Note: Descriptions are shown in the official language in which they were submitted.
, CA 02934362 2016-06-28
METHOD OF SEALING WELLS BY SQUEEZING SEALANT
BACKGROUND OF THE DISCLOSURE
Field of the Disclosure
The present disclosure generally relates to a method of sealing wells by
squeezing a sealant into an annulus thereof.
Description of the Related Art
The hard impermeable sheath deposited in the annular space in a well by
primary cementing is subjected to a number of stresses during the lifetime of
the well.
The pressure inside the casing can increase or decrease as the fluid filling
it changes
or as additional pressure is applied to the well, such as when the drilling
fluid is
replaced by a completion fluid or by a fluid used in a stimulation operation.
A change
of temperature also creates stress in the cement sheath, at least during the
transition
period before the temperatures of the steel and the cement come into
equilibrium. As a
result of pressure and temperature changes, the integrity of the cement sheath
can be
compromised. Thus, it can become necessary to repair the primary cement
sheath,
such as during a plug and abandonment operation. One way to repair the primary
cement sheath is by squeeze cementing, i.e., squeezing Portland cement
thereinto.
The use of conventional Portland cement for squeeze cementing has
limitations, for instance, if the primary cement sheath is leaking fluid, such
as gas,
through micro-channels, squeeze cementing is not feasible, even using micro-
fine
ground Portland cement.
SUMMARY OF THE DISCLOSURE
The present disclosure generally relates to a method of sealing wells by
squeezing sealant into the annulus between the inner and outer tubular
strings. In one
embodiment, a method for sealing a well includes: placing an obstruction in a
bore of
an inner tubular string disposed in a wellbore; forming an opening through a
wall of the
inner tubular string above the obstruction; mixing a resin and a hardener to
form a
sealant; and squeezing the sealant into the bore, through the opening, and
into an
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annulus formed between the inner tubular string and an outer tubular string,
thereby
repairing a cement sheath present in the annulus.
In another embodiment, a method for sealing a well includes: placing an
obstruction in a bore of an inner tubular string disposed in a wellbore;
forming an
opening through a wall of the inner tubular string above the obstruction;
mixing a resin
and a hardener to form a sealant; and squeezing the sealant into the bore,
through the
opening, and into an annulus formed between the inner tubular string and the
wellbore, thereby repairing a cement sheath present in the annulus.
BRIEF DESCRIPTION OF THE DRAWINGS
So that the manner in which the above recited features of the present
disclosure can be understood in detail, a more particular description of the
disclosure,
briefly summarized above, may be had by reference to embodiments, some of
which
are illustrated in the appended drawings. It is to be noted, however, that the
appended
drawings illustrate only typical embodiments of this disclosure and are
therefore not to
be considered limiting of its scope, for the disclosure may admit to other
equally
effective embodiments.
Figure 1 illustrates delivery of an equipment package to a platform for
performing the squeeze operation, according to one embodiment of the present
disclosure.
Figure 2A illustrates perforation of a production casing string. Figure 2B
illustrates deployment of a sealing string.
Figures 3A-3C illustrate operation of a mixing unit of the equipment package
to
form sealant.
Figure 4 illustrates squeezing of the sealant into an annulus formed between
the production casing string and a surface casing string.
Figures 5A and 5B illustrate a first alternative sealing operation, according
to
another embodiment of the present disclosure.
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Figures 6A and 6B illustrate a second alternative sealing operation, according
to another embodiment of the present disclosure.
Figures 7A and 7B illustrate a third alternative sealing operation, according
to
another embodiment of the present disclosure.
DETAILED DESCRIPTION
Figure 1 illustrates an illustrative equipment package 1 used for performing
the
squeeze operation, and located on a platform 2, according to one embodiment of
the
present disclosure. The platform 2 may be part of a well 3 further including a
subsea
wellbore 4, a drive pipe 5, a surface casing string 6, a production casing
string 7, and a
production tubing string 8. The drive pipe 5 is commonly set from above a
surface 9s
(aka waterline) of the sea 9, through the sea, and into the seafloor 9f (aka
mudline).
The drive pipe 5 allows the wellhead (not shown) to be located on the platform
2
above the waterline 9s.
Once the drive pipe 5 has been set, and (if desired cemented 10a, the subsea
wellbore 4 is drilled into the seafloor 9f within the envelope of the drive
pipe 5. The
surface casing string 6 is then run-in the drive pipe 5 and into the wellbore
4 and
cemented into place by forming a cement sheath 10b. When the wellbore 4
reaches
a hydrocarbon-bearing formation 11, i.e., crude oil and/or natural gas, the
production
casing 7 is run-into the wellbore 4 and cemented into place with cement sheath
10c.
Thereafter, the production casing string 7 is perforated 12 to permit the
fluid
hydrocarbons (not shown) to flow into the interior thereof. The hydrocarbons
are
transported from the formation 11 through the production tubing string 8. An
annulus
13 defined between the production casing string 7 and the production tubing
string 8 is
commonly isolated from the producing formation 11 with a production packer 14.
During production of hydrocarbons from the well 3, it may become necessary to
workover the well, install an artificial lift system, and/or stimulate or
treat the formation
11. To facilitate any of these operations, it is typically desirable to
temporarily plug the
well 3. Also, once the formation 11 has been produced to depletion,
regulations often
require permanently plugging the well 3 prior to abandoning the well 3. If
either or
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both of the cement sheathes 10b,c have become compromised, they will need to
be
repaired during either the temporary or permanent plugging and abandonment
operation, using the squeeze operation.
In order to prepare for the squeeze operation, the equipment package 1 is
delivered to the platform 2 via a transport vessel (not shown). The equipment
package
1 includes a coiled tubing unit 15, a mixing unit 16, and a squeeze pump 17.
The
coiled tubing unit 15 includes a drum having coiled tubing 22 (Figure 2B)
wrapped
therearound, a gooseneck, an injector head for driving the coiled tubing,
controls, and
a hydraulic power unit. A wireline winch 18 onboard the platform 2 may also be
used
to facilitate the squeeze operation. The wireline winch 18 typically includes
a drum
having wireline 19 (Figure 2A) wrapped therearound and a motor for winding and
unwinding the wireline, thereby raising and lowering a distal end of the
wireline relative
to the platform 2.
Figure 2A illustrates perforation of the production casing string 7. Figure 2A
shows the condition of the well during an abandonment or closing in operation,
wherein a lower cement plug 21 has been set and the production tubing string 8
has
been cut. To establish this condition, the well 3 abandonment operation
commences
by connecting a bottomhole assembly (BHA) (not shown) to the wireline 19
extending
through a lubricator (not shown). In the embodiment, the BHA includes a
cablehead, a
collar locator, and a tubing perforator, such as a perforating gun.
To deploy the BHA into the well bore, one or more valves of the tree are
opened and the BHA is deployed into the production tubing string in the
wellbore 4
using the wireline 19. The BHA is deployed to a depth adjacent to and above
the
production packer 14. Once the BHA has been deployed to the desired depth,
electrical power or an electrical signal is supplied to the BHA via the
wireline 19 to fire
the perforating gun into the production tubing string 8, thereby forming
tubing
perforations 20 through the wall thereof. The BHA is retrieved to the
lubricator and the
lubricator is then removed from the production tree.
Cement slurry (not shown) is then pumped through the production tree head,
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down the production tubing string 8, and into the annulus 13 via the created
tubing
perforations 20. Wellbore fluid displaced by the cement slurry will flow up
the annulus
13, through the wellhead and to the platform 2. Once a desired quantity of
cement
slurry has been pumped into the annulus 13, an annulus valve of the wellhead
is
closed while continuing to pump the cement slurry, thereby forcing or
"squeezing"
cement slurry into the adjacent formation 11. Once pumped into place, the
cement
slurry is allowed to cure for a predetermined amount of time, such as one
hour, six
hours, twelve hours, or one day, thereby forming the cement plug 21 in the
annulus,
the surrounding formation, and within the lower portion of the production
tubing string
8.
Once the cement plug 21 has cured, a second BHA (not shown) is connected to
the wireline 19 in the lubricator and deployed through the production tree.
The second
BHA commonly includes a cablehead, a collar locator, an anchor, a hydraulic
power
unit (HPU), an electric motor, and a tubing cutter. The second BHA is deployed
into
the production tubing string 8 to a depth adjacent to and above the production
packer
14. Once the second BHA has been deployed to the cutting depth, the HPU is
operated by supplying electrical power via the wireline 19 to extend blades of
the
tubing cutter and operate the motor to rotate the extended blades, thereby
severing an
upper portion of the production tubing string 8 from a lower portion thereof.
The
second BHA is then retrieved to the lubricator and the lubricator is removed
from the
production tree. The production tree is removed from the wellhead and the
severed
upper portion of the production tubing string 8 is removed from the wellbore
4, leaving
the wellbore in the state shown in Fig. 2A.
Once the severed portion of the production tubing string 8 has been removed, a
third BHA (not shown) is connected to the wireline 19 in the lubricator and
deployed
through the wellhead. The third BHA commonly includes a cablehead, a collar
locator,
a setting tool, and a bridge plug 23. The third BHA is deployed to a setting
depth
along a portion of the production casing string 7 adjacent, and above, the
lower
terminus of the surface casing string 6. Once the third BHA has been deployed
to the
setting depth, electrical power is supplied to the third BHA via the wireline
19 to
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operate the setting tool, thereby expanding the bridge plug 23 against an
inner surface
of the production casing string 7. Once the bridge plug 23 has been set as
shown in
Fig. 2A, the bridge plug 23 is released from the setting tool. The third BHA
(minus the
bridge plug 23) is then retrieved to the lubricator and the lubricator is
removed from the
wellhead.
A fourth BHA 24 is then connected to the wireline 19 in the lubricator and
deployed through the wellhead. The fourth BHA 24 commonly includes a
cablehead, a
collar locator, and a casing perforator, such as a perforating gun. The fourth
BHA 24
is deployed to a firing depth adjacent to and above the bridge plug 23. Once
the fourth
BHA 24 has been deployed to the firing depth, electrical power or an
electrical signal is
supplied to the fourth BHA via the wireline 19 to fire the perforating gun
into the
production casing string 7, thereby forming casing perforations 25 through a
wall
thereof as shown in Fig. 2A. The fourth BHA 24 is then retrieved to the
lubricator and
the lubricator is removed from the wellhead.
Figure 2B illustrates deployment of a sealing string. A fifth BHA 26 is
connected to the coiled tubing 22 in a snubbing unit (not shown) and deployed
through
the wellhead. The fifth BHA 26 includes a squeeze packer and a setting tool.
The
injector head of the coiled tubing unit 15 is operated to lower the fifth BHA
26 to a
squeezing depth adjacent to and above the casing perforations 25. Once the
fifth BHA
26 has been deployed to the squeezing depth, the squeeze pump 17 is operated
to
pump a setting plug (not shown), such as a ball, through the coiled tubing 22
to a seat
of the setting tool. Fluid pressure may then be exerted on the seated ball to
operate
the setting tool, thereby expanding the squeeze packer against an inner
surface of the
production casing string 7 to thereby seal the annuals between the coiled
tubing 22
and the production casing string 7. In the embodiment, additional fluid
pressure is
then applied to drive the ball through the seat of the setting tool, thereby
reopening the
bore of the coiled tubing 22.
Figures 3A-3C illustrate operation of the mixing unit 16 to form sealant 28.
The
mixing unit 16 in the embodiment includes two or more liquid totes 29a,b, and
a
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transfer pump 30a, b for each liquid tote, a dispensing hopper 31, and a
blender 32.
Each transfer pump 30a,b is, in the embodiment, a metering pump and the
dispensing
hopper 31 is a metering hopper. An inlet of each transfer pump 30a,b is
connected to
a respective liquid tote 29a,b.
A first liquid tote 29a of the liquid totes 29a,b includes a resin 33r. The
resin 33r
may be an epoxide, such as bisphenol F. The viscosity of the sealant 28 may be
adjusted by premixing the resin 33r with a diluent, such as alkyl glycidyl
ether or
benzyl alcohol. The viscosity of the sealant 28 may range between fifty and
two
thousand centipoise. The epoxide may also be premixed with a bonding agent,
such
as silane. A second liquid tote 29b of the liquid totes 29a,b may include a
hardener
33h selected based on the temperature in the wellbore 4. The contents of the
liquid
totes 29a, b may be reversed. For low temperature applications, the hardener
33h
may be an aliphatic amine or polyamine or a cycloaliphatic amine or polyamine,
such
as tetraethylenepentamine. For high temperature applications, the hardener 33h
may
be an aromatic amine or polyamine, such as diethyltoluenediamine. The
dispensing
hopper 31 includes a particulate weighting material 34 having a specific
gravity of at
least two. The weighting material 34 may be barite, hematite, hausmannite ore,
or
sand.
Alternatively, wellbore fluid may be non-aqueous and the resin 33r may also be
premixed with a surfactant to maintain cohesion thereof. Alternatively, the
resin 33r
may also be premixed with a defoamer.
To form the sealant 28, the first transfer pump 30a is operated to dispense
the
resin 33r into the blender 32. A motor of the blender 32 is then activated to
churn the
resin 33r. The hopper 31 is then operated to dispense the weighting material
34 into
the blender 32. The weighting material 34 is added, as required, in a
proportionate
quantity such that a density of the sealant 28 corresponds to a density of the
wellbore
fluid. The density of the sealant 28 may be equal to, slightly greater than,
or slightly
less than the density of the wellbore fluid.
The second transfer pump 30b is operated to dispense the hardener 33h into
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the blender 32. The hardener 33h is added in a proportionate quantity such
that the
thickening time of the sealant 28 corresponds to the time required to pump the
sealant
through the coiled tubing 22, plus the time required to squeeze the sealant
into the
annulus 36 (Figure 4) formed between the production casing string 7 and the
surface
casing string 6, plus a safety factor, such as one hour. Once the blender 32
has
formed the components of the sealant 28 into a homogenous mixture, a supply
valve
35 connecting the outlet of the blender ultimately to the squeeze pump 17 may
be
opened.
Figure 4 illustrates squeezing of the sealant 28 into the annulus 36. The
squeeze pump 17 is operated to pump the sealant 28 from the blender 32 and
into the
coiled tubing 22. The pumping may be monitored using the pressure gauge 37 of
the
equipment package 1. Once the sealant 28 has been pumped into the coiled
tubing
22 downstream of the squeeze pump 17, the inlet of the squeeze pump 17 is then
connected to a supply of chaser fluid (not shown), such as seawater, and the
squeeze
pump 17 is operated to pump the chaser fluid into the coiled tubing 22,
thereby driving
the sealant 28 through the coiled tubing 22 and into the annulus 36 via the
casing
perforations 25. The sealant 28 flows into or through voids in the cement
sheath 10c
present in the annulus 36, thereby filling the voids and restoring the
integrity of the
cement sheath 10c. As the stroke volume of the squeeze pump may be known or
calculated, a stroke counter of the squeeze pump 17 may be monitored during
pumping and the squeeze pump shutoff once a desired volume of the chaser fluid
has
been pumped based on a certain number of strokes, corresponding to the
internal
volume of the coiled tubing 22 extending from the squeeze pump 17, thereby
ensuring
that all of the sealant 28 has been discharged from the coiled tubing 22. A
portion of
the sealant 28 also typically forms a bore plug in the production casing
string 7. The
sealant 28 may also plug a portion of the cement sheath 10c adjacent to the
surface
casing string 6.
The squeeze packer is then unset, such as by exerting tension on (pulling on)
the coiled tubing 22. The coiled tubing 22 and the fifth BHA 26 is retrieved
to the
platform 2 and the sealant is allowed to cure for a time, such as between one
to five
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days. lithe abandonment operation is permanent, once the sealant 28 has cured,
the
drive pipe 5, surface casing string 6, and production casing string 7 will
typically be cut
at or just below the seafloor 9f, thereby completing the abandonment
operation.
Figures 5A and 5B illustrate a first alternative sealing operation, according
to
another embodiment of the present disclosure. In this alternative method of
sealing, a
sixth BHA 27 is deployed instead of the fourth BHA 24. The sixth BHA 27 is
deployed
to the firing depth adjacent to and above the bridge plug 23. The sixth BHA 27
is
similar to the fourth BHA 24 except for having a deep casing perforator, such
as a
perforating gun, instead of the casing perforator. The deep casing perforating
gun has
a charge strength sufficient to form deep perforations 38 through the walls of
the
production 7 and surface 6 casing strings and the cement sheath 10c without
damaging the wall of the drive pipe 5, thereby establishing access to the
cement
sheath 10b in an annulus 39 formed between the production and surface casing
strings. After performing the perforation step, the sixth BHA 27 is retrieved
to the
lubricator and the lubricator is removed from the wellhead.
The fifth BHA 26 is then connected to the coiled tubing 22 and the injector
head
of the coiled tubing unit 15 is operated to lower the fifth BHA to the
squeezing depth
adjacent to and above the deep perforations 38. Once the fifth BHA 26 has been
deployed to the squeezing depth, the squeeze packer of the fifth BHA 26 is
set. The
squeeze pump 17 is operated to pump the sealant 28 from the blender 32 and
into the
coiled tubing 22 and then to chase the sealant with a secondary fluid such as
seawater, thereby driving the sealant 28 through the coiled tubing 22 and into
the
annuli 36, 39 via the casing perforations 38. The sealant 28 flows into and
through
voids in the cement sheathes 10b,c present in the respective annuli 36, 39,
thereby
filling the voids and restoring the integrity thereof. The sealant 28 may also
plug a
portion of the cement sheath 10c adjacent to the surface casing string 6 and a
portion
of the cement sheath 10b adjacent to the drive pipe 5.
Figures 6A and 6B illustrate a second alternative sealing operation, according
to another embodiment of the present disclosure. In this second alternative
sealing
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method, the third BHA is deployed into the production casing string 7 to an
alternative
setting depth adjacent to a top of the severed production tubing string 8 and
adjacent
to the wellbore wall instead of along a portion of the production casing
string 7
adjacent to the surface casing string 6. Once the third BHA has been deployed
to the
alternative setting depth, the bridge plug 23 is set and released from the
setting tool.
The third BHA (minus the bridge plug 23) is then be retrieved to the
lubricator and the
lubricator is then removed from the wellhead.
The fourth BHA 24 is then connected to the wireline 19 in the lubricator and
deployed through the wellhead. The fourth BHA 24 is deployed to an alternative
firing
depth adjacent to and above the bridge plug 23. Once the fourth BHA 24 has
been
deployed to the alternative firing depth, electrical power or an electrical
signal is
supplied to the fourth BHA via the wireline 19 to fire the perforating gun
into the
production casing string 7, thereby forming alternative casing perforations 40
through
a wall thereof. The fourth BHA 24 is then retrieved to the lubricator and the
lubricator
is removed from the wellhead.
The fifth BHA 26 is then connected to the coiled tubing 22 and the injector
head
of the coiled tubing unit 15 is operated to lower the fifth BHA to an
alternative
squeezing depth adjacent to and above the alternative casing perforations 40.
Once
the fifth BHA 26 has been deployed to the alternative squeezing depth, the
squeeze
packer of the fifth BHA 26 is set. The squeeze pump 17 is operated to pump the
sealant 28 from the blender 32 and into the coiled tubing 22 and then to chase
the
sealant with a secondary fluid such as seawater, thereby driving the sealant
28
through the coiled tubing 22 and into the annulus 36 via the alternative
casing
perforations 40. The sealant 28 flows into and through the voids in the cement
sheath
10c present in the annulus 36 thereby filling the voids and restoring the
integrity of the
cement sheath. The sealant 28 thus plugs a portion of the cement sheath 10c
adjacent to the wellbore wall.
Figures 7A and 7B illustrate a third alternative sealing operation, according
to
another embodiment of the present disclosure. In this alternative, the bridge
plug 23 is
CA 02934362 2016-06-28
set at the alternative setting depth. The sixth BHA 27 is then deployed to a
second
alternative firing depth adjacent to and above a shoe of the surface casing
string 6 and
fired to form alternative deep perforations 41 through walls of the production
7 and
surface 6 casing strings and the cement sheath 10c.
The fifth BHA 26 is then connected to the coiled tubing 22 and the injector
head
of the coiled tubing unit 15 is operated to lower the fifth BHA to a second
alternative
squeezing depth adjacent to and above the alternative deep perforations 41.
Once the
fifth BHA 26 has been deployed to the second alternative squeezing depth, the
squeeze packer of the fifth BHA 26 is set. The squeeze pump 17 is operated to
pump
the sealant 28 from the blender 32 and into the coiled tubing 22 and then to
chase the
sealant with an alternative fluid such as seawater, thereby driving the
sealant 28
through the coiled tubing 22 and into the annuli 36, 39 via the casing
perforations 38.
The sealant 28 flows into and through voids in the cement sheathes 10b,c
present in
the respective annuli 36, 39, thereby filling the voids and restoring the
integrity thereof.
The sealant 28 plugs a portion of the cement sheath 10c adjacent to the
surface
casing string 6 and a portion thereof adjacent to the wellbore wall. The
sealant 28 may
also plug a portion of the cement sheath 10b adjacent to the wellbore wall.
Alternatively, a pipe string is used instead of the coiled tubing 22 to
transport
the sealant into the wellbore 4. The pipe string typically includes joints of
drill pipe or
production tubing connected together, such as by threaded couplings.
Alternatively, a cement plug is used instead of or in addition to the bridge
plug
23.
Alternatively, the well 2 may further include one or more intermediate casing
strings between the surface 6 and production 7 casing strings and the sealant
is
squeezed into one or more annuli formed between the production casing string
and
the intermediate casing strings. Alternatively, the sealant is squeezed into
an annulus
formed between a liner string and a casing string and/or between the liner
string and
the wellbore wall.
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Alternatively, the wellbore 4 may be subsea having a wellhead located adjacent
to the seafloor and any of the sealing operations may be staged from an
offshore
drilling unit or an intervention vessel.
Alternatively, the wellbore 4 may be
subterranean and any of the sealing operations may be staged from drilling or
workover rig located on a terrestrial pad adjacent thereto.
While the foregoing is directed to embodiments of the present disclosure,
other
and further embodiments of the disclosure may be devised without departing
from the
basic scope thereof, and the scope of the invention is determined by the
claims that
follow.
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