U.S. patent application number 15/185334 was filed with the patent office on 2017-02-16 for method of sealing wells by squeezing sealant.
The applicant listed for this patent is CSI Technologies LLC. Invention is credited to David BROWN, Jorge Esteban LEAL, Clifton MEADE, Fred SABINS, Jeffrey WATTERS.
Application Number | 20170044864 15/185334 |
Document ID | / |
Family ID | 56292557 |
Filed Date | 2017-02-16 |
United States Patent
Application |
20170044864 |
Kind Code |
A1 |
SABINS; Fred ; et
al. |
February 16, 2017 |
METHOD OF SEALING WELLS BY SQUEEZING SEALANT
Abstract
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 an outer
tubular string, thereby repairing a cement sheath present in the
annulus.
Inventors: |
SABINS; Fred; (Montgomery,
TX) ; MEADE; Clifton; (Houston, TX) ; BROWN;
David; (Cypress, TX) ; WATTERS; Jeffrey;
(Spring, TX) ; LEAL; Jorge Esteban; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
CSI Technologies LLC |
Houston |
TX |
US |
|
|
Family ID: |
56292557 |
Appl. No.: |
15/185334 |
Filed: |
June 17, 2016 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
62203140 |
Aug 10, 2015 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/12 20130101;
E21B 33/14 20130101 |
International
Class: |
E21B 33/14 20060101
E21B033/14; E21B 33/12 20060101 E21B033/12 |
Claims
1. A method for sealing a well, comprising: 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 an
outer tubular string, thereby repairing a cement sheath present in
the annulus.
2. The method of claim 1, wherein: the annulus is an inner annulus,
the opening is also formed through a wall of the outer tubular
string, and the sealant is also squeezed into an outer annulus,
thereby repairing a cement sheath present in the outer annulus.
3. The method of claim 1, wherein the inner and outer tubular
strings are both casing strings.
4. The method of claim 1, further comprising squeezing at least a
portion of the sealant into a formation into which the inner
tubular sting extends.
5. The method of claim 1, further comprising squeezing at least a
portion of the sealant into a formation into which the outer
tubular sting extends.
6. The method of claim 1, wherein the squeezing of the sealant into
the bore, through the opening, and into an annulus formed between
the inner tubular string and an outer tubular string comprises;
pumping the sealant through a tubular extending into the inner
tubular string and having a fluid volume; and thereafter pumping a
quantity of chaser fluid into the tubular having at least the
volume of the tubular.
7. The method of claim 1, wherein: the sealant is squeezed into the
bore through coiled tubing, and the method further comprises:
lowering the coiled tubing and a bottom hole assembly (BHA) through
the bore; and forming the obstruction by setting a squeeze packer
of the BHA against an inner surface of the inner tubular
string.
8. The method of claim 1, wherein: the wellbore is a subsea
wellbore, the method further comprises, prior to placing the
obstruction: severing an upper portion of a production tubing
string disposed in the wellbore from a lower portion thereof; and
removing the upper portion of the production tubing string from the
wellbore.
9. The method of claim 1, wherein: the resin is bisphenol F
epoxide, the hardener is selected from a group consisting of
tetraethylenepentamine for a low temperature well and
diethyltoluenediamine for a high temperature well, and the resin is
premixed with a diluent selected from a group consisting of alkyl
glycidyl ether and benzyl alcohol, and a weighting material having
a specific gravity of at least 2 is mixed with the resin and the
hardener.
10. A method for sealing a well, comprising: 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.
11. The method of claim 10, wherein: the annulus is an inner
annulus, the opening is also formed through a wall of an outer
tubular string, and the sealant is also squeezed into an outer
annulus, thereby repairing a cement sheath present in the outer
annulus.
12. The method of claim 10, wherein the inner tubular string is a
casing string.
13. The method of claim 10, wherein: the sealant is squeezed into
the bore through coiled tubing, and the method further comprises:
lowering the coiled tubing and a bottom hole assembly (BHA) through
the bore; and setting a squeeze packer of the BHA against an inner
surface of the inner tubular string.
14. The method of claim 10, wherein: the wellbore is a subsea
wellbore, the method further comprises, prior to placing the
obstruction: severing an upper portion of a production tubing
string disposed in the wellbore from a lower portion thereof; and
removing the upper portion of the production tubing string from the
wellbore.
15. The method of claim 1, wherein: the resin is bisphenol F
epoxide, the hardener is selected from a group consisting of
tetraethylenepentamine for a low temperature well and
diethyltoluenediamine for a high temperature well, and the resin is
premixed with a diluent selected from a group consisting of alkyl
glycidyl ether and benzyl alcohol.
16. The method of claim 10, wherein the density of the sealant
corresponds to the density of fluid present in the well.
17. The method of claim 10, wherein a viscosity of the sealant is
between 50-2,000 cp.
18. The method of claim 10, wherein: the resin is premixed with a
bonding agent, and the bonding agent is silane.
19. A method of infiltrating openings in a cement liner on the
exterior of a subsurface tubular, comprising: preparing a sealant
comprising: an epoxide resin, a hardener selected from a group
consisting of tetraethylenepentamine for a low temperature well and
diethyltoluenediamine for a high temperature well, wherein;
extending a conduit inwardly of the subsurface tubular to a
location therein having at least one opening extending through the
wall thereof, the opening located above an obstruction in the
tubular and extending through the tubular in a location where a
cement is present on the exterior of the tubular; and pumping the
sealant through the conduit and through the at least one opening in
the wall of the tubular, and thence into openings in the
cement.
20. The method of claim 19, further comprising an obstruction
between the conduit and the wall of the tubular in a location above
the openings in the wall of the tubular before pumping the sealant.
Description
BACKGROUND OF THE DISCLOSURE
[0001] Field of the Disclosure
[0002] The present disclosure generally relates to a method of
sealing wells by squeezing a sealant into an annulus thereof.
[0003] Description of the Related Art
[0004] 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.
[0005] 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
[0006] 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 annulus
formed between the inner tubular string and an outer tubular
string, thereby repairing a cement sheath present in the
annulus.
[0007] 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
[0008] 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.
[0009] FIG. 1 illustrates delivery of an equipment package to a
platform for performing the squeeze operation, according to one
embodiment of the present disclosure.
[0010] FIG. 2A illustrates perforation of a production casing
string. FIG. 2B illustrates deployment of a sealing string.
[0011] FIGS. 3A-3C illustrate operation of a mixing unit of the
equipment package to form sealant.
[0012] FIG. 4 illustrates squeezing of the sealant into an annulus
formed between the production casing string and a surface casing
string.
[0013] FIGS. 5A and 5B illustrate a first alternative sealing
operation, according to another embodiment of the present
disclosure.
[0014] FIGS. 6A and 6B illustrate a second alternative sealing
operation, according to another embodiment of the present
disclosure.
[0015] FIGS. 7A and 7B illustrate a third alternative sealing
operation, according to another embodiment of the present
disclosure.
DETAILED DESCRIPTION
[0016] FIG. 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.
[0017] 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.
[0018] 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 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.
[0019] 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 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 (FIG. 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 (FIG. 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.
[0020] FIG. 2A illustrates perforation of the production casing
string 7. FIG. 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.
[0021] 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.
[0022] Cement slurry (not shown) is then pumped through the
production tree head, 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.
[0023] 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.
[0024] 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 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.
[0025] 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.
[0026] FIG. 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.
[0027] FIGS. 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 transfer pump 30a, b for each
liquid tote, a dispensing hopper 31, and a blender 32.
[0028] 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.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] The second transfer pump 30b is operated to dispense the
hardener 33h into 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 (FIG. 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.
[0033] FIG. 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.
[0034] 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 days. If
the 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.
[0035] FIGS. 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.
[0036] 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.
[0037] FIGS. 6A and 6B illustrate a second alternative sealing
operation, according to another embodiment of the present
disclosure. In this second alternative sealing 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.
[0038] 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.
[0039] 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.
[0040] FIGS. 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 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.
[0041] 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.
[0042] 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.
[0043] Alternatively, a cement plug is used instead of or in
addition to the bridge plug 23.
[0044] 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.
[0045] 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.
[0046] 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.
* * * * *