Note: Descriptions are shown in the official language in which they were submitted.
APPARATUS, METHOD AND VVELLBORE INSTALLATION TO MITIGATE HEAT
DAMAGE TO WELL COMPONENTS DURING HIGH TEMPERATURE FLUID
INJECTION
BACKGROUND OF THE INVENTION
Field of the Invention
Embodiments of the invention relate to solutions involving any high
temperature fluid
injection where there is a need to prevent high temperature effects to well
components
such as casing, sealing cement or the earthen formation, including the uphole
shallow
formation, through which the wellbore passes. A particular application is to
mitigate
adverse heat effects from steam injection.
Description of Related Art
There are extensive viscous hydrocarbon reservoirs throughout the world. The
viscous
hydrocarbon is often called "bitumen", "tar", "heavy oil", and "ultra heavy
oil" (collectively
called "heavy oil") which typically have viscosities in the range of 3,000 to
over
1,000,000 centipoise. The high viscosity makes it difficult and expensive to
recover the
hydrocarbons.
Each oil reservoir is unique and responds differently to the variety of
methods employed
to recover the hydrocarbons therein. Generally, heating the heavy oil in situ
to lower the
viscosity has been employed. Normally these viscous heavy oil reservoirs can
be
produced with methods such as cyclic steam stimulation (CSS), steam drive
(Drive) and
steam assisted gravity drainage (SAGD), where steam is injected from surface
into the
reservoir to heat the oil and reduce its viscosity enough for production. The
methods
described above are commonly called Enhanced Oil Recovery (EOR) schemes.
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A large number of heavy oil reservoirs were developed with well casing and
sealing
cement materials that cannot withstand temperatures typically used in steaming
operations. Current "non-thermal" wellbore casing / cement systems are limited
to
temperatures between 60 and 120 deg C (depending on the quality of the
wellbore
casing) without compromising the wellbore casing and sealing cement. Typical
steam
or high temperature injection EOR schemes operate at temperatures over 200 deg
C.
Additionally, current methods of producing heavy oil reservoirs face other
limitations.
One particular problem is wellbore heat loss while the high temperature fluid
or steam is
traveling from surface to the reservoir. The problem worsens as depth
increases and
the steam quality decreases as more energy is lost to the wellbore and
formations
above the oil reservoir.
SUMMARY OF THE INVENTION
In accordance with a broad aspect of the present invention, there is provided
a wellbore
installation for a well comprising: a wellhead; an injection tubing extending
along a length
of the well and configured for conveying a high temperature fluid to an
injection zone in
the well, the injection tubing creating an annulus in the well between the
injection tubing
and a wall of the well; a packer set about the injection tubing and sealing
the annulus; a
pipe extending through the annulus alongside the injection tubing with an
inlet end
connected at the wellhead to surface piping and an outlet end positioned close
to the
packer; an outlet port on the wellhead; and a pump for creating a flow of a
cooling fluid
through a circuit from the surface piping through the pipe, from the pipe into
the annulus
close to the packer, returned up through the annulus alongside the injection
tubing and
out through the outlet port to the surface piping.
In accordance with another broad aspect of the present invention, there is
provided a
method for protecting a well from thermal damage during injection of high
temperature
fluids, the method comprising: a) introducing a cooling fluid to an annulus
between a high
temperature fluid injection pipe and the wellbore wall; b) allowing the
cooling fluid to
remain in the annulus for a residence time such that the cooling fluid becomes
a heated
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cooling fluid; c) circulating the heated cooling fluid from the annulus; and
repeating steps
a - c.
In accordance with another broad aspect of the present invention, there is
provided an
apparatus for high temperature injection to a reservoir in a well, the
apparatus
comprising: an injection tubing couplable to a wellhead, the injection tubing
configured
for conveying a high temperature fluid to an injection zone in the well; a
packer through
which a lower end of the injection tubing passes; a pipe extending alongside
the
injection tubing with an inlet end configured for connection at the wellhead
to surface
piping and an outlet end positioned close to the packer; and an outlet port on
the
wellhead, the apparatus configured for creating a cooling fluid circuit that
flows from
surface through the pipe and from the pipe alongside an external surface of
the injection
tubing close to the packer and then returned up to surface alongside the
injection tubing
and out through the outlet port.
It is to be understood that other aspects of the present invention will become
readily
apparent to those skilled in the art from the following detailed description,
wherein
various embodiments of the invention are shown and described by way of
example. As
will be realized, the invention is capable for other and different embodiments
and
several details of its design and implementation are capable of modification
in various
other respects, all captured by the present claims. Accordingly, the detailed
description
and examples are to be regarded as illustrative in nature and not as
restrictive.
BRIEF DISCRIPTION OF THE DRAVVINGS
It is noted that the attached drawings illustrate only typical embodiments of
this
invention and are therefore not to be considered limiting in scope, for the
invention may
admit to other equally effective embodiments.
Figure 1 illustrates a side view of a typical wellbore completed with "non-
thermal"
wellbore piping and sealing cement.
Figure 2 illustrates a side view of a typical wellbore completed with
"thermal" wellbore
piping and sealing cement.
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Figure 3 illustrates a Pipe and Instrumentation Diagram (P&ID) of the surface
apparatus
including vessels, fluid storage, pump, heat exchanger, piping, safety and
operating
controls for a pressure safety control embodiment.
Figure 4 illustrates a P&ID of the surface apparatus including fluid storage,
pump, heat
exchanger, safety and operating controls for a flow safety control embodiment.
Figure 5 illustrates a P&ID of the surface apparatus including fluid storage,
pump, heat
exchanger, safety and operating controls for a temperature safety control
embodiment.
DETAILED DISCRIPTION
Embodiments of the invention generally relate to an apparatus, a wellbore
installation
and a method related to a cooling fluid circuit to counteract any heat-
generated damage
to the well components during high temperature injection. For example,
embodiments
of the invention protect well components such as the wellhead, shallow
formations,
wellbore casing and/or wellbore cement from the effects of high temperature
injection.
While high temperature injection is often used in the recovery of heavy oil,
it is to be
noted that aspects of the invention are not limited to use in the recovery of
heavy oil but
are applicable to recovery of other products such as gas hydrates.
The apparatus includes an injection tubing that conveys the high temperature
fluid to an
injection zone. The injection tubing may be insulated to reduce heat transfer
through
the tubing walls. The apparatus further includes an isolation packer above the
injection
zone with the packer type to be compatible with high temperature and corrosive
fluid
injection. The packer can be any of mechanical set, hydraulic set, swellable,
inflatable
and slipless depending on well type, depth and application. The injection
tubing passes
through the packer, but the packer seals the annulus between the injection
tubing and
the wellbore casing that defines the interior wall of the wellbore. A second
pipe that has
a diameter sized to fit in the annulus between the injection tubing and the
wellbore
casing is also employed in the installation. The second pipe may have a
diameter
substantially equal to or smaller than the injection tubing. The second pipe
is installed
to extend from surface into the annulus. For example, in one embodiment the
second
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pipe has its outlet end positioned close above the packer. It does not pass
through the
packer like the injection tubing, but instead the second pipe opens on the
side of the
packer opposite the injection zone side. Having the outlet end immediately
uphole of
the packer allows the system to operate most efficiently by providing cooling
to the
entire wellbore length. Further, the full inner diameter can be used to
circulate the
cooling fluid out of the wellbore.
This second pipe could be continuous or jointed such as any of coil tubing
(continuous
steel and/or polymeric pipe) or jointed steel or polymeric pipe. Polymeric
pipe can be
any of various high temperature plastic materials such as of polyvinylchloride
(PVC). In
the case of jointed steel pipe or high temperature plastic pipe, such material
can be
coupled to the injection tubing to improve its stability and facilitate
installation.
Continuous steel pipe such as coil tubing can be installed without coupling to
the
injection tubing. The surface termination of the second pipe allows
installation and
removal of continuous steel pipe without removal of the injection piping. In
particular,
second pipe in the form of continuous steel pipe, can be installed and removed
through
the wellhead apart from removal of the injection tubing. Other types of second
pipe are
installed and removed while installing or removing the injection tubing. The
surface
connection (wellhead) has an outlet from the annulus. The outlet from the
wellhead is
close to the safety seal and therefore the wellhead is configured to reduce
heat damage
as close to surface and the wellheard as possible_
The wellbore installation permits a high temperature fluid to be conveyed from
surface,
through the well and into the wellbore, and the oil reservoir accessed
therethrough,
below the packer. At the same time, heat damage to the surrounding wellbore
wall
components (i.e. casing and cement) and the shallower formations is mitigated
through
the possible use of insulated injection tubing and a cooling fluid circuit
through the
second pipe. In particular, a cooling fluid can be introduced to the annulus
above the
isolation packer through the second pipe and after a residence time the
cooling fluid is
evacuated at the wellhead. Thus, a circulation of cooling fluid may be
established
through the wellbore annulus. The cooling fluid circuit mitigates heat damage
to well
components and shallow formations during high temperature fluid injection
operations.
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The wellbore installation works with surface process equipment including
equipment for
handling cooling fluid. Equipment may include, for example, fluid storage, a
pump, a
heat exchanger for cooling the cooling fluid, operating and safety controls
and piping to
provide a continuous cooling fluid flow into the well annulus between the
injection tubing
and the wellbore casing. The control system design and wellhead seals are
provided to
allow safe operation of the fluid flow and to prevent injected fluids from
escaping to
surface. This continuous fluid flow will provide temperature control to the
wellbore
casing and cement. Surface piping could be a closed circuit or open circuit
depending
on the amount of temperature control required to protect the wellbore casing.
lithe
temperature of the cooling fluid coming to surface can be cooled reasonably,
then the
fluid will be cooled and circulated back into the well. However, if the
temperature is too
high, then it may be uneconomical to recycle it.
Embodiments of the invention relate to surface wellhead / wellbore / well
casing /
formation protection from high temperature injection operations. One
embodiment of
the invention relates to steam injection into "non-thermal" wellbores where
wellbore
casing and sealing cementing cannot withstand the high temperatures of steam
injection or other high temperature injection EOR schemes. In another
embodiment, the
invention relates to steam injection into "thermal" wellbores where well
piping and
sealing cementing were selected to withstand the high temperatures of steam
injection
but where there is a desire to reduce or eliminate wellbore casing growth
above the
injection zone. Apparatus according to the invention includes a packer on
thermally
insulated injection tubing (IT), such as for example vacuum insulated
injection tubing
(VIT), installed to immediately above the oil reservoir with a second pipe
installed
between the IT and the wellbore casing from surface to the top of the packer.
At
surface the apparatus includes wellhead connections and equipment for handling
the
cooling fluid such as any of piping, closed or open fluid storage tanks, a
pump and
operating and safety controls whereby a cooling fluid is pumped, for example
possibly
continuously, into the annulus between the wellbore casing and the injection
tubing to
remove from the well any heat being lost by the IT. If desired, a heat
exchanger cools
the cooling fluid returned from the wellbore. This cooling fluid could be
cooled by heat
exchange, for example possibly to transfer its heat into the fluid to be used
in the
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generation of the steam or high temperature fluid, or by other conventional
cooling
methods such as air coolers.
In one embodiment of the invention, the operation system can include an aspect
of
temperature control. In one embodiment of the invention, the safety control
system can
be operated on vessel pressure. In another embodiment of the invention, the
safety
control system can be operated on fluid flow. While the cooling system
protects the well
from thermal expansion causing damage, these operation and safety control
systems
can further be employed to monitor overall well operations, packer condition
and for well
control.
The cooling fluid can be any fluid capable of storing and transferring heat
such as, for
example, one or a combination of water, hydrocarbon, cooling
fluid/refrigerant, air or
nitrogen. Embodiments of the invention can relate to processes where the
cooling
system is used to prevent heat loss from drilling or production operations in
permafrost
areas. In this embodiment the system would use an environmentally friendly
cooling
fluid, for example a hydrocarbon such as glycol, which can remain fluid below
0 deg C.
With reference now to the drawings, Figure 1 illustrates a typical "non-
thermal" well.
Drilled hole 1 contains surface casing 3 which has been cemented with non-
thermal
cement 2. Drilled hole 4 contains non-thermal production casing 6 which has
been
cemented with non-thermal cement 5. Injection tubing (IT) 8 is connected at
surface to
the injection wellhead 17. Injection tubing 8 extends down through an
isolation packer 9
immediately above the heavy oil reservoir 10. Steam or other high temperature
fluid is
injected from surface, down and out through the lower end of IT 8, through
production
casing perforations 11 and into heavy oil reservoir 10. Total depth of the
well is
illustrated by 12. Cooling fluid CF is injected from a supply through line 36
at surface
through second pipe 7. Cooling fluid CF is introduced to an annulus 13 between
the IT
8 and casing 6 at the outlet end 7' of the pipe adjacent packer 9 and is
returned to
surface through annulus 13 where it is evacuated at a wellhead outlet. The
outlet is
close to the upper end of the annulus, directly below the wellhead annular
safety seals
27. The cooling fluid at the outlet has been heated by heat radiating from
injection
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tubing 8. The cooling fluid circuit protects wellhead 17, the non-thermal well
casing 6
and non-thermal cement 5 from thermal damage. To additionally reduce heat loss
to
the wellbore, IT 8 can be configured with a thermally insulated wall. There
may be
check valves in or near wellhead outlet 29 and in line 36 to ensure the
direction of flow.
Figure 2 illustrates a typical "thermal" well. Items 1, 2 and 3 are as above,
drilled hole 4
contains thermal production casing 15 which has been cemented with thermal
cement
14. Items 7, 8, 9, 10, 11 and 12 are as above. Cooling fluid CF, to prevent
thermal
growth of thermal production casing 15, is again injected through second pipe
7 and
returned to surface through annulus 13 and wellhead outlet 29.
Figure 3 illustrates one embodiment of surface equipment. In any system, the
wellbore-heated, returning cooling fluid CF flows from outlet 29 and may be
disposed of
for example through piping 22a. However, in many embodiments, the thermal
energy
therein may be recovered and/or the fluid may be recycled. For example as
shown,
cooling fluid returning from the well through outlet 29 may be directed to a
cooler 32 for
fluid cooling therein. The fluid may then be sent to other processes or
disposal 22b,
pumped to a storage tank 33 or returned to the well through piping 36 either
directly or
from tank 33. A pump 35 drives the circulation of the cooling fluid. For
example, pump
35 operates to draw cooling fluid CF from tank 33 and to circulate it back
down the
second pipe 7 (Figures 1 and 2) before the cooling fluid returns up annulus 13
to return
through outlet 29.
The cooling fluid that is heated by circulation through the well may be cooled
by use of a
cooler. In this embodiment, cooler 32 is a heat exchanger that transfers heat
energy to
either cold process fluid 37 or air. In one embodiment, the process fluid is
used for
production of steam and, therefore, the heat exchanged in cooler 32
beneficially
preheats the process fluid.
In this embodiment, the surface piping and instrumentation may be useful for a
pressure
monitored cooling method with a safety shut down mode. Thus, the surface
equipment
in this embodiment further includes an emergency shut down (ESD) valve 31 and
a
pressure controller 34. The surface equipment pumps the returned, heated
cooling fluid
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CF into communication with pressure controller 34, then through emergency shut
down
(ESD) valve 31 before reaching heat exchanger 32.
Pressure controller 34 is upstream of ESD 31 and will close the ESD 31 if a
predetermined overpressure condition is sensed. For example, injection
pressure,
through string 8 and below packer 9 is higher than hydrostatic pressure in
annulus 13.
Thus, if string 8 or the isolation packer leaks and therefore fails, the
pressure from the
injection fluid may create a problematic increase in pressure which may come
up
through the annulus to surface. The present cooling circuit can monitor
continuously,
identify a string or packer failure and actuate ESD 31 to control the well.
Pressure
controller 34 can also communicate the sensed over pressure condition to the
injection
controls to possibly also cause the shut down of the injection system.
The piping up to ESD 31 is high pressure pipe. However, because of the well
control
afforded by ESD 31, the pipe and equipment thereafter need not have high
pressure
ratings to thereby provide cost efficiencies.
The surface equipment in this and other embodiments may further include a
pressure
vessel 30 close to the wellhead, which is useful as a volume buffer in case of
an
overpressure condition. Vessel 30 may be upstream of the ESD to permit a
volume of
return fluid to be accommodated even before the ESD.
Figure 4 illustrates another embodiment of surface control piping and
instrumentation.
This embodiment is useful in a flow monitored cooling method, which includes
one or
more flow volume monitors. Failures such as packer, string or casing failures
can lead
to cooling fluid volume increases or decreases. For example, if packer 9
fails, fluid can
be lost to or gained from the injection zone depending on the pressure
condition of the
injection zone. Any variance in the cooling fluid volume can be identified by
a fluid
volume meter such as a fluid level gauge 28 in tank 33 or via a flow meter
(TFC) 38 in
the piping.
The piping in a closed circuit is configured such that wellbore heated return
fluid from
outlet 29 flows through and then through emergency shut down (ESD) valve 31
before
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optionally passing to heat exchanger 32 and tank 33. Heated fluid is cooled,
herein via
a heat exchanger 32 by either cold process fluid 37 or by other means such as
air.
Cooling fluid CF is drawn from tank 33 by pump 35 which circulates it back
down the
second pipe 7 (Figures 1 and 2) before returning up annulus 13 and through
outlet 29
and its associated piping.
Volume meters 28 and/or 38 will close ESD 31 if flow volumes vary outside of
an
acceptable range. Flow meter 38, for example, monitors for return flows
greater or less
than the output of pump 35 or in comparison to another flow meter (TFC) on the
introduction line 36. While volumes returning that are less than those
introduced may
be accommodated, an increase in volume is cause for immediate shut down as
noted
above with respect to Figure 3. While tank gauge 28 is good for a closed loop
system,
flow meter 38 is useful for both a closed and an open system.
Figure 5 illustrates another embodiment of surface control piping and
instrumentation.
This embodiment is useful in a temperature monitored cooling method, which
includes
one or more temperature sensors (TRC) 40. A system that monitors temperature
gain
in fluid returning from the well may be useful to monitor the system
efficiencies. If the
temperature sensor identifies a return temperature in excess of a
predetermined limit, it
may indicate that the IT 8 is failing, for example, losing its thermal
insulative properties.
The system could be altered to increase cooling or flow rate of the cooling
liquid or IT 8
could be replaced. Temperatures of cooling fluid entering through line 36 and
pipe 7
will be generally less than 20 deg C, while returning temperatures should be
maintained
at less than 70 deg C and possibly less than 60 deg C.
The systems of Figures 3-5 can be used in various combinations.
The previous description and examples are to enable the person of skill to
better
understand the invention. The invention is not be lim ited by the description
and
examples but instead given a broad interpretation based on the claims to
follow.
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