Note: Descriptions are shown in the official language in which they were submitted.
CA 02757950 2011-11-08
PORTED PACKER
FIELD
[0001] The present disclosure relates generally to the field of well
completions for
use in the recovery of in situ hydrocarbons from a subterranean reservoir.
BACKGROUND
[0002] Viscous oil, such as heavy oil or bitumen, residing in reservoirs that
are too
deep for commercial mining may be recovered by in situ processes. Commonly,
viscous oil is
produced from subterranean reservoirs using in situ recovery processes that
reduce the
viscosity of the oil enabling it to flow to the wells; otherwise, an economic
production rate
would not be possible. In commercial in situ viscous oil recovery processes,
the temperature
or pressure is modified or a solvent is added to reduce the viscosity or
otherwise enhance
the flow of the viscous oil within the reservoir.
[0003] In certain processes, such as in SAGD (Steam Assisted Gravity
Drainage), a
dedicated injection well and a dedicated production well are used. The SAGD
process
involves injecting steam into the formation through an injection well or wells
at a rate which
forms a steam chamber and maintains a near constant operating pressure in the
steam
chamber. Steam at the edges of the steam chamber condenses as it heats the
adjacent
non-depleted formation. The mobilized oil and steam condensate flow via
gravity to a
separate production well located at the base of the steam chamber. An example
SAGD is
described in U.S. Patent No. 4,344,485 (Butler).
[0004] In other processes, such as in CSS (Cyclic Steam Stimulation), the
same well
is used both for injecting a fluid and for producing oil. In CSS, cycles of
steam injection,
soak, and oil production are employed. Once the production rate falls to a
given level, the
well is put through another cycle of injection, soak, and production. An
example of CSS is
described in U.S. Patent No. 4,280,559 (Best).
[0005] Steam Flood (SF) involves injecting steam into the formation through
an
injection well to provide stream drive. Steam moves through the formation,
mobilizing oil as
it flows toward the production well. Mobilized oil is swept to the production
well by the steam
drive. An example of steam flooding is described in U.S. Patent No. 3,705,625
(Whitten).
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[0006] Other thermal processes include Solvent-Assisted Steam Assisted
Gravity
Drainage (SA-SAGD), an example of which described in Canadian Patent No.
1,246,993
(Vogel); Vapour Extraction (VAPEX), an example of which is described in U.S.
Patent No.
5,899,274 (Frauenfeld); Liquid Addition to Steam for Enhanced Recovery
(LASER), an
example of which is described in U.S. Patent No. 6,708,759 (Leaute et al.);
and combined
Steam and Vapour Extraction Process (SAVEX), an example of which is described
in U.S.
Patent No. 6,662,872 (Gutek).
[0007] As is well known in the art, in order to prepare a well for
injection or
production, it is necessary to "complete" the well after the borehole is
drilled. Completing a
well typically includes casing the well, which means inserting a casing into a
drilled section of
the borehole. The casing is typically held in place by cement. Completion also
typically
includes inserting a tubing string within the casing, in the injection or
production section of
the well. The tubing string is typically sealed off from the casing with a
packer.
Conventionally, packers are used to provide a downhole seal between the tubing
string and
the surrounding casing in order to prevent the flow of fluids through a
portion of a wellbore
annulus defined between the tubing string and the casing. Packers are
desirable for a
number of uses, including providing a seal or barrier such that fluid may be
selectively
injected to or at a desired level in the wellbore to a desired zone within the
surrounding
formation.
[0008] Where the recovery process involves high-pressure steaming of
wells, such
as in CSS, it is necessary to conduct a casing integrity test prior to steam
injection to ensure
that the well will survive steaming. The main component of a casing integrity
test is a
pressure test of the casing. Typically, a service rig is required to remove
the tubing to
pressure test the well. The service rig is moved on the well and the well is
killed. The pump
and rod are then removed from the well. The tubing is removed and a scraper
and drift
assembly is run to clean the casing and test for anomalies. A packer is run
and set and the
casing is pressure tested. The tubing is run back into the well and then the
pump and rod are
run back in.
SUMMARY
[0009] Generally, the present disclosure describes a packer that is ported
to provide
fluid communication through the packer between the wellbore annulus above the
packer and
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the wellbore annulus below the packer. Such a ported packer can be used to
allow for
pressure testing the casing and/or for controlling a failed well.
[0010] In one aspect, the present disclosure provides a method of pressure
testing a
well casing, the well casing having disposed therein a packer and a tubing
string, the packer
having ports for providing fluid communication through the packer between a
wellbore
annulus above the packer and a wellbore annulus below the packer, the method
comprising:
injecting fluid and soluble perforation sealer balls to plug the ports in the
packer; bringing the
well casing up to a testing pressure to pressure test the well casing and then
reducing the
pressure; and shutting in the well casing until the well casing goes on vacuum
indicating that
the sealer balls have dissolved, thereby unplugging the ports.
[0011] In another aspect, the present disclosure provides a method of
controlling a
failed well having a well casing, the well casing having disposed therein a
packer and a
tubing string, the packer having ports for providing fluid communication
through the packer
between a wellbore annulus above the packer and a wellbore annulus below the
packer, the
method comprising: pressuring up the tubing string to create an aperture in
the tubing string;
pumping fluid and solid floating balls down the tubing string and out the
aperture;
once the balls are below the packer, flowing the well casing to allow the
balls to plug the
ports; allowing a well casing pressure to drop, and then bleeding off the well
casing to below
fracture pressure at a break in the well casing of the failed well;
maintaining pressure below
fracture pressure until reservoir pressure drops to a level where the well
casing can be
repaired; and circulating out the balls during well casing repair.
[0012] Other aspects and features of the present disclosure will become
apparent to
those ordinarily skilled in the art upon review of the following description
of specific
embodiments in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] Embodiments of the present disclosure will now be described, by way of
example only, with reference to the attached Figure.
[0014] Fig. 1 illustrates a ported packer in accordance with a disclosed
embodiment.
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DETAILED DESCRIPTION
[0015] The term "viscous oil" as used herein means a hydrocarbon, or mixture
of
hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
(centipoise) at
initial reservoir conditions. Viscous oil includes oils generally defined as
"heavy oil" or
"bitumen". Bitumen is classified as an extra heavy oil, with an API gravity of
about 100 or
less, referring to its gravity as measured in degrees on the American
Petroleum Institute
(API) Scale. Heavy oil has an API gravity in the range of about 22.3 to about
10 . The terms
viscous oil, heavy oil, and bitumen are used interchangeably herein since they
may be
extracted using similar processes.
[0016] "In situ" is a Latin phrase for "in the place" and, in the context of
hydrocarbon
recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. An
in situ
hydrocarbon recovery technique is one that recovers hydrocarbons from a
reservoir within
the earth.
[0017] As described above, the packer described herein is ported to provide
fluid
communication through the packer between the wellbore annulus above the packer
and the
wellbore annulus below the packer. Such a ported packer can be used to allow
for pressure
testing the casing and/or controlling a failed well.
[0018] Ported Packer
[0019] Figure 1 illustrates a ported packer in accordance with one embodiment.
The
packer (100) is disposed within a casing (102) and holds a tubing string (104)
in place.
Regular collars (106a and 106b), a NoGo collar (108), and a shaved and beveled
collar (110)
are also shown. Regular and shaved and beveled collars are standard equipment
for joining
jointed tubing together in a well. A shaved and beveled collar is a modified
regular collar that
has some material removed from its outside diameter and ends by turning it on
a lathe to
make it pass through restrictions in the wellbore more easily and with less
chance of catching
on sharp edges. A NoGo collar is a collar with a larger outside diameter that
is larger than a
restriction in the well so the tubing cannot pass that point.
[0020] The packer (100) comprises a top sub (112) and a bottom sub (114). The
subs (112 and 114) are attached to the top and bottom of the packer and
include top ports
(120a) and bottom ports (120b). The ports (120a and 120b) allow the annular
flow to bypass
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the packer (100). The subs (112 and 114) are threaded on their ends for
attachment to the
packer (100) and the seal bore.
[0021] A top seal bore (116) is attached to the top of the top sub (112). A
bottom
seal bore (118) is attached to the bottom of the bottom sub (114). The seal
bores are tubular
sections of pipe that are polished inside to allow seals to move up and down
inside making a
seal while preventing (or mitigating) wear of the seals. A stringer assembly
(105) is part of
the tubing string (104) and holds the seals that seal inside the seal bores
(116 and 118) and
allow thermal movement of the tubing string without loss of the ability to
isolate the annulus
above the packer (100) from the annulus below the packer (100).
[0022] The top sub (112) includes the top ports (120a) and the bottom sub
(114)
includes the bottom ports (120b) to provide fluid or gas communication through
the packer
(100) between the wellbore annulus above the packer (100) and the wellbore
annulus below
the packer (100). The size of the ports (120a and 120b) could be, for
instance, half an inch
in diameter to three quarters an inch in diameter. The size of the ports could
be larger,
depending on the size of the packer. The ports may be circular in cross-
section or may be
another shape. The number of ports may be, for instance, between 4 and 16, but
the
number may vary depending on the size of the packer and the desired pressure
drop across
the packer.
[0023] During steaming down the casing (102), steam flows through the top
ports
(120a) in the top sub (112), through the inside of the packer (100), and then
out the bottom
ports (120b) in the bottom sub (114) defining an annular flow path (122). The
annular flow
path (122) is illustrated in Figure 1. Steam flow would only be restricted by
the annular flow
path (122) to a small extent. The tubing (104) can float in the seal bores
(116 and 118)
during thermal movement.
[0024] An alternate design for the packer would be to remove the seal bores
(116
and 118) and the stinger assembly (105) and replace them with a thermal tubing
expansion
joint above the packer. The packer would then be attached to the tubing string
(104) and
thermal expansion of the tubing would take place within the expansion joint.
The tubing
expansion joint is a tubular device which allows thermal growth or compression
of the tubing
string but maintains pressure containment between the tubing and the annulus.
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[0025] Pressure Testing a Casing using the Ported Packer
[0026] To pressure test a casing, fluid and soluble perforation ball sealers
are
injected down the casing having a ported packer. A pressure pumping truck may
be used to
pump the fluid. The fluid may be water or another non-compressible fluid.
Soluble
perforation ball sealers are known in the art, and an example are BioBallsTM,
which are
available from Santrol Oil and Gas Stimulation Products (Fresno, Texas, United
States). The
ball sealers should be soluble in the liquid used to pressure test the casing
and should
dissolve in a manner that leaves only minimal residue behind. The balls should
be stable at
the temperatures experienced in the wellbore at the depth of the ported packer
yet dissolve
in a short length of time so as not to have the well shut in for a long period
of time. The balls
plug the top ports in the top sub. Next, the pressure is raised to a
predetermined point to test
the casing and is then released. After the test, the well is shut in until it
goes on vacuum
indicating that the balls have dissolved. The well is then put back on
production.
[0027] Controlling a Casing Failure using a Ported Packer
[0028] Such a ported packer may have the added advantage of being able to
control
a high-pressure casing failure. When a well fails (meaning that the casing can
no longer
retain pressure) because of a break in the well casing, reservoir fluid starts
flowing to and out
the break above the packer. After a well fails, one would land a pump,
pressure up the
tubing, and create an aperture in the well tubing. A common way to create such
an aperture
is to blow the burst. The burst is a window style pressure relief tool that,
at a predetermined
pressure, shears a rectangular hole out the side of the tubing giving access
to the annulus
from the tubing and relieves high pressure in the tubing before it gets high
enough to burst
the tubing. Next, floating solid ball sealers are pumped down the tubing with
a fluid which
could be hot water or another stable non-compressible fluid with a specific
gravity low
enough to ensure that the balls float. The balls are pumped out the burst.
Once the ball
sealers are below the packer, the casing pressure is bled off until the ball
sealers plug the
bottom ports in the bottom sub. Once the casing pressure drops, the casing is
bled off to
below fracture pressure at the break. The casing is then kept below the
fracture pressure at
the break until the well is at a low enough pressure to be worked on. The
balls can be
circulated out during casing repair.
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[0029] For use in thermal oil wells, the solid floating ball sealers should
be capable of
floating in the pumped fluids and be stable at the high temperatures
experienced in a thermal
oil well. In this case, the balls should be capable of withstanding
temperatures of over
300 C.
[0030] In a thermal oil well, produced water can boil or flash off leaving a
scale
behind that can plug off small spaces. To address a potential concern of
scaling across the
packer, one could use an acid wash before pressure testing to ensure the ports
are not
restricted.
[0031] This assembly could be run in a well after its first casing integrity
check, for
instance in cycle six or seven. A cycle is defined as the period of time from
when steam is
injected in the well to when steam is again injected into a well and includes
the soaking
period after steam but before production and the production period. This would
allow for an
analysis of the wellbore and pad damage. Subsequent casing checks could be
replaced with
pressure tests using a ported packer as described herein.
[0032] It would also be possible to run in a ported packer in the well before
the first
steam cycle and use it to pressure test the well every cycle ensuring casing
integrity is good
before every steam cycle.
[0033] Hydrocarbon Recovery Processes
[0034] The ported packer and methods described herein may be used in a
variety of
hydrocarbon recovery processes, including those described in the background
section. As
described in the background section, in recovery processes involving high-
pressure steaming
of wells, such as in CSS, it is necessary to periodically conduct a casing
integrity test prior to
steam injection to ensure that the well will survive steaming.
[0035] Potential advantages
[0036] By using this type of ported packer, one could check the casing
integrity of a
well by checking the pressure without having to pull out the tubing and could
result in less
downtime of the well and reduce the costs associated with testing the casing
integrity.
[0037] By using this type of ported packer, one has the ability to control a
casing
failure in a high-pressure regime. The conventional operating procedure in
response to a
high pressure casing failure consists of killing the well with heavy mud. This
procedure can
take roughly 2 days, whereas the ported packer well control procedure may take
approximately one half day.
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[0038] In the preceding description, for purposes of explanation, numerous
details
are set forth in order to provide a thorough understanding of the embodiments.
However, it
will be apparent to one skilled in the art that these specific details are not
required. In other
instances, well-known electrical structures and circuits are shown in block
diagram form in
order not to obscure the understanding.
[0039] The above-described embodiments are intended to be examples only.
Alterations, modifications and variations can be effected to the particular
embodiments by
those of skill in the art without departing from the scope, which is defined
solely by the claims
appended hereto.
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