U.S. patent application number 13/305347 was filed with the patent office on 2013-03-14 for packer assembly with a standoff.
The applicant listed for this patent is Nathan Landsiedel. Invention is credited to Nathan Landsiedel.
Application Number | 20130062073 13/305347 |
Document ID | / |
Family ID | 47828795 |
Filed Date | 2013-03-14 |
United States Patent
Application |
20130062073 |
Kind Code |
A1 |
Landsiedel; Nathan |
March 14, 2013 |
Packer Assembly with a Standoff
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) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Landsiedel; Nathan |
Fresno |
TX |
US |
|
|
Family ID: |
47828795 |
Appl. No.: |
13/305347 |
Filed: |
November 28, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61534422 |
Sep 14, 2011 |
|
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Current U.S.
Class: |
166/378 ;
166/118 |
Current CPC
Class: |
E21B 17/10 20130101;
E21B 33/1243 20130101; E21B 49/081 20130101 |
Class at
Publication: |
166/378 ;
166/118 |
International
Class: |
E21B 23/00 20060101
E21B023/00; E21B 33/12 20060101 E21B033/12 |
Claims
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
[0001] 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
[0002] 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
[0003] 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.
[0004] FIGS. 1 to 8 are views of apparatus or portions thereof
according to one or more aspects of the present disclosure; and
[0005] FIG. 9 is a flow chart of an embodiment of a method
according to one or more aspects of the present disclosure.
DETAILED DESCRIPTION
[0006] 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.
[0007] 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).
[0008] 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.
[0009] 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.
[0010] 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.
[0011] 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.
[0012] 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).
[0013] 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.
[0014] 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.
[0015] 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.
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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.
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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.
[0025] 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).
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] 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.
[0033] 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.
[0034] 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.
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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).
[0044] 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.
[0045] 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.
[0046] 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.
[0047] 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.
[0048] 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.
[0049] 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.
[0050] 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.
[0051] 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.
[0052] 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.
[0053] 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.
[0054] The Abstract at the end of this disclosure is provided to
comply with 37 C.F.R. .sctn.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.
* * * * *