Note: Descriptions are shown in the official language in which they were submitted.
WO 2012/034001 CA 02811058 2013-03-08PCT/US2011/050970
A METHOD FOR FINDING AND RE-ENTERING A LATERAL BORE IN A MULTI-
LATERAL WELL
BACKGROUND OF THE INVENTION
Field of the Invention
[0ool] Embodiments of the invention relate to systems and methods for
indentifying and entering lateral wellbores that extend from a primary
wellbore.
Embodiments of the invention further relate to locating a lateral wellbore, in
either a
cased or open-holed section of a primary wellbore, using a conveyance member,
including but not limited to coiled tubing, jointed tubulars, continuous rod,
and/or
wireline, and a tool string that allows an operator to orient and direct the
tool string
into the lateral wellbore. Embodiments of the invention further relate to
systems and
methods for measuring downhole characteristics, such as wellbore depth,
direction,
and inclination, transmitting a signal corresponding to the measured downhole
characteristics to the surface of the wellbore via electrical telemetry, mud
pulse
telemetry, electromagnetic telemetry, etc., comparing the measured downhole
characteristics to existing survey data, and verifying a location of a lateral
wellbore
based upon the compared data.
Description of the Related Art
[0002] The purpose of drilling multiple lateral wellbores from a single
primary
wellbore is to increase access to one or more reservoirs without incurring the
cost of
surface casing, surface site preparation, and other expenses associated with
drilling
multiple primary wells originating at the earth's surface. Lateral wellbores
are drilled
by re-entering the primary wellbore and performing a sidetrack operation. In
cases
where wellhead space is limited, such as in offshore applications, the
advantages of
multiple lateral wellbores are compounded further.
[0003] The downside to drilling multiple lateral wellbores, however, is that
subsequent workover operations requiring re-entry into a specific lateral
wellbore of
the multi-lateral well can be difficult. There is no control, absent special
methods and
apparatus, over which lateral wellbore a work string will enter upon being
lowered into
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the multi-lateral well. The general problem becomes one of directing the work
string
into the desired branch.
[0004] There are a few known methods used to re-enter a lateral wellbore,
however, these methods are extremely time consuming and at least partly rely
on a
trial and error process. One known method is described as the "Poke and Hope"
method. This method locates a work string near a lateral wellbore junction and
uses
a knuckle joint and an orienter in an effort to manipulate an end of a work
string into
the lateral wellbore. The work string is simply lowered to the bottom of the
lateral
wellbore, and the recorded maximum depth is compared to known well depth data
to
determine which lateral wellbore the work string has entered. The work string
may
then be returned to the depth of the lateral wellbore junction, manipulated
and
lowered again, it being assumed that the work string has entered into another
lateral
wellbore. The work string is again lowered to the bottom of the second lateral
wellbore; the recorded maximum depth is again compared to known well depth
data
to determine which lateral wellbore the work string has subsequently entered.
The
"Poke and Hope" method can be time consuming if there are several lateral
wellbores
in close proximity, since the method relies on the comparison of the "tagged"
or
"bottomed-out" data of each wellbore to ultimately identify a specific
wellbore. A big
drawback of the method includes obstructions in one or more of the lateral
wellbores
that can falsely indicate that the work string has bottomed out, thereby
providing a
recorded depth that does not match any of the known well data. Even worse, the
recorded depth may match the depth of a different lateral wellbore, thereby
leading to
an incorrect assumption that the work string is in a specific lateral wellbore
when it is
not.
[0005] Another known method is described as the "Enhanced Poke and Hope"
method. This method uses a fluid activated assembly connected to a work string
that
provides a signal, such as a pressure decrease, when the work string is
reciprocated
through an area of a lateral wellbore junction and "pokes" into the lateral
wellbore.
The location of the lateral wellbore junction is used as a reference point and
the work
string is then lowered, again with the assumption that the work string has
entered the
lateral wellbore. The recorded depth at the bottom is then compared to known
well
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depth data as described above. This method also suffers from the same
drawbacks
described above.
[0006] Therefore, there is a need for an improved system and method for
identifying and entering a lateral wellbore in a multi-lateral well.
SUMMARY OF THE INVENTION
[0007] In one embodiment, a method of locating and entering a lateral wellbore
that extends from a primary wellbore may comprise running a tool string into
the
primary wellbore to a location adjacent to a junction between the primary and
lateral
wellbores using existing survey data of at least one of the primary and
lateral
wellbores. The method may further comprise deflecting the tool string at an
angle
relative to a longitudinal axis of the tool string; measuring an inclination
and an
azimuth of the tool string; and comparing the measured inclination and azimuth
to
existing survey data of the lateral wellbore. The method may further comprise
running the tool string past the location adjacent to the junction and in a
direction of
the lateral wellbore based on the comparison of the measured inclination and
azimuth
to the existing survey data of the lateral wellbore; and measuring an
inclination and an
azimuth of the tool string after running it past the location adjacent to the
junction and
comparing the measured inclination and azimuth to existing survey data of the
lateral
wellbore to verify that the tool string has entered the lateral wellbore.
[0008] In one embodiment, a method of locating and entering a lateral wellbore
that extends from a primary wellbore may comprise locating a tool string
adjacent to a
junction between the primary and lateral wellbores. The method may further
comprise measuring a first downhole characteristic at the junction using a
measurement assembly of the tool string; comparing the measured first downhole
characteristic to existing survey data of the lateral wellbore; and
positioning the tool
string in a direction of the lateral wellbore based on the comparison of the
measured
first downhole characteristic and the existing survey data of the lateral
wellbore. The
method may further comprise moving the tool string in the direction of the
lateral
wellbore; measuring a second downhole characteristic after the tool string has
been
moved in the direction of the lateral wellbore; and comparing the measured
second
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downhole characteristic to existing survey data of the lateral wellbore to
verify that the
tool string has entered the lateral wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] So that the manner in which the above recited features of the
invention can
be understood in detail, a more particular description of the invention,
briefly
summarized above, may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however, that the
appended
drawings illustrate only typical embodiments of this invention and are
therefore not to
be considered limiting of its scope, for the invention may admit to other
equally
effective embodiments.
[0010] Figures 1-5 illustrate a method of identifying and entering a lateral
wellbore
from a primary wellbore according to one embodiment.
DETAILED DESCRIPTION
[0011] Figure 1 illustrates a conveyance member 10 connected to a tool string
100
that is located in a primary wellbore 5. In one embodiment, the conveyance
member
10 may include a coiled tubing string that is provided from a spoolable
mechanism 13
at the surface of the primary wellbore 5. The spoolable mechanism 13 may be
operable to provide an axial force to the coiled tubing string and thus the
tool string
100 as it is run into the primary wellbore 5. In one embodiment, the
conveyance
member 10 may include a jointed tubing string, a string of continuous rods,
and/or a
wireline that is provided from a platform at the surface of the primary
wellbore 5. In
one embodiment, one or more fluids may be supplied from the surface, through
the
conveyance member 10, to the tool string 100 for operation of one or more
components of the tool string 100. In one embodiment, a signal may be
communicated from the surface, through the conveyance member 10, to the tool
string 100 for operation of one or more components of the tool string 100. In
one
embodiment, the tool string 100 may include a connection assembly 20, an
orientation assembly 30, a measurement assembly 40, a deflection assembly 50,
a
sub assembly 60, and a guide assembly 70.
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[0012] The tool string 100 may be coupled to the conveyance member 10 by the
connection assembly 20. In one embodiment, the connection assembly 20 may
include any type of motorhead assembly known by one of ordinary skill in the
art. The
connection assembly 20 may be operable to provide a sealed and/or a high-
strength
(tensile, torsional, compressive) connection between the conveyance member 10
and
the tool string 100. In one embodiment, the connection assembly 20 may include
a
tubular member having a bore disposed therethrough, and may include one or
more
seals and/or slips for connection with the conveyance member 10. In one
embodiment, the connection assembly 20 may include one or more valves, such as
a
flapper valve or a check valve, operable to control fluid flow through the
connection
assembly 20. In one embodiment, the connection assembly 20 may include a
safety
disconnect operable to disconnect the tool string 100 from the conveyance
member
in the event of an emergency, such as if the tool string 100 becomes stuck in
the
primary wellbore 5. In one embodiment, the connection assembly 20 may include
a
15 circulation sub operable to isolate a lower portion of the tool string
100 from fluid flow,
while maintaining fluid circulation through an upper portion of the tool
string 100 and
the primary wellbore 5.
[0013] The connection assembly 20 may also be connected to the orientation
assembly 30. The orientation assembly 30 may include a tubular member having a
20 bore disposed therethrough, and may be selectively actuatable using fluid
pressure to
orient the lower portion of the tool string 100. In one embodiment, the
orientation
assembly 30 may include a hydraulic ratcheting device that is operable to
rotate the
lower portion of the tool string 100 about the longitudinal axis of the tool
string 100.
The orientation assembly 30 may be operable to index the lower portion of the
tool
string 100 to one or more fixed intervals between 0 degrees and 360 degrees
about
the longitudinal axis of the tool string 100. Pressurized fluid may be
supplied through
the orientation assembly 30 to actuate the assembly, thereby indexing
(rotating) the
lower portion of the tool string 100 one or more degrees. In one embodiment,
the
orientation assembly 30 may automatically reset by decreasing the fluid
pressure in
the assembly. In this manner, pressurized fluid may be repeatedly supplied
through
the orientation assembly 30 to index the lower portion of the tool string
through a 360
degree interval.
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[0014] The measurement assembly 40, also known as a measurement-while-
drilling device, may be connected to the orientation assembly 30. The
measurement
assembly 40 may include a tubular member having a bore disposed therethrough.
The measurement assembly 40 may be operable to measure one or more downhole
characteristics, such wellbore inclination and azimuth (direction). In one
embodiment,
the measurement assembly 40 may be operable to measure wellbore drift within
an
inclination range of 0 degrees to 90 degrees with .25 degree increments, and
wellbore
direction with azimuth readings having 1 degree resolution. The measurement
assembly 40 may also be operable to communicate a signal corresponding to the
measured downhole characteristics real-time to an operator at the wellbore
surface.
The signal may be decoded and the measured results may be displayed real-time
on
a monitor or other type of display screen. In one embodiment, the signal (and
thus
the measured downhole characteristics) may be communicated real-time via mud-
pulse telemetry, electromagnetic telemetry, and/or other telemetry methods
known by
one of ordinary skill in the art. The measurement assembly 40 may also include
a
power source, a microprocessor, a data acquisition system, and/or one or more
sensors for measuring a variety of downhole characteristics, including
wellbore and/or
tool string 100 depth, inclination, and direction. In one embodiment, the
measurement assembly 40 may be operable to measure the depth, inclination, and
azimuth of one or more portions of the tool string 100, including the
direction of the
tool string 100 face. In one embodiment, the measurement assembly 40 may be
operable to measure the orientation of a fixed point on the tool string 100
relative to
gravity, magnetic and/or true north, or other known constant. In one
embodiment, the
measurement assembly 40 may be operable to measure the orientation of the face
of
the tool string 100 and compare the measured tool string face to a fixed
reference
point, also known as a "tie-in point," on the tool string 100 to determine the
angular
direction that the tool string 100 is facing downhole. In one embodiment, the
measurement assembly 40 may be operable to measure the inclination of one or
more portions of the tool string 100 downhole. The measured inclination of the
tool
string 100 may be used as a measurement of the inclination of the wellbore at
that
location downhole. In one embodiment, pressurized fluid may be supplied
through
the measurement assembly 40 to selectively activate the assembly to measure a
downhole characteristic and communicate the measured downhole characteristic
to
an operator at the surface of the wellbore.
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[0015] The deflection assembly 50, also known as a kick-over knuckle joint,
may
be connected to the measurement assembly 40. The deflection assembly 50 may
include a tubular member having a bore disposed therethrough. The deflection
assembly 50 may be operable to tilt or deflect (i.e. "kick-over") the lower
portion of the
tool string 100 in the direction of a lateral wellbore. Pressurized fluid may
be used to
selectively actuate the deflection assembly 50 to deflect the lower portion of
the tool
string 100 at an angle of about 3 degrees to about 30 degrees, 45 degrees, or
60
degrees from the longitudinal axis of the tool string 100. In one embodiment,
the
deflection assembly 50 may be automatically reset by decreasing the fluid
pressure in
the assembly.
[0016] The sub assembly 60 may be connected to the deflection assembly 50, and
the guide assembly 70 may be connected to the sub assembly 60. The sub and
guide assemblies 60, 70 include the lower portions of the tool string 100 that
are
deflected out of alignment with the longitudinal axis of the tool string 100
by the
deflection assembly 50. The sub and guide assembles 60, 70 may each include a
tubular member have a bore disposed therethrough. The sub assembly 50 is
operable to provide adequate length to the lower portion of the tool string
100 to
sufficiently deflect it into a lateral wellbore, taking into account the angle
of inclination
from the primary wellbore 5, the diameter of the primary wellbore 5, and/or
the
diameter of the tool string 100. For example, the sub assembly 50 may need to
be
longer when in wellbores having larger inner diameters than when in smaller
diameter
wellbores. In one embodiment, the sub assembly 50 may be adjustable in length,
for
example, by telescoping, and/or may be shaped to have some curvature to
facilitate
entry into a lateral wellbore. The guide assembly 70 may include a guide nose
to
direct the tool string 100 into the primary and/or lateral wellbores; one or
more ports,
such as jetting nozzles, to allow fluid flow therethrough in all radial
directions; and one
or more flutes disposed on its outer surface to allow fluid flow around the
outer
diameter of the guide assembly 70.
[0017] In one embodiment, the tool string 100 may be lowered into one or more
primary and/or lateral wellbores using a wireline conveyance member 10. In one
embodiment, the tool string 100 may include a tractor member configured to
move the
tool string 100 through a wellbore having an inclined and/or horizontal
trajectory. In
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one embodiment, the tool string 100 may be lowered into one or more primary
and/or
lateral wellbores using a coiled tubing conveyance member 10 with a wireline
disposed through the coiled tubing conveyance member 10. The coiled tubing
conveyance member 10 may be used to move the tool string 100 through a
wellbore
having an inclined and/or horizontal trajectory, while the wireline may be
used to
communicate a signal to one or more components of the tool string 100. In one
embodiment, the connection assembly 20, the orientation assembly 30, the
measurement assembly 40, the deflection assembly 50, the sub assembly 60,
and/or
the guide assembly 70 may be operable using electrical power. In one
embodiment,
an electrical signal may be communicated via the wireline conveyance member 10
to
the orientation assembly 30, thereby actuating the orientation assembly 30 to
orient
the lower portion of the tool string 100. In one embodiment, the tool string
100 may
include a selectively actuatable anchoring mechanism to secure a portion of
the tool
string 100 in the wellbore while another portion of the tool string 100 is
rotated by the
orientation assembly 30. In one embodiment, an electrical signal may be
communicated via the wireline conveyance member 10 to the measurement assembly
40, thereby actuating the measurement assembly 40 to measure one or more
downhole characteristics. In one embodiment, an electrical signal may be
communicated via the wireline conveyance member 10 to the deflection assembly
50,
thereby actuating the deflection assembly 50 to deflect the lower portion of
the tool
string 100. The orientation assembly 30, the measurement assembly 40, and/or
the
deflection assembly 50 may communicate a signal via the wireline conveyance
member 10 to an operator to confirm operation of the assembly. Other forms of
wired
and/or wireless communication methods may be used with the embodiments
described herein.
[0018] Referring now to Figures 1-5, an embodiment for locating and entering
a
lateral wellbore from a primary wellbore is illustrated. The tool string 100
is shown
disposed in the primary wellbore 5, a portion of which may be lined with
casing 15
that is cemented therein.. The primary wellbore 5 may be a vertical wellbore,
a
horizontal wellbore, and/or an angled wellbore between vertical and
horizontal. A first
lateral wellbore 25 and a second lateral wellbore 35 extend from the primary
wellbore
5 at a first junction 23 and a second junction 33, respectively. The first and
second
lateral wellbores 25, 35 may be open-hole or may be lined with casing. In one
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embodiment, the first lateral wellbore 25 may drilled to a depth X with an
azimuth of
about 270 degrees and an inclination of about 88 degrees throughout the
wellbore. In
one embodiment, the second lateral wellbore 35 may drilled to a depth Y with
an
azimuth of about 250 degrees and an inclination of about 82 degrees throughout
the
wellbore.
[0019] A "primary wellbore" may include any wellbore that originates from the
surface (including on-land, off-shore, and/or subsea applications) and/or any
wellbore
that is in communication with a lateral wellbore. A "lateral wellbore" may
include any
wellbore that intersects another wellbore. Inclination of a wellbore may be
defined
herein as the angle of the wellbore defined by a tangent line and a vertical
line; the
vertical line being substantially parallel to the direction of earth's
gravity. In one
embodiment, 0 degree inclination is vertical and 90 degree inclination is
horizontal.
Azimuth of a wellbore may be defined herein as the angle of the wellbore
direction as
projected to a horizontal plane and relative to true north and/or magnetic
north. In
one embodiment, 0 degree azimuth coincides with North, 90 degree azimuth with
East, 180 degree azimuth with South, and 270 degree azimuth with West. The
depth
of a wellbore may be defined herein as an actual depth and/or a true vertical
depth.
In one embodiment, the actual depth is the depth of a point in the wellbore as
measured along the path of the wellbore. In one embodiment, the true vertical
depth
is the absolute vertical distance from a point in the wellbore to a point at
the surface.
The depth of one or more points along the length of the wellbore can be
measured
and used with the embodiments described herein.
[0020] The downhole characteristics and the existing survey data as described
herein may include measurements of and other information regarding the
wellbores,
the formation surrounding the wellbores, and/or one or more components of the
tool
string 100. In one embodiment, the downhole characteristics and existing
survey data
may include formation density, formation porosity/permeability, formation
resistivity,
formation fluids, and/or other rock and petro-physical properties. In one
embodiment,
the downhole characteristics and existing survey data may include inclination,
azimuth, and/or depth of the wellbores and/or one or more components of the
tool
string. In one embodiment, the downhole characteristics and existing survey
data
may include the location, such as the depth, of a casing, the location a
casing collar,
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the location of an RFID tag, the location of a PIP tag, and/or the location of
other
identifying "markers" in the wellbores. In one embodiment, the downhole
characteristics and existing survey data may include the emission of radiation
and/or
a gamma ray log at a location in the wellbores. In one embodiment, the
downhole
characteristic and existing survey data may include the absence of one or more
downhole characteristics and/or existing survey data of the wellbores. For
example,
the absence of a downhole characteristic when a measurement is taken at a
particular location in the primary and/or lateral wellbores may be used to
verify that
the tool string 100 is and/or is not in a specific wellbore.
[0021] As illustrated in Figure 1, the tool string 100 may be run into the
primary
wellbore 5 using the conveyance member 10. During run-in, the lower portion of
the
tool string 100 may be maintained at an angle substantially coincident with
the
longitudinal axis of the upper portion of the tool string 100. The depth that
the tool
string 100 is located within the primary wellbore 25 may be continuously
monitored
and measured during run-in from the surface and/or using the measuring
assembly
40. The tool string 100 may be positioned in the primary wellbore 5 at a
location
adjacent to the first junction 23. In one embodiment, the tool string 100 may
be
positioned in the primary wellbore 5 at a location ahead of, beyond, or next
to the first
junction 23. In one embodiment, existing survey data of the primary wellbore 5
may
be used to approximate the depth at which the tool string 100 is to be lowered
to
position the tool string 100 within close proximity to the first junction 23.
In one
embodiment, existing survey data of the first and/or second lateral wellbores
25, 35,
as well as any other lateral wellbores, may be used to confirm that the tool
string 100
is not located in a lateral wellbore, thereby verifying that the tool string
100 is located
in the primary wellbore 5.
[0022] As illustrated in Figure 2, when the tool string 100 is positioned at
the
desired depth relative to the first junction 23, the lower portion of the tool
string 100
may be deflected with respect to the longitudinal axis of the upper portion of
the tool
string 100. In one embodiment, pressurized fluid may be supplied to the
deflection
assembly 50 (from the surface via the conveyance member 10) until a
predetermined
amount of pressure actuates the deflection assembly 50 to deflect the sub and
guide
assemblies 60, 70 with respect to the longitudinal axis of the upper portion
of the tool
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string 100. The lower portion of the tool string 100 may be maintained in the
deflected position, with or without maintaining fluid circulation
therethrough. In one
embodiment, the guide assembly 70 may contact the inner surface of the primary
wellbore 5, which may constrain and prevent it from further deflection and
which may
force the upper potion of the tool string 100 toward an opposing side of the
inner
surface of the primary wellbore 5.
[0023] The measurement assembly 40 may be selectively activated to measure
one or more downhole characteristics, such as the inclination and the azimuth
of the
primary wellbore 5, the first lateral wellbore 25, and/or one or more portions
of the tool
string 100. In one embodiment, the measurement assembly 40 may be selectively
actuated to measure the angular direction that a lower portion of the tool
string 100,
such as a tool face of the guide assembly 70, is facing. The angular direction
of the
lower portion of the tool string 100 may be compared to a fixed reference
point, such
as a reference point on the tool string 100, to determine the angular
direction that the
lower portion of the tool string 100 is facing at the location in the primary
wellbore 5.
In one embodiment, the measurement assembly 40 may be selectively actuated to
measure the angle of inclination of an upper portion of the tool string 100,
such as a
portion above the deflection assembly 50. The angle of inclination of the
upper
portion of the tool string 100 may correspond to the angle of inclination of
the primary
wellbore 5 at that location. In one embodiment, pressurized fluid may be
supplied
through the measurement assembly 40 (from the surface via the conveyance
member
10) to activate the measurement assembly 40 and to generate a signal
corresponding
to the measured downhole characteristics. The measurement assembly 40 may
communicate the signal corresponding to the measured downhole characteristics
to
an operator at the surface of the primary wellbore 5. The signal may be sent
using
electronic telemetry, mud-pulse telemetry, electromagnetic telemetry, and/or
other
remote communication methods. The signal may be converted to display the
measured downhole characteristics on a monitor or other type of display
screen. The
measured downhole characteristics may be compared to existing survey data,
such
as the angular direction and inclination of the primary, first lateral, and/or
second
lateral wellbores 5, 25, 35.
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[0024] As illustrated in Figure 3, the lower portion of the tool string 100
may be
rotated using the orientation assembly 30 in the direction of the first
lateral wellbore
25. In one embodiment, pressurized fluid may be supplied to the orientation
assembly 30 (from the surface via the conveyance member 10) until a
predetermined
amount of pressure actuates the orientation assembly 30 to rotate the lower
portion of
the tool string 100 relative to the longitudinal axis of the upper portion of
the tool string
100. In one embodiment, pressurized fluid may be repeatedly pumped to the
orientation assembly 30 to index the lower portion of the tool string 100
until the sub
and guide assemblies 60, 70 are in alignment with the angular direction of the
first
lateral wellbore 25. The lower portion of the tool string 100 may be
maintained in
each indexed angular position, with or without maintaining fluid circulation
therethrough. In one embodiment, the deflection assembly 50 may also be
actuated
to deflect the lower portion of the tool string 100 in alignment with the
angle of
inclination of the first lateral wellbore 25, limited only by contact with the
inner surface
of the primary wellbore 5. The measurement assembly 40 may continuously
monitor,
measure, and communicate the one or more downhole characteristics described
above as the tool string 100 is oriented and directed into alignment with the
first
lateral wellbore 25.
[0025] In one embodiment, the tool string 100 may be located at a position in
the
primary wellbore ahead of the first junction 23. The tool string 100 may then
be
deflected and/or oriented as described above in the direction of the first
lateral
wellbore 25. The tool string 100 may then be lowered to the location of the
first
junction 23 and directed into the first lateral wellbore 25. The depth that
the tool string
100 is located within the primary wellbore 25 may be continuously monitored
and
measured from the surface and/or downhole and compared to existing survey data
of
the location of the first and/or second junctions 23, 33, and/or the primary
and/or
lateral wellbores 5, 25, 35.
[0026] In one embodiment, the tool string 100 may be located at a position in
the
primary wellbore beyond or below the first junction 23. The tool string 100
may then
be deflected and/or oriented as described above in the direction of the first
lateral
wellbore 25. The tool string 100 may be raised to the location of the first
junction 23
and then directed into the first lateral wellbore 25. The depth that the tool
string 100
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is located within the primary wellbore 25 may be continuously monitored and
measured from the surface and/or downhole and compared to existing survey data
of
the location of the first and/or second junctions 23, 33, and/or the primary
and/or
lateral wellbores 5, 25, 35.
[0027] In one embodiment, the tool string 100 may be located at a position in
the
primary wellbore next to the first junction 23. The tool string 100 may then
be
deflected and/or oriented as described above in the direction of the first
lateral
wellbore 25. In one embodiment, the tool string 100 may be located relative to
the
first junction 23 so that a lower portion of the tool string 100 may be
deflected directly
into the first lateral wellbore 25. The tool string 100 may then be oriented
or further
oriented if necessary and directed into the first lateral wellbore 25. The
depth that the
tool string 100 is located within the primary wellbore 25 may be continuously
monitored and measured from the surface and/or downhole and compared to
existing
survey data of the location of the first and/or second junctions 23, 33,
and/or the
primary and/or lateral wellbores 5, 25, 35.
[0028] As illustrated in Figure 4, when the lower portion of the tool string
100 is
oriented and deflected in the desired position, the tool string 100 may be
moved into
the first lateral wellbore 25. The depth, inclination, and/or direction of the
tool string
100 may be adjusted as it enters the first lateral wellbore 25 by comparing
one or
more measured downhole characteristics to existing survey data of the primary,
first
lateral, and/or second lateral wellbores 5, 25, 35. In this manner, the tool
string 100
may accurately locate, identify, and enter the first lateral wellbore 25.
[0029] As illustrated in Figure 5, the measurement assembly 40 may continue to
measure one or more downhole characteristics as it enters into the first
lateral
wellbore 25, and may communicate the measured downhole characteristics to the
operator at the surface of the primary wellbore 5. The measured downhole
characteristics can be compared to existing survey data to verify entry into
the first
lateral wellbore 25 and/or verify non-entry into the second lateral wellbore
35. For
example, the measured angle of inclination and azimuth of the tool string 100
and the
first lateral wellbore 25 at one or more locations within the first lateral
wellbore 25 can
be compared to existing survey data to verify that the tool string 100 has
entered and
is located in the first lateral wellbore 25. In one embodiment, the true
vertical depth of
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the wellbores and the depth of the wellbores as measured from the surface when
running the tool string 100 into the wellbores may also be used to verify the
location of
the tool string 100 in the primary wellbore 5 and/or first lateral wellbore 25
in a similar
manner. If the measured downhole characteristics correspond with the existing
survey data of the first lateral wellbore 25 at one or more locations within
the first
lateral wellbore 25, then the compared data can be used as a verification that
the tool
string 100 successfully identified and entered the first lateral wellbore 25.
In one
embodiment, the measured downhole characteristics may be compared to existing
survey data of the primary wellbore 5 and/or one or more lateral wellbores
that extend
from the primary wellbore 5 to verify which wellbore the tool string 100
entered and
which wellbore(s) the tool string 100 did not enter. In one embodiment, when
the
measured downhole characteristics and the existing survey data, of a target
wellbore
for example, are significantly different from each other, the compared data
may act as
a verification that the tool string 100 did not enter the target wellbore. The
existing
survey data of the primary and/or lateral wellbores 2, 25, 35 may have been
generated during previous wellbore operations, such as the drilling operations
utilized
to form the wellbores.
[0030] In one embodiment, the tool string 100 may be configured to measure one
or more downhole characteristics at the entrance of the lateral wellbores,
e.g. at a
location just past the wellbore junctions. The tool string 100 may not need to
be
lowered through the entire length of the lateral wellbore to verify entry or
non-entry.
Continuous monitoring and measuring of one or more downhole characteristics as
the
tool string 100 moves through the entrance of the lateral wellbore, and
comparison
with existing survey data may be sufficient to verify entry or non-entry when
the
measured survey data and the existing survey data are substantially coincident
and/or
substantially divergent. In one embodiment, after entry into the first or
second lateral
wellbores 25, 35 has been verified, the lower portion of the tool string 100
may be
returned to an angle substantially coincident with the longitudinal axis of
the upper
portion of the tool string 100.
[0031] In one embodiment, after verification of entry into the desired lateral
wellbore, one or more lateral wellbore operations may be conducted in the
lateral
wellbore using the conveyance member 10 and the tool string 100. In one
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embodiment, a stimulation operation, e.g. pumping acid into the first lateral
wellbore
to stimulate recovery of hydrocarbons, or a remedial work operation, e.g.
fishing out a
stuck tool from the first lateral wellbore, may be performed. Other lateral
wellbore
operations may include jetting, logging, analyzing, cementing, etc. In one
embodiment, the tool string 100 may include one or more components to conduct
the
lateral wellbore operation, such as stimulation tools, fishing tools, repair
tools, etc. In
one embodiment, these additional components may be located at least above the
measuring assembly 40 within the tool string 100. In one embodiment, the tool
string
100 may include one or more control valves, such as a sequencing valve, to
control
actuation of different tool string 100 components. The control valve may be
operable
to control fluid flow through the tool string 100 by diverting fluid into the
annulus
surrounding the tool string 100, based on the flow rate of fluid through the
control
valve. In one embodiment, the control valve may be preset to close at a
specific flow
rate by adjusting the strength of a biasing member, such as a spring, in the
valve. In
this manner, fluid may flow through the control valve at a first flow rate,
and may be
diverted to the annulus at a second flow rate that is greater than or less
than the first
flow rate.
[0032] In one embodiment, the tool string 100 may then be returned to the
first
junction 23 and the measurement assembly 40 may be activated to verify that
the tool
string 100 is located at the first junction 23. The above recited procedures
may then
be repeated to locate, identify, and/or enter the second lateral wellbore 35
using the
tool string 100, as well as verify that the tool string 100 has entered the
second lateral
wellbore 35.
[0033] In one embodiment, a method of locating and entering a lateral
wellbore
that extends from a primary wellbore may include running a tool string into
the primary
wellbore via a conveyance member to a location ahead of, beyond, or next to a
junction at the intersection of the primary and lateral wellbores. The tool
string may
include a connection assembly, an orientation assembly, a measurement
assembly, a
deflection assembly, a sub assembly, and a guide assembly. By
monitoring/measuring the depth that the tool string is run into the primary
wellbore
and comparing the measured depth to existing survey data of at least one of
the
primary and lateral wellbores, the tool string may be located adjacent to the
junction
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between the primary and lateral wellbores. Pressurized fluid may be supplied
to the
deflection assembly via the conveyance member to actuate the deflection
assembly
and thereby deflect a portion of the tool string at an angle relative to a
longitudinal
axis of the tool string. Pressurized fluid may be supplied to the measurement
assembly via the conveyance member to actuate the measurement assembly and
thereby measure the angular direction (azimuth) of the deflected portion of
the tool
string and the angle of inclination of a non-deflected portion of the tool
string. The
measured angular direction of the deflected portion of the tool string may be
compared to a fixed reference point to determine the angular direction that
the
deflected portion of the tool string is facing. The angle of inclination of
the non-
deflected portion of the tool string may correspond to the angle of
inclination of the
wellbore at that location. The measured angular direction and angle of
inclination
may be compared to existing survey data, including an angular direction and
angle of
inclination of the primary and/or lateral wellbores. Pressurized fluid may be
supplied
to the orientation assembly via the conveyance member to actuate the
orientation
assembly and thereby orient the deflected portion of the tool string in the
same
angular direction as the lateral wellbore based on the existing survey data.
Pressurized fluid may again be supplied to the measurement assembly via the
conveyance member to actuate the measurement assembly and thereby re-measure
the angular direction of the deflected portion of the tool string as stated
above to verify
that the deflected portion of the tool string is facing in the direction of
the lateral
wellbore. The tool string may be run in the direction of the lateral wellbore,
while
continuously monitoring/measuring the depth that the tool string is located.
Pressurized fluid may again be supplied to the measurement assembly via the
conveyance member to actuate the measurement assembly and thereby measure the
angular direction of the deflected portion of the tool string, as well as the
angle of
inclination of a non-deflected portion of the tool string, as stated above.
The
measured angular direction, the measured angle of inclination, and/or the
measured
depth can be compared to existing survey data of the primary and/or any
lateral
wellbores to verify that the tool string has entered the desired lateral
wellbore, as
defined by the existing survey data.
[0034] In one embodiment, the procedures described herein with respect
illustrations in Figures 1-5 may be configured into an automated process. A
controller
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may be used to control the operation of the tool string 100 based on a pre-
determined
operational sequence. The controller may be programmed with or in
communication
with a database containing stored existing survey data of a primary wellbore
and one
or more lateral wellbores extending from the primary wellbore. A target
lateral
wellbore may be identified from the existing survey data and the controller
may be
programmed and/or instructed to located, identify, and enter the target
lateral wellbore
using the tool string 100. Using the existing survey data, the controller may
direct
run-in of the tool string 100 to a location near the primary wellbore and the
target
lateral wellbore junction as described above. The controller may actuate the
measuring assembly 40, such as by directing fluid flow through the tool string
100, to
measure one or more downhole characteristics, and may receive and compare the
measured downhole characteristics to the existing survey data to verify that
the tool
string 100 is on the correct path to the target lateral wellbore. The
controller may also
actuate the orientation assembly 30 and/or the deflection assembly 50, such as
by
directing fluid flow through the tool string 100, to position the tool string
100 in the
direction of the target lateral wellbore, based on the measured downhole
characteristics and the existing survey data. Verification of entry into the
target lateral
wellbore may be provided by the controller, as it directs run-in of the tool
string 100
into the lateral wellbore, actuates the orientation assembly 30, the measuring
assembly 40, and the deflection assembly 50 as described above, and compares
measured downhole characteristics to existing survey data at one or more
locations
within the entered lateral wellbore.
[0035] While the foregoing is directed to embodiments of the invention, other
and
further embodiments of the invention may be devised without departing from the
basic
scope thereof, and the scope thereof is determined by the claims that follow.
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