Note: Descriptions are shown in the official language in which they were submitted.
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A CANISTER APPARATUS FOR A MULTIPHASE ELECTRIC SUBMERSIBLE
PUMP
TECHNICAL FIELD
[0001] The present disclosure generally relates to
producing hydrocarbons. In
particular, the disclosure relates to producing a multiphase stream from a
subterranean
reservoir using an electric submersible pump within a canister apparatus.
BACKGROUND
[0002] Oil sands are found in surface reservoirs and in
deeper subterranean
reservoirs. The oil sands in the surface reservoirs can be collected by
surface mining. The
deeper oil sands can be collected by in situ operations that include drilling
one or more
well bores from the surface into or near to the subterranean reservoir. The
deeper oil sands
are typically produced by mobilizing the bitumen within the oil sands and
pumping the
mobilized bitumen up to the surface.
[0003] During in situ operations, bitumen within oil
sands can be mobilized by
decreasing its viscosity through thermal-based, solvent-based processes, and
combinations
thereof. One commercially used in situ thermal-based process is referred to as
steam-
assisted gravity drainage (SAGD). SAGD typically involves drilling a pair of
wellbores.
One wellbore is referred to as the injection wellbore and the other wellbore
is referred to
as the production wellbore. Typically, the paired wellbores have a
substantially vertical
section that extends downward from the surface to about the depth of the
targeted reservoir.
There, the paired wellbores change direction and transition from the
substantially vertical
= section to a substantially horizontal section. The horizontal section can
extend for many
hundreds of meters through or near to a targeted reservoir. Within the
horizontal section,
the injection wellbore is typically positioned a few meters above the
production wellbore.
Generally, the point where the paired wellbores change direction is referred
to as a heel
section and the end of the horizontal section is referred to as the toe
section.
[0004] High-temperature and high-pressure steam is
introduced into the injection
wellbore at the surface. The steam travels down the injection wellbore and
exits the
horizontal section to enter into the targeted reservoir. The steam heats up
the targeted
reservoir which decreases the viscosity of the bitumen therein. The mobilized
bitumen
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then flows downward under gravity into the production wellbore along the
horizontal
section. The production wellbore also collects water that forms as the steam
cools and
condenses, or water that can otherwise be present within or near the targeted
reservoir.
The production well also collects various gases that are produced from the
targeted
reservoir by the steam. Together, the mobilized bitumen, the water, and the
produced
gases that are collected in the production well are referred to as a
multiphase production-
stream (MPS).
[0005] An artificial-lift system is located within the production wellbore
proximate
to the heel section. The artificial-lift system draws the MPS from the toe
towards the heel.
The artificial-lift system is often submersed in a liquid made up of the
mobilized bitumen,
liquid water, and a small proportion of the produced gas within the multiphase
production
stream. Typically, the artificial lift system is an electrical submersible
pump (ESP). The
ESP collects and pumps the liquid up to surface through a production string
that is
positioned within the wellbore.
[0006] As the MPS approaches the heel, the majority of the produced gases
within
the multiphase production stream break out from the liquids as free produced-
gas. The
free produced-gas collects within an annulus between the production string and
a layer of
casing on the inner surface of the production wellbore.
[0007] The annular produced-gas can be collected at the surface with gas-
handling
equipment. However, the collected annular produced-gas can contain corrosive
chemicals
that, over time, can corrode metals within the production wellbore, including
the casing.
Corrosion of the casing can result in casing failure which requires an
extensive work-over
to repair. Additionally, the pressure of the collected annular produced-gas
can fluctuate,
which in turn can fluctuate the level of the liquid in which the ESP is
submersed. When
the level of the liquid drops below the level of the ESP, the ESP can fail due
to gas locking
or overheating.
SUMMARY
[0008] Implementations of the present disclosure relate to an apparatus for
producing a multiphase production-stream (MPS) within an in situ oil-and-gas
production
operation. The in situ operation can be any of a thermal-based operation, a
solvent-based
operation, combinations of thermal-based operations and solvent-based
operations or other
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operations for producing oil-and-gas from an in situ production wellbore. Non-
limiting
examples of thermal-based operations include in situ combustion and steam-
assisted
gravity drainage (SAGD), with SAGD being used herein as but one example.
[0009] The production wellbore has a toe section, a heel section, and a
substantially horizontal-section therebetween with at least the heel section
encased with a
plurality of tubulars. The apparatus is for producing a multiphase production-
stream
(MPS) within the production wellbore. The apparatus includes a string of
production
tubulars that is insertable within the production wellbore for providing fluid
communication between an electrical submersible pump (ESP) and the surface
above. The
string of production tubulars and the plurality of tubulars define an annulus
therebetween.
The apparatus also includes a canister that is insertable within the
production wellbore for
housing the ESP. The canister has a first end that is in fluid communication
with the
substantially horizontal section and a second end that is in fluid
communication with the
string of production tubulars. The second end of the canister also provides a
fluid-tight
seal with one or more channels therethrough for conducting one or more ESP
cables
therethrough. The canister is for receiving at least part or substantially all
of the MPS from
the substantially horizontal section and for directing the received MPS to the
ESP. The
apparatus also includes one or more sealing members for providing a fluid-
tight seal
between the plurality of tubulars of the heel section while avoiding an
accumulation of a
broken-out gas component from the MPS within the annulus.
[0010] Further implementations of the present disclosure relate to a
canister
apparatus for housing an ESP in a production wellbore. The canister apparatus
includes a
first canister and a second canister. The first canister has a substantially
first open end and
a substantially closed second end. The first canister houses the ESP. The
second canister
is sealingly connected to the substantially closed second end of the first
canister. The
second canister houses a sealing member that defines one or more channels for
conducting
a portion of one or more ESP cables (which can include instrumentation cables)
through
the substantially closed second end. The sealing member is also configured to
provide a
fluid-tight seal against the one or more ESP cables for reducing or preventing
an incursion
of fluids into the canister apparatus.
[0011] Further implementations of the present disclosure relate to a method
of
producing a MPS from a production wellbore. The method includes the steps of
collecting
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at least a portion of the MPS within a production wellbore that is proximate
to a source of
the MPS; directing the collected MPS to an artificial lift-system within the
production
wellbore for delivering the MPS up the production wellbore to a surface above;
and
avoiding an accumulation of a broken-out gas component from the MPS within an
annular
portion the production wellbore. The annular portion extends from the surface
above to
proximate the artificial lift-system.
[0012] Implementations of the present disclosure include
a canister apparatus
within which the ESP of a SAGD production wellbore is housed. The canister
collects a
portion of MPS, directs the collected MPS to the ESP which then pumps the
collected
MPS to the surface through the production string. Because the MPS contains all
or
substantially all of the produced gas, the canister apparatus reduces the
amount of
= produced gas within the production-wellbore annulus to low levels or to
substantially
none. The reduced aniount of produced gas in the annulus can avoid some or all
of the
= costs associated with gas-handling surface equipment at each production
well or each well
pad. The reduced amount of produced gas in the annulus can also reduce or
prevent
corrosion induced casing failure and the problems associated with operating
the ESP in
the face of fluctuating levels of the liquid within which the ESP is
submersed.
= BRIEF DESCRIPTION OF THE DRAWINGS
[0013] Features of the present disclosure will become
more apparent in the
following detailed description in which reference is made to the appended
drawings, which
illustrate by way of example only:
[0014] FIG. 1 is an elevation-view schematic illustration
of a typical SAGD paired
wellbore arrangement;
[0015] FIG. 2 is an elevation-view schematic illustration
of one implementation of
the present disclosure for use in an in situ oil-and-gas production wellbore;
[0016] FIG. 3 shows illustrations of some implementations
of the present
disclosure wherein FIG. 3A shows a mid-line, cross-sectional view of one
implementation
of a canister apparatus; FIG. 3B shows a mid-line, cross-sectional view of
another
implementation of a canister apparatus also taken along line 3-3 of FIG. 3C;
and FIG. 3C
shows a cross-sectional view taken along line 3-3 in FIG. 3A;
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[0017] FIG. 4 shows illustrations of some implementations of the present
disclosure wherein FIG. 4A shows a mid-line cross-sectional view through an
example of
a secondary canister; FIG. 4B shows a front view of one example of a swellable-
matrix
arrangement; and FIG. 4C shows another example of a swellable-matrix
arrangement;
[0018] FIG. 5 shows one implementation of the present disclosure with an
elevation view of an example of an ESP and a centralizer arrangement within a
partially
cut-away canister apparatus; and
[0019] FIG. 6 is an elevation-view schematic illustration of another
implementation of the present disclosure for use in an in situ oil-and-gas
production
wellbore.
DETAILED DESCRIPTION
[0020] Implementations of the present disclosure relate to an apparatus
for
producing a multiphase production-stream (MPS) within an in situ oil-and-gas
production
operation. Steam-assisted gravity drainage (SAGD) wellbore is discussed herein
as but
one example of an in situ oil-and-gas production operation. It is understood
that
implementations of the present disclosure can be used in various different
types of in situ
oil-and-gas production operations such as thermal-based operations, solvent-
based
operations, combinations of thermal-based operations and solvent-based
operations and
other in situ production operations. The production wellbore has at least a
toe section, a
heel section, and a substantially horizontal-section therebetween. The
apparatus can
include an electric submersible pump (ESP) that is positionable within the
heel section for
collecting the MPS from the substantially horizontal section and lifting the
MPS to a
surface above the SAGD wellbore. The apparatus also includes a string of
production
tubulars that are positioned within the production wellbore to provide fluid
communication
between the ESP and the surface. The string of production tubulars and the
production
wellbore define an annulus therebetween. One or more sealing members provide a
fluid-
tight seal between the substantially horizontal section and the annulus. The
apparatus
additionally includes a canister that is insertable within the heel section
and is in fluid
communication with the substantially horizontal section, the canister
apparatus for housing
the ESP, for receiving the MPS from the substantially horizontal section and
directing the
received MPS to the ESP.
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[0021] Definitions
[0022] Unless defined otherwise, all technical and
scientific terms used herein
have the same meaning as commonly understood by one of ordinary skill in the
art to
= which this disclosure belongs.
[0023] As used herein, the term "about" refers to an
approximately +/-10%
variation from a given value. It is to be understood that such a variation is
always included
in any given value provided herein, whether or not it is specifically referred
to.
[0024] As used herein, the term "downhole" generally
describes a direction within
a wellbore that is away from the surface and towards the toe. The term
"downhole" can
also be more generally used herein to refer to a position within a wellbore
that is below
the surface.
[0025] As used herein, the term "multiphase production-
stream" or the acronym
"MPS" refer to a stream of fluid that is produced from an underground
reservoir during a
steam-assisted gravity drainage operation. The stream of fluid includes
mobilized
bitumen, water and produced gases.
[0026] As used herein, "uphole" generally describes a
direction within a wellbore
that is towards the surface and away from the toe. Uphole is opposite to
downhole and it
can be used in this context in a reference to a direction within a wellbore or
a position
within a wellbore that is relative to another feature.
[0027] Implementations of the present disclosure will now
be described in
reference to FIG. 1 to FIG. 6.
[0028] FIG. 1 shows a typical pair of SAGD wellbores 10
with an injection
wellbore 12 and a production wellbore 14, as is known in the prior art.
Although not
shown in FIG. 1, it is understood that more than one pair of SAGD wellbores 10
can be
localized together into well pads. At each well pad, multiple pairs of SAGD
wellbores 10
can effectively share infrastructure such as equipment, man power, power-
utility
connections, pipelines, and other resources.
[0029] Each wellbore 12, 14 of the paired wellbore 10 has
a substantially vertical
section 12A, 14A respectively that extends from a surface 16 to a depth that
is about the
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same depth as a targeted subterranean oil-sands reservoir 18. The
substantially vertical
sections 12A, 14A can deviate from a true vertical orientation. At this depth,
each wellbore
12, 14 changes direction or turns in a section referred to herein as a heel
section 12B, 14B
and transitions to a substantially horizontal section 12C, 14C that terminates
in a toe
section 12D, 14D. The substantially horizontal sections 12C, 14C can deviate
from a true
horizontal orientation.
[0030] One or both of the pair of SAGD wellbores 10 can be encased with a
plurality of metal tubulars 20, such as a casing, an intermediate casing, or a
liner. For
simplicity, FIG. 1 only shows the metal tubulars 20 as a cross-section through
each of the
pair of SAGD wellbores 10, it is understood that the metal tubulars 20 extends
around the
entire inner surface of each of the pair of SAGD wellbores 10. From the
surface 16 to the
heel section 12B, 14B, each of the pair of the SAGD wellbores 10 is encased
with a string
of casing 20A that is made up of many interconnected casing-joints. The
wellbores can
be encased through the heel section 12B, 14B with a string of intermediate
casing 20B that
is made up of interconnected intermediate casing joints. One or both of the
string of casing
20A or the string of intermediate casing 20B can be fixed to and sealed
against the open
wellbore by cement (not shown). Within the production wellbore 14 and at a
point
downhole from the heel section 14B, there is a last intermediate casing joint
22. Downhole
from the last intermediate casing joint 22, the substantially horizontal
section 14C can be
encased with a string of liner 20C that is made up of interconnected liner-
joints. The string
of liner 20C extends towards the toe section 14D. It is understood that the
string of casing
20A has a larger outer diameter than the string of intermediate casing 20B
which has a
larger outer diameter than the string of liner 20C. Furthermore, a liner
hanger and packing
element 23 is positioned at the junction between the last intermediate casing
joint 22 and
the string of liner 20C. The specific completion shown in FIG.1 is one non-
limiting
example of a SAGD wellbore completion, and it is understood that various
wellbore
completions can be used.
[0031] To mobilize the bitumen within the targeted reservoir 18, steam is
injected
at the surface 16 into the injection wellbore 12. In some implementations, the
steam can
include other additives of varying percentages by volume, such as solvents or
surfactants.
As shown by the arrows identified with X, the steam travels downhole and exits
the
injection wellbore 12 along the substantially horizontal section 12C and
enters the
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reservoir 18. Generally, the steam forms a chamber (not shown) about the
substantially
horizontal section 12C within the reservoir 18 by warming and mobilizing a
bitumen
component within the reservoir 18. Forming the chamber also produces vapor
that
includes water and liberated gas, which can also be referred to herein as
produced gas.
Over time the mobilized bitumen, water and produced gases flow into the
production
wellbore 14 in the form of a multiphase production-stream (MPS), as shown by
the arrows
identified with Y in FIG. 1.
[0032] Because sand
and other particulate matter can be entrained in the MPS, the
substantially horizontal section 14C typically includes a sand control means
24 for
reducing or preventing an inflow of sand and other particulate matter into the
production
wellbore 14. Sand control means 24 can include for example, layers of gravel
pack or
sand consolidation means and the like that arc positioned adjacent the string
of liner (not
shown). In some instances, the string of liner 20C includes one or more
slotted liner joints
that can reduce or prevent the inflow of sand into the production wellbore 14.
Optionally,
the slotted liner joints can be covered with another filtering means, for
example, such as
steel wool or a wire wrap or other such coverings.
[0033] The
horizontal section 14C can include an internal tubular 26, which can
also be referred to as a tailpipe or production pipe. The tailpipe 26 has a
first end 26A that
is oriented towards the toe section 14D of the production wellbore 14 and a
second end
2613 that is opposite the first end 26A. The tailpipe 26 can have any length
that fits between
the heel section 14B and the toe section 14D. The tailpipe 26 collects the MPS
as it flows
into the wellbore and directs the MPS in a direction from the toe section 14D
towards the
heel section 14B.
[0034] An ESP 21 is
housed within the heel section 1413 to create a differential
pressure within the production wellbore 14 with a lower pressure at the heel
section 1413
relative to the toe section 14D. This differential pressure helps the MPS to
flow towards
the heel section 14B. Proximate to the heel section 14B, some of the produced
gas within
the MPS can break out while the mobilized bitumen, water and any remaining and
entrained produced-gas can remain in a primarily liquid-phase that pools
around and
submerses the ESP 21. In FIG. 1, the broken-out produced gas is represented by
the arrows
indicated with G and the primarily liquid phase is shown as the arrow Z. The
primary
liquid phase can pool at the heel section 14B and can define a surface Zs that
extends
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upward into the substantially horizontal section 14A. In an effort to reduce
drawing any
broken-out produced gas into the ESP 21, an intake is typically positioned
below the ESP
= 21, away from the broken-out gas to draw the primarily liquid-phase into
the ESP 21 for
lifting the primary liquid-phase up to the surface 16 via a production tubing-
string 30. The
production tubing-string 30 can include interconnected tubing joints or it can
include
coiled tubing or any other suitable type of conduit that can withstand the
temperatures and
pressures that occur within the production wellbore 14 during SAGD operations.
[0035] Together, the metal tubulars 20 and the production
string 30 define an
= annulus 32 therebetween. The broken-out produced gas G travels through
the pooled
primary liquid phase and exits the surface Zs to travel up the annulus 32 for
collection and
processing by gas-handling equipment 34 at the surface 16. The gas-handling
equipment
34 can include various coolers, separators, pumps, compressors, and conductive
pipe that
interconnects the coolers, separators, pumps, compressors, and a gas pipeline
system.
Providing and maintaining the gas-handling surface equipment 34 can cost
millions of
dollars per well pad though the operational life of the well pad.
[00361 Implementations of the present disclosure include
a canister apparatus
within which the ESP of an in situ oil-and-gas production wellbore is housed.
Due to a
combination of sealing members about and within the canister apparatus, the
canister
apparatus collects a portion or substantially all of the MPS and directs the
collected MPS
to the ESP. The ESP pumps the collected MPS to the surface through a
production string.
Because the MPS contains all or substantially all of the produced gas, the
canister
apparatus reduces the amount of MPS and the produced gas therein that accesses
the
production-wellbore annulus to low levels or to substantially none. In other
words and as
shown in the non-limiting example of FIG. 2, when using the canister apparatus
of the
present disclosure, there is no Zs because there is little or substantially no
MPS and little
or substantially no broken-out production gas within the annulus 32. The
reduced amount
of produced gas in the annulus can avoid some or all of the costs associated
with gas-
= handling surface equipment at each production well or each well pad. The
reduced amount
of broken-out produced gas in the annulus can also reduce or prevent corrosion
induced
casing failure and the problems'associated with operating the ESP in the face
of fluctuating
levels of the liquid within which the ESP is submersed.
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[0037] The canister apparatus employs a combination of sealing members that
are
positioned between the canister apparatus and the tubulars of the production
well. These
sealing members direct some, most or substantially all of the MPS into the
canister
apparatus (rather than into the annulus 32). The sealing member's direction of
the MPS
into the canister apparatus can reduce the amount of MPS and broken-out
production gas
within the annulus. The combination of sealing members also includes an
elastomer
matrix that is within the canister apparatus. The elastomer matrix is
temperature stable
during thermally-based in situ operations, such as SAGD. In particular, the
elastomer
matrix provides a fluid-tight seal within the canister apparatus, which
reduces or
substantially prevents the leak of MPS fluids from within the canister
apparatus into the
annulus 32 and vice versa. While providing this fluid-tight seal, the
elastomer matrix
provides a channel for ESP cords to pass into the canister apparatus to access
the ESP
therein.
[0038] FIG. 2 shows one implementation of the present disclosure that
relates to a
canister apparatus 100 .for housing an ESP 121. Any features that are the same
or that are
similar between the figures are indicated with the same reference numbers
throughout the
figures. The specific wellbore completion shown in FIG. 2 is of a SAGD
wellbore
completion, which is provided as but one example of an in situ oil-and-gas
wellbore
completion that includes implementations of the present disclosure. It is
understood that
the implementations of the present disclosure can be used with various
wellbore
completions and various other in situ oil-and-gas production operations.
[0039] FIG. 3 shows that the canister apparatus 100 includes a primary
canister
102 and a secondary canister 103. The canister apparatus 100 is positionable
within the
heel section 14B of a production wellbore 14. The primary canister 102 is
configured to
house an ESP 121, a portion of ESP cables 27, and a portion of the production
tubing-
string 30. The primary canister 102 receives at least part of the MPS from the
horizontal
section 14C of the production wellbore 14 (see lines Y in FIG. 2). The primary
canister
102 communicates the received MPS to the ESP 121 for delivery to the surface
16 via the
production tubing-string 30.
[0040] In some implementations of the present disclosure, the primary
canister 102
is generally tubular with a first end 102A, a second end 102B, and a plenum
107 that is
defined therebetween. FIG. 3A shows a portion of the primary canister 102 and
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secondary canister 103 within a section of the metal tubulars 20. When the
primary canister
102 is positioned within the heel section 14B, the first end 102A is downhole
of the second
end 102B. The first end 102A is in fluid communication with the substantially
horizontal
section 14C of the production wellbore 14. In some implementations of the
present
disclosure, the first end 102A is sealingly engaged with an inner surface of
the metal
tubular 20 that is radially adjacent the first end 102A.
[0041] The second end 102B is substantially sealed with at least a portion
of the
secondary canister 103 and at least a portion of the production tubing-string
30 extending
therethrough. Both of the secondary canister 103 and the production tubing-
string 30 are
sealingly connected to the second end 10211 of the primary canister 102.
[0042] The primary canister 102 can be a substantially unitary body or it
can be
made up of at least two modular components. The implementation of the primary
canister
102 that is shown in FIG. 3A includes multiple modular components. For
example, the
primary canister 102 can include a first tubular body 112 that defines the
plenum 107. The
ends of the first tubular body 112 are configured to sealingly connect to a
first connector
114 and a second connector 116. In some implementations of the present
disclosure, these
components of the primary canister 102 can be threadably connected, friction
fit, snap fit
or other types of connections that provide a fluid-tight seal that can
withstand the
temperatures and pressures that occur within the production wellbore 14 during
SAGD
operations. In some implementations of the present disclosure, the first
tubular body 112
is a quick-connector body wherein the first connector 114 is a casing
connector and the
second connector 116 is a quick-connector nut.
[0043] Because both of the secondary canister 103 and the production tubing-
string 30 extend through the second end 102B, neither of the production tubing-
string 30
or the secondary canister 103 are centralized at the second end 10211 (see
FIG. 3B). The
production tubing-string 30 can have a bent shape and be fixed at either or
both ends of
the first tubular body to facilitate the connection with the ESP 121 when the
ESP 21 is also
centralized, as discussed further below.
[0044] The second end 106 can include an uphole wall 122 that defines a
secondary canister aperture 124 and a production tubing-string aperture 126
(see the cross-
sectional view of FIG. 3C). The secondary canister aperture 124 receives the
secondary
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canister 103 therethrough and the production tubing-string aperture 126
receives the
production tubing string 30 therethrough. In some implementations of the
present
disclosure, the uphole wall 122 can be sealingly retained at or near the
second end 106 by
one or more seals (nor shown) that prevent fluid communication across the
uphole wall
122, except through the production tubing-string 30 that extends through and
is sealed
against the production tubing-string aperture 126. Additionally, an
instrumentation line
(not shown) can extend through one or more instrumentation ports 300 that are
defined by
the uphole wall 122. More seals can include but are not limited to friction
fit, snap fit, set
screws, threading or combinations thereof, and can withstand the temperatures
and
pressures that occur downhole during SAGD operations.
[0045] The secondary canister 103 is received through the secondary
canister
aperture 124 that is defined by the uphole wall 122. The secondary canister
103 has a first
end 103A and a second end 103B (see FIG. 4A). The first end 103A is sealingly
connected
to the uphole wall 122 at or proximate to the secondary canister aperture 124.
The
secondary canister 103 is configured to house a portion of the ESP cables 27.
As shown
in FIG. 3C, the ESP cables can be an armoured ESP electrical cable 27A and
optionally,
any sensor lines 27B that can provide information to the surface 16 such as
pressure and
temperature information about the ESP 121 and/or the fluids that are entering
the ESP 121.
The ESP electrical cable 27A can include one or more individual electrical-
conductor
cables. In some implementations of the present disclosure, the ESP electrical
cable 27A
includes three individual electrical-conductor cables.
[0046] Referring now to FIG. 4, FIG 4A shows a mid-line, cross-sectional
view
through an example of a secondary canister, for example the implementations of
the
secondary canister 103 shown in FIG. 3A, FIG. 3B and FIG. 3C. FIG. 4B shows a
front
view of one example of a sealing member with a swellable-matrix arrangement,
for
example a front view of the sealing member 150 shown in FIG. 4A. and FIG. 4C
shows
another implementation of the sealing member 150.
[0047] As shown in FIG. 4A, the secondary canister 103 has can have an
internally
extending shoulder at the first end 103A for abuttingly receiving a sealing
member 150
that is temperature stable during SAGD operations. For example, in a SAGD
production
wellbore 12, the temperatures can rise to between about 200 C to about 300 C
and the
sealing member 150 does not substantially degrade or deteriorate when exposed
to these
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temperature ranges. In some implementations of the present disclosure, the
sealing
member 150 provides a fluid-tight seal to reduce or prevent the incursion of
fluids into the
secondary canister 103. In some implementations of the present disclosure, the
sealing
member 150 is a swellable elastomer matrix which is also referred to herein as
the
elastomer member 150. The elastomer member 150 can deform by absorbing fluids
and
swelling. In other implementations of the present disclosure, the elastomer
member 150
can be deformed when compressed by a compression nut (not shown). The
elastomer
member 150 can be a single element or alternatively, multiple elements that
are inserted
into the secondary canister 103. FIG. 4 shows some implementations of the
present
disclosure wherein the elastomer member 150 is provided as a two-piece
clamshell
arrangement. As shown in FIG. 4A, the elastomer member 150 defines one or more
channels 152 that extend longitudinally through the secondary canister 103
along or near
the midline of the elastomer member 150. As shown in FIG. 4B, the one or more
channels
152 can include a first channel 152A that allows the ESP electrical cable 27A
to pass
through the elastomer member 150 within the secondary canister 103.
Optionally, the
sensor line 27B passes through a second channel 152B. At or near the first end
103A of
the secondary canister 103, the elastomer member 150 abuts against the
shoulder and a top
cap can be secured to the second end 103B of the secondary canister 103 to
retain the
elastomer member 150 within the secondary canister 103.
10048] In the
implementations of the present disclosure where the elastomer
member 150 is a swellable matrix, when the elastomer member 150 contacts
fluids it
increases in volume within the secondary canister 103 and provides a fluid-
tight seal
around the ESP cables 27 along their respective channels 152A. In other
implementations
of the present disclosure, the elastomer member 150 can be compressed by a
compression
nut (not shown) to form the fluid-tight seal around the ESP cables 27. The
fluid-tight seal
prevents the incursion of any fluids from uphole of the secondary canister 103
into the
secondary canister 103 while providing the channels 152 for the ESP cables 27
to pass
through and physically connect with the ESP 121 that is further downhole
within the
canister apparatus 100. If wellbore fluids such as any conductive liquid or
gas were to
pass through the secondary canister 103, the ESP 121 could be subject to an
increased
susceptibility of gas locking.
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[0049] In some implementations of the present disclosure, the ESP
electrical cable
27A is an armoured electrical cable. The inventors have observed that by
drilling a pilot
hole through the armour, a sealing fluid can be introduced into the armour to
provide
further sealing against the movement of any fluids that are within the armour
towards the
ESP 121. In some implementations of the present disclosure, the sealing fluid
can be a
polymerizable fluid such as an epoxy that can be injected into the pilot hole
and then set,
or polymerized, within the armour. In other implementations of the present
disclosure, the
sealing fluid can be an expandable fluid that can be injected into the pilot
hole and then
expand to provide a fluid tight seal within the armour. FIG. 4B shows one
example of an
arrangement of the channels 152 that is suitable for an armoured ESP
electrical cable 27A
and a sensor cable 27B.
[0050] In other implementations of the present disclosure, a portion of the
armour
is stripped off the ESP electrical cable 27A to reveal the individual
electrical-conductor
cables therein for the section of the ESP electrical cable 27A that will be
housed within
the canister apparatus 100. In these implementations, the first channel 152A
has a cross-
sectional shape that accommodates the number and shape of individual
electrical-
conductor cables. FIG. 4C shows an example of the first channel 152A shaped to
accommodate three individual electrical-conductor cables, as is typical for
ESP electrical
=
cables 27A.
[0051] FIG. 5 shows a schematic example of the ESP 121 that is positioned
within
the primary canister 102. The ESP 121 has a first end 121A and a second end
121B that
is opposite the first end 121A. The first end 121A is proximate to the first
end 102A of
the primary canister 102. FIG. 5 shows an optional feature of a centralizer
160. The
centralizer 160 can include collars 162A, and 16213 for securing the
centralizer 160 about
the outer surface of the ESP 121 for example by hinges and connectors.
Optionally,
multiple centralizers 160 can be used, such as the four centralizers shown in
FIG. 5. The
centralizer 160 can also include at least one rib 164 that extends radially
outwardly from
the centralizer 160. The at least one rib 164 can also be referred to as a
bowspring. The
at least one rib 164 engages an inner surface 170 of the primary canister 102
for supporting
the ESP 121 off of the inner surface 170. In some implementations of the
present
disclosure, the centralizer 160 includes enough ribs 164 to support the ESP
121 in a
substantially centralized position within the primary canister 102.
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[0052] As shown in FIG. 5, the ESP 121 includes the following components: a
motor section 123, a sealing section 125, an intake section 127, and a pumping
section
129. The motor section 123 includes a receptacle for receiving the ESP cables
27A and
27B. The ESP electrical cable 27A provides electrical power to the motor
section 123.
While not shown, a rotatable shaft is operably coupled to the motor section
123 and the
pumping section 129. The sealing section 125 is adjacent the motor section
123. The
sealing section 125 seals about the rotatable shaft and prevents the
communication of
fluids from the intake section 127 into the motor section 123. The intake
section 127
receives the MPS within the primary canister 102 (as shown by arrows Z in FIG.
5). Due
to the pumping action of the pumping section 129, the intake section 127 can
receive MPS
about the entire outer circumference of the ESP 121 or alternatively, just
sections of the
outer circumference of the ESP 121. The intake section 127 directs the
received MPS
towards the pumping section 129 which pumps the received MPS towards the
production
tubing 30 (as shown by arrow Zp in FIG. 5).
[0053] The pumping section 129 can include any type of pumping stage that
can
deliver the received MPS to the surface through the production tubing-string
30 and handle
any produced gas that is entrained in the received MPS while reducing the
incidence of
gas locking of the ESP 121. In some implementations of the present disclosure,
the
pumping section 129 includes a centrifugal gas-handling pumping stage. The
centrifugal
gas-handling stage has=vanes that are designed to reduce the development of
low pressure
areas and blades that can break the produced gas within the received MPS into
smaller
bubbles. Both of these features can increase the homogeneity of the received
MPS, which
can reduce the incidence of gas locking of the ESP 121. In other
implementations of the
present disclosure, the pumping section 129 includes a helicoaxial gas-
handling pumping
stage. The helicoaxial gas-handling pumping stage includes both an axial
compressor and
a centrifugal pump with a boosting pressure that is sufficiently high to
compress the
produced gas within the received MPS, which also can reduce the incidence of
gas locking
of the ESP 121. In further implementations of the present disclosure, the
pumping section
129 can be part of a progressive cavity pump.
[0054] Referring again to FIG. 2, in order to facilitate movement of the
MPS from
the tail pipe 26 into the primary canister 102, the production wellbore 14 can
include a
sealing assembly 200 that prevents the communication of MPS or any component
thereof
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across any individual sealing member of the sealing assembly 200. The
individual sealing
members can be an inflatable packer, a swellable packer, a mechanically
actuated packer,
a diverter, and the like.
[0055] As shown in FIG. 2, the sealing member assembly 200 can include a
first
sealing member 202 that provides a fluid seal formed an outer surface of the
tailpipe 26
and an inner surface of the string of liner 20C. The first sealing member 202
can be
positioned proximate the second end 26B of the tailpipe 26 for preventing the
flow of MPS
therepast. The first sealing member 202 can help direct the MPS within the
production
wellbore towards the toe section 14D and into the first end 26A of the
tailpipe 26. A
second sealing member 204 can provide a fluid-tight seal against an outer
surface of the
primary canister 102 and an inner surface of the string of liner 20C. The
second sealing
member 204 can be positioned proximate to the first end 102A of the primary
canister 102.
The second sealing member 204 can help direct the MPS from the tailpipe 26
into the first
end 102A of the primary canister 102.
[0056] In some implementations of the present disclosure, at least one of
the first
end 102A of the primary canister 102 and the tailpipe 26 can be centralized
within the
production wellbore 14 by one or more centralizers 210.
[0057] As shown in FIG. 2, in some implementations of the present
disclosure, the
first end 102A of the primary canister 102 can have an extension that narrows
to a smaller
outer diameter as it ex.tends towards the toe section 14D. Optionally, the
smaller outer
diameter of the extension is substantially the same size as the outer diameter
of the tailpipe
26. In a further optional implementation of the present disclosure, the
extension 106A is
directly connected to the tailpipe 26, as shown in FIG. 6.
[0058] FIG. 3B shows another implementation of the present disclosure
wherein
the production tubing-string 30 sealingly terminates at the upper wall 122 by
a connection
136 at or about the production tubing-string aperture 126. The connection 136
can be a
friction fit, set screws, threading, or combinations thereof and can withstand
the
temperatures and pressures that occur downhole during SAGD operations. Within
the
primary canister 102, there is a production conduit 130 that is in fluid
communication with
the production tubing-string 30 through the connection 136. The production
conduit 130
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extends from the connection 136 to the ESP 121. The production conduit 130
provides a
conduit for communicating the MPS from the ESP 121 to the production tubing-
string 30.
[0059] In some implementations of the present disclosure, the tailpipe 26
is not
present. In these implementations, the MPS flows into the horizontal section
14C and then
the MPS flows towards the primary canister 102. The second sealing member 204
directs
the MPS flow into the primary canister 102.
[0060] In operation, the first end 102A of the primary canister 102
receives some
or substantially all of the MPS from the horizontal section 14C of the
production wellbore
14. Some produced gas within the MPS can break-out in a region of the
production
wellbore 14 that is between the first and second sealing members 202, 204.
Because this
region is bookended by the sealing members 202, 204, any produced gas that
does break
out can form a bubble in the upper portion of this region. Once this bubble
has occupied
as much volume within the region that is available, at the downhole pressures
and
temperatures that occur during SAGD operations, the bubble will equilibrate
and possibly
prevent the break-out of any further produced gas.
[0061] The received MPS within the primary canister 102 can flow into the
intake
section 127 of the ESP 121. The flow of received MPS into the intake section
127 can be
enhanced by operation of the pumping section 129. The MPS then flows through
the
pumping section 129 into the production tubing-string 30 for delivery to the
surface 16.
Because the produced gas within the MPS is mostly contained within the
received MPS
within the primary canister 102, there is substantially no produced gas within
the annulus
32. The absence of produced gas within the annulus 32 reduces the corrosion of
the metal
tubulars 20 within the annulus 32, such as the casing and intermediate casing
20A, 20B.
Furthermore, the reduced amount or lack of produced gas within the annulus 32
reduces
or removes the requirement of surface equipment 34 for handling the produced
gas within
the annulus 32.
[0062] If the elastomer member 150 is a swellable matrix, then the
elastomer
member 150 can be deformed by contacting it with a liquid prior to when the
elastomer
member 150 is secured within the secondary canister 103. Alternatively, the
elastomer
member 150 can deform when the apparatus is installed downhole and the
elastomer
member 150 comes into contact with a liquid. If the elastomer member 150 is
deformed
17
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by compression, then the compression nut can be tightened to compress the
elastomer
member 150 when the elastomer member 150 is secured within the secondary
canister 103
prior to downhole installation.
[0063] In some implementations of the present disclosure, an annular gas
other
than a produced gas, can be introduced into the annulus 32 from the surface
16. For
example nitrogen, or another suitable inert gas, can be introduced into the
annulus 32 as a
blanket gas.
[0064] In the implementation of the present disclosure shown in FIG. 6, a
blanket
gas BG and/or steam S and/or corrosion inhibited fluid can be introduced into
the annulus
32 from the surface 16. In these implementations, because the tailpipe 26 is
directly
connected to the first end 102A of the primary canister 102, the annulus 32
can extend past
the heel section 14B and into the horizontal section 14C. The steam S can be
of sufficient
quality and pressure that it can pass through the MPS liquid surface Zs and
exit the
production wellbore 14 along the horizontal section 14C. The steam S or
blanket gas BG
can be useful for maintaining a desired downhole temperature and for
optimizing the
mobility of the bitumen within the MPS.
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