U.S. patent application number 12/117915 was filed with the patent office on 2009-11-12 for system and method for perforated well sand control.
Invention is credited to Kevin W. England, Gregory Kubala, Philip F. Sullivan.
Application Number | 20090277636 12/117915 |
Document ID | / |
Family ID | 41265937 |
Filed Date | 2009-11-12 |
United States Patent
Application |
20090277636 |
Kind Code |
A1 |
Kubala; Gregory ; et
al. |
November 12, 2009 |
SYSTEM AND METHOD FOR PERFORATED WELL SAND CONTROL
Abstract
In one embodiment, a system includes a cased wellbore disposed
in a formation of interest. The system includes an emulsion
positioned in the wellbore at a depth of the formation of interest.
The emulsion includes an oil external phase and an aqueous internal
phase. The oil external phase includes particles having calcium
hydroxide. The aqueous internal phase includes insoluble silica
particles. The system further includes a perforating tool that
generates perforation tunnels through the cased wellbore into the
formation of interest. The system further includes a well flow
control device that shuts in the wellbore for a specified period of
time. The emulsion breaks during contact with the formation in the
perforation tunnels, and the calcium hydroxide and silica particles
form a cementitious material that consolidates the perforation
tunnels.
Inventors: |
Kubala; Gregory; (Houston,
TX) ; Sullivan; Philip F.; (Bellaire, TX) ;
England; Kevin W.; (Houston, TX) |
Correspondence
Address: |
SCHLUMBERGER TECHNOLOGY CORPORATION;David Cate
IP DEPT., WELL STIMULATION, 110 SCHLUMBERGER DRIVE, MD1
SUGAR LAND
TX
77478
US
|
Family ID: |
41265937 |
Appl. No.: |
12/117915 |
Filed: |
May 9, 2008 |
Current U.S.
Class: |
166/293 ;
166/297; 166/55 |
Current CPC
Class: |
E21B 43/11 20130101;
Y02W 30/91 20150501; Y02W 30/94 20150501; Y02W 30/92 20150501; C09K
8/565 20130101; C04B 28/18 20130101; C09K 8/46 20130101; E21B 33/13
20130101; E21B 43/025 20130101; C04B 28/18 20130101; C04B 14/062
20130101; C04B 14/066 20130101; C04B 18/08 20130101; C04B 18/146
20130101; C04B 40/0259 20130101 |
Class at
Publication: |
166/293 ;
166/297; 166/55 |
International
Class: |
E21B 33/13 20060101
E21B033/13 |
Claims
1. A method, comprising: preparing an emulsion comprising: an oil
external phase including particles comprising calcium hydroxide and
an aqueous internal phase comprising insoluble silica particles;
positioning an amount of the emulsion at a specified depth in a
wellbore; providing a specified pressure in the wellbore at the
specified depth, wherein the specified pressure is greater than a
formation fluid pressure at the specified depth and less than a
formation fracture pressure at the specified depth; perforating the
wellbore at the specified depth; and shutting in the wellbore for a
specified time period after the perforating.
2. (canceled)
3. The method of claim 1, further comprising providing a pressure
profile in the wellbore at the specified depth, wherein the
pressure profile includes a dynamic underbalance pressure
profile.
4. The method of claim 3, wherein the dynamic underbalance pressure
profile includes a final pressure that is greater than a formation
fluid pressure at the specified depth and less than a formation
fracture pressure at the specified depth.
5. The method of claim 4, wherein the oil external phase to aqueous
internal phase comprises an oil to water ratio between about 30/70
to about 60/40.
6. The method of claim 4, wherein the oil external phase to aqueous
internal phase comprises an oil to water ratio lower than about
40/60.
7. The method of claim 6, wherein the specified time period
comprises a time period sufficient for the calcium hydroxide and
the insoluble silica particles to form a cementitious material
disposed in the perforation tunnel, wherein the cementitious
material has a compressive strength greater than about 100 psi.
8. The method of claim 6, wherein the specified time period
comprises a time period sufficient for the calcium hydroxide and
the insoluble silica particles to form a cementitious material
disposed in the perforation tunnel, wherein the cementitious
material has a compressive strength between about 100 psi and about
1500 psi.
9. The method of claim 1, further comprising performing a
stimulation treatment at the specified depth in the wellbore.
10. A method, comprising: positioning an oil phase including
particles comprising calcium hydroxide in a wellbore at a specified
depth; positioning an aqueous phase comprising insoluble silica
particles in the wellbore above the specified depth; positioning a
perforating device in the wellbore at the specified depth; mixing
the oil phase and the aqueous phase after positioning the
perforating device; perforating the wellbore after the mixing; and
shutting in the wellbore for a specified time period after the
perforating.
11. The method of claim 10, wherein positioning the aqueous phase
comprising insoluble silica particles in the wellbore above the
specified depth comprises positioning the aqueous phase in a
tubing-casing annulus.
12. The method of claim 10, wherein mixing the oil phase and the
aqueous phase includes operating a downhole circulating device.
13. The method of claim 12, wherein at least one of the oil phase
and the aqueous phase do not include surfactants.
14. The method of claim 10, wherein the oil phase includes a first
surfactant present in a first concentration, wherein the aqueous
phase includes a second surfactant present in a second
concentration, and wherein at least one of the first concentration
and the second concentration comprise a concentration value less
than about 80% of a nominal concentration value.
15. The method of claim 10, wherein the oil phase includes a first
surfactant present in a first concentration, wherein the aqueous
phase includes a second surfactant present in a second
concentration, and wherein each of the first and second
concentrations comprise concentration values between 0% and about
4% surfactant, inclusive.
16. The method of claim 1 as used wireline-enabled perforating and
fracturing operations performed on a plurality treatment zones.
17. A system, comprising: a cased wellbore disposed in a formation
of interest; an emulsion positioned in the wellbore at a depth of
the formation of interest, the emulsion comprising an oil external
phase including particles comprising calcium hydroxide and an
aqueous internal phase comprising insoluble silica particles; a
perforating tool structured to generate perforation tunnels through
the cased wellbore into the formation of interest; and a well flow
control device structured to shut in the wellbore for a specified
period of time.
18. The system of claim 17, further comprising a well pressurizing
means that provides a specified pressure in the wellbore at the
depth of the formation of interest, wherein the specified pressure
is greater than a formation fluid pressure at the specified depth
and less than a formation fracture pressure at the specified
depth.
19. The system of claim 17 further comprising a well pressurizing
means that provides a pressure profile in the wellbore at the depth
of the formation of interest, wherein the pressure profile includes
a dynamic underbalance pressure profile.
20. The system of claim 17, wherein the insoluble silica particles
comprise a member selected from the group consisting of pozzolan,
fumed silica, precipitated silica, colloidal silica, calcined clay,
and fly ash.
21. The system of claim 17, wherein the particles comprising
calcium hydroxide and the insoluble silica particles comprise
particles having a median size of less than about fifty percent of
a median pore size of a typical void in the formation of
interest.
22. The system of claim 17, wherein the oil external phase to
aqueous internal phase comprises an oil to water ratio between
about 30/70 to about 60/40.
23. The system of claim 17, wherein a molar ratio of the calcium
hydroxide to the insoluble silica particles comprises a ratio from
about 0.8 to about 2.5.
24. The system of claim 17, wherein the oil phase includes a first
surfactant present in a first concentration, wherein the aqueous
phase includes a second surfactant present in a second
concentration, and wherein each of the first and second
concentrations comprise concentration values between 0% and about
4% surfactant, inclusive.
Description
BACKGROUND
[0001] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0002] Unconsolidated formations present a particulates and fines
migration problem. Currently available techniques are effective at
controlling particulate migration but suffer from some drawbacks.
For example, gravel packing controls particulates well, but in some
instances cannot be performed before or during a perforation
treatment, which in some highly unconsolidated formations can allow
enough particulates in the wellbore to complicate post-perforation
procedures and/or to destabilize the near-wellbore region of the
formation. In some cases, treatments can be utilized during
perforating, but the known treatments involve complex procedures
with several stages, for example curable resin treatments, and/or
sensitive chemistry subject to failure from common disturbances
such as contacting brine in the wellbore. Accordingly, there is a
demand for further improvements in this area of technology.
SUMMARY
[0003] One embodiment is a unique procedure for perforating a well
with a single-stage consolidation fluid in the wellbore during
perforation. Other embodiments include unique systems, methods, and
apparatus to control post-perforation fines migration. Further
embodiments, forms, objects, features, advantages, aspects, and
benefits shall become apparent from the following description and
drawings.
[0004] Methods and system embodiments may be used to treat any
appropriate subterranean formation and wellbore penetrated such,
including, but not limited to injection wells, water wells,
wellbore used for hydrocarbon/gas production, and the like.
[0005] Methods and system embodiments may be suited for any
wellbore/subterranean treatments understood in the art, including
without limitation a hydraulic fracture treatment, a matrix
acidizing treatment, an acid fracture treatment, or an energized
and/or foamed fluid fracture treatment.
[0006] Some embodiments may be used with treatments termed
"PerFRAC", where wireline-enabled perforating and fracturing
operations involve fracture stimulation treatments down the casing
with a perforating gun assembly in the wellbore. The perforating
guns selectively perforate the zones, which are fracture stimulated
one zone at a time. Isolation between stimulation zones may be
accomplished by any suitable means, including use of ball sealers.
Such an operation may provide effective isolation of each
perforated zone within the stage, effective placement of
specifically designed treatments into each perforated zone,
treating each zone at a relatively high flow rate, and efficient
completion of each stage in one wireline trip.
BRIEF DESCRIPTION OF THE FIGURES
[0007] FIG. 1 is a schematic diagram of a system for perforated
well sand control.
[0008] FIG. 2 is a schematic diagram of a perforation tunnel.
[0009] FIG. 3 is an illustration of bottom hole pressure versus
time through a perforating event.
[0010] FIG. 4 is a schematic diagram of an alternate embodiment of
a system for perforated well sand control.
[0011] FIG. 5 is an illustration of a consolidation fluid.
[0012] FIG. 6 is a schematic flow diagram of a procedure for
perforated well sand control.
[0013] FIG. 7 is a schematic flow diagram of a technique for
perforated well sand control.
DESCRIPTION OF THE ILLUSTRATIVE EMBODIMENTS
[0014] For the purposes of promoting an understanding of the
principles of the invention, reference will now be made to the
embodiments illustrated in the drawings and specific language will
be used to describe the same. It will nevertheless be understood
that no limitation of the scope of the invention is thereby
intended, and any alterations and further modifications in the
illustrated embodiments, and any further applications of the
principles of the invention as illustrated therein as would
normally occur to one skilled in the art to which the invention
relates are contemplated and protected.
[0015] FIG. 1 is a schematic diagram of a system 100 for perforated
well sand control. The system 100 includes a cased wellbore 102 in
a formation of interest 104. The cased wellbore 102 may be any type
of well known in the art, and in certain embodiments includes a
drilled hole 106 through an overburden 108, with a casing 110 and
cement layer 112 in the wellbore 102 to stabilize the well and
isolate the various zones 104, 108, 114 from fluid communication.
The formation of interest 104 includes a hydrocarbon producing
formation, a formation that is a target for injected fluid, or any
other formation wherein fluid conductivity between the wellbore 102
and the formation 104 is desirable. Further, the wellbore 102 may
include deviated or horizontal sections, including in sections of
the wellbore 102 through the formation of interest 104. The
formation of interest 104 is illustrated as a single zone in the
illustration of FIG. 1, but the formation of interest 104 may
include multiple zones or reservoir layers, portions of a zone or
reservoir layer, or any other section of the wellbore 102 where
fluid communication is desirable between the wellbore 102 and the
area surrounding the wellbore 102.
[0016] The system 100 further includes an emulsion 116 positioned
in the wellbore 102 at a depth of the formation of interest 104.
The emulsion is described more completely in FIG. 5 and the section
referencing FIG. 5. Further, details of an emulsion utilized in
certain embodiments are discussed in U.S. patent application Ser.
No. 11/861,894 to Sullivan et al., entitled "Emulsion System for
Sand Consolidation," filed Sep. 29, 2007, which is incorporated
herein by reference and in the entirety. In certain embodiments,
the emulsion includes an oil external phase having particles that
include calcium hydroxide and the emulsion further includes an
aqueous internal phase having insoluble silica particles.
[0017] In certain embodiments, the insoluble silica particles
includes a pozzolan, fumed silica, precipitated silica, colloidal
silica, calcined clay, and/or fly ash. In certain embodiments, the
particles having calcium hydroxide and the insoluble silica
particles have a median size of less than about fifty percent of a
median pore size of a typical void in the formation of interest
104. In certain embodiments, the oil external phase to the aqueous
internal phase has an oil to water ratio (volumetric) between about
30/70 to about 60/40. In certain embodiments, the oil to water
ratio may be lower than 30/70, especially where high compression
strength cementitious material (see FIG. 2 and referencing text)
may be desirable including, without limitation, highly
unconsolidated formations, high pressure formations, and high
permeability formations.
[0018] In certain embodiments, the system 100 includes a molar
ratio of the calcium hydroxide to the insoluble silica particles
between about 0.8 and 2.5. The resulting reaction of lime (CaO) to
silica (SiO.sub.2) that occurs when the emulsion 116 breaks occurs
in variable mol ratios, but generally occurs between the mol ratios
of about 0.8 to 2.5.
[0019] In certain embodiments, the oil phase includes a first
surfactant present in a first concentration and the aqueous phase
includes a second surfactant present in a second concentration. The
oil phase surfactant concentration varies depending upon the
surfactant used, the oil composition, the amount of time for which
the emulsion 116 must be stable, the temperature conditions at
which the emulsion will be exposed, and other considerations
understood in the art. Typical oil phase surfactant concentrations
include about 5% or more by volume surfactant, for example a
poly(isobutylene) ethanol amide at 5% by volume. The aqueous phase
surfactant concentrations likewise vary for considerations
understood in the art. Typical aqueous phase surfactant
concentrations include about 5% or more by volume surfactant, for
example a fatty acid ester at 5% by volume.
[0020] In certain embodiments, it is desirable to reduce the
surfactant concentrations in the oil phase and/or the aqueous
phase. For example, high surfactant concentrations can cause
undesirable foaming, formation wetting changes, or other problems
related to fluid chemistry and behavior. Further, surfactants tend
to be expensive chemicals and reductions are desirable to reduce
costs. In certain embodiments, the oil phase and aqueous phase
portions of the emulsions can be separated such that a minimum
emulsion stability time is required--for example, see FIG. 4 and
referencing texts. In an exemplary embodiment, a standard emulsion
formula includes surfactant amounts normally used in creating an
emulsion--or nominal concentration values for the surfactants. In
the exemplary embodiment, the oil phase includes a first surfactant
present in a first concentration and the aqueous phase includes a
second surfactant present in a second concentration, and at least
one of the first and second concentrations is included in the
emulsion 116 in an amount lower than about 80% of the nominal
concentration value for that surfactant. For example, if the
nominal surfactant concentration in the oil phase (the first
surfactant concentration) is 6% surfactant by volume, the first
surfactant concentration in certain embodiments is reduced to below
about 4.8%. In the example, the time of exposure for the emulsion
116 may be reduced to offset the lower emulsion 116 stability
relative to a stability of the standard emulsion formula. For
example, the wellbore 102 may be perforated quickly after
positioning the emulsion 116, or the emulsion 116 may be mixed
downhole in the wellbore just before perforating. In certain
embodiments, surfactant concentrations can be reduced to below 4%
in the oil phase and/or aqueous phase, and in certain further
embodiments surfactants can be completely removed from the oil
phase and/or aqueous phase.
[0021] In certain embodiments, the system 100 includes a
perforating tool 118 structured to generate perforation tunnels 120
through the cased wellbore 102 into the formation of interest 104.
In the illustration of FIG. 1, the perforating tool 118 just
generated the perforation tunnels 120 and the emulsion 116 has not
yet entered the formation 104 through the perforation tunnels 120.
The system 100 is illustrated as shown in FIG. 1 to schematically
illustrate an exemplary position of the emulsion 116, the
perforation tunnels 120, and the perforating tool 118. The
perforating tool 118 includes a perforating gun, including
through-tubing, through-casing, and/or coiled delivered perforating
guns. Alternatively, the tool 118 could be used with pipe conveyed
systems including jointed tubing, coiled tubing, drill string, and
the like. Also, the tool 118 may be conveyed by tractor as well.
Any device that generates perforation tunnels 120 is contemplated
within the present application.
[0022] In certain embodiments, the system 100 includes a well
control device 122 structured to shut in the wellbore 102 for a
specified period of time. The specified period of time includes a
time sufficient for the emulsion 116 to form cementitious material
in the perforation tunnels 120. In certain embodiments, the
emulsion 116 breaks after contacting sand in the formation of
interest 104, and/or breaks after exposure to formation fluids and
temperature over time. After the emulsion breaks, the calcium
hydroxide and silica begin reacting to form a cementitious
material. Any cementitious material should have compressive
strength between about 100 psi and 1500 psi to contain any sand and
fines migration from the formation of interest 104 and to
consolidate and stabilize the perforation tunnel 120. Depending
upon the temperature of the formation of interest 104, the
concentration of the calcium hydroxide, and the desired compressive
strength of the cementitious material, the specified period ranges
from around five hours to several days. The determination of a
specified period of time is dependent upon the specifics of a given
embodiment of the system 100, and is easily determined through
routine data gathering according to the formulation of the emulsion
116 and the conditions of the formation of interest 104.
[0023] In certain embodiments, the system 100 includes a well
pressurizing mechanism that provides a specified pressure in the
wellbore 102 at the depth of the formation of interest. In certain
further embodiments, the specified pressure in the wellbore is
greater than the pressure of the formation 104 fluid and less than
the formation 104 fracture pressure. For example, where the depth
of the formation 104 is 5000 feet, the fluid pressure gradient is
0.44 psi/ft, and the fracture gradient is 0.60 psi/ft, the
specified pressure in certain embodiments is between about 2200 psi
and 3000 psi. The well pressurizing mechanism includes any method
understood in the art, including at least positioning a spacer
fluid 124 with a density such that the specified pressure is
achieved and a pump (not shown) pressurizing the wellbore and the
well control device 122 holding the pressure in the wellbore until
the perforating tool 118 generates the perforation tunnels 120. The
density of the spacer fluid 124 and the emulsion 116 may be
sufficient to maintain the emulsion 116 at the depth of the
formation of interest 104, or the spacer fluid 124 and the emulsion
116 may be separated by mechanical means (e.g. a plug or packer) or
by positioning the emulsion 116 and spacer fluid 124 interface
within a narrow tubing where significant mixing is unlikely during
the time between placement and perforating the formation 104.
[0024] In certain embodiments, the well pressurizing mechanism
provides a pressure profile in the wellbore 102 at the depth of the
formation of interest 104. The pressure profile in certain
embodiments includes a dynamic underbalance pressure profile. For
example, the pressure in the wellbore 102 at the depth of the
formation of interest 104 may be above (overbalanced), or below
(underbalanced), or the same as (balanced) the formation fluid
pressure before the perforating tool 118 perforates the wellbore
102. In an embodiment utilizing a dynamic underbalance pressure
profile, the pressure in the wellbore 102 at the depth of the
formation of interest 104 may be momentarily lowered below the
formation fluid pressure and then raised and/or returned to a
higher pressure level. A dynamic underbalance pressure profile may
be implemented by any method known in the art, including without
limitation: by utilizing a surge chamber, vents, and/or through
proper design of the perforating tool 118 to create a momentary
low-pressure zone at the perforation tunnels 120 after
perforating.
[0025] FIG. 2 is a schematic diagram of a perforation tunnel 120.
The perforation tunnel 120 extends through the casing 110 and the
cement layer 112 into the formation of interest 104. In certain
embodiments, the perforation tunnel 120 includes a crushed zone 204
around the perforation tunnel 120. In an unconsolidated formation,
fines from the formation can migrate into the wellbore 102, causing
problems with handling of fines, wearing out equipment, and
environmental concerns with fines disposal. Further, bulk crushed
material can cause significant damage to the permeability and/or
conductivity of the perforation tunnel 120. In certain embodiments,
the perforation tunnel 120 is created in an underbalanced
condition, causing an initial surge of debris to exit the
perforation tunnel 120 into the wellbore 102 and enhancing the
conductivity of the perforation tunnel 120. In certain further
embodiments, the perforation tunnel 120 is created in a condition
wherein the emulsion 116 enters the perforation tunnel 120 and
begins to form cementitious material that consolidates and
stabilizes the perforation tunnel 120.
[0026] In one example, the perforation occurs in a dynamically
underbalanced condition, where the area surrounding the perforation
is briefly underbalanced immediately after perforating, and where
the area surrounding the perforation returns to an overbalanced
condition briefly after, forcing the emulsion 116 into the
perforation tunnel 120. In certain embodiments, the perforation
tunnel 120 may be created in a completely overbalanced condition,
where initial perforation debris is either expected to cause little
effect on the productivity of the formation of interest 104, or
where a subsequent stimulation treatment is expected to clear away
any perforation tunnel 120 damage. In certain embodiments, the
perforation tunnel 120 may be produced in a balanced or
underbalanced condition, and the emulsion 116 enters the
perforation tunnel 120 through fluid exchange mechanisms such as a
fluid density differential with the formation fluid.
[0027] FIG. 3 is an illustration 300 of bottom hole pressure 302
versus time 304 through a perforating event. In the illustration
300, the plotted pressure 306 shows the pressure 302 versus time
304, and the perforating event occurs at a time 308. The
illustration 300 is consistent with a perforating event performed
where the wellbore 102 is overbalanced, and the perforation is
performed in a dynamically underbalanced manner. At the time 308,
the plotted pressure 306 spikes due to detonation of the
perforating gun, and the plotted pressure quickly drops below a
formation fluid pressure 312. After a short period of time,
typically between less than half a second and a couple of seconds,
the plotted pressure 306 returns to the starting pressure value or
to some other designed pressure value. In certain embodiments,
except for potential excursions during the detonation of the
perforating tool 118, the plotted pressure is maintained below a
formation fracturing pressure 314.
[0028] FIG. 4 is a schematic diagram of an alternate embodiment of
a system 400 for perforated well sand control. The system 400 of
FIG. 4 is similar to the system 100 of FIG. 1, with significant
differences described herein. In the system 400, the perforating
tool 118 is illustrated as a through-tubing perforating gun that
has not yet perforated the wellbore 102. An oil phase 406 is
positioned at a specified depth in the wellbore 102, and an aqueous
phase 408 is positioned above the specified depth in the wellbore
102. In certain embodiments, the aqueous phase 408 is positioned in
a tubing 410 casing annulus, where a downhole tool 402 prevents
mixing of the oil phase 406 and the aqueous phase 408 until the
tool 402 is manipulated (e.g. mechanically, electrically,
hydraulically, or through other means understood in the art) to
release the aqueous phase 408 into the oil phase 406. In certain
embodiments, an optional downhole circulating device, for example a
pump or impeller, is operated to mix the aqueous phase 408 with the
oil phase 406 and create an emulsion 116.
[0029] FIG. 5 is an illustration of a consolidation fluid. In
certain embodiments, the consolidation fluid is an emulsion 116
including an oil phase 406 and an aqueous phase 408. The oil phase
includes particles 502 having calcium hydroxide, and the aqueous
phase 408 includes insoluble silica particles 504. The phases and
particles of the emulsion 116 are not shown to scale, and the
proportions of oil phase 406 to aqueous phase 408 may be any values
as otherwise described herein. The emulsion 116 may include
surfactants as needed for the system 100 conditions and stability
time needed, and the surfactants may be in the oil phase 406 and/or
aqueous phase 408.
[0030] The schematic flow diagram and related description which
follows provides an illustrative embodiment of performing
operations for perforated well sand control. Operations illustrated
are understood to be exemplary only, and operations may be combined
or divided, and added or removed, as well as re-ordered in whole or
part, unless stated explicitly to the contrary herein.
[0031] FIG. 6 is a schematic flow diagram of a procedure 600 for
perforated well sand control. The procedure 600 includes an
operation 602 to prepare an emulsion 116 and an operation 604 to
place an emulsion, by a suitable means, in a wellbore at a target
depth. The procedure 600 further includes an operation 604 to
position a perforating device at the specified depth, an operation
606 to pressurize the wellbore 102, and an operation 608 to
perforate the wellbore 102 at the specified depth. The procedure
600 further includes an operation 612 to shut in the wellbore 102
for a specified time period. In certain embodiments, the procedure
600 includes an operation 614 to perform a stimulation treatment.
The stimulation treatment may be any treatment understood in the
art for the formation of interest 104, including without limitation
a hydraulic fracture treatment, a matrix acidizing treatment, an
acid fracture treatment, or an energized and/or foamed fluid
fracture treatment.
[0032] FIG. 7 is a schematic flow diagram of a technique 700 for
perforated well sand control. The technique 700 includes an
operation 702 to position tubing 410 and tools (e.g. a perforating
device 118 and/or a downhole circulating device 404) in a wellbore
102. The technique 700 further includes an operation 704 to
position a first fluid in a tubing-casing annulus, where the first
fluid is an aqueous phase including insoluble silica particles. The
technique 700 further includes an operation 706 to position a
second fluid in the casing 110 at a specified depth, where the
second fluid is an oil phase including calcium hydroxide. In some
cases, the available depths for the fluid to be position are in the
casing below the end of the tubing; however, a portion of the
second fluid may be placed in the tubing, casing, and/or
tubing-casing annulus. The technique 700 further includes an
operation 708 to position a perforating device in the wellbore 102
at the specified depth. The technique 700 further includes an
operation 710 to mix the first fluid and the second fluid, and an
operation 712 to perforate the wellbore with a dynamic underbalance
pressure profile. In some instances it be efficient to mix the
emulsion prior to positioning the perforating device at the
specified depth; the perforating device could be position above the
position where the emulsion is mixed and then lowered to the
specified depth once the mixing is complete. The technique 700
further includes an operation 714 to shut in the well for a
specified time period.
[0033] As is evident from the figures and text presented above, a
variety of embodiments according to the invention are
contemplated.
[0034] One exemplary embodiment is a method including preparing an
emulsion. The emulsion includes an oil external phase including
particles comprising calcium hydroxide and an aqueous internal
phase including insoluble silica particles. The method further
includes positioning an amount of the emulsion at a specified depth
in a wellbore, perforating the wellbore at the specified depth, and
shutting in the wellbore for a specified time period after the
perforating.
[0035] In certain embodiments, the method further includes
providing a specified pressure in the wellbore at the specified
depth, where the specified pressure is greater than a formation
fluid pressure at the specified depth and less than a formation
fracture pressure at the specified depth. In certain embodiments,
the method includes providing a pressure profile in the wellbore at
the specified depth, where the pressure profile includes a dynamic
underbalance pressure profile. In certain further embodiments, the
dynamic underbalance pressure profile includes a final pressure
that is greater than a formation fluid pressure at the specified
depth and less than a formation fracture pressure at the specified
depth. In certain embodiments, the oil external phase to aqueous
internal phase comprises an oil to water ratio between about 30/70
to about 60/40. In certain embodiments, the oil external phase to
aqueous internal phase comprises an oil to water ratio lower than
about 40/60.
[0036] In certain embodiments, the specified time period includes a
time period sufficient for the calcium hydroxide and the insoluble
silica particles to form a cementitious material disposed in the
perforation tunnel, where the cementitious material has a
compressive strength greater than about 100 psi. In certain further
embodiments, the specified time period includes a time period
sufficient for the calcium hydroxide and the insoluble silica
particles to form a cementitious material disposed in the
perforation tunnel, where the cementitious material has a
compressive strength between about 100 psi and about 1500 psi. In
certain embodiments, the method further includes performing a
stimulation treatment at the specified depth in the wellbore.
[0037] One exemplary embodiment is a method including positioning
an oil phase including particles comprising calcium hydroxide in a
wellbore at a specified depth, and positioning an aqueous phase
including insoluble silica particles in the wellbore above the
specified depth. In certain embodiments, the method includes
positioning a perforating device in the wellbore at the specified
depth, mixing the oil phase and the aqueous phase after positioning
the perforating device, perforating the wellbore after the mixing,
and shutting in the wellbore for a specified time period after the
perforating.
[0038] In certain further embodiments, positioning the aqueous
phase including insoluble silica particles in the wellbore above
the specified depth includes positioning the aqueous phase in a
tubing-casing annulus. In certain further embodiments, mixing the
oil phase and the aqueous phase includes operating a downhole
circulating device. In certain embodiments, at least one of the oil
phase and the aqueous phase do not include surfactants. In certain
embodiments, the oil phase includes a first surfactant present in a
first concentration, the aqueous phase includes a second surfactant
present in a second concentration, and at least one of the first
concentration and the second concentration comprise a concentration
value less than about 80% of a nominal concentration value. In
certain embodiments, the oil phase includes a first surfactant
present in a first concentration, the aqueous phase includes a
second surfactant present in a second concentration, and each of
the first and second concentrations include concentration values
between 0% and about 4% surfactant, inclusive.
[0039] One exemplary embodiment is a system including a cased
wellbore disposed in a formation of interest, an emulsion
positioned in the wellbore at a depth of the formation of interest,
where the emulsion includes an oil external phase including
particles having calcium hydroxide, and an aqueous internal phase
including insoluble silica particles. In certain embodiments, the
system includes a perforating tool structured to generate
perforation tunnels through the cased wellbore into the formation
of interest, and a well flow control device structured to shut in
the wellbore for a specified period of time.
[0040] In certain further embodiments, the system includes a well
pressurizing means that provides a specified pressure in the
wellbore at the depth of the formation of interest, where the
specified pressure is greater than a formation fluid pressure at
the specified depth and less than a formation fracture pressure at
the specified depth. In certain embodiments, the system includes a
well pressurizing means that provides a pressure profile in the
wellbore at the depth of the formation of interest, wherein the
pressure profile includes a dynamic underbalance pressure profile.
In certain embodiments, the insoluble silica particles include
pozzolan, fumed silica, precipitated silica, colloidal silica,
calcined clay, and/or fly ash. In certain embodiments, the
particles having calcium hydroxide and the insoluble silica
particles include particles having a median size of less than about
fifty percent of a median pore size of a typical void in the
formation of interest. In certain embodiments, the oil external
phase to aqueous internal phase includes an oil to water ratio
between about 30/70 to about 60/40. In certain embodiments, a molar
ratio of the calcium hydroxide to the insoluble silica particles
includes a ratio from about 0.8 to about 2.5. In certain
embodiments, the oil phase includes a first surfactant present in a
first concentration, and the aqueous phase includes a second
surfactant present in a second concentration, where each of the
first and second concentrations include concentration values
between 0% and about 4% surfactant, inclusive.
[0041] Embodiments of the invention may use any suitable means for
perforation known to those of skill in the art, including
propellants, jetting, and the like.
[0042] While the invention has been illustrated and described in
detail in the drawings and foregoing description, the same is to be
considered as illustrative and not restrictive in character, it
being understood that only the preferred embodiments have been
shown and described and that all changes and modifications that
come within the spirit of the inventions are desired to be
protected. It should be understood that while the use of words such
as preferable, preferably, preferred, more preferred or exemplary
utilized in the description above indicate that the feature so
described may be more desirable or characteristic, nonetheless may
not be necessary and embodiments lacking the same may be
contemplated as within the scope of the invention, the scope being
defined by the claims that follow. In reading the claims, it is
intended that when words such as "a," "an," "at least one," or "at
least one portion" are used there is no intention to limit the
claim to only one item unless specifically stated to the contrary
in the claim. When the language "at least a portion" and/or "a
portion" is used the item can include a portion and/or the entire
item unless specifically stated to the contrary.
* * * * *