U.S. patent application number 11/539409 was filed with the patent office on 2007-04-26 for mechanically modified filter cake.
This patent application is currently assigned to M-I LLC. Invention is credited to Michael A. Freeman.
Application Number | 20070089909 11/539409 |
Document ID | / |
Family ID | 37943141 |
Filed Date | 2007-04-26 |
United States Patent
Application |
20070089909 |
Kind Code |
A1 |
Freeman; Michael A. |
April 26, 2007 |
MECHANICALLY MODIFIED FILTER CAKE
Abstract
A down hole tool including a compression surface, a compression
surface axis, and at least one support member configured to attach
the compression surface to a well drilling tool assembly, wherein
the extendable support member is extendable by an extension force
provided to the support member. The down hole tool is rotatable
relative to an axis of the well drilling tool assembly, and as the
well drilling tool assembly rotates, the at least one compression
device exerts a lateral force along a sidewall of a wellbore. Also,
a method of forming filter cake comprising releasing a drilling
fluid and contacting the drilling fluid with a mechanical pressure
on the sidewall of the wellbore and the drilling fluid.
Inventors: |
Freeman; Michael A.;
(Kingwood, TX) |
Correspondence
Address: |
OSHA LIANG/MI
ONE HOUSTON CENTER
SUITE 2800
HOUSTON
TX
77010
US
|
Assignee: |
M-I LLC
Houston
TX
|
Family ID: |
37943141 |
Appl. No.: |
11/539409 |
Filed: |
October 6, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60724639 |
Oct 7, 2005 |
|
|
|
Current U.S.
Class: |
175/57 ;
175/325.1; 175/408 |
Current CPC
Class: |
E21B 12/00 20130101;
E21B 33/13 20130101 |
Class at
Publication: |
175/057 ;
175/325.1; 175/408 |
International
Class: |
E21B 7/00 20060101
E21B007/00; E21B 17/10 20060101 E21B017/10 |
Claims
1. A down hole tool comprising: at least one compression surface;
at least one extendable support member configured to attach the
compression surface to a well drilling tool assembly, wherein the
at least one extendable support member is extendable by an
extension force provided to the support member; and at least one
compression surface axis, wherein the at least one compression
surface is rotable around and relative to the at least one
compression surface axis; wherein the down hole tool is rotable
relative to an axis of the well drilling tool assembly; and wherein
as the well drilling tool assembly rotates, the at least one
compression surface exerts a lateral force along a sidewall of a
wellbore.
2. The down hole tool of claim 1, wherein the at least one
compression surface is substantially cylindrical.
3. The down hole tool of claim 1, wherein the at least one
compression surface is free to rotate
4. The down hole tool of claim 1, wherein the at least one
compression device is substantially spherical.
5. The down hole tool of claim 1, wherein the compression surface
is porous.
6. The down hole tool of claim 1, wherein the support member
automatically extends at a predefined pressure.
7. The down hole tool of claim 1, wherein the support member
comprises a spring.
8. The down hole tool of claim 1, wherein the extension force is
provided by a hydraulic force.
9. The down hole tool of claim 1, wherein the extension force is
provided by a mechanical force.
10. A method of forming filter cake comprising: releasing a
drilling fluid, wherein the drilling fluid comprises at least one
of a group consisting of compressible, deformable and encapsulated
particles, wherein the drilling fluid flows along a sidewall of the
wellbore; and contacting the drilling fluid with a compression
surface of a well drilling tool assembly along the sidewall of the
wellbore.
11. The method of claim 10, further comprising: embedding the
compressible and deformable particles mechanically into the
sidewall of the wellbore;
12. The method of claim 10, further comprising: breaking the
encapsulated particles under a mechanical pressure of the
compression surface; wherein upon the breaking, the encapsulated
particles release at least one first reactive component along the
sidewall of the wellbore.
13. The method of claim 10, wherein the group of compressible and
deformable particles comprises at least one of the group consisting
of thermally softened gilsonite, graphite, polymer beads, glass
ceramic spheres, starches, talc, gross cellulose, swollen, and
partially swollen super-absorbent polymer particles and lead.
14. The method of claim 10, wherein the compression surface is
substantially cylindrical.
15. The method of claim 10, wherein the compression surface is
substantially annular.
16. The method of claim 10, wherein the compression surface is
substantially spherical.
17. The method of claim 10, further comprising: extending an
extendable support member configured to attach the compression
surface to the well drilling tool assembly; wherein the extendable
support member extends the compression surface inside the wellbore;
and wherein extending the extendable support member applies a
lateral force between the compression surface and the sidewall of
the wellbore.
18. The method of claim 12, wherein the at least one first reactive
component released from the encapsulated materials combines with at
least one second reactive component to form a cement along the
sidewall of the wellbore.
19. The method of claim 12, wherein the at least one first reactive
component released from the encapsulated materials are painted on
the sidewall of the wellbore by the compression surface.
20. A well drilling tool assembly comprising: a drillstring; a
drill bit; and at least one compression surface; wherein the at
least one compression surface attaches to the drillstring between
the drill bit and a surface exit to a wellbore; wherein rotating
the drillstring rotates the at least one compression surface; and
wherein as the well drilling tool assembly rotates, the at least
one compression surface exerts a lateral force along a sidewall of
the wellbore.
21. The well drilling tool assembly of claim 20, further
comprising: an extendable support member configured to attach the
compression surface to the drillstring; wherein extending the
extendable support member provides a lateral force between the
compression surface and the sidewall of the wellbore.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application 60/724,639, filed Oct. 7, 2005, herein incorporated by
reference.
FIELD
[0002] Embodiments disclosed herein relate generally to a down hole
tool used to drill a borehole for the recovery of oil, gas, water,
or other minerals. More particularly, embodiments relate to methods
and apparatus for reducing the permeability of the sidewalls of a
wellbore.
BACKGROUND
[0003] The selection of materials for well construction is
essential to the successful completion of an oil or gas well. Among
the most important is the selection of a drilling fluid. A drilling
fluid having the desired properties is passed down through the
drill pipe, out a nozzle at the drill bit, and returned to the
surface through an annular portion of the well bore. The drilling
fluid primarily functions to remove cuttings from the bore hole;
lubricate, cool and clean the drill bit; reduce friction between
the drilling string and the sides of the bore hole; maintain
stability of the bore hole; prevent the inflow of fluids from
permeable rock formations; and provide information on down hole
conditions. The composition of a drilling fluid is carefully
selected to optimize production within the vast diversity of
geological formations and environmental conditions encountered in
oil and gas recovery. At the same time, the fluid should not
present a risk to personnel, drilling equipment, or the
environment.
[0004] In most rotary drilling procedures the drilling fluid takes
the form of a "mud," i.e., a liquid having solids suspended
therein. The solids function to impart desired rheological
properties to the drilling fluid and also to increase the density
thereof in order to provide a suitable hydrostatic pressure at the
bottom of the well. The drilling mud may be either a water-based
mud or an oil-based mud.
[0005] Water-based drilling muds may consist of polymers,
biopolymers, clays and organic colloids added to a water-based
fluid to obtain the required viscous and filtration properties.
Heavy minerals, such as barite or calcium carbonate, may be added
to increase density. Solids from the formation are incorporated
into the mud and often become dispersed in the mud as a consequence
of drilling. Further, drilling muds may contain one or more natural
and/or synthetic polymeric additives, including polymeric additives
that increase the rheological properties (e.g., plastic viscosity,
yield point value, gel strength) of the drilling mud, and polymeric
thinners and flocculents.
[0006] Polymeric additives included in the drilling fluid may act
as fluid loss control agents. Fluid loss control agents, such as
starch, prevent the loss of fluid to the surrounding formation by
reducing the permeability of filter cakes formed on the newly
exposed rock surface. In addition, polymeric additives are employed
to impart sufficient carrying capacity and thixotropy to the mud to
enable the mud to transport the cuttings up to the surface and to
prevent the cuttings from settling out of the mud when circulation
is interrupted.
[0007] Most of the polymeric additives employed in drilling mud are
resistant to biodegration, extending the utility of the additives
for the useful life of the mud. Specific examples of biodegradation
resistant polymeric additives employed include biopolymers, such as
xanthans (xanthan gum) and scleroglucan; various acrylic based
polymers, such as polyacrylamides and other acrylamide based
polymers; and cellulose derivatives, such as
dialkylcarboxymethylcellulose, hydroxyethylcellulose and the sodium
salt of carboxy-methylcellulose, chemically modified starches, guar
gum, phosphomannans, scleroglucans, glucans, and dextrane. See U.S.
Pat. No. 5,165,477, which is incorporated herein by reference.
[0008] Most drilling fluids are designed to form a thin,
low-permeability filter cake to seal permeable formations
penetrated by the bit. This is essential to prevent both the loss
of fluids to the formation and the influx of fluids that may be
present in the formation. Filter cakes often comprise bridging
particles, cuttings created by the drilling process, polymeric
additives, and precipitates. A key feature of a drilling fluid is
to retain these solid and semi-solid particles as a stable
suspension, free of significant settling over the time scale of
drilling operations.
[0009] The permeability of the filter cake is dependent upon
particle distribution, particle size, compressive forces, and
electrochemical conditions of the mud. The composition of the
drilling fluid may be adjusted to increase or decrease
permeability, for example, by adding soluble salts, increasing the
number of particles in the colloidal size range, and/or to vary
their surface charge. Fluid from the mud which permeates the
barrier is known as filtrate. The probability of successful
completion of a well may depend, in large part, upon the filtration
properties of the mud being matched to the geological formations
and the composition of the filtrate.
[0010] Filtration occurs as the suspended particles slurried in the
drilling fluid are trapped against the wellbore wall. So long as
the hydraulic pressure on the drilling fluid is greater than the
geomechanically derived pressure on the fluids within the
formation, the difference in pressure will drive drilling fluid to
flow into the formation. The solid particles in the slurry are
drawn along by the hydrodynamic drag produced by the fluid moving
into the formation. At the wellbore wall, if the particles are
large enough to bridge the openings in the formation, the particles
are stopped. The particles are then held by the drag of the fluid
(filtrate) flowing around them and into the formation openings.
[0011] Because the openings between the bridging particles are
generally smaller than the initial openings, finer particles are
now able to bridge, and thus be removed from the fluid stream. The
increasing buildup of solids correspondingly reduces the flow of
filtrate, so the hydrodynamic force that propels and traps
particles in the filter cake is continually reduced. Conversely,
hydraulic pressure on the drilling fluid, since it may no longer
force fluid to flow, is increasingly expressed as mechanical
pressure across the depth of the filter cake. This mechanical
pressure works to pack and compress the initially formed particle
bed into denser and less permeable arrangements. Generally
speaking, the greater the differential pressure, the higher the
ultimate mechanical pressure with concomitantly greater compression
of the layers of filter cake first laid down. Greater compression
results in tighter particle packing, higher mechanical strength,
and lower permeability.
[0012] This process may cause the drill string to become
`differentially stuck` in a wellbore. When sufficient filtration
flux is present to draw the impermeable pipe against the wall, its
blockage of flow is quickly translated into mechanical force,
holding it in place. Pipe stuck in this fashion should be quickly
freed, or the forces may become too great for the draw works at the
surface to pull it free. If not quickly freed, the forces may
exceed the tensile strength of the pipe so that it is impossible to
free it by pulling from the surface.
[0013] When the fluid is not being actively pumped though the well,
the process continues, trapping smaller and smaller particles,
until the fluid flux through the ever deeper bed becomes too slow
to move particles. Eventually, the permeability is reduced to a
point where even though some finite volume of filtrate may continue
to pass, its drag is insufficient to overcome the forces that
maintain the particles in suspension, resulting in succeeding
layers of particles building up very little mechanical compression.
Generally speaking, while more viscous than the initial fluid, this
layer of relatively widely separated particles is softer and more
permeable than the compressed filter cake below. At this point, the
`filter cake` is really a dewatered suspension, sometimes called
`dehydrated mud` in the case of water-based fluids.
[0014] When the fluid is actively pumped, the flow of fluid along
the axis of the wellbore is much faster than the radial flow of
fluid into the formation. The axial flow along the wellbore now
creates drag to pull particles up the wellbore and away from the
formation pore where filtration is occurring. As may be expected,
the filter cakes formed by a circulating fluid are more permeable
than those formed under static conditions. Such cakes are referred
to as `dynamic` cakes to differentiate them from those formed under
static conditions. It has been estimated that up to 80% of all the
filtrate lost to formation is lost through dynamic filtration with
circulating fluid.
[0015] Fluid flow up the wellbore is typically fastest around the
drill bit and the several stands of larger diameter, heavy-weight
drilling collars, pipes, down hole motors, jars, etc. immediately
above it. Such drill collars and heavyweight pipe are larger in
exterior diameter, while having the same interior diameter as the
pipe above, and they possess more mass and provide extra `weight,`
or pressure on the drill bit, to improve its rate of penetration.
Their increased stiffness may also serve to reduce excursion of the
drilled hole from the planned trajectory. Motors, turning the bit
independent of the pipe, are also often larger in diameter than the
body of pipe above.
[0016] Somewhat paradoxically, this region of fastest flow is also
the region that most needs filter cake. This is the area that has
most recently been exposed to the drilling fluid. The freshly
drilled rock has had the shortest time to build up any sort of
filter cake, and the higher fluid velocity more actively strips
away the growing particle bed than at any other point in the well,
Not surprisingly, it is during the time between drilling and the
formation of an equilibrium dynamic cake that most of the filtrate
is lost, with potentially damaging results. This is often the
region where pipe becomes differentially stuck.
[0017] Because much of modern drilling is done with sequential,
discrete pieces of pipe, circulation is periodically interrupted to
allow a new piece of pipe to be inserted into the closed
circulation path. These momentarily static conditions result in
rapid filter cake growth. Resumption of circulation strips much of
this newly formed cake away, but especially in the near-bit region,
some of the statically placed particles remain to improve the
dynamic cake.
[0018] There are a number of chemical ways of adjusting filter cake
properties are known in the art, including the use of clay and
non-clay based drilling fluids, use of weighting materials,
viscosifiers, dispersants, fluid loss control agents, insoluble
reinforcing materials, breaking fluids, and encapsulated delivery
particles.
[0019] Specifically, U.S. Pat. No. 4,506,734, incorporated herein
by reference, provides a method for reducing the viscosity and the
resulting residue of a water-based or oil-based fluid introduced
into subterranean formation by introducing a viscosity-reducing
chemical contained within hollow or porous, crushable and fragile
beads along with a fluid, such as a hydraulic fracturing fluid,
under pressure into the subterranean formation. When the fracturing
fluid passes or leaks off into the formation, or the fluid is
removed by back flowing, the resulting fractures in the
subterranean formation close and crush the beads. The crushing of
the beads then releases the viscosity-reducing chemical into the
fluid. This process is dependent upon the closure pressure of the
formation to obtain release of the breaker and is, thus, subject to
varying results dependent upon the formation and its closure
rate.
[0020] Further, U.S. Pat. No. 4,741,401, incorporated herein by
reference, discloses a method for breaking a fracturing fluid
comprised of injecting into the subterranean formation a capsule
comprising an enclosure member containing the breaker. The
enclosure member is sufficiently permeable to at least one fluid
existing in the subterranean environment or injected with the
capsule such that the enclosure member is capable of rupturing upon
sufficient exposure to the fluid, thereby releasing the breaker,
The patent teaches that the breaker is released from the capsule by
pressure generated within the enclosure member due solely to the
fluid penetrating into the capsule whereby the increased pressure
caused the capsule to rupture (i.e., destroys the integrity of the
enclosure member), thus releasing the breaker. This method for
release of the breaker would result in the release of substantially
the total amount of breaker contained in the capsule at one
particular point in time.
[0021] U.S. Pat. No. 4,919,209, incorporated herein by reference,
discloses a proposed method for breaking a fracturing fluid.
Specifically, the patent discloses a method for breaking a gelled
oil fracturing fluid for treating a subterranean formation which
comprises injecting into the formation a breaker capsule comprising
an enclosure member enveloping a breaker. The enclosure member is
sufficiently permeable to at least one fluid existing in the
formation or in the gelled oil fracturing fluid injected with the
breaker capsule, such that the enclosure member is capable of
dissolving or eroding off upon sufficient exposure to the fluid,
thereby releasing the breaker.
[0022] However, encapsulated delivery particles, and methods of
triggering payload delivery, as described in the prior art, have
limitations. For example, premature release of the enzyme payload
sometimes occurs due to product manufacturing defects,
imperfections, or coating damage experienced in pumping the
particles through surface equipment tubular and perforations.
Additionally, premature release of the enzyme payload may cause
damage to drilling components and the formation being drilled due
to the acidic and/or caustic properties of the encapsulated
payloads. As such, a localized application of a filter cake
adjusting particle and/or enzyme may be beneficial to the
successful completion of a well.
[0023] The probability of successful completion of a well, and the
cost of drilling a wellbore is proportional to the time it takes to
drill to a particular location and depth. In oil and gas drilling
the time it takes to remove the drillstring from the wellbore,
known in the field as "tripping," can greatly increase the cost of
drilling a well. When a low quality filer cake is formed, the time
it takes to trip the drillstring may increase due to problems such
as differential sticking. Differential sticking occurs when a
drillstring is held against the filter cake by hydrostatic pressure
in the wellbore, most commonly during the pulling of a drillstring
from the wellbore, or as a result of filter cake accumulation on a
drill bit.
[0024] Methods and apparatuses for promoting filter cake sealing
are known in the art. One example of such a method is disclosed in
SU 1361304 A1, therein describing a device deployed by centrifugal
action, and relying on such centrifugal action to apply a sealing
pressure to the filter cake. Alternate examples of methods and
apparatuses are disclosed in WO 2004/057151 A1, therein describing
providing a sliding mechanical contact to a filter cake. The
sliding mechanical contact provides a small angle of attack from
extendable subparts to provide a plastering effect to the filter
cake.
[0025] While the above mentioned methods and apparatuses may
provide mechanical contact with a filter cake, there still is a
need for methods and apparatuses for providing an optimized filter
cake that may decrease the costs associated with tripping the
drillstring, reducing downtime, and thereby increasing overall
drilling efficiency. Additionally, there exists a need for methods
and apparatuses that may provide for simultaneous application of
chemicals or energies that improve the sealing and strengthening
character of a filter cake, thereby further improving drilling
efficiency.
SUMMARY
[0026] In one aspect, embodiments disclosed herein relate to a down
hole tool that may be used in drilling wellbores. The down hole
tool includes at least one compression surface and at least one
compression surface axis, with at least one extendable support
member configured to attach the tool to a well drilling tool
assembly, the extendable support member extendable by an extension
force provided to the support member. The down hole tool may be
rotable relative to an axis of the well drilling tool assembly, and
the at least one compression surface may be rotable around and
relative to the at least one compression surface axis. As the well
drilling tool assembly rotates, the at least one compression device
may move along a sidewall of a wellbore, such that a lateral force
is applied between the at least one compression surface and the
sidewall of the wellbore.
[0027] In another aspect, embodiments relate to a method of forming
a filter cake that includes rotating a well drilling tool assembly
that includes a drill bit, a drillstring, and at least one
compression device in a wellbore, releasing a drilling fluid that
includes at least one of a group consisting of compressible,
deformable, and encapsulated particles, and providing mechanical
pressure on a sidewall of the wellbore.
[0028] In still another aspect, embodiments relate to a well
drilling tool assembly that includes a drillstring, a drill bit,
and at least one compression surface. The compression surface may
attach to the drillstring between the drill bit and a surface exit
to a wellbore, wherein rotating the drillstring may rotate the at
least one compression device, and rotating the at least one
compression surface against a sidewall of the wellbore causes
mechanical pressure between the at least one compression surface
and the sidewall of the wellbore.
[0029] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0030] FIG. 1 is a drawing of a typical well drilling hole assembly
inside a wellbore.
[0031] FIG. 2 is a close perspective drawing of one embodiment of a
compression device of the present disclosure.
[0032] FIG. 3 is a drawing of one embodiment of a compression
device of the present disclosure attached to a typical well
drilling hole assembly inside a wellbore.
[0033] FIG. 4 is a close perspective side drawing of one embodiment
of a compression device of the present disclosure attached to a
typical well drilling hole assembly inside a wellbore during
drilling.
[0034] FIG. 5 is a top view drawing of one embodiment of a
compression device of the present disclosure illustrated in FIG.
4.
[0035] FIG. 6 is a close perspective drawing of one embodiment of a
compression device of the present disclosure during drilling.
[0036] FIG. 7 is a top view drawing of an alternate embodiment of
the present disclosure utilizing a compression device comprising a
plurality of balls.
[0037] FIG. 8 is a side view drawing of the alternate embodiment of
the present disclosure illustrated in FIG. 7.
[0038] FIG. 9 is a top view drawing of an alternate embodiment of
the present disclosure utilizing an annular compression device.
[0039] FIG. 10 is a side view drawing of the alternate embodiment
of the present disclosure illustrated in FIG. 9.
DETAILED DESCRIPTION
[0040] Referring initially to FIG. 1, a typical well drilling hole
assembly 20 in a wellbore 24 is shown. Well drilling hole assembly
20 generally includes at least a drillstring 21 and a bottom hole
assembly 22. The bottom hole assembly 22 may include a drill bit 23
and various down hole tools (not shown separately) such as, for
example, reaming devices and/or compression devices, that may be
used while drilling the wellbore 24. Bottom hole assembly 22 may be
attached to drillstring 21 in a number of ways, such as by a
threadable connection 25. Drillstring 21 is rotated from the
surface around and relative to drillstring axis 26. Due to the
rotation of drillstring 21, bottom hole assembly 22 also rotates
relative to drillstring axis 26. The rotable motion of drillstring
21 may cause cutters 27 along with any down hole tools on bottom
hole assembly 22 to engage the formation.
[0041] Referring now to FIG. 2, a compression device 30 according
to one embodiment of the present disclosure is shown. Compression
device 30 is shown attached to bottom hole assembly 32. In this
embodiment, an extendable compression surface 33 is attached to
bottom hole assembly 32 by support member 34. Compression surface
33 rotates around and relative to compression axis 35. Support
members 34 extend outwardly from bottom hole assembly 32 toward the
sidewalls of a wellbore 36. Support members 34a, 34b, and 34c are
shown laterally expanded; however, one of ordinary skill in the art
will appreciate that any configuration, number or type of support
members are within the scope of the present disclosure, and as
such, this embodiment is not intended to be a limitation on the
scope of the present disclosure. One of ordinary skill in the art
will appreciate that compression surface 33 may by extendable by
support members 34a, 34b, and 34c, or any other type of support
member that is capable of extending compression surface 33 against
the sidewalls of a wellbore 36. Examples of support members 34 may
include, for example, hydraulically actuated support members,
pressurized support members, springs, and/or other means of
extending a device known to those of ordinary skill in the art.
[0042] Additionally, to supply adequate lateral force to compress
filter cake and/or break encapsulated particles, one of ordinary
skill in the art will appreciate that more than the mere pressure
supplied by centrifugal force caused by the rotation of compression
device 30 may be required. While centrifugal force may provide a
force strong enough to extend compression surface 30, a positively
applied extension force (e.g., a force generated by springs,
hydraulic pressure, or pneumatic pressure), may be required to
adequately force compression surface 30 against the sidewalls of
wellbore 36. The extendibility of compression surface 33 by support
members 34 may provide an increased lateral force capable of, for
example, breaking encapsulated particles and/or mechanically
compressing a filter cake. Compression surface 33 may be extended
by supplying an extension force to compression surface 33 or
compression device 30. In one embodiment, the extension force may
be hydraulic or mechanical force exerted from, for example, the
drill sting, to force compression surface 33 or compression device
30 radially outward. After the extension force extends compression
surface 33 or compression device 30 radially outward, support
members 34 may lock compression surface 33 or compression device 30
in an extended position. In such an embodiment, retracting
compression surface 33 or compression device 30 away from sidewalls
of the wellbore 36 may require removing the extension force and
bringing support members 34 toward drillstring 21.
[0043] In alternate embodiments not including lockable support
members 34, after expansion, the extension force may continue to
exert pressure on compression surface 33 or compression device 30
thereby substantially continuously applying a lateral force against
the sidewalls of wellbore 36. Compression surface 33 may then
retract out of an extended position when the extension force is
subsequently decreased or removed. Such an embodiment may be
beneficial when a substantial lateral force is desired to compress
filter cake and/or brake encapsulated particles, because the
extension force may substantially continuously provide a lateral
force between compression surface 33 and sidewalls of wellbore 36.
Such an embodiment may also result in more uniform pressure between
compression surface 33 and sidewalls of wellbore 36, even as
drillstring 21 moves inside the wellbore and the radius between
drillstring axis 26 and sidewalls of wellbore 36 varies. On of
ordinary skill in the art will appreciate that alternate methods of
providing the extension force may be known to those of ordinary
skill in the art, and as such, are within the scope of the present
disclosure.
[0044] Still referring to FIG. 2, as support member 34 is extended
outwardly from bottom hole assembly 32, pressure may be applied
between compression surface 33 and the sidewalls of a wellbore 36.
Contact between compression surface 33 and the sidewall may cause
compression surface 33 to rotate relative to compression axis 35 as
bottom hole assembly 32 is rotated. While compression surface 33
rotates, contact with the sidewall is maintained by the generally
curved outer compression surface 33. Compression surface 33
effectively moves along the sidewall of the wellbore as bottom hole
assembly 32 is rotated. As compression device 30 traverses the
inner circumference of the wellbore, compression surface 33
continues to rotate relative to compression axis 35, applying
pressure to the sidewalls of the wellbore 36. The amount of
pressure exerted by compression device 30 onto the sidewalls is
adjustable according to the amount of lateral force applied. The
lateral force may be provided by the actuation of, for example,
springs, hydraulic pressure, pneumatic pressure, or other methods
known to those skilled in the art. Such a lateral force may be
adjusted by the use of, among other things, springs and/or
hydraulic pressure. For example, in one embodiment, a lateral force
may be varied by setting the tension of attachment mechanism 34 to
a specific level.
[0045] Lateral force applied to the sidewall of wellbore 36
compresses the uneven inner circumference of the wellbore, reduces
imperfections, and reduces the quantity of drill "cuttings" (i.e.,
pieces of formation) present in the drilling mud. The mechanical
pressure the lateral force generates may compress the filter cake
as it forms along the inner circumference of the wellbore, thereby
reducing the permeability of the filter cake. Further, as
encapsulated particles, or other particulate matter suspended in
the drilling mud pass between compression surface 33 and the
sidewalls of wellbore 36, the mechanical pressure generated by the
lateral force may break the encapsulated particles or otherwise
press the suspended particulate matter into the sidewall of
wellbore 36. The breaking of encapsulated particles and/or
compression of suspended particulate matter may therefore result in
a less permeable filter cake.
[0046] Referring now to FIG. 3, a compression device 40 attached to
bottom hole assembly 42, is shown. This illustration shows a
potential attachment point of compression device 40 to bottom hole
assembly 42. As compression device 40 rotates around and relative
to drillstring axis 46, the compression surface 43 may rotate
around and relative to compression axis 45. While the drillstring
axis 46 and compression axis 45 are shown as separate axes, it is
contemplated that the drillstring axis 46 and the compression axis
45 may be substantially the same.
[0047] Still referring to FIG. 3, the placement of compression
device 40 on the well drilling hole assembly may be important in
creating an effective filter cake. To create an effective filter
cake, the sidewalls of the wellbore are preferably sealed as
quickly after drilling as possible. In one embodiment, compression
device 40 may be attached to bottom hole assembly 42. In another
embodiment, however, while drilling specific formations, it may be
advantageous to attach compression device 40 to another point on
the well drilling hole assembly, including along drillstring 41 or
any other point where attachment is possible.
[0048] Now referring to FIGS. 4 and 5 together, a bottom hole
assembly 52 with compression device 40 attached, during drilling,
is shown. While drilling a well, drilling fluid 58 may be pumped
down the drillstring through bottom hole assembly 52 exiting
through jet 59 located on the drill bit. Drilling fluid 58 passes
over the bottom of the wellbore, through the annular passageway to
return to the surface. The annular passageway is defined as the
region between the well drilling assembly and the sidewalls of
wellbore 56. As drilling fluid 58 passes along the bottom 54 and
sidewalls of wellbore 56, it may carry away drill cuttings, rock
fragments, and other particulate matter that accrues as a result of
drilling. Both during and after drilling, the sidewalls of wellbore
56 may be permeable to water and other compounds in the drilling
fluid. As particulate matter passes with drilling fluid 58 over the
sidewalls of wellbore 56, some of the particulate matter may
collect along crevasses in the sidewalls of wellbore 56.
Additionally, as drilling fluid 58 passes along the sidewalls of
wellbore 56, unstable substrate may be carried away with drilling
fluid 58. The interaction of drilling fluid 58 with particulate
matter and the sidewalls of wellbore 56 causes a layer of filter
cake 57 to form along the sides of wellbore 56.
[0049] In one embodiment, compression device 40 rolls over the
sidewalls of wellbore 56 causing mechanical pressure in direction
E. The mechanical pressure against the sidewalls of wellbore 56 may
thereby compress filter cake 57. After the compression of filter
cake 57 by compression device 50, compressed filter cake 59 may be
less permeable to drilling fluid 58.
[0050] Referring now to FIG. 6, the rotation of a compression
device 60 during drilling, is shown. Drilling fluid 68 utilized in
well drilling may include a combination of water-based and/or
oil-based solution with suspended particles designed to create a
specific environment determined by the requirements of the
formation being drilled. Examples of suspended particles include
compressible and deformable particles used in drilling, such as
gilsonite, graphite, polymer, ceramics, starches, talc, gross
cellulose, super-absorbent polymer, and lead. Additionally, classes
of formation specific agents that may be suspended include
particles such as weighting materials, viscosifiers, dispersants,
fluid loss control agents, and insoluble reinforcing materials.
[0051] Still referring to FIG. 6, in one embodiment, compression
device 60 rotates around and relative to compression axis 65 in
direction F, As drilling fluid 68 flows along the sidewalls of
wellbore 66, suspended particles in drilling fluid 68 become
trapped in the crevasses of the sidewalls of wellbore 66. To
prevent the flow of drilling fluid 68 into the sidewalls of
wellbore 66, compression device 60 applies mechanical pressure
along the sidewalls of wellbore 66. The mechanical pressure applied
to the compressible and deformable particles trapped in the
crevasses of the sidewalls of wellbore 66 may deform to match the
contours of the crevasses. The effect of deforming the particles
may be to substantially seal the sidewalls of wellbore 66, thereby
forming a less permeable filter cake 69.
[0052] Drilling fluid 68 may also contain solutions including
breaker fluids, epoxy mixtures, acid/cationic, silicate
precipitants, nylon, polymerization activators, and any other
solution known in the art of well drilling. These solutions may be
mixed directly into drilling fluid 68 or otherwise suspended
therein. Solutions mixed directly into drilling fluid 68 may
contact the drillstring, the drill bit, and other drilling
apparatus prior to contact with the sidewalls of wellbore 66.
Because solutions may be caustic, acid, or otherwise damaging to
drilling equipment, or formation, it may be advantageous to control
the release of these solutions into the drilling fluid. One way of
controlling the release of solution into the drilling fluid is by
suspending encapsulated particles containing the solutions or
solution components in drilling fluid 68. The solution may then be
released when certain conditions are satisfied. Examples of
conditions that may trigger release of an encapsulated solution
include specific pressures, temperatures, and chemical activators
used to dissolve the encapsulation material. Additional groups of
solution and solution components include hydraulic cement slurries,
formation fracturing fluids, formation acidizing fluids, and other
solutions or solution components known to one skilled in the art of
well drilling.
[0053] In one embodiment, encapsulated particles containing two
reactants which may react to produce cement, are suspended in
drilling fluid 68, and then released into wellbore 66. The
encapsulated particles become trapped between compression device 60
and the sidewalls of wellbore 66. The mechanical pressure applied
to the encapsulated particles breaks the encapsulation, thereby
releasing the solution into the drilling fluid and onto the
sidewalls of wellbore 66. As the solution moves over the sidewalls
of wellbore 66, the sidewalls may become sealed, and a less
permeable filter cake 69 may be formed.
[0054] In yet another embodiment, encapsulated particles suspended
in drilling fluid 68 are released into wellbore 66. A first
reactive compound may be contained in the encapsulated particles,
and a second reactive compound may be released directly into the
drilling fluid. As compression device 60 breaks the encapsulated
particles, as described above, the first reactive compound may be
released into the drilling fluid where it reacts with the second
reactive compound to produce a sidewall sealing compound. The
compound may then be absorbed by the sidewalls of wellbore 66, or
effectively painted onto the sidewalls of wellbore 66 by the
continued rolling action of compression device 60.
[0055] Now referring to FIG. 7, an embodiment of compression device
70 is shown. In this embodiment, compression device 70 includes a
plurality of balls 71 spaced substantially evenly around the
sidewalls of wellbore 76. In this illustration, plurality of balls
71 are spaced at 120 degree increments; however, one of ordinary
skill in the art will appreciate that other spacing angles may be
advantageous based on the requirement of specific formations. The
plurality of balls 71 are attached to drillstring 72, and are thus
rotable around drillstring axis 74. Additionally, the plurality of
balls 71 is rotable around independent compression axis 73 of each
of the plurality of balls 71. As such, each of the plurality of
balls 71 are rotable independent of the rotation speed of either
drillstring 72, or another independent compression surfaces.
Referring briefly to FIG. 8, the plurality of balls 71 may be
spaced vertically along drillstring 72. However, other embodiments
of the present invention may be foreseen, such as where each one of
the plurality of balls are in the same plane perpendicular to
drillstring 72.
[0056] During drilling, the plurality of balls 71 may rotate
separately around and relative to independent compression axis 73
and/or drillstring 72. As such, the use of plurality of balls 71
may provide additional coverage area along the sidewalls of
wellbore 76. The additional coverage area may result in greater
lateral force, a more widespread application of mechanical
pressure, and therefore a less permeable filter cake.
[0057] Now referring to FIGS. 9 and 10 together, an alternate
embodiment of compression device 80 is shown. In this embodiment,
compression device 80 includes an annular shaped ring 81 attached
to drillstring 82 by a plurality of attachment mechanisms 83. As
drillstring 82 rotates around drillstring axis 86, compression
device 80 rotates around and relative to drillstring axis 86. Thus,
in this embodiment, drillstring axis 86 is substantially the same
as the compression device axis 86. Compression device 80 may be
extended such that mechanical pressure is applied to the sidewalls
of wellbore 88. The mechanical pressure of compression device 80
may compress the sidewalls of wellbore 88 and compress filter cake
(as described above) such that a less permeable 89 sidewall of
wellbore 88 is formed.
[0058] To achieve more effective drilling conditions, the sidewalls
of the wellbore being drilled may be sealed to reduce the fluid
amount escaping from the wellbore into the formation. In accordance
with one embodiment, a well drilling tool assembly rotates a
compression device along the sidewalls of a wellbore. Rotating the
compression device may apply mechanical pressure to the sidewalls
of the wellbore, compressing the sidewalls, thereby making the
sidewalls less permeable. In another embodiment, drilling fluid may
be released into the wellbore, where the drilling fluid may contain
one of a group of compressible, deformable, and encapsulated
particles. The mechanical pressure exerted on the sidewall of the
wellbore by the compression device may therein interact with the
drilling fluid containing the compressible, deformable, and/or
encapsulated particles, to create a less permeable wellbore
sidewall.
[0059] Advantageously, embodiments disclosed herein may provide for
one or more of the following. A compression device of the present
disclosure may result in a less permeable filter cake created by
exertion of a mechanical pressure, which may result in a drilling
environment less prone to differential sticking. Due to a less
permeable filter cake, should the drillstring contact the sidewalls
of the wellbore, zones of high and low pressure may be less likely
to occur, thereby reducing the chance of differential sticking.
Because differential sticking may result in increased "tripping"
time, as well as increased well drilling costs, the less permeable
filter cake formed by the present disclosure may result in a more
efficient drilling process.
[0060] Compression devices, in accordance with embodiments
disclosed herein, may also provide the advantage of applying a
mechanical pressure to either dynamic or statically growing filter
cake. In one instance, a compression device may be passed over the
growing filter cake after a period of static filtration and before
the resumption of circulation. The mechanical pressure may be
particularly beneficial in the near bit region to more tightly pack
the weakest and most loosely held, last-deposited layers, of filter
cake. Compressing the weakest layers may provide a less permeable
filter cake, decreasing the propensity for differential sticking,
thereby increasing drilling efficiency.
[0061] Further, a compression device, in accordance with an
embodiment of the present disclosure, may impart physical
properties to the filter cake, for example, heat, loss of heat,
radiation, chemical reaction surface, and/or three-dimensional
arrangement. Heat, loss of heat, and chemical catalysis may serve
to modify the chemical and mechanical properties of the compressed
material. The imposition of a discrete, three-dimensional
arrangement of the surface may modify its hydrodynamic character.
Control over the physical properties of filter cake creation,
during drilling, may provide the advantage of a filter cake that is
less permeable. Additionally, a compression surface may be porous,
or otherwise able to pass or transfer fluids or solids that may
chemically or physically alter the material being compressed. Such
a compression surface may offer the advantage of allowing the
continual passage of radical initiators to promote polymerization
of filter cake and/or filtrate components.
[0062] The mechanical pressure exerted by the compression device of
the present disclosure may be used with drilling fluid containing
compressible, deformable, and/or encapsulated particles. These
drilling fluid combinations may be used for filter cake creation,
along with other uses known to those skilled in the art. Because
the prior art delivery of these drilling solution components may be
damaging to well drilling components, a more local application, as
may be provided by the present disclosure, may provide additional
advantages to efficient well drilling. Finally, to create an
effective filter cake, the sidewalls of the wellbore are preferably
sealed as quickly after drilling as possible. Embodiments of the
present disclosure may allow quicker scaling of the sidewalls of
the wellbore due, at least in part, to a local application of
mechanical pressure. Sealing speed may also be increased by
including the breaking of encapsulated particles and/or compression
of suspended particulate matter.
[0063] While the present disclosure has been described with respect
to a limited number of embodiments, those skilled in the art,
having benefit of this disclosure, will appreciate that other
embodiments may be devised that do not depart form the scope of the
disclosure as disclosed herein. Accordingly, the scope of the
present disclosure should be limited only by the attached
claims.
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