Note: Descriptions are shown in the official language in which they were submitted.
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METHODS AND EQUIPMENT TO IMPROVE RELIABILITY OF PINPOINT
STIMULATION OPERATIONS
BACKGROUND
The present invention relates to subterranean stimulation operations and, more
particularly, to apparatuses and methods for improving the reliability of
pinpoint stimulation
operations.
To produce hydrocarbons (e.g., oil, gas, etc.) from a subterranean formation,
well bores
may be drilled that penetrate hydrocarbon-containing portions of the
subterranean formation.
The portion of the subterranean formation from which hydrocarbons may be
produced is
commonly referred to as a "production zone." In some instances, a subterranean
formation
penetrated by the well bore may have multiple production zones at various
locations along the
well bore.
Generally, after a well bore has been drilled to a desired depth, completion
operations are
performed. Such completion operations may include inserting a liner or casing
into the well
bore and, at times, cementing a casing or liner into place. Once the well bore
is completed as
desired (lined, cased, open hole, or any other known completion) a stimulation
operation may be
performed to enhance hydrocarbon production into the well bore. Where methods
of the present
invention reference "stimulation," that term refers to any stimulation
technique known in the art
for increasing production of desirable fluids from a subterranean formation
adjacent to a portion
of a well bore. Examples of some common stimulation operations involve
hydraulic fracturing,
acidizing, fracture acidizing, and hydrajetting. Stimulation operations are
intended to increase
the flow of hydrocarbons from the subterranean formation surrounding the well
bore into the
well bore itself so that the hydrocarbons may then be produced up to the
wellhead.
One suitable hydrajet stimulation method, introduced by Halliburton Energy
Services,
Inc., is known as the SURGIFRAC and is described in U.S. Pat. No. 5,765,642.
The
SURGIFRAC process may be particularly well suited for use along highly
deviated portions of a
well bore, where casing the well bore may be difficult and/or expensive. The
SURGIFRAC
hydrajetting technique makes possible the generation of one or more
independent, single plane
hydraulic fractures. Furthermore, even when highly deviated or horizontal
wells are cased,
hydrajetting the perforations and fractures in such wells generally results in
a more effective
fracturing method than using traditional perforation and fracturing
techniques.
Another suitable hydrajet stimulation method, introduced by Halliburton Energy
Services, Inc., is known as the COBRAMAX-H and is described in U.S. Pat. No.
7,225,869.
The COBRAMAX-H process may be
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particularly well suited for use along highly deviated portions of a well
bore. The
COBRAMAX-H technique makes possible the generation of one or more independent
hydraulic
fractures without the necessity of using mechanical tools to achieve zone
isolation, can be used
to perforate and fracture in a single down hole trip, and may eliminate the
need to set mechanical
plugs through the use of a proppant slug or wellbore fill.
Current pinpoint stimulation techniques suffer from a number of disadvantages.
For
instance, during hydrajetting operations, the movements of the hydrajetting
tool generally
reduces the tool performance. The movements of the hydrajetting tool may be
caused by the
elongation or shrinkage of the pipe or the tremendous turbulence around the
tool. The reduction
in tool performance is generally compensated by longer jetting times so that a
hole is eventually
created. However, the increase in jetting times leads to an inefficient and
time consuming
hydrajetting process.
The COBRAMAX-H process also suffers from some drawbacks. Specifically, the
COBRAMAX-H process involves isolating the hydrajet stimulated zones from
subsequent well
operations. The primary sealing of the previous regions in the COBRAMAX-H
process is
achieved by placing sand plugs in the zones to be isolated. The placement of
sand plugs,
particularly in horizontal well bores, requires a very low flow rate which is
difficult to achieve
when using surface pumping equipment designed for high rate pumping
operations. Moreover,
when the operating pressures are high, the orifices of the tool must be very
small to create a low
flow rate. The small size of the orifices makes them susceptible to plugging.
Additionally, the placement of sand plugs in horizontal or substantially
horizontal well
bores may be difficult. Specifically, current methods of placement of sand
dunes in horizontal
well bores entail slowly pumping the sand down the well bore as shown in
Figure 1. An
artificially low flow rate 2 is used to allow dropping of sand to the bottom
side of the casing 4 to
form a sand dune 6. To that end, the terminal velocity of the sand dropping
down has to be faster
than the flow velocity reaching the fracture point. However, this approach may
prove
ineffective. As shown in Figure 1, as a sand dune 6 is created, the area above
the dune becomes
smaller, thereby increasing the flow velocity over the sand dune 6. The
increased flow velocity
destroys the top of the sand dune 6. As a result, the flow that passes on top
of the sand dune 6
may enter the fracture 8 and further open it.
Finally, the SURGIFRAC process which uses the Bernoulli principle to achieve
sealing
between fractures poses certain challenges. During the SURGIFRAC process, the
primary flow
goes to the fracture while the secondary, leakoff flow, is supplied by the
annulus. In some
instances, such as in long horizontal well bores, a large number of fractures
may be desired. The
formation of each fracture results in some additional leakoff (i.e., seepage).
Consequently. with
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the increase in the number of fractures, the amount of the secondary leakoff
flow increases and
eventually can significantly reduce the amount of the primary flow to the new
fracture. The
increased fluid losses reduce the efficiency of the operations and increases
the cost.
Accordingly, a flow limiter device is desirable to reduce annulus flow
requirements while
maintaining pore-pressure and limited flow influx to previous fractures below
the new fracture,
and after pumping has ceased, to let the new fracture slowly close without
producing proppant.
SUMMARY
The present invention relates to subterranean stimulation operations and, more
particularly,
to apparatuses and methods for improving the reliability of pinpoint
stimulation operations.
In one exemplary embodiment, the present invention is directed to a pinpoint
stimulation
improvement apparatus comprising: a hold down device; at least one flow
reducer coupled to the
hold down device; and a jetting tool coupled to the flow reducer. The flow
reducer is positioned
downstream from the jetting tool and the fluid flowing through the jetting
tool passes through the
flow reducer and forms a sand plug downstream from the pinpoint stimulation
improvement
apparatus.
In another exemplary embodiment, the present invention is directed to a method
of creating
a sand plug at a fracture in a wellbore having a fracture opening comprising
the steps of: flowing
a sand slurry to the fracture opening at a low flow rate; creating a sand dune
proximate to the
fracture opening; flowing the sand slurry into an upper portion of the
fracture; allowing sand
particles to drop down into the wellbore; depositing sand particles on the
sand dune; and
substantially plugging the fracture opening.
In yet another exemplary embodiment, the present invention is directed to a
method of
creating a sand plug in a well bore in a subterranean formation comprising:
directing a high
pressure fluid downhole through a pinpoint stimulation improvement apparatus
comprising a
jetting tool, a hold down device and a flow reducer; flowing the high pressure
fluid through the
jetting tool; reducing pressure of the high pressure fluid to obtain a low
pressure fluid; wherein
the pressure of the high pressure fluid is reduced by flowing the high
pressure fluid through the
flow reducer, wherein the flow reducer is positioned downstream from the
jetting tool;
discharging the high pressure fluid with the reduced pressure from the
pinpoint stimulation
improvement apparatus through an outlet of the flow reducer; and depositing
solid materials into
the well bore downhole from the pinpoint stimulation improvement apparatus.
The features and advantages of the present invention will be apparent to those
skilled in the
art from the description of the preferred embodiments which follows when taken
in conjunction
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with the accompanying drawings. While numerous changes may be made by those
skilled in
the art, such changes are within the scope of the invention as limited by the
appended claims.
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BRIEF DESCRIPTION OF THE DRAWINGS
These drawings illustrate certain aspects of some of the embodiments of the
present
invention, and should not be used to limit or define the invention.
Figures 1 depicts a cross-sectional view of placement of sand dunes in a
horizontal well
in accordance with the Prior Art.
Figures 2 depicts a cross-sectional view of placement of sand dunes in a
horizontal well
in accordance with an exemplary embodiment of the present invention.
Figure 3 depicts a perspective view of sand plug formation in accordance with
an
exemplary embodiment of the present invention.
Figure 4 depicts a simplified Pinpoint Stimulation Improvement Apparatus in
accordance with an exemplary embodiment of the present invention.
Figure 5 is a perspective view of a Pinpoint Stimulation Improvement Apparatus
in
accordance with an exemplary embodiment of the present invention.
Figures 6A and 6B depict a cross-sectional comparison of a traditional packer
configuration (Figure 6A) and an inflatable packer with a hold down
implementation of a
Pinpoint Stimulation Improvement Apparatus (Figure 6B) in accordance with an
exemplary
embodiment of the present invention.
Figure 7 is a flow limiter used in a Pinpoint Stimulation Improvement
Apparatus in
accordance with an exemplary embodiment of the present invention.
While embodiments of this disclosure have been depicted and described and are
defined by reference to example embodiments of the disclosure, such references
do not imply
a limitation on the disclosure, and no such limitation is to be inferred. The
subject matter
disclosed is capable of considerable modification, alteration, and equivalents
in form and
function, as will occur to those skilled in the pertinent art and having the
benefit of this
disclosure. The depicted and described embodiments of this disclosure are
examples only,
and not exhaustive of the scope of the disclosure.
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DETAILED DESCRIPTION
The present invention relates to subterranean stimulation operations and, more
particularly,
to apparatuses and methods for improving the reliability of pinpoint
stimulation operations.
Illustrative embodiments of the present invention are described in detail
herein. In the
interest of clarity, not all features of an actual implementation may be
described in this
specification. It will of course be appreciated that in the development of any
such actual
embodiment, numerous implementation-specific decisions may be made to achieve
the specific
implementation goals, which may vary from one implementation to another.
Moreover, it will
be appreciated that such a development effort might be complex and time-
consuming, but would
nevertheless be a routine undertaking for those of ordinary skill in the art
having the benefit of
the present disclosure.
The terms "couple" or "couples," as used herein are intended to mean either an
indirect or
direct connection. Thus, if a first device couples to a second device, that
connection may be
through a direct connection, or through an indirect electrical connection via
other devices and
connections. The term "upstream" as used herein means along a flow path
towards the source of
the flow, and the term "downstream" as used herein means along a flow path
away from the
source of the flow. The term "uphole" as used herein means along the
drillstring or the hole from
the distal end towards the surface, and "downhole" as used herein means along
the drillstring or
the hole from the surface towards the distal end.
It will be understood that the term "oil well drilling equipment" or "oil well
drilling
system" is not intended to limit the use of the equipment and processes
described with those
terms to drilling an oil well. The terms also encompass drilling natural gas
wells or hydrocarbon
wells in general. Further, such wells can be used for production, monitoring,
or injection in
relation to the recovery of hydrocarbons or other materials from the
subsurface. This could also
include geothermal wells intended to provide a source of heat energy instead
of hydrocarbons.
Turning now to Figure 2, placement of a sand dune in accordance with an
exemplary
embodiment of the present invention is depicted. The manner of placement of
the sand dune 10
is dependent upon the terminal velocity of the dropping particles,
particularly in the fracture 12
or to the ability to pack-off the near-wellbore area. In accordance with an
exemplary
embodiment of the present invention, the particle terminal velocity is
reflected as the ability of
the particle to fall inside the fracture 12. Figure 2 depicts a perspective
view of the particles
dropping in the fracture 12 in accordance with an exemplary embodiment of the
present
invention.
As shown in Figures 2 and 3, it may be assumed that the proppants in the
fracturing fluid
mostly drop on the bottom surface of the casing 18. Although the present
methods and systems
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are discussed in conjunction with a casing, as would be appreciated by those
of ordinary skill in
the art, with the benefit of this disclosure, the methods and systems
disclosed herein are also
applicable to well bores that do not include a casing. As proppants drop in
the borehole, a small
sand dune 10 begins to develop around the fracture 12 as shown in Figure 2. As
shown in Figure
3, as the sand dune 10 is developed, sand will fall into portions of the
fracture 12, which in
Figure 3 is depicted as extending into the formation along the circumference
of the casing 18.
The creation of a sand plug is then performed by pumping a slow flowing
proppant slurry
downhole into the borehole as depicted by arrow 14. Part of the proppant
slurry 14 may be lost
into the bottom portion of the fracture 12 and the casing 18 as the sand dune
10 develops. In
contrast, part of the proppant slurry may flow into the top side of the
fracture 12 as shown by
arrow 16.
In order to successfully create an effective sand plug, the downward proppant
terminal
velocity 30 inside the fracture 12 has to be higher than the upward leak off
velocity 32 upwards
in the fracture 12 which results in particles settling inside the fracture 12
on the top side of the
casing 18. This ensures the creation of a stable proppant plug in the casing
18. Alternately, due
to the restricted flow rate the fracture below the hold-down will be closing
and becoming packed
with proppant or very narrow in the areas not fully propped. If the sand
grains do not fall back
even at this reduced flow velocity the sand plug in the wellbore can form if
proppant can be
carried into the near wellbore portion of the fracture and achieve a packed
area, such that fluid
cannot enter the main body of the fracture without having to seep though this
proppant pack. If
this process does not further reduce the flow such that the grains do not fall
back downward as
described above, they will soon completely fill any remaining void area until
ultimately this
pack-off has grown into the wellbore itself, substantially plugging off the
fracture opening and
forming a solid mass inside the wellbore until it is completely filled. Once
completely filled, any
fluid flow into the fracture has to seep through this entire wellbore mass and
the packed near-
wellbore fracture area. If any flow carrying proppant later occurs it will
only serve to enlarge the
volume of the wellbore plug with this plug growth toward the heel of the
lateral.
As would be appreciated by those of ordinary skill in the art, with the
benefit of this
disclosure, placement of sand plugs in accordance with embodiments disclosed
herein requires a
very low flow rate that is typically hard to control using surface pumping
equipment designed for
high rate pumping. One solution is to provide a low flow rate downhole in
conjunction with
performing hydrajetting operations. However, the hydrajet tools or other tools
used downhole
utilize high pressures. Therefore, small orifices may be required in order to
create very low flow
rates. However, such small orifices are susceptible to plugging. Accordingly,
in order to
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perform the methods disclosed herein, a system must be used that can produce
low flow rates
without plugging the orifices of the tool downhole, such as the hydrajetting
tool.
In accordance with an exemplary embodiment of the present invention,
successful
placement of sand plugs in the well bore may entail creation of a hold-down
mechanism for a
stimulation system such as, for example, a hydrajetting system such as
SurgiFract/CobraMax as
discussed above. Figure 4 depicts a simplified Pinpoint Stimulation
Improvement Apparatus
(PSIA), denoted generally with reference numeral 400, that may be used to
perform the methods
disclosed herein. As shown in Figure 4, the PSIA 400 may include one or more
flow reducers
402, a mechanical hold down device 404 which may regulate fluid flow through
the well bore by
blocking off upstream flow from the flow reducer 402 outlet (in Figure 4, from
the flow reducer
402 to the left), and a stimulation jetting tool 406. In one exemplary
embodiment, the
stimulation jetting tool 406 may be a hydrajetting tool and/or the hold down
device 404 may be a
packer or an inflatable element. In one exemplary embodiment, the PSIA 400 may
allow a low
flow rate, but greatly reduce the high pressure required by the jetting tool
itself before fluid is
discharged from the flow reducer 402. The low pressure fluid discharged from
the flow reducer
402 may then form a sand plug 408. Specifically, as shown in Figure 4, a high
pressure fluid
410 is directed downhole and flows downstream through the PSIA 400. The high
pressure fluid
410 then may pass through the jetting tool 406 and flow downhole through at
least one flow
reducer 402 before exiting the PSIA 400. In one embodiment, the PSIA 400 may
include two
flow reducers 402 located uphole and downhole, respectively, relative to the
mechanical hold
down device 404 with the mechanical hold down device 404 located there
between.
Accordingly, the high pressure fluid 410 passes through one or more flow
reducers 402 before
exiting the PSIA 400 and forming a sand plug 408 downhole from the PSIA 400
and the jetting
tool 406.
As would be appreciated by those of ordinary skill in the art, with the
benefit of this
disclosure, in order to create the sand plug 408, the high pressure fluid
flowing through the PSIA
400 is laden with suitable solid materials. As the high pressure fluid 410
passes through the one
or more flow reducers 402, its pressure will be reduced, turning it into a low
pressure fluid.
Once the low pressure fluid passes through the flow reducer 402, it may be
discharged from the
PSIA 400 through an outlet 414. Upon discharge from the PSIA 400, the solid
materials
included therein will be deposited into the well bore 412 at the desired
location downhole from
the PSIA 400, forming a sand plug 408.
Although Figure 4 depicts a flow reducer 402 which appears to include a simple
choke, as
would be appreciated by those of ordinary skill in the art, with the benefit
of this disclosure, a
simple choking device is not best suited for performing the methods disclosed
herein.
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Specifically, a simple choke would require very small opening, for example,
0.5 BPM through it
at pressure differentials of 5000 psi. However, achieving 5000 psi pressure
differential may
require 0.1" nozzle opening. Such a small opening will be prone to being
plugged by debris or
the sand slurry used in the jetting process. Accordingly, the flow reducers
402 used in the PSIA
400 must be designed to address these issues. As discussed in more detail
below, a flow reducer
402 may be designed in accordance with an exemplary embodiment of the present
invention.
Turning now to Figure 5, a cross-sectional view of a portion of the PSIA 400
of Figure 4,
in accordance with an exemplary embodiment of the present invention, is
depicted. The portion
of the PSIA 400 depicted in Figure 5 includes the two flow reducers 402 and
the mechanical
hold down device 404. The PSIA 400 may comprise one or more flow reducers 402,
and a
mechanical hold down device 404. The mechanical hold down device 404 may
include an
elastomeric element 104 and a spring-mandrel 106 placed on the inner surface
of the elastomeric
element 104. The spring-mandrel 106 is stiff and provides some flexure, while
acting as a
resetting mechanism to the elastomeric element 104. Additionally, the spring-
mandrel 106
provides a free flow between the area behind and inside the mandrel. In one
exemplary
embodiment, "blanked" areas may be placed strategically to allow installation
of chokes to
promote flow through the outside section of the spring-mandrel 106, thereby
continuously
clearing the area from sand or proppants. Specifically, chokes may be placed a
few places (such
as at the blanked sections) to insure that a portion of the flow always goes
through the outside of
the spring-mandrel 106 and hence, that no sand or proppants are trapped in the
elastomeric
cavity.
The elastomeric element 104 may perform as a hold down device. Figures 6A and
6B
depict a cross sectional comparison of an elastomeric element used as an
inflatable packer
configuration (in accordance with the prior art) with the elastomeric element
hold down
configuration in accordance with an exemplary embodiment of the present
invention.
Specifically, Figure 6A depicts the traditional packer implementation 202 and
Figure 6B depicts
the new hold down configuration 204. In the packer implementation 202 the
elastomeric
element 206 is pressurized such that a total seal occurs between the top and
bottom (right and left
of Figures 6A and 6B) of the packer. The pressure achieved must be high enough
so that the
elastomeric element 206 is completely deformed, forming a competent seal. The
slats 208 in the
packer implementation 202 can become permanently deformed, with the
deformation becoming
more pronounced after each cycle. The pressurization of the packer
implementation 202 may be
achieved using a clean fluid 210. The clean fluid 210 is placed in the cavity
212 through the
cavity opening 214 and the cavity opening 214 is closed, leaving the packer
set. To unset the
packer, the cavity opening 214 must be manually opened.
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In contrast, with the hold down implementation 204, the elastomeric element
216 may be
pressurized by a process fluid 213 such as a sand slurry or an acid, often
containing sand or other
particles. The pressure of the process fluid 213 is pro-rated using a pressure
reduction system,
discussed in more detail below. Because the pressure is pro-rated, the low
pressure of the
process fluid 213 inflates the elastomeric element 216 just enough to touch
the outside walls (not
shown), without causing a complete seal. Sealing is not the primary object of
the hold down
implementation and unlike the packer implementation, fluid flow remains
continuous through the
tool, as well as possibly around the tool, from the top to the bottom (from
right to left in Figures
6A and 6B) of the tool. Moreover, in the hold down implementation, the
elastomeric element
216 is not deformed. The elastomeric element 216 is strengthened and protected
by slats 220
which are either outside of the elastomeric element 216 or covered within it
(not shown). The
outer slats 220 are stretched by the spring-mandrel 106. As a result, the
elastomeric element 216
deflates as soon as the process fluid 213 ceases to be pumped through the
tool, or the flow rate
becomes too low to create adequate pressure as it flows through the flow
reducer 402 at this very
low rate. Thus, the hold down capabilities of the PSIA 400 perform as an
anchoring mechanism
allowing the tool to be maintained at a fixed position for a desired period
before deflating and
allowing it to move to a second desired location. As the elastomeric element
216 deflates, the
spring-mandrel 106 collapses the elastomeric element 216 back in position and
the PSIA 400 is
dislodged from its location.
In one embodiment, the PSIA 400 in accordance with an exemplary embodiment of
the
present invention may be utilized to improve the performance of a hydrajetting
tool.
Specifically, the tool movements due to pipe elongation/shrinkage, temperature
and/or pressure
can be minimized by engaging the hold down implementation of the PSIA 400. As
would be
appreciated by those of ordinary skill in the art, with the benefit of this
disclosure, the strength
requirements for the hold-down device are minimal. For instance, in a vertical
well, a 4000 ft.
tubing, 2-3/8" outside diameter - 4.7 lb./ft. would only need 3800 lbs. of
elongation force to
stretch a full 1 ft.; or about 319 lb./in., if it was not somewhat restrained
by the casing above it.
As would be appreciated by those of ordinary skill in the art, with the
benefit of this disclosure,
in reality, this value will have to be subtracted by some large unknown value,
representing
friction with the wellbore wall. Note that, even in "vertical" wells, wells
are never truly vertical;
some slants occur during the drilling of the well. In horizontal wells,
movement can sometimes
be large due to the "jerkiness" of the system. However, the pipe friction
negates some of this
movement. For instance, for a 2000 ft. tubing as in the above example, in a
horizontal well,
assuming a friction factor of 0.35 between the pipe and the well bore wall,
the friction force may
be close to 3290 lbs, thus needing an additional help of only 500 lbs to
prevent the tool's
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movement. Similarly, the jet reaction force causes some small side movements
of the tool. For
instance, a 0.25" jet at a pressure of 5000 psi may produce a 400 lb. thrust
acting as a downward
piston force. Consequently, some small additional force will suffice in
preventing the
movements of a hydrajetting tool during operation. When in the hold down
implementation, the
PSIA 400 provides a flexible, elastomeric hold down system which minimizes the
tool
movements and improves the efficiency of the hydrajetting process.
As depicted in Figures 4 and 5, the PSIA 400 may include one or more flow
reducers 402.
Figure 7 depicts a flow reducer 402 in accordance with an exemplary embodiment
of the present
invention. As depicted in Figure 7, the fluid may be routed through a pressure
reducing channel
300, which wraps around the outer surface of the inner tubing 302 a multitude
of times. The
fluid enters the pressure reducing channel through the inlet 304. The friction
pressure drop due
to the continuous turn becomes very high, even though the channel size is
quite big. As the fluid
flows through the pressure reducing channel 300, the fluid flow rate is also
reduced. The fluid,
now having a lower flow rate, then exits the pressure reducing channel 300
through an outlet (not
shown) and flows back into the inside of the inner tubing 302. In one
exemplary embodiment, as
depicted in Figure 7, the channel may be intercepted at three points (e.g.,
306), thus bypassing a
portion of the channel for pressure control.
As depicted in Figure 7, in one exemplary embodiment, the flow reducer 402 may
further
comprise one or more pressure control modules 308a, 308b, and 308c. In one
embodiment, the
pressure control modules 308a, 308b, and 308c may be ball seat arrangements.
The ball seat
arrangement includes a seat body 310. The seat body 310 is arranged so that it
can be sealed
within the flow reducer 402. A ball 312 may be inserted into the seat body 310
through an
opening (not shown). Once the ball 312 is inserted into the seat body 310, it
is caged therein.
Although Figure 7 depicts three ball seat modules 308a, 308b, and 308c, as
would be appreciated
by those of ordinary skill in the art, with the benefit of this disclosure, a
different number of ball
seat modules may be utilized. Each ball seat module 308 bypasses a portion of
the pressure
reducing channel 300 through ports located just above each potential ball seat
module position.
These ports connect the channel 300 to the inside of the inner tubing.
Although the pressure
control modules 308 are discussed in conjunction with the flow reducer 402, as
would be
appreciated by those of ordinary skill in the art, with the benefit of this
disclosure, the pressure
control modules 308 may be used independently as a general purpose check
valve.
In one exemplary embodiment, the ball seat arrangement of the pressure control
modules
308a, 308b, and 308c may also perform as a check valve. Specifically, the ball
seat arrangement
may permit fluid flow from the bottom to the top of the PSIA 400 of Figure 7
for cleaning
purposes. Moreover, the ball seat modules 308 may provide a high flow rate
return line for the
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fluids that are pumped down the annulus while maintaining a low flow rate for
the fluids being
pumped down through the PSIA 400.
In one embodiment, it may be desirable to control the pressure of the fluid
flowing through
the elastomeric element In one exemplary embodiment, two or more flow reducers
402 may be
used as shown in Figure 5. The pressure control units may be set with multiple
combinations so
that the intended pressure and flow is reached.
In one embodiment, the present invention may be utilized in conjunction with
the
COBRAMAX-H process where the creation of solid sand plugs are required for the
process.
This sand plug creation depends upon the ability to pump sand slurries at a
very low flow rate.
Typically, the high pressure of the fluids results in a high flow rate. The
flow reducer 402 may
be used to reduce the flow rate to as low as 1/2 bpm (barrels per minute)
without using extra
small chokes that would tend to plug when exposed to sand. Therefore, the PSIA
400 allows the
placement of competent sand plugs at desired locations. To achieve a similar
result using
conventional chokes, a 0.09" choke must be utilized which would potentially
plug with sand that
is 30 Mesh or greater. Although a flow reducer 402 in accordance with an
exemplary
embodiment of the present invention has some size limitations, it can be
designed to accept 8
Mesh or even larger particles.
In another exemplary embodiment, the present invention may be used in
conjunction with
SURGIFRAC operations. Specifically, once a first fracture is created during
the SURGIFRAC
operations, the hydrajetting tool is moved to a second location to create a
second fracture.
However, some of the fluids that are being pumped into the annulus will
leakoff into the already
existing fracture. As the number of fractures increases, the amount of fluid
that leaks off also
increases. The hold down implementation of the PSIA 400 reduces the amount of
leak off fluid
flow through the annulus from the hydrajetting tool (not shown) to the
existing fractures.
Specifically, as the elastomeric element 206 inflates, it restricts the path
of the leak of fluid flow,
thereby reducing the amount of fluids leaked off. Consequently, the PSIA 400
will reduce the
annulus flow requirement while maintaining pore-pressure and limited flow
influx to let the
fracture slowly close without producing proppants back into the wellbore after
fluid injection has
stopped.
As would be appreciated by those of ordinary skill in the art, with the
benefit of this
disclosure, the term "pinpoint stimulation" is not limited to a particular
dimension. For instance,
depending on the zones to be isolated, the area subject to the "pinpoint
stimulation" may be a
few inches or in the order of tens of feet in size. Moreover, although the
present invention is
disclosed in the context of "stimulation" processes, as would be appreciated
by those of ordinary
skill in the art, the apparatuses and methods disclosed herein may be used in
conjunction with
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WO 2013/038397 PCT/1B2012/055129
other operations. For instance, the apparatuses and methods disclosed herein
may be used for
non-stimulation processes such as cementing; in particular squeeze cementing
or other squeeze
applications of chemicals, fluids, or foams.
As would be appreciated by those of ordinary skill in the art, although the
present
invention is described in conjunction with a hydrajetting tool, it may be
utilized with any
stimulation jetting tool where it would be desirable to minimize tool movement
and/or fluid leak
off. Moreover, as would be appreciated by those of ordinary skill in the art,
with the benefit of
this disclosure, any references to the term "sand" may include not only quartz
sand, but also
other proppant agents and granular solids. Additionally, as would be
appreciated by those of
ordinary skill in the art, with the benefit of this disclosure, although the
present invention is
described as using one PSIA, two or more PSIAs may be used simultaneously or
sequentially in
the same application to obtain desired results, without departing from the
scope of the present
invention.
As would be apparent to those of ordinary skill in the art, with the benefit
of this
disclosure, a flow reducer 402 in accordance with an embodiment of the present
invention may
be used to achieve a pressure drop of 1000 psig or more, which is typically
not achievable using
a simple choke.
Accordingly, a PSIA in accordance with an exemplary embodiment of the present
invention may be used to create sand plugs at a fracture in a wellbore to
substantially plug the
fracture opening. The flow rate of the sand slurry may be reduced to a desired
rate using a PSIA
as described in detail above. The low flow rate sand slurry may then be
discharged into the well
bore at a desired location, such as the opening of a fracture that is to be
plugged. As the sand
slurry is discharged, a sand dune is created proximate to the fracture
opening. A portion of the
sand slurry flows into an upper portion of the fracture and sand particles are
dropped down into
the wellbore. As sand particles are deposited onto the sand dune, the sand
dune becomes larger
until it substantially plugs the fracture opening. As would be appreciated by
those of ordinary
skill in the art, with the benefit of this disclosure, because of the low flow
rate of the sand slurry,
the sand dune is not disturbed as the sand slurry flows to the fracture
opening. Alternately, due to
the restricted flow rate the fracture below the hold-down will be closing and
becoming packed
with proppant or very narrow in the areas not fully propped such that if the
sand grains do not
fall back even at this reduced flow velocity they will ultimately pack off the
near-wellbore part
of the fracture and this pack will either cause flow to become so low that the
grains now fall or
will completely fill this fracture area and the pack will grow into the
wellbore and complete the
wellbore packoff and build a complete wellbore sand plug.
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CA 02848249 20150810
Therefore, the present invention is well-adapted to carry out the objects and
attain the
ends and advantages mentioned as well as those which are inherent therein.
While the
invention has been depicted and described by reference to exemplary
embodiments of the
invention, such a reference does not imply a limitation on the invention, and
no such
limitation is to be inferred. The invention is capable of considerable
modification, alteration,
and equivalents in form and function, as will occur to those ordinarily
skilled in the pertinent
arts and having the benefit of this disclosure. The depicted and described
embodiments of the
invention are exemplary only, and are not exhaustive of the scope of the
invention.
Consequently, the invention is intended to be limited only by the scope of the
appended
claims, giving full cognizance to equivalents in all respects. The terms in
the claims have
their plain, ordinary meaning unless otherwise explicitly and clearly defined
by the patentee.
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