U.S. patent application number 14/147004 was filed with the patent office on 2015-09-24 for top mount dual bit well drilling system.
The applicant listed for this patent is EDWIN J. BROUSSARD, JR.. Invention is credited to EDWIN J. BROUSSARD, JR..
Application Number | 20150267492 14/147004 |
Document ID | / |
Family ID | 54141608 |
Filed Date | 2015-09-24 |
United States Patent
Application |
20150267492 |
Kind Code |
A1 |
BROUSSARD, JR.; EDWIN J. |
September 24, 2015 |
TOP MOUNT DUAL BIT WELL DRILLING SYSTEM
Abstract
A top mount dual bit well drilling mechanism has a rotary driven
tubular housing having a top mount body within an upper end portion
of the housing to which the upper end of a mud motor is mounted for
support within the housing. A reamer bit is connected for rotation
by the tubular housing upon rotation by a well drilling string and
defines a core removing bit chamber that is recessed within the
reamer bit and has communication with the core receiving
receptacle. A core removing bit is rotated within the core removal
bit chamber by the mud motor and continuously cuts away the upper
end of a formation core that enters the receptacle as the reamer
bit cuts into the formation.
Inventors: |
BROUSSARD, JR.; EDWIN J.;
(New Iberia, LA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
BROUSSARD, JR.; EDWIN J. |
New Iberia |
LA |
US |
|
|
Family ID: |
54141608 |
Appl. No.: |
14/147004 |
Filed: |
March 18, 2014 |
Current U.S.
Class: |
175/107 |
Current CPC
Class: |
E21B 4/02 20130101; E21B
10/04 20130101; E21B 10/605 20130101; E21B 10/26 20130101 |
International
Class: |
E21B 25/10 20060101
E21B025/10; E21B 10/26 20060101 E21B010/26; E21B 10/60 20060101
E21B010/60; E21B 4/02 20060101 E21B004/02; E21B 10/02 20060101
E21B010/02 |
Claims
1. A top mount dual bit well drilling mechanism for drilling
attachment to a tubular well drilling string extending from a
drilling rig located at the Earth's surface, comprising: a tubular
housing for connection with a tubular well drilling string; a top
mount body having an upper end portion mounted in non-rotatable
relation within said tubular housing and having a connecting end; a
drilling fluid energized rotary motor being supported within said
tubular housing by said connecting end of said top mount body; a
reamer bit being connected with said tubular housing and having a
plurality of spaced cutter retaining blades each having
multiplicity of formation cutter elements mounted thereto and
defining a downwardly facing core receiving receptacle, said reamer
bit being rotated by said tubular housing upon rotation of said
tubular housing by said tubular well drilling string, said reamer
bit defining a core removing bit chamber therein in communication
with said downwardly facing core receiving receptacle; a core
removing bit being disposed for rotation within said core removal
bit chamber and having a cutting face oriented for engaging and
removing a formation core that remains and enters said downwardly
facing core receiving receptacle as said formation cutter elements
of said reamer bit cut a wellbore into the formation; and a bit
drive shaft being driven by said drilling fluid energized rotary
motor and being connected in rotary driving relation with said core
removing bit.
2. The top mount dual bit well drilling mechanism of claim 1,
comprising: said reamer bit having an axis of rotation; said
tubular housing of said drilling mechanism having a longitudinal
center-line being concentric with said axis of rotation of said
reamer bit; said drilling fluid energized rotary motor having a
longitudinal center-line; said top mount body supporting said
drilling fluid energized rotary motor with said longitudinal
center-line thereof being laterally offset from said longitudinal
center-line of said tubular housing of said drilling mechanism; and
said core removing bit being rotatable about said longitudinal
center-line of said drilling fluid energized rotary motor.
3. The top mount dual bit well drilling mechanism of claim 1,
comprising: said reamer bit having an axis of rotation; said
tubular housing of said well drilling mechanism having a
longitudinal center-line being concentric with said axis of
rotation of said reamer bit; said drilling fluid energized rotary
motor having a longitudinal center-line; said top mount body
supporting said drilling fluid energized rotary motor with said
longitudinal center-line thereof in concentric relation with said
longitudinal center-line of said tubular housing of said well
drilling mechanism; and said core removing bit being rotatable
about said longitudinal center-line of said drilling fluid
energized rotary motor.
4. The top mount dual bit well drilling mechanism of claim 1,
comprising: said reamer bit defining a cutting face; said core
removing bit defining a cutting face being recessed within said
reamer bit and located inwardly of said cutting face of said reamer
bit and permitting formation core stabilization of said reamer bit
within said downwardly facing core receiving receptacle.
5. The top mount dual bit well drilling mechanism of claim 1,
comprising: said drilling fluid energized rotary motor having a
tubular motor housing; a stator member being located within said
tubular motor housing; a rotor member being located within said
stator member and being rotated by drilling fluid flow between said
stator and rotor members; and a bit drive shaft being rotationally
driven by said rotor member and having driving connection with said
core removing bit.
6. The top mount dual bit well drilling mechanism of claim 1,
comprising: said reamer bit having right hand rotation during well
drilling; and said drilling fluid energized rotary motor rotating
said core removing bit to the left during well drilling.
7. The top mount dual bit well drilling mechanism of claim 1,
comprising: said reamer bit having right hand rotation during well
drilling; and said drilling fluid energized rotary motor rotating
said core removing bit to the right during well drilling.
8. The top mount dual bit well drilling mechanism of claim 1,
comprising: internal splines being defined within said tubular
housing; external splines being defined by said top mount body and
engaging said internal splines and establishing a non-rotatable
relationship of said top mount body within said tubular housing; a
retainer and adjustment member being threaded within said tubular
housing and having retaining and adjusting engagement with said top
mount body; said drilling fluid energized rotary motor having a
tubular motor housing being connected with and supported by said
top mount body and being seated within said reamer bit body; and a
bit drive shaft extending through said tubular housing and into
said core removing bit chamber and being in threaded driving
connection with said core removing bit.
9. The top mount dual bit well drilling mechanism of claim 1,
comprising: drilling fluid flow passages being defined within said
tubular housing and both internally and externally of said drilling
fluid energized rotary motor.
10. The top mount dual bit well drilling mechanism of claim 1,
comprising: a drilling fluid supply chamber being located within
said tubular housing and externally of said top mount body and said
drilling fluid energized rotary motor; a substantially centrally
located drilling fluid flow passage extending longitudinally
through said top mount body and providing a supply of drilling
fluid to said fluid energized rotary motor; a flow diverting
passage being defined in said top mount body and being in
communication with said substantially centrally located drilling
fluid flow passage and diverting a portion of the drilling fluid
being supplied by the well drilling string into said drilling fluid
supply chamber; and reamer bit supply passages being defined within
said reamer bit and conducting flows of drilling fluid from said
drilling fluid supply chamber to spaces between said cutter
retaining blades.
11. The top mount dual bit well drilling mechanism of claim 10,
comprising: replaceable flow control nozzles being located within
designated drilling fluid flow passages to control the volume of
drilling fluid flow for operation of said drilling fluid energized
rotary motor, for cooling drilling components and to supply
drilling fluid flow for efficient operation of said reamer bit and
said core removing bit.
12. A top mount dual bit well drilling mechanism for drilling
attachment to a tubular well drilling string extending from a
drilling rig located at the Earth's surface, comprising: a tubular
housing having a mounting sub at the upper end thereof for rotary
driven connection with a tubular well drilling string; a top mount
body defining a drilling fluid flow passage therethrough and having
an upper end portion mounted in non-rotatable relation within said
tubular housing and having a connecting end; a drilling fluid
energized rotary motor being supported within said tubular housing
by said connecting end of said top mount body and defining a motor
operation chamber in communication with said drilling fluid flow
passage of said top mount body; a reamer bit being connected with
said tubular housing and having a plurality of spaced cutter
retaining blades each having multiplicity of formation cutter
elements mounted thereto and defining a reamer bit cutting face,
said reamer bit defining a downwardly facing centrally located core
receiving receptacle and being rotated by said tubular housing upon
rotation of said tubular housing by said tubular well drilling
string, said reamer bit defining a core removing bit chamber
therein in communication with said downwardly facing core receiving
receptacle; a core removing bit being disposed for rotation within
said core removal bit chamber and having a cutting face thereof
located inwardly of said cutting face of said reamer bit and
oriented for engaging and removing a formation core that remains
and enters said downwardly facing core receiving receptacle as said
formation cutter elements of said reamer bit cut a wellbore into
the formation; and a bit drive shaft being driven by said drilling
fluid energized rotary motor and being connected in rotary driving
relation with said core removing bit.
13. The top mount dual bit well drilling mechanism of claim 12,
comprising: said reamer bit having an axis of rotation; said
tubular housing of said drilling mechanism having a longitudinal
center-line being concentric with said axis of rotation of said
reamer bit; said drilling fluid energized rotary motor having a
longitudinal center-line; said top mount body supporting said
drilling fluid energized rotary motor with said longitudinal
center-line thereof being laterally offset from said longitudinal
center-line of said tubular housing of said drilling mechanism; and
said core removing bit being rotatable about said longitudinal
center-line of said drilling fluid energized rotary motor.
14. The top mount dual bit well drilling mechanism of claim 12,
comprising: said reamer bit having an axis of rotation; said
tubular housing of said well drilling mechanism having a
longitudinal center-line being concentric with said axis of
rotation of said reamer bit; said drilling fluid energized rotary
motor having a longitudinal center-line; said top mount body
supporting said drilling fluid energized rotary motor with said
longitudinal center-line thereof in concentric relation with said
longitudinal center-line of said tubular housing of said well
drilling mechanism; and said core removing bit being rotatable
about said longitudinal center-line of said drilling fluid
energized rotary motor.
15. The top mount dual bit well drilling mechanism of claim 12,
comprising: said drilling fluid energized rotary motor having a
tubular motor housing; a stator member being located within said
tubular motor housing; a rotor member being located within said
stator member and being rotated by drilling fluid flow between said
stator and rotor members; and a bit drive shaft being rotationally
driven by said rotor member and having driving connection with said
core removing bit.
16. The top mount dual bit well drilling mechanism of claim 12,
comprising: internal splines being defined within said tubular
housing; external splines being defined by said top mount body and
engaging said internal splines and establishing a non-rotatable
relationship of said top mount body within said tubular housing; a
retainer and adjustment member being threaded within said tubular
housing and having retaining and adjusting engagement with said top
mount body; said drilling fluid energized rotary motor having a
tubular motor housing being connected with and supported by said
top mount body and being seated within said reamer bit body; and a
bit drive shaft extending through said tubular motor housing and
into said core removing bit chamber and being in threaded driving
connection with said core removing bit.
17. The top mount dual bit well drilling mechanism of claim 16,
comprising: drilling fluid flow distribution passages being defined
within said core removing bit; said drilling fluid energized rotary
motor having a stator within said tubular motor housing and having
a rotor with said stator being rotated by drilling fluid flow
between said stator and rotor; said rotor having a non-circular
output shaft drive member; a flex shaft having non-rotatable
connection with said non-circular output shaft drive member and
cushioning shock forces of said rotor; a tubular bit drive shaft
being connected in driven relation with said flex shaft and being
connected in driving relation with said core removing bit and
having a drilling fluid flow passage therein in communication with
said drilling fluid flow distribution passages of said core
removing bit.
Description
RELATED PROVISIONAL APPLICATION
[0001] Applicant hereby claims the benefit of U.S. Provisional
Patent Application No. 61/886,498, filed on 3 Oct. 2013 by Edwin J.
Broussard, Jr. and entitled "Steerable Well Drilling System", which
provisional application is incorporated herein by reference for all
purposes.
RELATED UTILITY APPLICATION
[0002] This application is related to the subject matter of pending
non-provisional application Ser. No. 14/085,091, filed on Nov. 20,
2013 by Edwin J. Broussard, Jr. and entitled "Steerable Well
Drilling System".
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] The present invention relates generally to well drilling
systems and particularly to well drilling mechanisms having a
reamer bit defining a central opening within which a formation core
is permitted to enter as the reamer bit progresses into the
formation. The well drilling system of the present invention has a
core removal bit that is located within the reamer bit and is
independently rotated for continuously cutting away the core of
formation material that is not cut away by the rotating cutters of
the reamer bit.
[0005] The present invention also concerns dual drill bit well
drilling systems having a drilling housing to which is mounted a
reamer bit. The housing and the reamer bit are rotated by any
suitable rotary power system such as a rotary drill string or a
drilling fluid driven rotary motor, also known as a "mud motor".
Within the drilling housing is mounted a core removal bit mud motor
that has drilling fluid energized driving relation with the core
removal bit and accomplish continuous cutting of the upper end
portion of the remaining formation core. The core removal bit is
preferably composed of a metal bit body structure, typically
composed of steel, to which is adhered a carbide or other
hard-facing material that defines cutter elements and having a PDC
coating to enhance the durability thereof. If desired, the core
removal bit may have a multiplicity of PDC cutter elements affixed
thereto or may have any other drill bit form that is suitable for
cutting away the remaining formation core that is left by the
reamer bit, without departing from the spirit and scope of the
present invention. Generally, the terms "cutting elements" or
"cutting face", as employed in this specification, means a range of
formation cutting devices including PDC cutting elements, carbide
cutting elements, PDC coated carbide or metal bit structure, bits
defining hardened metal cutting teeth, and the like as is deemed
suitable for efficient cutting of the character of formation
material that is being drilled.
[0006] The reamer bit preferably incorporates polycrystalline
diamond (PDC) formation cutting elements that are supported by a
matrix material that is affixed to a reamer bit body but may also
incorporate hardened metal cutting elements or rotary cone cutting
elements, if desired. Even further, the present invention concerns
a dual bit wellbore drilling system having a reamer bit that has no
central cutting elements and therefore leaves a central core of
formation material during drilling. The reamer bit therefore
defines a downwardly facing central opening that is entered by the
central core as the reamer bit progresses into the formation during
drilling activity. The smaller, mud motor driven core removal bit
is either located concentrically or eccentrically with respect to
the reamer bit for efficiently removing the remaining core material
from the top of the core simultaneously with formation cutting by
the reamer bit.
[0007] 2. Description of the Prior Art
[0008] Dual PDC well drilling systems having an external reamer bit
and an interior mud motor driven core removal bit are disclosed by
U.S. Pat. No. 7,562,725 of Edwin J. Broussard, Jr. and Herman J.
Schellstede. A reamer bit is mounted to and rotated by a rotary
drill string that extends from a rotary drilling rig at the
surface. The core removal bit is rotated by a mud motor that is
located within a drilling unit, the mud motor being driven by the
flow of drilling fluid that is pumped through the drill string from
the surface. Another somewhat similar drilling system is disclosed
by U.S. Pat. No. 8,201,642 of Steven J. Radford, et al, wherein a
reamer bit is rotated in one direction by the drill string and a
concentric bit is located within the reamer bit and is rotated in a
counter rotational direction by a downhole motor such as a positive
displacement motor (PDM). It is noted that the smaller centrally
located bit is located entirely within the outer reamer bit, with
its cutting elements engaging the central portion of the formation
within which the wellbore is being drilled. The drill cuttings of
the smaller bit will tend to build up on the cutting interface of
the smaller bit, thus further interfering with its formation
cutting capability. Though these types of drilling systems will
function and achieve wellbore drilling, typically no provision is
made for controlling the delivery of drilling fluid for reamer
drilling, core removal bit drilling, mud motor operation and
bearing cooling for the mud motor and other components of the
drilling system.
[0009] During well drilling with a conventional PDC bit, it is
known that the most central of the PDC cutter members will be
rotated against the formation being drilled at a slower speed as
compared with the PDC cutter members that are located further from
the center portion of the bit. This difference in formation cutting
speed is due to the circumferential distance each of the PDC cutter
members travel during each revolution of drill bit rotation. The
cutter members at the outer periphery of a drill bit travel at a
greater formation cutting speed than the cutters near the center of
the bit. The slower cutting speed of the more centrally located
cutters causes inefficient formation cutting at the central portion
of the borehole being drilled, so that the central portion of the
drill bit cutting face tends to crush, rather than cut the
formation material, and thus retards the overall penetration rate
of the bit. It is considered desirable therefore, to employ the
benefits of PDC cutter members for rotary well drilling without
having the well drilling efficiency hampered by inefficient
formation cutting at the central portion of a drill bit.
[0010] It has been determined that by relieving the central portion
of the cutting face of a drill bit, the formation cutting
efficiency and penetration rate of the bit will be significantly
enhanced. However, such a drill bit will permit a central formation
core to remain. This core must be removed so that it will not
interfere with the drilling process. According to U.S. Pat. No.
7,562,725 of Edwin J. Broussard and Herman J. Schellstede, a dual
PDC drilling system is provided having an outer reamer bit for
cutting away a major part of the formation during drilling and
having an inner core removal bit that is independently rotated,
such as by means of a mud motor or other rotary power system of the
drilling mechanism and which functions to continuously and
completely cut away the remaining central formation core that is
not cut away by the reamer bit. U.S. Pat. No. 8,201,642 discloses a
dual bit well drilling system having a reamer bit and a small
centrally located bit within the reamer bit that is rotated in a
direction that is opposite the rotation of the reamer bit. Another
well drilling system has been developed which employs a rotary PDC
reamer bit for primary drilling and employs a fixed PDC element at
the center of the reamer bit to fracture away or crush the
formation core material that is not cut away by the reamer bit.
[0011] PDC drill bits typically drill an oversize wellbore, and
thus allow for lateral movement of the drill bit within the
formation while drilling. This lateral drill bit movement is
undesirable because it causes the resulting borehole to be oversize
or out of gauge and will often cause the PDC cutters to be sheared
from the bit. Drill bit manufacturers recognize this potential
problem and are known to design the PDC bits to have a somewhat
concave cutting face and rounded towards the outer periphery. This
bit geometry causes wedging of the drill bit into the borehole and
thus minimizes the potential for lateral bit movement during
drilling and also minimizes the development of shearing forces on
the PDC cutter members. However, these concave PDC bit designs
cause the cutter area of the bits to be increased and thus cause
the cost of the resulting bit to also be increased. This increased
drill bit cost is a commercial disadvantage in the well drilling
industry.
[0012] The dual PDC drill bit arrangement of the present invention
achieves more rapid penetration in most hard subsurface formations
because drilling penetration is not resisted by poor drilling
capability of the central portion of the bit and by the presence of
a formation core that develops between the PDC bit blades and
retards penetration movement of the bit. The larger the core
diameter is and longer it is, (to a point) will significantly
stabilize the bit during its drilling rotation and thus minimize
the lateral movement that is typically inherent in causing the
drilling of oversize wellbores by PDC drill bits. The faster the
rate of penetration, the more properly gauged the resulting
wellbore will be and the better the bit will be stabilized during
its rotational operation. With these advantageous features of bit
design incorporated, a flatter PDC bit could be built, having less
surface cutter area, thereby minimizing the number of PDC cutters
that are employed in bit designs and minimizing the application of
torque force to the drill string.
SUMMARY OF THE INVENTION
[0013] It is a principal feature of the present invention to
provide a novel well drilling system that is adapted for threaded
mounting to a bit box of a drill string or mud motor for straight
drilling.
[0014] It is also another feature of the present invention to
provide a novel well drilling system that may incorporate any of a
number of different types of formation cutting elements, such as
polycrystalline diamond cutting elements, hardened metal cutting
elements, rotary cone type rock bits within the spirit and scope of
the present invention.
[0015] It is also a feature of the present invention to provide a
novel well drilling system having a reamer bit that is rotationally
driven by a drill string or by any other rotary drive mechanism and
a core removal bit that is located within a tubular housing of the
well drilling system and is rotated along or near the longitudinal
axis of the reamer bit.
[0016] It is another feature of the present invention to provide a
novel well drilling system having fluid flow control features to
ensure optimum drilling by a reamer bit and a core removal bit and
to further ensure optimum flow of drilling fluid for cooling of mud
motor bearings and for mud motor operation.
[0017] It is an even further feature of the present invention to
provide a novel well drilling mechanism having a PDC reamer bit
that is capable of being rotationally driven by a rotary drill
string or a mud motor that is mounted to a rotatable or non-rotary
drill string and which defines a central bit opening within which
is located a formation core removing rotary bit that is
independently driven in the direction of rotation of the reamer bit
or in the opposite direction of rotation of the reamer bit.
[0018] It is also a feature of the present invention to provide a
novel well drilling mechanism having a core removal mud motor and
core removal bit assembly that is supported in eccentric or
concentric relation within a drill housing by a top mount section
of the tubular drill housing and positions a core removal bit for
mud motor driven rotation within a bit chamber for continuous
cutting of a formation core that remains as reamer bit drilling
occurs.
[0019] Briefly, the various objects and features of the present
invention are realized through the provision of a well drilling
system having a tubular housing that is connected with a drill
string and has core removal bit assembly that is supported within
the housing by a top mount within the upper end portion of the
tubular housing of the well drilling system. The housing of the top
mount well drilling system has an internal mud motor and may be
mounted to the lower end of a drill string extending from the
drilling rig at the surface and only rotates if the drill string is
rotated from above via rotary/kelly or by the top drive of a
drilling rig.
[0020] The rotation speed of the inner core removal bit is
determined according to the characteristics of the different types
of subsurface formations that are encountered. It is expected that
the rate of penetration will increase geometrically since the inner
core of the formation is continuously and completely cut away from
the top down, rather than being chipped or crushed as is typically
the case with conventional PDC bits.
[0021] The well drilling mechanism has a housing to which is
mounted reamer bit having a small mud motor located within the
housing and supported by the top portion of the housing. This small
mud motor is arranged to drive a core removal bit at higher rpm's
than that of the reamer bit. The rate of penetration of the well
drilling system of the present invention, in comparison with
conventional PDC drilling systems, increases geometrically. Because
the present invention has a combination of a PDC reamer bit with a
mud motor driven core removal bit, which has PDC cutters on the
reamer bit, whether the core removal bit be centered or offset from
the center-line of the larger reamer bit, achieves efficient
removal the formation core while drilling more efficiently with the
reamer bit.
[0022] The dual bit drilling mechanism of the present invention has
an outer reamer bit that has been bored or otherwise prepared for
containing a small mud motor having a bearing pack that is provided
for wear resisting rotary support of a drill bit drive shaft. A
core removal bit is threaded to the drive shaft mechanism of the
small mud motor and is positioned within a bit chamber that is
defined within a reamer bit body. When the drilling system is
designed for left hand rotation of the reamer bit, opposite the
typical direction of rotation of the reamer bit by a well drilling
system, the various threaded connections of the mud motor bearing
pack components will have left hand threads to resist the left hand
reactive torque that is received due to cutting engagement of the
core removal bit with the remaining formation core. When the mud
motor imparts left hand rotation to the core removal bit, left hand
reactive torque of the mud motor will be applied to all connections
except the connection of the core removal bit to the bit drive
shaft.
[0023] Only a small amount of power is required to rotate a
relatively small bit, such as 11/4'' core removal bit. Also the mud
motor has a smaller bearing pack with a larger power section
driving the core removal bit to ensure adequate rotational power.
The PDC reamer bit has fluid passages that are nozzled to a
specific size, creating internal bit pressure that forces drilling
fluid through the mud motor power section, rotating the core
removal bit below. This feature allows the bearing pack fluid to
divert to the lower pressure of the well bore annulus, thereby
simultaneously cooling the mud motor bearing pack and the core
removal bit, and flushing away drill cuttings from the core removal
bit. The entire drilling assembly can be threaded into the bit box
of a bottom hole assembly for straight wellbore drilling.
[0024] The dual drill bit mechanism of the present invention has a
combination of a PDC reamer with a mud motor driven core removal
bit, with PDC cutter elements mounted to the reamer bit by means of
cutter retention matrix or by any other suitable means for cutter
retention. Whether the core removal bit be centered or in laterally
offset relation with the larger reamer, the core removal bit cuts
away the formation core more efficiently while drilling. The
optimal offset distance of the core removal bit relative to the
center or axis of reamer bit rotation will be determined by the
well drilling parameters at any point in time.
[0025] The PDC reamer bit has fluid passages that are nozzled to a
specific size, creating predetermined internal bit pressure,
thereby forcing drilling fluid through the mud motor power section,
rotating the core removal bit below. The mud motor is supported
within the tubular housing of the drilling system by a top mount
body or housing section which also serves to isolate the bearing
pack fluid bypass opening from the high pressure chamber that is
within the housing of the drilling system. This feature allows the
flow of bearing pack fluid to be diverted to the lower pressure of
the well bore annulus, thereby simultaneously cooling the mud motor
bearing pack and the core removal bit and serving to flush drill
cuttings from the core removal bit. A hardened internal wear
resisting sleeve is located within the reamer bit to prevent wear
to the reamer bit by the core removal bit. The complete drilling
assembly is adapted to be threaded into the bit box of the drill
string for typical straight hole drilling.
[0026] The PDC cutters near the center of the reamer bit can be
designed to slightly overlap the reamer core area, cutting the edge
of the core and preventing core contact with the reamer bit.
However, it should be borne in mind that the presence of a small
formation core can have a stabilizing effect on the PDC reamer bit,
by serving to ensure against lateral deviation of the reamer bit
from a straight course. Also because of wellbore core removal,
minimal bottom hole assembly weight is required to cause the PDC
cutters to efficiently penetrate into the formation and drill a
straight hole effortlessly. As more weight added to any drill bit,
it will force the drill collars above to flex and lay to one side
of the well bore, causing the drill bit to be cocked on a slight
angle, thereby drilling off in a selected direction. Thus, the
drilling system is capable of directional drilling for correction
of wellbore direction as needed. If drilling continues in the
selected direction, the angle of the drill bit will continually
increase as additional borehole is drilled. There will also be less
heat generated by friction due to efficient cutting of formation
material, rather than having the PDC cutters at the central portion
of a standard PDC bit slide on top of the formation or crush the
formation rather than cutting it, thereby extending PDC drill bit
life dramatically.
[0027] Significant vibration is typically experienced when the
rotor of the mud motor of the core removal bit is spinning within
the stator in response to drilling fluid flow. For this reason,
resilient stabilizers formed of rubber or rubber-like polymer
material are provided within the mud motor to absorb the vibration.
This feature prevents damage to the small PDC coated carbide core
removal bit as it spins within the core removal bit chamber of the
reamer bit. The offset core removal bit will be recessed behind the
PDC cutters of the reamer bit and is positioned for efficient
removal of the formation core that remains as the reamer bit
penetrates into the formation. The optimal recessed distance of the
core removal bit is determined by the parameters of the formation
being drilled; however, it should be borne in mind that the
formation core also serves to stabilize rotation of the reamer bit.
With the core removal bit centered within the reamer bit, it can be
recessed behind the PDC cutting members on the blades of the reamer
bit and protrude out of the reamer bit, provided the core removal
bit outer diameter overlaps the PDC cutters in the center of the
reamer bit.
[0028] Though the mud motor powered rotary drilling system or head
may incorporate a variety of formation cutting or eroding elements,
such as polycrystalline diamond (PDC) cutting elements and hardened
metal rock cutting or chipping elements, steel, carbide or other
metal cutting members, which may include hard-facing material or
PDC or other hard coatings, for purposes of simplicity the
invention is discussed herein as it concerns formation boring by
using PDC cutting elements particularly for the reamer bit. The
drilling mechanism has a tubular housing that is connected with a
mounting sub that is connected with a drill string extending from a
drilling rig the surface. The lower end portion of the tubular
housing is provided with a vibration isolation member to dampen any
vibration forces that are encountered. A reamer bit is connected
with the lower end of the tubular housing below a stabilizer that
ensures centering of the drilling system within the wellbore being
drilled.
[0029] A mud motor is located within the tubular housing of the
well drilling system and includes a rotor having an axis of
rotation that can be concentric or eccentric with respect to the
longitudinal rotational axis of the tubular housing and reamer. The
drilling fluid inlet of the mud motor is in communication with a
high pressure fluid chamber that is defined within the tubular
housing. An interchangeable orifice flow control nozzle is present
within the partition for control of drilling fluid flow past the
mud motor for cooling and cleaning of the reamer bit and for
cooling and lubricating the bearing pack of the mud motor.
[0030] The bottom hole drilling mechanism incorporates an external
reamer bit having a central portion with no cutting elements, thus
defining a downwardly facing central opening that is entered by a
central formation core as formation drilling progresses. The
formation core that remains as the reamer bit is operated is cut
away from top to bottom by a mud motor driven core removal bit that
is located for mud motor powered rotary movement within a core bit
chamber within the reamer bit. Preferably, the core removal bit is
a carbide bit having core cutting edges or teeth and being formed
of carbide material that is preferably coated with PDC material.
Alternatively, the core removal bit may have a cutting face that is
defined by a multiplicity of PDC cutting elements that are secured
to the bit structure by a cutter retaining matrix material. The
core removal bit may have other forms and may be composed of a
variety of formation cutting elements or teeth; however each of its
various forms and materials permits the core removal bit to cut
away the remaining formation core from the top down as penetration
of the reamer bit progresses into the formation.
[0031] The core removal bit mud motor is mounted within the reamer
bit head typically by being threaded into a threaded receptacle of
a top mount sub that is provided within the upper end of a drilling
housing. The core removal bit is provided with formation cutting
elements and is rotated at a different, typically higher rate of
rotation as compared with the rate of rotation of the reamer bit.
However, if the core removal bit has the same rotary speed as the
reamer bit, the rotary speed of the core removal bit will be added
to the rotary speed of the reamer bit, causing the core removal bit
to rotate at a faster rotary speed than the reamer bit. The reamer
and core removal bits work in concert to facilitate a greater
overall formation penetration rate as compared with conventional
PDC drill bits.
[0032] The fluid flow that operates the mud motor is also employed
for cooling and cleaning of the core removal bit. The core removal
bit has a plurality of drilling fluid passages that permit the flow
of drilling fluid for cleaning of the cutting elements of the core
removal bit and for cooling and lubricating the bearing pack of the
core removal bit to promote extended service life thereof. Drilling
fluid flow through the reamer passages is selectively adjustable by
means of replaceable flow control nozzles that are sized according
to well drilling parameters, such as well depth, formation
character and hardness, fluid pressure at the drill bits, and the
like.
[0033] When the core removal or inner bit is rotated about an axis
of rotation that is offset from the rotational axis of the reamer
bit, the core removing cutting edges of the core removal bit are
not centered on the top of the formation core, but rather cut
across the top surface of the core to cut it away from the top
down. Regardless how big or what the offset of the core removal bit
is, the recessed core removal bit will always remove the remaining
formation core that is not cut away by the PDC cutter elements of
the reamer bit. As the formation core is continuously cut away by
the core removal bit, it does not restrict the efficiency of
formation penetration by the PDC cutters of the reamer bit.
BRIEF DESCRIPTION OF THE DRAWINGS
[0034] So that the manner in which the above recited features,
advantages and objects of the present invention are attained and
can be understood in detail, a more particular description of the
invention, briefly summarized above, may be had by reference to the
preferred embodiment thereof which is illustrated in the appended
drawings, which drawings are incorporated as a part hereof.
[0035] It is to be noted however, that the appended drawings
illustrate only a typical embodiment of this invention and are
therefore not to be considered limiting of its scope, for the
invention may admit to other equally effective embodiments.
[0036] In the Drawings:
[0037] FIG. 1 is a schematic illustration showing a well drilling
rig that is located at the surface of the Earth's surface and
extends a drill string or stem into a wellbore that is being
drilled and shows a well drilling system embodying the principles
of the present invention being connected with the drill string;
[0038] FIG. 2 is a longitudinal sectional view of an upper portion
of a duel bit well drilling mechanism embodying the principles of
the present invention and showing top mounting of an eccentrically
arranged drilling fluid energized rotary motor for operation an
core removing drill bit of a dual bit drilling system and showing
mounting of the drilling system to a drill string;
[0039] FIG. 3 is a longitudinal sectional view similar to that of
FIG. 2 showing an intermediate section of the well drilling system
of FIG. 2;
[0040] FIG. 4 is a longitudinal sectional view similar to that of
FIGS. 2 and 3 showing a bearing pack section of the well drilling
system of FIGS. 2-4;
[0041] FIG. 5 is a longitudinal sectional view showing a dual bit
well drilling mechanism having an exterior reamer bit and having an
eccentrically arranged internal core removal bit being rotatably
driven by the drilling fluid energized rotary motor;
[0042] FIG. 6 is a bottom view of the dual bit well drilling
mechanism showing right hand rotation of the exterior reamer bit
and left hand rotation of the internal laterally offset core
removal bit;
[0043] FIG. 7 is a longitudinal sectional view showing a laterally
offset core removal bit having an external reamer bit that is
rotated to the right during drilling and an internal core removal
bit that also rotated to the right by its drilling fluid energized
rotary motor;
[0044] FIG. 8 is a bottom view showing the dual bit mechanism of
FIG. 7 and illustrating the overlapping relation of inner portions
of the PDC cutter supporting blades of the reamer bit with the
cutting face of the internal core removal bit;
[0045] FIG. 9 is a longitudinal sectional view, similar to FIG. 2,
showing the upper section of a well drilling housing having an
eccentrically arranged drilling fluid energized rotary motor for
rotary actuation of an eccentric or laterally offset core removal
bit;
[0046] FIG. 10 is a longitudinal sectional view, similar to FIG. 9
showing flow control nozzles being arranged for controlling the
flow of drilling fluid through an external annulus, and for
controlling the flow of drilling fluid through the drilling fluid
energized rotary motor;
[0047] FIG. 11 is a longitudinal sectional view of a dual bit well
drilling system having a concentrically arranged drilling fluid
energized rotary motor with drilling fluid flow control by flow
passage dimensions;
[0048] FIG. 12 is a longitudinal sectional view showing the
concentrically arranged drilling fluid energized rotary motor of
FIG. 11 and showing flow control nozzle being mounted for
controlling the flow of drilling fluid through the drilling fluid
energized rotary motor of the dual bit drilling system of the
present invention;
[0049] FIG. 13 is a longitudinal sectional view showing a bearing
pack section of the dual bit drilling system of FIG. 12;
[0050] FIG. 14 is a longitudinal sectional view of the lower
section of the dual bit drilling system of FIGS. 11-13 showing the
concentric dual bit mechanism, with the reamer bit arranged for
right hand rotation and the internal core removal bit also arranged
for right hand rotation;
[0051] FIG. 15 is a bottom view of the concentric dual bit
mechanism of FIG. 14 showing an overlapping relation of the inner
portions of the PDC cutter supporting blades of the reamer bit with
the cutting face of the internal core removal bit;
[0052] FIG. 16 is a longitudinal sectional view showing the
concentrically arranged dual bit drilling mechanism with the
external reamer bit arranged for right hand rotation during
drilling and the internal core removal bit being arranged for left
hand rotation;
[0053] FIG. 17 is a bottom view showing the concentric dual bit
well drilling system of FIG. 16 and further showing an overlapping
relation of the inner portions of the PDC cutter supporting blades
of the reamer bit with the cutting face of the internal core
removal bit;
[0054] FIG. 18 is a longitudinal sectional view showing the upper
portion of a concentrically arranged drilling fluid energized
rotary motor for a concentric dual bit well drilling mechanism and
showing a spline arrangement maintaining a non-rotatable relation
of the motor mechanism within the tubular housing of the well
drilling system;
[0055] FIG. 19 is a longitudinal sectional view showing an upper
portion of a concentrically arranged drilling fluid energized
rotary motor also showing a spline arrangement maintaining a
non-rotatable relation of the motor mechanism within the tubular
housing of the well drilling system;
[0056] FIG. 20 is a section view taken along line 20-20 of FIG.
19;
[0057] FIG. 21 is a longitudinal sectional view showing the dual
bit well drilling system of the present invention with the mud
motor and core removal bit of the dual bit well drilling mechanism
being concentrically arranged and having gauge control elements
being mounted to ensure formation core controlled stability of the
reamer bit against undesired lateral deviation from its intended
course during drilling activity;
[0058] FIG. 22 is a longitudinal sectional view showing the dual
bit well drilling system of the present invention and showing an
eccentrically arranged drilling fluid actuated rotary motor and an
eccentric core removal bit positioned within a gauge lined central
core receptacle of the reamer bit;
[0059] FIG. 23 is a transverse section view taken along line 23-23
of FIG. 22 and showing flow control nozzles;
DETAILED DESCRIPTION OF PREFERRED EMBODIMENT
[0060] While the well drilling system is discussed herein
particularly as it concerns PDC drill bits, it is not intended to
limit the spirit and scope of the present invention to such, since
this invention is adaptable to a variety of drilling systems,
including systems for effectively drilling materials other than
earth formations. Referring now to the drawings and first to the
schematic illustration of FIG. 1, a well drilling rig 10 is shown
that is located at the surface "S" of the Earth. The well drilling
rig has a rotary turntable 12, rotary top drive or other rotary
drive mechanism for rotating a kelly 14 to which is connected a
drill string 16 that is composed of multiple sections of drill
pipe, also known as drill stem. The drill string 16 extends from
the drilling rig into a wellbore 18 that is being drilled through
various earth formations 20 to one or more production zones that
may contain crude oil, natural gas, distillate and other petroleum
products. The drill stem or pipe 16 of the drill string is tubular
and defines a central flow passage 22 through which drilling fluid,
also called drilling mud, is pumped for the purpose of cooling and
lubricating the drilling mechanism and flushing away drill cuttings
and other debris that is loosened from the formation during
drilling. When drilling a straight wellbore, the rotary drive
mechanism of a drilling rig continually rotates the drill string
and drilling fluid is continuously pumped through the drill pipe
while the weight of the drill string is applied to the drill bit to
drill straight ahead. When the well drilling system is being used
to drill a directional wellbore, as drilling fluid is through the
drill pipe and with the drill string stationary, a bent housing mud
motor is rotationally oriented to the desired direction for
wellbore deviation or correction. The well driller will then slide
the drill string ahead to correct the course of the wellbore or to
change the wellbore direction. After sliding the drill string a
desired distance to achieve the well correction or change that is
desired, the driller will then begin to rotate the drill string and
once again and drill straight ahead.
[0061] A well drilling mechanism 26 is connected with the bit box
of the mud motor powered drilling mechanism 24, will be
hydraulically powered by pressurized drilling fluid that is pumped
through the drill stem to the drill bit or bits 28 of the well
drilling mechanism 26. Every mud motor has two sets of threads,
internal threads and external threads. With a standard mud motor,
the internal and external threads constitute right hand threads
because the mud motor is supported at its upper end by the drill
string. The left hand reactive torque that occurs during drilling
tends to tighten all of the right hand threads of the outer body of
the mud motor. All internal threads of the motor constitute right
hand threads because the motor rotor drives the drill bit to the
right and thus has the effect of tightening all of the threads
beneath it. The opposite effect occurs during the practice of the
present invention, when the mud motor is arranged to rotate a core
removal bit to the left. The mud motor for driving the core removal
bit of the present invention is supported at its upper end by a top
mount that is located within a tubular drilling body that is in
turn supported by a rotary drill string.
[0062] As shown in FIG. 2-5, at the lower or distal end of the
drill string 16 is mounted a dual bit well drilling mechanism shown
generally at 30, which is typically rotated by a drill string, but
can be rotated by a mud motor if desired. The dual bit well
drilling mechanism 30 is employed to achieve rotation of a reamer
bit, shown generally at 32, and a core removal bit, shown generally
at 34, both being shown in FIG. 5. The dual bit well drilling
mechanism 30 comprises a tubular housing, shown generally at 36 in
FIG. 2, which is comprised of a mounting sub 38 which defines an
upwardly projecting externally threaded connection 40 that is
received by the internally threaded receptacle 42 of a bit box
connector 44. The tubular housing 36 of the drilling fluid
energized rotary motor or "mud motor" further includes an upper
housing section 46 having an upper internally threaded connection
48 having threaded assembly with an upper externally threaded
connection 50. The upper housing section 46 also functions as an
outer reamer drive member and has threaded connection at 49 with a
lower housing section 51 which is threadedly connected at 47 with a
reamer bit body 52. The lower housing section 51 is typically
provided with a plurality of external elongate radially spaced
centralizer members 53 that centralize the drilling mechanism
within a wellbore being drilled. Spaces between the centralizer
members define flow passages within the wellbore and externally of
the tubular housing for the return flow of drilling fluid and drill
cuttings after the drilling fluid has been discharged from the
drill bit mechanism of the well drilling system.
[0063] The reamer bit body 52 is typically composed of a durable
metal composition, such as steel, and defines an external surface
54, as shown in FIG. 6, to which a cutter retention matrix 56 is
affixed by bonding, welding or by any other suitable means for
attachment. As is evident from the bottom view of FIGS. 5 and 6,
the cutter retention matrix 56 is formed to define a plurality of
outwardly radiating vanes or blades 58, having leading edge
portions 60 that define a multiplicity of cutter receptacles 62
each having a PDC cutter element 64 secured immovably therein.
Thus, a plurality of substantially radially oriented arrays of PDC
cutter elements 64 are arranged to present cutting edges that
engage and cut away a small portion of the formation/reamer bit
interface during each rotational revolution of the reamer bit.
Collectively, the radiating arrays of PDC cutter elements 64
continuously cut away the major portion of the formation material
within which the wellbore is being drilled. Gauge or wear pad
members 66, which may be defined by PDC members or by any other
hard and wear resistant material, are retained by the cutter
retention matrix material 56 and serve to minimize the potential
for wear of the cutter retention matrix material as the outer wall
of the reamer bit is rotated in contact with the abrasive wall
surface of the wellbore.
[0064] When drilling with conventional PDC drill bits the
centermost PDC cutter elements tend to crush the central portion of
the formation material within the borehole, rather than cut it
away, due to the inefficient cutting characteristics of the PDC
cutters at the central region of the bit. Even when a PDC bit is
provided with a small concentric bit, such as taught by U.S. Pat.
No. 8,201,642, for drilling a central portion of a borehole, the
center portion of the small concentric bit also tends to crush,
rather than cut away the central formation material due to the
inefficient formation cutting characteristics of the centrally
located formation cutting elements of the small concentric bit.
However, as is evident from FIGS. 5-8 of the drawings, the reamer
body 52 and the inner portions of the cutter support blades 58
define a downwardly facing central opening 68 which, since the
reamer bit has no central cutter elements to retard drill bit
penetration, maximizes formation cutting efficiency of the reamer
bit. The open central portion of the reamer bit presents virtually
no resistance to bit penetration as is typically experienced by
conventional PDC drill bits having formation cutter elements at the
central portions thereof. However, during drilling activity a
central portion of formation material is not cut away and thus
defines a formation core 69 that enters the central opening 68 as
the reamer bit cuts away the formation material. The core removal
bit 34 is positioned to efficiently cut away this central formation
core as the reamer bit continues to cut away the formation
material.
[0065] The downwardly facing central opening 68 is collectively
defined by inner surface sections 71 of the cutter support blade
members 58 as shown in FIG. 6. A cylindrical wall surface 76 is
defined within the reamer bit body 52 and partially within the
matrix material 56 and is eccentric with respect to the center-line
C/L.sup.1 of the reamer bit body, such that its center-line
C/L.sup.2 is laterally offset with respect to center-line
C/L.sup.1. The cylindrical wall surface 76 defines a bit chamber 77
within which the core removal bit 34 is positioned for core cutting
rotation. It should be borne in mind, however, that the core
removal bit 34 can be either eccentrically located or
concentrically located with respect to the center-line C/L.sup.1 of
the tubular housing 36.
[0066] As shown in FIGS. 2-10, the core removal bit 34 is
positioned within a core bit chamber 77 for rotation about the
center-line C/L.sup.2 and has a core cutting face 70 that is
recessed inwardly of the central opening 68 for cutting engagement
with the upper end of the formation core, that is shown in broken
lines at 72 in FIG. 5, and remains as the reamer bit progresses
into the formation during drilling. The outer, generally
cylindrical surface of the core removal bit 34 is spaced from the
internal cylindrical wall 76 so as to define an annular clearance
75 through which drilling fluid is permitted to flow for cooling
and cleaning the core removal bit. The core cutting face 70 of the
core removal bit 34 is provided with a plurality of cutting
elements 73 that serve to continuously and completely cut away the
remaining formation core that is not cut away by the cutting
elements 64 of the reamer bit 32. Preferably, however, the core
removal bit 34 and its formation cutting elements are composed of a
hardened and durable metal composition such as tungsten carbide
that may be coated with PDC material to enhance the durability of
the cutting face. It should be noted that the reamer bit 32 is
typically rotated by a rotating drill string or may be rotated by a
drilling fluid energized mud motor that is connected with a drill
string. However, the core removal bit 34 is independently rotated
by a drilling fluid energized rotary motor or mud motor shown
generally at 74 which is located within the tubular housing 36 of
the well drilling mechanism 30. The generally cylindrical bore or
wall 76 is formed eccentrically with respect to the center-line of
the tubular housing 36 and defines a bit chamber 77 within which
the core removal bit 34 is independently rotated by the mud motor
at a predetermined rotational speed and rotational direction
[0067] For reamer bit stabilization, to minimize lateral movement
of the reamer bit, the matrix material 56 and its PDC cutter
supporting blades 58 collectively define a downwardly facing
centrally located opening or core receiving receptacle or chamber
68. A bearing support sleeve member 80 is seated within the bore 76
and is sealed to the body 52 of the reamer bit by a plurality of
annular seal members 81 that are contained with external seal
recesses of the bearing support sleeve member 80. The bearing
support sleeve member 80 also serves as an internal wear resisting
liner to protect the core removal bit 34 against excessive wear
during drilling operations. A bearing set 82 having inner and outer
bearing members is located between the bearing support sleeve
member 80 and a drive shaft 86 to which the core removal bit 34 has
rotary driving connection, thus providing for rotary stabilization
of the core removal bit during its rotation.
[0068] It should be noted that the mud motor 74 is supported within
the tubular housing 36 of the well drilling system 30 by means of a
top mount so that the mud motor and core removing bit as well as
the bearing pack of the mud motor are supported by the upper end
portion of the tubular housing. As shown in FIGS. 2 and 9, a
top-mount body 83 having a drilling fluid flow passage 84 therein
is positioned within the tubular body and has a splined connection
85 that permits linear adjustment of the top mount body within the
housing section 46 and prevents rotation of the top mount body
relative to the housing section. The flow passage 84 is
eccentrically located within the top mount body 83 in that it is
defined about the laterally offset center-line C/L.sup.2. An
externally threaded retainer and adjustment member 87 is received
by an internal threaded section 88 of the tubular housing section
46 and defines spanner recesses 89 by which the retainer and
adjustment member 87 is rotated by a spanner tool for adjusting the
position of the top mount body 83 within the tubular housing and
securing the top mount body against upward movement within the
tubular body. A flow diverting passage 90 within the top mount body
83 communicates the drilling fluid flow from a high pressure
chamber 96 into fluid flow passage 84 with an annulus or annular
reamer bit supply chamber 91 between the tubular housing 36 and the
top mount body 83 to provide for drilling fluid flow within the
flow passage 84 of the top mount body and the annulus 91. The top
mount body 83 defines an externally threaded connector 92 at the
lower end thereof which establishes threaded engagement within an
internally threaded connector 93 of a mud motor top sub 94. The top
sub 94 has threaded connection with the upper internally threaded
connector of a tubular housing 95 of the mud motor 74. Fluid flow
through the flow passage 84 and into a motor operation chamber 97
is controlled by a replaceable flow control nozzle 98 to provide
for controlled operating speed and power of the mud motor 74.
[0069] The top mount mud motor and dual bit drilling system of FIG.
10 differs from that of FIG. 9 in that the top mount body 83
defines a flow passage 126 that is in communication with the high
pressure chamber 96 under the control of a replaceable flow control
nozzle 127 so that fluid pressure within the annulus 91 and the
motor operation chamber 97 is controlled by the respective flow
control nozzles 127 and 98 according to the fluid pressure design
of the mud motor and the reamer bit.
[0070] Within the mud motor 74 is provided a stator member 99 which
is of tubular form and is composed of rubber or a rubber like
polymer material and defines a generally helical internal profile
100. An elongate rotor member 101, also having an external geometry
that is composed of rubber or a rubber like polymer material,
defines a generally helical external profile 102 that cooperates
with the internal profile 100 of the stator member 99 so that the
flowing drilling fluid passes along the length of the stator and
rotor members and causes rotation of the rotor member. The rotor
member 101 is provided with a structural core that extends along
its length and provides stability and structural integrity for the
rotor member. A mud motor positioning and stabilizing member 103 is
located in close fitting relation within the tubular housing 36 and
defines an opening 104 within which the mud motor housing 95 is
received. As the rotor member 101 is rotated within the stator
member considerable vibration forces are developed. The mud motor
positioning and stabilizing member 103 is composed of a resilient
material and functions to minimize transfer of the rotor vibration
forces to the mud motor housing and to the tubular housing 36. The
lower end of the rotor member 101 defines a non-circular drive
member 105 that is engaged within a non-circular receptacle 106 of
a rotor driven shaft member 107, which is preferably a flex shaft
composed of flexible and durable material, such as beryllium
copper, to minimize shock forces that are transmitted by the rotor
of the mud motor to the drive shaft and core removal bit of the
drilling system.
[0071] As shown in FIG. 4, the rotor driven shaft 107 has a lower
end defining cross-over ports 108 and a flow passage 109 and has
threaded connection at 110 with the upper end portion 111 of the
tubular drive shaft 86 of the core removal bit 34. The drive shaft
86 defines a central flow passage 112 that is in communication with
the flow passage 109 and conducts drilling fluid flow to the core
removal bit 34 for cooling the bit and for flushing away drill
cuttings that occur at the cutting face 70. A bearing pack, shown
generally at 113 in FIG. 4 includes sets of radial bearings 114 and
thrust bearings 115. Drilling fluid being discharged from the
stator and rotor during operation of the mud motor enters an
annular flow passage 116, as shown at the lower portion of FIG. 3
and flows downwardly for cooling and lubrication of the bearing
pack and for cooling and flushing drill cuttings from the core
removal bit 34. An annular fluid flow clearance or passage 117
exists through the bearing pack 113, thereby permitting drilling
fluid flow through the bearing pack for cleaning and cooling the
bearings and materially enhancing the service life of the core
removal bit mud motor and its bearing members. The drilling fluid
is discharged from the clearance or flow passage 117 of the bearing
pack into the chamber 77 within which the core removal bit 34 is
located and then flows through the clearance 75 between the
exterior surface of the core removal bit 34 and the surface 76 of
the bit chamber within which the core removal bit is also
positioned for core cutting rotation.
[0072] As the reamer bit 32 of FIG. 5 is rotated by the drill
string and weight is applied a circular region of the subsurface
formation is cut away, thereby leaving a formation core 72 that
enters the downwardly facing opening 68. As drilling continues the
upper end portion of the formation core is contacted by the cutting
face 70 of the core removal bit so that continued penetration of
the dual bit mechanism causes the core removal bit 34 to
continuously cut away the formation core from top to bottom. This
activity causes the formation core 72 to have a generally
cylindrical external surface that is in close fitting relation with
the inner surface segments 71 of the cutter supporting blade
members of the reamer bit. A benefit of this close fitting
relationship is that the formation core functions as a
stabilization gauge to stabilize controlled rotation of the reamer
bit and maintains controlled tracking of the course of the wellbore
that is being drilled. The formation core thus prevents the reamer
bit from wandering or being forced off course during the drilling
process. To maintain the close fitting relationship of the
formation core and the inner surface segments 71, gauge protector
members 118 are inset within the matrix material of the cutter
support blades and function to ensure against accelerated wear or
erosion of the cylindrical surface of the formation core.
Controlled tracking of the dual bit drilling system is also
enhanced by the rapid drill bit penetration that occurs due to the
absence of any formation crushing activity at the centermost region
of the wellbore being drilled. The drive shaft 86 defines an
externally threaded lower extremity 119 that is received in
threaded engagement within an internally threaded receptacle 120 of
the bit body 121 of the core removal bit 34.
[0073] When the reamer bit is rotated to the right by the drill
string and the core removal bit 34 is rotated to the left by its
mud motor, as in FIGS. 5, 6, 16 and 17, the threads of the mud
motor components will be left hand threads to ensure against
unthreading of the mud motor components by the reactive torque that
is developed as the core removal bit cuts away the formation core.
When both the reamer bit and the core removal bit are driven to the
right, the thread connections throughout the mud motor and drive
shaft will be right hand threads since thread disengagement will
not occur. However, in this case the core removal bit should be
rotated at a greater rotational speed than the rotational speed of
the reamer bit, so that the cutting speed of the core removal bit
will be proper for the core cutting capability that is needed.
[0074] Drilling fluid distribution passages 122 are defined within
the bit body 121 of the core removal bit 34 and serve to conduct
fluid flow from the flow passage 112 of the drive shaft 86 to the
cutting face of the core removal bit. Replaceable flow control
nozzles 123 are located at the outlet openings of the drilling
fluid distribution passages 122 and ensure proper drilling fluid
flow to the cutting face of the core removal bit. Drilling fluid
within the annulus 91 is permitted to flow through fluid
distribution passages 124 within the body 52 of the reamer bit and
to exit between the cutter supporting blades 58 under the control
of replaceable flow control nozzles 125.
[0075] The tubular housing of the mud motor 74 is defined in part
by a bearing housing section 126 that encapsulates the bearings 114
and 115 and defined an internal annular flange 127 that defines
shoulders for bearing support and positioning. A drive shaft
enlargement 128 also defines a bearing support and positioning
shoulder for the thrust bearings 115. The lower portion of the
tubular housing of the mud motor 74 is defined by a housing sub 130
that has threaded connection with the bearing housing section 126
at 132. A downwardly facing generally planar annular surface 134 of
the housing sub is seated for positioning and stability on a
corresponding upwardly facing annular surface 135 that is defined
within the reamer bit body 52. The drive shaft 86 of the core
removal bit 34 extends through a central passage 136 of the housing
sub 130 with sufficient annular clearance that drilling fluid flows
through the clearance and through the bearing set 84 to the bit
chamber 77.
[0076] With reference to FIGS. 11-21, there is disclosed a
concentric dual bit well drilling mechanism is disclosed wherein a
reamer bit and a core removal bit rotate about a common
longitudinal center-line C/L.sup.1. As shown in FIGS. 11-14,
wherein like reference numerals identify like parts, the dual bit
drilling system 30 has a tubular housing 36 that defines a
longitudinal center-line C/L.sup.1 about which the center of the
flow passage 22 is concentric. A connecting sub 38 of the housing
36 is also concentric with the longitudinal center-line C/L.sup.1
and the centers of the intermediate housing section 46 and the
reamer bit body 52 are also concentric with the longitudinal
center-line C/L.sup.1. Like components are identified by like
reference numerals.
[0077] FIGS. 19 and 20, in addition to showing most of the features
of FIG. 18, illustrate a top mount body 130 that is received within
the tubular housing section 46 of the housing 36 and has an
internally splined section 131 similar to the splined section 85 of
FIG. 18. The top mount body 130 has external splines 132 that fit
within the internal splined section 85 and thus permit linear
movement of the top mount body within the tubular housing section
46 while ensuring that the top mount body is not rotatable within
the housing section. The top mount body is linearly adjustable
within the housing section 46 by means of an externally threaded
adjustment member 87 that is threaded within the housing by a
thread connection 88. This threaded adjustment permits the mud
motor mechanism, its drive shafts and the core removal bit to be
adjustable within the tubular housing. The threaded adjustment
member 87 is rotated for linear adjustment by the use of a tool
such as a spanner device. The entire mud motor mechanism, including
the mud motor housing 95, its bearing pack, drive shaft and the
core removal bit are inserted into the mud motor housing as a unit.
The adjustment member 87 is then installed and adjusted to ensure
against longitudinal movement of the mud motor within the housing
36 of the dual bit drilling system.
[0078] As shown in FIG. 19, the top mount body 130 defines a
plurality of flow passages, two of which are shown at 133 and 134,
which permit the flow of drilling fluid from the high pressure
chamber 96 into the annulus or annular drilling fluid supply
chamber 91 that supplies the reamer bit. Replaceable flow control
nozzles 135 and 136, which are threaded into the inlets of the
reamer bit flow passages, are seated within an upwardly facing
recess 137 of the top mount body and control the flow of drilling
fluid within the passages 133 and 134. These flow control nozzles
can be changed out as well conditions dictate. For control of the
supply of drilling fluid to the mud motor and core removal bit an
elongate support shaft 138 extends downwardly from the central
portion of the top mount body 130 and defines a central flow
passage 139 through which drilling fluid flows from the high
pressure chamber 96. A replaceable flow control nozzle 140 is
threaded into the externally threaded lower end portion of the
support shaft 138 and can be changed out as well conditions
dictate. The mud motor top sub 94 is threaded onto the lower end
portion of the support shaft 138 by a thread connection 141.
[0079] During borehole drilling with the reamer bit 32, the core
removal bit 34 of FIGS. 5-8, being eccentrically located with
respect to the center of the reamer bit, will have an orbital
motion as well as being rotated independently of the rotary motion
of the reamer bit. This orbital motion causes the PDC cutter
members of the core removal bit to sweep across the central region
of the borehole, thereby continuously cutting away the small core
that remains as the formation is cut away by the reamer bit. The
core removal bit 34 is rotated by the core removal bit mud motor
74, which requires very little power for its operation, because of
its small size in comparison with the size of the reamer bit. The
core removal bit is driven at a significantly greater rotary speed
which causes its PDC cutter members to move at an optimum speed
relative to the formation for efficiently cutting away the core
region of the formation, without developing elevated heat.
Moreover, the core removal bit is efficiently cooled during its
operation by the volume of drilling fluid that is discharged at its
cutting face from the fluid control nozzles of the core removal bit
and from the clearance between the core removal bit and the central
opening of the reamer bit.
[0080] Referring now to FIGS. 11-14 a dual bit well drilling
mechanism is shown generally at 30 which differs from the dual bit
well drilling mechanism 30 of FIGS. 2-6 principally in the
concentric arrangement of the core removal bit 34 with respect to
the reamer bit 32. In this case, the central opening 68 of the
reamer bit is concentric with respect to the center-line C/L.sup.1
of the reamer bit and with virtually all of the tubular components
of the tubular housing and core removal bit mud motor. Though the
core removal bit is rotated by its mud motor 74 in the same manner
as discussed above in connection with FIGS. 2-6, it will not have
oscillating motion during rotation of the reamer bit since its
rotation is concentric with the reamer bit. To continuously cut
away the central core that remains due to rotary cutting of the
borehole by the reamer bit, the core removal bit will simply be
rotated by the core removal bit mud motor 74 and will rely totally
on the arrangement and cutting capability of the cutting face 70
thereof.
[0081] According to the bottom view of FIG. 15 the top mount duel
bit well drilling mechanism 30, the reamer bit 32 is shown by a
directional arrow to have right hand formation cutting or drilling
rotation and the concentric core removal bit 34 to have right hand
cutting or drilling rotation as well Like components of the dual
bit mechanism are indicated by like reference numerals. The cutting
face 70 of the core removal bit may have any suitable configuration
and may incorporate a wide range of suitable formation cutting
materials without departing from the spirit and scope of the
present invention. The core removal bit is shown in Figure and
other Figures of the Drawings to have arrays of PDC cutter elements
that extend to its center, but it should be borne in mind that the
cutting face 70 of the core removal bit may be defined by other
formation cutting materials and other drill bit designs. For
example, a hard and durable material such as tungsten carbide that
is fixed to a metal drill bit body and may have a coating of PDC
material affixed thereto is effectively serviceable for use as the
core removal bit. Typically, the tungsten carbide or any other
suitable hard and durable material is applied as a hard-facing to a
bit body that is composed of a durable metal such as steel. The
hard-facing material typically defines formation cutting teeth for
continuously cutting away the formation core from top to bottom as
drilling operations continue.
[0082] The longitudinal section view of FIG. 16 shows a concentric
dual bit mechanism having a reamer bit that is rotated to the right
for drilling activity and a core removal bit that is concentric
within the reamer bit and is rotated to the left during drilling
and a core removable bit that is rotated to the left. FIG. 17 is a
bottom view of the dual bit mechanism of FIG. 16. The longitudinal
section views of FIGS. 18 and 19 and the transverse section view of
FIG. 20 also show the concentric version of the dual bit well
drilling system of the present invention and differ only in the
particular design of the top mount mechanism.
[0083] FIG. 21 is a longitudinal section view showing the
concentric dual bit drilling system of the present invention in its
entirety, while FIG. 22 shows the eccentric version of the dual bit
drilling system of the invention. The transverse section view of
FIG. 23 is taken along line 23-23 of FIG. 22 and shows the
laterally offset center-line C/L.sup.2 of the embodiment of FIG.
22.
[0084] In view of the foregoing it is evident that the present
invention is one well adapted to attain all of the objects and
features hereinabove set forth, together with other objects and
features which are inherent in the apparatus disclosed herein.
[0085] As will be readily apparent to those skilled in the art, the
present invention may easily be produced in other specific forms
without departing from its spirit or essential characteristics. The
present embodiment is, therefore, to be considered as merely
illustrative and not restrictive, the scope of the invention being
indicated by the claims rather than the foregoing description, and
all changes which come within the meaning and range of equivalence
of the claims are therefore intended to be embraced therein.
* * * * *