Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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METHODS AND APPARATUS FOR DOWNHOLE EXTRACTION AND ANALYSIS OF
HEAVY OIL
FIELD OF THE DISCLOSURE
This disclosure relates generally to sampling formation fluid and, more
particularly, to
methods and apparatus for downhole extraction and analysis of heavy oil.
BACKGROUND
Recently, exploration of heavy oil has increased. Venezuela and Canada each
have
reserves of about 170 billion barrels of heavy oil. The viscosity of the heavy
oil is generally
between 1,000 cP and 10,000 cP.
SUMMARY
This summary is provided to introduce a selection of concepts that are further
described
below in the detailed description. This summary is not intended to identify
key or essential
features of the claimed subject matter, nor is it intended to be used as an
aid in limiting the scope
of the claimed subject matter.
An example method disclosed herein includes lowering a viscosity of formation
fluid in a
subterranean formation, flowing the formation fluid from the subterranean
formation into a
downhole tool, and controlling the viscosity of a portion of the formation
fluid in the downhole
tool.
An example downhole tool disclosed herein includes a pressurization device to
draw
formation fluid from a subterranean formation into a flowline of the example
downhole tool.
The example downhole tool also includes a chamber to enclose a portion of the
flowline. The
chamber is to control a viscosity of the formation fluid flowing through the
portion of the
flowline enclosed by the chamber.
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Another example method disclosed herein includes flowing formation fluid
from a subterranean formation into a microfluidic flowline disposed in a
downhole tool and
controlling a viscosity of the formation fluid in a portion of the
microfluidic flowline.
Another example relates to a method, comprising: lowering a viscosity of
formation fluid in a subterranean formation via a heater surrounding an inlet
secured to the
subterranean formation by a packer; flowing the formation fluid from the
subterranean
formation into the inlet; separating a hydrocarbon phase from the formation
fluid; heating the
hydrocarbon phase; and providing a pressure differential to induce the
hydrocarbon phase to
flow into a microfluidic flowline from a flowline coupled to the inlet.
1 0 Another example relates to a downhole tool, comprising: an inlet
for a flowline
comprising a heater to heat a subterranean formation and a packer to secure
the inlet to the
subterranean formation; a pressurization device to draw formation fluid from
the subterranean
formation into the flowline; a hydrophobic filter to separate a hydrocarbon
phase from the
formation fluid; a chamber to enclose at least a portion of a microfluidic
flowline
1 5 communicatively coupled to the flowline; wherein the hydrocarbon phase
is directed to flow
through the portion of the microfluidic flowline; the chamber further
comprising a heater to
heat an interior of the chamber to control a viscosity of the hydrocarbon
phase flowing
through the portion of the microfluidic flowline.
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BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 illustrates an example system in which embodiments of example methods
and
apparatus for downhole extraction and analysis of heavy oil can be
implemented.
FIG. 2 illustrates another example system in which embodiments of the example
methods
and apparatus for downhole extraction and analysis of heavy oil can be
implemented.
FIG. 3 illustrates another example system in which embodiments of the example
methods
and apparatus for downhole extraction and analysis of heavy oil can be
implemented.
FIG. 4 illustrates various components of an example device that can implement
embodiments of the methods and apparatus for downhole extraction and analysis
of heavy oil.
FIG. 5 also illustrates various components of the example device that can
implement
embodiments of the methods and apparatus for downhole extraction and analysis
of heavy oil.
FIG. 6 illustrates example methods for downhole extraction and analysis of
heavy oil in
accordance with one or more embodiments.
DETAILED DESCRIPTION
Certain examples are shown in the above-identified figures and described in
detail below.
In describing these examples, like or identical reference numbers are used to
identify common or
similar elements. The figures are not necessarily to scale and certain
features and certain views
of the figures may be shown exaggerated in scale or in schematic for clarity
and/or conciseness.
Accordingly, while the following describes example systems, persons of
ordinary skill in the art
will readily appreciate that the examples are not the only way to implement
such systems.
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Example methods and apparatus for downhole extraction and analysis of heavy
oil are
disclosed herein. Example methods disclosed herein may include lowering a
viscosity of
formation fluid in a subterranean formation. Lowering the viscosity of the
formation fluid in the
subterranean formation may include heating the subterranean formation. The
example methods
may also include flowing the formation fluid from the subterranean formation
into a downhole
tool and controlling the viscosity of at least a portion of the formation
fluid in the downhole tool.
Flowing the formation fluid into the downhole tool may include controlling a
pressurization
device. The viscosity of at least a portion of the formation fluid in the
downhole tool may be
controlled by separating a hydrocarbon phase from the formation fluid and
heating the
hydrocarbon phase. In some examples, the hydrocarbon phase is separated from
the formation
fluid by flowing the formation fluid through a hydrophobic filter.
FIG. 1 illustrates a wellsite system in which the present invention can be
employed. The
wellsite can be onshore or offshore. In this example system, a borehole 11 is
formed in
subsurface formations by rotary drilling in a manner that is well known.
Embodiments can also
use directional drilling, as will be described hereinafter.
A drill string 12 is suspended within the borehole 11 and has a bottom hole
assembly 100
which includes a drill bit 105 at its lower end. The surface system includes
platform and derrick
assembly 10 positioned over the borehole 11. The assembly 10 includes a rotary
table 16, kelly
17, hook 18 and rotary swivel 19. The drill string 12 is rotated by the rotary
table 16, energized
by means not shown, which engages the kelly 17 at the upper end of the drill
string 12. The drill
string 12 is suspended from the hook 18, attached to a traveling block (also
not shown), through
the kelly 17 and the rotary swivel 19, which permits rotation of the drill
string 12 relative to the
hook 18. As is well known, a top drive system could also be used.
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In the example of this embodiment, the surface system further includes
drilling fluid or
mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the
drilling fluid 26 to the
interior of the drill string 12 via a port in the swivel 19, causing the
drilling fluid 26 to flow
downwardly through the drill string 12 as indicated by the directional arrow
8. The drilling fluid
26 exits the drill string 12 via ports in the drill bit 105, and then
circulates upwardly through the
annulus region between the outside of the drill string and the wall of the
borehole, as indicated
by the directional arrows 9. In this well known manner, the drilling fluid 26
lubricates the drill
bit 105 and carries formation cuttings up to the surface as it is returned to
the pit 27 for
recirculation.
The bottom hole assembly 100 of the illustrated embodiment including a logging-
while-
drilling (LWD) module 120, a measuring-while-drilling (MWD) module 130, a roto-
steerable
system and motor 150, and drill bit 105.
The LWD module 120 is housed in a special type of drill collar, as is known in
the art,
and can contain one or a plurality of known types of logging tools. It will
also be understood
that more than one LWD and/or MWD module can be employed, e.g. as represented
at 120A.
(References, throughout, to a module at the position of 120 can also mean a
module at the
position of 120A as well.) The LWD module 120 includes capabilities for
measuring,
processing, and storing information, as well as for communicating with the
surface equipment.
In the present embodiment, the LWD module 120 includes a fluid sampling
device.
The MWD module 130 is also housed in a special type of drill collar, as is
known in the
art, and can contain one or more devices for measuring characteristics of the
drill string 12 and
drill bit. The MWD tool further includes an apparatus (not shown) for
generating electrical
power to the downhole system. This may include a mud turbine generator powered
by the flow
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of the drilling fluid, it being understood that other power and/or battery
systems may be
employed. In the present embodiment, the MWD module 130 includes one or more
of the
following types of measuring devices: a weight-on-bit measuring device, a
torque measuring
device, a vibration measuring device, a shock measuring device, a stick slip
measuring device, a
direction measuring device, and an inclination measuring device.
FIG. 2 is a simplified diagram of a sampling-while-drilling logging device of
a type
described in U.S. Patent 7,114,562 utilized as
the LWD tool 120 or part of an LWD tool suite 120A. The LWD tool 120 is
provided with a
probe 6 for establishing fluid communication with a formation F and drawing
the fluid 21 into
the tool, as indicated by the arrows. The -probe 6 may be positioned in a
stabilizer blade 23 of the
LWD tool and extended therefrom to engage the borehole wall. The stabilizer
blade 23
comprises one or more blades that are in contact with the borehole wall. Fluid
drawn into the
downhole tool using the probe 6 may be measured to determine, for example,
pretest and/or
pressure parameters. Additionally, the LWD tool 120 may be provided with
devices, such as
sample chambers, for collecting fluid samples for retrieval at the surface.
Backup pistons 81
may also be provided to assist in applying force to push the drilling tool
and/or probe against the
borehole wall.
Referring to Fig. 3, shown is an example wireline tool 300 that may be another
environment in which aspects of the present disclosure may be implemented. The
example
wireline tool 300 is suspended in a wellbore 302 from the lower end of a
multiconductor cable
304 that is spooled on a winch (not shown) at the Earth's surface. At the
surface, the cable 304
is communicatively coupled to an electronics and processing system 306. The
example wireline
tool 300 includes an elongated body 308 that includes a formation tester 314
having a selectively
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extendable probe assembly 316 and a selectively extendable tool anchoring
member 318 that are
arranged on opposite sides of the elongated body 308. Additional components
(e.g., 310) may
also be included in the tool 300.
The extendable probe assembly 316 may selectively seal off or isolate selected
portions
of the wall of the wellbore 302 to fluidly couple to the adjacent formation F
and/or to draw fluid
samples from the formation F. Accordingly, the extendable probe assembly 316
may be
provided with a probe having an embedded plate, as described above. The
formation fluid may
be expelled through a port (not shown) or it may be sent to one or more fluid
collecting chambers
320 and 322. In the illustrated example, the electronics and processing system
306 and/or a
downhole control system are configured to control the extendable probe
assembly 316 and/or the
drawing of a fluid sample from the formation F.
FIG. 4 is a schematic view of an example downhole tool 400 that may be used to
implement the example tools 100 and 120 of FIGS. 1 and 2 and 300 of FIG. 3.
The example
downhole tool 400 includes an elongated body 402 having an inlet 404 fluidly
coupled to a main
flowline 406. A separation block 408 such as, for example, a separation block
described in U.S.
Patent 7,575,681, entitled "Microfluidic Separator" and filed on September 8,
2004
is adjacent the inlet 404 along the main flowline
406. The separation block 408 includes a filter 410 (e.g., a
polytetrafluoroethylene membrane).
In some examples, the filter 410 is hydrophobic and/or microfluidic. A
microfluidic flowline
412 is fluidly coupled to the separation block' 408. The microfluidic flowline
412 passes through
at least one sensor 414, 416, 418, 420 and 422 (e.g., a viscometer, a bubble
point sensor, etc.)
disposed in a chamber 424. In some examples, one or more of the sensors 414,
416, 418, 420
and 422 are microfluidic. The chamber 424 encloses a portion of the
microfluidic flowline 412.
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The chamber 424 includes a heater 426 (e.g., a resistor wire) to control a
temperature of
an interior of the chamber 424. In some examples, the chamber 424 includes a
fan and/or pump
to circulate air inside the chamber 424. The microfluidic flowline 412 extends
through the
chamber 424 and is fluidly coupled to the main flowline 406 downstream of a
backpressure
regulator 428 such as, for example, a check valve or a relief valve disposed
along the main
flowline 406. A pressurization device 430 disposed in the example downhole
tool 400 is fluidly
coupled to an outlet 432 of the main flow line 406. In the example illustrated
in FIG. 4, the
pressurization device 430 is a piston 434 disposed in a cylinder 436. In some
examples, the
cylinder 436 has a volume of about 1 L. In other examples, the pressurization
device 430 is a
pump. The example downhole tool 400 also includes backup pistons 438.
FIG. 5 is a simplified, front view of the example downhole tool 400 of FIG. 4.
The
example downhole tool 400 includes a packer 500 adjacent the inlet 404 and a
heater 502
adjacent the packer 500. The heater 502 is to heat a subterranean formation
via conduction,
ohmic heating, and/or microwave heating.
During operation, the heater 502 may be used to heat a subterranean formation
to lower a
viscosity of the formation fluid in the subterranean formation to a suitable
viscosity (e.g., about
1000 cP). In some examples, the heater 502 heats about 1 L to about 1.5 L of
formation fluid in
the subterranean formation. Once the viscosity of the formation fluid is
lowered to the suitable
viscosity, the pressurization device 430 draws the formation fluid from the
subterranean
formation into the main flowline 406 of the example downhole tool 400. In some
examples, the
pressurization device 430 draws about 100 mL to about 0.5 L of formation fluid
into the main
flowline 406. The pressurization device 430, the backpressure regulator 428
and/or the filter 410
disposed in the separation block 408 cause a pressure differential across the
filter 410 and
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between the main flowline 406 and the microfluidic flowline 412. As a result,
the formation
fluid passes through the filter 410, and a portion of the formation fluid
(e.g., a hydrocarbon phase
of the formation fluid) is separated from the formation fluid by the filter
410 and flows into the
microfluidic flowline 412. A remainder of the formation fluid flows into the
main flowline 406
downstream of the separation block 408, and the separated portion of the
formation fluid (e.g.,
the hydrocarbon phase) is induced to flow into the microfluidic flowline 412
by the pressure
differential.
The separated portion of the formation fluid passes through the one or more
microfluidic
sensors 414, 416, 418, 420 and 422 disposed in the chamber 424 to determine at
least one
characteristic (e.g., viscosity, density, composition, etc.) of the separated
portion of the formation
fluid. The heater 426 heats the interior of the chamber 424 to control the
viscosity of the
separated portion of the formation fluid flowing through the portion of the
microfluidic flowline
412 enclosed by the chamber 424. After the separated portion of the formation
fluid passes
through the one or more microfluidic sensors 414, 416, 418, 420 and 422, the
separated portion
of the formation fluid flows into the main flowline 406 downstream of the
pressure regulator
428. The separated portion and the remainder of the formation fluid are then
drawn into cylinder
436 by the piston 434.
FIG. 6 depicts an example flow diagram representative of processes that may be
implemented using, for example, computer readable instructions. The example
process of FIG. 6
may be performed using a processor, a controller and/or any other suitable
processing device.
For example, the example processes of FIG. 6 may be implemented using coded
instructions
(e.g., computer readable instructions) stored on a tangible computer readable
medium such as a
flash memory, a read-only memory (ROM), and/or a random-access memory (RAM).
As used
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herein, the term tangible computer readable medium is expressly defined to
include any type of
computer readable storage and to exclude propagating signals. The example
process of FIG. 6
may be implemented using coded instructions (e.g., computer readable
instructions) stored on a
non-transitory computer readable medium such as a flash memory, a read-only
memory (ROM),
a random-access memory (RAM), a cache, or any other storage media in which
information is
stored for any duration (e.g., for extended time periods, permanently, brief
instances, for
temporarily buffering, and/or for caching of the information). As used herein,
the term non-
transitory computer readable medium is expressly defined to include any type
of computer
readable medium and to exclude propagating signals.
Some or all of the example process of FIG. 6 may be implemented using any
combination(s) of application specific integrated circuit(s) (ASIC(s)),
programmable logic
device(s) (PLD(s)), field programmable logic device(s) (FPLD(s)), discrete
logic, hardware,
firmware, etc. Also, one or more operations depicted in FIG. 6 may be
implemented manually or
as any combination(s) of any of the foregoing techniques, for example, any
combination of
firmware, software, discrete logic and/or hardware. Further, although the
example process of
FIG. 6 is described with reference to the flow diagram of FIG. 6, other
methods of implementing
the process of FIG. 6 may be employed. For example, the order of execution of
the blocks may
be changed, and/or some of the blocks described may be changed, eliminated,
sub-divided, or
combined. Additionally, one or more of the operations depicted in FIG. 6 may
be performed
sequentially and/or in parallel by, for example, separate processing threads,
processors, devices,
discrete logic, circuits, etc.
FIG. 6 depicts an example process 600 that may be used with the example
downhole tool
400 disclosed herein. The example process 600 begins by lowering a viscosity
of the formation
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fluid in the subterranean formation (block 602). The viscosity of the
formation fluid may be
lowered by heating the subterranean formation. At block 604, it is determined
if the viscosity of
the formation fluid is less than about 1000 cP. However, a different threshold
viscosity value
could be used instead. In some examples, whether the viscosity of the
formation fluid is less
than 1000 cP may be determined by an amount of time the subterranean formation
is heated
(e.g., 45 minutes). If the viscosity of the formation fluid is not less than
1000 cP, then the
example method returns to block 602. If the viscosity of the formation fluid
is less than 1000 cP,
then the formation fluid is flowed from the subterranean formation into the
example downhole
tool 400 (block 606). In some examples, the formation fluid is flowed into the
main flowline
406 by controlling a pressurization device 430 such as the piston 434.
At block 608, a pressure differential is provided between the main flowline
406 and the
microfluidic flowline 412. In some examples, the pressurization device 430,
the backpressure
regulator 428 and/or the filter 410 disposed in the separation block 408
provide the pressure
differential across the filter 410 and between the main flowline 406 and the
microfluidic flowline
412. At block 610, a portion of the formation fluid is separated. For example,
the pressure
differential causes the formation fluid to pass through the filter 410 (e.g.,
a hydrophobic
membrane) in the separation block 408, and the filter 410 separates a portion
of the formation
fluid from a remainder of the formation fluid. In some examples, the portion
of the formation
fluid separated from the remainder of the formation fluid is a hydrocarbon
phase. At block 612,
the separated portion of the formation fluid is flowed into the microfluidic
flowline 412. For
example, the differential pressure induces the separated portion of the
formation fluid to flow
into the microfluidic flowline 412.
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A viscosity of the separated portion of the formation fluid is then controlled
(block 614).
The viscosity of the separated portion of the formation fluid may be
controlled by controlling a
temperature of the separated portion of the formation fluid in the
microfluidic flowline 412. For
example, the heater 426 of the chamber 424 heats the separated portion of the
formation fluid
flowing through the microfluidic flowline 412 enclosed by the chamber 424. At
block 616, the
separated portion of the formation fluid is flowed through at least one
microfluidic sensor 414,
416, 418, 420 and 422 (e.g., a viscometer, a bubble-point sensor, etc.). At
least one characteristic
of the separated portion of the formation fluid is determined by the one or
more sensors 414,
416, 418, 420 and 422 (block 618).
Although a few example embodiments have been described in detail above, those
skilled
in the art will readily appreciate that many modifications are possible in the
example
embodiments without materially departing from this invention. Accordingly, all
such
modifications are intended to be included within the scope of this disclosure
as defined in the
following claims. In the claims, means-plus-function clauses are intended to
cover the structures
described herein as performing the recited function, structural equivalents,
and also equivalent
structures. Thus, although a nail and a screw may not be structural
equivalents in that a nail
employs a cylindrical surface to secure wooden parts together, whereas a screw
employs a
helical surface, in the environment of fastening wooden parts, a nail and a
screw may be
equivalent structures.
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The Abstract at the end of this disclosure is provided to comply with 37
C.F.R. 1.72(b)
to allow the reader to quickly ascertain the nature of the technical
disclosure. It is submitted with
the understanding that it will not be used to interpret or limit the scope or
meaning of the claims.
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