Note: Descriptions are shown in the official language in which they were submitted.
WO 95/09964 ' ~ 21 l 3 3 ~ 0 PCT~S93/09399
METHOD AND APPARATUS FOR SEALING AND TRANSFERING
FORCE IN A WELLBORE
BACKGROUND OF THE INVENTION
1. Field of the Invention:
The present invention relates generally to methods and
apparatuses for forming downhole pressure plugs in a wellbore. More
particularly, the present invention relates to methods of forming downhole
plugs to seal the wellbore and to transfer stress from a wellbore tool to the
wellbore itself.
2. Description of the Prior Art:
It is conventional in the oil and gas industry to seal wellbores
using packers, bridge plugs, and the like. Typically, a wellbore tool, such
as a packer or bridge plug, is run into the wellbore to a desired location
therein. The packer or bridge plug is inflated or otherwise actuated into
sealing engagement with the wellbore. Such a seal may be effected to
separate regions in the wellbore, to contain fluid pressure either above or
below the wellbore tool for fracturing or other well treatment operations, or
other conventional reasons.
Conventional wellbore tools have a force threshold beyond
which the wellbore tool will fail mechanically, or will lose gripping and
sealing engagement with the wellbore, which tends to cause undesirable
movement of the wellbore tool within the wellbore. The force threshnm
typically is defined in terms of a maximum or limiting differential pressure
across the wellbore tool that the wellbore tool can withstand without
failure or movement in the wellbore.
WO 95/0996=t ~ 2 ~ 7 3 3 2 p PCT/US93/09399
2
If the force threshold is exceeded, mechanical failure of the
wellbore tool or undesirable movement of the wellbore tool may result.
Mechanical failure may result in at least partial inoperability of the
wellbore tool. If the wellbore tool is rendered inoperable, the wellbore
may be undesirably obstructed, requiring expensive fishing remedial
operations. Mechanical failure at least will require expensive and time-
consuming repair or replacement of the wellbore tool.
Even if the wellbore tool does not fail and is not otherwise
damaged, the wellbore tool may be moved or displaced within the
wellbore if the force threshold is exceeded. Such movement or
displacement is undesirable because the positioning of the wellbore tool
within the wellbore frequently is of great importance. Also, movement or
displacement of the wellbore tool could damage other wellbore tools or
the producing formation itself, thereby necessitating fishing, workover, or
other remedial wellbore operations.
In secondary recovery operations, such as formation
fracturing, reliable and dependable packers and bridge plugs frequently
are necessary. Many secondary recovery operations require sealing off
or packing a selected formation interval, and introducing extremely high
pressure fluids into the selected interval. High-pressure fluids exert
extreme axial forces on the packers or bridge plugs used to seal off the
interval. Thus, the possibility of exceeding the force threshold of such
wellbore tools is very great in formation fracturing, and requires the use
of expensive, reinforced, high-pressure rated wellbore tools. High-
pressure wellbore tools typically have relatively large cross-sectional
diameters, precluding their use in through-tubing operations or
operations in otherwise reduced-diameter or obstructed wellbores.
WO 95/09964 , _ ,~ PCT/US93/09399
'~' _ ~ ~ 3 ~ 11332
An alternative to high-pressure rated wellbore tools is to
plug or seal the wellbore with cement. Cement plugs have a number of
drawbacks. Expensive and specialized cementing equipment usually is
required to pump cement into the wellbore to form a cement plug. Also,
a significant time period must elapse to permit a cement plug to harden
' or set into a sealing or load-bearing cement plug. Another drawback of
cement plugs is that they are relatively permanent, and require expensive
and time-consuming milling operations to remove them from the wellbore.
CA 02173320 2003-10-08
4
SUMMARY OF THE INVENTION
it is one objective of an aspect of the present invention to provide
an apparatus for sealing a wellbore, wherein a first wellbore region is
isolated
from fluid communication with a second wellbore region.
It is another objective of an aspect of the present invention to
provide a method and apparatus for forming a sealing plug member within a
wellbore, wherein the plug member transfers force resulting from pressurized
fluid in the wellbore to the wellbore itself, obviating the need for high-
pressure
rated wellbore sealing tools.
It is yet another objective of an aspect of the present invention to
provide a method and apparatus for sealing a wellbore with a plug member that
is both strong and substantially fluid-impermeable, yet is easily and quickly
removable from the wellbore using conventional wellbore tools.
These and other objectives of the present invention are
accomplished by at least partially obstructing a wellbore with a partition or
obstruction member. A fluid slurry of an aggregate mixture of particulate
matter
is pumped into the wellbore adjacent the partition or obstruction member. The
aggregate mixture of particulate material contains at least one component of
particulate material, and each of the at least one particulate material
components has an average discrete particle dimension different from that of
the other particulate material components. Fluid pressure then is applied to
the
aggregate material and fluid is drained from the aggregate material through a
fluid drainage passage in the partition or obstruction member. The fluid
pressure and drainage of fluid from the aggregate mixture combined to
compact the aggregate mixture into a substantially solid, load-bearing, force-
transferring, substantially fluid-impermeable plug member, which seals a first
wellbore region from fluid flow communication with a second wellbo~e region.
The plug member is easily removed from the wellbore by directing a high-
pressure fluid stream toward the plug member, thereby dissolving or
CA 02173320 2003-10-08
disintegrating the particulate material of the plug member into a fluid
slurry,
which may be circulated out of or suctioned from the wellbore.
Preferably, the aggregate mixture of particulate matter contains a
binder component comprising a finely dispersed particulate material which is
5 capable of hydrating and swelling to fill pores or interstitial spaces
between
other particulate material components of the aggregate mixture of the plug
member.
In accordance with one aspect of the present invention there is
provided a load-bearir~~ end ~Aal~n J ap~arati ~e fnr i icP in a wellbore
subject to a
source of axial force, said wellbore having a wellbore surface defined therein
which forms at least a part of a wellbore passageway which allows
communication of fluids and objects between a first wellbore region and a
second wellbore region, comprising:
a partition member for selectively, and at least partially,
obstructing said wellbore passageway; and
a plug member, composed at least partially of a force-compacted,
and at least partially drained, particulate matter, for laterally transferring
a
selected amount of force from said source of axial force to said wellbore
surface.
In accordance with another aspect of the present invention there
is provided a load-bearing apparatus for use in a wellbore subject to an axial
force from a source of axial force, with fluid being disposed in at least a
portion
of said wellbore, said wellbore having a wellbore surface defined therein
which
at least partially defines a passageway which allows communication of fluids
and objects between a first wellbore region and a second wellbore region,
comprising:
a partition member for selectively, and at least partially,
obstructing said passageway;
CA 02173320 2003-10-08
5a
a plug member, composed at least partially of a fluid-force-
compacted particulate matter, for laterally transferring force from said
source of
axial force to said wellbore surface; and
a drain member for removing said fluid from at least a portion of
said plug member, at least during compaction, to allow compaction.
In accordance with yet another aspect of the present invention
there is provided a load-bearing and sealing apparatus for use in a wellbore
subject to axial force,~said wellbore having a wellbore conduit therein which
has
a central passageway defined therethrough which allows communication of
fluids and objects between a first wellbore region and a second wellbore
region, . .
comprising:
a partition member for selectively, and at least partially,
obstructing said central passageway of said wellbore conduit between said
first
wellbore region and said second wellbore region, which engages said wellbore
conduit and which can withstand axial force less than a failure threshold
amount; and
a plug member, composed at least partially of a particulate
matter, which has been mechanically compacted by said axial force and at
least partially drained during compaction, and a binder component for filling
interstitial spaces in said particulate matter, said plug member being
disposed
between a source of said axial force and said partition member, and being in
contact with said wellbore conduit;
wherein said plug member transfers to said wellbore conduit a
portion of said axial force in an amount at least as much as said axial force
exceeds said failure threshold amount, and thus protecting said partition
member from receipt of excessive axial force amounts; and
wherein said plug member defines a relatively substantially fluid-
impermeable barrier to minimize flow between said first wellbore region and
said second wellbore region.
In accordance with still yet another aspect of the present
invention there is provided a load-bearing and sealing apparatus for use in a
wellbore, said wellbore having a wellbore conduit therein which has a central
CA 02173320 2003-10-08
5b
passageway defined therethrough which allows communication of fluids and
objects between a first wellbore region and a second wellbore region, said
wellbore being coupled to a source of high pressure fluid, said apparatus
comprising:
a removable partition member for selectively, and at least
partially, obstructing said central passageway of said wellbore conduit
between
said first wellbore region and said second wellbore region, which engages said
wellbore conduit and which can withstand axial force less than a failure
threshold amount; and
9 0 a plug member, composed at (east partially of a particulate matter
which has been mechanically compacted between a fluid column provided by
said source of high pressure fluid and said removable partition member and a
binder component for filling interstitial spaces in said particulate matter,
said
plug member being disposed between said source of high pressure fluid and
said removable partition member, and in contact with said wellbore conduit;
which is operable in a plurality of operating modes, including:
(a) a plug member formation mode of operation wherein said
removable partition member is delivered to a selected location within said
central passageway of said wellbore conduit and urged into engagement with
said wellbore conduit, and said particulate matter and said binder component
are delivered to a selected position within said wellbore conduit adjacent
said
partition member and compacted by said fluid column provided by said source
of high pressure fluid to form said plug member;
(b) a force-transference and sealing mode of operation,
wherein at least said axial force in excess of said failure threshold is
transferred
laterally through said plug member to said wellbore conduit to minimize axial
force applied to said partition member and at least a portion of said
particulate
matter defines a relatively fluid-permeable barrier; and
an optional plug disintegration mode of operation, wherein said
plug member is disintegrated by application of a high pressure fluid stream
thereto.
CA 02173320 2003-10-08
5c
In accordance with still yet another aspect of the present
invention there is provided a pressure plug for use in a wellbore to transfer
force away from a wellbore tool disposed in the wellbore to the wellbore
itself,
the pressure plug comprising:
a mass of particulate matter formed adjacent said wellbore tool,
said mass of particulate matter including:
(a) at least one class of individual particulate matter that is
insoluble in water, each of said at least one class of individual particulate
material having an average particle dimension different from that of any other
class of the individual particulate material; and
a binder material.
In accordance with still yet another aspect of the present
invention there is provided a method of forming a pressure plug in a wellbore,
comprising the method steps of:
providing a plurality of types of particulate material, including at
least:
(a) a coarse granular material that is insoluble in water;
(b) an intermediate granular material that is insoluble in water;
(c) a fine granular material that is insoluble in water; and
(d) a colloid material;
forming a mixture of said plurality of types of particulate material;
depositing said mixture of said plurality of types of particulate
material adjacent a selected wellbore structure;
compacting said plurality of types of particulate material into a
plug by applying a high force fluid column thereto; and
draining fluid from at least a portion of said plug during at least
compaction.
In accordance with still yet another aspect of the present
invention there is provided an aggregate mixture for use in forming a pressure
plug in a wellbore, the aggregate mixture comprising:
CA 02173320 2003-10-08
5d
a plurality of types of particulate materials that are insoluble in
water, each type of the particulate materials having a particulate size range
which is different from that of the other types of particulate materials; and
a hydrating ultra-fine material.
In accordance with still yet another aspect of the present
invention there is provided a method of transferring axial force in a wellbore
from a fluid column to a wellbore surface, comprising the steps of:
at least partially obstructing a portion of said wellbore with an
obstructing member;
delivering a mass of particulate material to said wellbore in a
position adjacent said obstructing member;
applying said axial force from said fluid column to said mass of
particulate material causing mechanical compaction of said mass of particulate
material and reducing fluid permeability of said mass of particulate material;
and
transferring through said mass of particulate material a selected
amount of axial force to said wellbore surface.
In accordance with still yet another aspect of the present
invention there is provided a method of transferring stress from a wellbore
tool
disposed in a wellbore to the wellbore itself, the method comprising the steps
of:
delivering an aggregate mixture into said wellbore wherein said
aggregate mixture is deposited proximally to said wellbore tool;
applying force to said aggregate mixture; and
removing fluid from said aggregate mixture to form a substantially
solid, substantially fluid-impermeable plug of said aggregate mixture, wherein
force loads on said wellbore tool are transferred by said substantially solid
substantially fluid-impermeable plug to said wellbore and away from said
wellbore tool.
In accordance with still yet another aspect of the present
invention there is provided a load-bearing and sealing apparatus for use in a
wellbore subject to a source of axial force, said wellbore having a wellbore
CA 02173320 2003-10-08
5e
surface defined therein which forms at least a part of a wellbore passageway
which allows communication of fluids and objects between a first wellbore
region and a second wellbore region, comprising:
a partition member for selectively, and at least partially,
obstructing said wellbore passageway; and
a plug member, composed at least partially of a force-compacted,
and at least partially drained, particulate matter, for laterally transferring
a
selected amount of axial force from said source of axial force to said
wellbore
surface, and at least one layer of drainage material disposed adjacent said
particulate matter.
In accordance with still yet another aspect of the present
invention there is provided a load-bearing and sealing apparatus for use in a
wellbore subject to a source of axial force, said wellbore having a wellbore
surface defined therein which forms at least a part of a wellbore passageway
which allows communication of fluids and objects between a first wellbore
region and a second wellbore region, comprising:
a partition member for selectively engaging and sealing against
said wellbore surface, and being able to withstand safely a differential
pressure
up to a particular limiting differential pressure; and
a plug member, composed at least partially of a force-compacted,
and at least partially drained, particulate matter, for laterally transferring
a
selected amount of force from said source of axial force to said wellbore
surface, enabling said partition member to operate safely when exposed to
differential pressures which exceed said particular limiting differential
pressure.
In accordance with still yet another aspect of the present
invention there is provided a load-bearing apparatus for use in a wellbore
comprising:
a wellbore tool for at least partially obstructing a wellbore
passageway; and
a plug member, composed at least partially of a force-compacted,
and at least partially drained, particulate matter, for anchoring said
wellbore tool
relative to said wellbore passageway.
CA 02173320 2003-10-08
5f
In accordance with still yet another aspect of the present
invention there is provided a load-bearing and sealing apparatus for use in a
wellbore subject to axial force, said wellbore having a wellbore surface
therein
which at least partially defines a central passageway which allows
communication of fluids and objects between a first wellbore region and a
second wellbore region, comprising:
a partition member for selectively, and at least partially,
obstructing said central passageway between said first wellbore region and
said
second wellbore region, which engages said wellbore surface and which can
withstand axial force less than a failure threshold amount; and
a plug member, composed at least partially of a particulate
matter, which has been mechanically compacted by said axial force and which
is disposed between a source of said axial force and said partition member,
and in contact with said wellbore surface;
wherein said plug member transfers to said wellbore surface a
portion of said axial force in an amount at least as much as said axial force
exceeds said failure threshold amount, and thus protecting said partition
member from receipt of excessive axial force amounts; and
wherein said plug member defines a relatively substantially fluid
impermeable barrier to minimize flow between said first wellbore region and
said second wellbore region.
In accordance with still yet another aspect of the present
invention there is provided a load-bearing and sealing apparatus for use in a
wellbore, said wellbore having a wellbore surface therein which at least
partially
defines a passageway which allows communication of fluids and objects
between a first wellbore region and a second wellbore region, said wellbore
being coupled to a source of high pressure fluid, said apparatus comprising:
a removable partition member for selectively, and at least
partially, obstructing said passageway between said first wellbore region and
said second wellbore region, which 'engages said wellbore surface and which
can withstand axial force less than a failure threshold amount; and
CA 02173320 2003-10-08
5g
a plug member, composed at least partially of a particulate matter
which has been mechanically compacted between a fluid column provided by
said source of high pressure fluid and said removable partition member and a
binder component for filling interstitial spaces in said particulate matter,
said
plug member being disposed between said source of high pressure fluid and
said removable partition member, and in contact with said wellbore surface;
which is operable in a plurality of operating modes, including:
(a) a plug member formation mode of operation wherein said
removable partition member is delivered to a selected location within said
central passageway and urged into engagement with said wellbore surface,
and said particulate matter and said binder component are delivered to a
selected position within said wellbore adjacent said partition member and
compacted by said fluid column provided by said source of high pressure fluid
to form said plug member;
(b) a force-transference and sealing mode of operation,
wherein at least said axial force in excess of said failure threshold amount
is
transferred laterally through said plug member to said wellbore surface to
minimize axial force applied to said partition member and at least a portion
of
said particulate matter defines a relatively fluid-permeable barrier; and
(c) an optional plug disintegration mode of operation, wherein
said plug member is disintegrated by application of a high pressure stream
thereto.
In accordance with still yet another aspect of the present
invention there is provided a load-bearing apparatus for use in a wellbore
subject to an axial force from a source of axial force, with fluid being
disposed
in at least a portion of said wellbore, said wellbore having a wellbore
surface
defined therein which at least partially defines a passageway which allows
communication of fluids and objects between a first wellbore region and a
second wellbore region, comprising:
a partition member for selectively, and at least partially,
obstructing said passageway;
CA 02173320 2003-10-08
5h
a plug member, composed at least partially of a fluid-force-
compacted particulate matter, for laterally transferring force from said
source of
axial force to said wellbore surface; and
a drain path defined relative to said partition member for
removing said fluid from at least a portion of said plug member, at least
during
compaction, to allow compaction.
In accordance with still yet another aspect of the present
invention there is provided a pressure plug for use in a wellbore to transfer
force away from a wellbore tool disposed in the wellbore to the wellbore
itself,
the pressure plug comprising:
a mass of particulate matter formed adjacent said wellbore tool,
said mass of particulate matter including:
(a) at least one class of individual particulate matter that is
insoluble in water, each of said at least one class of individual particulate
material having a particle dimension range different from that of any other
class
of the individual particulate material; and
(b) a binder material.
In accordance with still yet another aspect of the present
invention there is provided a method of forming a pressure plug in a wellbore,
comprising the steps of:
providing particulate material, including at least one of:
(a) a coarse granular material that is insoluble in water;
(b) an intermediate granular material that is insoluble in water;
and
(c) a fine granular material that is insoluble in water;
providing a binder material;
forming a mixture of said particulate material and said binder
material;
depositing said mixture of said particulate material and said
binder material adjacent a selected wellbore structure;
compacting said of particulate material into a plug by applying a
high force fluid column thereto; and
CA 02173320 2003-10-08
5i
draining fluid from at least a portion of said plug during at least
compaction.
Other objects, features and advantages of the present invention
will become apparent to those skilled in the art with reference to the
drawings
and detailed description, which follow.
~ , 2 ~ 7 3 3 2 0 pCT~S93/09399
WO 95/09964 , , . ,.
BRIEF DESCRIPTION OF THE DRAWINGS
The novel features believed characteristic of the invention are
set forth in the appended claims. The invention itself, however, as well as .
a preferred mode of use, further objectives and advantages thereof, will best
be understood by reference to the following detailed description of an
illustrative embodiment when read in conjunction with the accompanying
drawings, wherein:
Figure 1 illustrates, in partial longitudinal section, a wellbore
including the apparatus according to the present invention;
Figure 2 schematically illustrates relative sizes of the
particulate matter that makes up the aggregate mixture, which forms a plug
member according to the present invention;
Figure 3 schematically depicts a wellbore containing
coarse sand particles;
Figure 4 illustrates a wellbore containing an aggregate
mixture in accordance with the present invention;
Figure 5 is a table illustrating the results of permeability
tests performed on various mixtures and aggregate mixtures for use in
forming a plug member according to the present invention;
Figure 6 depicts a superimposition of a pair of graphs of
data obtained during testing of a pressure plug or plug member
according to the present invention;
WO 95/09964 . __ ~ -- . ~ ~ ~ ~ PCT/LTS93/09399
s
7
Figure 7 is a graph comparing the pressure rating of
conventional high-pressure rated inflatable packers with the pressure
rating of plug member formed according to the present invention;
Figure 8 is a partial longitudinal section view of the sealing
' and load-bearing apparatus of Figure 1, the apparatus being shown in a
plug member removal or washing-out mode of operation; and
Figures 9a through 9e should be read together and depict
a one-quarter longitudinal section view of a partition or obstruction
member according to the present invention.
WO 95/09964 , , " " ~ ~ ~ ~ ~ PCT/US93/09399
8
DETAILED DESCRIPTION OF THE INVENTION
Referring now to the figures, and specifically to Figure 1, a
preferred embodiment of the wellbore apparatus according to the present
invention will be described. Figure 1 illustrates, in partial longitudinal
section, a wellbore 1. Wellbore 1 is shown as a cased wellbore, but the
present invention is contemplated for use in open wellbores, production
tubing, or the like, having conduit or a fluid passageway therethrough in
which a pressure-tight seal may be advantageous. Wellbore 1 is provided
with a source of axial force, in this case a workstring 3. In the case of
workstring 3, the source of axial force is fluid pressure, but may be any
other source of axial force. A removable partition or obstruction member 5
is disposed in wellbore 1. In this case, partition or obstruction member is
an inflatable packer 5. However, the obstruction or partition member may
be any sort of wellbore tool that is capable of selectively, and at least
partially obstructing fluid flow from a first region of wellbore 1 from a
second
region. Inflatable packer 5 is provided at an upper extent with a screen
filter
assembly 7, and at a lower end with fluid outlet 9. The utility and function
of screen filter 7 and fluid outlet 9 will be described hereinafter.
A pressure plug or plug member 11 according to the present
invention is disposed adjacent to and above inflatable packer 5. Plug
member 11 comprises a compacted aggregate mixture of particulate matter.
Plug member 11 provides a substantially fluid-impermeable seal in wellbore
1, and thereby isolates a first region of wellbore 1 from fluid flow
communication with a second region. Further, plug member 11 serves to
transfer axial force from the source of axial force (in this case, fluid
pressure
from workstring 3) laterally to wellbore 1, thereby permitting use of a lower-
WO 95/0996 , ~ ~ ~ pCT/US93/09399
.. 9
pressure rated inflatable packer 5 or other obstruction or partition member.
The specific wellbore operation illustrated in Figure 1 is a
secondary recovery operation, such as formation fracturing. Thus, wellbore
1 is provided with two sets of perforations 13, 15. Each set of perforations
13, 15 and the area defines a region in wellbore 1. In secondary rer;overy
operations, it may be advantageous to isolate one set of perforations, in this
case upper set 13, from another set of perforations, in this case lower set
15, so that secondary recovery operations can be directed to only one
formation through a single set of perforations 13. The secondary recovery
operation illustrated in Figure 1 is known conventionally as fracturing the
formation. In such a fracturing operation, wellbore 1 is packed-off,
preferably with a plug member 7 according to the present invention.
Workstring 3 then is run into wellbore 1, and fracturing fluid 17, which is
conventional, is pumped into wellbore 1, out through perforations 13, and
into the formation. Frequently, tremendous pressures are required to force
fracturing fluid 17 into the formation. These fluid pressures may be exerted
on wellbore 1, plug member 11, and inflatable packer 5. Such a fracturing
operation, if employing only an inflatable packer 5 or other wellbore tool,
would require inflatable packer 5 to withstand extreme differential pressure,
and the resulting axial force, without mechanical failure or movement within
wellbore 1. Accordingly, such high-pressure rated inflatable packers 5, as
well as other high-pressure rated wellbore tools, are very expensive.
Additionally, such wellbore tools generally are larger in diameter, which may
preclude their use in through-tubing workover operations.
Plug member 7 is advantageous in that it provides a
substantially fluid-impermeable seal in wellbore 1, and transfers axial force
(caused in this case by fluid pressure from workstring 3) laterally to the
WO 95/09964 , ; - ~ ~ ~ PCT/US93/09399
wellbore and away from inflatable packer 5. Therefore, low-pressure rated
inflatable packers 5, or other low-pressure rated wellbore tools, can be used
in conjunction with plug member 11 according to the present invention and
still maintain a substantially fluid-impermeable and strong seal in wellbore
1. .
Figure 2 schematically illustrates the relative sizes of the
classes of particulate matter that makes up the aggregate mixture that forms
plug member 11 according to the present invention. Preferably, the
particulate matter is silica sand, or silicon dioxide. Sand particles 21
schematically represent grains of conventional, coarse 20/40 mesh, sand.
The term "mesh" is conventional in the industry and represents an average
discrete particle size for particulate materials, particularly sand.
Recommended Practice Number 58, entitled "Recommend Practices for
Testing Sand Used in Gravel Packing Operations," published by the
American Petroleum Institute, Dallas, Texas, is exemplary of the
measurement of average discrete particle size of sands. Intermediate sand
grains 23 schematically illustrate the size of 100 mesh silica sand, as
contrasted to the size of coarse 20/40 mesh silica sand. Fine sand particles
25 schematically illustrate the relative size of 200 mesh sand particles, as
contrasted to intermediate 100 mesh sand particles 23 and coarse 20/40
mesh sand particles 21. According to the present invention, an aggregate
mixture of silica sand particles of various dimensional classes or mesh sizes
is employed to form plug member 11. The use of sand particles 21, 23, 25
of varying average discrete particle dimension is important to forming the
substantially fluid-impermeable, force transferring plug member 11 according
to the present invention.
Figure 3 schematically depicts a wellbore 101 containing
coarse sand particles 121. Coarse sand particles 121 are schematically
depicted as particles of 20/40 mesh silica sand, as illustrated in Figure 2.
WO 95/09964 PCT/US93/09399
v 11 2113320
As is illustrated, there are numerous pores and interstitial spaces between
individual sand particles 121. These pores or interstitial spaces permit the
sand to be fluid-permeable, and also provide room for individual sand
particles 121 to displace relative to each other in response to forces applied
to the sand.
Figure 4 illustrates a wellbore 201 containing a plug member
211 in accordance with the present invention. Plug member 211 comprises
an aggregate mixture of coarse, 20/40 mesh sand particles 221,
intermediate, 100 mesh sand particles 223, and fine, 200 mesh sand
particles 225. As is illustrated, the aggregate mixture of coarse,
intermediate, and fine sand particles cooperate to reduce the volume of
pores and interstitial spaces between the various sand particles 221, 223,
225. Such an aggregate mixture results in a more substantially fluid-
impermeable plug member 211, and provides less space for individual sand
grains to displace and move in response to forces exerted on plug member
211.
Figure 5 is a table illustrating the results of permeability tests
performed on various mixtures and aggregate mixtures for use in forming
plug member 11, 211 according to the present invention. In the left hand
column is a number assigned to each test performed. The central column
indicates the volumetric percentage of each component making up the
aggregate mixture, wherein component A is 20/40 mesh silica sand
(illustrated as 21 in Figure 2, 121 in Figure 3, and 221 in Figure 4),
component B is 100 mesh silica sand (illustrated as 223 in Figure 4),
component C is 200 mesh silica sand (illustrated as 225 in Figure 4), and
component D is a bentonite or clay "gel." the right hand column indicates
the measured or estimated fluid permeability of the mixture or aggregate
WO 95/09964 M , , , ~ ~ 7 3 ~ 2. 0 pCT~S93/09399
12
mixture tested, in millidarcies. The Darcy is a unit of fluid permeability of
materials, which is determined according to Darcy's law, which follows:
K=GAL
PA
wherein, P = pressure across sand (in bars);
~, = dynamic viscosity of fluid (in centipoise);
A = cross-sectional area of sand (in square centimeters);
L = length of sand column (in centimeters);
Q = volume flow rate of effluent from sand column (in milliliters
per second); and
K = permeability (in centimeters per second).
Accordingly, each aggregate sand mixture tested was formed
into a column of known length L, and known cross-sectional area A. A fluid
having a known dynamic viscosity ~,, in this case water, was placed at one
end of the sand column at a known pressure P. At an opposite end of the
column, the flow rate of fluid effluent through the column Q was measured.
The foregoing known and measured data was inserted into the above-
identified mathematical statement of Darcy's law, and a permeability K was
obtained in millidarcies. For test number one, a sand column of 100%
20/40 mesh sand was tested, and yielded an estimated permeability of
2,800 millidarcies. As a second test, an aggregate mixture containing 60%
by volume 20/40 mesh sand, 20% by weight 100 mesh sand, and 20% by
weight 200 mesh sand was tested, and yielded a permeability of 66
millidarcies. As a third test, an aggregate mixture of 80% by weight 20/40
mesh sand, 10% by weight, 100 mesh sand, and 10% by weight 200 mesh
sand was tested and yielded a permeability of 415 millidarcies. As a fourth
test, an aggregate mixture of 60% by weight 20/40 mesh sand, 30% by
weight 100 mesh sand, and 10% by weight 200 mesh sand was tested and
yielded a permeability of 233 millidarcies. As a fifth test, an aggregate
WO 95/09964 '. PCT/US93/09399
13
mixture of 60% by weight 20/40 mesh sand, 10% by weight 100 mesh sand,
and 30% by weight 200 mesh sand was tested and yielded a permeability
of 51 millidarcies. As a sixth test, an aggregate mixture of 40% by weight
20/40 mesh sand, 30% by weight 100 mesh sand, and 30% by weight 200
mesh sand was tested and yielded a permeability of 50 millidarcies.
Test numbers 7, 8 and 9 reflect aggregate mixtures that are
preferred for use in forming plug member 11, 211 according to the present
invention. The aggregate mixtures tested in tests 7, 8 and 9 contain a fourth
or binder component, five to ten percent by weight of bentonite. Bentonite
is a rock deposit that contains quantities of a desirable clay mineral called
montmorillonite. Montmorillonite is a colloidal material that disperses in
fluid
or water into individual, flat, plate-like clay crystals with dimensions
ranging
between about five and five hundred millimicrons. The flat plate-like clay
crystals presumably overlap each other very tightly to produce a generally
substantially fluid-impermeable structure. Additionally, montmorillonite
crystals "hydrate" in water, wherein water molecules bond to the crystals,
causing the crystals to swell to enlarged dimensions, which may further
obstruct pores or interstitial spaces between coarser particles. Bentonite or
bentonitic clays are interchangeable terms for any clay-like material
possessing the properties discussed herein.
The addition of a binder of bentonite or bentonitic clay material
to the aggregate mixtures described herein results in an aggregate mixture
having an extremely low fluid permeability. It is believed that the
microscopic nature of the clay particles, combined with their ability to
hydrate and swell, permits the clay particles to fill and almost completely
obstruct any pores or interstitial spaces remaining in an aggregate sand
mixture (as illustrated in Figure 4). This theory is borne out by the test
results in tests 7, 8, and 9. For test 7, an aggregate mixture of 60% by
,. ~ ~ 7 3 3 2 Q PCT/US93/09399
WO 95/09964
s ~ r.
14
weight 20/40 mesh sand, 20% by weight 100 mesh sand, 15% by weight
200 mesh sand, and 5% by weight of bentonite material was tested and
yielded a permeability of 0.064 millidarcies. For test number 8, an
aggregate mixture of 60% by weight 20/40 mesh sand, 15% by weight 100 .
mesh sand, 10% by weight 200 mesh sand, and 15% by weight of bentonite
material was tested, and yielded permeability of 0.063 millidarcies. For a
ninth and final test, an aggregate mixture of 60% by weight 20/40 mesh
sand, 20% by weight 100 mesh sand, 15% by weight 200 mesh sand, and
5% by weight bentonite material was tested and yielded a permeability of
0.081 millidarcies.
From the foregoing test results, trends indicating preferred
compositions of aggregate mixtures for use in forming plug member 11, 211
according to the present invention can be noted. Marked decreases in fluid
permeability are obtained by adding significant quantities of fine sand
particles, such as 200 mesh sand, to a mixture containing coarse sand and
intermediate sand components. A further reduction in permeability is
obtained by adding ultra-fine, hydrating particles, such as bentonite or
bentonitic clay materials.
Figure 6 depicts a superimposition of a pair of graphs of data
obtained during testing of a pressure plug or plug member 311 according
to the present invention. As illustrated in the central portion of Figure 6,
the
test rig comprises an artificial wellbore, in this case a length of casing
301,
with a partition member, in this case an inflatable packer 305, disposed
within wellbore 301. Inflatable packer 305 is further provided with a screen
filter 307 at an uppermost end thereof, which is in fluid communication with
a fluid exhaust member 309 at a lowermost extent of inflatable packer 305.
WO 95109964 . ~ , ~ -, ~ ~ ~ PCT/US93/09399
Adjacent and atop inflatable packer 305 is column of drainage
sand 331 approximately 3 feet in height. Drainage sand 307 is a coarse,
preferably 20/40 mesh, silica sand. Because the relatively coarse drainage
sand 331 has a significant quantity of pores and interstitial spaces between
individual sand particles, 307 will function as a pre-filter for fluid
entering
screen filter 307 of inflatable packer 305. Such a pre-filter is advantageous
to prevent extremely fine particles from entering inflatable packer 305 and
tending to cause abrasion and resulting failure of inflatable packer 305.
It is believed to be important to provide either a column of
drainage sand, or to maximize the content (consistent with the desired level
of fluid-impermeability) of relatively coarse (20/40 mesh silica sand)
particles
in the aggregate mixture so that drainage of plug members 11, 211, 311 is
enhanced and to facilitate removal of plug member 11, 211, 311, by
washout. Without coarse particles, plug member 11, 211, 311 may
compact into a rock-like member that cannot be removed easily.
A pressure plug or plug member 311 according to the present
invention is formed atop drainage sand 331. According to the preferred
embodiment of the present invention, plug member 311 is a column of
aggregate mixture as described herein that is twelve inches in height. The
preferred aggregate mixture is that described with reference to test number
7 (60% by weight 20/40 mesh silica sand, 20% by weight 100 mesh silica
sand, 15% by weight 200 mesh silica sand, and 5% by weight bentonite),
having a measured fluid permeability of 0.064 millidarcies.
A quantity of pressurized fluid, in this case water 317, is
disposed in wellbore above plug member 311. Pressurized fluid 317 serves
as the source of axial force in the illustrated preferred embodiment.
Pressurized fluid 317 exerts hydrostatic pressure both in a radial and an
WO 95/09964 -. , . ~ ~ ~ ~ PCT/US93/09399
16
axial direction within wellbore 301. Because wellbore 301 typically is
extremely strong, and resistant to deformation, the axial force component,
which otherwise would act directly on inflatable packer 305, is the quantity
of interest for purposes of the present invention.
Wellbore 301 is provided with a number of strain gauges 333,
335, 337, 339, 341, which measure normalized hoop stress in wellbore 301,
thereby giving an indication of force transferred through plug member 311
to wellbore 301.
During the test illustrated in Figure 6, pressurized fluid 317
was stepped-up in pressure in 1,000 pounds per square inch (psi)
increments ranging from 0 psi to 9,000 psi. The resulting strain gauge
outputs, 343, 345, 347, 349, 351, and implicit force measurements, are
plotted over the range of pressure increases in the left hand portion of
Figure 6. The abscissa axis of the left hand graph plots the magnitude of
fluid pressure in pressurized fluid 317 in wellbore 301. The ordinate axis of
the left hand graph plots hoop stress values measured by stain gauges 333,
335, 337, 339, 341. As is illustrated, strain gauge 333, which is located on
an exterior of wellbore 301 at a point in which wellbore 301 is filled with
pressurized fluid, shows the largest variation in measured hoop stress 343
as fluid pressure is increased. Strain gauge 335 which is located on the
exterior of wellbore 301 where wellbore 301 is obstructed by plug member
311, indicates the second highest change in measured hoop stress 345.
Stain gauge 337, which is located on the exterior of wellbore 301 at a point
where wellbore 301 is filled with drainage sand 331, but above sand filter
307, measures a hoop stress 347 maximum of approximately 1,000 psi.
Strain gauge 339, which is located on the exterior of wellbore 301 at a
location where wellbore 301 is filled with drainage sand 331 and sand filter
307, measures a hoop stress 349 maximum of somewhat less than 1,000 ,
WO 95!09964 ~ ; ~ ~ ~ PCT/US93/09399
17
psi. Strain gauge 341, which is located on the exterior of wellbore 301
wherein wellbore 301 is filled with drainage sand 331, and is just below
screen filter 307 measures a hoop stress 351 maximum of less than 500 psi.
The right hand graph of Figure 6 depicts the pressure
distribution over the length of wellbore 301, from areas filled by pressurized
fluid 317 to the top of inflatable packer 305. The abscissa axis of the right
hand graph plots measured hoop stress values, and is substantially similar
to the ordinate axis of the left hand graph. The ordinate axis of the right
hand graph corresponds with the height of wellbore 301 and correlates
transfer of force from pressurized fluid 317 through plug member 311 and
drainage sand 331, to wellbore 301. As is illustrated, upper right portion
451 of the plotted line is substantially vertical and reflects a relatively
uniform
pressure distribution in wellbore 301, which is to be expected because at
that point, wellbore 301 is filled with pressurized fluid 317, which exerts a
generally uniform hydrostatic pressure on wellbore 301. A central portion
453 of the plotted line indicates a significant measured pressure drop in
wellbore 301 where wellbore 301 is occupied by plug member 311
according to the present invention. A lower left portion 455 of the plotted
line indicates a fairly steady, maintained low pressure, which averages less
than 1,000 psi in wellbore 301. The significant pressure drop in wellbore
301 where it is occupied by plug member 311 according to the present
invention indicates that the axial force exerted by pressurized fluid 317
substantially is transferred by sand plug 311 to wellbore 301. Thus, a
relatively insignificant axial force load of generally less than 1,000 psi is
experienced by drainage sand and inflatable packer 305. Because such a
large magnitude of axial force resulting from pressurized fluid 317 in
wellbore 301 is transferred to the generally stronger wellbore 301, much
weaker and less expensive inflatable packers 305, or other wellbore tools
may be employed with plug member 311 according to the present invention
WO 95/0996. v , y -_ ; '" ~ ~ ~ PCT/LTS93/09399
18
to seal a first wellbore region against fluid flow to or from a second
wellbore
region.
Figure 7 is a graph comparing the pressure rating of
conventional high-pressure rated inflatable packers (such as 305 in IFigure
6) with the pressure rating of plug member 11, 211, 311 formed according
to the present invention. The abscissa axis of the graph plots the values of
limiting differential pressure of failure threshold that each type of sealing
member can withstand and maintain effective sealing integrity. The ordinate
axis plots the casing inner diameter of the wellbore to be sealed. Plotted
line 457 represents the pressure rating of a high-pressure rated, 3 3/8"
outer diameter inflatable packing element. The ability of the packing
element to withstand pressure differentials (limiting differential pressure in
Figure 7) is a function of the diameter of the casing or wellbore that the
inflatable packer must seal. For small diameter casing, such as 4 1 /2"
casing, the limiting differential pressure or failure threshold is relatively
high
at approximately 9,000 psi. However, as the casing or wellbore diameter
increases, the inflatable packer must expand further to sealingly engage the
casing inner diameter, thus reducing the pressure differential (limiting
differential pressure) that it is capable of withstanding. Therefore, for a
large
diameter casing, such as 10 3/4" diameter casing, the inflatable packer can
only withstand a pressure differential (limiting differential pressure) of
approximately 2,000 psi. In contrast, the pressure rating of a plug member
11, 211, 311, according to the present invention is much higher, and is less
sensitive to casing diameter than are conventional inflatable packing
elements. Area 459 of Figure 7 represents the pressure rating of plug
members 11, 211, 311 formed according to the present invention, as
predicted by tests conducted substantially as described with reference to
frigure 6. As is illustrated, in relatively small diameter casing, plug
members
11, 211, 311 can withstand pressure differentials (limiting differential
WO 95/09964 w ~, ~ ~ 7 3 3 2 0 pCT~S93109399
19
pressure) of upwards of 14,000 psi. In larger diameter casing, plug
members 11, 211, 311 formed according to the present invention can
withstand pressure differentials (limiting differential pressure) of upwards
of
_ 5,000 psi. From the data depicted in Figure 7, it becomes apparent that
plug members 11, 211, 311 formed according to the present invention
possess significant advantages over conventional inflatable packer elements
and other wellbore tools.
Figure 8 is a partial longitudinal section view of the sealing and
load-bearing apparatus of Figure 1, the apparatus being shown in a plug
member 11 removal or washing-out mode of operation. As in Figure 1,
wellbore 1 has removable partition or obstruction member 5, including
screen filter member 7 and fluid exhaust member 9, and plug member 11
disposed therein. Original fracturing workstring 3 is replaced by a
circulating or washout workstring 503. Circulating or washout workstring
503 is provided with a nozzle at a terminal end thereof for directing a high-
pressure fluid stream 19 toward plug member 11. High pressure fluid
stream 19 is provided to dissolve or wash out plug member y 1. As is
illustrated, the impact of high pressure fluid stream 19 upon plug member
11 causes the particulate matter of plug member 11 to separate into
discrete particles. Relatively slow-moving wellbore fluid suspends the
particles of particulate matter so that the particulate matter and wellbore
fluid
505 may be circulated out of or suctioned from wellbore 1. After plug
member 11 is fully disintegrated, inflatable packer member 5 may be
conventionally deflated and retrieved. Therefore, plug member 11 according
to the present invention, while stronger and capable of bearing more load
with excellent sealing integrity, is simply and easily removed from wellbore
1 when its presence is no longer desirable.
WO 95/09964 t ', 2 ~ 7 3 3 2 p pCT~S93/09399
ti figures 9a through 9e, which should be read together, depict
in one-quarter longitudinal section, a partition or obstruction member, in
this
case an inflatable bridge plug 605, according to the present invention. A
screen filter 607 is provided at an uppermost end of bridge plug 605.
Screen filter 607 is plugged at its upper end with plug member 611. A
connection tube 613 connects a lower extent of screen filter 607 in fluid
communication with fishing neck 615. Fishing neck 615 is provided with a
fluid flow conduit 615a therethrough for fluid communication with upper
element adapter 617. Upper element adapter 617 is connected by threads
to fishing neck 615, and is provided with a fluid conduit 617a therethrough
and is connected by threads to poppet housing 619.
A mandrel 621 is connected by threads to upper element
adapter 617. Mandrel 621 is provided with a fluid conduit 621 a
therethrough, and also includes a fluid port 621 b. A poppet 623 is disposed
between an exterior of mandrel 621 and an interior of poppet housing 619.
Poppet 623 is further provided with a pair of seal members 623a. Poppet
is biased upwardly by a biasing member or spring 625.
An element adapter 627 is connected by threads to poppet
housing 619. Element adapter 627 is connected by threads to an upper
element ring 629. Upper element ring 629 cooperates with upper wedge
ring 631 to secure a conventional inflatable packer element 633 to element
ring 629. Inflatable packer element 633 is conventionally constructed of
elastomeric materials and a plurality of circumferentially overlapping
flexible
metal strips.
A lower element ring 635 is secured to inflatable packing
element 633 by lower wedge ring 637. Lower element ring 629 is connected
by threads to a lower element adapter 639. Lower element adapter 639 is
WO 95/09964
PCT/US93/09399
21
provided with a threaded bleed port 641, which is selectively opened and
closed to bleed air from between mandrel 621 and inflatable packing
element 633 during assembly of bridge plug 605. Lower adapter 639 is
- connected by threads to a lower housing 643. Lower housing 463 is
secured to mandrel 621 by means of a shear member 645, which permits
' relative motion between lower housing 643 and mandrel 621 upon
application of a force sufficient to fail shear member 645.
A guide shoe 647 is connected by threads to mandrel 621,
and is provided with a fluid conduit 647a in fluid communication with fluid
conduit 621 a of mandrel 621. Guide shnP ~a~ ~~ f~ ~rthcr nrnvirlcrl ,~,~+h
closure member, in this case a ball seat 647b, which is adapted to receive
a ball 649 to selectively obstruct fluid flow through inflatable bridge plug
605.
Preferably, ball seat 647b is a pump-through ball seat, which will release
ball
649 and permit fluid flow out of bridge plug 605 upon application of fluid
pressure of selected magnitude.
In operation, bridge plug 605 according to the present
invention is assembled into a workstring (not shown) at the surtace of the
wellbore (not shown) and is run into the wellbore to a desired location. At
the desired location in the wellbore, bridge plug 605 may be set actuated
or inflated into sealing engagement with the wellbore by the following
procedure.
Pressurized fluid is pumped through workstring and enters
bridge plug 605 through screen filter 607. Pressurized fluid flows from
screen filter, fluid conduit 613a in connection tube 613, through fluid
conduit
615a in fishing neck 615, through fluid conduit 617a of upper adapter 617,
and into fluid conduit 621 a of mandrel 621. Closure member 647b, 649,
obstructs the fluid conduit in 621 a in mandrel 621 so that fluid pressure may
WO 95/09964
2 ~ 7 3 3 2 Q pCT~S93/09399
22
be increased inside mandrel 621. As fluid pressure increases, fluid flows
through port 621b into a chamber defined between mandrel 621, upper
adapter 617x, poppet housing 619, and poppet 623. Responsive to fluid
pressure, poppet 623 moves relative to mandrel 621 and poppet housing
619 when the fluid pressure differential acting on poppet 623 exceeds the
biasing force of biasing member 625. As poppet 623 moves relative to
poppet housing 619, poppet 623 moves past a shoulder 619a formed in the
interior wall of poppet housing 619, wherein pressurized fluid is permitted
to flow around poppet 623 and poppet seal member 623x. Fluid continues
to flow between the exterior of mandrel 621 and inflatable packing element
633 to inflate inflatable packing member 629.
Inflation of inflatable packing element 633 will cause shear
member 645 in lower housing 643 to fail, thereby permitting relative
movement between mandrel 621 and lower packing element assembly
(which includes lower element ring 635, wedge ring 637, lower element
adapter 639, and lower housing 643). Inflation of inflatable packer element
633 and relative movement between the lower element assembly and
mandrel 621 permits inflatable packing element 633 to extend generally
radially outwardly from mandrel 621 and into sealing engagement with a
sidewall of the wellbore.
After sealing engagement is obtained, fluid pressure within
mandrel 621 may be reduced, which permits biasing member 625 to return
poppet 623 to its original position, blocking fluid flow out of the inflation
region defined between mandrel 621 and inflatable packing element 631.
Bridge plug 605 described herein is arranged as a permanent
bridge plug. Permanent bridge plugs, once set or inflated, cannot be
deflated or unset and removed from the wellbore. It is within the scope of
WO 95/09964 ° =,y r ;~- F ~ 21 l 3 3 2 0 PCT~S93/09399
'- . .~. 23
the present invention, however, to provide a retrievable bridge plug, which
may be selectively inflated and deflated and removed from or repositioned
in the wellbore. Such a retrievable bridge plug may be obtained by provision
of conventional deflation means to permit selective inflation and deflation of
the retrievable bridge plug. Bridge plug 605 according to the present
invention provides a drainage passage 621a, in fluid communication with
drainage sand (331 in Figure 6) through sand screen 607, and in
communication with an exhaust member (guide shoe 649) to provide
drainage of fluid from the plug member according to the present invention.
With reference now to Figures 1 through 9e, the operation of
the present invention will be described. The following description is of a
through-tubing formation fracturing operation. However, the present
invention is not limited in utility to either through-tubing operations or
fracturing and other secondary operations.
As a preliminary step, workstring 3 is prepared at the surface
with a terminal end or sub adapted for delivering and setting a partition or
obstruction member, preferably inflatable packer 5, 605. Partition or
obstruction member 5, 605 need not, however, be inflatable packer 5, 605,
but could be any sort of wellbore tool adapted to selectively and at least
partially obstruct wellbore 1.
Workstring 3 then is run into wellbore 1 to a selected depth or
location therein. As illustrated in Figures 1 and 8, the selected depth or
location in wellbore 1 may be a point between sets of perforations 13, 15,
wherein it is advantageous to separate and isolate a first wellbore region or
zone proximal to one set of perforations 13 from a second region or zone
proximal to a second set of perforations 15. At the selected depth or
WO 95/09964 ~. . , ~ ~ 7 3 3 2 0 pCTlUS93/09399
24
location in wellbore 1, partition or obstruction member 5, 605 is set and
released from workstring 3 in a conventional manner.
For through-tubing operations, it is advantageous that
workstring 3 and partition or obstruction member 5, 605 have outer
diameters that are as small as possible to facilitate movement of workstring
3 and partition or obstruction member 5, 605 through reduced-diameter
production tubing or otherwise obstructed wellbore sections.
According to a preferred embodiment of the present invention,
inflatable packer 5, 605 is provided with an elongate screen filter assembly
7, 607, which is in fluid flow communication with a fluid exhaust assembly
9, 647 to provide fluid drainage. Preferably with such an inflatable packer,
a slurry of drainage or filter sand is (331 in Figure 6) deposited adjacent to
inflatable packer 5, 605 in a quantity sufficient to fully encase or enclose
screen filter member assembly 7, 607. Such a column of drainage sand
provides a pre-filter for the screen filter assembly 7, 607, preventing
abrasive
fines from entering inflatable packer 5, 605 and tending to cause premature
mechanical failure of inflatable packer 5, 605. A preferred drainage sand
column (331 in Figure 6) is formed of coarse, 20/40 mesh, silica sand that
is pumped into wellbore 11 in a fluid slurry with ordinary fresh water as the
slurry fluid.
After partition or obstruction member 5, 605 is set and
released, at least partially obstructing wellbore 1, aggregate mixture is
prepared at the surface into a fluid slurry. Preferably, the aggregate mixture
comprises 60% by weight coarse, 20/40 mesh, silica sand, 20% by weight
intermediate, 100 mesh, silica sand, 15% by weight fine, 200 mesh, silica
sand, and 5% by weight bentonite or bentonitic material. Preferably, fresh
water is used as the slurry fluid to hydrate and disperse bentonitic particles
WO 95109964 ,' - . ~ ,~. ~ ~ PCT/US93/09399
,~ 25 2 ~ 7332
into a colloidal form. The slurry should be sufficiently agitated to ensure
dispersion of the bentonitic material.
The aggregate mixture slurry then is pumped through
workstring 3 and into wellbore 1 adjacent and atop the drainage sand
column. After a sufficient volume of aggregate mixture fluids slurry (a
quantity sufficient to produce a column at least 12" in height) is pumped into
wellbore 1, pumping should cease. A period of time, preferably greater than
five to ten minutes, should elapse to permit the aggregate mixture fluid
slurry
to settle to a relatively quiescent condition.
After the settling period has elapsed, fracturing operations may
be commenced. In a typical fracturing operation, conventional fracturing
fluid (17 in Figure 1 and 317 in Figure 6) is pumped through workstring 3
into wellbore 1 at a volume flow rate sufficient to achieve the necessary
fluid
pressure for successful fracturing (typically approaching 10,000 psi). As
fluid pressure increases, the axial force exerted by fluid pressure on plug
member 11, 211, 311 increases. The increased axial force on plug member
11, 211, 311 compacts plug member 11, 211, 311 and causes drainage of
gross water from the aggregate mixture fluid slurry, through drainage sand
and drain filter assembly 7, 607, wherein the gross water is exhausted
through fluid exhaust assembly below inflatable packer 5, 605. Gross water
is fluid contained in the pores or interstitial spaces between sand grains in
the aggregate mixture. Gross water is to be distinguished from hydrated
water, which comprises small quantities of water that is hydrated or bonded
to bentonitic particles. It is extremely advantageous to drain gross water
from plug member 11, 211, 311, so that the aggregate mixture can be
compacted to a strong, substantially solid and substantially fluid-
impermeable plug member 11, 211, 311. Hydrated water is desirable
because it maintains bentonitic particles in the hydrated or swelled form,
WO 95/09964 ~ ~ ~ ~ PCT/US93/09399
' ' ~ 26
which tends to reduce the fluid permeability of plug member 11, 211, 311.
Thus, a preferred plug member 11, 211, 311 according to the
present invention will possess two regions of differing permeability: a solid
substantially fluid-impermeable, force transferring region; and a relatively
fluid-permeable drainage sand region. Screen filter 7, 607 of inflatable
packer 5, 605 permits drainage of gross water from plug member 11, 211,
311 yet prevents significant quantities of the aggregate mixture of plug
member 11, 211, 311 or drainage sand 331 from being carried away with
the gross water.
As fluid pressure is increased, plug member 11, 211, 311 is
compressed and compacted and becomes more substantially fluid-
impermeable and stronger. It is believed that plug member 11, 211, 311
according to the present invention employs a "slip-stick" deformation
mechanism, which improves the strength and substantial fluid impermeability
of plug member 11, 211, 311. It is believed that the combination of coarse,
intermediate, and fine sand particles, along with the ultra-fine, hydrated,
bentonitic particles, permits plug member 11, 211, 311 to deform
continuously as axial forces exerted thereon vary. This continuous
deformation, called the slip-stick mechanism, permits plug member 11, 211,
311 to compact into a strong and substantially fluid-impermeable plug that
continuously redistributes stresses within itself, thereby avoiding
disintegration and failure. During the fracturing operation, the slip-stick
mechanism of the aggregate material of plug member 11, 211, 311 permits
plug member 11, 211, 311 to seal against fluid pressure loss, and to
transfer axial loads, which otherwise would be exerted directly on inflatable
packer 5, 605, to wellbore 1, which can more easily bear such extreme
loads. Fluid drainage must be provided to permit the aggregate mixture to
compact tightly and to achieve the slip-stick deformation mechanism, which
WO 95109964
PCT/LTS93/09399
.:. 2, 217330
cannot be achieved if the content of gross water in the aggregate mixture
is excessive.
It should be noted that force transfer away from partition or
obstruction member 5, 605 is sufficiently substantial that partition member
' S, 605 may be unset or deflated, and plug member 11, 211, 311 will
maintain its strength and sealing integrity.
After fracturing operations are complete, plug member 11, 211,
311 may be disintegrated, dissolved, or washed out (substantially as
described with reference to Figure 8) by directing a high-pressure fluid
stream 19 from workstring 3. The disintegrated fluid member and fluid may
be circulated out of wellbore 1 or suctioned therefrom using a conventional
wellbore tool.
Thus, the present invention is operable in a plurality of modes
of operation, the modes of operation including: a delivery mode of
operation in which an aggregate mixture including particulate matter is
conveyed into a wellbore in a fluid slurry form to a position adjacent a
partition or obstruction member. Another mode of operation is a
compaction mode in which axial force from a source of axial force in the
wellbore is applied to the aggregate mixture to compact the aggregate
mixture and at least partially form a plug member. Yet another mode of
operation is a force-transfer mode in which the plug member transfers force
from the source of axial force away from the partition member into the
wellbore. Still another mode of operation is a wash-out mode of in which
the plug member is disintegrated by application of a stream of high-pressure
fluid. Still another mode of operation is a communication mode in which the
plug member is disintegrated and the partition member is removed from the
WO 95/0996 PCT/LTS93/09399
. ; ~~:.~ 28 213320
wellbore thereby allowing fluid communication between first and second
wellbore regions.
The present invention has a number of advantages. One
advantage of the present invention is the provision of a strong, substantially
fluid-impermeable means for sealing against fluid flow communication
between a first and second regions in a wellbore. Another advantage of the
present invention is that the force-transfer characteristics of the plug
member obviate the need for expensive high-pressure rated partition or
obstruction members, such as inflatable packers or bridge plugs.
Therefore, through-tubing operations and operations in otherwise obstructed
wellbores are facilitated and rendered less costly. Still another advantage
of the present invention is that the plug member is formed easily and is
disintegrated easily, permitting rapid and efficient workover or secondary
recovery operations.
While the invention has been shown in only one of its forms,
it is not thus limited, but is susceptible to various changes and
modifications
without departing from the scope thereof.
