Note: Descriptions are shown in the official language in which they were submitted.
I
GAS INSULATED TUBING
[1] The technical field generally relates to insulated tubing, and more
specifically,
to tubing that is insulated using a gas jacket, and methods of manufacturing
and deploying
the same.
BACKGROUND
[2] In heavy hydrocarbon recovery operations, a heated fluid is injected
into the
ground through an injector well to heat the hydrocarbons. The heating of the
heavy
hydrocarbons, such as bitumen, makes the hydrocarbons less viscous, and
therefore
more mobile, allowing them to be extracted through a producer well. Both the
injector well
and the producer well are typically pre-heated before they are used for
production
processes. In the preheating process and the production process, injected
fluids, such as
steam used in steam-assisted gravity drainage ("SAGD") operations, lose heat
as they
travel down the well to the bitumen-bearing zone. Additional fluids are
typically injected
to make up for this heat loss.
[3] To reduce the need for additional fluid, vacuum insulated tubing
("VIT") is
typically used in the vertical portions of the wells during pre-heating of the
injector and
producer wells and of the injector well during production. The use of VITs in
wells reduces
heat loss to the ground before the heated fluid reaches the bitumen-bearing
zone, thus
requiring less steam or other heated fluid, and therefore making wells more
efficient and
potentially cutting down on pre-heating time. In SAGD, the use of VIT results
in a reduced
amount of steam required to produce an equivalent amount of bitumen, which
means
proportionately less natural gas required to make steam, and ultimately
resulting in
reduced greenhouse gas emissions. Additionally, because not as much steam is
needed
to soften the bitumen, there is also a reduction in water usage.
[4] VIT consists of two rigid, concentric tubing strings welded to one
another at
joints. The rigid tubing strings, typically made out of steel, provide
strength to allow the
VIT to be deployed downhole with minimal damage if the VIT scrapes up against
the well
casing, as well as heat resistance. The thermal joints provide the structural
strength and
connection required for creation and maintenance of a vacuum. Specifically,
the thermal
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joint allows for a strong connection between the tubings and provides for an
absolute seal
to maintain the vacuum between the tubings. The vacuum is typically created
and
maintained between the tubing strings through use of a layer of getter, which
is a chemical
used to absorb gases such as hydrogen. When the air between the tubings is
removed
in this manner, the vacuum layer is created, which makes it difficult for heat
to move across
from the inner tubing string to the outer tubing string by convection. In this
way, VIT
reduces the amount of heat that a well loses to its surroundings above the
bitumen-bearing
zone.
[5] The creation and subsequent maintenance of the vacuum in a VIT are
difficult
and expensive. There is significant work required to create and maintain the
vacuum by
multistage welding, welding and vacuum inspection, pre-stress, forgoing, etc.
Getter is
also an expensive material. Furthermore, the metallic thermal joints
connecting the
tubings act as a highly conductive thermal bridge. As a result of this thermal
bridge,
instead of heat traveling axially through the vacuum, a temperature difference
between
the two tubings will cause heat to flow through the metal welding to the
cooler tubing and
cause overall heat loss to the casing and formation, thus reducing the
effectiveness of the
insulation system. Furthermore, the layer of getter can often be thick, and
can thus act as
an additional thermal bridge when the getter is thick enough to further
connect the inner
and outer tubings. The effectiveness of the heat loss mitigation ability of a
VIT is further
undermined by the fact that in some cases, more than 65% of the heat loss in a
VIT takes
place by radiation.
[6] The use of other thermal insulating materials between the tubings such
as
open cell polyurethane foam, calcium silicate, aerogel, and fibotherm is also
expensive.
Such materials are also prone to damage and dampness if there is a leak
between the
tubings or if there is condensation, which can negatively impact the
effectiveness of the
insulating properties of the materials and can be very difficult or expensive
to replace or
maintain once the tubing is deployed downhole.
[7] Various challenges still exist with regard to insulated tubings and
there is a need
for enhanced technologies.
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SUMMARY
[8] Methods and assemblies relating to insulated tubing are described
herein.
The insulated tubing is easily assembled and manufactured without the creation
of a
vacuum, while providing for effective heat loss mitigation.
[9] In an aspect, an insulated tubing has an inner tubing, a first low
emissivity
coating adjacent the exterior surface of the inner tubing, an outer tubing
positioned around,
and substantially concentric to, the inner tubing so as to create a gas-filled
annulus
between the exterior surface of the inner tubing and the interior surface of
the outer tubing,
and at least one spacer in the annulus connecting the inner tubing and the
outer tubing,
the at least one spacer made out of a resilient, low thermally-conductive
material.
[10] In a further aspect, a method of insulating tubing comprises the steps
of
providing an inner tubing, applying a first low emissivity coating to the
exterior surface of
the inner tubing, providing a plurality of outer tubing wedges, securing at
least one spacer
made out of a low thermally conductive material to at least one of the
exterior surface of
the inner tubing and the interior surface of one of the outer tubing wedges,
positioning the
plurality of outer tubing wedges around the inner tubing to form an outer
tubing concentric
to the inner tubing, the at least one spacer maintaining an annulus between
the inner and
outer tubings, and attaching the outer tubing wedges to one another at wedge
joints.
[11] In a further aspect, a thermal-assisted hydrocarbon production
wellbore
system has a wellbore having at least a substantially vertical portion, a
casing disposed
within the at least substantially vertical portion of the wellbore and an
insulated tubing
having an inner tubing, a first low emissivity coating adjacent the exterior
surface of the
inner tubing, an outer tubing positioned around, and substantially concentric
to, the inner
tubing so as to create a gas-filled annulus between the exterior surface of
the inner tubing
and the interior surface of the outer tubing, and at least one spacer in the
annulus
connecting the inner tubing and the outer tubing, the at least one spacer made
out of a
resilient, low thermally-conductive material, disposed within the
substantially vertical
portion of the wellbore casing.
[12] In a further aspect, a method of using insulated tubing in a wellbore
comprises
the steps of providing a wellbore having at least a substantially vertical
portion, providing
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a casing disposed within the at least substantially vertical portion of the
wellbore, providing
an insulated tubing having an inner tubing, a first low emissivity coating
adjacent the
exterior surface of the inner tubing, an outer tubing positioned around, and
substantially
concentric to, the inner tubing so as to create a gas-filled annulus between
the exterior
surface of the inner tubing and the interior surface of the outer tubing, and
at least one
spacer in the annulus connecting the inner tubing and the outer tubing, the at
least one
spacer made out of a resilient, low thermally-conductive material, lowering
the insulated
tubing into the casing, and securing the insulated tubing in the downhole
position.
[13] The absence of a vacuum allows for simple, low-cost construction of
the
insulated tubing, while the air jacket provides for high-quality, low-
maintenance heat
insulation. This can result in a decreased well start-up period, a reduced
injected heating
fluid-to-oil ratio (such as a steam-to-oil ratio in SAGD), reduced heat loss
in thermal
operations, improved operational efficiency, and reduced GHG emissions.
BRIEF DESCRIPTION OF THE DRAWINGS
[14] Figure 1 is a transverse cross-sectional view of a part of a length of
an
insulated tubing, in an aspect.
[15] Figure 2 is a schematic perspective representation of the insulated
tubing
shown in Figure 1.
[16] Figure 3 is a perspective cutaway view of the insulated tubing shown
in Figure
1.
[17] Figure 4 is a longitudinal sectional view of the insulated tubing
shown in Figure
1.
[18] Figure 5 is a perspective view of two outer tubing segments of an
insulated
tubing, in a further aspect.
[19] Figure 6 is a schematic perspective representation of a cap for the
annulus of
an insulated tubing, in an aspect.
[20] Figure 7 is a cross-sectional view of an insulated tubing, in a
further aspect.
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[21] Figure 8 is a perspective view of the spacer used in the annulus of
the
insulated tubing shown in Figure 1.
[22] Figure 9 is a cross-sectional view of an insulated tubing, in an
aspect, having
a spacer with a corrugated cross-section.
[23] Figure 10 is a front plan view of a spacer for use in the annulus of
an insulated
tubing, in an aspect.
[24] Figure 11 is a cross-sectional view of a plurality of wedges that can
be
assembled to make an outer tubing of an insulated tubing, in an aspect.
[25] Figure 12 is a perspective view of the assembled outer tubing of
Figure 11,
shown as part of an insulated tubing, in an aspect.
[26] Figure 13 is a cross-sectional view of two half shells that can be
assembled to
make an outer tubing of an insulated tubing, in an aspect, shown around an
inner tubing.
[27] Figure 14A is a perspective view of one of the half shells shown in
Figure 13.
[28] Figure 14B is a top plan view of one of the half shells shown in
Figure 13.
[29] Figure 15 is a cross-sectional view of an insulated tubing, in an
aspect, having
a third low emissivity coating disposed between the outer tubing and the first
low emissivity
coating.
[30] Figure 16 is a transverse cross-sectional view of the insulated tubing
shown in
Figure 15.
[31] Figure 17 is a schematic representation of a thermal-assisted
hydrocarbon
production wellbore system, in an aspect.
[32] Figure 18 is a schematic perspective representation of the inner
tubing and
spacer of the insulated tubing shown in Figure 1, with arrows showing the
assembly of the
inner tubing and the spacer together.
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[33] Figure 19A is a schematic representation of an inner tubing and a
spacer of
an insulated tubing, in an aspect, wherein the spacer comprises an open ring,
and with
arrows showing the assembly of the inner tubing and spacer together with the
spacer in
an open ring configuration.
[34] Figure 19B is a schematic representation of the inner tubing and the
spacer
shown in Figure 19A, with the spacer in a closed ring configuration around the
inner tubing.
DETAILED DESCRIPTION
[35] Described is an insulated pipe-in-pipe assembly or tubing, a thermal-
assisted
hydrocarbon production wellbore assembly comprising insulated tubing, a method
of
manufacturing insulated tubing, and a method of installing insulated tubing in
a wellbore.
The insulated tubing can be manufactured without the creation of a vacuum,
which can
eliminate the need for expensive getter material and air-tight welding joints
between inner
and outer tubings that can be difficult to create and maintain, and which
welding joints act
as heat conductive bridges between the inner and outer tubings.
[36] As shown in Figs. 1-4, an insulated tubing 10 has an inner tubing 20,
a first
low emissivity coating 60 adjacent the exterior surface 26 of the inner tubing
20, and an
outer tubing 30 positioned around, and substantially concentric to, the inner
tubing 20 so
as to create an annulus 40 between the exterior surface 26 of the inner tubing
20 and the
interior surface 32 of the outer tubing 30. At least one spacer 50 is disposed
in the annulus
40 connecting the inner tubing 20 and the outer tubing 30, the at least one
spacer 50 made
out of a resilient, low thermally-conductive material. The remainder of the
annular space
40 is filled with a gas 42.
[37] The inner tubing 20 can be a pipe made out of a rigid, high-strength,
heat-
resistant material such as metal. In some aspects, the inner tubing 20 can be
made out
of steel, aluminum, urethane, fibreglass, carbon fibre, or high density
polyethylene or other
thermoplastic material. However, cheaper or lower grade materials can be used
for the
inner tubing 20, as the inner tubing 20 does not need to maintain a vacuum in
the annulus,
thus lowering the potential damage to the insulating capability of the
insulated tubing 10 if
a leak is formed in the inner tubing 20 to allow gas to escape into the
central fluid-
conducting bore or fluid conduit 90 running lengthwise through the inner
tubing 20. The
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inner tubing 20 has a length and diameter suitable to the application for
which it is used.
In an aspect, the insulated tubing 10 can be disposed in a wellbore for the
injection of
fluids downhole, in which case, the inner tubing 20 can have a length shorter
than, or
roughly equal to, the length of a vertical portion of the wellbore. In some
aspects, the inner
tubing 20 can be formed out of multiple segments of inner tubing 20 joined end-
to-end to
define a continuous central bore therethrough. Segments of inner tubing 20 can
be
secured to one another through known means, such as welding or flanged ends
secured
to one another through nuts and bolts. However, it will be understood that in
some
aspects, the inner tubing 20 can be formed out of one continuous piece of
tubing, rather
than through the connection of a plurality of tubing segments.
[38] The
outer tubing 30 can be a pipe with an inner diameter larger than the outer
diameter of the inner tubing 20. The outer tubing 30 can be made out of a
rigid, high-
strength material such as metal. In some aspects, the outer tubing 30 can be
made out
of steel, aluminum, urethane, urethane, fibreglass, carbon fibre, or high
density
polyethylene or other thermoplastic material. The rigid, high-strength nature
of the outer
tubing 30 can be particularly useful in downhole use to minimize damage to the
insulated
tubing 10 when installed, and/or retrieved from, downhole, in the event the
insulated tubing
scrapes up against a casing in the wellbore or the walls of the wellbore
itself. Steel
outer tubing 30 can be particularly useful for downhole applications, given
its high strength.
However, cheaper or lower grade materials than steel can be used for the outer
tubing 30,
as the outer tubing 30 does not need to maintain a vacuum in the annulus, thus
lowering
the potential damage to the insulating capability of the insulated tubing 10
if a leak is
formed in the outer tubing 30. The outer tubing 30 has a length and diameter
suitable to
the application for which it is used. In an aspect, the insulated tubing 10
can be disposed
in a wellbore for the injection of fluids downhole, in which case, the outer
tubing 30 can
have a length shorter than, or roughly equal to, the length of a vertical
portion of the
wellbore. In some aspects, such as that shown in Fig. 5, the outer tubing can
be formed
out of multiple segments of outer tubing 35 joined end-to-end to define a
continuous
central bore therethrough. Segments of outer tubing 35 can be secured to one
another
through known means, such as welding or flanged ends secured to one another
through
nuts and bolts. However, it will be understood that in some aspects, the outer
tubing can
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be formed out of one continuous piece of tubing, rather than through the
connection of a
plurality of outer tubing segments 35.
[39] The inner diameter of the outer tubing 30 will be larger than the
outer diameter
of the inner tubing 20, allowing the inner tubing 20 to fit concentrically
within the outer
tubing 30 while leaving an annulus 40 between the tubings 20, 30. The width of
the
annulus 40 can be sized to suit the application of the insulated tubing 10 and
can depend
on the level of convective heat transfer of the gas 42 filling the annulus 40
and how much
insulating capability is desirable for the insulated tubing 10. In some
instances, the width
of the annulus 40 is designed according to various standards and regulations,
depending
on the application. The length of the inner tubing 20 can be substantially
equal to the
length of the outer tubing 30.
[40] As shown in Fig.2, the inner and outer tubings 20, 30 can be connected
at one
or both ends with a cap 70 to close off the annulus 40 at one or both ends,
while
maintaining the central fluid-conducting bore or fluid conduit 90 through the
inner tubing
20 open at both ends to receive fluid at one end, conduct the fluid along the
length of the
central fluid conduit 90, and allow the fluid to exit at the other end. In
some aspects, the
cap(s) 70 can substantially seal the annulus 40 from the outside elements,
thus
maintaining the gas 42 contained within the annulus 40. The cap 70 can be made
out of
the same material as the inner tubing 20 and/or the outer tubing 30. In some
aspects,
there is no cap provided at all; instead, the length of the inner tubing 20
can be slightly
shorter than the length of the outer tubing 30, to allow for a field weld of
the inner and
outer tubings 20, 30 together adjacent at least one end during the assembly of
the
insulated tubing 20, 30. In yet other aspects, in the absence of a cap, the
inner and outer
tubings 20, 30 can be continuous with one another such that at at least one
end, the inner
and outer tubings 20, 30 form a continuous body to close off the annulus at
the end, while
maintaining the central fluid-conducting bore 90 through the inner tubing 20
open at the
end.
[41] It will be understood that the inner and outer tubings can be
connected together in
other manners than those described above. For example, the inner and outer
tubings
could be manufactured into segments, with each segment comprising a portion of
the outer
tubing welded to a portion of the inner tubing, and with the portion of outer
tubing shorter
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than the portion of inner tubing, such that the portion of inner tubing
protrudes from at least
one end of the portion of outer tubing. The portions of inner tubing
protruding from at least
one end of the portion of outer tubing could have threaded apertures defining
the central
fluid-conducting bore or fluid conduit therethrough, or the threaded portion
could be on the
outside of such portion. The threads on the protruding ends of the inner
tubing portions
could be mated with the protruding ends of other inner tubing portions
directly or using a
common lug between them. Such a configuration would of course mean that the
outer
tubing would be discontinuous along its length and there would be sections of
the insulated
tubing where the inner tubing lacks insulation at its periphery. In other
aspects, mating
flanges or other mating means or devices could be used, rather than threads,
to connect
the inner tubing segments together.
[42] Where a cap 70 is provided, the cap 70 can be made out of a material
with a
low heat transfer coefficient to minimize heat transfer between the inner and
outer tubings
20, 30 through conduction. In some aspects, the cap can be made out of a
resilient
material, such as high-temperature rubber, to provide for effective sealing of
the annulus
40 while accommodating thermal stresses by compression when the inner tubing
20
expands and contracts through gain or loss of heat. In some aspects, the cap
70 at one
or both ends of the annulus 40 can be removable.
[43] In some aspects, such as that shown in Fig. 6, a cap 170 is provided
with a
first sealable intake aperture 172. The first sealable intake aperture 172 can
be releasably
sealed with the use of, for example, a plug 173 that covers or plugs the
aperture 172. In
some aspects, the plug 173 can be made out of a resilient material. In some
aspects,
such as that shown in Fig. 6, the plug 173 can have a threaded member and the
cap 170
can have a corresponding threaded receiver aperture 172 that can receive the
threaded
portion of the plug 173 to thereby seal the aperture 172. This can be useful,
for example,
when the insulated tubing 10 is deployed downhole and it is desired to fill or
refill the gas
42 within the annulus 40. In such a case, the cap 170 adjacent the end of the
insulated
tubing 10 closest to the surface of a vertical portion of the wellbore can be
removed or the
intake aperture 172 can be opened, and the gas 42 can be replenished through
the intake
aperture 172 or directly into the annulus 40, and then the intake aperture 172
can be
closed or the cap 70 replaced. This functionality can allow for easy
maintenance of the
gas layer 42 within the annulus 40.
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[44] In aspects where the annulus is split into an inner annulus 142 and an
outer
annulus 144 by a third low emissivity coating 193, as further described below,
a second
sealable intake aperture 182 can be provided. The second sealable intake
aperture 182
could also have a corresponding plug 183 that allows the second sealable
intake aperture
182 to be closed or sealed. While in aspects where the annulus 40 is not split
into inner
and outer annuli or where the inner and outer annuli 142, 144, contain the
same gas, the
second sealable intake aperture 182 may not be required. Where inner and outer
annuli
142, 144 are present, such as is shown in Fig. 15, this second sealable intake
aperture
182 can allow for independent gas replenishment of the inner annulus 142 from
the outer
annulus 144. Specifically, the first sealable intake aperture 172 can be
disposed near the
periphery of the cap 170 or of the end of the insulated tubing and can be in
fluid
communication with the outer annulus 144, while the second sealable intake
aperture 182
can be disposed nearer to the center of the cap 170 or of the end of the
insulated tubing
and can be in fluid communication with the inner annulus 142. This may be
particularly
useful where the outer annulus 144 and inner annulus 142 contain different
gases or are
kept under different pressures, to allow independent control over each.
[45] Heat losses from the inner tubing 20 by radiation can be reduced, or
in some
cases eliminated, by covering at least a portion of the exterior surface 26 of
the inner
tubing 20 with a first reflective material or first low emissivity coating 60.
In some aspects,
the first low emissivity coating 60 comprises an aluminum foil layer wrapped
around the
inner tubing 20. In some aspects, the first low emissivity coating 60
comprises an
aluminum paint coated onto the exterior surface 26 of the inner tubing 20. For
example,
an aluminum paint having an emissivity of around 0.34 can be selected and
applied to the
inner tubing 20, which would reduce radiation by 66%.
[46] In an aspect, such as that shown in Fig. 7, a second low emissivity
coating 74 can
be provided on the exterior surface 34 of the outer tubing 30 to provide an
additional barrier
to heat loss from the insulating tubing 10 to the environment by radiation.
The second low
emissivity coating 74 can be provided on the exterior surface 34 using an
aluminum paint,
which can be more resistant to being scratched off or completely damaged
during tubing
string placement and removal than a foil layer. In some aspects, a protective
coating 72
can be provided over the second low emissivity coating 74 to help shield it
from damage
as it is deployed downhole. The protective coating 72 will generally be a
clear,
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transparent, or translucent coating that allows light to pass therethrough.
For example,
the protective coating 72 could comprise a hard acrylic or resin layer overtop
of the second
low emissivity coating 74. In some aspects, the protective coating 72 can be
an oil-
repellant coating that can prevent oil from contaminating the second low
emissivity coating
74, particularly where the second low emissivity coating 74 is an aluminum
paint layer. It
will be understood, however, that a protective coating 72 is not necessary, as
the presence
of the protective coating could reduce the effectiveness of the second low
emissivity
coating 74 by hindering light from reflecting off of the second low emissivity
coating 74.
[47] As shown in Figs. 1, 2, and 4, at least one spacer or centralizer 50
is disposed
in the annulus 40 connecting the inner tubing 20 and the outer tubing 30. In
an aspect,
the insulated tubing 10 can comprise a plurality of spacers 50 disposed along
the length
of the insulated tubing 10. The at least one spacer 50 is used to maintain a
minimum
radial distance between the inner and outer tubings 20, 30 by minimizing or
preventing
radial movement between the tubings 20, 30, and thus ensures a minimum gaseous
insulation layer thickness. The at least one spacer 50 can also be used to
hold the inner
and outer tubings 20, 30 in place relative to one another when the at least
one spacer 50
is secured to the inner and outer tubings 20, 30. By supporting the inner
tubing 20
centralized within the outer tubing 30, the at least one spacer 50 can prevent
possible
damage to the first low emissivity coating 60 disposed adjacent the exterior
surface 26 of
the inner tubing 20 and can transfer loads between the inner and outer tubings
20, 30.
The constant thickness of the annulus 40 furthermore provides for
substantially equal
thermal insulation around all of the inner tubing 20.
[48] The at least one spacer 50 has a low thermal conductivity k. In some
aspects,
the at least one spacer 50 has a thermal conductivity k less than 200 W/m.K.
In a further
aspect, the at least one spacer 50 has a thermal conductivity k in the range
of 0.02 W/m.K
to 200 W/m.K. In some cases the at least one spacer 50 has a thermal
conductivity k in
the range of 0.02 W/m.K to 100 W/m.K. The non-thermally conductive material of
the
spacer(s) 50 limits conductive heat transfer between the inner and outer
tubings 20, 30.
[49] The material of the at least one spacer 50 is resilient and can be
volumetrically
compressible to allow the at least one spacer 50 to compress and decompress
between
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the inner and outer tubings 20, 30 as the inner tubing 20 bulges and contracts
into the
annular space 40 with the addition or removal of heat to or from the inner
tubing 20. In
some aspects, the material of the at least one spacer 50 expands with
temperature
increases and retracts with temperature decreases in the inner tubing 20,
rather than
melting or burning against the inner tubing 20. For example, the at least one
spacer 50
can be made out of rubber, which can be resilient, volumetrically
compressible, and also
expands with temperature increases and retracts with temperature decreases. In
a further
aspect, the at least one spacer 50 can be made out of a synthetic rubber.
These properties
of the at least one spacer 50 can allow the at least one spacer 50 to provide
a good seal
in the annulus 40 as the temperature in the inner tubing 20 rises, while also
maintaining
the seal when temperatures are cycled and the temperature is decreased. In
particular,
in the course of using the heat insulated tubing 10, operatively a
considerable temperature
difference can arise between the inner tubing 20 and the outer tubing 30. This
temperature
difference causes the dilatation of the inner tubing 20. As a consequence, the
inner tubing
20 is susceptible to bulging. However, the at least one spacer 50 can undergo
compressive stress to maintain the central position of the inner tubing 20
within the outer
tubing 30 in the operating temperature range of the inner tubing 20. As the
inner tubing
20 cools and returns to its original size, the resiliency of the at least one
spacer 50 can
allow the at least one spacer 50 to move with the retracting inner tubing 20
to maintain a
seal in the annulus between the at least one spacer 50 and the exterior
surface 26 of the
inner tubing 20 and the interior surface 32 of the outer tubing 30.
[50] The resiliency of the at least one spacer 50 can also reduce the
likelihood of
a leak in the seal it provides if the insulated tubing 10 suffers from a
physical impact or
force during deployment of the insulated tubing 10 in, or retrieval from, a
wellbore. Should
a physical impact to the insulated tubing 10, however, result in damage to the
seal
between the inner and outer tubings 20, 30, the result would not necessarily
be
catastrophic, as the annulus 40 does not comprise a vacuum that must be
maintained.
[51] The at least one spacer 50 can be secured and arranged about the
exterior
surface 26 of the inner tubing 20 or the interior surface 32 of the outer
tubing 30, or both.
Where the at least one spacer 50 is secured to the inner or outer tubing 20,
30, a
substantial seal can be formed therebetween. In some aspects, the at least one
spacer
50 is in sealing engagement with the interior surface 32 of the outer tubing
30, and in a
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further aspect, the at least one spacer 50 is secured to the interior surface
32 of the outer
tubing 30 and is compressed between the interior surface 32 of the outer
tubing 30 and
the exterior surface 26 of the inner tubing 26 so as to form a substantial
seal between the
at least one spacer 50 and the exterior surface 26 of the inner tubing 20. In
other aspects,
the at least one spacer 50 is in sealing engagement with the exterior surface
26 of the
inner tubing 20, and in a further aspect, the at least one spacer 50 is
secured to the exterior
surface 26 of the inner tubing 20 and is compressed between the interior
surface 32 of the
outer tubing 30 and the exterior surface 26 of the inner tubing 26 so as to
form a substantial
seal between the at least one spacer 50 and the interior surface of the outer
tubing 30.
The at least one spacer 50 can be secured to the inner and/or outer tubings
20, 30 through
known means such as heat-resistant glue or a strap around the inner tubing 20
that
secures the at least one spacer 50 in sealing engagement against the inner
tubing 20.
[52] In an aspect, thermal joints between the inner and outer tubings 20,
30, such
as joints formed by welding or brazing, which would otherwise form a
conductive heat
bridge between the inner and outer tubings 20, 30, are absent along the length
of the
insulated tubing 10 within the annulus 40. In some aspects, the only physical
connection
between the inner and outer tubings 20, 30 within the annulus 40 along the
length of the
insulated tubing 10 between the ends of the annulus 40 or the caps 70, as
applicable, is
the at least one spacer 50.
[53] The at least one spacer 50 can be configured in several ways. In the
aspect
shown in Figs. 4 and 8, the at least one spacer 50 comprises a ring or a donut-
shaped
base of low thermally-conductive material which, when disposed in the annulus
40
between the inner and outer tubings 20, 30 forms a substantial seal therein
and divides
the annulus 40 into sealed off compartments 44. When a plurality of spacers 50
are
disposed along the length of the annulus 40, several annular compartments 44
can be
formed which are substantially sealed off from one another such that when a
leak is formed
in one compartment 44, the other compartments 44 do not suffer from the same
leak.
[54] In another aspect, such as that shown in Fig. 9, the at least one
spacer 58 is
a ring of low thermally-conductive material with a corrugated cross section
that provides
for an interrupted line contact of the at least one spacer 58 with the
interior surface 32 of
CPST Doc: 274515.1
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14
the outer tubing 30 and an interrupted line contact of the at least one spacer
58 with the
exterior surface 26 of the inner tubing 20 to minimize heat transfer.
[55] In other aspects, such as those shown in Figs. 7 and 10, the at least
one
spacer 51, 52 can comprise radial ribs 52, 53 spaced apart from each other
around the
circumference of the inner tubing 20 and extending between the inner tubing 20
and the
outer tubing 30.
[56] As the insulated tubing 10 lacks a vacuum between the inner and outer
tubings
20, 30, the outer tubing 30 can be assembled on-site, around the inner tubing
20 when
the ends of the inner tubing 20 are connected at both ends or when it is
otherwise
inconvenient to slide the inner tubing 20 into the outer tubing 30, and/or
using thermal
joints. For example, in the aspect shown in Figs. 5, 11, and 12, the outer
tubing is
comprised of a plurality of wedges 38 or panels having an arcuate cross-
section, which,
when assembled together, form a section of the outer tubing. While four wedges
38 are
shown, it will be understood that fewer or more wedges could be used to form
the outer
tubing. The wedges 38 can be secured to one another at a wedge joint 39, which
could
be a thermal joint such as a brazed joint or a thermal weld. In the aspect
shown in Figs.
13 and 14A and 14B, the plurality of wedges comprise two half shells 99, which
together
form a section of the outer tubing 37. For example, the outer tubing 37 could
comprise
two metal sheath half shells. The use of a plurality of wedges 38 or half
shells 99 to form
the outer tubing can be both convenient and cost effective.
[57] The remainder of the annular space 40 around the first low emissivity
coating
60 and the at least one spacer 50 is filled with a gas 42, such as air. The
gas layer 42 can
act as a heat insulator in the annulus 40. The gas 42 can be selected based on
its k-
value, which tend to be very low for gases. In some aspects, the gas 42
comprises air. In
some aspects, the gas 42 comprises at least one of methane, nitrogen, argon,
krypton,
and helium.
[58] Referring to Figs. 15 and 16, in an aspect, a third low emissivity
coating 193
can be disposed between the first low emissivity coating 60 and the outer
tubing 30,
thereby dividing the annulus therebetween into an outer annulus 144 and an
inner annulus
142. In some aspects, the third low emissivity coating 193 can fluidically
seal the inner
CPST Doc: 274515.1
Date Recue/Date Received 2020-07-02
15
annulus 142 from the outer annulus 144. The third low emissivity coating 193
can provide
such a seal at one or both of its ends by sealingly engaging the cap 70, if
any, or an end
of the of the insulated tubing 110 through the use of known means, such as
heat-resistant
glue. The third low emissivity coating 193 is made out of a reflective
material, such as an
aluminum foil.
[59] The third low emissivity coating 193 can be held in place or suspended
between the first low emissivity coating 60 and the outer tubing 30 using
spacers 150
which are divided into inner and outer portions sandwiching the third low
emissivity coating
193 therebetween. In this way, the third low emissivity coating 193 does not
contact the
first low emissivity coating 60 or the outer tubing 30. In some aspects, a
seal between the
inner annulus 142 and the outer annulus 144 can be provided by the third low
emissivity
coating 193 using additional spacers 150 adjacent one or both ends of the
insulated
tubing. The additional spacers 150 can sealingly engage the cap 70, if any, or
an end of
the insulated tubing. In this way, the third low emissivity coating 193 would
be suspended
along the length of the insulated tubing 10, forming a barrier between the
inner and outer
annuli 142, 144, and sealed at at least one end to a spacer 150, which in turn
seals off an
end of the inner and outer annuli 142, 144. However, it will be understood
that the third
low emissivity coating 193 could be suspended between the first low emissivity
coating 60
and the outer tubing 30 using other means, such as by suspending the third low
emissivity
coating 193 within the outer tubing 30 using wires or supports connected to
one or both of
the inner and outer tubings 20, 30. In some aspects, the third low emissivity
coating 193
could be suspended between the first low emissivity coating 60 and the outer
tubing 30 by
attaching the third low emissivity coating 193 to at least one spacer 150
using a heat-
resistant glue or the like. In some aspects, the third low emissivity coating
193 could be
suspended in segments between spacers 150 by attaching each segment of the
third low
emissivity coating 193 to adjacent spacers 150. The use of the third low
emissivity coating
193 can thus provide for two gas layers within the insulated tubing which can
provide a
further barrier to radiative heat loss from the inner tubing 20.
[60] It will be understood that fourth, fifth, and additional low
emissivity coatings
can be provided between the first low emissivity coating 60 and the outer
tubing 30 to
provide for additional gas layers therebetween that can provide further
barriers to radiative
heat loss from the inner tubing 20. The number of additional low emissivity
coatings can
CPST Doc: 274515.1
Date Recue/Date Received 2020-07-02
16
depend on the size of the outer tubing 30 that can accommodate the additional
layers of
low emissivity coating, without the additional layers of low emissivity
coating contacting
one another, the first and third low emissivity coatings, or the inner and
outer tubings 20,
30.
[61] Still in reference to Figs. 15 and 16, the inner annulus 142 contains
a gas 140
therein, while the outer annulus 144 contains another gas 146 therein. In some
aspects,
gases 140 and 146 are one and the same gas. In other aspects, gases 140 and
146 can
be different gases from each other. This could, for example, be useful where a
gas
provides a more significant insulating effect, but is more expensive than
other gases, in
which case, the more expensive gas could be used in the inner annulus 142,
while air or
a less expensive gas, which still provides some insulating capabilities, could
be used in
the outer annulus 142. In some aspects, gases 140 and 146 can be kept under
different
pressures, although in other aspects the pressures could be equal. Differing
pressures of
the gases 140 and 146 can in some cases help with controlling bulging of the
inner tubing
20 during temperature changes. Temperature increases can cause inner tubing 20
to
expand, thus compressing spacers 150 near the periphery of the outer tubing 30
and
releasing compressive stress on spacers 150 near the center of the outer
tubing 30. This
can be managed by maintaining gas 140 at a higher pressure than gas 146, so
that gas
140 applies pressure on the inner tubing 20 to reduce the amount of bulging
that can
occur.
[62] Referring now to Fig. 17, the insulated tubing 10 can be installed in
an
underground wellbore 86. For example, the insulated tubing 10 could be
installed in a
substantially vertical portion 84 of a casing 80 of the underground wellbore
86 used for the
injection of heated fluid for the production of hydrocarbons from an
underground reservoir.
[63] In an aspect, a thermal-assisted hydrocarbon production wellbore
system 82
is provided. The wellbore system 82 has a wellbore 86 having at least a
substantially
vertical portion 84 in which a casing 80 is disposed. The insulated tubing 10
is disposed
in the substantially vertical portion 84 of the casing 80 and spaced from the
casing 80.
[64] The wellbore system 82 is configured to inject heated fluid through
the
insulated tubing 10 so it can exit downhole. The heated fluid could in some
aspects be
CPST Doc: 274515.1
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17
steam used for start-up and production in a SAGD operation, or could be used
for injection
of other heated fluids, such as heated liquid solvents or vaporized solvents,
or both steam
and solvents. In an aspect, the wellbore system 82 is a cyclic steam
stimulation ("CSS")
wellbore system, wherein the substantially vertical portion 84 of the wellbore
86 is the
entirety of the wellbore 86.
[65] In an aspect, a further gas layer is provided in the casing annulus
181. In an
aspect, the casing annulus 181 is filled with methane gas.
[66] A method of manufacturing the insulated tubing 10 is also provided. In
a
method of manufacturing insulated tubing 10, inner tubing 20 is provided. The
exterior
surface 26 of the inner tubing 20 is wrapped in the first low emissivity
coating 60. A plurality
of outer tubing wedges 38 and at least one spacer 50 are provided. The at
least one
spacer 50 is secured to at least one of the exterior surface 26 of the inner
tubing 20 and
the interior surface 32 of one of the outer tubing wedges 38. The plurality of
outer tubing
wedges 38 are positioned around the inner tubing 20 to form an outer tubing 30
concentric
to the inner tubing 20, the at least one spacer 50 maintaining the annulus 40
between the
inner and outer tubings 20, 30. The outer tubing wedges 38 are then sealed
together at
wedge joints 39. The method can be performed in the absence of a vacuum, and
in some
aspects, can involve the step of injecting a gas into the annulus 40.
[67] In some aspects, the step of wrapping the inner tubing 20 in the first
low
emissivity coating 60 involves wrapping a sheet of aluminum foil around the
inner tubing
20. In other aspects, the step of wrapping the inner tubing 20 in the first
low emissivity
coating 60 involves applying a layer of aluminum paint to the exterior surface
26 of the
inner tubing 20. In a further aspect, the method of manufacturing the
insulated tubing 10
involves applying a layer of aluminum paint 74 to the exterior surface 34 of
the outer tubing
30. In yet a further aspect, the method of manufacturing the insulated tubing
10 involves
applying a layer of protective coating 72 overtop of the layer of aluminum
paint 74 applied
to the exterior surface 34 of the outer tubing 30.
[68] In some aspects, the outer tubing wedges comprise two half shells 99
and the
step of sealing the tubing wedges 99 together involves sealing the half shells
at two wedge
joints 39. As will be understood by those skilled in the art, the number of
wedge joints 39
CPST Doc: 274515.1
Date Recue/Date Received 2020-07-02
18
required will equal the number of outer tubing wedges 38 required to together
form the
outer tubing.
[69] In an aspect, the step of sealing the wedges 38 together at wedge
joints 39
can involve thermally joining the wedges 38 together. For example, the wedges
38 can
be sealed together by thermal welding. In another example, the wedges 38 can
be sealed
together using a brazing process. The formation of a thermal joint 39 using a
thermal
process around the inner tubing 20 is possible as it is not necessary to
create a vacuum
between the inner and outer tubings 20, 30.
[70] The method of manufacturing can further involve closing at least one
end of
the annulus 40 with the cap 70. In some aspects, the step of closing the at
least one end
of the annulus 40 comprises welding the inner tubing 20 and outer tubing 30
ends together.
In some aspects, the step of closing the at least one end of the annulus 40
involves
applying a cap 70 made out of resilient material adjacent the at least one end
of the
annulus 40. The step of closing the at least one end of the annulus 40 can
involve sealing
the at least one end of the annulus 40.
[71] Referring to Fig. 18, the at least one spacer 50 can be a ring of low
thermally-
conductive material, in which case, the step of securing the spacer 50 to at
least one of
the exterior surface 26 of the inner tubing 20 and the interior surface 32 of
one of the outer
tubing wedges 38 can involve sliding the spacer 50 axially over the inner
tubing 20, with
the inner tubing 20 fitted within the ring's aperture. If the at least one
spacer is an open
ring, such as is shown in Figs. 19A and B, the step of securing the spacer 57
to at least
one of the exterior surface 26 of the inner tubing 20 and the interior surface
32 of one of
the outer tubing wedges 38 can involve opening the ring 57, bringing it over
the inner
tubing 20, and securing the open ends of the ring 57 together. In some
aspects, the spacer
57 comprises an open ring that has flanges 56 adjacent the open ends, in which
case, the
step of securing the open ends of the ring 57 together can include the use of
nuts and
bolts. In another aspect, the step of securing the open ends together can
include allowing
the open ends to abut one another due to the resiliency of the spacer 57
material and its
propensity to bias its open ends together in a non-stressed state, in
accordance with the
arrows AB shown in Figure 19A.
CPST Doc: 274515.1
Date Recue/Date Received 2020-07-02
19
[72] In an aspect, and referring again to Fig. 11, the step of positioning
the plurality of outer
tubing wedges 38 around the inner tubing 20 to form an outer tubing 35
concentric to the inner
tubing 20 forms only a segment of the outer tubing 35. The method of
manufacturing in this case
would involve the manufacture of a plurality of segments of the outer tubing
35 and the further
step of securing the outer tubing 35 segments end-to-end with one another in
the longitudinal
direction of the insulated tubing, such as through thermal welds or brazing
them together around
the circumference of the outer tubing 35 at the junction between the two outer
tubing 35 segments.
In some aspects, the segments of outer tubing 35 are provided with bevelled
edges to facilitate
thermal welding.
[73] Referring to Fig. 13, in an aspect, the step of positioning the
plurality of outer tubing
wedges or half shells 99 around the inner tubing 20 to form an outer tubing 37
concentric to the
inner tubing 20 with the at least one spacer 55 maintaining the annulus 40
between the inner and
outer tubings 20, 37 can involve compressing the at least one spacer 55
between the inner tubing
20 and the at least one outer tubing wedges 99 to provide for a sealing
engagement of the at least
one spacer 55 with the inner and outer tubings 20, 37.
[74] Referring again to Fig. 15, in an aspect, the method can involve
disposing a third low
emissivity coating 193 between the first low emissivity coating 60 and the
outer tubing 30, thereby
dividing the annulus therebetween into an outer annulus 144 and an inner
annulus 142. The
method can further involve the step of filling or replenishing at least one of
the outer annulus 144
and the inner annulus 142 with a gas. In an aspect, the step of filling or
replenishing at least one
of the outer annulus 144 and the inner annulus 142 with a gas involves filling
or replenishing the
outer annulus 144 with a different gas than the gas in the inner annulus 142.
In some aspects,
the method further involves the step of maintaining the gas in the inner
annulus 142 at a different
pressure than the gas in the outer annulus 144. In yet a further aspect, the
gas in the inner
annulus 142 is maintained at a higher pressure than the gas in the outer
annulus 144.
[75] A method of using the insulated tubing 10 in a wellbore 86 will now be
described. The
method can involve the steps of providing the wellbore 86 having at least a
substantially vertical
portion 84, providing a casing 80 disposed within the at least substantially
vertical portion of the
wellbore 86, and providing the insulated tubing 10. The method further
includes the step of
lowering the insulated tubing 10 into the casing 80 and securing the insulated
tubing 10 in its
downhole position.
CPST Doc: 484690,1
Date recue/Date received 2023-05-05
20
[76] Subsequent steps of the method can involve injecting a heated fluid
into the inner
tubing 20. The heating fluid can comprise steam, liquid solvent, vaporized
solvent, or a
combination of one or more of the foregoing.
[77] This technology disclosed herein can help maintain the temperature of
hot fluids
flowing through the insulated tubing 10 without the use of a vacuum jacket.
[78] The insulated tubing 10 can use a double-tubing layout with the inner
tubing 20
wrapped in a low-emissivity coating 60 and the inner tubing 20 supported
within the outer tubing
30 using a spacer 50 made out of a resilient, low thermally-conductive
material. The annulus 40
between the inner tubing 20 and the outer tubing 30 around the spacers 50 is
filled with a gas that
provides an insulating layer to the inner tubing 20.
[79] The result is a low-cost, but effective way to insulate tubing. The
low-emissivity
coating 60 can reduce radiant heat transfer, while the gas-filled annulus acts
as an effective
insulating layer between the inner tubing 20 and the outer tubing 30. The
resilient, low thermally-
conductive material of the spacers 50 reduces the effect of conductive heat
transfer between the
inner and outer tubing 30, and in some aspects, can act as an annular seal
within the annulus 40.
The resulting insulated tubing 10 can also provide for a reliable insulation
system because broken
seals that may occur, for example, as the insulated tubing 10 is deployed
downhole, are less
consequential because there is no vacuum to maintain. Thus, rather than
replacing the entire
tubing in the event of a leak, the gas-filled annulus can either be refilled
with gas and sealed up,
or where the gas is air, no action at all may be required to fix the leak. In
some aspects disclosed
herein, this reparation is made possible in situ.
[80] The technology disclosed herein also provides for a cheap and easy way
to
manufacture the insulated tubing using a plurality of wedges 38 to form the
outer tubing.
Furthermore, as there is no vacuum to be created and the outer tubing 30 can
be provided in
smaller wedges 39 for transport, the pipeline assembly site can easily be at
the surface of a
wellbore 86.
CPST Doc: 484690,1
Date recue/Date received 2023-05-05
