U.S. patent application number 15/508093 was filed with the patent office on 2017-09-14 for multilateral access with real-time data transmission.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Ernesto BUSTAMANTE, Alejandro CHACON, Alexys Jose GONZALEZ, Jose Antonio NOGUERA.
Application Number | 20170260834 15/508093 |
Document ID | / |
Family ID | 55631178 |
Filed Date | 2017-09-14 |
United States Patent
Application |
20170260834 |
Kind Code |
A1 |
CHACON; Alejandro ; et
al. |
September 14, 2017 |
MULTILATERAL ACCESS WITH REAL-TIME DATA TRANSMISSION
Abstract
An example method includes introducing a downhole tool string
into a main wellbore of a multilateral wellbore that includes a
lateral wellbore that extends from the main wellbore. The downhole
tool string includes a wand and a kickover knuckle joint coupled to
the wand. A first measurement is obtained with an orientation
measurement device, and an angular orientation of the kickover
knuckle joint and the wand is aligned with the lateral wellbore as
based on the first measurement. The downhole tool string is then
advanced into the lateral wellbore and a second measurement is
obtained with the orientation measurement device within the lateral
wellbore. The second measurement is compared with known deviation
survey measurements corresponding to the lateral wellbore to
verifying a location of the downhole tool string in the lateral
wellbore. A wellbore stimulation operation is then undertaken with
the downhole tool string within the lateral wellbore.
Inventors: |
CHACON; Alejandro; (Bogota,
CO) ; GONZALEZ; Alexys Jose; (Cabimas, VE) ;
BUSTAMANTE; Ernesto; (Scottsdale, AZ) ; NOGUERA; Jose
Antonio; (Caracas, VE) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
55631178 |
Appl. No.: |
15/508093 |
Filed: |
October 1, 2014 |
PCT Filed: |
October 1, 2014 |
PCT NO: |
PCT/US2014/058546 |
371 Date: |
March 1, 2017 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 17/20 20130101;
E21B 47/024 20130101; E21B 43/25 20130101; E21B 47/00 20130101;
E21B 47/12 20130101; E21B 41/0035 20130101; E21B 43/26
20130101 |
International
Class: |
E21B 41/00 20060101
E21B041/00; E21B 43/25 20060101 E21B043/25; E21B 17/20 20060101
E21B017/20; E21B 47/00 20060101 E21B047/00; E21B 43/26 20060101
E21B043/26; E21B 47/024 20060101 E21B047/024; E21B 47/12 20060101
E21B047/12 |
Claims
1. A method, comprising: introducing a downhole tool string into a
main wellbore of a multilateral wellbore, the multilateral wellbore
including a lateral wellbore that extends from the main wellbore at
a junction, and the downhole tool string including a wand and a
kickover knuckle joint coupled to the wand; obtaining a first
measurement with an orientation measurement device included in the
downhole tool string, the first measurement including at least one
of the following measurements: an azimuth, an inclination, and a
tool-face direction of the downhole tool string; aligning an
angular orientation of the kickover knuckle joint and the wand with
the lateral wellbore as based on the first measurement; advancing
the downhole tool string into the lateral wellbore and obtaining a
second measurement with the orientation measurement device while
the downhole tool string is positioned in the lateral wellbore, the
second measurement including at least one of the azimuth, the
inclination, and the tool-face direction of the downhole tool
string; and comparing the second measurement with known deviation
survey measurements corresponding to the lateral wellbore and
thereby verifying a location of the downhole tool string in the
lateral wellbore; and undertaking one or more wellbore stimulation
operations with the downhole tool string while positioned in the
lateral wellbore.
2. The method of claim 1, wherein aligning the angular orientation
of the kickover knuckle joint and the wand with the lateral
wellbore comprises: activating an orienting sub included in the
downhole tool string; and changing the angular orientation of the
kickover knuckle joint and the wand with the orienting sub.
3. The method of claim 1, wherein the downhole tool string further
includes a sequencing flow sub, and wherein undertaking the one or
more wellbore stimulation operations comprises: activating the
sequencing flow sub to prevent a stimulation fluid from passing
into at least an orienting sub, the kickover knuckle joint, and the
wand; and diverting the stimulation fluid out of the sequencing
flow sub.
4. The method of claim 1, wherein undertaking the one or more
wellbore stimulation operations comprises at least one of acidizing
a portion of the lateral wellbore and hydraulically fracturing a
portion of the lateral wellbore.
5. The method of claim 1, wherein the downhole tool string further
includes a wellbore telemetry device communicably coupled to the
orientation measurement device, the method further comprising
communicating the first and second measurements to the surface
location in real-time.
6. The method of claim 5, wherein communicating the first and
second measurements to the surface location in real-time comprises
operating the wellbore isolation device using at least one of mud
pulse telemetry, electromagnetic telemetry, acoustic telemetry,
ultrasonic telemetry, electrical lines, fiber optic lines, radio
frequency transmission, and any combination thereof.
7. The method of claim 1, wherein the downhole tool string further
includes a gauge carrier that includes one or more sensors or
gauges, the method further comprising measuring one or more
downhole parameters with the gauge carrier as the downhole tool
string advances within the main or lateral wellbores.
8. The method of claim 1, wherein the lateral wellbore is a first
lateral wellbore and the junction is a first junction, the method
further comprising: retracting the downhole tool string from the
first lateral wellbore and into the main wellbore; moving the
downhole tool string within the main wellbore toward a second
lateral wellbore that extends from the main wellbore at a second
junction; obtaining a third measurement with the orientation
measurement device, the first measurement including at least one of
the azimuth, the inclination, and the tool-face direction of the
downhole tool string; aligning the angular orientation of the
kickover knuckle joint and the wand with the second lateral
wellbore as based on the third measurement; advancing the downhole
tool string into the second lateral wellbore and obtaining a fourth
measurement with the orientation measurement device while the
downhole tool string is positioned in the second lateral wellbore,
the fourth measurement including at least one of the azimuth, the
inclination, and the tool-face direction of the downhole tool
string; comparing the fourth measurement with known deviation
survey measurements corresponding to the second lateral wellbore
and thereby verifying a location of the downhole tool string in the
second lateral wellbore; and undertaking one or more wellbore
stimulation operations with the downhole tool string while
positioned in the second lateral wellbore.
9. The method of claim 8, wherein undertaking the one or more
wellbore stimulation operations with the downhole tool string while
positioned in the second lateral wellbore comprises at least one of
acidizing a portion of the second lateral wellbore and
hydraulically fracturing a portion of the second lateral
wellbore.
10. A rigless well intervention system, comprising: a downhole tool
string extendable within a main wellbore on a conveyance from a
surface location, the main wellbore having a central axis and a
lateral wellbore that extends from the main wellbore at a junction,
wherein at least a portion of each of the main and lateral
wellbores is lined with casing, the downhole tool string including:
a wand and a kickover knuckle joint coupled to the wand to deflect
the wand from the central axis; an orienting sub that adjusts an
angular orientation of at least the kickover knuckle joint and the
wand about the central axis; an orientation measurement device that
measures one or more of an azimuth, an inclination, and a tool-face
direction of at least one of the kickover knuckle joint and the
wand; a wellbore telemetry device communicably coupled to the
orientation measurement device for communicating at least one of
the azimuth, the inclination, and the tool-face direction to the
surface location in real-time; and a sequencing flow sub that is
actuatable to prevent a stimulation fluid from passing into at
least the orienting sub, the kickover knuckle joint, and the wand,
and instead divert the stimulation fluid out of the sequencing flow
sub to undertake a wellbore stimulation operation in the lateral
wellbore.
11. The system of claim 10, wherein the conveyance is coiled
tubing.
12. The system of claim 10, wherein the orienting sub is an
indexing tool that rotates a predetermined number of degrees about
the central axis upon being activated.
13. The system of claim 10, wherein the orientation measurement
device comprises a measurement-while-drilling tool.
14. The system of claim 10, wherein the wellbore telemetry device
operates using at least one of mud pulse telemetry, electromagnetic
telemetry, acoustic telemetry, ultrasonic telemetry, electrical
lines, fiber optic lines, radio frequency transmission, and any
combination thereof.
15. The system of claim 10, wherein the stimulation fluid is at
least one of a fracturing fluid and an acid.
16. A downhole tool string, comprising: a wand; a kickover knuckle
joint coupled to the wand to deflect the wand from a central axis;
an orienting sub that adjusts an angular orientation of at least
the kickover knuckle joint and the wand about the central axis; an
orientation measurement device that measures one or more of an
azimuth, an inclination, and a tool-face direction of at least one
of the kickover knuckle joint and the wand; a wellbore telemetry
device communicably coupled to the orientation measurement device
for communicating at least one of the azimuth, the inclination, and
the tool-face direction to a surface location in real-time; and a
sequencing flow sub that is actuatable to prevent a stimulation
fluid from passing into at least the orienting sub, the kickover
knuckle joint, and the wand, and instead divert the stimulation
fluid out of the sequencing flow sub to undertake a wellbore
stimulation operation.
17. The downhole tool string of claim 16, wherein the orienting sub
is an indexing tool that rotates a predetermined number of degrees
about the central axis upon being activated.
18. The downhole tool string of claim 16, wherein the orientation
measurement device comprises a measurement-while-drilling tool.
19. The downhole tool string of claim 16, wherein the wellbore
telemetry device operates using at least one of mud pulse
telemetry, electromagnetic telemetry, acoustic telemetry,
ultrasonic telemetry, an electrical line, a fiber optic line, radio
frequency transmission, and any combination thereof.
20. The downhole tool string of claim 16, wherein the stimulation
fluid is at least one of a fracturing fluid and an acid.
21. The downhole tool string of claim 16, further comprising: a
motor head assembly; and a gauge carrier that includes one or more
sensors or gauges used to measure downhole parameters.
Description
BACKGROUND
[0001] The present disclosure relates to multilateral wellbore
operations and, more particularly, to downhole tool strings having
an orientation measurement device that can be used to locate
lateral wellbores.
[0002] Operators seeking to produce hydrocarbons from subterranean
formations often drill multilateral wells. Unlike conventional
vertical wells, a multilateral well includes a primary wellbore and
one or more lateral wellbores that branch from the primary
wellbore. Although multilateral wells are often more expensive to
drill and complete than conventional wells, multilateral wells are
generally more cost-effective overall, as they usually maximize
production of reservoirs and therefore have greater production
capacity and higher recoverable reserves. Multilateral wells are
also an attractive choice in situations where it is necessary or
desirable to reduce the amount of surface drilling operations, such
as when environmental regulations impose drilling restrictions.
[0003] Although multilateral wells may offer advantages over
conventional wells, they may also involve greater complexity, which
may pose additional challenges. One such challenge involves
locating and entering a specific lateral wellbore that branches
from a primary wellbore. A number of techniques have been developed
for locating and entering lateral wellbores, including the
installation of special jewelry in the casing at a junction of the
lateral and primary wellbores. This jewelry allows the landing of a
whipstock adjacent to the junction to force any subsequent tubing
run into the primary wellbore into the desired lateral
wellbore.
[0004] Another technique for locating and entering a lateral
wellbore involves utilizing a downhole tool string that includes an
indexing tool, a kickover knuckle joint attached to the lower end
of the indexing tool, and a wand extension attached to the lower
end of the kickover knuckle joint. The downhole tool string may
first be lowered to the bottom of the primary wellbore to tag the
bottom thereof and perform any desired treatment. After performing
the treatment, the downhole tool string may then be raised to the
estimated location of a junction between the primary and lateral
wellbores. The kickover knuckle joint can be used to deflect the
wand away from the central axis of the downhole tool string and
fluid is pumped to the downhole tool string from a surface
location, which will maintain the wand in contact with the
wellbore, preventing it from fully kicking out. Upon locating the
lateral wellbore, the tip of the wand is able to bend fully into
the lateral wellbore and exhaust pressurized fluid from the
downhole tool string, which may be sensed at the surface as a
pressure drop, and thereby provide positive indication that the
lateral wellbore has been located.
[0005] If the wand fails to locate the lateral wellbore, the
downhole tool string is lowered again a certain amount of length in
the primary wellbore and the indexing tool may be used to rotate
the kickover knuckle joint and the wand to operate at a different
angular orientation. The downhole tool string is then raised within
the primary wellbore until the wand locates the lateral wellbore.
This process is repeated until the wand positively locates the
lateral wellbore.
[0006] As can be appreciated, this process can require a
significant consumption of fluids needed to operate the downhole
tool string through these repetitions, which can occur over the
span of potentially several hours, as well as excessively fatiguing
the coiled tubing workstring.
[0007] Moreover, in some cases, fluid venting from the downhole
tool string may not reliably signal that a lateral wellbore has
been located. In some instances, for example, the tip of the wand
may not fully bend and vent even though it locates and enters a
lateral wellbore. In other cases, the downhole tool string may vent
when it is not in the lateral wellbore, inter a/ia, because the
curvature of the conveyance (e.g., coiled tubing) above the
downhole tool string may be sufficient to allow the wand to fully
bend and vent. Because of the possibility of premature venting,
once the operator believes that a lateral wellbore has been
positively located, the downhole tool string is often lowered to
the bottom of the lateral wellbore to tag the bottom thereof. This
depth is then compared with the previously recorded depth of the
primary wellbore and, if the two depths are identical, it can be
surmised that a lateral wellbore has not been found, and the
operator must repeat the procedure for locating the lateral
wellbore.
[0008] The need to repeatedly tag the bottom of the primary and
lateral wellbores may add undesirable delays and expense to lateral
wellbore operations. Lateral wellbores that have a very similar
bottom depth also pose an additional problem, as it might not be
clear on which of the two laterals the coiled tubing and string are
located.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The following figures are included to illustrate certain
aspects of the present disclosure, and should not be viewed as
exclusive embodiments. The subject matter disclosed is capable of
considerable modifications, alterations, combinations, and
equivalents in form and function, without departing from the scope
of this disclosure.
[0010] FIG. 1 depicts a rigless well intervention system in which
the principles of the present disclosure may be employed.
[0011] FIGS. 2A and 2B are progressive partial cross-sectional
views of an exemplary downhole tool string.
[0012] FIG. 3 is a schematic flow chart of a method of locating a
lateral wellbore.
DETAILED DESCRIPTION
[0013] The present disclosure relates to multilateral wellbore
operations and, more particularly, to a downhole tool strings
having an orientation measurement device that can be used to locate
lateral wellbores.
[0014] The embodiments described herein provide a system and method
of locating a lateral wellbore of a multilateral wellbore and
performing a wellbore stimulation in the lateral wellbore.
According to the present disclosure, a downhole tool string
includes an orientation measurement device that can provide
real-time measurements of inclination, azimuth, and tool face
direction as the downhole tool string advances downhole. The
real-time measurements may be used to angularly align a wand
included in the downhole tool string with the lateral wellbore, and
subsequently verify that the downhole tool string has positively
entered the lateral wellbore. This may prove advantageous in
eliminating the need to pump excessive amounts of fluid to the
downhole tool string and the wand in seeking the lateral wellbore,
and may also reduce the time required to find the lateral wellbore.
Moreover, the downhole tool string and associated conveyance may
assume less fatigue since multiple cycling up and down within the
wellbore can be avoided by implementing the principles of the
present disclosure. Once the downhole tool has successfully entered
the lateral wellbore, a wellbore stimulation operation such as
acidizing, water conformance treatments, distributed temperature
survey with fiber optics, abrasive perforating, amongst others.
[0015] Referring to FIG. 1, illustrated is an exemplary rigless
well intervention system 100 that may employ the principles of the
present disclosure, according to one or more embodiments. As
illustrated, the rigless well intervention system 100 (hereafter
"the system 100") may include a parent or main wellbore 102 and at
least one lateral wellbore 104 that extends from the main wellbore
102. The main wellbore 102 may be a wellbore drilled from a surface
location (not shown) to penetrate a subterranean formation 106, and
the lateral wellbore 104 may intersect the main wellbore 102 at a
junction 108 and may otherwise comprise a lateral or deviated
wellbore drilled at an angle from the main wellbore 102. While the
main wellbore 102 is shown as being oriented generally vertical,
the main wellbore 102 may alternatively be oriented generally
horizontal or at any angle between vertical and horizontal, without
departing from the scope of the disclosure.
[0016] Both the main and lateral wellbores 102, 104 may be lined
with a liner or a string of casing 110 and subsequently cemented in
place, or may be left without any liner, which is called a
"barefoot" completion. As known in the art, the string of casing
110 may comprise multiple lengths of tubular conduits or pipe
secured together at their ends and extended into the main and
lateral wellbores 102, 104.
[0017] The system 100 may further include a downhole tool string
112 that is able to be run into the main wellbore 102 on a
conveyance 114 extending from the surface location (not shown). In
some embodiments, the conveyance 114 may be coiled tubing or the
like, and the surface location may include a wellhead installation
(not shown) and a coiled tubing unit (not shown). The coiled tubing
unit may be configured to access the main wellbore 102 via the
wellhead installation and thereby extend the downhole tool string
112 into the main wellbore 102. Accordingly, in at least one
embodiment, the system 100 may be characterized as "rigless,"
meaning that a drilling rig or drilling service unit is not located
nor required at the surface location. Rather, the main and lateral
wellbores 102, 104 have already been drilled and completed, and the
downhole tool string 112 may be selectively introduced into the
main and/or lateral wellbores 102, 104 to undertake one or more
wellbore stimulation operations, such as acidizing, water
conformance treatments, distributed temperature survey with fiber
optics, abrasive perforating, amongst others.
[0018] The downhole tool string 112 may include various components
and devices used to undertake the wellbore stimulation operations.
In some embodiments, for instance, the downhole tool string 112 may
include at least an orienting sub 116, an orientation measurement
device 118, a kickover knuckle joint 120, and a wand 122. In at
least one embodiment, the downhole tool string 112 may further
include at least one centralizer (not shown) used to radially
centralize the downhole tool string 112 within the main and/or
lateral wellbores 102, 104. The various components of the downhole
tool string 112 may be connected to each other end to end with
threaded connections. In all embodiments, the downhole tool string
112 may facilitate fluid communication through its entire length
and thereby able to provide a fluid to the wand 122 from the
conveyance 114.
[0019] The orienting sub 116 may include any known device used for
rotating the components of the downhole tool string 112 about a
central axis 124 of the downhole tool string 112. More
particularly, the orienting sub 116 may be selectively activated to
rotate the orientation measurement device 118, the kickover knuckle
joint 120, and the wand 122 about the central axis 124. In other
embodiments, as described below, the axial positions of the
orienting sub 116 and the orientation measurement device 118 may be
reversed, without departing from the scope of the disclosure.
[0020] Example devices that may be suitable as the orienting sub
116 include, but are not limited to, an indexing tool and a
continuously run motor. An indexing tool may facilitate rotation of
a predetermined number of degrees (e.g., 30.degree., 45.degree.,
etc.) about the central axis 124 upon actuating or being activated.
The indexing tool may be activated using fluid pressure conveyed
thereto via the conveyance 114. When the fluid pressure from the
conveyance 114 is increased and subsequently released, the indexing
tool may be configured to automatically rotate the predetermined
number of degrees, and thereby alter the angular configuration of
the components of the downhole tool string 112 located therebelow.
In embodiments where the orienting sub 116 is a continuously run
motor, the continuously run motor may provide selective 360.degree.
rotation about the central axis 124 of the downhole tool string
112. One of ordinary skill in the art with the benefit of this
disclosure will be able to select and employ an appropriate
orienting sub 116 for a particular application.
[0021] The orientation measurement device 118 may include one or
more sensors configured to measure, detect, and otherwise determine
the orientation of a known fixed point on the downhole tool string
112 relative to gravity, magnetic north, or other parsable
environmental constants. In some embodiments, for example, the
orientation measurement device 118 may comprise a
measurement-while-drilling (MWD) tool, such as a MWD tool
commercially available from Sperry Drilling and Halliburton Energy
Services of Houston, Tex., USA. The orientation measurement device
118 may be configured to measure and report the real-time azimuth,
inclination, and tool-face direction of the downhole tool string
112 and, more particularly, of the kickover knuckle joint 120 and
the wand 122, in addition to temperature and gamma ray
measurements.
[0022] The orientation measurement device 118 may also include a
wellbore telemetry device 126 configured to communicate either
wired or wirelessly with the surface location, thereby allowing a
well operator to receive real-time measurements of the azimuth,
inclination, and tool-face direction of the downhole tool string
112. The wellbore telemetry device 126 may be any downhole
telemetering device known to those skilled in the art including,
but not limited to, mud pulse telemetry, electromagnetic telemetry,
acoustic telemetry, ultrasonic telemetry, electrical lines, fiber
optic lines, radio frequency transmission, or any combination
thereof.
[0023] The kickover knuckle joint 120 may be any suitable device
adapted to deflect the wand 122 with respect to the central axis
124 of the downhole tool string 112. In some embodiments, the
kickover knuckle joint 120 is a selectively activated knuckle
joint, such as a hydraulic kickover joint available from NOV. Other
suitable kickover knuckle joints 120 include, but are not limited
to, restricted ball joints, pin joints, bourdon tubes, or an
asymmetrically slotted member with internal pressurization means.
One of ordinary skill in the art with the benefit of this
disclosure should be able to select and implement the appropriate
kickover knuckle joint 120 for a particular application.
[0024] In some embodiments, the kickover knuckle joint 120 may not
bend or deflect until it is activated through fluid pressure
conveyed thereto via the conveyance 114. Upon assuming fluid
pressure, the kickover knuckle joint may be configured to bend or
otherwise deflect from the central axis 124. Accordingly,
activation of the kickover knuckle joint 120 may be controlled from
the surface by controlling the hydraulic pressure conveyed to the
kickover knuckle joint 120 via the conveyance 114.
[0025] The wand 122, also known as a nozzle probe, may be
operatively coupled to the kickover knuckle joint 120 and otherwise
located at the distal end of the downhole tool string 112. By
activating the kickover knuckle joint 120, the wand 122 may be
deflected from alignment with the central axis 124 to enter a
lateral wellbore, such as the lateral wellbore 104.
[0026] The wand 122 may exhibit a length sufficient to be deflected
into the lateral wellbore 104 when it locates the junction 108. The
wand 122 may be deflected with respect to the central axis 124 to a
predetermined maximum deflection angle 128. The maximum deflection
angle 128 of the wand 122 may depend on a number of factors,
including the inner diameter of the main wellbore 102 and the axial
length of wand 122. Generally, a suitable maximum deflection angle
128 for the wand 122 may be in the range from about 3.degree. to
about 30.degree. from the central axis 124. In some embodiments,
the kickover knuckle joint 120 may be configured to deflect the
wand 122 about 15.degree. from the central axis 124.
[0027] Exemplary operation of the downhole tool string 112 in
locating and entering the lateral wellbore 104 is now provided. The
general location of the junction 108 and its angular orientation
within the main wellbore 102 may be known from prior survey
measurements taken while drilling and completing the main and
lateral wellbores 102, 104. Upon building the downhole tool string
112, the angular orientation of the kickover knuckle joint 120 may
also be noted and known relative to the orientation measurement
device 118. Therefore, using the measurements obtained by the
orientation measurement device 118 as the downhole tool string 112
is conveyed downhole, the angular orientation of the kickover
knuckle joint 120 within the main wellbore 102 may be calculated
and otherwise known. The angular orientation of the kickover
knuckle joint 120 may be reoriented as needed so that the wand 122
is able to angularly align with the lateral wellbore 104. Changing
the angular orientation of the kickover knuckle joint 120 may be
accomplished by activating the orienting sub 116 to rotate the
kickover knuckle joint 120 and the wand 122 the predetermined
number of degrees (e.g., 30.degree., 45.degree., etc.).
[0028] As the downhole tool string 112 is conveyed downhole within
the main wellbore 102, the orientation measurement device 118 may
be continuously obtaining measurements and reporting the same in
real-time to the surface location using the wellbore telemetry
device 126. As a result, a well operator may be apprised of the
real-time location of the downhole tool string 112 as it nears the
junction 108. Upon reaching the junction 108, the angular
orientation of the wand 122 may be adjusted so that it is able to
align with the lateral wellbore 104. The correct angular
orientation of the wand 122 may be confirmed in real-time with the
orientation measurement device 118 or otherwise as the wand 122
bends or deflects into the lateral wellbore 104 and vents fluid
pressure, which may be sensed at the surface location.
[0029] Once the wand 122 is angularly oriented with the lateral
wellbore 104, the downhole tool string 112 may be advanced into the
lateral wellbore 104 and the orientation measurement device 118 may
again be used to verify the present location of the downhole tool
string 112. More particularly, after entering the lateral wellbore
104, the location of the downhole tool string 112 may be uniquely
validated in real-time by obtaining new inclination, azimuth, and
tool-face direction measurements with the orientation measurement
device 118 and comparing those measurements with known deviation
survey measurements corresponding to the lateral wellbore 104. If
the new measurements and the deviation survey measurements fail to
match, that may indicate that the downhole tool string 112 failed
to enter the lateral wellbore 104 and instead remains in the main
wellbore 102. If this occurs, the lateral location procedure will
be repeated. If the present measurements and the deviation survey
measurements match, however, that may provide positive indication
that the downhole tool string 112 has successfully entered the
lateral wellbore 104. While in the lateral wellbore 104, the well
operator may proceed to undertake various wellbore stimulation
operations, such as acidizing, water conformance treatments,
distributed temperature survey with fiber optics, abrasive
perforations, amongst others.
[0030] Referring now to FIGS. 2A and 2B, illustrated are
progressive partial cross-sectional views of an exemplary downhole
tool string 200, according to one or more embodiments. The downhole
tool string 200 may be the same as or similar to the downhole tool
string 112 of FIG. 1 and therefore may be best understood with
reference thereto, where like numerals indicate like components not
described again. FIG. 2A depicts an exploded view of the upper
portions of the downhole tool string 200, and FIG. 2B depicts an
exploded view of the lower portions of the downhole tool string
200. As indicated by the exploded views, the various components of
the downhole tool string 200 may be threadably coupled. In other
embodiments, however, one or more of the components of the downhole
tool string 200 may be coupled using any other attachment means
including, but not limited to, mechanical fasteners, welding, and
brazing.
[0031] Referring first to FIG. 2A, the downhole tool string 200 may
include a connector 202 used to couple the downhole tool string 200
to a conveyance, such as the conveyance 114 of FIG. 1. The downhole
tool string 200 may further include a motor head assembly 204 and a
sequencing flow sub 206 positioned between the connector 202 and
the orienting sub 116. The motor head assembly 204 may include one
or more check valves 210 (shown as a first check valve and a second
check valve) configured to prevent fluid from flowing uphole and
otherwise back to the conveyance 114 from the downhole tool string
200. Rather, the check valves 210 may be configured to allow fluid
to proceed downhole through the downhole tool string 200.
[0032] The motor head assembly 204 may further include a hydraulic
disconnect 208a, a circulation port 208b, and a burst disc 212. The
hydraulic disconnect 208a may allow lower portions of the downhole
tool string 200 below the motor head assembly 204 to be
disconnected in the event the downhole tool string 200 becomes
stuck in the main or lateral wellbores 102, 104 (FIG. 1). The
circulation port 208b may provide an outlet for fluids conveyed to
the downhole tool string 200 from the conveyance 114 (FIG. 1) in
the event the lower portions of the downhole tool string 200 below
the motor head assembly 204 become stuck. The burst disc 212 may
allow fluid circulation through the downhole tool string 200 in the
event the lower components of the downhole tool string 200 below
the motor head assembly 204 become plugged. Penetrating or breaking
the burst disc 212 may result in fluid communication to the annulus
surrounding the downhole tool assembly 200 via the motor head
assembly 204.
[0033] The sequencing flow sub 206 may be activated to divert fluid
flow received from the conveyance 114 (FIG. 1) so that no fluid
flows to the components of the downhole tool string 200 below the
sequencing flow sub 206. Following its actuation, any fluid
introduced into the sequencing flow sub 206 may be diverted and
ejected from the sequencing flow sub 206 via one or more side
nozzles 207. As will be appreciated, the sequencing flow sub 206
may allow stimulation fluids, such as abrasive fluids and acids, to
be injected into the main and lateral wellbores 102, 104 (FIG. 1)
while undertaking the various wellbore stimulation operations
mentioned herein. The mechanism of activation of the sequencing
flow sub 206 is based on flow rate of the fluid pumped from the
surface. The sequencing flow sub 206 can be setup with several flow
rate activation settings, depending on the specific need. Once the
flow exceeds the predetermined rate, the flow to the tools below
the sequencing flow sub 206 is stopped via a spring-operated
mechanism or similar, and a sleeve, or another similar device,
shifts to expose the nozzles 207, thus allowing flow to come out of
the nozzles 207.
[0034] In some embodiments, a cross-over sub 214 may interpose and
otherwise be positioned between the orienting sub 116 and the
orientation measurement device 118. In other embodiments, however,
the cross-over sub 214 may be omitted and the orienting sub 116 may
instead be directly coupled to the orientation measurement device
118, without departing from the scope of the disclosure.
[0035] Referring to FIG. 2B, in some embodiments, the downhole tool
string 200 may further include a gauge carrier 216. In at least one
embodiment, a cross-over sub 218 may interpose and otherwise be
positioned between the gauge carrier 216 and the orientation
measurement device 118 (FIG. 2A). In other embodiments, however,
the cross-over sub 218 may be omitted and the gauge carrier 216 may
instead be directly coupled to the orientation measurement device
118, without departing from the scope of the disclosure.
[0036] The gauge carrier 216 may include various sensors and gauges
used to measure downhole parameters such as, but not limited to,
pressure and temperature. The sensors and gauges included in the
gauge carrier 216 may further include a gamma ray sensor and a
casing collar locator.
[0037] As illustrated, an optional cross-over sub 220 may interpose
and otherwise be positioned between the gauge carrier 216 and the
kickover knuckle joint 120. Moreover, in some embodiments, the
downhole tool string 200 may further include an extension arm 222
used to extend the reach or axial length of the wand 122 located at
the distal end of the downhole tool string 200. As will be
appreciated, the extension arm 222 may prove advantageous in
embodiments where the diameter of the main or lateral wellbores
102, 104 (FIG. 1) are large. In other embodiments, the extension
arm 222 may be omitted. As illustrated in FIG. 2B, the wand 122 may
include one or more vents 224 (shown as vents 224a and 224b)
defined therein. The vents 224a,b may provide outlets used to vent
fluid pressure from the downhole tool string 220 when the wand 122
locates and deflects into a lateral wellbore (e.g., the lateral
wellbore 104 of FIG. 2).
[0038] In the illustrated embodiment of FIGS. 2A and 2B, the
orientation measurement device 118 is depicted as being positioned
below the orienting sub 116 along the axial length of the downhole
tool string 200 and thereby able to obtain real-time inclination
and tool-face data closer to the kickover knuckle joint 120. In
other embodiments, however, the orientation measurement device 118
may alternatively be positioned above the orienting sub 116,
without departing from the scope of the disclosure. In such
embodiments, the angular orientation of the kickover knuckle joint
120 may nonetheless be known or otherwise calculated by knowing the
degrees of rotation per indexing cycle of the orienting sub 116 and
the number of times the orienting sub 116 has been activated.
[0039] Referring now to FIG. 3, illustrated is a schematic flow
chart of an exemplary method 300 of locating a lateral wellbore,
according to one or more embodiments. The method 300 may be
accomplished using either of the downhole tool strings 112, 200
described herein in locating and entering one or more lateral
wellbores, such as the lateral wellbore 104 of FIG. 1. According to
the method 300, a downhole tool string may be introduced into a
main wellbore of a multilateral wellbore, as at 302. The
multilateral wellbore may include a lateral wellbore that extends
from the main wellbore at a junction. Moreover, the downhole tool
string may include a wand and a kickover knuckle joint coupled to
the wand.
[0040] A first measurement may be obtained with an orientation
measurement device included in the downhole tool string, as at 304.
The first measurement may include at least one of an azimuth, an
inclination, and a tool-face direction of the downhole tool string.
The first measurement may be communicated to a surface location in
real time with a wellbore telemetry device communicably coupled to
the orientation measurement device. The angular orientation of the
kickover knuckle joint and the wand may then be aligned with the
lateral wellbore as based on the first measurement, as at 306. In
some embodiments, this may include activating an orienting sub
included in the downhole tool string, and thereby changing the
angular orientation of the kickover knuckle joint and the wand.
[0041] The downhole tool string may then be advanced into the
lateral wellbore to obtain a second measurement with the
orientation measurement device, as at 308. The second measurement
may be obtained while the downhole tool string is positioned in the
lateral wellbore and may include at least one of the azimuth, the
inclination, and the tool-face direction of the downhole tool
string. The second measurement may be communicated to the surface
location in real time with the wellbore telemetry device.
[0042] The second measurement may then be compared with known
deviation survey measurements corresponding to the lateral
wellbore, as at 310. Comparing the second measurement with the
known deviation survey measurements may verify a location of the
downhole tool string within the lateral wellbore. Once it is
verified that the downhole tool string is located within the
lateral wellbore, one or more wellbore stimulation operations may
be undertaken with the downhole tool string while positioned in the
lateral wellbore, as at 312. Undertaking the one or more wellbore
stimulation operations may include activating a sequencing flow sub
included in the downhole tool string to prevent a stimulation fluid
from passing into at least an orienting sub, the kickover knuckle
joint, and the wand, and diverting the stimulation fluid out of the
sequencing flow sub. Undertaking the one or more wellbore
stimulation operations may further include at least one treating a
portion of the lateral wellbore such as acidizing, water
conformance treatments, distributed temperature survey with fiber
optics, abrasive perforating, amongst others. The foregoing steps
of 302-312 may then be repeated at a second lateral wellbore within
the multilateral wellbore, as at 314.
[0043] Embodiments disclosed herein include:
[0044] A. A method that includes introducing a downhole tool string
into a main wellbore of a multilateral wellbore, the multilateral
wellbore including a lateral wellbore that extends from the main
wellbore at a junction, and the downhole tool string including a
wand and a kickover knuckle joint coupled to the wand, obtaining a
first measurement with an orientation measurement device included
in the downhole tool string, the first measurement including at
least one of an azimuth, an inclination, and a tool-face direction
of the downhole tool string, aligning an angular orientation of the
kickover knuckle joint and the wand with the lateral wellbore as
based on the first measurement, advancing the downhole tool string
into the lateral wellbore and obtaining a second measurement with
the orientation measurement device while the downhole tool string
is positioned in the lateral wellbore, the second measurement
including at least one of the azimuth, the inclination, and the
tool-face direction of the downhole tool string, comparing the
second measurement with known deviation survey measurements
corresponding to the lateral wellbore and thereby verifying a
location of the downhole tool string in the lateral wellbore, and
undertaking one or more wellbore stimulation operations with the
downhole tool string while positioned in the lateral wellbore.
[0045] B. A rigless well intervention system that includes a main
wellbore having at least a portion thereof lined with casing, a
lateral wellbore that extends from the main wellbore at a junction,
at least a portion of the lateral wellbore being lined with casing,
a downhole tool string extendable within the main wellbore on a
conveyance from a surface location and having a central axis, the
downhole tool string including a wand and a kickover knuckle joint
coupled to the wand to deflect the wand from the central axis, an
orienting sub that adjusts an angular orientation of at least the
kickover knuckle joint and the wand about the central axis, an
orientation measurement device that measures one or more of an
azimuth, an inclination, and a tool-face direction of at least one
of the kickover knuckle joint and the wand, a wellbore telemetry
device communicably coupled to the orientation measurement device
for communicating at least one of the azimuth, the inclination, and
the tool-face direction to the surface location in real-time, and a
sequencing flow sub that is actuatable to prevent a stimulation
fluid from passing into at least the orienting sub, the kickover
knuckle joint, and the wand, and instead divert the stimulation
fluid out of the sequencing flow sub to undertake a wellbore
stimulation operation in the lateral wellbore.
[0046] C. A downhole tool string that includes a wand, a kickover
knuckle joint coupled to the wand to deflect the wand from a
central axis, an orienting sub that adjusts an angular orientation
of at least the kickover knuckle joint and the wand about the
central axis, an orientation measurement device that measures one
or more of an azimuth, an inclination, and a tool-face direction of
at least one of the kickover knuckle joint and the wand, a wellbore
telemetry device communicably coupled to the orientation
measurement device for communicating at least one of the azimuth,
the inclination, and the tool-face direction to a surface location
in real-time, and a sequencing flow sub that is actuatable to
prevent a stimulation fluid from passing into at least the
orienting sub, the kickover knuckle joint, and the wand, and
instead divert the stimulation fluid out of the sequencing flow sub
to undertake a wellbore stimulation operation.
[0047] Each of embodiments A, B, and C may have one or more of the
following additional elements in any combination: Element 1:
wherein aligning the angular orientation of the kickover knuckle
joint and the wand with the lateral wellbore comprises activating
an orienting sub included in the downhole tool string, and changing
the angular orientation of the kickover knuckle joint and the wand
with the orienting sub. Element 2: wherein the downhole tool string
further includes a sequencing flow sub, and wherein undertaking the
one or more wellbore stimulation operations comprises activating
the sequencing flow sub to prevent a stimulation fluid from passing
into at least an orienting sub, the kickover knuckle joint, and the
wand, and diverting the stimulation fluid out of the sequencing
flow sub. Element 3: wherein undertaking the one or more wellbore
stimulation operations comprises at least one of acidizing a
portion of the lateral wellbore and hydraulically fracturing a
portion of the lateral wellbore. Element 4: wherein the downhole
tool string further includes a wellbore telemetry device
communicably coupled to the orientation measurement device, the
method further comprising communicating the first and second
measurements to the surface location in real-time. Element 5:
wherein communicating the first and second measurements to the
surface location in real-time comprises operating the wellbore
isolation device using at least one of mud pulse telemetry,
electromagnetic telemetry, acoustic telemetry, ultrasonic
telemetry, electrical lines, fiber optic lines, radio frequency
transmission, and any combination thereof. Element 6: wherein the
downhole tool string further includes a gauge carrier that includes
one or more sensors or gauges, the method further comprising
measuring one or more downhole parameters with the gauge carrier as
the downhole tool string advances within the main or lateral
wellbores. Element 7: wherein the lateral wellbore is a first
lateral wellbore and the junction is a first junction, the method
further comprising retracting the downhole tool string from the
first lateral wellbore and into the main wellbore, moving the
downhole tool string within the main wellbore toward a second
lateral wellbore that extends from the main wellbore at a second
junction, obtaining a third measurement with the orientation
measurement device, the first measurement including at least one of
the azimuth, the inclination, and the tool-face direction of the
downhole tool string, aligning the angular orientation of the
kickover knuckle joint and the wand with the second lateral
wellbore as based on the third measurement, advancing the downhole
tool string into the second lateral wellbore and obtaining a fourth
measurement with the orientation measurement device while the
downhole tool string is positioned in the second lateral wellbore,
the fourth measurement including at least one of the azimuth, the
inclination, and the tool-face direction of the downhole tool
string, comparing the fourth measurement with known deviation
survey measurements corresponding to the second lateral wellbore
and thereby verifying a location of the downhole tool string in the
second lateral wellbore, and undertaking one or more wellbore
stimulation operations with the downhole tool string while
positioned in the second lateral wellbore. Element 8: wherein
undertaking the one or more wellbore stimulation operations with
the downhole tool string while positioned in the second lateral
wellbore comprises at least one of acidizing a portion of the
second lateral wellbore and hydraulically fracturing a portion of
the second lateral wellbore.
[0048] Element 9: wherein the conveyance is coiled tubing. Element
10: wherein the orienting sub is an indexing tool that rotates a
predetermined number of degrees about the central axis upon being
activated. Element 11: wherein the orientation measurement device
comprises a measurement-while-drilling tool. Element 12: wherein
the wellbore telemetry device operates using at least one of mud
pulse telemetry, electromagnetic telemetry, acoustic telemetry,
ultrasonic telemetry, electrical lines, fiber optic lines, radio
frequency transmission, and any combination thereof. Element 13:
wherein the stimulation fluid is at least one of a fracturing fluid
and an acid.
[0049] Element 14: wherein the orienting sub is an indexing tool
that rotates a predetermined number of degrees about the central
axis upon being activated. Element 15: wherein the orientation
measurement device comprises a measurement-while-drilling tool.
Element 16: wherein the wellbore telemetry device operates using at
least one of mud pulse telemetry, electromagnetic telemetry,
acoustic telemetry, ultrasonic telemetry, an electrical line, a
fiber optic line, radio frequency transmission, and any combination
thereof. Element 17: wherein the stimulation fluid is at least one
of a fracturing fluid and an acid. Element 18: further comprising a
motor head assembly, and a gauge carrier that includes one or more
sensors or gauges used to measure downhole parameters.
[0050] By way of non-limiting example, exemplary combinations
applicable to A, B, and C include: Element 4 with Element 5;
Element 7 with Element 8; Element 9 with Element 11; and Element 9
with Element 12.
[0051] Therefore, the disclosed systems and methods are well
adapted to attain the ends and advantages mentioned as well as
those that are inherent therein. The particular embodiments
disclosed above are illustrative only, as the teachings of the
present disclosure may be modified and practiced in different but
equivalent manners apparent to those skilled in the art having the
benefit of the teachings herein. Furthermore, no limitations are
intended to the details of construction or design herein shown,
other than as described in the claims below. It is therefore
evident that the particular illustrative embodiments disclosed
above may be altered, combined, or modified and all such variations
are considered within the scope of the present disclosure. The
systems and methods illustratively disclosed herein may suitably be
practiced in the absence of any element that is not specifically
disclosed herein and/or any optional element disclosed herein.
While compositions and methods are described in terms of
"comprising," "containing," or "including" various components or
steps, the compositions and methods can also "consist essentially
of" or "consist of" the various components and steps. All numbers
and ranges disclosed above may vary by some amount. Whenever a
numerical range with a lower limit and an upper limit is disclosed,
any number and any included range falling within the range is
specifically disclosed. In particular, every range of values (of
the form, "from about a to about b," or, equivalently, "from
approximately a to b," or, equivalently, "from approximately a-b")
disclosed herein is to be understood to set forth every number and
range encompassed within the broader range of values. Also, the
terms in the claims have their plain, ordinary meaning unless
otherwise explicitly and clearly defined by the patentee. Moreover,
the indefinite articles "a" or "an," as used in the claims, are
defined herein to mean one or more than one of the element that it
introduces. If there is any conflict in the usages of a word or
term in this specification and one or more patent or other
documents that may be incorporated herein by reference, the
definitions that are consistent with this specification should be
adopted.
[0052] As used herein, the phrase "at least one of" preceding a
series of items, with the terms "and" or "or" to separate any of
the items, modifies the list as a whole, rather than each member of
the list (i.e., each item). The phrase "at least one of" allows a
meaning that includes at least one of any one of the items, and/or
at least one of any combination of the items, and/or at least one
of each of the items. By way of example, the phrases "at least one
of A, B, and C" or "at least one of A, B, or C" each refer to only
A, only B, or only C; any combination of A, B, and C; and/or at
least one of each of A, B, and C.
[0053] The use of directional terms such as above, below, upper,
lower, upward, downward, left, right, uphole, downhole and the like
are used in relation to the illustrative embodiments as they are
depicted in the figures, the upward direction being toward the top
of the corresponding figure and the downward direction being toward
the bottom of the corresponding figure, the uphole direction being
toward the surface of the well and the downhole direction being
toward the toe of the well.
* * * * *