Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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METHOD AND APPARATUS FOR DRILLING A WELLBORE FOR RECOVERY
OF HYDROCARBONS FROM A HYDROCARBON RESERVOIR
TECHNICAL FIELD
[0001] The present application relates to directional drilling of
wellbores in
a hydrocarbon reservoir, such as wellbores for use as injection or production
wells in steam-assisted gravity drainage (SAGD) processes.
BACKGROUND DISCUSSION
[0002] Extensive deposits of viscous hydrocarbons exist around the world,
including large deposits in the northern Alberta oil sands that are not
susceptible
to standard oil well production technologies. The hydrocarbons in such
deposits
are too viscous to flow at commercially relevant rates at the temperatures and
pressures present in the reservoir. For such reservoirs, thermal techniques
may
be utilized to heat the reservoir to mobilize the hydrocarbons and produce the
heated, mobilized hydrocarbons from wells. One such technique for recovering
viscous hydrocarbons using alternating injection of steam and production of
fluid
from a well in a hydrocarbon reservoir is known as cyclic steam stimulation
(CSS). One such technique for utilizing a horizontal well for injecting heated
fluids and producing hydrocarbons is described in U.S. Patent No. 4,116,275,
which also describes some of the problems associated with the production of
mobilized viscous hydrocarbons from horizontal wells.
[0003] One thermal method of recovering viscous hydrocarbons using
spaced horizontal wells is known as steam-assisted gravity drainage (SAGD).
SAGD utilizes gravity in a process that relies on the density difference of
the
mobile fluids to achieve a desirable vertical segregation within the
reservoir.
Various embodiments of the SAGD process are described in Canadian Patent No.
1,304,287 and U.S. Patent No. 4,344,485. In the SAGD process, pressurized
steam is delivered through an upper, horizontal, injection well, into a
viscous
hydrocarbon reservoir while hydrocarbons are produced from a lower,
horizontal,
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production well. The injection and production wells are typically situated in
the
lower portion of the reservoir, with the producer located close to the base of
the
hydrocarbon deposit to collect the hydrocarbons that flow toward the base of
the
deposit.
[0004] The relative locations of the injection and the production wells
are
important in the recovery of hydrocarbons. In particular, it is desirable that
the
production well be parallel and spaced vertically from the injection well. It
is
therefore desirable to control the location and direction of the drill during
drilling
of the injection and production wells.
SUMMARY
[0005] In an aspect of the present disclosure, there is provided a method
of
drilling a wellbore for use in a hydrocarbon recovery operation. The method
includes receiving signals from at least two gyroscopes coupled to a drill
during
drilling of the wellbore, the signals indicative of a change in orientation of
the
gyroscopes, analyzing the signals from the gyroscopes to identify a location
of
the drill relative to a previously identified location, comparing the location
of the
drill to a target location of the drill, and, in response to determining that
the
location of the drill differs from a target location, adjusting a direction of
the drill
based on the location of the drill, wherein drilling of the wellbore is
continuous
during receipt of the signals and analysis of the signals.
[0006] In another aspect, an apparatus for drilling a wellbore for use in
a
hydrocarbon recovery operation is provided. The apparatus includes a drill for
creating the wellbore, a component coupled to the drill, a drill string
coupled to
the component, and at least two gyroscopes coupled to the component and in
communication with an external electronic device for providing signals to the
electronic device during drilling of the wellbore utilizing the drill, the
signals
indicative of a change in orientation of the gyroscopes, such that the drill
is
continuously rotatable to continuously drill the wellbore during receipt of
the
signals and analysis of the signals.
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[0007] Other aspects and features of the present disclosure will become
apparent to those of ordinary skill in the art upon review of the following
description of specific embodiments in conjunction with the accompanying
figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] Embodiments of the present application will now be described, by
way of example only, with reference to the attached Figures, wherein:
[0009] FIG. 1 is a sectional view through a reservoir, illustrating a
SAGD
well pair;
[0010] FIG. 2 is a sectional side view illustrating a SAGD well pair
including
an injection well and a production well;
[0011] FIG. 3 is a graph illustrating recovery factor as a function of
time for
three simulations of injection and production wells;
[0012] FIG. 4 is an end view of a component of an apparatus for drilling
a
wellbore according to an embodiment, showing hidden detail;
[0013] FIG. 5 is side view of the component of FIG. 4, and showing hidden
detail;
[0014] FIG. 6 is sectional side view illustrating an apparatus for
drilling a
wellbore during drilling according to an embodiment;
[0015] FIG. 7 is a flowchart showing a method of drilling a wellbore for
use
in hydrocarbon recovery according to an embodiment;
[0016] FIG. 8 is a perspective view of a component of an apparatus for
drilling a wellbore according to another embodiment, showing hidden detail;
and
[0017] FIG. 9 is a sectional side view illustrating an apparatus for
drilling a
wellbore during drilling, according to another embodiment.
DETAILED DESCRIPTION
[0018] For simplicity and clarity of illustration, reference numerals may
be
repeated among the figures to indicate corresponding or analogous elements.
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Numerous details are set forth to provide an understanding of the examples
described herein. The examples may be practiced without these details. In
other instances, well-known methods, procedures, and components are not
described in detail to avoid obscuring the examples described. The description
is
not to be considered as limited to the scope of the examples described herein.
[0019] The disclosure generally relates to an apparatus and method of
drilling a wellbore for use in a hydrocarbon recovery operation. The method
includes receiving signals from at least two gyroscopes coupled to a drill
during
drilling of the wellbore, the signals indicative of a change in orientation of
the
gyroscopes, analyzing the signals from the gyroscopes to identify a location
of
the drill relative to a previously identified location, comparing the location
of the
drill to a target location of the drill, and, in response to determining that
the
location of the drill differs from a target location, adjusting a direction of
the drill
based on the location of the drill, wherein drilling of the wellbore is
continuous
during receipt of the signals and analysis of the signals.
[0020] Reference is made herein to an injection well and a production
well.
The injection well and the production well may be physically separate wells.
Alternatively, the production well and the injection well may be housed, at
least
partially, in a single physical wellbore, for example, a multilateral well.
The
production well and the injection well may be functionally independent
components that are hydraulically isolated from each other, and housed within
a
single physical wellbore.
[0021] A steam-assisted gravity drainage (SAGD) process may be utilized
for mobilizing viscous hydrocarbons. In the SAGD process, a well pair,
including
a hydrocarbon production well and a steam injection well are utilized. One
example of a well pair is illustrated in FIG. 1 and an example of a
hydrocarbon
production well 100 and injection well 108 is illustrated in FIG. 2. The
hydrocarbon production well 100 includes a generally horizontal segment 102
that extends near the base or bottom 104 of the hydrocarbon reservoir 106. The
injection well 108 also includes a generally horizontal segment 110 that is
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disposed generally parallel to and is spaced generally vertically above the
horizontal segment 102 of the hydrocarbon production well 100.
[0022] During SAGD, steam is injected into the injection well 108 to
mobilize the hydrocarbons and create a steam chamber 112 in the reservoir 106,
around and above the generally horizontal segment 110. In addition to steam
injection into the injection well, light hydrocarbons, such as the C3 through
C10
alkanes, either individually or in combination, may optionally be injected
with the
steam such that the light hydrocarbons function as solvents in aiding the
mobilization of the hydrocarbons. The volume of light hydrocarbons that is
injected is relatively small compared to the volume of steam injected. The
addition of light hydrocarbons is referred to as a solvent aided process
(SAP).
Alternatively, or in addition to the light hydrocarbons, various non-
condensing
gases, such as methane or carbon dioxide, may be injected. Viscous
hydrocarbons in the reservoir are heated and mobilized and the mobilized
hydrocarbons drain under the effect of gravity. The produced emulsion, which
includes the mobilized hydrocarbons along with produced water, is collected in
the generally horizontal segment 102. The emulsion also includes gases such as
steam and production gases from the SAGD process.
[0023] FIG. 3 is a graph illustrating oil recovery factor as a function
of
time for three simulations of injection and production wells utilized in a
SAGD
process. The simulations illustrated include a first simulation of perfectly
aligned,
straight, production and injection wells that are vertically aligned and are
five
meters apart. A second simulation is also illustrated in which the injection
and
production wells are generally 5 meters apart but the injection well meanders
from directly vertically above the production well, and thus is not located
directly
above the production well along the entire length of the injection well. The
third
simulation is similar to the second simulation with the exception that the
meandering is more severe and the toe of the injection well is four meters
laterally spaced from the production well and is three meters vertically
spaced
from the production well. The simulations illustrated in FIG. 3 show that the
vertical alignment with consistent vertical spacing of the injection well and
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production well, as in the first simulation, results in a better recovery
compared
to an injection well that meanders from vertical alignment with the production
well. Closer control of the relative locations of the injection and production
wells
is therefore desirable.
[0024] Views of a component of an apparatus for drilling a wellbore are
shown in FIG. 4 and FIG. 5. The views shown in FIG. 4 and FIG. 5 show hidden
detail for the purpose of the present explanation. In the present example, the
component 402, also referred to as a sub, is generally cylindrical and
includes a
first end 404, which is downhole in relation to a second end 406. Thus, the
first
end 404 is located farther along the well during the drilling operation than
the
second end 406. The component 402 couples the drill that is utilized to drill
the
well, to the drill string 420, which may be drill pipe or coil tubing.
[0025] The component 402 in the present example includes four
gyroscopes 408, 410, 412, 414 housed therein. The gyroscopes 408, 410, 412,
414 are fiber-optic gyroscopes that are each coupled to a fiber-optic wire 416
that runs from the respective gyroscope 408, 410, 412, 414, to the surface,
and
is coupled to an electronic device, such as a computer, that is external to
the
well, for analyzing signals received from the gyroscopes 408, 410, 412, 414 to
determine locations of the gyroscopes 408, 410, 412, 414. The fiber-optic
wires
416 are housed in a protective sheath 418, such as a stainless steel line, to
protect the fiber-optic wires 416 within the drill string 420. The gyroscopes
408,
410, 412, 414 may be coupled to the fiber-optic wires 416 in any suitable
manner.
[0026] Each of the gyroscopes 408, 410, 412, 414 is sealed in a
respective
pocket within the component 402, to inhibit the ingress of fluid into the
pocket
and into contact with the gyroscopes 408, 410, 412, 414.
[0027] Referring now to FIG. 6, a sectional side view of the apparatus
for
drilling a wellbore is shown in the process of drilling the wellbore. The
first end
of the component 402, in which the four gyroscopes 408, 410, 412, 414 (shown
in FIG. 4 and FIG. 5) are housed, is coupled to the drill 602. The drill 602
includes the motor and drill bit. The component 402 does not rotate within the
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well. The drill 602 is therefore coupled to the first end of the component
402, for
example, via a mechanical coupling that facilitates rotation of the drill 602
without rotation of the component 402. Any suitable coupling may be utilized
to
facilitate rotation of the drill 602 without rotation of the component 402.
[0028] The drill string 420 is coupled to the second end 406 of the
component 402. The drill string 420, such as the drill pipe or coil tubing, is
coupled to the component 402 by, for example, threaded connection, welding,
latching, or any other suitable coupling. In the present example, the drill
string
is coil tubing.
[0029] Fluid, such as mud, is pumped through the drill string 420, and
through the motor of the drill 602, to cause rotation of the drill 602 to
create the
wellbore, which may be utilized for a production well, such as the well 100 or
an
injection well, such as the well 108. The fiber-optic wires 416 are protected
from
the fluid, which may be mud, by the protective sheath 418, also referred to as
a
conduit. The fiber-optic wires 416 extend through the drill string 420 to the
electronic device 606 at the surface.
[0030] Accuracy of determining the location of a gyroscope decreases with
the distance of the gyroscope from a reference point, for example, surface or
another point in the wellbore. Utilizing multiple gyroscopes, the accuracy is
increased in comparison to determination of the location utilizing a single
gyroscope. As the drill 602 advances, thus creating the well, the location of
the
drill 602 is determined based on signals from the gyroscopes 408, 410, 412,
414.
The signals from the gyroscopes 408, 410, 412, 414 are repeatedly analyzed to
continuously monitor the location of the drill 602. Thus, the direction of the
drill
602 may also be determined and a steering mechanism utilized to adjust the
direction of the drill 602 when the drill 602 location differs from a target
location.
The direction of the drill 602 may therefore be adjusted based on an
identified
location or direction.
[0031] A method of drilling a wellbore for use in a hydrocarbon recovery
operation is shown in FIG. 7. Some of the processes of the method may be
carried out by software executed by, for example, a computer processor of the
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electronic device 606 located at the surface. Coding of software for carrying
out
such processes of the method is within the scope of a person of ordinary skill
in
the art given the present description. The method may contain additional or
fewer processes than shown and described. Computer-readable code executable
by, for example, the processor to perform parts of the method may be stored in
a computer-readable medium.
[0032] Fluid, such as mud, is pumped through the drill string 420, and
through the motor of the drill 602, to cause rotation of the drill 602 for
drilling
the wellbore. During drilling, and thus during pumping of the mud through the
drill string 420, the electronic device 606 receives and analyzes signals from
the
gyroscopes 408, 410, 412, 414 at 702. The signals are indicative of a change
in
orientation of the gyroscopes and are received at the electronic device via
the
fiber-optic wires 416. Thus, the drilling is continuous while signals are
transmitted from the gyroscopes 408, 410, 412, 414 to the electronic device
606. In other words, the pumping of mud to rotate the drill 602 and rotation
of
the drill 602 continues while the signals are transmitted from the gyroscopes
408, 410, 412, 414 to the electronic device 606 via the fiber-optic wires 416.
[0033] In the example shown in FIG. 6, the apparatus is utilized to drill
a
horizontal wellbore for a horizontal well. The apparatus described herein is
not
limited to drilling wellbores for horizontal wells, however. The apparatus may
also be utilized to drill a wellbore for a vertical well, for example. Thus,
the
present method may be carried out in drilling any wellbore, including a
horizontal
wellbore and a vertical wellbore.
[0034] The signals from the gyroscopes 408, 410, 412, 414 are analyzed to
identify a location of the drill 602 at 704. Alternatively, the signals from
the
gyroscopes may be analyzed to identify a location of a drill assembly as a
whole,
the drill assembly comprising the motor, the drill bit, one or more
components,
and drill string, or an element of the drill assembly other than the drill,
for
example, component 402, or a position along drill string 420. To identify the
location of the drill 602, the signals from each of the gyroscopes 408, 410,
412,
414 are utilized to determine a distance, orientation, and depth of each of
the
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gyroscopes. At 704, a location of the gyroscopes is then determined to
identify a
present location of the drill relative to a previously identified location.
The
previously identified location may be the location of the gyroscopes at the
surface or wellhead. The location that is determined may be determined based
on an average of locations determined utilizing the signals from each of the
gyroscopes.
[0035] The present location that is determined at 704 is then compared to
a target location at 706. For example, a difference between the present
location
of the drill and the target location may be determined. The difference may
then
be compared to a threshold value at 708. In response to determining that the
difference between the present location of the drill and the target location
meets
or exceeds the threshold value, i.e., the present location differs from the
target
location, the method continues at 710 and the direction of the drill 602 is
adjusted utilizing a steering mechanism.
[0036] In response to determining that the difference between the present
location of the drill and the target location does not meet the threshold
value at
708, the method continues at 702.
[0037] Rather than comparing a distance to a threshold value, the
location
that is determined at 704 may be compared to a target zone at 706. When the
location is not within the target zone at 708, the process continues at 710
and
the direction of the drill 602 is adjusted utilizing the steering mechanism.
[0038] As drilling of the wellbore continues, signals are repeatedly
received
at the electronic device 606 and these signals are repeatedly analyzed to
monitor
the drill location during drilling. The drilling is continuous during
transmission of
the signals from the gyroscopes to the electronic device and during receipt of
the
signals and analysis at the electronic device. Thus, drilling is not
interrupted to
determine location of the drill because rotation of the drill continues during
the
transmission of the signals from the gyroscopes to the electronic device via
the
fiber-optic wires.
[0039] In the above-described example, four gyroscopes 408, 410, 412,
414 are utilized in the component 402. Optionally, fewer or a greater number
of
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gyroscopes may be utilized. Additional components may also be utilized. For
example, three components may be utilized, each including four gyroscopes such
that 12 gyroscopes are utilized to determine drill location. The components
may
be coupled together with the component that is furthest downhole coupled to
the
drill and the component that is farthest from the drill coupled to the drill
string
420. The intermediate component may couple the three components together.
Utilizing 12 gyroscopes, the location and direction of the drill may be
determined
with much greater accuracy by comparison to use of a single gyroscope.
[0040] A component of an apparatus for drilling a wellbore according to
another embodiment is shown in FIG. 8. The example shown in FIG. 8 includes
hidden detail for the purpose of the present explanation. The component 802,
also referred to as a sub, is generally cylindrical and includes a first end
804,
which is downhole in relation to a second end 806 when in use. Thus, the first
end 804 is located farther along the well during the drilling operation than
the
second end 806. The component 802 is coupled to the drill that is utilized to
drill
the well.
[0041] A plurality of gyroscopes 808, 30 of which are shown, are housed
in
the component 802. Although 30 gyroscopes are illustrated in this example, any
suitable number of gyroscopes may be utilized. The gyroscopes 808 are coupled
to a processor 822 and an electromagnetic pulser 824. The processor 822 and
the electromagnetic pulser 824 are powered by a power source 826 such as a
battery coupled to a motion capture power generator.
[0042] The gyroscopes 808, processor 822, electromagnetic pulser 824 and
power source 826 are sealed in pockets within the component 802, to inhibit
the
ingress of fluid into the pockets and into contact with the gyroscopes 808,
processor 822, electromagnetic pulser 824 and power source 826.
[0043] In addition to the gyroscopes 808, one or more magnetometers
828, inclinometers 830, and accelerometers 832 may be housed in the
component 802. The one or more magnetometers 828, inclinometers 830, and
accelerometers 832 are also coupled to the processor 822 and are sealed in the
component to inhibit contact of fluids with the one or more magnetometers 828,
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inclinometers 830, and accelerometers 832. The one or more magnetometers
828, inclinometers 830, and accelerometers 832 are utilized to provide further
information regarding the location of the drill.
[0044] The one or more magnetometers 828 are utilized to identify a
magnetic direction, which is a naturally occurring magnetic direction
resulting
from magnetic north and local magnetic rock. The magnetic direction is then
utilized to determine an angular position of the gyroscopes 808 at each time
at
which signals are taken and sent from the gyroscopes 808 to the processor 822.
The processor 822 may then utilize the additional information in calculating
position.
[0045] In addition, one or more accelerometers 832 may be utilized to
provide further information. For example, in each rotation of the component
802, the magnetometers 828 may provide a single location, also referred to as
an anchor location, and the acceleromoters 832 may be utilized for angular
positions between the anchor locations. One or more inclinometers 830 may also
optionally be utilized when rotation stops. The inclinometers 830 provide
further
information during brief periods in which rotation is discontinued.
[0046] Referring now to FIG. 9, a sectional side view of the apparatus
including the component of FIG. 8 is shown in the process of drilling the
wellbore. The first end 804 of the component 802 is coupled to a drill
apparatus,
referred to generally as the drill 902, by a mechanical coupling, for example,
by
threaded connection of the component 802 to a portion of the drill 902. The
drill
902 includes the motor and drill bit. In this example, the component 802
rotates
within the well.
[0047] A drill string 920 is coupled to the second end 806 of the
component
802. The drill string 920, such as the drill pipe or coil tubing, is coupled
to the
component 802 in any suitable manner.
[0048] Fluid, such as mud, is pumped through the drill string 920,
through
the component 802, and through the motor of the drill 902, to cause rotation
of
the drill 902 to create the wellbore, which may be utilized for a production
well,
such as the well 100, or an injection well, such as the well 108. The
gyroscopes
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808, processor 822, electromagnetic pulser 824 and power source 826, shown in
FIG. 8, are sealed within the component 802 and are thus protected from the
fluid, which may be mud.
[0049] During drilling, and thus during pumping of the mud, an electronic
device 906 at the surface receives signals indicative of a location of the
drill 902
via the electromagnetic pulser 824. Thus, the drilling is continuous while
signals
are transmitted to the electronic device 906. In other words, the pumping of
mud to rotate the drill 902 and rotation of the drill 902 continue while the
signals
are transmitted at 702 (as shown in FIG. 7).
[0050] Accuracy of determining the location of a gyroscope decreases with
the distance of the gyroscope from a reference point, for example, surface or
another point in the wellbore. Utilizing multiple gyroscopes, the accuracy is
increased in comparison to determination of the location utilizing a single
gyroscope. As the drill 902 advances, thus creating the well, the location of
the
drill 902 is determined based on signals from the gyroscopes 808.
[0051] In addition, signals from the one or more magnetometers,
inclinometers, and accelerometers are received at the processor 822. The
signals from the gyroscopes 808 as well as signals from, for example,
magnetometers, inclinometers, and accelerometers, are repeatedly received by
the processor 822 and the signals are aggregated or partially analyzed at the
processor 822. A resulting signal is transmitted to the electronic device 906
at
702 for further processing by the electronic device 906. Thus, the signals are
analyzed by one or both of the processor 810 and the electronic device 906 to
continuously monitor the location of the drill 902 at 704.
[0052] A present location of the drill 902 relative to a previously
identified
location is determined at 704. The previously identified location may be the
location of the gyroscopes at the surface or wellhead. The location that is
determined may be determined based on an average of locations determined
utilizing the signals from each of the gyroscopes.
[0053] The present location is compared to a target location at 706.
Thus,
the direction of the drill 902 may also be determined and, in response to
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determining that the present location of the drill 902 differs from the target
location at 708, a steering mechanism is utilized to adjust the direction of
the
drill 902 at 710. The direction of the drill 902 may therefore be adjusted
based
on an identified location or direction.
[0054] In addition, measurement after drilling (MAD) may be carried out
to
acquire data after the completion of drilling. During MAD, additional data is
collected as the drill string is retrieved from the well. The data from MAD
may
be utilized to cross-check or validate the data obtained during the drilling
operation. The drill string is generally not rotated as the drill string is
retrieved
from the well, although rotation may be utilized in response to the drill
string
becoming stuck during retrieval, for example, the drill string may be moved
back
and forth while rotating in order to free the drill string.
[0055] Advantageously, the location and direction of the drill are
determined during drilling, which differs from existing techniques, such as
measurement while drilling (MWD). MWD is a non-continuous process in which
downhole measurements are first stored and later transmitted to surface, for
example, as pressure pulses in the mud system or electro-magnetic (EM)
signals.
Thus, the drilling operation continues as the location and direction are
determined, reducing or eliminating the time during which drilling is stopped
for
measurement purposes. By repeatedly determining drill location and direction
while drilling continues, the progress of the drilling may be monitored and
direction adjustments may be made such that the well generally follows a
desired
path, with little meandering from the path. In addition, the use of more than
one gyroscope increases accuracy of determination of the drill location and
direction to increase accuracy of drilling.
[0056] The above-described embodiments are intended to be examples
only. Alterations, modifications and variations can be effected to the
particular
embodiments by those of skill in the art. The scope of the claims should not
be
limited by the embodiments set forth in the examples, but should be given the
broadest interpretation consistent with the description as a whole.
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