Note: Descriptions are shown in the official language in which they were submitted.
SYSTEM AND METHOD FOR RECOVERING HEAT FROM A HEATED FIRST WELL AND
USING THE RECOVERED HEAT IN A PROCESS AT ONE OR MORE SECOND WELLS
TECHNICAL FIELD
[0001] The following relates to systems and methods for recovering heat
from a heated first
well and using the recovered heat in a process at one or more second wells.
BACKGROUND
[0002] Bitumen is known to be considerably viscous, does not flow like
conventional crude
oil, and can be present in an oil sand reservoir. As such, bitumen is
recovered using what are
considered non-conventional methods. For example, bitumen reservoirs are
typically extracted
from a geographical area using either surface mining techniques, wherein
overburden is
removed to access the underlying pay (e.g., oil sand ore-containing bitumen)
and transported to
an extraction facility; or using in situ techniques, wherein subsurface
formations (containing the
pay) are heated such that the bitumen is caused to flow into one or more wells
drilled into the
pay while leaving formation rock in the reservoir in place. Both surface
mining and in situ
processes produce a bitumen product that is subsequently sent to an upgrading
and refining
facility, to be refined into one or more petroleum products.
[0003] Bitumen reservoirs that are too deep to feasibly permit bitumen
recovery by mining
techniques are typically accessed by drilling wellbores into the hydrocarbon
bearing formation
(i.e. the pay) and implementing an in situ technology. There are various in
situ technologies
available, such as steam driven based techniques (e.g., Steam Assisted Gravity
Drainage
(SAGD) and Cyclic Steam Stimulation (CSS)), steam-solvent co-injection
techniques (e.g.,
expanding solvent-SAGD (ES-SAGD)) and waterless solvent-based techniques
(e.g., N-Solv,
Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH) and
other
electromagnetically-assisted solvent extraction (EASE) technologies and
methods. In a typical
implementation of the SAGD method, a pair of horizontally oriented wells are
drilled into the
bitumen reservoir, such that the pair of horizontal wells are vertically
aligned with respect to
each other and separated by a relatively small distance, typically in the
order of several meters.
The well installed closer to the surface and above the other well is generally
referred to as an
injector well, and the well positioned below the injector well is referred to
as a producer well.
The injector well and the producer well are then connected to various
equipment installed at a
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surface site. Similar well configurations can be used for the above-mentioned
solvent-based
recovery processes.
[0004] Prior to extracting bitumen from the reservoir using the SAGD
method, "start-up" of
the wells is generally required. As used herein, "start-up" generally refers
to the step of
achieving or enabling fluid communication between two or more wells situated
in a bitumen
reservoir. In a typical SAGD implementation, start-up is conventionally
achieved by injecting and
circulating steam through both the injector well and the producer well. The
steam is circulated
through both wells until the region between the injector well and the producer
well (i.e. the inter-
well region) has been sufficiently heated to mobilize the bitumen and
therefore allow fluid
communication between the wells. Once start-up has been achieved, production
can begin.
During production, steam is typically introduced into the bitumen reservoir
through the injector
well which, in the process of condensing, further heats up the surrounding
bitumen to lower its
viscosity. The heated bitumen and the condensate then flows towards the
producer well due to
gravity, and are then pumped to the surface through the producer well.
[0005] Towards the end of the SAGD lifecycle is commonly referred to as a
"wind-down"
stage when the wells are near abandonment. Abandonment of a well can include
various
interventions, also known as workovers, including gas source identification,
cement squeeze,
and installation of bridge plugs to isolate well sections. However, such
abandonment of a well
can be considered challenging and expensive when considering the well
economics at or near
the end of well life, particularly in hot and sour wells. For example, tools
to identify gas sources
are available, but can be expensive to use if the well is too hot under sour
conditions (i.e. with
the presence of H2S), wherein the components of the tools are not rated for
high-temperature
service. This requires either waiting for the well to cool in order to allow
for the use of less
expensive tools, or incurring the cost of the more expensive tools.
[0006] It is an object of the following to address at least one of the
above challenges or
disadvantages.
SUMMARY
[0007] In one aspect, there is provided a method of obtaining heat for use
in an oil recovery
process, the method comprising: circulating a fluid in a first well that is
ready or near
abandonment to exchange energy from the first well and surrounding formation
to the fluid in
order to heat the fluid; and providing the heated fluid to a process being
applied at one or more
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second wells, the process comprising circulating or injecting the heated fluid
at the one or more
second wells.
[0008] In another aspect, there is provided a system for obtaining heat for
use in an oil
recovery process, the system comprising: a closed-loop circuit positioned in a
first well that is
ready or near abandonment, for circulating a fluid in the first well to
exchange energy from the
first well and surrounding formation to the fluid in order to heat the fluid,
and for providing the
heated fluid to a process being applied at one or more second wells, the
process comprising
circulating or injecting the heated fluid at the one or more second wells.
[0009] The methods and systems can be used to recover heat from a heated
well/formation,
and use the recovered heat in a process at one or more other wells. In an
implementation, the
system is used when the heated well is at or near the end of its lifecycle,
when the formation
surrounding the heated well has increased in temperature over time as a result
of an oil
recovery process having been implemented at that well. The heat contained in
the formation
surrounding the well can therefore be considered "lost" or otherwise unused
and available for
recovery and reuse in another process. The heat can be recovered by
circulating a cold (or
cooled or cooler) heat transfer fluid at the heated well (i.e. a heat transfer
fluid that is at a cooler
temperature than the first well or formation). The relatively cooler heat
transfer fluid is then
effective to create a heat exchange mechanism with the heated formation to
increase the
temperature of the heat transfer fluid for subsequent use.
[0010] The energy from a heated well/formation can be used to pre-condition
various
processes, such as: heating solvent streams for solvent recovery processes,
achieving or
contributing to start-up processes at new SAGD wells, or activating chemical
technologies that
require heat.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] Embodiments will now be described with reference to the appended
drawings
wherein:
[0012] FIG. 1 is a schematic diagram of a heat reclamation system for
providing a heated
fluid to a heated fluid application;
[0013] FIG. 2 is a schematic diagram of a heat reclamation system for
injecting or soaking
a heated fluid from the heat reclamation system at a second well;
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[0014] FIG. 3 is a schematic diagram of a heat reclamation system for
recirculating a
heated fluid from the heat reclamation system at a second well;
[0015] FIG. 4 is a schematic diagram of a heat reclamation system for
recirculating a heat
transfer fluid (HTF) from the heat reclamation system at a second well;
[0016] FIG. 5 is a schematic diagram showing additional detail of a system
for circulating a
fluid at a first well to reclaim heat at that well for use at a second well;
[0017] FIG. 6 is a schematic diagram of a heat reclamation system for
injecting or soaking
a solvent or water from the heat reclamation system at a second well;
[0018] FIG. 7 is a schematic diagram showing additional detail of a system
for circulating a
fluid at a first pair of wells to reclaim heat at that well for use at a
second well or well pair;
[0019] FIGS. 8A to 8D are schematic diagrams of a system for circulating a
fluid at a first
well with an existing tubing and casing completion;
[0020] FIG. 9 is a flow chart illustrating operations performed in
reclaiming heat at a first
well for injecting a heated fluid at a second well;
[0021] FIG. 10 is a flow chart illustrating operations performed in
reclaiming heat at a first
well for injecting a heated fluid at a second well with a recirculation of
cooled fluid at the second
well;
[0022] FIG. 11 is a flow chart illustrating operations performed in
reclaiming heat at a first
well for injecting a heated fluid at a second well with additional heat being
added to the heated
fluid; and
[0023] FIG. 12 is a flow chart illustrating operations performed in
circulating a fluid in a
heated well to cool that well for a subsequent abandonment of the well.
DETAILED DESCRIPTION
[0024] A system for recovering heat from a heated well and using the
recovered heat in a
process at one or more other wells is herein described. In an implementation,
the system is
used when the heated well is at or near the end of its lifecycle, when the
formation surrounding
the heated well has increased in temperature over time as a result of an oil
recovery process
having been implemented at that well, for example SAGD. The heat contained in
the formation
surrounding the well can therefore be considered "lost" or otherwise unused
and available for
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recovery and reuse in another process. The heat can be recovered by
circulating a cold (or
cooled or cooler) heat transfer fluid at the heated well that is effective to
create a direct or
indirect heat exchange mechanism with the heated formation to increase the
temperature of the
heat transfer fluid for subsequent use at a second well. For example, the
heated fluid can be
injected at one or more second wells, or circulated at the one or more second
wells. The heat
transfer fluid can therefore include an injection fluid used in an advanced
oil recovery process
such as SAGD, CSS, or solvent-based recovery, e.g., water or solvent. The heat
transfer fluid
can also include a fluid meant to be circulated at the one or more second
wells, e.g., for use in
pre-heating or start-up processes. It can be appreciated that heat transfer
fluids used directly in
one or more other wells should be compatible with the formation, that is,
without harming oil
permeability, without causing chemical reactions between the rock and heat
transfer fluid,
without causing asphaltene depositions, etc.
[0025] Turning now to the figures, FIG. 1 illustrates schematically a heat
recovery system
denoted by numeral "10". The heat recovery system 10 includes a source fluid
14 that is
circulated through at least a portion of a well 12. The well 12 illustrated in
FIG. 1 is a
horizontally-oriented well with a vertical/slant portion, and a bent portion,
often referred to as the
"heel", that extend to a horizontal portion towards an endpoint, often
referred to as the "toe" of
the well 12. This type of well 12 is typically of steam-based, solvent-based
or steam and solvent
based advanced oil recovery processes. It can be appreciated that the system
10 and
principles described herein equally apply to other well configurations, such
as vertical wells, well
pairs (i.e. a producer well situated below an injector well), infill or step-
out wells (i.e. wells
positioned between or adjacent wells or well pairs), observation wells, etc.
[0026] The source fluid 14 can be considered a cool or cooled fluid that
when circulated in
the well 12 is heated by the formation and well completion which in exchange
cools the well 12
and the surrounding formation 15 over time. The fluid returns from its
downhole circulation path
as a heated fluid 16. The heated fluid 16 is provided to or otherwise consumed
by a heated
fluid application 18. As will be described and exemplified below, the heated
fluid application 18
can include any suitable use of the heated fluid 16. This can include, for
example, direct usage
of the heated fluid 16 at another well 12, or further recirculation of the
heated fluid 16 to heat
another well 12. Some example heated fluid applications 18 can include,
without limitation:
solvent-based oil recovery processes, start-up of wells (e.g., SAGD, solvent,
SAGD and
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solvent), start-up of infill or step-out wells, and chemical technology
activation during start-up
(i.e. soak).
[0027] As illustrated in FIG. 1, the system 10 can be configured to focus
on circulating the
source fluid 14 and thus achieving heat exchange in the vertical/slant or heel
portions of the well
12. This can be done to minimize materials and the associated costs with
deploying the system
10. However, it will be appreciated that the system 10 can extend into any
desired portion of
the well 12, including into and along the horizontal portion of the well 12.
[0028] FIG. 2 illustrates an example implementation of the heat recovery
system 10. In
this example, the source fluid 14 is circulated in at least one of the wells
12 in a well pair that
includes an injector well 12 and a producer well 20 in a SAGD operation. The
source fluid 14 is
circulated to recover heat in the formation 15, which can include heat that is
trapped or lingering
within a steam chamber 22 formed during the SAGD production process. In this
example
implementation, the well 12 is at or near the end of its lifecycle, and the
circulated source fluid
14 is heated to become heated fluid 16 that is used directly at a second well
pair, including a
second injector well 26 and a second producer well 28. For example, the source
fluid 14 can be
water or solvent, wherein the heated fluid 16 becomes an injection or soak
into the formation 15
surrounding the second well pair 26, 28. As explained later, the heated fluid
16 can be heated
solely by circulation through the heated first well 12, or can be supplemented
with additional
heat. It can be appreciated that the steam chamber 22 is shown in isolation in
FIG. 2 for ease
of illustration, and typically at that stage of production, the steam chamber
22 would have at
least partially merged with and into one or more adjacent steam chambers
associated with other
well pairs (not shown).
[0029] For example, heated water may require additional heat to create
steam that is
suitable for a SAGD or CSS process at the second well 26. However, it can be
appreciated that
in such cases, the heat recovered from the first heated well 12 reduces the
energy and cost of
generating heated fluid 16 that is suitable for the process being used at the
second well 26.
While a single second well 26 is shown in FIG. 2, it can be appreciated that
the heated fluid 16
can be used in processes at more than one second well 26. For example, the
heated fluid 16
can be used at a well pad that serves more than one well pair to reduce the
overall energy
required to generate the steam or to heat (warm up at surface instead of
downhole) a solvent
used at those multiple well pairs. It is also recognized that the heat
extracted by the system 10
can also activate chemical technologies. Since some chemicals can decompose
into other
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chemicals in the presence of heat, the system 10 can be used to soak the
second well(s) 26
with a thermally activated chemical and use the heat extracted from the heated
well 12 to
commence the chemical reaction. That is, by warming up the chemical used for
the soak, one
can facilitate oil emulsification, with the chemical improving the interaction
between oil and
water, promoting fluid mobility that can translate into shorter start-up
times, e.g., to accelerate
SAGD/solvent start-up. It is also recognized that the system 10 can be
beneficial to microbial
technologies, since microbes prefer temperatures close to, or higher than, 25
C to grow. That
is, by pre-heating streams containing such microbes, one can encourage their
growth. For
example, some microbes can be modified to consume chemicals previously soaked
in the
reservoir and turn the chemicals into other chemicals that are known to
improve oil mobility and
promote oil in water emulsions.
[0030] FIG. 3 illustrates another example implementation, in which the
heated fluid 16 is
recirculated and reused as the source fluid 14 in another heat recovery
operation. In this
example, the source fluid 14 is circulated to recover heat in the formation
15, which can include
heat that is trapped or lingering within a steam chamber 22 formed during the
SAGD production
process, similar to what is shown in FIG. 2. In this example, the heated fluid
16 is then
circulated at the second well 26 rather than used as an injection or soak
medium. The heated
fluid 16 is therefore used as a pre-heat or start-up fluid at or near the
beginning of the lifecycle
of the second well 26. The heated fluid 16, after circulation, can be a
candidate for recirculation
as a source fluid 14 at another well that is at or near the end of its
lifecycle. The implementation
shown in FIG. 3 is particularly advantageous when the fluid is a heat transfer
fluid that is meant
to be used and reused in a closed loop, as a heat source and heat sink rather
than being a fluid
that is meant to be consumed in an oil recovery process.
[0031] For example, such a heat transfer fluid suitable for recirculation
in a closed loop can
be one that is maintained in a liquid phase, and remains stable through a
range of operating
temperatures. The fluid can be formulated from a base oil such that it is
resistant to oxidation
and oxidative breakdown, as well as resistant to increases in viscosity as a
result of such
oxidation. The fluid can also be formulated to exhibit a consistent heat
capacity and thermal
conductivity over the range of temperatures used during circulation, in order
to maintain
consistent heat transfer into the formation. Fluids with these properties have
been found to be
stable at relatively high temperatures, e.g., greater than 300 degrees
Celsius. Temperatures of,
for example, 250 degrees Celsius or greater can be used. Various fluid types
can be used as
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the fluid, for example, Calflo0 produced by Petro-Canada which, in addition
to the above
properties, is found to leave minimal deposits and be relatively stable at
high temperatures,
namely those greater than 300 degrees Celsius. Calflo is made from a hydro-
treated mineral
oil in which bonds are saturated to make the oil more stable and resistant to
oxidation. Other
liquid-phase heat transfer fluids can also be used according to the principles
described herein,
for example, synthetic oils such as polyalphaolefins, glycol, aromatics, light
crude oil, produced
emulsion, water, a molten salt (e.g., one able to reach temperatures of > 500
degrees C), etc.
The fluid can also be modified to include additives, such as anticorrosive or
antifouling agents,
any additive to improve thermal stability of the fluid, nanoparticles,
hydrocarbons, water, non-
condensable gas (i.e. to act as a pushing agent to accelerate well
communication), foaming
agents, surfactants, etc.
[0032] It can be appreciated that a heat exchange mechanism can be used to
add heat to
the heat transfer fluid that is heated at the first well 12 and then used in a
second closed loop at
a second well 26. FIGS. 4 and 5 illustrate such a scenario in greater detail.
Referring first to
FIG. 4, a first set of heat transfer fluid (HTF) circulation equipment 62a is
used to recover heat
from a first well 12, which in this example is at or near the end of its
lifecycle in a SAGD
operation, using a first closed loop circulation 60. The heated HTF 64 that is
produced can then
be used by a second set of HTF circulation equipment 62b at a second well 26
using a second
closed loop circulation 68. The heated HTF 64 can be further heated, if
necessary or desired,
using HTF pre-heating equipment 66, before it is used by the second set of HTF
circulation
equipment 62b. Accordingly, heat recovered from the formation 15 surrounding
the first well 12
can be used as a pre-heating or start-up fluid.
[0033] That is, the system 10 shown in FIG. 4 can be used before (or in
some
implementations instead of) a steam circulation or bullheading process
normally referred to as a
"start-up" phase, as well as during production subsequent to preheating and/or
start-up. The
pre-heating phase is used in order to heat the area surrounding the well to at
least reduce the
amount of time required to complete the circulation or start-up phase, and
reduce the amount of
steam or solvent required for same. For example, in a typical SAGD start-up,
fluid
communication is achieved in the area between the wells by heating that area
using steam
circulation or bullheading. Similarly, a solvent-based advanced oil recovery
process can require
at least some pre-heating before the solvents used can become effective. When
using steam
circulation to achieve start-up, the steam facilities are required to be
installed at the surface prior
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to commencing the start-up phase, which limits how early this process can
begin. For example,
it can be multiple years between drilling a well and the installation of the
steam facilities.
Moreover, circulating steam can be time consuming, typically requires
continual supervision on-
site due to operational considerations such as pressure spikes and so-called
"steam hammer",
uses facilities that are significant in size and cost, and increases the
amount of water used in
the oil recovery process.
[0034] The system described herein can advantageously enable earlier pre-
heating of a
bitumen reservoir surrounding a well pair to at least reduce the amount of
steam circulation
required, or remove the requirement of steam at all, e.g., in solvent based
recovery processes.
This can be done at least in part using energy recovered from the first well
12. The system can
also be assembled on a moveable module or skid that can be moved off-site once
the pre-
heating phase is completed, and relocated to another site where needed,
providing
portability. Pre-heating using a mobile heated fluid module can therefore
occur prior to the
steam generation facilities at surface being completed, which means that at
least some warming
of the interwell region can be achieved during an otherwise idle or "dead"
period.
[0035] As depicted in FIG. 4, after the heated HTF 64 is circulated at the
second well 26,
28, it becomes cooled by transferring its heat into the formation 15
surrounding the second well
26, 28 or in the interwell region between a pair of wells. This allows the
cooled HTF to be
recirculated at another heated well, or at the same heated well 12 to recover
additional heat
from the formation 15. Therefore, the circulation of an HTF 60 can be repeated
multiple times
depending on the rate of transfer and ability to recover heat during multiple
passes through the
heated formation 15.
[0036] FIG. 5 illustrates an example of an HTF circulation system 62. The
system 62
includes a fluid supply vessel 70 (e.g., a thermally rated expansion tank)
containing a supply of
the source fluid 14, and one or more pumps 72 for drawing fluid from the fluid
supply vessel 70.
As noted above, the fluid circulation system 62 can be assembled on a movable
platform, rig or
"module" to enable the system 62 to be moved to another site where needed, for
example, after
the heat reclamation process is completed. The pumps 26 are used to create a
fluid circulation
60 in the well 12 to extract heat from the surrounding formation 15. The
returned fluid, now
heated fluid 64 can be sent to a second well 26 as described above, and
optionally fed to fluid
heating equipment 76 for further heating prior to being used at the second
well 26. It can be
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appreciated that, when available, pumping capabilities downhole can also be
used to circulate
the fluid 74 as herein described.
[0037] Turning now to FIG. 6, a further implementation is illustrated in
which the circulated
fluid 42 is a solvent, water, chemical solution, microbes, or otherwise a
fluid that is used directly
in the process applied at the second well 26. In this example, the fluid 42
can be fed or
introduced from a suitable supply or source (not shown) and circulated in the
first heated well 12
in the same manner as that described above. This generates a heated fluid 44
of solvent or
water (or other), which can be optionally further heated by fluid heating
equipment 46 such as a
boiler or steam generator and fed to fluid injection equipment 48, e.g., for
solvent or steam
injection. It can be appreciated from the illustration in FIG. 6 that the
fluid 42 is heated by the
formation 15 at the first well 12, optionally further heated to be at a
desired temperature, and
directly used (injected or soaked) in a second well 26 in a relatively earlier
stage in the oil
recovery process than the first well 12. That is, heat that is abandoned or
left behind at the first
well 12 can be used to reduce the amount of energy required to perform at
least one operation
requiring heating at another well. It can be appreciated that, as discussed
above, the heating
performed by circulation through the first well 12 may provide sufficient heat
for direct
consumption, e.g., in a solvent-based process.
[0038] FIG. 7 provides yet another implementation in which fluid
circulation equipment 62
is configured to circulate fluid 60 in two streams, namely a first stream 60a
in a first heated well
12 and a second stream 60b in a second heated well 20. For example, in a SAGD
well pair 12,
20 at or near the end of its lifecycle, circulating fluid 60 within both wells
12, 20 can increase the
amount of heat reclamation using the processes described herein.
[0039] FIGS. 8A through 8D illustrate further detail of several non-
limiting examples of
circulation techniques that can be applied downhole in the well 12 in order to
circulate the fluid
14. It can be appreciated that various completion configurations may be
implemented in wells
used for oil recovery, and the examples provided in FIGS. 8A-8D are
illustrative of only a few, in
order to illustrate that various adaptions are possible depending on the type
of completion, type
of well 12, etc.
[0040] FIG. 8A provides an enlarged view of a well 12 in which a closed
loop fluid
circulation has been installed. The well 12 can generally be any type of well
as discussed
above. In the figure, a portion of a generally vertical portion 80 is shown,
which transitions to a
slant or heel portion 82, which then transitions into a generally horizontal
portion 84. The well
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12 shown in FIG. 8A herein represents various types of wells to which fluid
can be circulated,
including SAGD or CSS wells, infill or step-out wells, observation wells,
wells used for solvent
injection, wells heated by electric heating, etc. The portions of the well 12
shown in FIG. 8A can
be formed by installing a casing within a wellbore drilled into the overburden
and the formation
15 that contains the pay as is known in the art.
[0041] In this example configuration, the horizontal portion 84 is
shortened by a break of
indeterminate length for ease of illustration. The well 12 in this example
implementation
includes long tubing 86 extending down the well 12 and normally terminating
near the toe of the
well 12. The long tubing 86 in this example has been pulled back such that it
terminates at or
near the heel portion 82. The long tubing 86 extends through a length of short
tubing 88 that
terminates near the heel portion 82 of the well 12 creating an annulus between
the inner surface
of the short tubing 88 and the outer surface of the long tubing 86. In this
example, the long
tubing 86 is pulled within the short tubing 88 such that the short tubing 88
can be plugged or
otherwise blocked, e.g., using a bridge plug 90 as shown in FIG. 8A, to
contain the long tubing
86 therewithin. In this way, the long tubing 86 can be used to pump the fluid
14 down into the
well 12 and recirculate in a closed-loop manner back to the surface via the
annulus between the
short tubing 88 and the long tubing 86. This circulation is illustrated
schematically using a path
of arrows in FIG. 8A. As noted above, in other configurations, the system 10
can be configured
to extend the recirculation circuit into and along at least a portion of the
horizontal portion of the
well 12, in this example the long tubing 86. In such configurations, the long
tubing 86 may not
need to be pulled back as shown, or to the same extent.
[0042] The long tubing 86 and short tubing 88 are normally used for
injecting steam into
the injector wells 12. When steam is used during a circulation phase (i.e. for
achieving start-up),
the steam is injected down the long tubing 86 and returns via the annulus
between the long
tubing 86 and the short tubing 88. Then, when the SAGD production phase
begins, steam can
be injected in both the long tubing 86 and the short tubing 88 of the injector
well 12 to heat the
pay in the formation 15. It can be appreciated that the long/short tubing
configuration shown in
FIG. 8A is just one example, and that any tubing or string nested within
another tubing or string,
that is obstructed, can be utilized to implement the fluid circulation systems
as described herein.
[0043] Regarding producer wells (e.g. well 20 shown in FIG. 7), generally,
the long tubing
86 and short tubing 88 can also be installed therein, and when steam is used
for pre-heating,
steam can be injected into both the long tubing 86 and the short tubing 88 of
the producer well
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20. During the production phase, the producer wells 20 are used to collect
heated bitumen by
receiving produced fluids through the slotted liner that extends along the
generally horizontal
portion 80, which are collected by the long tubing 86 and pumped to surface.
It can be
appreciated that in other implementations, the produced bitumen is gas lifted
to surface. The
fluid circulation systems described herein can therefore be deployed into any
well 12, 20 that
comprises at least a portion of tubing running along the well 12 and which can
be adapted to
enable a closed-loop circulation path and allow heat in the vicinity of the
well 12 to be captured.
[0044] FIG. 8B illustrates an alternative implementation that may result
for a different type.
of completion applied to the well 12. In this example, the casing that forms
the portions 80, 82,
84 is plugged near the heel using, e.g., a bridge plug 90 after the long
tubing 86 has been pulled
to a position wherein the end of the long tubing 86 is behind the bridge plug
90 thus enabling a
circulation of fluid. In this example, the fluid 14 can similarly be pumped
downhole using the
long tubing 86 and circulates via the annulus between the outer surface of the
long tubing 86
and the inner surface of the well 12 provided by the casing.
[0045] FIG. 8C is another alternative implementation, in which similar to
FIG. 8A the long
tubing 86 is pulled back towards the heel portion 82. However, in this
example, the long tubing
86 is plugged using a bridge plug 90 to allow the fluid 14 to be circulated
within the long tubing
86. This is achieved by introducing an additional length of tubing 92 that is
fed into the long
tubing 86 and is used to pump the fluid 14 downhole for circulation via an
annulus between an
outer surface of the additional tubing 92 and the inner surface of the long
tubing 86.
[0046] FIG. 8D provides yet another alternative implementation that is
similar to FIG. 80
but wherein the long tubing 86 is left as it was installed during the well's
completion, and
plugged at a position along the long tubing 86 that aligns with the heel
portion 82. As with the
examples above, the long tubing 86 can be plugged using a bridge plug 90.
[0047] It can be appreciated from FIGS. 8A-8B that there are numerous ways
to achieve a
circulation path within the heated well 12, and that various additional
alternatives are possible
both within the scope of the completion types illustrated and other types of
completions. For
example, the additional tubing 92 could instead be introduced into the well
with its own closed
loop without requiring any of the existing tubing to be plugged, as
illustrated schematically in
FIGS. 1, 4, and 6.
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[0048] It can also be appreciated that the bridge plug 90 can be deployed
in any suitable
manner. For example, a bridge plug 90 such as that illustrated in FIGS. 8A-8D
can be deployed
or "landed" by being pushed by a length of tubing until it reaches a desired
location near the end
of the long tubing 86. Hydraulic fluid can then be pumped down the tubing to
activate the piston
in the bridge plug, which causes the opposing inclined planes of the bridge
plug 90 to move
relative to each other to increase the diameter of the bridge plug 90 thus
sealing the end of the
long tubing 86. When hydraulic fluid reaches a predetermined pressure, the
tubing disengages
from the bridge plug 90 and can be pulled back up to surface. To remove the
bridge plug 90, a
hook-type tool installed on the end of similar tubing used to deploy the
bridge plug 90, can be
deployed into the long tubing 86 to hook onto the bridge plug 90, and when
attached, can be
pulled upwardly to release the bridge plug 90, which allows the bridge plug 90
to be pulled back
to surface by recoiling the tubing.
[0049] It can also be appreciated that a bridge plug 90 is only one example
of a
mechanism that can be used to block or obstruct tubing in a well 12. Other
examples of suitable
obstruction mechanisms include a bullnose attachment, which can be punctured
to unseat the
obstruction. A similar obstruction can also be used, which can be ruptured
through the
application of hydraulic pressure, after the obstruction is no longer needed.
Further examples of
suitable obstruction mechanisms include packers that increase in size when
water is applied
thereto, fluid injected bags that swell to create a seal, sliding sleeves,
burst discs, and valves.
For sliding sleeves and valves, a control line can be used to allow the
mechanism to remain in
the long tubing and be controlled remotely. That is, by using a valve or other
shut-off
mechanism, the mechanism can be closed for pre-heating to create the closed
loop for the
heated fluid circulation, and opened for a subsequent SAGD phase.
[0050] FIG. 9 is a flow chart illustrating operations performed in
reclaiming heat at a first
well for injecting a heated fluid at a second well. At step 100 the system 10
is used to feed fluid
into the first well 12, and at step 102 the system 10 is configured to receive
heated fluid from the
first well 12. For example, any one of the above-described circulation
configurations can be
implemented in order to circulate a source fluid 14 at the heated first well
12 without losing the
source fluid 14 into the formation 15 such that the source fluid 14 is heated
to generate a heated
fluid 16. The heated fluid 16 is then delivered or otherwise provided to one
or more second
wells at step 104. In this example, the heated fluid 16 is injected into the
one or more second
wells at step 106.
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[0051] FIG. 10 is a flow chart illustrating operations performed in
reclaiming heat at a first
well for injecting a heated fluid at a second well with a recirculation of
cooled fluid at the second
well. At step 200 a source fluid 14 is fed into a first well 12 and heated
fluid 16 is received from
the first well 12 at step 202. At step 204 the heated fluid 16 is delivered or
otherwise provided
to one or more second wells. In this example, the heated fluid 16 is fed into
the one or more
second wells at step 206 in order to transfer the reclaimed heat to the second
well. Then, at
step 208, the cooled fluid is received from the second well, namely via a
second closed loop
circulation at the second well. As discussed above, this cooled fluid can
become the source 14
fluid at another heated well 12 or reused at the same first well 12 to extract
additional heat.
[0052] FIG. 11 is a flow chart illustrating operations performed in
reclaiming heat at a first
well for injecting a heated fluid at a second well with additional heat being
added to the heated
fluid. At step 300 a source fluid 14 is fed into a first well 12 and heated
fluid 16 is received from
the first well 12 at step 302. At step 304 the heated fluid 16 is delivered or
otherwise provided
to one or more second wells. In this example, the heated fluid 16 is further
heated and fed or
injected into the one or more second wells at step 306. That is, FIG. 11
illustrates a process in
which the temperature of the heated fluid 16 is not high enough for the
intended use at the one
or more second wells, and is further heated to achieve a predetermined/desired
temperature.
Then, optionally at step 208, cooled fluid may be received at the second well
and reused, or
sent to another heated well 12, similar to what has been discussed above.
[0053] FIG. 12 is a flow chart illustrating operations performed in
circulating a fluid in a
heated well to cool that well for a subsequent abandonment of the well. At
step 400 the source
fluid 14 is circulated in the heated well 12, e.g., as illustrated above. By
transferring heat from
the well 12 and surrounding formation 15 into the source fluid 14, it can be
appreciated that at
step 402 the temperature of the well 12 into which the fluid 14 is circulated
decreases, which
facilitates subsequent abandonment. For example, in step 404 the cooled well
may have a
more suitable temperature for introducing instruments and equipment to
prepared the well 12 for
abandonment.
[0054] For simplicity and clarity of illustration, where considered
appropriate, reference
numerals may be repeated among the figures to indicate corresponding or
analogous elements.
In addition, numerous specific details are set forth in order to provide a
thorough understanding
of the examples described herein. However, it will be understood by those of
ordinary skill in the
art that the examples described herein may be practiced without these specific
details. In other
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instances, well-known methods, procedures and components have not been
described in detail
so as not to obscure the examples described herein. Also, the description is
not to be
considered as limiting the scope of the examples described herein.
[0055] It will be appreciated that the examples and corresponding diagrams
used herein are
for illustrative purposes only. Different configurations and terminology can
be used without
departing from the principles expressed herein. For instance, components and
modules can be
added, deleted, modified, or arranged with differing connections without
departing from these
principles.
[0056] The steps or operations in the flow charts and diagrams described
herein are just for
example. There may be many variations to these steps or operations without
departing from the
principles discussed above. For instance, the steps may be performed in a
differing order, or
steps may be added, deleted, or modified.
[0057] Although the above principles have been described with reference to
certain specific
examples, various modifications thereof will be apparent to those skilled in
the art as outlined in
the appended claims.
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