U.S. patent application number 15/947030 was filed with the patent office on 2019-10-10 for positioning contact surface with a radial extension that decreases for a directional drilling assembly.
The applicant listed for this patent is Extreme Rock Destruction, LLC. Invention is credited to William W. King, David Miess, Gregory Prevost, Michael Reese, Edward Spatz.
Application Number | 20190309575 15/947030 |
Document ID | / |
Family ID | 68096367 |
Filed Date | 2019-10-10 |
United States Patent
Application |
20190309575 |
Kind Code |
A1 |
Spatz; Edward ; et
al. |
October 10, 2019 |
POSITIONING CONTACT SURFACE WITH A RADIAL EXTENSION THAT DECREASES
FOR A DIRECTIONAL DRILLING ASSEMBLY
Abstract
A downhole assembly for a directional drilling apparatus is
provided. The downhole assembly includes at least one positioning
element. The positioning element has a first radial extension when
the downhole assembly is drilling a wellbore. When the downhole
assembly inclination is greater than a predetermined amount, such
as when the downhole assembly is horizontal, the positioning
element has a second radial extension that is less than the first
radial extension.
Inventors: |
Spatz; Edward; (Houston,
TX) ; Reese; Michael; (Houston, TX) ; Miess;
David; (Houston, TX) ; Prevost; Gregory;
(Houston, TX) ; King; William W.; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Extreme Rock Destruction, LLC |
Houston |
TX |
US |
|
|
Family ID: |
68096367 |
Appl. No.: |
15/947030 |
Filed: |
April 6, 2018 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 7/067 20130101;
E21B 17/1078 20130101; E21B 7/046 20130101; E21B 7/06 20130101 |
International
Class: |
E21B 7/06 20060101
E21B007/06; E21B 17/10 20060101 E21B017/10 |
Claims
1. A downhole apparatus comprising: a housing configured and sized
to fit within a wellbore, the housing including a drilling assembly
at a bottom portion of the housing and having at least a first bend
located above the drilling assembly; at least one positioning
element coupled to the housing, the at least one positioning
element comprising: a blade wherein the blade comprises: at least a
radially inner portion and at least a removable radially outer
portion coupled to the radially inner portion; and wherein the
blade has a first radial extension that includes the radially inner
portion and the removable radially outer portion, wherein the blade
has a second radial extension that includes the radially inner
portion when the removable radially outer portion is removed such
that the second radial extension is less than the first radial
extension.
2. The downhole apparatus of claim 1 wherein the at least one
positioning element is coupled to the housing such that the first
bend is located between the at least one positioning element and
the drilling assembly.
3. The downhole apparatus of claim 1 wherein the blade is a metal
and the removable radially outer portion is a wearable
material.
4. The downhole apparatus of claim 3 wherein the wearable material
comprises a material that is softer than a material comprising the
radially inner portion.
5. The downhole apparatus of claim 4 wherein the wearable material
selected from the group of material consisting of: a metal softer
than the material of the first portion, a phenolic material softer
than the material of the first portion, or a combination
thereof.
6. The downhole apparatus of claim 1 wherein the removable radially
outer portion comprises interstitial hard material.
7. The downhole apparatus of claim 1 wherein the removable radially
outer portion is a dissolvable material.
8. The downhole apparatus of claim 7 wherein the dissolvable
material is configured to dissolve based on a composition of a
drilling fluid.
9. The downhole apparatus of claim 8 wherein the dissolvable
material is a polymer material that dissolves in the presence of
saltwater.
10. A downhole apparatus comprising: a housing configured and sized
to fit within a wellbore, the housing including a drilling assembly
at a bottom portion of the housing and having at least a first bend
located above the drilling assembly; at least one positioning
element coupled to the housing, the at least one positioning
element comprising: a blade wherein the blade comprises: at least a
removable radially inner portion and at least a radially outer
portion coupled to the removable radially inner portion; and
wherein the blade has a first radial extension that includes the
removable radially inner portion and the radially outer portion,
wherein the blade has a second radial extension that includes the
radially outer portion when the removable radially inner portion is
removed such that the second radial extension is less than the
first radial extension.
11. The downhole apparatus of claim 10 wherein the removable
radially inner portion supports the radially outer portion until it
is removed.
12. The downhole apparatus of claim 10 wherein the removable
radially inner portion comprises a dissolvable material.
13. The downhole apparatus of claim 12 wherein the dissolvable
material is a polymer.
14. The downhole apparatus of claim 13 wherein the polymer is
configured to dissolve when salt is present in a drilling
fluid.
15. The downhole apparatus of claim 10 wherein the radially outer
portion comprises a hard metal.
16. The downhole apparatus of claim 10 wherein the radially inner
removable portion comprises a piston operably coupled to a piston
driver wherein the piston has an extended position and a retracted
position such that the radially inner removable portion is removed
when the piston is in the retracted position.
17. The downhole apparatus of claim 12 wherein the radially inner
portion comprises a bladder and the dissolvable material comprises
a seal for the bladder such that the bladder is filled with a fluid
when the dissolvable material is not dissolved and the bladder is
empty when the dissolvable material is dissolved.
18. A downhole apparatus comprising: a housing configured and sized
to fit within a wellbore, the housing including a drilling assembly
at a bottom portion of the housing and having at least a first bend
located above the drilling assembly; at least one positioning
element coupled to the housing, the at least one positioning
element comprising: a movable first portion; and a piston coupled
to the first portion wherein the piston has an extended position
and a retracted position, wherein the movable first portion has a
first radial extension when the piston is in the extended position
and the movable first portion has a second radial extension less
than the first radial extension when the piston is in the retracted
position.
19. The downhole apparatus of claim 18 comprising a sensor to sense
an inclination of the housing such that when the sensor detects
that the inclination of the housing is greater than a predetermined
orientation, the piston is moved from the extended position to the
retracted position.
Description
CROSS-REFERENCE TO RELATED APPLICATION(S)
[0001] The present application is cross-referenced to U.S. patent
application Ser. No. 15/667,704 Method, Apparatus By Method, And
Apparatus Of Guidance Positioning Members For Directional Drilling,
filed Aug. 3, 2017 the disclosure of which is incorporated herein
as if set out in full. The present application is cross-referenced
with U.S. patent application Ser. No. 15/808,798 Bottom Hole
Assemblies For Directional Drilling, filed Nov. 9, 2017, the
disclosure of which is incorporated as if set out in full.
TECHNICAL FIELD
[0002] The technology of the present application relates to
improved bottom hole assemblies (BHAs) and stabilizers for
directional drilling.
BACKGROUND
[0003] As has been disclosed and described in prior applications
made by the applicant of the current technology the contact points
of directional drilling assemblies with the borehole wall define
and in large part control the directional behavior, and build and
turn capabilities of a given assembly.
[0004] A key aspect of directional drilling which is well known to
those skilled in the art is the difficulty of making the initial
kick off into a build curve. A build curve can take many
configurations but as a general proposition it is meant to turn the
wellbore from vertical to horizontal. A typical architecture for a
horizontal well will include a build length of about 900 feet and a
buildup rate (BUR) of 10 degrees per 100 drilled feet. In some
instances as a curve is built and gains angle towards horizontal
the sensitivity, or ability of a given assembly to build angle
increases. One explanation for this phenomenon is that prior to
about 45 degrees of build the contact points obtain less "bite"
into the borehole wall to provide build leverage to the system.
Increasingly as the build goes beyond 45 degrees a given assembly
becomes more aggressive in building angle. It can be considered to
be more sensitive and reactive in slide mode drilling.
[0005] This increased sensitivity becomes of significant concern if
the same assembly is pressed forward into the lateral section. The
oversensitivity of the system in response to slide correction runs
can create extensive tortuosity resulting in increased torque,
drag, and ultimately a reduction in ultimate lateral wellbore
length. Frequently this problem is addressed by switching out
assemblies after the curve has been built, costing the operator an
additional trip, in many cases solely to replace the build assembly
with a less aggressive assembly for the lateral. In many instances
the outer diameters of the stabilizers used in the replacement
assembly are reduced, by between an 1/8 inch in diameter and 1 inch
in diameter (depending on nominal hole diameter). This is done to
reduce the torque and drag experienced in the lateral section, but
provides a sub-optimum stabilization in the lateral section.
[0006] What is needed is a directional bottomhole assembly which is
capable of aggressively building angle in the upper curve and then
modifies to a less aggressive assembly in the lower curve or
lateral section of the wellbore.
BRIEF SUMMARY
[0007] As has been laid out in the cross-referenced applications,
the current applicants have identified the significant impact the
radial extension of a scribe side above bend positioning element
has on the ultimate build characteristics of a directional BHA. To
a lesser extent, but also significant in their influence on build
are the radial extensions of a bend side near bit positioning
element and/or a bend side kick pad if either or both are
employed.
[0008] Prior art has given paramount importance to the bend angle
as the overwhelmingly determinant attribute of a directional
assembly's build capabilities in slide mode. Extensive geometric
modeling performed by the applicants and verified by field test
have demonstrated that reduced radial extensions of a scribe side
above bend element and (if any) bend side positioning or kick pad
elements act to reduce the build rate (sensitivity) in slide mode,
even with an aggressive bend angle.
[0009] The technologies of the present application teach methods of
obtaining the goal of effectively making the curve and the lateral
with the same assembly in a single run by reducing the radial
extension of the contacting elements over the course of the curve,
or at the inception or first several hundred feet of the lateral
section.
[0010] The contacting elements of the current technology are
abradeable/erodible, dissolvable, or mechanically depressible to
provide outer radial extensions that are reduced over the course of
the build or at the commencement of the lateral section.
[0011] One version of abradeable/erodible contact surfaces are
manufactured entirely or substantially from brass, tin, low
hardness steel or other relatively soft metal or metal alloy. The
soft metal material is mounted on the parent BHA positioning
elements through known manufacturing processes such as casting,
brazing, mechanical attachment, or adhesives. The soft metal
material is sound enough early in the run to provide the leverage
required for aggressive build rates but by wearing down over the
course of the curve section or into the lateral section reduces the
radial extension of the contact surfaces to yield a less
aggressive, less sensitive directional assembly. Typically an
intervening hard material, such as hard facing or embedded tungsten
carbide inserts is deployed under the soft material on the steel of
the parent BHA positioning body. This intervening hard material
effectively limits the continuation of wear after the softer outer
material has worn away. In the case of drilling through formations
that are harder and more abrasive the soft metal sheathing of the
contact surfaces can be formed with inclusions of harder material
to reduce the rate of wear and abrasion. Candidate hard material
inclusions may be but are not limited to: steel, tungsten carbide,
natural diamond, synthetic diamond, or any other materials or
combinations of materials known in the art.
[0012] Phenolic materials are an alternative material for
abradeable/erodible contact surfaces. As with soft metal sheathing
materials phenolic may be formed with known manufacturing
techniques and mounted to the parent BHA positioning elements
mechanically, or by adhesives as are known in the art. Harder
material inclusions may be deployed in the phenolic to resist
accelerated wear in more abrasive drilling applications. As with
the soft metal noted above an intervening hard material such as
hard facing or tungsten carbide inserts typically underlays the
phenolic to limit continued wear after the phenolic has worn
away.
[0013] Dissolvable materials are also known in the art. Reference
is made to U.S. Pat. No. 9,856,411 as an example of the downhole
use of dissolvable materials. The subject patent discusses
specifically a degradable thermoset polymer material for use in
frac plug applications. This or a similar material may be used for
the sheathing material of the contact elements of the BHA. When
used in this way the thermoset materials are attacked with fluid
that reacts with the thermoset and dissolves the thermoset
material. By way of a non-limiting example, a slug of high salt
content fluid in the drilling fluid column to dissolve the
sheathing and thereby reduce the radial extension of the contact
surfaces. While a thermoset material that is dissolves in a high
salt content fluid is described, other composites and fluid
additives are possible. Of note is the fact that different
formulations of dissolvable material will dissolve at different
rates or in response to variations in fluid make up. In practicing
the technology of this application dissolvable formulations are
chosen which will survive substantially intact in the early part of
the drilling. Another optional applicable feature of dissolvable
material formulations of the present application is the use of a
more slowly dissolvable shell as an outer surface of the
dissolvable with a more quickly dissolving formulation at the core
of the dissolvable component. This approach may better resist
dissolving for a substantial or all of the curve section of the
well, and then quickly dissolve and evacuate later in the run.
[0014] As with soft metal or phenolic materials if the formations
to be drilled are abrasive and will wear the polymer material too
quickly then the polymer may be reinforced with inclusions of
harder material as listed earlier. Also, as with soft metals, an
underlying hard material layer limits ongoing wear after the outer
dissolvable layer has dissolved away.
[0015] Dissolvable materials may also be used as an intervening
material between the parent BHA positioning element base and an
outer hard material facing. Once the curve has been made or nearly
made and the drilling is ready to enter or has entered the lateral
section a slug of high salt content drilling fluid is pumped down
to dissolve the intervening thermoset polymer material. The outer
metal sheath can then be depressed along slide, guide, or hinged
surfaces as known in the art to effectively reduce the radial
extension of the contact surfaces.
[0016] Another alternative is to have the outer contact surfaces
set with caged rotating balls in contact with the formation. The
balls are under laid by wearable or dissolvable material. Over the
course of the run the underlying support for the ball wears down
reducing the radial extension of the ball. If a dissolvable
material is used as before a slug of high salt fluid may be used to
dissolve the underlying support to reduce the radial extension of
the contact surfaces when the wellbore has reached the end of the
curve or the beginning of the lateral section.
[0017] In the embodiments where a harder surface or ball are under
laid by a dissolvable or wear element the tool may be designed to
allow for the replacement of the underlying wear element or
dissolvable to prepare the tool for use in another well.
[0018] In another embodiment, for use in well operations employing
either water based or oil based drilling fluids, an outer wear
resistant facing is deployed on a tensioned strip of fluid, such as
water or oil, swellable elastomer. The strip is anchored end to end
or side to side above a depression gap in the tool body. The
tensioning of the elastomer maintains the outer hard surface at the
designed diameter early in the run. As the elastomer swells during
the course of the run, or when activated by an appropriate fluid
additive, it elongates, relaxing the tension and reducing the
diameter of the deployed hard surface. An additional feature of
this embodiment includes dissolvable supporting structures between
the tool body and the tensioned rubber strip. These structures
supply additional support to the tensioned strip early in the run
and dissolve over the course of the run allowing the swollen strip
to depress, decreasing the outer diameter of the contact
surface.
[0019] In an alternative embodiment a hard outer surface is
supported in its desired initial position by a ball in an angled
channel below the hard surface. The ball is held in place by a
dissolvable material. Once the retaining dissolvable material
dissolves away the ball is free to move along the channel in a
reduced radial deployment allowing the outer hard surface to
depress. In the case of the above bend positioning element the
movement of the ball to a reduced radial deployment is assisted by
gravity in slide mode when the tool is in the lower curve or
lateral sections of the wellbore.
[0020] In an alternative embodiment a hard outer surface is
supported by a bladder containing an incompressible fluid. An
orifice in the bladder is sealed with a dissolvable material. Over
the course of the tool run the drilling fluid attacks the
dissolvable seal, eventually breaking the seal and allowing the
contained incompressible fluid to evacuate the bladder, allowing
for the depression of the hard outer surface.
[0021] In an alternative embodiment a hard outer surface is
supported in its desired initial position by a piston in a piston
housing below the hard surface. The piston is connected to and
actuated by a sensor and battery assembly. The sensor may be an
inclinometer or a revolution counter. In the case of the
inclinometer, once the BHA achieves (or exceeds) a predefined
inclination, such as, for example, a 90 degree inclination in some
embodiments or a 45 degree inclination in other embodiments, a
signal from the sensor and battery pack causes the retraction of
the piston allowing the outer hard surface to retract. In the case
of the revolution counter once the counter has sensed a
predetermined number of revolutions of the motor the sensor and
battery pack causes the retraction of the piston. In both cases the
sensor pack may be armed at surface such as by a key or a magnetic
arming device when the tool is being run into the hole.
BRIEF DESCRIPTION OF THE DRAWINGS
[0022] FIG. 1 shows a cross section view of an above bend
positioning/stabilizer element with a soft metal wearable outer pad
mounted on a blade.
[0023] FIG. 2 shows a cross section view of an above bend
positioning/stabilizer element with harder material inclusions in a
soft metal wearable outer pad mounted on a blade.
[0024] FIG. 3 shows a cross section view of an above bend
positioning/stabilizer element with a dissolvable outer pad mounted
on a blade.
[0025] FIG. 4a shows a cross section view of an above bend
positioning/stabilizer element with an outer hard material element
underlain by dissolvable material.
[0026] FIG. 4b shows a cross section view of an above bend
positioning/stabilizer element with an outer hard material element
depressed into a lower position.
[0027] FIG. 5a shows a cross section view of an above bend
positioning/stabilizer element with a caged hard metal ball
underlain by a wearable or dissolvable material.
[0028] FIG. 5b shows a cross section view of an above bend
positioning/stabilizer element with a caged hard metal ball
depressed into a lower position.
[0029] FIG. 6a shows a cross section view of an above bend
positioning/stabilizer element with a swellable rubber tensioner
supporting a hard outer surfacing material.
[0030] FIG. 6b shows a cross section view of an above bend
positioning/stabilizer element with a now swollen and depressed
rubber tensioner supporting a hard outer surfacing material.
[0031] FIG. 7a shows a cross section view of an above bend
positioning/stabilizer element with a hinged hard metal surface
underlain by a channeled hard metal ball held in place by a
dissolvable insert.
[0032] FIG. 7b shows a cross section view of an above bend
positioning/stabilizer element with a hinged hard metal surface now
depressed following the dissolving of the insert and the movement
of the hard metal ball down the channel.
[0033] FIG. 8a shows a cross section view of an above bend
positioning/stabilizer element with a hard metal surface underlain
by a fluid filled bladder sealed with a dissolvable stopper.
[0034] FIG. 8b shows a cross section view of an above bend
positioning/stabilizer element with a hard metal surface underlain
by a bladder now unsealed and depressed.
[0035] FIG. 9a shows a cross section view of an above bend
positioning/stabilizer element with a hinged hard metal surface
underlain by a deployed piston rod held in place by a piston
housing connected to a sensor and battery pack.
[0036] FIG. 9b shows a cross section view of an above bend
positioning/stabilizer element with a hinged hard metal surface now
depressed by the retraction of the piston rod in response to a
signal from the sensor and battery pack.
DETAILED DESCRIPTION
[0037] FIG. 1 shows a cross section view of an above bend
positioning/stabilizer element 100 (generically positioning element
100) with a soft metal wearable outer pad 103 mounted on a blade
102 and underlain by a hard material surface 106. The parent
housing body, which may be the housing of a down hole assembly or
bottom hole assembly (BHA) is shown at 101. As can be appreciated,
the blade 102 with both the wearable outer pad 103 and hard
material surface 106 has a first radial extension from the parent
housing body 101. When the wearable outer pad 103 wears, due to
friction for example, the blade 102 with the hard material surface
106 will have a second radial extension that is less than the first
radial extension. Each of the embodiments described herein provides
a positioning/stabilizer elements that have first radial extensions
that are greater than the second radial extension. The hard
material surface 106 may be referred to as a radially inner portion
and the wearable outer pad 103 may be referred to as a removable
radially outer portion.
[0038] FIG. 2 shows a cross section view of an above bend
positioning/stabilizer element 200 with a soft metal wearable outer
pad 203 mounted on a blade 202 and underlain by a hard material
surface 206. In this embodiment soft metal wearable outer pad 203
includes hard material inclusions 204, sometimes referred to as
interstitial hard material 204. The parent housing body is shown at
201.
[0039] FIG. 3 shows a cross section view of an above bend
positioning/stabilizer element 300 with a dissolvable outer pad 305
mounted on a blade 302 and underlain by a hard material surface
306. The parent housing body is shown at 301. In an alternative
embodiment (not shown) dissolvable outer pad 305 may be reinforced
with harder material.
[0040] FIG. 4a shows a cross section view of an above bend
positioning/stabilizer element 400a with an outer hard material
element 406a underlain by dissolvable material 405 mounted on blade
402. Depression areas 407 are void and will allow hard metal
element 406a to depress once dissolvable material 405 has
dissolved. The parent housing body is shown at 401.
[0041] FIG. 4b shows a cross section view of an above bend
positioning/stabilizer element 400b with an outer hard material
element 406b now depressed into blade 402 following the dissolving
of the dissolving material 405 previously shown in FIG. 4a. The
parent housing body is shown at 401.
[0042] FIG. 5a shows a cross section view of an above bend
positioning/stabilizer element 500a with a caged hard metal ball
509a held in cage 508 in blade 502 and underlain by a wearable or
dissolvable material 505. The parent housing body is shown at
501.
[0043] FIG. 5b shows a cross section view of an above bend
positioning/stabilizer element 500b with a caged hard metal ball
509b now depressed into blade 502 following the wear or dissolving
of element 505 shown in FIG. 5a. The parent housing body is shown
at 501.
[0044] FIG. 6a shows a cross section view of an above bend
positioning/stabilizer element 600a with a swellable tensioner 611a
anchored to blade 602 at anchor points 610. The swellable tensioner
611a supports a hard outer surfacing material 606a in a radially
extended position. The parent housing body is shown at 601. The
swellable material for the swellable tensioner 611a may comprise a
number of swellable materials such as, for example, natural rubber,
synthetic rubber, hydrogels, to name but a few materials.
[0045] FIG. 6b shows a cross section view of an above bend
positioning/stabilizer element 600b with a now swollen and
depressed swellable tensioner 600b anchored to blade 602 at anchor
points 610. Relaxed swellable tensioner 611b maintains attachment
with hard outer surfacing material 606b now in a relaxed position.
The parent housing is shown at 601.
[0046] FIG. 7a shows a cross section view of an above bend
positioning/stabilizer element 700a with a hinged hard metal
surface 706a underlain by a channeled hard metal ball 709a held in
place by a dissolvable insert 705 in channel 711 all deployed in or
on blade 702. In FIG. 700a hinged hard metal surface 706a is shown
in a radially extended position anchored at hinge 712. The parent
housing is shown at 701.
[0047] FIG. 7b shows a cross section view of an above bend
positioning/stabilizer element 700b with a hinged hard metal
surface 706b now depressed following the dissolving of the insert
705 and the movement of the hard metal ball 709b down the channel
711. The parent housing is shown at 701.
[0048] FIG. 8a shows a cross section view of an above bend
positioning/stabilizer element 800a with a hard metal surface 806a
underlain by a fluid filled bladder 813a sealed with a dissolvable
stopper 805. The fluid in the bladder may be free of components
such as salt which would attack the dissolvable stopper 805. The
bladder 813a is anchored to blade 802 at points 810. The parent
housing is shown at 801.
[0049] FIG. 8b shows a cross section view of an above bend
positioning/stabilizer element 800b with a hard metal surface 806b
underlain by bladder 813b now unsealed, deflated and depressed. The
deflated bladder 813b is anchored to blade 802 at points 810. The
parent housing is shown at 801.
[0050] FIG. 9a shows a cross section view of an above bend
positioning/stabilizer element 900a with a hinged hard metal
surface 906a underlain by a deployed piston rod 909a held in place
by a piston housing 905 connected to a sensor and battery pack 913
through connector 914. Radially extended hard metal surface 906a is
attached to blade 902 at hinge 912. The parent housing is shown at
901.
[0051] FIG. 9b shows a cross section view of an above bend
positioning/stabilizer element 900b with a hinged hard metal
surface 906b now depressed by the retraction of the piston rod 909b
in response to a signal from the sensor and battery pack 913 sent
through connector 914. Radially retracted hard metal surface 906b
is attached to blade 902 at hinge 912. The parent housing is shown
at 901.
[0052] Although the embodiments shown in the Figures refer to above
bend positioning/stabilizer elements the technologies of this
application may equally be applied to below bend
positioning/stabilizer elements, kick pad elements, or string
stabilizers.
[0053] Although the embodiments shown in the Figures show a single
blade in cross section the technologies of this application may
equally be applied to positioning/stabilizer elements with two or
more blades.
[0054] Although specific embodiments are disclosed in the Figures
those skilled in the art will readily see that the features of the
technologies disclosed in this application may be adapted from one
embodiment to another. For instance (not shown) the sensor and
battery pack and piston assembly shown in FIGS. 9a and 9b could be
deployed in the depressions 407 and blade 402 of FIG. 4a with
appropriate modifications to hard metal surface 406a.
[0055] Although the technologies of the present application have
been described with reference to specific embodiments, these
descriptions are not meant to be construed in a limiting sense.
Various modifications of the disclosed embodiments, as well as
alternative embodiments of the technologies will become apparent to
persons skilled in the art upon reference to the description of the
technologies. It should be appreciated by those skilled in the art
that the conception and the specific embodiments disclosed may be
readily utilized as a basis for modifying or designing other
structures for carrying out the same purposes of the technologies.
It should also be realized by those skilled in the art that such
equivalent constructions do not depart from the spirt and
equivalent constructions as set forth in the appended claims. It is
therefore contemplated that the claims will cover any such
modifications or embodiments that will fall within the scope of the
technology.
* * * * *