U.S. patent application number 13/180013 was filed with the patent office on 2011-11-24 for tension/collar/reamer assemblies and methods.
This patent application is currently assigned to Strataloc Technology Products LLC. Invention is credited to Richard A. Nichols, Roger Pierce, Bruce L. Taylor.
Application Number | 20110284291 13/180013 |
Document ID | / |
Family ID | 32850759 |
Filed Date | 2011-11-24 |
United States Patent
Application |
20110284291 |
Kind Code |
A1 |
Nichols; Richard A. ; et
al. |
November 24, 2011 |
Tension/Collar/Reamer Assemblies And Methods
Abstract
The present invention provides drilling assembles and methods
that are especially useful for a bottom hole drilling assembly for
drilling/reaming/ or other operations related to drilling a
borehole through an earth formation. In one embodiment, the
drilling assembly utilizes standard drill collars which are
modified to accept force transfer sections. In another embodiment,
the drilling assembly comprises a tension inducing sub which
creates a force that may be used to place the bottom hole assembly
or portions thereof in tension. In another embodiment, a reaming
assembly is held in tension to provide a stiffer reaming
assembly.
Inventors: |
Nichols; Richard A.;
(Spring, TX) ; Taylor; Bruce L.; (Spring, TX)
; Pierce; Roger; (Houston, TX) |
Assignee: |
Strataloc Technology Products
LLC
|
Family ID: |
32850759 |
Appl. No.: |
13/180013 |
Filed: |
July 11, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
12785875 |
May 24, 2010 |
7987926 |
|
|
13180013 |
|
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Current U.S.
Class: |
175/57 ; 175/320;
175/406 |
Current CPC
Class: |
E21B 17/02 20130101;
E21B 7/28 20130101; E21B 17/00 20130101; E21B 17/16 20130101 |
Class at
Publication: |
175/57 ; 175/320;
175/406 |
International
Class: |
E21B 7/00 20060101
E21B007/00; E21B 10/26 20060101 E21B010/26; E21B 17/00 20060101
E21B017/00 |
Claims
1-13. (canceled)
14. A drilling assembly for use in drilling a gas or oil borehole,
said drilling assembly comprising: a series of outer tubulars
connected to form a drilling string; a bit at the bottom end of
said drilling string; one or more high density members within said
outer tubular at or near the bottom of said drilling string;
wherein said drilling string, when under greater than 10,000 pounds
of weight on bit, has a neutral zone located not more than about 45
feet above said bit with said drilling string being in tension
above said neutral zone.
15. The assembly of claim 14 wherein at least one of said high
density member includes tungsten.
16. The assembly of claim 15 wherein at least one of said high
density member has a central bore therethrough.
17. The assembly of claim 16 wherein at least one of said high
density member has a pipe therethrough to prevent contact of said
high density member with drilling fluid circulation flow through an
aperture in said pipe that runs through said drilling assembly.
18. The assembly of claim 14 wherein said drilling string, when
under greater than about 32 thousand pounds of weight on bit, has a
neutral zone located not more than about 45 feet above said bit
with said drilling string being in tension above said neutral
zone.
19. The assembly of claim 14 wherein said drilling string, when
under greater than about 50 thousand pounds of weight on bit, has a
neutral zone located not more than about 45 feet above said bit
with said drilling string being in tension above said neutral
zone.
20. The assembly of claim 14 wherein said drilling string, when
under greater than about 32 thousand pounds of weight on bit, has a
neutral zone located not more than about 14 feet above said bit
with said drilling string being in tension above said neutral
zone.
21. A method for making a drilling assembly for use in drilling a
gas or oil borehole, said method comprising: utilizing a series of
outer tubulars connected to form a drilling string; providing a bit
at the bottom end of said drilling string; utilizing one or more
high density members within said outer tubular at or near the
bottom of said drilling string which are configured so that said
drilling string, when under greater than 10,000 pounds of weight on
bit, has a neutral zone located not more than about 45 feet above
said bit with said drilling string being in tension above said
neutral zone.
22. The method of claim 21 wherein at least one of said high
density member includes tungsten.
23. The method of claim 22 wherein at least one of said high
density member has a central bore therethrough.
24. The method of claim 23 wherein at least one of said high
density member has a pipe therethrough to prevent contact of said
high density member with drilling fluid circulation flow through an
aperture in said pipe that runs through said drilling assembly.
25. The method of claim 21 wherein said drilling string, when under
greater than about 32 thousand pounds of weight on bit, has a
neutral zone located not more than about 45 feet above said bit
with said drilling string being in tension above said neutral
zone.
26. The method of claim 21 wherein said drilling string, when under
greater than about 50 thousand pounds of weight on bit, has a
neutral zone located not more than about 45 feet above said bit
with said drilling string being in tension above said neutral
zone.
27. The method of claim 21 wherein said drilling string, when under
greater than about 32 thousand pounds of weight on bit, has a
neutral zone located not more than about 14 feet above said bit
with said drilling string being in tension above said neutral zone.
Description
[0001] The benefit of U.S. Provisional Patent Application No.
60/442,737, filed Jan. 27, 2003, and U.S. Utility patent
application Ser. No. 10/761,892, filed Jan. 21, 2004, and U.S.
Provisional Patent Application No. 60/721,406, filed Sep. 28, 2005,
is hereby claimed, and is hereby incorporated by reference.
TECHNICAL FIELD
[0002] The present invention relates generally to drilling
wellbores for oil, gas, and the like. More particularly, the
present invention relates to assemblies and methods for improved
drill bit and drill string performance.
BACKGROUND ART
[0003] Due to their size and construction, prior art heavy weight
drill collars are unbalanced to some degree and tend to introduce
variations. Moreover, even if they were perfectly balanced, the
heavy weight drill collars have a buckling point and tend to bend
up to this point during the drilling process. The result of
imbalanced heavy weight collars and the bending of the overall
downhole assembly produces a flywheel effect with an imbalance
therein that may easily cause the drill bit to whirl, vibrate,
and/or lose contact with the wellbore face in the desired drilling
direction. The oil and gas drilling industry has long sought and
continues to seek solutions to the above problems.
SUMMARY OF THE INVENTION
[0004] Accordingly, it is an objective of the present invention to
provide an improved drilling assembly and method.
[0005] An objective of another possible embodiment is to provide
faster drilling ROP (rate of penetration), longer bit life, reduced
stress on drill string joints, truer gage borehole, improved
circulation, improved cementing, improved lower noise MWD and LWD,
improved wireline logging accuracy, improved screen assembly
running and installation, fewer bit trips, reduced or elimination
of tortuosity, reduced or elimination of drill string buckling,
reduced hole washout, improved safety, and/or other benefits.
[0006] Another objective of yet another possible embodiment of the
present invention is to provide means for transmitting the force
from one or a plurality of weight sections which may or may not
comprise standard drill collars through threaded connectors to any
desired point there below through any number of box/pin connection
up to and including placing substantially the entire weight of a
plurality of weight sections at the top of the drill bit.
[0007] An objective of yet another possible embodiment of the
present invention provides a much shorter compression length of the
bottom hole assembly with respect to the first order of buckling
length to thereby virtually eliminate buckling of the bottom hole
assembly and the resulting tortuosity in the hole.
[0008] Another objective of yet another possible embodiment of the
present invention is to provide an outer steel sleeve for the
bottom hole assembly which is held in tension instead of being in
compression even at close distances from the drill bit such that
buckling of the drill string is eliminated.
[0009] Another objective of yet another possible embodiment of the
present invention is to apply an increased amount of weight
adjacent the bit and to permit increased revolutions per minute
(RPM) of the drill string to thereby increase the drilling rate of
penetration (ROP) in many formations.
[0010] Another objective of yet another possible embodiment of the
present invention may comprise combining one or more or several or
all of the above objectives with or without one or more additional
objectives, features, and advantages.
[0011] These and other objectives, features, and advantages of the
present invention will become apparent from the drawings, the
descriptions given herein, and the appended claims. However, it
will be understood that the above-listed objectives, features, and
advantages of the invention are intended only as an aid in
understanding aspects of the invention, and are not intended to
limit the invention in any way, and therefore do not form a
comprehensive or restrictive list of objectives, and/or features,
definitions, and/or advantages of the invention.
[0012] Accordingly, a method is provided for drill collars utilized
in a bottom hole assembly for drilling oil and gas wells. The drill
collars may be standard drill collars commonly utilized in drilling
operations for decades and may comprise threaded connections on
opposite ends thereof for interconnection to form the bottom hole
assembly. The method may comprise installing a plurality of
slidable force transfer members within a plurality of drill collars
such that the plurality of force transfer members are operable for
transferring a force through each of the plurality of threaded
connections for applying the force to the drill bit during drilling
of the borehole while holding one or more of the plurality of
tubulars in tension with the drill pipe string during the drilling
of the borehole. The method might further comprise producing the
force with a tension inducing sub secured to the bottomhole
assembly so that the tension inducing sub producing the force for
application to the plurality of force transfer members.
[0013] Various embodiments of a tension inducing sub for use with a
drilling assembly are also taught. The tension inducing sub may
comprise one or more elements such as, for instance, a tubular
housing, a threaded connection for the tubular housing for
connecting to the plurality of threaded tubulars, a force transfer
assembly mounted in the tubular housing for transferring a force
through the threaded connection to the plurality of force transfer
elements, and a mechanism for creating the force. In one
embodiment, the mechanism might further comprise a plurality of
gears arranged to provide a mechanical advantage such that a
smaller force induced in a first gear is magnified by the
mechanical advantage to produce the force.
[0014] The present invention may also be embodied within a reamer
assembly for enlarging a borehole which may comprise a housing, one
or more reamer blades extendable radially outwardly to engage the
borehole to be enlarged, one or more force transfer members
slidably mounted within the tubular housing, at least one threaded
connection for the housing, one or more force creation members for
connection to the threaded connection, the one or more force
creation members comprising one or more force transfer members
operable for transferring a force through the at least one threaded
connection to the one or more force transfer members slidably
mounted within the tubular housing. The reamer might further
comprise a plurality of weight sections as the force creation
members, i.e., the force of weight. The plurality of weight
sections comprise weight sections threadably mounted above and
below the reamer. The reamer might further comprise a bit wherein
the force is transferred to the bit through the one or more force
transfer members so as to be operable for stiffening the reamer
housing by placing the reamer housing in tension while the borehole
is being enlarged.
BRIEF DESCRIPTION OF DRAWINGS
[0015] For a further understanding of the nature and objects of the
present invention, reference should be had to the following
detailed description, taken in conjunction with the accompanying
drawings, in which like elements may be given the same or analogous
reference numbers and wherein:
[0016] FIG. 1 is an elevational view, in cross-section, of heavy
weight drill collars having high density sections in accord with
one possible embodiment of the present invention;
[0017] FIG. 1A is an enlarged elevational view, in cross-section,
of the upper assembly 12 of FIG. 1 in accord with the present
invention;
[0018] FIG. 1B is an enlarged elevational view, in cross-section,
of the lower assembly 14 of FIG. 1 in accord with the present
invention;
[0019] FIG. 2 is an elevational view, in cross-section, of a heavy
weight drill collar having a high density section in disks in
accord with one possible construction of the present invention;
[0020] FIG. 3A is an elevational view, in cross-section, of a heavy
weight drill collar with multiple high density inner sections with
weight transmitting elements wherein all of the high density weight
is transferred through the center of the tool for application
directly to the top of the drill bit while the outer steel sheath
is in tension in accord with the present invention;
[0021] FIG. 3B is a schemmatical view showing tension and
compression forces in one preferred embodiment of the present
invention as per FIG. 3A wherein the gravitational force produced
by tungsten alloy weight sections is transmitted directly to the
bit or bit connection sub through the interior of the tool.
[0022] FIG. 3C is an elevational view, in cross-section, of the
drilling assembly of FIG. 3A wherein the bottom hole assembly may
be in tension within two feet of the drill bit in accord with one
embodiment of the present invention;
[0023] FIG. 3D is an elevational view, in cross-section, of the
drilling assembly of FIG. 3A wherein the bottom hole assembly may
be in tension within fourteen feet of the drill bit in accord with
one embodiment of the present invention;
[0024] FIG. 3E is an elevational view in cross-section, of the
drilling assembly of FIG. 3A wherein the bottom hole assembly may
be in tension within forty-five feet of the drill bit in accord
with one embodiment of the present invention;
[0025] FIG. 3F is an elevational view, in cross-section, showing
the transfer of weight through other drill string components such
as a stabilizer or weight section with integral stabilizer in
accord with the present invention;
[0026] FIG. 4A is an end view of the tungsten alloy segment shown
in FIG. 4B in accord with one embodiment of the present
invention:
[0027] FIG. 4B is an elevational view, in cross-section, showing a
tungsten alloy segment that may be utilized in combination to form
a weight pack in accord with one embodiment of the present
invention;
[0028] FIG. 4C is an end view of the tungsten alloy segment with
thermal expansion tabs shown in FIG. 4D in accord with one
embodiment of the present invention
[0029] FIG. 4D is an elevational view, in cross-section, showing a
tungsten alloy segment with thermal expansion tabs as one possible
means for controlling the centering the as temperature changes;
[0030] FIG. 5A is an elevational view showing a bottom hole
assembly in accord with the present invention which shows the
concentration of 50% more useable weight on the bit with a very
short compression length of the bottom hole assembly than a
comparable prior art bottom hole assembly as shown in FIG. 5C;
[0031] FIG. 5B is an elevational view showing a bottom hole
assembly in accord with the present invention with 300% more
useable weight on the bit and a significantly shortened compression
length of the bottom hole assembly as compared to the prior art
shown in FIG. 5C;
[0032] FIG. 5C is an elevational view showing a prior bottom hole
assembly for comparison purposes with embodiments of the present
invention shown in FIG. 5A and FIG. 5B;
[0033] FIG. 6A and FIG. 6B are elevational views including a
comparison chart showing the effect of buoyant forces of different
weight mud for a prior art heavy weight steel drill collar as
compared to a high density heavy weight drill collar in accord with
the present invention;
[0034] FIG. 7A is a comparison chart showing the bottom hole
assembly compression lengths of two feet versus eighty-nine feet
for one embodiment of the present invention as compared to standard
drill collars which places the same weight on the drill bit;
[0035] FIG. 7B is a comparison chart showing the bottom hole
assembly compression lengths and relationship to the first order of
buckling for one embodiment of the present invention as compared to
standard drill collars which places the same weight on the drill
bit;
[0036] FIG. 7C is a comparison chart showing the bottom hole
assembly compression lengths and relationship to the second order
of buckling for one embodiment of the present invention as compared
to standard drill collars which places the same weight on the drill
bit;
[0037] FIG. 8 is a schemmatical elevational view of one possible
use of the present invention as a transition member between the
drill pipe and the bottom hole assembly to provide improved
drilling operation;
[0038] FIG. 9 is an elevational view, partially in cross-section,
of a force transfer threadable connection in accord with the
present invention;
[0039] FIG. 10 is an elevational view, in cross-section, of a
hydraulic tension inducing sub to produce a downward force on force
transfer tubes in accord with one possible embodiment of the
present invention;
[0040] FIG. 11 is an elevational view, in cross-section, of a
standard drill collar which has been modified slightly to accept a
force transfer tube in accord with one possible embodiment of the
present invention;
[0041] FIG. 12 is an elevational view of a bottom hole drilling
assembly utilizing a tension inducing sub and modified drill
collars that include force transfer tubes in accord with one
possible embodiment of the present invention;
[0042] FIG. 13 is an elevational sketch showing a reamer that has
been modified to utilize a force transfer tube in accord with one
possible embodiment of the present invention;
[0043] FIG. 14 is an exploded elevational sketch showing a reamer
modified to accept a force transfer tube utilized in a downhole
assembly along with Heavi-Pac.TM. weight sections in accord with
one possible embodiment of the present invention;
[0044] FIG. 15 is an elevational sketch, in cross-section, of a
rig-tightened tension inducing sub utilized to apply a force to a
force transfer tube in accord with one possible embodiment of the
present invention;
[0045] FIG. 16 is a view of components utilized in an adjustable
force tension inducing sub in accord with one possible embodiment
of the present invention;
[0046] FIGS. 17A and 17B combine to form an elevational view of
components of the adjustable force tension inducing sub of FIG. 16
in accord with one possible embodiment of the present
invention;
[0047] FIGS. 18A and 18B combine to form an elevational view of
components of the adjustable force tension inducing sub of FIG. 16
in accord with one possible embodiment of the present
invention;
[0048] FIG. 19 is an elevational view of components of the
adjustable force tension inducing sub of FIG. 16 in accord with one
possible embodiment of the present invention;
[0049] FIG. 20 is an elevational view of components of the
adjustable force tension inducing sub of FIG. 16 in accord with one
possible embodiment of the present invention;
[0050] FIGS. 21A and 21B combine to form an elevational view of
components of the adjustable force tension inducing sub of FIG. 16
in accord with one possible embodiment of the present
invention;
[0051] FIGS. 22A and 22B combine to form an elevational view of
components of the adjustable force tension inducing sub of FIG. 16
in accord with one possible embodiment of the present
invention;
[0052] FIGS. 23A and 23B combine to form an elevational view of
components of the adjustable force tension inducing sub of FIG. 16
in accord with one possible embodiment of the present invention;
and
[0053] FIGS. 24A and 24B combine to form an elevational view of
components of the adjustable force tension inducing sub of FIG. 16
in accord with one possible embodiment of the present
invention.
[0054] While the present invention will be described in connection
with presently preferred embodiments, it will be understood that it
is not intended to limit the invention to those embodiments. On the
contrary, it is intended to cover all alternatives, modifications,
and equivalents included within the spirit of the invention.
GENERAL DESCRIPTION AND PREFERRED MODES FOR CARRYING OUT THE
INVENTION
[0055] Now referring to the drawings, and more particularly to FIG.
1, FIG. 1A, and FIG. 1B, there is shown an elevational view of one
possible construction of a portion of a drilling assembly 10 which
may be utilized in a drill string in accord with the present
invention. Drilling assembly 10 may preferably be utilized as a
portion of a bottom hole drilling assembly but may also be used
elsewhere in the drill string as desired. In FIG. 1, upper section
12 and lower section 14 may be the same or may be significantly
different in construction. Upper section 12 is connected to lower
section 14 through sub 23. FIG. 1A shows one possible construction
for upper heavy weight assembly 12 and FIG. 1B shows a possible
construction for lower heavyweight assembly section 14. In the
particular embodiments shown in FIG. 1A and FIG. 1B, upper assembly
portion 12 and lower assembly portion 14 function differently as
discussed hereinafter and may be utilized separately or in
conjunction with each other. For instance, multiple upper assembly
portions 12 may be threadably connected and stacked together if
desired for transferring force through each assembly 12 closer to
the drill bit. Alternatively, lower assembly portions 14 may
preferably be stacked together to increase the weight of a bottom
hole assembly.
[0056] In general operation of assembly 12 shown in FIG. 1A, inner
sections, such as 16, are moveable with respect to outer sections,
such as 17, to supply weight or force to the drill bit during
drilling while simultaneously maintaining the outer sections 17 in
tension. In comparison with the embodiment of FIG. 1B, in general
operation of assembly 14 shown in FIG. 1B, inner sections 18 are
not moveable with respect to outer section 24. One preferred
embodiment for a bottom hole drilling assembly would utilize
multiple stacked assemblies similar to assembly portion 12 which
are threaded together and/or multiple stacked assemblies similar to
assembly portion 14 which are in the bottom hole assembly to
replace standard heavy weight steel drilling collars. Thus,
assemblies 12 and 14 may be utilized independently of each other
and may or may not be utilized together.
[0057] In upper assembly 12, high density section 16 is slidably
mounted with respect to outside tube 17. In a preferred embodiment
high density section 16 may comprise tungsten alloy as discussed
hereinafter. Some benefits of the present invention may also be
obtained using other high density materials such as, for example
only, heavy metals, steel, depleted uranium, lead, molybdenum,
osmium, and/or other dense materials. If desired, section 16 may
utilize lighter weight materials to transfer force through assembly
12. However, in a preferred embodiment significant force on the bit
is created by weight of multiple high density sections 16 as taught
herein.
[0058] Because the weight or force associated with high density
section 16 is preferably transferred to a lower sub rather than to
outside tube 17, outside tube 17 and/or other outside tubes are not
necessarily compressed by the weight of high density section 16.
Instead tube 17 is more likely to be placed into tension depending
on its relative position in the bottom hole assembly, thereby
stiffening the bottom hole assembly. As discussed in more detail
hereinafter, the present invention permits that a large percentage
of the compression length of the bottom hole assembly (that portion
of the bottom hole assembly in compression) may be reduced, as
indicated graphically in FIG. 5A-FIG. 5C and FIG. 7A-FIG. 7C by use
of drilling assemblies in accord with the present invention such as
upper assemblies 12 and/or lower assemblies 14. The reduced
compression length of the bottom hole assembly results in a stiffer
assembly that rotates with less vibration and reduced or eliminated
buckling-flywheel effects. The stiffer drill string can then be
rotated faster and will drill a cleaner, truer, bore hole, with an
increased drilling rate of penetration (ROP).
[0059] In another embodiment of the invention, as discussed in FIG.
3A-FIG. 3E, all or practically all and/or selectable lengths of the
outer tubulars in the bottom hole assembly of the drill string are
in tension. By drastically reducing the compression length of the
bottom hole assembly as compared to the buckling point thereof,
buckling of the bottom hole assembly is essentially eliminated. In
the embodiments of FIG. 3A-FIG. 3E, the weight of preferred high
density elements, such as tungsten alloy sections, may be
transmitted through the interconnection joints to any number of
other lower sections and even down to the top of the drill bit.
Thus, the unbalanced flywheel effects caused by buckling of the
bottom hole assembly during rotation of the drill string are
substantially reduced or completely eliminated.
[0060] Drilling assemblies 12 and 14 of the present invention may
comprise smaller, shorter, components than the standard 31 foot
long steel heavy weight collars. Therefore, assembly section 12 and
14 can be machined or adjusted or weighted to be dynamically and
statically balanced as discussed hereinafter to further reduce or
eliminate all flywheel effects. The stiff, balanced bottom hole
assembly will drill smoother and straighter with reduced bit whirl.
As will be discussed hereinafter, a bottom hole assembly built
utilizing the balanced, stiff, concentric, high weight
subassemblies thereof such as drilling assembly 12 and 14, can be
rotated faster. The greater balance, concentricity, increased
vibration characteristics, and possibly decreased surface volume
for contacting the borehole wall decreases drill string torque or
resistance to the rotation of the drill string as compared to
standard bottom hole drilling assemblies. ROP is often directly
related to the RPM of the drill string so that doubling the
drilling RPM may also double the rate of drilling penetration.
[0061] In many oil and gas fields that the rate of penetration
(ROP) is also directly proportional to the weight on the bit, so
that doubling the actual weight on the bit after buoyancy effects
are taken into consideration may double the drilling rate of
penetration.
[0062] In a preferred embodiment for a bottom hole assembly in
accord with the present invention, the concentration of weight or
force applied to the bit at a position near the bit significantly
prevents lateral vibrational movement of the bit due to the
increased force required to overcome the greatly increased inertia
of the concentrated mass at the bit. Thus, bit whirling is
significantly dampened or prevented resulting in a truer bore hole
and faster ROP. Other vibrational effects such as bit bounce are
also reduced by the elasticity and noise dampening effects of the
preferred high density material utilized as discussed hereinafter.
While the prior art has concentrated largely on bit design to
eliminate bit whirling, bit bounce, and tortuosity, it is submitted
by the present inventors that these problems are much better
eliminated by the design of the bottom hole assembly tubulars as
taught herein.
[0063] In the embodiment of the invention shown in FIG. 1B,
assembly 14 may comprise high density section 18 which may be
securely affixed to outside tube 20. Thus, in assembly 14 inner
section 18 is not moveable with respect to outside tube or wall 20.
One preferred means of mounting utilizes a shrink fit mounting
method whereby close tolerances of the mating surfaces may prevent
assembly when the temperatures of the components 18 and 20 are the
same, but heating or cooling of one of the component 18 and 20
permits the assembly and provides a very secure fit after the
temperature is stabilized. For instance, outside tube 20 may be
heated to a high temperature, e.g., up to about 450 degrees
Fahrenheit, thereby expanding. High density section 18, which has
approximately the same dimension and cannot fit at equalized
temperatures, may then be inserted into outside tube due to the
expansion caused by a significant temperature difference. When both
outside tube 20 and high density section 18 are the same
temperature, then the components are held fast to each other. Note
that as explained below, the high density material may preferably
comprise a tungsten alloy which is designed to have similar tensile
strength and elasticity as steel. Thus, the combined assembly has
similar mechanical properties as standard steel heavy weight
collars but has a weight almost twice that of a standard steel
heavy weight collar. In heavier muds, the combined assembly may
have an actual applied weight on the bit after buoyancy effects
that is more than twice that of the same length of standard steel
heavy weight collars. (See FIG. 6A and FIG. 6B)
[0064] In the above described designs, wash pipes or inner tubulars
22 and 24 are preferably utilized on the inside of high density
sections 16 and 18 to protect and preserve high density sections 16
and 18. Thus, high density sections 16 and 18 are preferably
contained between inner and outer tubulars such as steel tubulars
rather than exposed to circulation flow through bore 26. In a
preferred embodiment, high density sections 16 and 18 are also
sealed therein to prevent any contact with the circulation fluid.
If desired, inner tubulars 22 and/or 24 could also or alternatively
be affixed to high density sections 16 and 18 by assembling when
there is a significant temperature difference that provides just
enough clearance for assembly whereby after the temperatures of the
components are approximately the same, the components are affixed
together.
[0065] It is highly advantageous during directional drilling to be
able to take a magnetic survey as close to the bit as possible.
Typically, one to three hundred feet may need to be drilled before
the effects of actions taken by the directional driller can be seen
due to the need to keep the compass away from the magnetic bottom
hole assembly. This results in sometimes getting off target and
makes corrections to get back on target difficult. In one
embodiment of the present invention, a nonmagnetic tungsten alloy
may be utilized. In this case, inner and outer tubulars, such as 22
and 20 may comprise a nonmagnetic metal such as Monel. Because the
amount of Monel required is significantly reduced as compared to
prior art Monel tubulars which are typically utilized for the
purpose of making magnetic surveys, the cost for Monel material is
also significantly reduced. Moreover, Monel heavyweight drill
collars are not normally utilized so that the compass survey data
is generally not available adjacent or within the heavy weight
drilling collar portion of the drill string. By permitting compass
measurements closer to the bit, the drilling accuracy can be
significantly improved.
[0066] Other constructions of the high density assembly for
directional drilling may comprise use of tungsten powder or slurry
to provide a readily bendable weight section for use in direction
drilling where a stiff bottom hole assembly may cause sticking
problems or even be incapable of bending the necessary number of
degrees per depth required by the drilling projection. The greater
flexibility and heavier weight of a bottom hole assembly in accord
with this embodiment of the present invention permits greater
weight to be applied to the bit even when using a bent sub with
considerable angle. The ability to apply more weight on the bit
during directional drilling in accord with the present invention is
likely to increase the ROP of directional drilling operations
thereby significantly reducing the higher cost of directional
drilling. Directional drilling bottom hole assemblies may comprise
mud motors, bent subs, and the like. The use of a flexible
heavyweight section with this type of directional drilling assembly
provides means for improved and faster directional drilling.
Moreover, the use of nonmagnetic material within the bottom hole
assembly itself gives rise to the potential of placing the compass
much closer to the bit than is now possible thereby permitting much
more accurate drilling, fewer doglegs, and better producing wells
that accurately go through the drilling target or targets along an
optimal drilling path with a faster ROP.
[0067] In one preferred embodiment, the tensile strength and
elasticity of a preferred tungsten alloy are adjusted to be similar
to that of steel. One preferred embodiment of the present invention
completely avoids use of cobalt within the tungsten alloy to
provide greater elasticity of the tungsten alloy. Cobalt has in the
past been utilized within a tungsten alloy to increase the tensile
strength thereof. However, increasing the tensile strength reduces
the elasticity making the tungsten compound brittle. In accord with
one embodiment of the present invention, a cobalt tungsten alloy is
avoided as being unsuitable for general use in a bottom hole
assembly environment when it will be subjected to many different
types of stress, e.g., torsional, bending, compressive, and the
like, which bottom hole drilling assemblies encounter. A presently
preferred embodiment tungsten alloy in accord with the present
invention comprises 93-95% W (tungsten), 2.1% NI, 0.9% Fe, and 2-4%
MO. This alloy has greater plasticity than prior art tungsten
alloys utilized in bottom hole assemblies and is therefore better
suited to withstand the stresses created thereby. The components
are preferably adjusted to provide mechanical properties similar to
that of steel whereby the above formulation is believed to be
optimal such that the assembly reacts in many ways as a standard
steel collar.
[0068] The tungsten alloy has a high mechanical vibration impedance
approximately twice that of steel which also limits vibrations in
the drill string thereby reducing tool joint failure in the drill
string. In one embodiment of the present invention as also
discussed in connection with FIG. 8, a transition section
comprising tungsten alloy may be utilized between the bottom hole
assembly and the drill pipe string, or at any other desired
position in the drilling string, to thereby dampen vibrations
transmitted from the bottom hole assembly to the drill pipe string.
The transition section may be constructed in accord with one of the
construction embodiments taught herein and may be positioned
between the bottom hole assembly and the drill pipe string.
[0069] FIG. 2 shows one possible construction of drilling assembly
30 in accord with one embodiment of the present invention utilizing
a plurality of tungsten elements 32 stacked in mating relationship
with each other. The dimensions of each tungsten element 32 are
preferably tightly controlled to provide that drilling assembly 30
is balanced. Likewise, the dimensions of outer tubular 40, upper
section 44, and lower section 46 are also tightly controlled. The
length of assembly 30 may be approximately half that of a standard
drill collar. Each element is small enough so that dimensions can
be tightly controlled during machining If any static or dynamic
imbalance were detected, then a specially weighted tungsten element
32 may be utilized and inserted at a desired rotational and axial
position, and fixed in position to thereby correct the imbalance.
During assembly in one preferred embodiment, tungsten elements 32
are preferably inserted into outer tubular 40 when there is a large
temperature difference. The dimension tolerances are selected so
that only when there is a significant temperature difference is it
possible to insert weighted tungsten elements 32 into outer tubular
40. When the temperature is approximately the same, the relative
expansion/contraction of the components will result in a very tight
and secure fit.
[0070] Drilling assembly 50 may be utilized to transfer force such
as the force of the weight of heavy metal, steel, tungsten,
depleted uranium, lead, and/or other dense materials from upper
positions in bottom hole assembly to lower positions in the bottom
hole assembly. FIG. 3A shows an internal construction of a portion
of drilling assembly 50. Drilling assembly 50 may comprise many
sections as shown in FIG. 3A which are threadably connected
together, as are standard drill string tubulars, which transfer
force such as force created by weight through the assembly and
through the threaded connectors.
[0071] FIG. 3B schematically shows one possible basic mode of
operation of weight transfer drilling assembly 50. Drilling
assembly 50 may comprise any number of high density heavy weight
section collars constructed from outer tubulars 54A-54D and
moveable weight packs 56A-56D supported therein. The weight or
force acting on or created within each weight pack may be
collectively transferred to the next lower weight pack through the
tool joints. Preferably, the high weight packs 56A-56D may comprise
tungsten alloy but the slidable weight packs could comprise any
material, including lower density materials, which are suitable to
provide a desired weight for a particular application. Each high
density weight pack 56 is interconnected by rods/tubes/or other
means to thereby transmit the weight downwardly in the bottom hole
assembly through a plurality of threaded connections that connect
the tubulars as do standard drill string tubulars and may even
transfer all weight directly to bit 82. In a preferred embodiment,
a large portion or all of the string of outer tubulars 54A-54D is
thereby held in tension so that collar buckling of the bottom hole
assembly is effectively eliminated. The placement of the collective
entire weight of one or more high density weight sections 56A-56D
through a plurality of threaded connections directly on the top of
bit 82 has the effect of preventing bit bounce because of the
significant inertia which must be overcome to cause the bit to move
upwardly. The high vibration absorbing properties of tungsten alloy
in accord with the present invention also reduce the tendency of
drill bit 82 to vibrate upwardly. Drill bit 82 is therefore held to
the face of the formation for smoother, faster, drilling.
[0072] The ability to hold the bit face in contact with the bottom
of the bore greatly increases the rate of drilling penetration
especially for modern PDC bits. The PDC cutting elements of bits
have a very short length and, ideally, must be held in constant
contact with the surface to be cut for maximum cutting effects.
Thus, a bottom hole assembly in accord with the present invention
is ideally suited for maximizing the drilling potential of modern
PDC bits.
[0073] Weight packs 54A and 54B may comprise a plurality of
tungsten compound elements 32, an example of which is shown in FIG.
4A and FIG. 4B. In this example, each tungsten element 32 has a pin
34, box 36, and body 38. The tungsten elements are stacked
together. The relatively short tungsten elements 32 may be
manufactured to very high tolerances to thereby avoid any
imbalances. The completed assembly is preferably dynamically and
statically balanced. If necessary, any fine tuning balancing may be
accomplished utilizing tungsten elements that are weighted to
offset the imbalance and positioned axially and fixed in a radial
position by tabs, grooves, or the like.
[0074] Due to the flexibility of the tungsten compound of the
present invention, the relative thickness of tungsten can be made
relatively large as compared to the thickness of the outer tubulars
such as outer tubular 20, 40, 54A, and so forth in one of the
embodiments of the present invention. Thus, the present invention
will have a higher density per volume as compared to some prior art
devices discussed hereinbefore. For instance, in one presently
preferred embodiment it is desirable that the wall thickness of
body 38 be at least 25% to 50% greater than the wall thickness of
the outer tubular as compared with prior art designs which utilize
a thick steel jacket. For the 10.0 inch diameter assembly, which
may be utilized for drilling bore holes where a prior art 9.5 inch
diameter drill collar was previously utilized, and assuming a 3.5
inch bore through weight section 32 (which may be reduced closer to
2.875 for some situations as per other prior art downhole
assemblies), the wall thickness is 2.25 inches as compared to a 1.0
inch wall thickness of the outer tubular. Thus, for this situation
the wall thickness of weight section 32 is 125% greater than the
wall thickness of the outer tubular.
[0075] In a preferred embodiment, pin 34 and box 36 may have a
taper of about three to four inches per foot. This structure
provides a strong connection between the weight sections 32 that
has significant bending resistance thereby producing a stiffer
assembly.
[0076] Weight sections 32 are stacked together and may be mounted
in a shrink fit manner, by compression, or may be moveable axially.
In any case, it is presently not considered necessary to provide
any threads on the weight sections to interconnect with outer
structural tubulars, as has been attempted in the prior art with
brittle weighting material.
[0077] As shown in FIG. 3A, drilling assembly 50, which is used for
force and/or weight transfer through threaded connections, may
comprise one or more hollow tubulars such as tubular housing 54A or
54B. One end of each tubular housing 54A and 54B is preferably
secured to a pin such as pin portion 71 of pin thread body 74. An
opposite end of each tubular housing 54A and 54B may be secured to
a pin such as pin portion 73 of box thread body 86. Preferably, pin
portion 71 and pin portion 73 utilize the same type of thread for
joining multiple tubular housings together within drilling assembly
50. It will be noted that housings such as housing 54A and 54B may
comprise multiple tubulars and so be built in selectable lengths.
In this case, each tubular forming a housing, such as housing 54A,
may be secured with another tubular utilizing sub 52 which
preferably comprises a double pin threaded body to thereby form a
housing of any size length.
[0078] Located inside hollow tubular housings 54A and 54B are
weight packs 56A and 56B. As discussed hereinbefore, weight packs
56A and 56B may be made from any suitable material such as heavy
metal, steel, depleted uranium, lead, or other dense materials, but
are preferably formed of tungsten alloy. Weight packs 56A and 56B
may be made in solid form in the form of liquids or powders, e.g.,
tungsten powder or a tungsten slurry. Preferably, any liquids and
powders are placed inside sealed containers to prevent any possible
leakage. Weight packs 56A and 56B may be mounted in different ways.
When used as part of a weight transfer system as illustrated in
FIG. 3A, weight packs 56A and 56B are preferably free to slide up
and down for a short axial distance in space 70 but completely
prevented from radial movement by suitable means some of which are
discussed herein.
[0079] In a preferred embodiment, weight packs 56A and 56B are
preferably centered within housings 54A and 54B. In one possible
embodiment, this may be accomplished by means of centering rings
92. Centering rings 92 are preferably designed to adjust to
temperature and pressure changes, allowing diameter compensation
for weight packs 56A and 56B in downhole applications. Centering
rings 92 permit axial movement of weight packs 56A and 56B. In
another embodiment, tabs, fins, grooves, tubulars, or the like
could be utilized.
[0080] It is not necessary that the centering elements be
positioned between the outer surface of the weight packs and the
inner surface of the outer tubular. For instance, as shown in FIG.
4C and FIG. 4D in another embodiment, bronze tabs may be bolted
onto, for instance, pin 34. Bronze has a higher thermal expansion
rate than either steel or tungsten and therefore expands during
heat to keep the weight packs centralized within the outer tubular,
e.g., with a fixed annular spacing substantially regardless of
temperature.
[0081] However, weight packs 56A and 56B could also be restrained
by shrink fit or placed in the compression between pin and box
bodies, if desired. In this case, the drilling assembly would
operate more like drilling assembly 14 as discussed
hereinbefore.
[0082] Preferably, weight packs 56A and 56B are sealed between
tubular housings 54A and 54B by wash pipes such as wash pipes 58
(See FIG. 3A) to prevent contact with fluid due to circulation flow
through aperture 75 that runs through drilling assembly 50. Wash
pipes 58 utilize seal 60 on a lower end thereof and seal 90 on an
upper end thereof for sealing off the weight packs. Space 70 and
the sealed volume enclosing weight packs 56A and 56B may preferably
be filled with a non-compressible fluid for pressure balancing
purposes.
[0083] In a preferred embodiment, upper transfer tube 78 and lower
weight transfer tube 80 are split into two sections and engage each
other at connection 87. Other arrangements could also be utilized
to connect or avoid the need to connect the weight transfer
element, but may require the operators to add components during
installation. Thus, this construction allows operators to
interconnect the components of the bottom hole assembly in
substantially the way that the standard steel heavy weight bottom
hole assembly is connected.
[0084] Upper weight transfer tube 78 and lower weight transfer tube
80 also utilize seals to prevent fluid leakage to weight packs 56A
and 56B. Seal 62 is utilized for sealing the upper end of upper
weight transfer tube 78 and seal 76 is utilized for sealing the
lower end of upper weight transfer tube 78 with respect to weight
packs 56A and 56B. Seal 84 and seal 88 are utilized by lower weight
transfer tube 80 for the same purpose.
[0085] Upper weight transfer tube 78 and lower weight transfer tube
80 are also axially movable with weight packs 56A and 56B. Upper
weight transfer tube 78 and lower weight transfer tube 80 are
thereby able to transfer the weight of upper weight pack 56A onto
lower weight pack 56B. Upper weight transfer tube 78 comprises
upper platform 79, which engages and supports the weight of upper
weight pack 56A. The force applied to upper platform 79 is applied
to lower platform 81 and the top of weight pack 56B. The weight of
each high density section is thereby transmitted downwardly and may
even be applied through a bit sub directly to the top of the bit.
The outer tubes, such as outer tubes 54A and 54B are held in
tension by the relatively axially moveable weight of the weight
sections to provide a stiff bottom hole assembly which effectively
eliminates buckling. The truer drilling resulting therefrom may
eliminate the need for stabilizers in many circumstances to avoid
the cost, friction, and torsional forces created due to such
use.
[0086] While one or more weight transfer tubulars, such as upper
transfer tube 78 and lower weight transfer tube 80 are shown in
this preferred embodiment as the weight or force transmitting
element in this embodiment, other weight or force transmitting
elements such as rods or the like may be utilized. As well, the
weight or force transmitting elements may extend through apertures
other than center bore 75 to connect the weight sections.
Therefore, the present invention is not limited to utilizing split
tubular force or weight transmission elements as illustrated,
although this is a presently preferred embodiment. Force or
transfer tubes 78 and 80 provide a relatively simple construction
that permits connecting a plurality of heavyweight sections in a
typical manner utilizing standard equipment for this purpose.
[0087] It will be noted that the transfer of weight or force is
made through a standard threaded pin-box connection 83 which is of
the type typically utilized in drilling strings. In accord with the
present invention, the force or weight can be transferred through
any drill string component as may be desired. For instance, FIG. 3F
shows the weight of weight pack 56A being transferred through
stabilizer 94. If desired, stabilizer 94 can be built integral or
machined in one piece with the outer tubular, thereby eliminating
the need for a connection. This construction is difficult or
impractical with prior art heavy weight collars that require a
separate stabilizer. Due to the component structure of the present
invention, it is possible to machine desirable structures such as
stabilizer 94 directly into the outer tube. However, stabilizer 94
could also be mounted by other means or clamped on or provided as a
separate component.
[0088] In one preferred embodiment, an enlarged or bored out
aperture through a standard stabilizer permits a weight
transmitting tubular to be inserted therein. The bending strength
ratio for the pin-box connection has a BSR in the range of
approximately 2.5 which is often a desired value to permit equal
bending of the box elements and the pin so that neither element is
subject to excessive bending stress. Various portions of the
pin-box connection can be altered to thereby obtain a desired BSR,
e.g., boring out the passageway through the joint. It is often
possible to modify many standard drill string components by simply
boring out the passageway and still be well within the desired BSR
range so that specialized equipment is not required. Thus, the
weight transmitting tubular construction may also be utilized to
transmit weight or force through any type of drilling element such
as stabilizers, bit connection sections, and the like. The
straight, unperturbed, continuous wall flow path through tubular
weight transfer elements 78 and 80 produces a more continuous bore
through the bottom hole assembly to reduce fluid turbulence and
associated wear at the pin-box connections, as occurs in prior art
heavy weight collar sections. The fluid turbulence and wear reduces
the life of prior art heavy weight collar sections as drilling
fluid is circulated through the drill string as per standard
drilling operation procedures. Thus, the transfer tubular elements
78 and 80 also have the advantageous purpose of actually increasing
the reliability pin-box connections as compared to prior art
pin-box bottom hole assembly connections.
[0089] Using multiple weight transfer packs, extremely heavy weight
can be applied in a very short distance close to the actual bit or
working area. FIG. 3C-FIG. 3E show examples of the use of drilling
assembly 50 to apply the weight of the weight packs at distances
such as two feet above the bit at point 102 in FIG. 3C, fourteen
feet above the bit at point 104 in FIG. 3D, and 45 feet above the
bit at point 106 in FIG. 3E. Comparison of these values with prior
art heavy weight sections are shown in the graphs of FIG. 7A-7C.
The outer tubulars above these points are therefore in tension
providing for a stiff, concentrically balanced, bottom hole
assembly. Many different combinations of the components of the
drilling assemblies such as drilling assembly 14 and drilling
assembly 50 can be made to add as much weight to the bottom hole
assembly in a desirable position for efficient drilling. All this
can be done to maximize the weight on the bit and stay far below
the buckling points of standard down hole tools.
[0090] The use of the present invention eliminates or significantly
reduces most of the current problems associated with heavy weight
drilling requirements such as bending of the bottom hole assembly,
buckling of the bottom hole assembly, pressure differential
sticking, broken or damaged thread connections, crooked hole boring
or drilling, hole washouts, bent drill pipe, down hole vibrations,
bit whirl, drill string whip, drill string wrap (wind-up), drill
bit slap-stick, bit wear, bit bounce, and others. With the
reduction or elimination of these problems, it is anticipated that
increased rates of penetration can be achieved and overall costs
significantly reduced.
[0091] FIG. 5A-FIG. 5C show an embodiment of the present invention
which illustrates that the compression length of the bottom hole
assembly is adjustable and may be greatly shortened as compared to
prior art drilling assemblies. For instance, in FIG. 5A compression
length 112 provides about 15.8 thousand pounds weight on the bit in
12 lb./gal mud. The short compression length 112 shown for bottom
hole assembly 110 in accord with the present invention is easily
comparable visually with the much longer compression length 116 for
bottom hole assembly 120 utilizing standard steel drill collars
shown in FIG. 5C. Standard bottom hole assembly 120 provides only
10.0 thousand pounds and still has a much longer compression
length. Bottom hole assembly 120 is much more subject to
bending/buckling problems and many other problems as discussed
above. As shown in FIG. 5B, compression length 111 is much shorter
than compression length 116 but provides a weight on the bit (WOB)
of 32.3 thousand pounds or more than three times the WOB as the
prior art standard configuration shown in FIG. 5C. Accordingly, it
will be anticipated that the configuration of FIG. 5B will drill
faster and truer than the prior art configuration of FIG. 5C.
[0092] As discussed above, a shortened compression length for the
down hole drilling assembly has many advantages, e.g., reduced
buckling for truer drilling. It will be noted that above each
compression length is a respective neutral zone 122, 124, 126.
Above each neutral zone 122, 124, and 126, the drill string is in
tension and therefore not subject to buckling. By utilizing the
drilling assembly of the present invention, a much larger
percentage of the bottom hole assembly is in tension to thereby
provide a stiffer bottom hole assembly that will drill a truer gage
hole at higher ROP as explained hereinbefore.
[0093] FIG. 6B shows one preferred embodiment wherein the diameter
of a high density drilling assembly of the present invention may
preferably be somewhat enlarged as compared to a standard diameter
drill collar. Even though the diameter is enlarged as compared to a
standard diameter drill collar, the washout produced by the present
invention due to the velocity of fluid through the smaller annulus
can be reduced as can be mathematically shown as per the attached
equation listings. This is because the length of the heavy weight
drill collars can be reduced while still providing the same weight.
This analysis ignores the significant effects of faster ROP in
reducing washout. Also, this analysis ignores the significant
effect of a truer, straighter hole on washouts, which effect is
very important. Thus, the same weight of the bottom hole assembly
can be provided in a bottom hole assembly that is much shorter, by
about one-half. Due to this shortened length, less washout occurs
than with a standard steel bottom hole assembly. Prior art larger
diameter bottom hole assemblies as discussed in the prior art
section had significant problems with washout although the use of
wider diameter bottom hole assemblies had the beneficial effects of
placing at least some weight closer to the drill bit. Moreover,
because the actual weight on the bit may be about several times as
much by utilizing the present invention, the rate of penetration
may be much faster drilling thereby further reducing borehole
washout. The total circulating system pressure drop is also lowered
because of the shorter bottom hole assembly. The shorter length of
the bottom hole assembly also decreases the likelihood of sticking
in the borehole such as differential sticking or other types of
sticking making the drilling operation more trouble free of drastic
events that may cause loss of the hole.
[0094] FIG. 7A is a comparison chart showing the bottom hole
assembly compression lengths of two feet versus eighty-nine feet
for one embodiment of the present invention as compared to standard
drill collars which places the same weight on the drill bit (WOB).
FIG. 7B is a comparison chart showing the bottom hole assembly
compression lengths and relationship to the first order of buckling
for one embodiment of the present invention as compared to standard
drill collars which places the same weight on the drill bit. The
first order of buckling is approximately 150 feet for a standard
9.5 inch steel drill collar assembly in 12 lb. mud. The second
order of buckling is 290 feet. This compares to a first order of
buckling for a 10-inch assembly in 12 lb. mud for the present
invention of 140 feet and a second order of buckling of 275 feet.
In the present invention, the drilling string is in tension at the
position of the first and second order of buckling thereby reducing
or eliminating buckling. The formulas for these calculations are as
follows:
1.94 ( E * 144 * I * P 2 3 / P = First Order of Buckling
##EQU00001## 3.75 E * 144 * I * P 2 3 / P = Second Order of
Buckling ##EQU00001.2##
where: [0095] E=moment of Elasticity [0096] I=moment of Inertia,
and [0097] P=Lbs-ft buoyed weight
[0098] In the situation of FIG. 7A for 15,750 lbs. weight on the
bit (WOB) in 12.0 lb. mud, a bottom hole assembly in accord with
the present invention has a compression length that is, for all
practical purposes, completely unaffected by buckling.
[0099] In the situation of FIG. 7B for 32,390 lbs. WOB in 12.0 lb.
mud, a bottom hole assembly in accord with the present invention
has a compression length one-tenth of the first order of buckling
and so is almost unaffected. However, with a standard drilling
assembly, the compression length is greater than the first order of
buckling and so the bottom hole assembly is likely to produce
substantial wobbling or an unbalanced flywheel effect during
rotation.
[0100] In the situation of FIG. 7C for 51,500 lbs. WOB in 12.0 lb.
mud, a bottom hole assembly in accord with the present invention
has a compression length of only about one-quarter of the first
order of buckling. To obtain the same WOB with a standard drilling
assembly requires a compression length of 290 feet wherein the
bottom hole assembly is subject to both first and second order of
buckling and is likely to produce substantial wobbling during
drilling.
[0101] A review of the above description shows that the present
invention may be utilized to either greatly increase the stiffness
of the bottom hole assembly or greatly increase the flexibility
thereof, depending on the desired function.
[0102] FIG. 8 shows another use of the present invention as a
transition element 142 that may be utilized to interconnect bottom
hole assembly 140 to the drill pipe string 144. Due to the
significant vibration dampening effect of tungsten, the vibrations
produced during drilling in the bottom hole assembly can be
dampened significantly. This protects the pipe connections and also
permits a better signal to noise ratio for acoustic signals
transmitted through the drill string or mud for MWD and LWD
equipment. The weight packs are still useful for adding weight to
and/or shortening the length of bottom hole assembly 140, as
discussed hereinbefore. The transition member can be utilized in
other locations in the drill string or in multiple positions, if
desired.
[0103] Force transfer section 200 shown in FIG. 9 provides an
enlarged view of a presently preferred embodiment for transferring
force, such as weight through threaded pin connection 202 and
threaded box connection 204. It is well known that a drilling rig
may be utilized for making up and breaking out connections such as
202 and 204 for use in a drilling string. Force transfer section
200 comprises axially moveable upper force transfer tube 206 and
lower force transfer tube 208 which may be utilized to transfer
force through the threaded connections, such as weight to be
applied to the drill bit, as explained heretofore in some detail.
Mud seals 210 and 212 may be utilized to seal around the respective
upper and lower force transfer tubes. If desire, any suitable
anti-rotation connection, such as anti-rotation connection 214 as
illustrated, may be provided so that upper force transfer tube 206
and lower force transfer tube 208 do not rotate with respect to
each other. It will be noted that upper transfer tube 206 extends
axially within pin connection 202 and lower transfer tube 208
extends axially within box connection 204 for transferring force
through the connection. It will also be readily apparent that pin
connection 202 and box connection 204 can be made up or broken out
utilizing standard drilling rig equipment without need for
modification thereto. As used herein a drilling rig may include
derricks and the like utilized for making up and breaking out
tubulars such as workover rigs, completion units, subsea
intervention units, and/or coiled tubing units utilized and/or
other units for providing long tubulars in wells.
[0104] As discussed hereinbefore, another aspect of the present
invention is a statically and dynamically balanced drilling
assembly. The tolerances on the relatively small components are
quite tight and preferably require that the components, such as
weight packs and outer tubular be machined round within 0.005
inches and may be less than 0.003 inches. In this way, the rotation
axis coincides with one of the principal axis of inertia of the
body. The condition of unbalance of a rotating body may be
classified as static or dynamic unbalance. For instance, the
assembly may be tested to verify that it does not rotate to a
"heavy side" when free to turn. Thus, the center of gravity is on
the axis of rotation. An idler roll may be in perfect static
balance and not be in a balanced state when rotating at high
speeds. A dynamic unbalance may occur when the body is in static
balance and is effectively a twisting force in two separate planes,
180 degrees opposite each other. Because these forces are in
separate planes, they cause a rocking motion from end to end. In
the prior art, due to the buckling and bending of the downhole
assembly, there is little motivation to attempt to provide a
balanced bottom hole assembly because the buckling and bending will
cause significant imbalance regardless. For dynamic balancing, the
drilling assembly is first statically balanced. After rotating to
the operating speed, if necessary, any dynamic unbalance out of
tolerance is eliminated by adding or subtracting weight as
indicated by a balancing machine. The determination of the
magnitude and angular position of the unbalance is the task of the
balancing machine and its operator. As discussed hereinbefore, any
imbalance out of tolerance can be corrected because the weight pack
is provided in sections, any one of which can be rotatably adjusted
as necessary and axially positioned. If desired, grooves, pins, or
the like may be utilized on pin 34 and socket 36 for weight
elements 32 such that each weight element can be affixed in a
particular rotational position. A permissible imbalance tolerance
is determined based on the mass of the downhole assembly and the
anticipated rotational speed.
[0105] In summary, the present invention provides a much higher
average weight per cubic inch for a downhole assembly. For instance
a weight/per unit volume or average density of standard steel
heavyweight collar may be about 0.283 pounds per cubic inch wherein
an average weight per unit volume of a drilling assembly of the
present invention is significantly greater and may be about 0.461
pounds per cubic inch. The vibration dampening characteristics of
tungsten reduce bit vibrations for smoother drilling. A heavier
average weight per unit volume permits use of a shorter compression
length of the bottom hole assembly. The concentration of weight
closer to the drill bit reduces bit whirl and bit vibration and bit
bounce. In a preferred embodiment, the drilling assemblies of the
present invention are much more highly balanced than prior art
bottom hole assembly elements due to much tighter control of
overall tool concentricity and straightness. Increased rate of
penetration occur due to reduced bit wear, vibration dampening,
reduced bit whirl, and reduced bit bounce. Because of decreased
vibration, fewer trips are required because the bit life is
lengthened and the tool joints are less subject to vibration
stress. Lower torque stress is applied to the drilling string
because of less wall contact by the bottom hole assembly due to
decreased surface area and more concentric rotation thereof. The
compression length of a bottom hole assembly in accord with the
present invention is much reduced as compared to the first or
second order of tubular buckling (see attached calculation sheets)
so that the bottom hole assembly in accord with the present
invention is straighter. It should also be noted that a more highly
balanced, vibration dampened, bottom hole assembly built utilizing
weighting assemblies such as drilling assembly 10, 12, 14, 30, or
50, or variations thereof can be rotated faster with less vibration
and harmonics to thereby increase drilling rates of
penetration.
[0106] The weight transfer assembly is operable to transfer the
inner weight of several drill collars through the tool joints from
the upper collar to a lower or lowest point in the drill string
while keeping the entire BHA (bottom hole assembly) in tension.
There are no bending or buckling moments in the string and all of
the weight may be placed directly above the bit. The collars may be
the same length as standard drill collars and there is no
difference in make-up or break-out. The near bit assembly may have
a tungsten matrix weight while the assemblies above may have
tungsten/lead weights. The tungsten matrix reduces vibration,
bounce, and chatter and provides more power in a compact area
directly above the bit. By transferring the weight for drilling to
a point very near the drill bit, the neutral point is also lowered
to that point. Additionally putting the weight directly above the
bit increases the force of restitution (force required to move a
pendulum from its vertical position) and increases the centripetal
force that cause a body to seek a true concentric axis of rotation.
Placing the weight near the bit increases the inertia or impact of
the bit against the formation and holds the bit steadier against
the formation as may be especially desirable for certain types of
drill bits. The resistance to drag is also increased due to the
greater inertia resulting in a more stable drilling speed of the
bit.
[0107] The present invention provides a means for producing a
stiffer drilling assembly that has many benefits, some of which are
discussed above, by applying a force to force transfer tubes. The
force may be produced by weights or by other means. As noted above,
bronze expansion tabs shown in FIGS. 4C and 4D, may utilize a
downhole thermal expansion differential with respect to steel to
produce a force or tension on the force transfer tubes. Many other
possible means may also be utilized to produce a force or tension
on the force transfer tubes. Some possible examples are discussed
hereinafter.
[0108] FIG. 10 shows a hydraulic tension inducing sub 1000, which
produces a force on force transfer tube 1002 in accord with one
possible embodiment of the present invention. Tension inducing sub
1000 may use differential pressure to produce a force. For
instance, in one embodiment, the differential hydraulic pressure
between the annulus outside tension inducing sub 1000 and the mud
column pressure at 1010 is applied to piston 1012. Piston 1012
applies this force to axially moveable force transfer tube 1002,
which transfers the force to the string for other force transfer
tubes 1004 and eventually to the top of bit 1008, as indicated in
FIG. 11 and FIG. 12. If desired, pressure equalizing piston 1014
may be utilized to pressurize hydraulic fluid beneath piston 1012
to the same pressure as that in the annulus.
[0109] In another embodiment, FIG. 11 shows a standard drill collar
1006 which has been modified to accept a force transfer tube 1004
in accord with one possible embodiment of the present invention. In
one embodiment, force transfer tube 1004 may be mounted to move or
float axially by a certain fixed amount within standard drill
collar 1006. For instance, as one possible means for doing this,
within an existing drill collar 1006, the weight section might be
bored out to accept force transfer tube 1004. Drill collars 1006
could also be originally made with force transfer tube 1004.
Although many constructions may be utilized, in one possible
embodiment, force transfer tube may comprise a collar, enlargement,
or the like of desired width at the upper end to act as a stop
surface (not shown). A counterbore within drill collar 1006 would
permit movement of the stop surface within the counterbore by a
certain axially length. After insertion of force transfer tube 1004
into drill collar 1006, a nut or the like which blocks further
axial movement of force transfer tube 1004 may be inserted to one
end of the counterbore, so that the desired limited amount of axial
movement is allowed. Other means for accomplishing the same
mechanical result could also be used. Smaller force transfer tubes
that fit in the original openings might also be used. Accordingly,
there are many ways, typically low cost, for modifying standard
drill collars to incorporate force transfer tubes. As noted
hereinbefore, force transfer tubes can be made in many different
ways to effect force transfer from one section to another.
[0110] FIG. 12 is an elevational view of a bottom hole drilling
assembly utilizing a tension inducing sub, such as tension inducing
sub 1000 or other versions thereof, some of which are discussed
herein, along with weight sections that may comprise modified drill
collars 1006 or other tubular members that comprise force transfer
tubes 1004 in accord with one possible embodiment of the present
invention.
[0111] In operation, an embodiment of the invention such as shown
in FIGS. 10-12, provides that a force is created on force transfer
tubes 1004 by tension inducing sub 1000, or other tension inducing
means such as that shown in FIGS. 4C and 4D or other tension
inducing means. The force so produced on the force transfer tubes
1004 is provided to be sufficiently greater than combined weight of
drill collars 1006. Therefore, the external bodies of drill collars
1006 are held in tension even though in a typical BHA during
drilling they would be at least partially in compression, as per
the discussion hereinbefore.
[0112] In the example of FIG. 10, a tension inducing sub 1000
produces a downward force acting on force transfer tube 1002 and
all subsequent force transfer tubes 1004 which might be, for
example only, a downward force of 60,000 pounds, depending on the
hydraulics. If the drill collars 1004 shown in FIG. 12 collectively
weigh 30,000 pounds, then the entire threadedly connected drill
collar string formed by drill collars 1006 will be in tension at a
force of 30,000 pounds rather than in compression. An additional
benefit is that, for reasons discussed hereinbefore, the collective
weight of 30,000 pounds of the string of drill collars 1006 is
applied to the top of drill bit 1008 through the force transfer
tubes. Moreover, the stiffer drilling assembly would have numerous
benefits and could be made very inexpensively.
[0113] Subsequent figures show various other embodiments of tension
inducing subs also in accord with the present invention. However,
the invention is not limited by the particular embodiments of the
invention shown herein, which may be selected based on the
particular requirements. Once the concept of the present invention
is understood by those of skill in the art, it will be understood
that the tension inducing sub of the present invention may be
implemented I many various types of devices that may be used to
apply a desired amount of force on the force transfer tubes
including, but not limited to, pressurized nitrogen acting on a
piston, gases produced by relatively slow burning explosives,
springs, temperature expansion, and the like. Moreover, multiple
downhole tension inducing subs may be stacked together to thereby
multiply the force created thereby which acts on the force transfer
tubes. The operation might also be controlled with downhole sensors
depending on the type of tension inducing sub construction. For
instance, tension inducing sub 1000 might utilize downhole valving
and feedback control sensors to maintain a desired tension due to
variations in the downhole hydraulics.
[0114] It will be understood that various downhole tools may
utilize force transfer tubes 1004 for stiffening their construction
utilizing the principles disclosed herein. For instance, a reamer
is subject to bending forces wherein in a stiffer reamer may
operate with greatly improved performance. As one example of a
stiffer reamer assembly, FIG. 13 is an elevational sketch showing
reamer 1020 that has been modified to utilize an axially moveable
force transfer tube 1022 in accord with one possible embodiment of
the present invention. Reamer blades 1028 may move radially
outwardly as indicated for reaming out a section of the borehole
to, for example, facilitate a gravel pack operation or for other
purposes. FIG. 14 is an exploded elevational sketch of downhole
assembly 1026 showing reamer 1020 as may be utilized along with
weight sections, such as weight sections 50 (see also FIG. 3A or
3B) or other weight sections, preferably utilizing force transfer
tubes, or tension inducing subs such as sub 1000. Additional weight
sections 50 may be connected below reamer 1020 which may also
connect to bit 1024. In operation, downhole assembly 1026 places
reamer 1020 in tension rather than compression, which is believed
to improve functioning of reamer 1020 which may otherwise be
subject to bending as may affect the reaming performance.
[0115] FIG. 15 is an elevational sketch, in cross-section, of yet
another tension inducing sub 1000. In this embodiment, tension
inducing sub 1000 may be rig-tightened utilizing a drilling rig to
provide a desired rotational force. After tightening, tension
inducing sub 1030 then applies force to a force transfer tube 1032
in accord with one possible embodiment of the present invention. In
this embodiment, force transfer tube 1032 may be selected to be a
specific length which will result in a desired amount of tension
produced in the weight sections. Section 1036 may be connected to a
bottom hole assembly with force transfer tubes, e.g., three weight
sections 50 comprising force transfer tubes, or modified standard
collars 1006. Once threaded section 1036 is tightened by the rig or
the like to the uppermost weight section, then a desired length
force transfer tube 1032 may be inserted into section 1036. Then
section 1034 is tightened by the rig. The length of force transfer
tube is selected to place the known length of weight sections 50
into a desired tension. For instance, as an example which is
intended only to show operation, suppose it is desired to produce
50,000 pounds of tension in the three weight sections 50. Suppose
also that 0.125 inches of extension 1038 of force transfer tube
1032 produces 50,000 pounds tension in a length of three weight
sections. Then the length of force transfer tube 1032 may be chosen
to effect this amount of tension. It will be appreciated that if
there were six weight sections, with identical stretch as described
above, then 0.25 inches of extension 1038 would be required to
place all six sections in 50,000 pounds of tension. As a
non-limiting example, a typical preload amount may range from
10,000 to 150,000 pounds of tension in such a string and 50,000
pounds may sometimes be considered in the general range of optimal.
However, this depends on hole conditions, on the type of weight
sections, and the type of bit. It will be appreciated that once
1034 is tightened to produce the desired tension, then upper
section 1040 may be attached and the upper drill string is then
attached in a typical way.
[0116] FIG. 16-FIG. 24B show another possible embodiment of an
adjustable force tension inducing sub in accord with the present
invention. In this embodiment, the basic operation is the same as
discussed above. Instead of utilizing hydraulic power, or rig
torsion, or nitrogen pressure, or thermal expansion tabs, or the
like, the tool provides an adjustable length tube. It will be
appreciated that many different assemblies and/or methods may be
utilized to produce a variable length force transfer tube or
applying a variable force to force transfer tubes.
[0117] Referring to FIG. 16, tension inducing sub 1100 is shown in
cross-section. Tension inducing sub 1100 permits an operator to
dial in a desired amount of force onto force transfer tube 1102
which can be used to place a downhole string of weight sections
having force transfer tubes into a selectable amount of tension. In
this embodiment, worm gear 1104 is accessible from opening 1106 to
accomplish this. The internal components provide a high mechanical
advantage so that a small force on worm gear 1104 over a
predetermined number of turns results in a large force on transfer
tube 1102. For instance, as one possible example, 300 turns at 2.3
foot pounds on worm gear 1104 may produce 50,000 pounds of force on
force transfer tube 1106. In one embodiment, a drill or the like,
perhaps with a counter, may be utilized to drive worm gear 1104
over the 300 or other number of desired turns. Other views shown in
FIG. 16 are presented for convenience and also shown in the
remaining figures. In operation, tension inducing sub 1100 is
connected to the top of a bottom hole assembly. As discussed above,
the amount of tension which will be induced by movement of force
transfer tube 1102 is known and related to the number of weight
sections. As also discussed above for one possible example only to
show operation, force transfer tube 1102 might be moved by 0.125
inches to apply 50,000 pounds of tension to three weight sections
already connected together. Alternatively, 50,000 pounds of tension
might be applied to six of the same type of weight sections by
moving force transfer tube by 0.250 inches. In any event, the
amount of movement is known from the stretch characteristics of
weight sections and the desired amount of tension is dialed in
using worm gear 1106.
[0118] FIGS. 17A and 17B show rapid transit nut 1108 which is
splined to mate to spline housing 1110 to permit axial movement
only. In one preferred embodiment rapid transit nut 1108 can move
axially by six inches. As rapid transit nut 1108 is moved axially
as a result of turning worm gear 1104, spiral screw 1112 rotates
thrust screw 1114. In one embodiment, six inches of axial movement
of rapid transit nut 1108 produces one-quarter turn of spiral screw
1112 and also thrust screw 1114 which results in 0.250 inches of
axial movement of thrust screw 1114, which in turn is applied to
transfer tube 1102. FIGS. 18A and 18B show an enlarged view of
tension inducing sub 1100 shown in FIG. 16 with components from
FIGS. 17 and 17B marked as indicated. FIG. 19 illustrates one
possible embodiment of an outer body 1116 for tension inducing sub
1100.
[0119] FIG. 20 shows rapid transit nut 1108 and an internal view of
spiral screw 1112 within rapid transit nut 1108. Spiral screw 1112
mates to internal threads within rapid transit nut 1108. In one
embodiment, rather than machining internal threads within rapid
transit nut 1108, bearing material such as babbit is poured into an
interior of rapid transit nut 1108 while spiral screw is positioned
therein and allowed to cool to thereby provide mating threads.
FIGS. 21A and 21B show additional views of rapid transit nut 1108
and spiral screw 1112.
[0120] FIGS. 22A, 22B, 23A and 23B show pressure balance piston
1118 to provide for equalizing pressure between the bore and
interior components of tension inducing sub 1100. Worm gear 1104
rotates travel nut 1120 which moves axially and engages rapid
transit nut 1108 through nut thrust bearing 1122. FIGS. 24A and 24B
show a cross-sectional view of tension inducing sub 1100 as
compared with rapid transit nut 1108 and spiral screw 1112.
[0121] In operation, tension inducing sub 1000 or 1100, or other
tension inducing subs or means discussed hereinbefore, may be used
to produce a desired tension in attached weight sections which
include force transfer tubes. Tension inducing sub produces a force
on the force transfer tubes which stretch or place the outer walls
of the weight sections in tension. The weight of the entire string
may then be applied to the top of the bit while the bottom hole
assembly is held in tension.
[0122] The foregoing disclosure and description of the invention is
therefore illustrative and explanatory of a presently preferred
embodiment of the invention and variations thereof, and it will be
appreciated by those skilled in the art, that various changes in
the design, manufacture, layout, organization, order of operation,
means of operation, equipment structures and location, methodology,
the use of mechanical equivalents, as well as in the details of the
illustrated construction or combinations of features of the various
elements may be made without departing from the spirit of the
invention. For instance, the present invention may also be
effectively utilized in coring, reaming, milling and/or other
operations as well as standard drilling. The present invention may
be used with relatively inexpensive drill collars modified to
include force transfer tubes.
[0123] In general, it will be understood that such terms as "up,"
"down," "vertical," and the like, are made with reference to the
drawings and/or the earth and that the devices may not be arranged
in such positions at all times depending on variations in
operation, transportation, mounting, and the like. As well, the
drawings are intended to describe the concepts of the invention so
that the presently preferred embodiments of the invention will be
plainly disclosed to one of skill in the art but are not intended
to be manufacturing level drawings or renditions of final products
and may include simplified conceptual views as desired for easier
and quicker understanding or explanation of the invention. Thus,
various changes and alternatives may be used that are contained
within the spirit of the invention. Because many varying and
different embodiments may be made within the scope of the inventive
concept(s) herein taught, and because many modifications may be
made in the embodiment herein detailed in accordance with the
descriptive requirements of the law, it is to be understood that
the details herein are to be interpreted as illustrative of a
presently preferred embodiments and not in a limiting sense.
* * * * *