocarbon-bearing formation 312 to the surface 310. In addition, the production tubular 328 can be used to control the injection of one or more fluids (e.g., fluid 332) from the surface 310 into the wellbore 302 and/or hydrocarbon-bearing formation 312.

In at least one embodiment, the production tubular 328 can be a single length of piping disposed substantially in the completion assembly 318, and having a packer assembly with at least one packer (first and second packers 334, 335) engaged about the inner diameter of the completion assembly 318. As will be described in more detail below, the packer assembly may include a standoff 336 between the first and second packers 334, 335 to provide lateral support. In other embodiments, the production tubular 328 can be connected or secured in a series of pipes (not shown) about the completion assembly 318, and a left or first portion of one or more of the production tubulars 328, and a middle or second portion, can be connected or secured to the first packer 334. Accordingly, the first packer 334 can support the first and second connected production tubulars 328. Moreover, a right or third portion of the production tubular 328, and the middle portion, can connect or secure to the second packer 335.

In one or more embodiments, the packer(s) 334, 335 can include an inflatable packer, and/or a swell-packer with a cup-packer as a back-up isolation support at each transition between adjacent zones 313, 314, 315. In an operation, the packers 334, 335 can provide zonal isolation between each zone 313, 314, 315 of the hydrocarbon-bearing formation 312. For example, formation fluids may enter the completion assembly 318 from one of the zones 313, 314, 315, and may be at substantially lower pressure than the fluids in the other zones of the wellbore 302.

Referring to FIG. 4, illustrated is a schematic view of an apparatus or portions thereof according to one or more aspects of the present disclosure. The apparatus includes a drill string 405 deployed from a platform (also referred to as a platform and derrick assembly) 410 that provides an environment for application of one or more aspects of the present disclosure. The platform 410 and drill string 405 may be a part of an onshore or offshore well site. In this well site, a wellbore 415 is formed in subterranean formations by rotary drilling, which may also include directional drilling.

The drill string 405 is suspended within the wellbore 415, and includes a plurality of drill pipes (one of which is designated 412) and a bottom hole assembly 420 with a drill bit 425 at its lower end. The platform 410 is positioned over the wellbore 415 and includes a rotary table 430, a kelly 432, a hook 435 and a rotary swivel 437. The drill string 405 is rotated by the rotary table 430, energized by means not shown, which engages the kelly 432 at the upper end of the drill string 405. The drill string 405 is suspended from the hook 435, attached to a traveling block (also not shown) through the kelly 432 and the rotary swivel 437, which permits rotation of the drill string 405 relative to the hook 435. A topdrive may also be used.

At the surface of the well site, drilling fluid (or mud) 440 is stored in a pit (or tank) 443. A pump 446 delivers the drilling fluid 440 to the interior of the drill string 405 via a port in the rotary swivel 437, causing the drilling fluid 440 to flow downwardly through the drill string 405 as indicated by the directional arrow 450. The drilling fluid 440 exits the drill string 405 via ports in the drill bit 425 and then circulates upwardly through the annulus region between the outside of the drill string 405 and the wall of the wellbore 415, as indicated by the directional arrows 453. The drilling fluid 440 lubricates the drill bit 425 and carries formation cuttings up to the surface as it is returned to the pit 443 for recirculation.

The bottom hole assembly 420 is constructed with a packer module 455 (which may include a formation fluid pressure measurement device) and a packer assembly housed in a special type of drill collar. As will be described in more detail below, the packer assembly includes a plurality of packers 482, 484 and a standoff 486. The standoff 486 between the plurality of packers 482, 484 provides lateral support. A pumping module 454 is employed to inflate the plurality of packers 482, 484 into contact with a wall of the wellbore 415. The pumping module 454 can also pump drilling fluid 440 and reduce the pressure in an area (section, portion or interval) sealed between the plurality of packers 482, 484 when they are extended. The signals, which are indicative of the formation characteristics, may be communicated to the surface equipment.

The bottom hole assembly 420 is also constructed with an LWD module (one of which is designated 456), a measurement while drilling (“MWD”) module (one of which is designated 457), a roto-steerable system and motor 460 and the drill bit 425. The LWD module 456 is housed in a special type of drill collar, and can contain one or a plurality of types of logging tools. It will also be understood that more than one LWD module 456 and/or MWD module 457 can be employed. The LWD module 456 may include capabilities for measuring, processing and storing information, as well as for communicating with the surface equipment. In the present embodiment, the LWD module 456 includes, without limitation, a fluid-sampling device or a pressure measurement device.

The MWD module 457 is also housed in a special type of drill collar, and can contain one or more devices for measuring characteristics of the drill string 405 and drill bit 425. The well site further includes power equipment (not shown) for generating electrical power to the drill string 405. While this may include a mud turbine generator powered by the flow of the drilling fluid, it should be understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module 457 includes, without limitation, one or more measuring devices such as a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device and an inclination measuring device.

Referring to FIGS. 5 and 6, illustrated are schematic views of an apparatus or portions thereof according to one or more aspects of the present disclosure. The apparatus includes a downhole tool such as a packer module 500, or portions thereof, including a quad packer assembly within a wellbore 505 in a subterranean formation 510. The quad packer assembly includes first, second, third and fourth packers 520, 525, 530, 535 expandable from a mandrel 540 into contact with a wall of the wellbore 505. While the mandrel 540 includes a coupling 545 to a wireline, the packer module may also be conveyed downhole via drill pipe, coiled tubing, etc. The quad packer assembly also includes a first standoff 550 located about a first sampling inlet 555 and between the first and second packers 520, 525, a second standoff 560 located about a second sampling inlet 565 and between the second and third packers 525, 530, and a third standoff 570 located about a third sampling inlet 575 and between the third and fourth packers 530, 535. The first, second and third standoffs 550, 560, 570 have a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel 540. As an example for a 8.5 inch nominal wellbore size, the mandrel 540 may be about 3 inches in diameter, the packer module 500 about 4.75 inches in diameter, the packers 520, 525, 530, 535 about 6.75 to 7 inches in diameter before inflation and the standoffs 550, 560, 570 about 7.5 inches in diameter. Thus in this example, the perimeter of the standoffs 550, 560, 570 is diametrically larger than an outer perimeter of the mandrel 540 by about 250 percent. For a 12.25 inch nominal wellbore size, the standoffs 550, 560, 570 may be about 11 to 11.25 inches in diameter.

As mentioned above, testing may include pressurizing the first, second, third and fourth packers 520, 525, 530, 535 to isolate an annular portion of a wall of the wellbore 505, collecting one or more samples of formation fluid via the isolated portion of the wall of the wellbore 505, and depressurizing the first, second, third and fourth packers 520, 525, 530, 535 to permit movement of the mandrel 540 within the wellbore 505. The samples may be collected via the first, second and third sampling inlets 555, 565, 575 and filtered via a filter (see FIG. 7) located in the first, second and third standoffs 550, 560, 570.

When the pressure is reduced in the intervals sealed by the first, second, third and fourth packers 520, 525, 530, 535, the wellbore pressure above the first packer 520 and below the fourth packer 535 applies a compressive force to the mandrel 540. When this force exceeds the buckling limit, the mandrel 540 flexes as shown on FIG. 6. The first, second and third standoffs 550, 560, 570, however, maintain the mandrel 540 in a relatively aligned position, and protect the first, second, third and fourth packers 520, 525, 530, 535 against excessive deformations that would otherwise result from the flexion of the mandrel 540.

Referring to FIG. 7, illustrated is a perspective view of an apparatus or portions thereof according to one or more aspects of the present disclosure. The apparatus includes a standoff 700 locatable about, for instance, a sampling inlet of a quad packer assembly. As mentioned above, the standoff 700 has a rigid outer perimeter formed from a plurality of first members (ones of which are designated 710, e.g., non-circular members, non-concentric members, longitudinal members, webs) spanning ones of a plurality of second members (ones of which are designated 720, e.g., substantially circular members, concentric ring members, ring members, supporting rings). The rigid outer perimeter may be approximately one inch smaller than a diameter of the wellbore (e.g., 7.5 inch rigid outer perimeter and 8.5 inch wellbore diameter).

In an embodiment, the second members (e.g., ring members) 720 are substantially coaxially aligned with a longitudinal axis of a mandrel (see FIGS. 5 and 6) and the first members (e.g., longitudinal members) 710 extend substantially parallel to the longitudinal axis of the mandrel and coupled to ones of the first members. The first members (e.g., webs) 710 may span across ones of the second members (e.g., supporting rings) 720, which may provide mechanical rigidity. Also, ones of the second members (e.g., substantially ring-shaped end members) 720 at opposing ends 730, 740 of the standoff 700 may be coupled to a mandrel. Additionally, spacers may be employed to engage the mandrel.

The standoff 700 includes a plurality of openings (ones of which are designated 750) through which wellbore fluid flows. The plurality of openings may form 35 to 50 percent of an outer envelope of the standoff 700 through which wellbore fluid flows. The standoff may comprise stainless steel. A middle second member (e.g., ring member) 720 may have an inner diameter sufficiently large to accommodate a filter (e.g., a cylindrical filter) 760 between a mandrel that traverses the standoff 700 and the standoff 700, itself. While the filter 760 is shown outside of the standoff 700 for purposes of illustration, in practice the filter 760 would reside within the standoff 700 proximate one of the second members 720. An analogous function can be obtained by, for instance, wire-wrapping a portion of the standoff 700 while maintaining a gap between wraps. The openings 750 may facilitate fluid communication between the wellbore and a large portion area of the filter 760.

The openings (e.g., longitudinal grooves) 750 in the standoff 700 may provide flow area for drilling fluids contained in a well, which may allow a downhole tool employing a packer assembly to be moved in the wellbore without restricting the flow of drilling fluid around the standoff 700. Similar devices within the scope of the present disclosure may include a different number and/or geometry of the ridges/grooves on the device. Similar devices within the scope of the present disclosure may retain the certain materials, and/or remove undercuts on the internal diameter, and/or have fewer/smaller grooves and flow passages, which may augment the strength of the standoff 700 and/or reduce the volume of fluid in the interval between packers.

Referring to FIG. 8, illustrated is a perspective view of an apparatus or portions thereof according to one or more aspects of the present disclosure. The apparatus includes a standoff 800, a portion of which is illustrated for use as a kit employable with a packer assembly. The standoff 800 is couplable to a mandrel between a first packer and a second packer and has a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel. The standoff 800 includes many of the features as described above including a plurality of first members (one of which is designated 810) spanning ones of a plurality of second members (one of which is designated 820). The standoff 800 also includes a plurality of openings (one of which is designated 850) through which wellbore fluid flows.

To facilitate the use of the standoff 800 in a kit, the standoff 800 includes a fastener to allow sections of the standoff 800 to be mated together about a mandrel in the field. In the illustrated embodiment, the fastener includes a sleeve (one of which is designated 860) on a first section of the mandrel 800 that will mate with a sleeve on a second section (not shown) of the mandrel 800 through which a pin 870 will slide to hold the two sections of the standoff 800 together about the mandrel or other structure. Of course, other fasteners may be employed depending on the application.

Referring to FIG. 9, illustrated is a flow chart of a method according to one or more aspects of the present disclosure. The method begins in a module 910. In a module 920, first and second packers are coupled to a mandrel of a downhole tool. Thereafter, a standoff is coupled to the mandrel of the downhole tool between the first and second packers in a module 930. The standoff has a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel. In a module 940, the downhole tool is conveyed within a wellbore extending into a subterranean formation.

Once at the selected depth, a portion of the wellbore is isolated by expanding the first and second packers into contact with a wall of the wellbore in a module 950. In a module 960, the standoff is contacted the wall of the wellbore by reducing pressure in the isolated portion of the wellbore. The first and second packers can be expanded and the pressure reduced in the isolated portion of the wellbore employing processes as described above (see, e.g., FIG. 1 and the description thereof). The method ends in a module 970.

Thus, a downhole tool for conveyance in a wellbore extending into a subterranean formation via a wireline or drill pipe, and method of operating and assembling the same has been introduced herein. The downhole tool may include a mandrel, a first packer and a second packer expandable from the mandrel into contact with a wall of the wellbore, and a standoff (e.g., including stainless steel) coupled to the mandrel between the first packer and the second packer and having a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel (e.g., the rigid outer perimeter is approximately one inch smaller than a diameter of the wellbore). The standoff may include a plurality of first members (e.g., non-circular members, non-concentric members, longitudinal members, webs) spanning ones of a plurality of second members (e.g., substantially circular members, concentric ring members, ring members, supporting rings) that form the rigid outer perimeter. The standoff may include a plurality of ring members each substantially coaxially aligned with a longitudinal axis of the mandrel, and a plurality of longitudinal members each extending substantially parallel to the longitudinal axis of the mandrel and coupled to ones of the plurality of ring members. The standoff may include substantially ring-shaped end members at opposing ends coupled to the mandrel. The standoff may include a plurality of openings (e.g., forming 35 to 50 percent of an outer envelope of the standoff) through which wellbore fluid flows. The mandrel may include an inlet and the standoff includes a filter adjacent to the inlet.

A kit employable with a downhole tool for conveyance in a wellbore extending into a subterranean formation and having a mandrel, and a first packer and a second packer expandable from the mandrel into contact with the wall of the wellbore. The kit includes a standoff couplable to the mandrel between the first packer and the second packer and having a rigid outer perimeter that is diametrically larger than an outer perimeter of the mandrel. The standoff of the kit also includes a fastener (e.g., sleeve and pin) to mate two sections of the standoff about the mandrel. The standoff may include many of the features as described above.

The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled 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 purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled 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 comply with 37 C.F.R. §1.72(b) to allow 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.