U.S. patent application number 10/638941 was filed with the patent office on 2004-11-11 for method and apparatus for monitoring and recording of the operating condition of a downhole drill bit during drilling operations.
This patent application is currently assigned to Baker Hughes Incorporated. Invention is credited to Lin, Chih, Nguyen, Don Quy, Schmidt, Scott Ray, Sullivan, Eric Charles, Zadrapa, Glenn R., Zaleski, Theodore Edward JR..
Application Number | 20040222018 10/638941 |
Document ID | / |
Family ID | 27486232 |
Filed Date | 2004-11-11 |
United States Patent
Application |
20040222018 |
Kind Code |
A1 |
Sullivan, Eric Charles ; et
al. |
November 11, 2004 |
Method and apparatus for monitoring and recording of the operating
condition of a downhole drill bit during drilling operations
Abstract
A drill bit for use in drilling operations in a wellbore, the
drill bit having a bit body including a plurality of bit legs, each
supporting a rolling cone cutter; a coupling member formed at an
upper portion of said bit body; at least one temperature sensor for
monitoring at least one temperature condition of said improved
drill bit during drilling operations; and at least one temperature
sensor cavity formed in said bit body and adapted for receiving,
carrying, and locating said at least one temperature sensor in a
particular position relative to said bit body which is empirically
determined to optimize temperature sensor discrimination.
Inventors: |
Sullivan, Eric Charles;
(Houston, TX) ; Zaleski, Theodore Edward JR.;
(Houston, TX) ; Schmidt, Scott Ray; (The
Woodlands, TX) ; Nguyen, Don Quy; (Houston, TX)
; Zadrapa, Glenn R.; (Highlands, TX) ; Lin,
Chih; (Spring, TX) |
Correspondence
Address: |
Melvin A. Hunn, Esq.
HILL & HUNN LLP
Suite 1440
201 Main Street
Fort Worth
TX
76102
US
|
Assignee: |
Baker Hughes Incorporated
|
Family ID: |
27486232 |
Appl. No.: |
10/638941 |
Filed: |
August 11, 2003 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10638941 |
Aug 11, 2003 |
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09777569 |
Feb 6, 2001 |
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6626251 |
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09777569 |
Feb 6, 2001 |
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09012803 |
Jan 23, 1998 |
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6230822 |
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09012803 |
Jan 23, 1998 |
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08760122 |
Dec 3, 1996 |
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5813480 |
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08760122 |
Dec 3, 1996 |
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08643909 |
May 7, 1996 |
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08643909 |
May 7, 1996 |
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08390322 |
Feb 16, 1995 |
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Current U.S.
Class: |
175/39 ;
175/57 |
Current CPC
Class: |
E21B 12/02 20130101;
E21B 10/22 20130101; E21B 47/26 20200501; E21B 10/08 20130101; E21B
47/01 20130101; E21B 47/07 20200501 |
Class at
Publication: |
175/039 ;
175/057 |
International
Class: |
E21B 012/02 |
Claims
What is claimed is:
1. An improved drill bit for use in drilling operations in a
wellbore, comprising: a bit body including a plurality of bit legs,
each supporting a rolling cone cutter; a coupling member formed at
an upper portion of said bit body; at least one temperature sensor
for monitoring at least one temperature condition of said improved
drill bit during drilling operations; and at least one temperature
sensor cavity formed in said bit body and adapted for receiving,
carrying, and locating said at least one temperature sensor in a
particular position relative to said bit body which is empirically
determined to optimize temperature sensor discrimination.
2. An improved drill bit for use in drilling operations, according
to claim 1: wherein said at least one temperature sensor comprises
at least one temperature sensor for each of said plurality of bit
legs; and wherein said at least one temperature sensor cavity
comprises at least one temperature sensor cavity formed in each of
said plurality of bit legs which is adapted for receiving,
carrying, and locating a particular temperature sensor in a
particular position relative to a particular bit leg, and which is
empirically determined to optimize temperature sensor
discrimination for that particular bit leg.
3. An improved drill bit for use in drilling operating, according
to claim 1: wherein said at least one temperature sensor cavity
comprises at least one temperature sensor cavity formed in a
particular one of said plurality of bit legs which is adapted for
receiving, carrying, and locating said at least one temperature
sensor in a particular position relative to said particular one of
said plurality of bit legs, and which is empirically determined to
optimize temperature sensor discrimination.
4. An improved drill bit for use in drilling operations, according
to claim 3: wherein each of said plurality of bit legs include a
bearing head for engagement with a rolling cone cutter; and wherein
said particular position comprises a medial position within said
bearing head.
5. An improved drill bit, according to claim 4: wherein said
bearing head is substantially cylindrically symmetrical along a
centerline; and wherein said particular position comprises a medial
position within said bearing head proximate said centerline.
6. An improved drill bit according to claim 5: wherein said bearing
head extends between a lower extent of said bit leg and a thrust
face; and wherein said particular position comprises a medial
position within said bearing head about said centerline between
said lower extent of said bit body and said thrust face.
7. An improved drill bit, according to claim 1: wherein said
improved drill bit includes a lubrication system for providing
lubrication for each of said rolling cone cutters; and wherein said
at least one temperature sensor is not in communication with said
lubrication system.
8. An improved drill bit according to claim 1, further comprising:
a service bay formed in said bit body to allow access to at least
said at least one temperature sensor cavity.
9. An improved drill bit according to claim 1, further comprising:
pressure isolator members to maintain at least said at least one
temperature sensor cavity in pressure isolation from said
wellbore.
10. A method of performing drilling operations in a well bore,
comprising: providing a bit body including a plurality of bit legs,
each supporting a rolling cone cutter; providing a coupling member
formed at an upper portion of said bit body; providing at least one
temperature sensor for monitoring at leas t one temperature
condition of said bit body during drilling operations; empirically
determining a particular position for said at least one temperature
sensor well which optimizes temperature sensor discrimination;
forming at least one temperature sensor well in said bit body at
said particular position relative to said bit body which is
empirically determined to optimize temperature sensor
discrimination; locating said at least one temperature sensor in
said at least one temperature sensor well; utilizing said improved
drill bit during drilling operations in said wellbore; and
utilizing said at least one temperature sensor to sense at least
one temperature during drilling operations.
11. A method of performing drilling operations in a wellbore,
according to claim 10: wherein said step of providing at least one
temperature sensor comprises providing at least one temperature
sensor for each of said plurality of bit legs; and wherein said
step of forming at least one temperature sensor well comprises
forming at least one temperature sensor cavity formed in each of
said plurality of bit legs which is adapted for receiving,
carrying, and locating a particular temperature sensor in a
particular position relative to a particular bit leg, and which is
empirically determined to optimize temperature sensor
discrimination for that particular bit leg.
12. A method of performing drilling operations in a wellbore,
according to claim 10: wherein said step of forming at least one
temperature sensor well comprises forming at least one temperature
sensor cavity formed in a particular one of said plurality of bit
legs adapted for receiving, carrying, and locating said at least
one temperature sensor in a particular position relative to said
particular one of said plurality of bit legs which is empirically
determined to optimize temperature sensor discrimination.
13. A method of performing drilling operations in a wellbore,
according to claim 12: wherein each of said plurality of bit legs
include a bearing head for engagement with a rolling cone cutter;
and wherein said particular position comprises a medial position
within said bearing head.
14. A method of performing drilling operations in a wellbore,
according to claim 13: wherein said bearing head is substantially
cylindrically symmetrical along a centerline; and wherein said
particular position comprises a medial position within said bearing
head proximate said centerline.
15. A method of performing drilling operations in a wellbore,
according to claim 14: wherein said bearing head extends between a
lower extent of said bit leg and a thrust face; and wherein said
particular position comprises a medial position within said bearing
head about said centerline between said lower extent of said bit
body and said thrust face.
16. A method of performing drilling operations in a wellbore,
according to claim 10, further comprises: wherein said improved
drill bit includes a lubrication system for providing lubrication
for each of said rolling cone cutters; wherein said at least one
temperature sensor is not in communication with said lubrication
system.
17. A method of performing drilling operations in a wellbore,
according to claim 10, further comprising: providing at least one
service bay formed in said bit body to allow access to said at
least said temperature sensor cavity.
18. A method of providing drilling operations, according to claim
10, further comprising: providing pressure isolator members to
maintain at least said at least one temperature sensor cavity in
pressure isolation from said wellbore.
19. An improved drill bit for use in drilling operations in a
wellbore, comprising: a bit body including a cutting structure
carried thereon; a coupling member formed at an upper portion of
said bit body; at least one temperature sensor for monitoring at
least one temperature condition of said improved drill bit during
drilling operations; and at least one temperature sensor cavity
formed in said bit body and adapted for receiving, carrying, and
locating said at least one temperature sensor in a particular
position relative to said bit body which is empirically determined
to optimize temperature sensor discrimination.
20. A method of performing drilling operations in a wellbore,
comprising: providing a bit body including a cutting structure;
providing a coupling member formed at an upper portion of said bit
body; temperature condition of said bit body during drilling
operations; empirically determining a particular position for said
at least one temperature sensor well which optimizes temperature
sensor discrimination; forming at least one temperature sensor well
in said bit body at said particular position relative to said bit
body which is empirically determined to optimize temperature sensor
discrimination; locating said at least one temperature sensor in
said at least one temperature sensor well; utilizing said improved
drill bit during drilling operations in said wellbore; and
utilizing said at least one temperature sensor for monitoring at
least one temperature condition during drilling operations.
21. An improved drill bit for use in drilling operations in a
wellbore, comprising: a bit body including a plurality of bit legs,
each supporting a rolling cone cutter; a coupling member formed at
an upper portion of said bit body; at least one operating condition
sensor for monitoring at least one operating condition of said
improved drill bit during drilling operations and producing an
electrical output signal corresponding thereto; a plurality of
electrical conductors for coupling electrically-activated
components carried by said improved drill bit including said at
least one operating condition sensor; a plurality of wire pathways
formed in said bit body; and at least one fluid-impermeable tube
segment coupled to said bit body and communicatively aligned with
said plurality of wire pathways to route and protect said plurality
of electrical conductors.
22. An improved drill bit according to claim 21, further
comprising: wherein said at least one operating condition sensor
comprises at least one operating condition sensor for each of said
plurality of bit legs; and wherein said at least one
fluid-permeable tube segment comprises a plurality of
fluid-impermeable tube segments coupled to said bit body and
communicatively aligned with said plurality of wire pathways to
route and protect said plurality of electrical conductors,
including a fluid-impermeable tube segment extending from a wire
pathway formed in each of said plurality of bit legs to a segment
connector.
23. An improved drill bit according to claim 21, further
comprising: wherein said at least one operating condition sensor
comprises at least one temperature sensor for each of said
plurality of bit legs; wherein said at least one fluid-impermeable
tube segment comprises a plurality of fluid-impermeable tube
segments coupled to said bit body and communicatively aligned with
said plurality of wire pathways to route and protect said plurality
of electrical conductors, including: (a) a plurality of
fluid-impermeable tube segments, each communicating with a wire
pathway formed in each of said plurality of bit legs at a first end
portion; and (b) a segment connector adapted for coupling to a
second end portion of said plurality of fluid-impermeable tube
segments.
24. An improved drill bit according to claim 23: wherein said a
plurality of fluid-impermeable tube segments are positioned
substantially transverse to a centerline of said improved drill
bit.
25. An improved drill bit according to claim 23: wherein said
segment connector is substantially centrally located relative to
said a plurality of fluid-impermeable tube segments.
26. An improved drill bit according to claim 23: wherein each of
said plurality of fluid-impermeable tube segments are angularly
substantially equidistant from adjoining tube segments.
27. A method of performing drilling operations in a wellbore,
comprising: providing a bit body including a plurality of bit legs,
each supporting a rolling cone cutter; providing a coupling member
formed at an upper portion of said bit body; providing at least one
operating condition sensor for monitoring at least one operating
condition of said bit during drilling operations; providing a
plurality of electrical conductors for coupling
electrically-activated components carried by said drill bit
including said at least one operating conditions; providing a
plurality of wire pathways formed in said bit body; providing at
least one fluid-impermeable tube segment coupled to said bit body
and communicatively aligned with said plurality of wire pathways to
route and protect said plurality of electrical conductors. locating
said at least one temperature sensor in said at least one
temperature sensor well; locating said at least one temperature
sensor in said at least one temperature sensor well; utilizing said
improved drill bit during drilling operations in said wellbore;
utilizing said at least one operating condition sensor to sense at
least one temperature during drilling operations.
28. A method of performing drilling operations in a wellbore,
according to claim 27: wherein said step of providing at least one
operating condition sensor comprises providing at least one
operating condition sensor for each of said plurality of bit legs;
and wherein said step of providing at least one fluid-impermeable
tube segment comprises providing a plurality of fluid-impermeable
tube segments coupled to said bit body and communicatively aligned
with said plurality of wire pathways to route and protect said
plurality of electrical conductors, including a fluid-impermeable
tube segment extending from a wire pathway formed in each of said
plurality of bit legs to a segment connector.
29. A method of performing drilling operations in a wellbore,
according to claim 28: wherein said plurality of fluid-impermeable
tube segments are positioned substantially transverse to a
centerline of said improved drill bit.
30. A method of performing drilling operations in a wellbore,
according to claim 29: wherein said segment connector is
substantially centrally located relative to said plurality of
fluid-impermeable tube segments.
31. A method of performing drilling operations in a wellbore,
according to claim 28: wherein each of said plurality of
fluid-impermeable tube segments are angularly substantially
equidistant from adjoining tube segments.
32. A method of manufacturing a rock bit for use in drilling
operations in a wellbore, comprising: providing a plurality of bit
legs; forming at least one sensor cavity in each of said plurality
of bit legs; forming a wire pathway in each of said plurality of
bit legs; providing a plurality of fluid-impermeable tube segments;
welding said plurality of bit legs together to form a bit body;
securing said plurality of fluid-impermeable tube segments to said
bit body in communication with said wire pathway in each of said
plurality of bit legs; locating a sensor in said at least one
cavity; and routing conductors through said wire pathway in each of
said plurality of bit legs and said plurality of fluid-impermeable
tube segments.
33. A method of manufacturing a rock bit, according to claim 32,
further comprising: sealing said at least one sensor cavity in each
of said bit legs, said wire pathway in each of said plurality of
bit legs, and said plurality of fluid-impermeable tube
segments.
34. A method of manufacturing a rock bit, according to claim 32,
further comprising: wherein said sensor in each of said plurality
of bit legs comprises a temperature sensor; potting said
temperature sensor in a thermally conductive potting material.
35. A method of manufacturing a rock bit, according to claim 32,
further comprising: sealing said at least one sensor cavity, said
wire pathway in each of said plurality of bit legs, and said
plurality of fluid-impermeable tube segments at substantially
atmospheric pressure.
36. A method of manufacturing a rock bit, according to claim 32,
further comprising: providing a lubrication system for each of said
plurality of bit legs; maintaining said lubrication system out of
communication with said at least one sensor cavity in each of said
plurality of bit legs, said wire pathways in each of said bit legs,
and said plurality of fluid-impermeable tube segments.
37. An improved drilling apparatus for use in drilling operations
in a wellbore, comprising: a bit body including a plurality of bit
legs, each supporting a rolling cone cutter; a lubrication system
for each rolling cone cutter for supplying lubricant thereto; a
coupling member formed at an upper portion of said bit body; at
least one lubricant condition sensor for monitoring at least one
electrical condition of said lubricant during drilling operations;
and at least one electronic memory member, communicatively coupled
to said at least one lubricant condition sensor, bit body, for
recording in memory data obtained by said at least one lubricant
condition sensor.
38. An improved drilling apparatus for use in a drilling operations
in a wellbore, according to claim 37, wherein said at least one
lubricant condition sensor comprises an electrical component which
is sensitive to changes in dielectric constant of said
lubricant.
39. An improved drilling apparatus for use in drilling operations
in a wellbore, according to claim 37., wherein said at least one
lubricant condition sensor comprises a capacitor which receives
lubricant between capacitor plates and which changes its
capacitance value as said lubricant degrades during use.
40. An improved drilling apparatus for use in drilling operations
in a wellbore, according to claim 37, wherein said at least one
lubricant condition sensor provides a general indication of decline
in service life of said drill bit.
41. An improved drilling apparatus for use in drilling operations
in a wellbore, according to claim 37, wherein said at least one
lubricant condition sensor provides a general indication of decline
in operating condition of said lubrication system.
42. An improved drilling apparatus for use in drilling operations
in a wellbore, according to claim 37, wherein said at least one
lubricant condition sensor provides a general indication of decline
in operating condition of said lubrication system by monitoring
generally the effect of working shearing on said lubricant.
43. An improved drilling apparatus for use in drilling operations
in a wellbore according to claim 37, wherein said at least one
lubricant condition sensor provides a general indication of decline
in operating condition of said lubrication system by monitoring, at
least indirectly, a total acid number for said lubricant.
44. An improved drilling apparatus for use in drilling operations
in a wellbore, according to claim 37, wherein said at least one
lubricant condition sensor provides a general indication of decline
in operating condition of said lubrication system by monitoring a
total acid number for said lubricant indirectly, by monitoring
dielectric constant of said lubricant.
45. An improved drilling apparatus according to claim 37, wherein
said at least one electronic memory member is located in, and
carried by sa id bit body.
46. An improved drill bit for use in drilling operations in a
wellbore, comprising: (a) a bit body formed from a plurality of bit
legs; (b) each of said plurality of bit legs including: (1) a
bearing head; (2) a rolling cone cutter coupled to said bearing
head; (3) a bearing assembly facilitating rotary movement of said
rolling cone cutter relative to said bearing head; (4) a
lubrication system for providing lubricant to said bearing
assembly; (5) an electrical sensor in communication with said
lubrication system for monitoring at least one electrical property
of said lubricant; (c) electronic memory carried by said bit body;
and (d) a sampling circuit for developing digital samples from said
sensor from each of said plurality of bit legs and recording said
digital samples in said electronic memory.
47. A method of performing drilling operations in a wellbore,
comprising: providing a bit body including a plurality of bit legs,
each supporting a rolling cone cutter; providing a lubrication
system for each rolling cone cutter for supplying lubricant
thereto; providing a coupling member formed at an upper portion of
said bit body; providing at least one lubricant condition sensor
for monitoring at least one electrical condition during drilling
operations; providing at least one electronic memory member,
communicatively coupled to said at lest one lubricant condition
sensor, for recording in memory data obtained by said at least one
lubricant condition sensor; utilizing said improved drill bit
during drilling operations in a wellbore; utilizing said at least
one lubricant condition sensor to sense said at least one
electrical condition of said lubricant during drilling operations;
and utilizing said at least one electronic memory member for
recording data pertaining to said at least one electrical condition
of said lubricant.
48. A method of performing drilling operations in a wellbore,
according to claim 47, wherein said electrical sensor comprises an
electrical component which is sensitive to changes in dielectric
constant of said lubricant.
49. A method of performing drilling operations in a wellbore,
according to claim 47, wherein said at least one lubricant
condition sensor comprises a capacitor which receives lubricant
between capacitor plates and which changes its capacitance value as
said lubricant degrades during use.
50. A method of performing drilling operations in a wellbore,
according to claim 47, wherein said at least one lubricant
condition sensor comprises a capacitor which is disposed in a
lubricant reservoir and which receives lubricant between capacitor
plates and which changes its capacitance value as said lubricant
degrades during use.
51. A method of performing drilling operations in a wellbore,
according to claim 47, wherein said at least one lubricant
condition sensor provides a general indication of decline in
service life of said drill bit.
52. A method of performing drilling operations in a wellbore,
according to claim 47, wherein said at least one lubricant
condition sensor provides a general indication of decline in
operating condition of said lubrication system.
53. A method of performing drilling operations in a wellbore,
according to claim 47, wherein said at least one lubricant
condition sensor provides a general indication of decline in
operating condition of said lubrication system by monitoring
generally the effect of working shearing on said lubricant.
54. A method of performing drilling operations in a wellbore,
according to claim 47, wherein said at least one lubricant
condition sensor provides a general indication of decline in
operating condition of said lubrication system by monitoring
changes in dielectric constant due to working shear for said
lubricant.
55. A method of performing drilling operations in a wellbore,
according to claim 47, wherein said at least one lubricant
condition sensor provides a general indication of decline in
operating condition of said lubrication system by monitoring a
total acid number for said lubricant through changes in dielectric
constant due to working shear.
56. An improved drill bit for use in drilling operations in a
wellbore when coupled to a drillstring having a central flow path
for communicating drilling fluid, comprising: a bit body including
a cutting structure carried thereon; at least one bit nozzle
carried by said bit body for jetting drilling fluid into said
wellbore; a flow path through said bit body for supplying said
drilling fluid to said at least one bit nozzle; a coupling member
formed at an upper portion of said bit body for securing said bit
body to said drillstring; at least one sensor for monitoring at
least one operating condition during drilling operations; an
erodible ball; and a fastener system for securing said erodible
ball in a fixed predetermined position relative to said flow path
until a predetermined operating condition is detected by said at
least one sensor, and for then releasing said erodible ball into
said flow path to at least partially obstruct flow through one of
said at least one bit nozzles.
57. An improved drill bit, according to claim 56, wherein said
erodible ball includes at least one of the following: (1) at least
one flow port extending through at least a portion of said erodible
ball to allow drilling fluid to pass therethrough and erode said
erodible ball; and (2) at least one circumferential groove formed
in at least a portion of said erodible ball to allow drilling fluid
to pass therethrough and erode said erodible ball.
58. An improved drill bit, according to claim 56, wherein said
fastener system includes a frangible connector.
59. An improved drill bit, according to claim 56, said fastener
system includes an electrically-actuable fastener.
60. An improved drill bit, according to claim 56, said fastener
system includes an electrically-actuable frangible connector.
61. An improved drill bit, according to claim 56, said erodible
ball will respond at least as one of the following due to contact
with said drilling fluid: (1) dissolve; and (2) disintegrate.
62. An improved drill bit, according to claim 56, said fastener
system will respond in accordance with at least one of the
following upon detection of said predetermined operating condition:
(1) electrically respond to said predetermined operating condition
to release said erodible ball; and (2) mechanically respond to said
predetermined operating condition to release said erodible
ball.
63. An improved drill bit, according to claim 56, wherein said at
least one flow port comprises a plurality of orthogonally aligned
ports extending through said erodible ball.
64. An improved drill bit, according to claim 56, wherein said at
least one circumferential groove comprises a plurality of
intersecting grooves formed on an exterior surface of said erodible
ball.
65. An improved drill bit, according to claim 56, wherein said
erodible ball is eroded by said drilling fluid in a relatively
predictable and predetermined manner.
66. An improved drill bit, according to claim 56, wherein said
erodible ball is eroded by said drilling fluid in no less than a
minimum erosion time interval.
67. An improved drill bit for use in drilling operations in a
wellbore, comprising: a bit body including a cutting structure
carried thereon; a coupling member formed at an upper portion of
said bit body; at least one bit condition sensor system for
monitoring at least one bit condition of said improved drill bit
during drilling operations; at least one semiconductor memory,
located in and carried by said bit body, for recording in memory
data obtained by said at least one bit condition sensor; and
wherein said at least one bit condition sensor system includes: (a)
an electrical sensor component which has at least one electrical
attribute which changes in response to changes in said at least one
bit condition; (b) a monitoring circuit component for monitoring
changes in said at least one electrical attribute of said
electrical sensor component as changes occur in said at least one
bit condition; and (c) a sampling circuit for sampling said
monitoring circuit and recording data in said at least one
semiconductor memory.
68. An improved drill bit, according to claim 67, wherein said
electrical sensor component comprises an electrically resistive
component which changes resistance in response to changes in said
at least one bit condition.
69. An improved drill bit, according to claim 67, wherein said
monitoring circuit component comprises an oscillator which changes
its frequency of operation in response to changes in said at least
one electrical attribute of said electrical sensor component.
70. An improved drill bit, according to claim 67, wherein said
sampling circuit includes an averaging circuit for averaging an
output of said monitoring circuit.
71. An improved drill bit, according to claim 67, wherein said
electrical sensor component comprises an electrically resistive
component which changes resistance in response to change in
temperature of said improved drill bit.
72. An improved drill bit, according to claim 67: wherein said
electrical sensor component comprises an electrically resistive
component which changes resistance in response to change in
temperature of said improved drill bit; and wherein said monitoring
circuit component comprises an oscillator which changes its
frequency of operation in response to changes in resistance of said
electrical sensor component.
73. An improved drill bit, according to claim 67, further
comprising: a lubrication system for lubricating said cutting
structure; wherein said electrical sensor component comprises an
electrical component which changes at least one electrical
attribute in response to changes in condition of said lubrication
system; and wherein said monitoring circuit component comprises an
oscillator which changes its frequency of operation in response to
changes in said at least one electrical attribute of said
electrical sensor component.
74. An improved drill bit, according to claim 67, further
comprising: a lubrication system for lubricating said cutting
structure; wherein said electrical sensor component comprises an
electrical component which changes capacitance in response to
changes in operating condition of said lubrication system; and
wherein said monitoring circuit component comprises an oscillator
which changes its frequency of operation in response to changes in
said capacitance of said electrical sensor component.
75. An improved drill bit, according to claim 67, further
comprising: wherein said electrical sensor component comprises an
electrically resistive component which changes resistance in
response to change in relative temperature of a portion of said
improved drill bit; and wherein said monitoring circuit component
comprises an oscillator which changes its frequency of operation in
response to changes in resistance of said electrical sensor
component.
76. An improved drill bit, according to claim 67, further
comprising: a lubrication system for lubricating said cutting
structure; wherein said electrical sensor component comprises an
electrical component which changes capacitance in response to
changes in condition of a lubricant in said lubrication system; and
wherein said monitoring circuit component comprises an oscillator
which changes its frequency of operation in response to changes in
said capacitance of said electrical sensor component.
77. An improved drill bit for use in drilling operations in a
wellbore when coupled to a drillstring having a central flow path
for communicating drilling fluid, comprising: a bit body including
a cutting structure carried thereon; an interior space defined by
said bit body, including: (a) at least one bit nozzle flow path
carried by said bit body for jetting drilling fluid into said
wellbore; (b) a central flow path through said bit body for
supplying said drilling fluid to said at least one bit nozzle flow
path; a coupling member formed at an upper portion of said bit body
for securing said bit body to said drillstring; at least one sensor
for monitoring at least one operating condition during drilling
operations; a signal flow path defined through said bit body for
connecting said interior space to a space exterior of said bit
body; a selectively-actuable flow control device for controlling
said signal flow path until a predetermined operating condition is
detected at least in part by said at least one sensor; and wherein
upon actuation of said selectively-actuable flow control device, at
least one detectable pressure change is developed in said
wellbore.
78. An improved drill bit according to claim 77, wherein said
signal flow path connects said interior space to an annular region
external to said improved drill bit.
79. An improved drill bit according to claim 77, wherein said
selectively-actuable flow control device controls said signal flow
path by preventing flow.
80. An improved drill bit according to claim 77, wherein said
selectively-actuable flow control device includes: a structural
body; a selectively-actuable binder which changes state in response
to at least one control signal; and a control member for
selectively supplying said at least one control signal to said
selectively-actuable binder, to cause a state change, an d to
change said structural body to change at least one flow condition
for said signal flow path.
81. An improved drill bit according to claim 77, wherein said
selectively-actuable flow control device comprises an
electrically-actuable flow control device.
82. An improved drill bit according to claim 77, wherein said
selectively-actuable flow control device comprises a
thermally-actuable flow control device.
83. An improved drill bit according to claim 77, wherein, upon
actuation, said selectively-actuable flow control device develops a
persistent detectable pressure change in said wellbore.
84. An improved drill bit according to claim 77, wherein said
detectable pressure change comprises a pressure change which is
detectable at a surface location du ring drilling operations.
85. An improved drill bit for use in drilling operations in a
wellbore, comprising: a bit body; a cutting structure carried by
said bit body; a coupling member formed at an upper portion of said
bit body; at least one operating condition sensor, located in and
carried by said bit body, for monitoring at least one operating
condition during drilling operations; at least one electrical power
consuming component, located in and carried by said bit body, for
receiving and processing data from said at least one operating
condition sensor, during drilling operations; an electrical power
source, located in and carried by said bit body, for supplying
electrical power to said at least one electrical power consuming
component; and at least one switch member, electrically connected
between said at least one electrical power consuming component and
said electrical power source, which automatically switches between
a low-power consumption mode of operation to a high-power
consumption mode of operation in response to detection of at least
one ambient condition ordinarily present during drilling
operations.
86. An improved drill bit according to claim 85, wherein said at
least one switch member comprises at least one pressure actuable
switch member.
87. An improved drill bit according to claim 85, wherein said
low-power consumption mode of operation comprises a no-power
consumption mode of operation.
88. An improved drilling apparatus including a drill bit coupled to
a bottomhole assembly for use in drilling operations in a wellbore,
comprising: a bit body; a cutting structure carried by said bit
body; a coupling member formed at an upper portion of said bit body
for securing said bit body in said bottomhole assembly; at least
one drilling condition sensor, located in and carried by said bit
body, for monitoring at least one of the following and producing
sensor data in the form of at least one electrical signal
corresponding thereto: (a) a drilling environment condition; (b) a
drill bit operating condition; (c) a drilling operation condition;
and (d) a formation condition; a controller member for receiving
said at least one electrical signal, processing at least one
electrical signal, and developing at least one condition conclusion
concerning at least one of the following: (a) a drilling
environment condition conclusion; (b) a drill bit operating
condition conclusion; and (c) a drilling operation condition
conclusion; at least one controllable actuator member carried in at
least one of (1) said bit body and (2) said bottomhole subassembly
proximate said bit body, for adjusting at least one of the
following in response to at least one control signal; (a) a drill
bit operating condition; (b) a drilling operation condition;
wherein said controller member supplies at least one control signal
to said at least one controllable actuator member in response to
changes in at least one of the following: (a) said sensor data; and
(b) said at least one condition conclusion.
89. An improved drilling apparatus according to claim 88, further
comprising: an electronic memory member, communicatively coupled to
said at least one drilling condition sensor and said controller
member for recording sensor data, and providing recorded sensor
data to said controller member for analysis.
90. An improved drilling apparatus according to claim 88, wherein
said controller member comprises a programmable data processing
device for executing program instructions which define at least one
routine for analyzing said sensor data, developing at least one
condition conclusion, and providing at least one control signal to
said at least one controllable actuator.
91. An improved drilling apparatus according to claim 88, wherein
said controller member supplies said at least one control signal,
to perform at least one of the following: (a) increase the
influence of said at least one controllable actuator member on the
drilling operations; and (b) decrease the influence of said at
least one controllable actuator member on the drilling
operations.
92. An improved drilling apparatus, according to claim 88: wherein
said at least one drilling condition sensor provides a
substantially continuous flow of sensor data during drilling
operations; and wherein said controller member operates
substantially continuously during drilling operations to process
said sensor data, develop said at least one condition conclusion,
and provide said at least one control signal to said a t least one
controllable actuator member.
93. An improved drilling apparatus according to claim 88: wherein
said controller member is provided with at least one operating set
point concerning at least one of: (a) a drill bit operating
condition; and (b) a drilling operation condition; wherein said
controller member provides said at last one control signal to said
at least one controllable actuator in order to obtain operation
consistent with said at least one operating set point.
94. An improved drilling apparatus according to claim 88: wherein
said at least one operating set point comprises at least one
desired drilling performance standard for particular drilling
conditions.
95. An improved drilling apparatus according to claim 88, where in
said at least one controllable actuator member comprises at least
one of the following: (a) a system for adjusting an orientation of
at least one cutting structure carried by said drill bit; (b) a
system for adjusting cone rotation speed for at least one rolling
cone cutter carried by said drill bit; (c) a system for adjusting
an orientation of at least one nozzle carried by said drill bit;
(d) a system for adjusting nozzle opening size of at least one
nozzle carried by said drill bit; (e) a system for adjusting at
least one orienting pad carried by said bottomhole assembly; (f) a
system for adjusting speed of operation of at least one drilling
motor carried by said bottomhole assembly; (g) a system for
adjusting at least one steering system carried by said bottomhole
assembly; and (h) a system for adjusting cutting gage of said drill
bit to determine diameter of said wellbore.
96. An improved drilling apparatus according to claim 88, wherein
said controller member develops said at least one condition
conclusion by analyzing said sensor data with respect to time in
order to identify at least one of: (a) trends within said sensor
data; (b) patterns within said sensor data; and (c) correspondence
to predetermined sensor data profiles.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application is a continuation-in-part of the following
co-pending, commonly owned patent application U.S. patent
application Ser. No. 08/760,122, filed 3 Dec. 1996, entitled Method
and Apparatus for Monitoring and Recording of Operating Conditions
of a Downhole Drill Bit During Drilling Operations, with the
following inventors: Theodore E. Zaleski, Jr., and Scott R.
Schmidt; which is a continuation under 37 CFR 1.62 of U.S. patent
application Ser. No. 08/643,909, filed 7 May 1996, entitled Method
and Apparatus for Monitoring and Recording of Operating Conditions
of a Downhole Drill Bit During Drilling Operations, with the
following inventors: Theodore E. Zaleski, Jr., and Scott R.
Schmidt; which is a continuation of U.S. patent application Ser.
No. 08/390,322, filed 16 Feb. 1995, entitled Method and Apparatus
for Monitoring and Recording of Operating Conditions of a Downhole
Drill Bit During Drilling Operations, with the following inventors:
Theodore E. Zaleski, Jr., and Scott R. Schmidt. These prior
applications are incorporated herein by reference as if fully set
forth.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present application relates in general to oil and gas
drilling operations, and in particular to an improved method and
apparatus for monitoring the operating conditions of a downhole
drill bit during drilling operations.
[0004] 2. Description of the Prior Art
[0005] The oil and gas industry expends sizable sums to design
cutting tools, such as downhole drill bits including rolling cone
rock bits and fixed cutter bits, which have relatively long service
lives, with relatively infrequent failure. In particular,
considerable sums are expended to design and manufacture rolling
cone rock bits and fixed cutter bits in a manner which minimizes
the opportunity for catastrophic drill bit failure during drilling
operations. The loss of a cone or cutter compacts during drilling
operations can impede the drilling operations and necessitate
rather expensive fishing operations. If the fishing operations
fail, side track drilling operations must be performed in order to
drill around the portion of the wellbore which includes the lost
cones or compacts. Typically, during drilling operations, bits are
pulled and replaced with new bits even though significant service
could be obtained from the replaced bit. These premature
replacements of downhole drill bits are expensive, since each trip
out of the wellbore prolongs the overall drilling activity, and
consumes considerable manpower, but are nevertheless done in order
to avoid the far more disruptive and expensive fishing and side
track drilling operations necessary if one or more cones or
compacts are lost due to bit failure.
SUMMARY OF THE INVENTION
[0006] IN GENERAL: The present invention is directed to an improved
method and apparatus for monitoring and recording of operating
conditions of a downhole drill bit during drilling operations. The
invention may be alternatively characterized as either (1) an
improved downhole drill bit, or (2) a method of performing drilling
operations in a borehole and monitoring at least one operating
condition of a downhole drill bit during drilling operations in a
wellbore, or (3) a method of manufacturing an improved downhole
drill bit.
[0007] When characterized as an improved downhole drill bit, the
present invention includes (1) an assembly including at least one
bit body, (2) a coupling member formed at an upper portion of the
assembly, (3) at least one operating condition sensor carried by
the improved downhole drill bit for monitoring at least one
operating condition during drilling operations, and (4) at least
one electronic or semiconductor memory located in and carried by
the assembly, for recording in memory data pertaining to the at
least one operating condition.
[0008] The present invention may be characterized as in improved
drill bit for use in drilling operations in a wellbore. The
improved drill bit includes an number of components which
cooperate. A bit body is provided which includes a plurality of bit
heads, each supporting a rolling cone cutter. A coupling member is
formed at an upper portion of the bit body. Preferably, but not
necessarily, the coupling member comprises a threaded coupling for
connecting the improved drill bit to a drillstring in a
conventional pin-and-box threaded coupling. The improved drill bit
may include either or both of a temperature sensor and a
lubrication system sensor.
[0009] TEMPERATURE SENSING: For example, the improved drill bit
includes at least one temperature sensor for monitoring at least
one temperature condition of the improved drill bit during drilling
operations. In accordance with this particular embodiment of the
present invention, at least one temperature sensor cavity is formed
in the bit body and adapted for receiving, carrying and locating at
least one temperature sensor in a particular position relative to
the bit body which is empirically determined to optimize
temperature sensor discrimination. At least one electronic or
semiconductor memory member is provided, and located in, and
carried by the drill bit body, for recording in memory data
obtained by the at least one temperature sensor.
[0010] In accordance with this embodiment of the present invention,
the temperature sensor cavity is located in the bit body in a
position which is empirically determined to optimize temperature
sensor discrimination. More particularly, the temperature sensor
cavity is located in the head bearing in a substantially medial
position which is proximate to the centerline of the head bearing.
More particularly, the temperature sensor cavity is provided in a
medial position within the head bearing about its centerline
between its base and the thrust face.
[0011] CONDUCTOR ROUTING: Conductors are provided to
communicatively couple the electrical components carried by the
improved rock bit. A plurality of wire pathways are formed in the
plurality of bit legs in order to allow the conductors to be routed
to the electrical components. In order to allow electrical
connection between the components carried in the legs of the
improved rock bit, a novel tri-tube assembly is provided. The
tri-tube assembly includes a plurality of fluid-impermeable tube
segments. Each of the fluid-impermeable tube segments is placed
into communication with a wire pathway in one of the plurality of
bit legs. The opposite ends of the fluid-impermeable tube segments
are brought together at a connector. Conductors are routed through
the fluid-impermeable tube segments to provide power to
power-consuming electrical components and to pass data between the
electrical components.
[0012] LUBRICATION MONITORING: The present invention can also be
utilized to monitor the operating condition of the lubrication
systems in an improved rock bit. In accordance with the present
invention, a bit body is formed from a plurality of bit legs. Each
of the plurality of bit legs include a head bearing, a rolling cone
cutter coupled to the head bearing, a bearing assembly facilitating
rotary movement of the rolling cone cutter relative to the bearing
head, a lubrication system for providing lubricant to the bearing
assembly, and an electrical sensor in communication with the
lubrication of the lubrication system for monitoring at least one
electrical property of the lubricant.
[0013] Additionally, a semiconductor member is carried by the bit
body, and a sampling circuit is provided for developing digital
samples from the sensor from the plurality of bit legs and for
recording the digital samples in the semiconductor memory. In
accordance with one embodiment of the present invention, the
electrical sensor comprises a dielectric sensor which is
preferably, but not necessarily, a capacitive electrical component.
In accordance with the present invention, the capacitive electrical
component is placed within the lubrication system to allow
lubricant to lodge between the capacitor plates. As the lubricant
degrades during use due to working shear, or if ingress of drilling
fluid into the lubricating system occurs, the lubricant is altered
in a manner which changes the dialectric constant of the lubricant.
An increase in working shear will result in an increase in the
dialectric constant of the lubricant. This change in the dielectric
constant of the lubricant is detected utilizing the capacitive
circuit component. The ingress of drilling fluid will also impact
the dielectric permitivity of the lubricant and can also be
detected utilizing the capacitive circuit element.
[0014] TRANSIENT-PRESSURE CHANGE COMMUNICATION SYSTEM: The
embodiment of the improved drill bit which is described herein
further includes a relatively simple downhole-to-surface
communication system which is utilized to provide a warning signal
to a surface location by generating transient or persistent
pressure change within the wellbore. A transient pressure change
may be generated utilizing an erodible ball. The erodible ball is
secured in position within the improved drill bit utilizing a
fastener system. The erodible ball is maintained in a predetermined
position relative to a flow path which supplies drilling fluid to
at least one bit nozzle carried by the improved drill bit. Once a
predetermined operating condition is detected by a monitoring
system carried by the improved drill bit (such as the temperature
and lubrication monitoring systems described above), the fastener
system is actuated to release the erodible ball into the flow path.
The erodible ball passes down the flow path toward the bit nozzle,
where it is caught by the bit nozzle and serves to at least
partially and temporarily obstruct the flow of drilling fluid
through the bit nozzle. In accordance with the present invention,
the erodible ball preferably includes at least one flow port
extending through at a least a portion of the erodible ball to
allow drilling fluid to pass therethrough, and at least one
circumferential groove formed over at least one portion of the
erodible ball to allow drilling fluid to pass around the ball.
[0015] PERSISTENT PRESSURE CHANGE COMMUNICATION SYSTEM: A
persistent pressure change, as opposed to a transient or temporary
pressure change, may be generated utilizing an
electrically-actuable valve which utilizes the pressure
differential between the central bore of the drillstring and the
annular region between the drillstring and the borehole. For
example, allowing fluid communication between the annulus and the
central bore will decrease the pressure of the drilling fluid
within the central bore. In this particular embodiment, a port is
provided between the exterior of the bit body and the flow paths
within the bit body. An electrically-actuable "valve" is provided
to block flow until signalling is required. Preferably, the "valve"
includes a structural body which is secured into a flow blocking
condition by a propellent material that is thermally actuable. An
electrical element is carried in the structural element. When an
open flow path is desired, a current is passed through the
electrical element causing it to change from a solid state to a
gaseous state. This allows the structural element to change shape,
allowing fluid flow between the central bore and the annulus. This
causes a slight pressure decrease in the drilling fluid which is
carried in the central bore.
[0016] At least one pressure sensor can be located in an uphole
location (such as a surface location) in order to detect the
pressure change. In accordance with the embodiment of the present
invention which utilizes transient pressure changes, the erodible
ball is constructed to erode or dissolve under exposure to drilling
fluid in a manner which provides a pressure change of a minimum
time duration, in order to distinguish the pressure change from
pressure changes which occur for other reasons during drilling
operations.
[0017] DOWNHOLE ADAPTIVE CONTROL: The present invention may also be
utilized to provide adaptive control of a drilling tool during
drilling operations. The purpose of the adaptive control is to
select one or more operating set points for the tool, to monitor
sensor data including at least one sensor which determines the
current condition of at least one controllable actuator member
carried in the drilling tool or in the bottomhole assembly near the
drilling tool which can be adjusted in response to command signals
from a controller.
[0018] The above as well as additional objectives, features, and
advantages will become apparent in the following description.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] The novel features believed characteristic of the invention
are set forth in the appended claims. The invention itself,
however, as well as a preferred mode of use, further objectives and
advantages thereof, will best be understood by reference to the
following detailed description of an illustrative embodiment when
read in conjunction with the accompanying drawings, wherein:
[0020] FIG. 1 depicts drilling operations conducted utilizing an
improved downhole drill bit in accordance with the present
invention, which includes a monitoring system for monitoring at
least one operating condition of the downhole drill bit during the
drilling operations;
[0021] FIG. 2 is a perspective view of an improved downhole drill
bit;
[0022] FIG. 3 is a longitudinal section view of a portion of the
downhole drill bit depicted in FIG. 2;
[0023] FIG. 4 is a block diagram view of the components which are
utilized to perform signal processing, data analysis, and
communication operations;
[0024] FIG. 5 is a block diagram depiction of electronic memory
utilized in the improved downhole drill bit to record data;
[0025] FIG. 6 is a block diagram depiction of particular types of
operating condition sensors which may be utilized in the improved
downhole drill bit of the present invention;
[0026] FIG. 7 is a flowchart representation of the method steps
utilized in constructing an improved downhole drill bit in
accordance with the present invention;
[0027] FIGS. 8A through 8H depict details of sensor placement on
the improved downhole drill bit of the present invention, along
with graphical representations of the types of data indicative of
impending downhole drill bit failure;
[0028] FIG. 9 is a block diagram representation of the monitoring
system utilized in the improved downhole drill bit of the present
invention;
[0029] FIG. 10 is a perspective view of a fixed-cutter downhole
drill bit;
[0030] FIG. 11 is a fragmentary longitudinal section view of the
fixed-cutter downhole drill bit of FIG. 10;
[0031] FIG. 12 is a partial longitudinal section view of a bit head
constructed in accordance with the present invention;
[0032] FIG. 13 is a partial longitudinal section view of a portion
of the bit head which provides the relative locations and
dimensions of the preferred temperature sensor cavity of the
present invention;
[0033] FIG. 14 is a graphical representation of relative
temperature data from a tri-cone rock bit during test
operations;
[0034] FIG. 15 is a simplified plan view of the conductor, service,
and sensor cavities and associated tri-tube assembly utilized in
accordance with one embodiment of the present invention to route
conductors through the improved drill bit;
[0035] FIG. 16 is a fragmentary cross-section view of the tri-tube
wire way in accordance with the preferred embodiment of the present
invention;
[0036] FIG. 17 is a top view of the tri-tube assembly in accordance
with the preferred embodiment of the present invention;
[0037] FIG. 18 is a perspective view of the connector of the
tri-tube assembly in accordance with the preferred embodiment of
the present invention;
[0038] FIG. 19 is a pictorial representation of the service bay cap
and associated pipe plug in accordance with the preferred
embodiment of the present invention;
[0039] FIG. 20 is a pictorial and block diagram representation of
the electrical conductors and electrical components utilized in
accordance with the preferred embodiment of the present
invention;
[0040] FIG. 21 is a pictorial representation of the operations
performed for testing the seal integrity of the cavities of the
improved bit of the present invention, and for potting the
cavities;
[0041] FIG. 22 is a pictorial representation of an encapsulated
temperature sensor in accordance with the preferred embodiment of
the present invention;
[0042] FIG. 23 is a longitudinal section view of a
pressure-actuated switch which may be utilized in connection with
the improved bit of the present invention to switch the bit between
operating states;
[0043] FIG. 24 is a section view of an alternative
pressure-actuated switch;
[0044] FIG. 25 is a flow chart representation of the manufacturing
process utilized for the preferred embodiment of the improved bit
of the present invention;
[0045] FIGS. 26 and 27 are circuit, block diagram and graphical
presentations of the signal processing utilized in accordance with
the preferred resistance temperature sensing system of the present
invention;
[0046] FIG. 28 is a circuit and block diagram representation of the
preferred lubrication monitoring system of the present
invention;
[0047] FIG. 29A through 29F are block diagram representations of
the Application Specific Integrated Circuit utilized in the present
invention;
[0048] FIGS. 30A, 30B and 30C are graphical and pictorial
representations of the examination of optimum lubrication system
monitoring in accordance with the present invention;
[0049] FIG. 31 is a fragmentary and simplified longitudinal section
view of the placement of the lubrication monitoring system in
accordance with the present invention;
[0050] FIGS. 32A, 32B, 32C, 32D, and 32E are simplified pictorial
representations of a simple mechanical system for communication to
a remote surface location utilizing an erodible ball;
[0051] FIGS. 33 and 34 are simplified pictorial representations of
an alternative communication system which utilizes an
electrically-actuable flow blocking device;
[0052] FIGS. 35A through 351 are block diagram and simplified
pictorial representations of adaptive control of a drilling
apparatus in accordance with the present invention;
[0053] FIGS. 36 and 37 are pictorial and cross-section views of the
system of communicating utilizing a persistent pressure change.
DETAILED DESCRIPTION OF THE INVENTION
[0054] 1. OVERVIEW OF DRILLING OPERATIONS: FIG. 1 depicts one
example of drilling operations conducted in accordance with the
present invention with an improved downhole drill bit which
includes within it a memory device which records sensor data during
drilling operations. As is shown, a conventional rig 3 includes a
derrick 5, derrick floor 7, draw works 9, hook 11, swivel 13, kelly
joint 15, and rotary table 17. A drillstring 19 which includes
drill pipe section 21 and drill collar section 23 extends downward
from rig 3 into borehole 1. Drill collar section 23 preferably
includes a number of tubular drill collar members which connect
together, including a measurement-while-drilling logging
subassembly and cooperating mud pulse telemetry data transmission
subassembly, which are collectively referred to hereinafter as
"measurement and communication system 25".
[0055] During drilling operations, drilling fluid is circulated
from mud pit 27 through mud pump 29, through a desurger 31, and
through mud supply line 33 into swivel 13. The drilling mud flows
through the kelly joint and into an axial central bore in the
drillstring. Eventually, it exits through jets or nozzles which are
located in downhole drill bit 26 which is connected to the
lowermost portion of measurement and communication system 25. The
drilling mud flows back up through the annular space between the
outer surface of the drillstring and the inner surface of wellbore
1, to be circulated to the surface where it is returned to mud pit
27 through mud return line 35. A shaker screen (which is not shown)
separates formation cuttings from the drilling mud before it
returns to mud pit 27.
[0056] Preferably, measurement and communication system 25 utilizes
a mud pulse telemetry technique to communicate data from a downhole
location to the surface while drilling operations take place. To
receive data at the surface, transducer 37 is provided in
communication with mud supply line 33. This transducer generates
electrical signals in response to drilling mud pressure variations.
These electrical signals are transmitted by a surface conductor 39
to a surface electronic processing system 41, which is preferably a
data processing system with a central processing unit for executing
program instructions, and for responding to user commands entered
through either a keyboard or a graphical pointing device.
[0057] The mud pulse telemetry system is provided for communicating
data to the surface concerning numerous downhole conditions sensed
by well logging transducers or measurement systems that are
ordinarily located within measurement and communication system 25.
Mud pulses that define the data propagated to the surface are
produced by equipment which is located within measurement and
communication system 25. Such equipment typically comprises a
pressure pulse generator operating under control of electronics
contained in an instrument housing to allow drilling mud to vent
through an orifice extending through the drill collar wall. Each
time the pressure pulse generator causes such venting, a negative
pressure pulse is transmitted to be received by surface transducer
37. An alternative conventional arrangement generates and transmits
positive pressure pulses. As is conventional, the circulating mud
provides a source of energy for a turbine-driven generator
subassembly which is located within measurement and communication
system 25. The turbine-driven generator generates electrical power
for the pressure pulse generator and for various circuits including
those circuits which form the operational components of the
measurement-while-drilling tools. As an alternative or supplemental
source of electrical power, batteries may be provided, particularly
as a back-up for the turbine-driven generator.
[0058] b 2. UTILIZATION OF THE INVENTION IN ROLLING CONE ROCK BITS:
FIG. 2 is a perspective view of an improved downhole drill bit 26
in accordance with the present invention. The downhole drill bit
includes an externally-threaded upper end 53 which is adapted for
coupling with an internally-threaded box end of the lowermost
portion of the drillstring. Additionally, it includes bit body 55.
Nozzle 57 and the other obscured nozzles jet fluid that is pumped
downward through the drillstring to cool downhole drill bit 26,
clean the cutting teeth of downhole drill bit 26, and transport the
cuttings up the annulus. Improved downhole drill bit 26 includes
three bit heads (but may alternatively include a lesser or greater
number of heads) which extend downward from bit body 55 and
terminate at journal bearings (not depicted in FIG. 2 but depicted
in FIG. 3, but which may alternatively include any other
conventional bearing, such as a roller bearing) which receive
rolling cone cutters 63, 65, 67. Each of rolling cone cutters 63,
65, 67 is lubricated by a lubrication system which is accessed
through compensator caps 59, 60 (obscured in the view of FIG. 2),
and 61. Each of rolling cone cutters 63, 65, 67 includes cutting
elements, such as cutting elements 71, 73, and optionally include
gage trimmer inserts, such as gage trimmer insert 75. As is
conventional, cutting elements may comprise tungsten carbide
inserts which are press fit into holes provided in the rolling cone
cutters. Alternatively, the cutting elements may be machined from
the steel which forms the body of rolling cone cutters 63, 65, 67.
The gage trimmer inserts, such as gage trimmer insert 75, are press
fit into holes provided in the rolling cone cutters 63, 65, 67. No
particular type, construction, or placement of the cutting elements
is required for the present invention, and the drill bit depicted
in FIGS. 2 and 3 is merely illustrative of one widely available
downhole drill bit.
[0059] FIG. 3 is a longitudinal section view of the improved
downhole drill bit 26 of FIG. 2. One bit head 81 is depicted in
this view. Central bore 83 is defined interiorly of bit head 81.
Externally threaded pin 53 is utilized to secure downhole drill bit
26 to an adjoining drill collar member. In alternative embodiments,
any conventional or novel coupling may be utilized. A lubrication
system 85 is depicted in the view of FIG. 3 and includes
compensator 87 which includes compensator diaphragm 89, lubrication
passage 91, lubrication passage 93, and lubrication passage 95.
Lubrication passages 91, 93, and 95 are utilized to direct
lubricant from compensator 97 to an interface between rolling cone
cutter 63 and cantilevered journal bearing 97, to lubricate the
mechanical interface 99 thereof. Rolling cone cutter 63 is secured
in position relative to cantilevered journal bearing 97 by ball
lock 101 which is moved into position through lubrication passage
93 through an opening which is filled by plug weld 103. The
interface 99 between cantilevered journal bearing 97 and rolling
cone cutter 63 is sealed by o-ring seal 105; alternatively, a rigid
or mechanical face seal may be provided in lieu of an o-ring seal.
Lubricant which is routed from compensator 87 through lubrication
passages 91, 93, and 95 lubricates interface 99 to facilitate the
rotation of rolling cone cutter 63 relative to cantilevered journal
bearing 97. Compensator 87 may be accessed from the exterior of
downhole drill bit 26 through removable compensator cap 61. In
order to simplify this exposition, the plurality of operating
condition sensors which are placed within downhole drill bit 26 are
not depicted in the view of FIG. 3. The operating condition sensors
are however shown in their positions in the views of FIGS. 8A
through 8H.
[0060] 3. OVERVIEW OF DATA RECORDATION AND PROCESSING: FIG. 4 is a
block diagram representation of the components which are utilized
to perform signal processing, data analysis, and communication
operations, in accordance with the present invention. As is shown
therein, sensors, such as sensors 401, 403, provide analog signals
to analog-to-digital converters 405, 407, respectively. The
digitized sensor data is passed to data bus 409 for manipulation by
controller 411. The data may be stored by controller 411 in
nonvolatile memory 417. Program instructions which are executed by
controller 411 may be maintained in ROM 419, and called for
execution by controller 411 as needed. Controller 411 may comprise
a conventional microprocessor which operates on eight or
sixteen-bit binary words. Controller 411 may be programmed to
merely administer the recording of sensor data in memory, in the
most basic embodiment of the present invention; however, in more
elaborate embodiments of the present invention, controller 411 may
be utilized to perform analyses of the sensor data in order to
detect impending failure of the downhole drill bit and/or to
supervise communication of either the processed or unprocessed
sensor data to another location within the drillstring or wellbore.
The preprogrammed analyses may be maintained in memory in ROM 419,
and loaded onto controller 411 in a conventional manner, for
execution during drilling operations. In still more elaborate
embodiments of the present invention, controller 411 may pass
digital data and/or warning signals indicative of impending
downhole drill bit failure to input/output devices 413, 415 for
communication to either another location within the wellbore or
drillstring, or to a surface location. The input/output devices
413, 415 may be also utilized for reading recorded sensor data from
nonvolatile memory 417 at the termination of drilling operations
for the particular downhole drill bit, in order to facilitate the
analysis of the bits performance during drilling operation.
Alternatively, a wireline reception device may be lowered within
the drillstring during drilling operations to receive data which is
transmitted by input/output device 413, 415 in the form of
electromagnetic transmissions.
[0061] 4. EXEMPLARY USES OF RECORDED AND/OR PROCESSED DATA: One
possible use of this data is to determine whether the purchaser of
the downhole drill bit has operated the downhole drill bit in a
responsible manner; that is, in a manner which is consistent with
the manufacturer's instruction. This may help resolve conflicts and
disputes relating to the performance or failure in performance of
the downhole drill bit. It is beneficial for the manufacturer of
the downhole drill bit to have evidence of product misuse as a
factor which may indicate that the purchaser is responsible for
financial loss instead of the manufacturer. Still other uses of the
data include the utilization of the data to determine the
efficiency and reliability of particular downhole drill bit
designs. The manufacturer may utilize the data gathered at the
completion of drilling operations of a particular downhole drill
bit in order to determine the suitability of the downhole drill bit
for that particular drilling operation. Utilizing this data, the
downhole drill bit manufacturer may develop more sophisticated,
durable, and reliable designs for downhole drill bits. The data may
alternatively be utilized to provide a record of the operation of
the bit, in order to supplement resistivity and other logs which
are developed during drilling operations, in a conventional manner.
Often, the service companies which provide
measurement-while-drilling operations are hard pressed to explain
irregularities in the logging data. Having a complete record of the
operating conditions of the downhole drill bit during the drilling
operations in question may allow the provider of
measurement-while-drilli- ng services to explain irregularities in
the log data. Many other conventional or novel uses may be made of
the recorded data which either improve or enhance drilling
operations, the control over drilling operations, or the
manufacture, design and use of drilling tools.
[0062] 5. EXEMPLARY ELECTRONIC MEMORY: FIG. 5 is a block diagram
depiction of electronic memory utilized in the improved downhole
drill bit of the present invention to record data. Nonvolatile
memory 417 includes a memory array 421. As is known in the art,
memory array 421 is addressed by row decoder 423 and column decoder
425. Row decoder 423 selects a row of memory array 417 in response
to a portion of an address received from the address bus 409. The
remaining lines of the address bus 409 are connected to column
decoder 425, and used to select a subset of columns from the memory
array 417. Sense amplifiers 427 are connected to column decoder
425, and sense the data provided by the cells in memory array 421.
The sense amps provide data read from the array 421 to an output
(not shown), which can include latches as is well known in the art.
Write driver 429 is provided to store data into selected locations
within the memory array 421 in response to a write control
signal.
[0063] The cells in the array 421 of nonvolatile memory 417 can be
any of a number of different types of cells known in the art to
provide nonvolatile memory. For example, EEPROM memories are well
known in the art, and provide a reliable, erasable nonvolatile
memory suitable for use in applications such as recording of data
in wellbore environments. Alternatively, the cells of memory array
421 can be other designs known in the art, such as SRAM memory
arrays utilized with battery back-up power sources.
[0064] 6. SELECTION OF SENSORS: In accordance with the present
invention, one or more operating condition sensors are carried by
the production downhole drill bit, and are utilized to detect a
particular operating condition. The preferred technique for
determining which particular sensors are included in the production
downhole drill bits will now be described in detail with reference
to FIG. 7 wherein the process begins at step 171.
[0065] In accordance with the present invention, as shown in step
173, a plurality of operating condition sensors are placed on at
least one test downhole drill bit. Preferably, a large number of
test downhole drill bits are examined. The test downhole drill bits
are then subjected to at least one simulated drilling operation,
and data is recorded with respect to time with the plurality of
operating condition sensors, in accordance with step 175. The data
is then examined to identify impending downhole drill bit failure
indicators, in accordance with step 177. Then, selected ones of the
plurality of operating condition sensors are selected for placement
in production downhole drill bits, in accordance with step 179.
Optionally, in each production downhole drill bit a monitoring
system may be provided for comparing data obtained during drilling
operations with particular ones of the impending downhole drill bit
failure indicators, in accordance with step 181. In one particular
embodiment, in accordance with step 185, drilling operations are
then conducted with the production downhole drill bit, and the
monitoring system is utilized to identify impending downhole drill
bit failure. Finally, and optionally, in accordance with steps 187
and 189 the data is telemetered uphole during drilling operations
to provide an indication of impending downhole drill bit failure
utilizing any one of a number of known, prior art or novel data
communications systems. Of course, in accordance with step 191,
drilling operations may be adjusted from the surface location
(including, but not limited to, the weight on bit, the rate of
rotation of the drillstring, and the mud weight and pump velocity)
in order to optimize drilling operations.
[0066] The types of sensors utilized during simulated drilling
operations are set forth in block diagram form in FIG. 6, and will
now be discussed in detail. Bit leg 80 may be equipped with strains
sensors 125 in order to measure axial strain, shear strain, and
bending strain. Bit leg 81 may likewise be equipped with strain
sensors 127 in order to measure axial strain, shear strain, and
bending strain. Bit leg 82 is also equipped with strain sensors 129
for measuring axial strain, shear strain, and bending strain.
[0067] Journal bearing 96 may be equipped with temperature sensors
131 in order to measure the temperature at the counterface of the
cone mouth, center, thrust face, and shirttail of the cantilevered
journal bearing 96; likewise, journal bearing 97 may be equipped
with temperature sensors 133 for measuring the temperature at the
counterface of the cone mouth, thrust face, and shirttail of the
cantilevered journal bearing 97; journal bearing 98 may be equipped
with temperature sensors 135 at the counterface of the cone mouth,
thrust face, and shirttail of cantilevered journal bearing 98 in
order to measure temperature at those locations. In alternative
embodiments, different types of bearings may be utilized, such as
roller bearings. Temperature sensors would be appropriately located
therein.
[0068] Lubrication system may be equipped with reservoir pressure
sensor 137 and pressure at seal sensor 139 which together are
utilized to develop a measurement of the differential pressure
across the seal of journal bearing 96. Likewise, lubrication system
85 may be equipped with reservoir pressure sensor 141 and pressure
at seal sensor 143 which develop a measurement of the pressure
differential across the seal at journal bearing 97. The same is
likewise true for lubrication system 86 which may be equipped with
reservoir pressure sensor 145 and pressure at seal sensor 147 which
develop a measurement of the pressure differential across the seal
of journal bearing 98.
[0069] Additionally, acceleration sensors 149 may be provided on
bit body 55 in order to measure the x-axis, y-axis, and z-axis
components of acceleration experienced by bit body 55.
[0070] Finally, ambient pressure sensor 151 and ambient temperature
sensor 153 may be provided to monitor the ambient pressure and
temperature of wellbore 1. Additional sensors may be provided in
order to obtain and record data pertaining to the wellbore and
surrounding formation, such as, for example and without limitation,
sensors which provide an indication about one or more electrical or
mechanical properties of the wellbore or surrounding formation.
[0071] The overall technique for establishing an improved downhole
drill bit with a monitoring system was described above in
connection with FIG. 7. When the test bits are subjected to
simulated drilling operations, in accordance with step 175 of FIG.
7, and data from the operating condition sensors is recorded.
Utilizing the particular sensors depicted in block diagram in FIG.
6, information relating to the strain detected at bit legs 80, 81,
and 82 will be recorded. Additionally, information relating to the
temperature detected at journal bearings 96, 97, and 98 will also
be recorded. Furthermore, information pertaining to the pressure
within lubrication systems 84, 85, 86 will be recorded. Information
pertaining to the acceleration of bit body 55 will be recorded.
Finally, ambient temperature and pressure within the simulated
wellbore will be recorded.
[0072] 7. EXEMPLARY FAILURE INDICATORS: The collected data may be
examined to identify indicators for impending downhole drill bit
failure. Such indicators include, but are not limited to, some of
the following:
[0073] (1) a seal failure in lubrication systems 84, 85, or 86 will
result in a loss of pressure of the lubricant contained within the
reservoir; a loss of pressure at the interface between the
cantilevered journal bearing and the rolling cone cutter likewise
indicates a seal failure;
[0074] (2) an elevation of the temperature as sensed at the
counterface of the cone mouth, center, thrust face, and shirttail
of journal bearings 96, 97, or 98 likewise indicates a failure of
the lubrication system, but may also indicate the occurrence of
drilling inefficiencies such as bit balling or drilling motor
inefficiencies or malfunctions;
[0075] (3) excessive axial, shear, or bending strain as detected at
bit legs 80, 81, or 82 will indicate impending bit failure, and in
particular will indicate physical damage to the rolling cone
cutters;
[0076] (4) irregular acceleration of the bit body indicates a
cutter malfunction.
[0077] The simulated drilling operations are preferably conducted
using a test rig, which allows the operator to strictly control all
of the pertinent factors relating to the drilling operation, such
as weight on bit, torque, rotation rate, bending loads applied to
the string, mud weights, temperature, pressure, and rate of
penetration. The test bits are actuated under a variety of drilling
and wellbore conditions and are operated until failure occurs. The
recorded data can be utilized to establish thresholds which
indicate impending bit failure during actual drilling operations.
For a particular downhole drill bit type, the data is assessed to
determine which particular sensor or sensors will provide the
earliest and clearest indication of impending bit failure. Those
sensors which do not provide an early and clear indication of
failure will be discarded from further consideration. Only those
sensors which provide such a clear and early indication of
impending failure will be utilized in production downhole drill
bits. Step 177 of FIG. 7 corresponds to the step of identifying
impending downhole drill bit failure indicators from the data
amassed during simulated drilling operations.
[0078] Field testing may be conducted to supplement the data
obtained during simulated drilling operations, and the particular
operating condition sensors which are eventually placed in
production downhole drill bits may be selected based upon a
combination of the data obtained during simulated drilling
operations and the data obtained during field testing. In either
event, in accordance with step 179 of FIG. 7, particular ones of
the operating condition sensors are included in a particular type
of production downhole drill bit. Then, a monitoring system is
included in the production downhole drill bit, and is defined or
programmed to continuously compare sensor data with a
pre-established threshold for each sensor.
[0079] For example, and without limitation, the following types of
thresholds can be established:
[0080] (1) maximum and minimum axial, shear, and/or bending strain
may be set for bit legs 80, 81, or 82;
[0081] (2) maximum temperature thresholds may be established from
the simulated drilling operations for journal bearings 96, 97, or
98;
[0082] (3) minimum pressure levels for the reservoir and/or seal
interface may be established for lubrication systems 84, 85, or
86;
[0083] (4) maximum (x-axis, y-axis, and/or z-axis) acceleration may
be established for bit body 55.
[0084] In particular embodiments, the temperature thresholds set
for journal bearings 96, 97, or 98, and the pressure thresholds
established for lubrication systems 84, 85, 86 may be relative
figures which are established with respect to ambient pressure and
ambient temperature in the wellbore during drilling operations as
detected by ambient pressure sensor 151 and temperature sensor 153
(both of FIG. 6). Such thresholds may be established by providing
program instructions to a controller which is resident within
improved downhole drill bit 26, or by providing voltage and current
thresholds for electronic circuits provided to continuously or
intermittently compare data sensed in real time during drilling
operations with pre-established thresholds for particular sensors
which have been included in the production downhole drill bits. The
step of programming the monitoring system is identified in the
flowchart of FIG. 7 as steps 181, 183.
[0085] Then, in accordance with step 185 of FIG. 7, drilling
operations are performed and data is monitored to detect impending
downhole drill bit failure by continuously comparing data
measurements with pre-established and predefined thresholds (either
minimum, maximum, or minimum and maximum thresholds or patterns in
the measurements). Then, in accordance with step 187 of FIG. 7,
information is communicated to a data communication system such as
a measurement-while-drilling telemetry system. Next, in accordance
with step 189 of FIG. 7, the measurement-while-drilling telemetry
system is utilized to communicate data to the surface. The drilling
operator monitors this data and then adjusts drilling operations in
response to such communication, in accordance with step 191 of FIG.
7.
[0086] The potential alarm conditions may be hierarchically
arranged in order of seriousness, in order to allow the drilling
operator to intelligently respond to potential alarm conditions.
For example, loss of pressure within lubrication systems 84, 85, or
86 may define the most severe alarm condition. A secondary
condition may be an elevation in temperature at journal bearings
96, 97, 98. Finally, an elevation in strain in bit legs 80, 81, 82
may define the next most severe alarm condition. Bit body
acceleration may define an alarm condition which is relatively
unimportant in comparison to the others. In one embodiment of the
present invention, different identifiable alarm conditions may be
communicated to the surface to allow the operator to exercise
independent judgement in determining how to adjust drilling
operations. In alternative embodiments, the alarm conditions may be
combined to provide a composite alarm condition which is composed
of the various available alarm conditions. For example, an arabic
number between 1 and 10 may be communicated to the surface with 1
identifying a relatively low level of alarm, and 10 identifying a
relatively high level of alarm. The various alarm components which
are summed to provide this single numerical indication of alarm
conditions may be weighted in accordance with relative importance.
Under this particular embodiment, a loss of pressure within
lubrication systems 84, 85, or 86 may carry a weight two or three
times that of other alarm conditions in order to weight the
composite indicator in a manner which emphasizes those alarm
conditions which are deemed to be more important than other alarm
conditions.
[0087] The types of responses available to the operator include an
adjustment in the weight on bit, the torque, the rotation rate
applied to the drillstring, and the weight of the drilling fluid
and the rate at which it is pumped into the drillstring. The
operator may alter the weight of the drilling fluid by including or
excluding particular drilling additives to the drilling mud.
Finally, the operator may respond by pulling the string and
replacing the bit. A variety of other conventional operator options
are available. After the operator performs the particular
adjustments, the process ends in accordance with step 193.
[0088] 8. EXEMPLARY SENSOR PLACEMENT AND FAILURE THRESHOLD
DETERMINATION: FIGS. 8A through 8H depict sensor placement in the
improved downhole drill bit 26 of the present invention with
corresponding graphical presentations of exemplary thresholds which
may be established with respect to each particular operating
condition being monitored by the particular sensor.
[0089] FIGS. 8A and 8B relate to the monitoring of pressure in
lubrication systems of the improved downhole drill bit 26. As is
shown, pressure sensor 201 communicates with compensator 85 and
provides an electrical signal through conductor 205 which provides
an indication of the amplitude of the pressure within compensator
85. Conductor path 203 is provided through downhole drill bit 26 to
allow the conductor to pass to the monitoring system carried by
downhole drill bit 26. This measurement may be compared to ambient
pressure to develop a measurement of the pressure differential
across the seal. FIG. 8B is a graphical representation of the
diminishment of pressure amplitude with respect to time as the seal
integrity of compensator 85 is impaired. The pressure threshold Pr
is established. Once the monitoring system determines that the
pressure within compensator 85 falls below this pressure threshold,
an alarm condition is determined to exist.
[0090] FIG. 8C depicts the placement of temperature sensors 207
relative to cantilevered journal bearing 97. Temperature sensors
207 are located at the counterface of the cone mouth, shirttail,
center, and thrust face of journal bearing 97, and communicate
electrical signals via conductor 209 to the monitoring system to
provide a measure of either the absolute or relative temperature
amplitude. When relative temperature amplitude is provided, this
temperature is computed with respect to the ambient temperature of
the wellbore. Conductor path 211 is machined within downhole drill
bit 26 to allow conductor 209 to pass to the monitoring system.
FIG. 8D graphically depicts the elevation of temperature amplitude
with respect to time as the lubrication system for journal bearing
97 fails. A relative temperature threshold T.sub.T is established
to define the alarm condition. Temperatures which rise above the
sum of the temperature threshold T.sub.T and the bottom-hole
temperature trigger an alarm condition.
[0091] FIG. 8E depicts the location of strain sensors 213 relative
to downhole drill bit 26. Strain sensors 213 communicate at least
one signal which is indicative of at least one of axial strain,
shear strain, and/or bending strain via conductors 215. These
signals are provided to a monitoring system. Pathway 217 (which is
shown in simplified form to facilitate discussion, but which is
shown in the preferred location elsewhere in this application) is
defined within downhole drill bit 26 to allow for conductors 215 to
pass to the monitoring system. The most likely location of the
strain sensors 213 to optimize sensor discrimination is region 88
of FIG. 8E, but this can be determined experimentally in accordance
with the present invention. FIG. 8F is graphical representation of
strain amplitude with respect to time for a particular one of axial
strain, shear strain, and/or bending strain. As is shown, a strain
threshold ST may be established. Strain which exceeds the strain
threshold triggers an alarm condition.
[0092] FIG. 8G provides a representation of acceleration sensors
219 which provide an indication of the x-axis, y-axis, and/or
z-axis acceleration of bit body 55. Conductors 221 pass through
passage 223 to monitoring system 225. FIG. 8H provides a graphical
representation of the acceleration amplitude with respect to time.
An acceleration threshold AT may be established to define an alarm
condition. When a particular acceleration exceeds the amplitude
threshold, an alarm condition is determined to exist.
[0093] While not depicted, the improved downhole drill bit 26 of
the present invention may further include a pressure sensor for
detecting ambient wellbore pressure, and a temperature sensor for
detecting ambient wellbore temperatures. Data from such sensors
allows for the calculation of a relative pressure threshold or a
relative temperature threshold.
[0094] 9. OVERVIEW OF OPTIONAL MONITORING SYSTEM: FIG. 9 is a block
diagram depiction of monitoring system 225 which is optionally
carried by improved downhole drill bit 26. Monitoring system 225
receives real-time data from sensors 226, and subjects the analog
signals to signal conditioning such as filtering and amplification
at signal conditioning block 227. Then, monitoring system 225
subjects the analog signal to an analog-to-digital conversion at
analog-to-digital converter 229. The digital signal is then
multiplexed at multiplexer 231 and routed as input to controller
233. The controller continuously compares the amplitudes of the
data signals (and, alternatively, the rates of change) to
pre-established thresholds which are recorded in memory. Controller
233 provides an output through output driver 235 which provides a
signal to communication system 237. In one preferred embodiment of
the present invention, downhole drill bit 26 includes a
communication system which is suited for communicating of either
one or both of the raw data or one or more warning signals to a
nearby subassembly in the drill collar. Communication system 237
would then be utilized to transmit either the raw data or warning
signals a short distance through either electrical signals,
electromagnetic signals, or acoustic signals. One available
technique for communicating data signals to an adjoining
subassembly in the drill collar is depicted, described, and claimed
in U.S. Pat. No. 5,129,471 which issued on Jul. 14, 1992 to Howard,
which is entitled "Wellbore Tool With Hall Effect Coupling", which
is incorporated herein by reference as if fully set forth.
[0095] In accordance with the present invention, the monitoring
system includes a predefined amount of memory which can be utilized
for recording continuously or intermittently the operating
condition sensor data. This data may be communicated directly to an
adjoining tubular subassembly, or a composite failure indication
signal may be communicated to an adjoining subassembly. In either
event, substantially more data may be sampled and recorded than is
communicated to the adjoining subassemblies for eventual
communication to the surface through conventional mud pulse
telemetry technology. It is useful to maintain this data in memory
to allow review of the more detailed readings after the bit is
retrieved from the wellbore. This information can be used by the
operator to explain abnormal logs obtained during drilling
operations. Additionally, it can be used to help the well operator
select particular bits for future runs in the particular well.
[0096] 10. UTILIZATION OF THE PRESENT INVENTION IN FIXED CUTTER
DRILL BITS: The present invention may also be employed with
fixed-cutter downhole drill bits. FIG. 10 is a perspective view of
an earth-boring bit 511 of the fixed-cutter variety embodying the
present invention. Bit 511 is threaded 513 at its upper extent for
connection into a drillstring. A cutting end 515 at a generally
opposite end of bit 511 is provided with a plurality of natural or
synthetic diamond or hard metal cutters 517, arranged about cutting
end 515 to effect efficient disintegration of formation material as
bit 511 is rotated in a borehole. A gage surface 519 extends
upwardly from cutting end 515 and is proximal to and contacts the
sidewall of the borehole during drilling operation of bit 511. A
plurality of channels or grooves 521 extend from cutting end 515
through gage surface 519 to provide a clearance area for formation
and removal of chips formed by cutters 517.
[0097] A plurality of gage inserts 523 are provided on gage surface
519 of bit 511. Active, shear cutting gage inserts 523 on gage
surface 519 of bit 511 provide the ability to actively shear
formation material at the sidewall of the borehole to provide
improved gage-holding ability in earth-boring bits of the fixed
cutter variety. Bit 511 is illustrated as a PDC ("polycrystalline
diamond compact") bit, but inserts 523 are equally useful in other
fixed cutter or drag bits that include a gage surface for
engagement with the sidewall of the borehole.
[0098] FIG. 11 is a fragmentary longitudinal section view of
fixed-cutter downhole drill bit 511 of FIG. 10, with threads 513
and a portion of bit body 525 depicted. As is shown, central bore
527 passes centrally through fixed-cutter downhole drill bit 511.
As is shown, monitoring system 529 is disposed in cavity 530. A
conductor 531 extends downward through cavity 533 to accelerometers
535 which are provided to continuously measure the x-axis, y-axis,
and/or z-axis components of acceleration of bit body 525.
Accelerometers 535 provide a continuous measure of the
acceleration, and monitoring system 529 continuously compares the
acceleration to predefined acceleration thresholds which have been
predetermined to indicate impending bit failure. For fixed-cutter
downhole drill bits, whirl and stick-and-slip movement of the bit
places extraordinary loads on the bit body and the PDC cutters,
which may cause bit failure. The excessive loads cause compacts to
become disengaged from the bit body, causing problems similar to
those encountered when the rolling cones of a downhole drill bit
are lost. Other problems associated with fixed cutter drill bits
include bit "wobble" and bit "walking", which are undesirable
operating conditions.
[0099] Fixed cutter drill bits differ from rotary cone rock bits in
that rather complicated steering and drive subassemblies (such as a
Moineau principle mud motor) are commonly closely associated with
fixed cutter drill bits, and are utilized to provide for more
precise and efficient drilling, and are especially useful in a
directional drilling operation.
[0100] In such configurations, it may be advantageous to locate the
memory and processing circuit components in a location which is
proximate to the fixed cutter drill bit, but not actually in the
drill bit itself. In these instances, a hardware communication
system may be adequate for passing sensor data to a location within
the drilling assembly for recordation in memory and optional
processing operations.
[0101] 11. OPTIMIZING TEMPERATURE SENSOR DISCRIMINATION: In the
present invention, an improved drill bit is provided which
optimizes temperature sensor discrimination. This feature will be
described with reference to FIGS. 12 through 14. FIG. 12 depicts a
longitudinal section view of bit head 611 of improved drill bit 609
shown relative to a centerline 613 of the improved drill bit 609.
In a tri-cone rock bit, the bit body will be composed of three bit
heads which are welded together. In order to enhance the clarity of
this description, only a single bit head 611 is depicted in FIG.
12.
[0102] When the bit head are welded together, an external threaded
coupling is formed at the upper portion 607 of the bit heads of
improved drill bit 609. The manufacturing process utilized in the
present invention to construct the improved drill bit is similar in
some respects to the conventional manufacturing process, but is
dissimilar in other respects to the conventional manufacturing
process. In accordance with the present invention, the steps of the
present invention utilized in forging bit head 611 are the
conventional forging steps. However, the machining and assembly
steps differ from the state-of-the-art as will be described
herein.
[0103] As is shown in FIG. 12, bit head 611 includes at its lower
end head bearing 615 with bearing race 617 formed therein.
Together, head bearing 615 and bearing race 617 are adapted for
carrying a rolling cone cutter, and allowing rotary motion during
drilling operations of the rolling cone cutter relative to head
bearing 615 as is conventional. Furthermore, bit head 611 is
provided with a bit nozzle 619 which is adapted for receiving
drilling fluid from the drilling string and jetting the drilling
fluid onto the cutting structure to cool the bit and to clean the
bit.
[0104] In accordance with the preferred embodiment of the
manufacturing process of the present invention, four holes are
machined into bit head 611. These holes are not found in the prior
art. These holes are depicted in phantom view in FIG. 12 and
include a tri-tube wire 621, a service bay 625, a wire way 629, and
a temperature sensor well 635. The tri-tube wire 621 is
substantially orthogonal to centerline 613. The tri-tube wire 621
is slightly enlarged at opening 623 in order to accommodate
permanent connection to a fluid-impermeable tube as will be
discussed below. Tri-tube wire way 621 communicates with service
bay 625 which is adapted for receiving and housing the electronic
components and associated power supply in accordance with the
present invention. A service bay port 627 is provided to allow
access to service bay 625. In accordance with the present
invention, a cap is provided to allow for selective access to
service bay 625. The cap is not depicted in this view but is
depicted in FIG. 19. Service bay 625 is communicatively coupled
with wire way 629 which extends downward and outward, and which
terminates approximately at a midpoint on the centerline 614 of the
head bearing 615. Temperature sensor well 635 extends downward from
wire way 629. The temperature sensor well is substantially aligned
with centerline 614 of bearing head 615. Temperature sensor well
635 terminates in a position which is intermediate shirttail 633
and the outer edge 636 of head bearing 615. A temporary access port
631 is provided at the junction of wire way 629 and temperature
sensor well 635. After assembly, temporary access port 631 is
welded closed.
[0105] The location of temperature sensor well 635 was determined
after empirical study of a variety of potential locations for the
temperature sensor well. The empirical process of determining a
position for a temperature sensor well which optimizes sensor
discrimination of temperature changes which are indicative of
possible bit failure will now be described in detail. The goal of
the empirical study was to locate a temperature sensor well in a
position within the bit head which provides the physical equivalent
of a "low pass" filter between the sensor and a source of heat
which may be indicative of failure. The "source" of heat is the
bearing assembly which will generate excess heat if the seal and/or
lubrication system is impaired during drilling operations.
[0106] During normal operations in a wellbore, the drill bit is
exposed to a variety of transients which have some impact upon the
temperature sensor. Changes in the temperature in the drill bit due
to such transients are not indicative of likely bit failure. The
three most significant transients which should be taken into
account in the bit design are:
[0107] (1) temperature transients which are produced by the rapid
acceleration and deceleration of the rock bit due to "bit bounce"
which occurs during drilling operations;
[0108] (2) temperature transients which are associated with changes
in the rate of rotation of the drill string which are also
encountered during drilling operations; and
[0109] (3) temperature transients which are associated with changes
in the rate of flow of the drilling fluid during drilling
operations.
[0110] The empirical study of the drill bit began (in Phase I) with
an empirical study of the drilling parameter space in a laboratory
environment. During this phase of testing, the impact on
temperature sensor discrimination due to changes in weight on bit,
the drilling rate, the fluid flow rate, and the rate of rotation
were explored. The model that was developed of the drill bit during
this phase of the empirical investigation was largely a static
model. A drilling simulator cannot emulate the dynamic field
conditions which are likely to be encountered by the drill bit.
[0111] In the next phase of the study (Phase II) a rock bit was
instrumented with a recording sub. During this phase, the drilling
parameter space (weight on bit, drilling rate, rate of rotation of
the string, and rate of fluid flow) was explored in combination
with the seal condition over a range of seal conditions,
including:
[0112] (1) conditions wherein no seal was provided between the
rolling cone cutter and the head bearing;
[0113] (2) conditions wherein a notched seal was provided at the
interface of the rolling cone cutter and the head bearing;
[0114] (3) conditions wherein a worn seal was provided between the
rolling cone cutter and the head bearing; and
[0115] (4) conditions wherein a new seal was provided between the
interface of the rolling cone cutter and the head bearing.
[0116] Of course, seal condition number 1 represents an actual
failure of the bit, while seal condition numbers 2 and 3 represent
conditions of likely failure of the bit, and seal condition number
4 represents a properly functioning drill bit.
[0117] During the empirical study, an instrumented test bit was
utilized in order to gather temperature sensor information which
was then analyzed to determine the optimum location for a
temperature sensor for the purpose of determining the bit condition
from temperature sensor data alone. In other words, a location for
a temperature sensor cavity was determined by determining the
discrimination ability of particular temperature sensor locations,
under the range of conditions representative of the drilling
parameter space and the seal condition.
[0118] During testing a bit head was provided with temperature
sensors in various test positions including:
[0119] (1) a shirttail cavity--the axially-oriented sensor well was
drilled such that its centerline was roughly contained in the plane
formed by the centerlines of the bit and the bearing with its tip
approximately centered between the base of the seal gland and the
shirttail O.D. surface;
[0120] (2) a pressure side cavity--the pressure side well was
located similarly to the shirttail well with one exception; its tip
was located just near the B4 hardfacing/base metal interface
nearest the cone mouth;
[0121] (3) a centerline cavity--the center well was located
similarly to the previous two with one exception; its tip was
located on the bearing centerline approximately midway between the
thrust face and the base of the bearing pin;
[0122] (4) a thrust face cavity--the thrust face well was located
similarly to the previous three with one exception; the tip was
located near the B4 hardfacing/base metal interface near thrust
face on the pressure side.
[0123] The shirttail, by design, is not intended to contact the
borehole wall during drilling operations, hence the temperature
detected from this position tends to "track" the temperature of the
drilling mud, and the position does not provide the best
temperature sensor discrimination.
[0124] The empirical study determined that the pressure side cavity
was not an optimum location due to the fact that it was cooled by
the drilling mud flowing through the annulus, and thus was not a
good location for discriminating likely bit failure from
temperature data alone. In tests, the sensor located in the
pressure side cavity observed little difference in measurement as
the seal parameter space was varied; in particular, there was
little discrimination between effective and removed seals. The
thrust face cavity was determined to be too sensitive to transients
such as axial acceleration and deceleration due to bit bounce, and
thus would not provide good temperature sensor discrimination for
detection of impending or likely bit failure. The shirttail cavity
was empirically determined not to provide a good indication of
likely bit failure as it was too sensitive to ambient wellbore
temperature to provide a good indication of likely bit failure. The
empirical study determined that the centerline cavity is the
optimum sensor location for optimum temperature sensor
discrimination of likely bit failure from temperature data
alone.
[0125] FIG. 13 is a partial longitudinal section view of an
unfinished (not machined) bit head 611 which graphically depicts
the position of temperature sensor well 635 relative to centerline
613 and datum plane 630 which is perpendicular thereto. As is
shown, temperature sensor well 635 is parallel to a line which is
disposed at an angle from datum plane 630 which is perpendicular to
centerline 613. The angle is 210 and 14 minutes from datum plane
line 630. The dimensions of temperature sensor well (including its
diameter and length) can be determined from the dimensions of FIG.
13. This layout represents the preferred embodiment of the present
invention, and the preferred location for the temperature sensor
well which has been empirically determined (as discussed above) to
optimize temperature sensor discrimination of impending or likely
bit failure under the various steady state and transient operating
conditions that the bit is likely to encounter during actual
drilling operations. It is also important to note that the sensor
well position will vary with the bit size. The preferred embodiment
is a 91/2 inch drill bit.
[0126] In accordance with preferred embodiment of the present
invention, the temperature sensor that is utilized to detect
temperature within the improved drill bit is a resistance
temperature device. In the preferred embodiment, a resistance
temperature device is positioned in each of the three bit heads in
the position which has been determined to provide optimal
temperature sensor discrimination.
[0127] FIG. 14 is a graphical depiction of the measurements made
while utilizing the thermistor temperature sensors for a three-leg
rolling cutter rock bit. In this view, the x-axis is representative
of time in units of hours, while the y-axis is representative of
relative temperature in units of degrees Fahrenheit. As is shown,
graph 660 represents the relative temperature in the service bay
635 (of FIG. 12), while graph 662 represents the relative
temperature in head number one, graph 664 represents the relative
temperature of head number two, and graph 666 represents the
relative temperature of head three. As is shown in the view of FIG.
14, the relative temperature in bit head two is substantially
elevated relative to the temperatures of the other bit heads,
indicating a possible mechanical problem with the lubrication or
bearing systems of bit head number two.
[0128] 12. USE OF A TRI-TUBE ASSEMBLY FOR CONDUCTOR ROUTING WITHIN
A DRILL BIT: In the preferred embodiment of the present invention,
a novel tri-tube assembly is utilized to allow for the electrical
connection of the various electrical components carried by the
improved drill bit. This is depicted in simplified plan view in
FIG. 15. This figure shows the various wire pathways within a
tri-cone rock bit constructed in accordance with the present
invention. As is shown, bit head 611 includes a temperature sensor
well 635, which is connected to wire pathway 629, which is
connected to service bay 625. Service bay 625 is connected to
tri-tube assembly 667 through tri-tube wire way 621. The other bit
heads are similarly constructed. Temperature sensor well 665 is
connected to wire pathway 663, which is connected to service bay
661; service bay 661 is connected through tri-tube wire pathway 659
to the tri-tube assembly 667. Likewise, the last bit head includes
temperature sensor well 657 which is connected to wire pathway 655,
which is connected to service bay 653. Service bay 653 is connected
to tri-tube wire pathway 651 which is connected to the tri-tube
assembly.
[0129] As is shown in the view of FIG. 15, tri-tube assembly
includes a plurality of fluid-impermeable tubes which allow
conductors to pass between the bit heads. In the view of FIG. 15,
tri-tube assembly 667 includes fluid-impermeable tubes 671, 673,
675. These fluid-impermeable tubes 671, 673, 675 are connected
together through tri-tube connector 669.
[0130] In the preferred embodiment of the present invention, the
fluid-impermeable tubes 671, 673, 675 are butt-welded to the heads
of the improved rock bit. Additionally, the fluid-impermeable tubes
671, 673, 675 are welded and sealed to tri-tube connectors 669. In
this configuration, electrical conductors may be passed between the
bit heads through the tri-tube assembly 667. The details of the
preferred embodiment of the tri-tube assembly are depicted in FIGS.
16, 17, and 18. In the view of FIG. 16, the tri-tube wire way 621
is depicted in cross-section view. As is shown, it has a diameter
of 0.191 inches. The tri-tube wire pathway 621 terminates at a
beveled triad hole 691 which has a larger cross-sectional diameter.
The fluid-impermeable tube is butt-welded in place within the
beveled triad hole.
[0131] FIG. 17 is a pictorial representation of the tri-tube
assembly 667. As is shown therein, the fluid-impermeable tubes 671,
673, 675 are connected to triad coupler 669. As is shown, the
fluid-impermeable tubes are substantially angularly equidistant
from adjoining fluid-impermeable tube members. In the configuration
shown in FIG. 17, the fluid-impermeable tubes 671, 673, 675 are
disposed at 120.degree. angles from adjoining fluid-impermeable
tubes.
[0132] FIG. 18 is a pictorial representation of coupler 669. As is
shown, three mating surfaces are provided with orifices adapted in
size and shape to accommodate the fluid-impermeable tubes 671, 673,
675. In accordance with the present invention, the
fluid-impermeable tubes 671, 673, 675 may be welded in position
relative to coupler 669.
[0133] FIG. 19 is a pictorial representation of service bay cap
697. As is shown, service bay cap 697 is adapted in size and shape
to cover the service bay openings (such as openings 627). As is
shown, a threaded port 699 is provided within service bay cap 697.
During assembly operations, a switch or electrical wire passes
through threaded port 699 to allow an electrical component to be
accessible from the exterior of the improved drill bit. A conductor
or leads for a switch are routed through an externally-threaded
pipe plug 700 which is utilized to fill threaded port 699, as will
be discussed below.
[0134] FIG. 20 is a block diagram and schematic depiction of the
wiring of the preferred embodiment of the present invention. As is
shown, bit legs 710, 712, 714 carry temperature sensors 716, 718,
720. An electronics module 742 is provided in bit leg 710. Three
conductors are passed between bit leg 710 and bit leg 712.
Conductors 726, 728 are provided for providing the output of
temperature sensor 718 to electronic module 742. Conductor 736 is
provided as a battery lead (+). A single conductor 734 is provided
between bit leg 712 and bit leg 714: conductor 734 is provided as a
battery lead (series) for temperature sensors 718, 720. Three
conductors are provided between bit leg 710 and bit leg 714.
Conductors 730, 732 provide sensor data to electronics module 742.
Conductor 738 provides a battery lead (-) between sensors 716, 720.
In accordance with the present invention, conductors 726, 728, 736,
734, 730, 732, and 738 are routed between bit legs 710, 712, 714,
through the tri-tube assembly discussed above. A plurality of leads
746, 748 are provided to allow testing of the electronics and
retrieval of stored data.
[0135] In accordance with the present invention, the electrical
components carried by electronics module 742 are maintained in a
low power consumption mode of operation until the bit is lowered
into the wellbore. A starting loop 744 is provided which is
accessible from the exterior of the bit (and which is routed
through the service bay cap, and in particular through the pipe
plug 700 of service bay cap 697 of FIG. 19). Once the wire loop 744
is cut, the electronic components carried on electronics module 742
are switched between a low power consumption mode of operation to a
monitoring mode of operation. This preserves the battery and allows
for a relatively long shelf life for the improved rock bit of the
present invention. As an alternative to the wire loop 744, any
conventional electrical switch may be utilized to switch the
electronic components carried by electronic module 742 from a low
power consumption mode of operation to a monitoring mode of
operation.
[0136] For example, FIG. 23 is a cross-section depiction of the
pressure-actuated switch 750 which may be utilized instead of the
wire loop 744 of FIG. 20. As is shown, the pair of electrical leads
751 terminate at pressure switch housing 752 which capulates and
protects the electrical components contained therein. As is shown,
conductive layers 753, 754 are disposed on opposite sides of
conductor 755. The leads 751 are electrically connected at coupling
756 to conductor 753, 754. Spaces 757, 758 are provided between
conductors 755 and conductor 753, 754. Applying pressure to switch
housing 752 will cause conductors 753, 754, 755 to come together
and complete the circuit through leads 751.
[0137] FIG. 24 is a simplified cross-section view of an alternative
switch which may be utilized in conjunction with an alternative
embodiment of the present invention. As is shown, the switch 1421
is adapted to be secured by fasteners 1435, 1437 in cavity 1439
which is formed in the cap of the service bay. Switch 1421 includes
a switch housing 1423 which surrounds a cavity 1425 which is
maintained at atmospheric pressure. Within the housing 1423 are
provided switch contacts 1427, 1429 which are coupled to electrical
leads 1431, 1433. When the device is maintained at atmospheric
pressure, the switch contacts 1427, 1429 are maintained out of
contact from one another; however, when the device is lowered into
a wellbore where the ambient pressure is elevated, the pressure
deforms housing 1423, causing switch contacts 1427, 1429 to come
into mating and electrical contact. Utilization of this pressure
sensitive switch mechanism ensures that the electronic components
of the present invention are not powered-up until the device is
lowered into the wellbore and is exposed to a predetermined ambient
pressure which is preferably far higher than pressures encountered
at the surface locations of the oil and gas properties.
[0138] In accordance with the present invention, each of the
temperature sensors in the bit legs is encased in a plastic
material which allows for load and force transference in the rock
bit through the plastic material, and also for the conduction of
tests. This is depicted in simplified form in FIG. 22, wherein
temperature sensor 716 (of bit leg one) is encapsulated in
cylindrical plastic 762. The leads 722 and 724, which communicate
with temperature sensor 716, are accessible from the upper end of
capsule 762.
[0139] One important advantage of the present invention is that the
temperature monitoring system is not in communication with any of
the lubrication system components. Accordingly, the temperature
monitoring system of the present invention can fail entirely,
without having any adverse impact on the operation of the bit. In
order to protect the electrical and electronic components of the
temperature sensing system of the present invention from the
adverse affects of the high temperatures, high pressures, and
corrosive fluids of the wellbore group drilling operations, the
cavities are sealed, evacuated, filled with a potting material, all
of which serve to protect the electrical and electronic components
from damage.
[0140] The sealing and potting steps are graphically depicted in
FIG. 21. As is shown, a vacuum source 770 is connected to the
cavities of bit leg one. The access ports for bit legs two and
three are sealed, and the contents of the cavities in the bit are
evacuated for pressure testing. The objective of the pressure
testing is to hold 30 milliTor of vacuum for one hour. If the
improved rock bit of the present invention can pass this pressure
vacuum test, a source of potting material (preferably Easy Cast 580
potting material) is supplied first to bit leg three, then to bit
leg two, as the vacuum source 770 is applied to bit leg one. The
vacuum force will pull the potting material through the conductor
paths and service bays of the rock bit of the present invention.
Then, the service bays of the bit legs are sealed, ensuring that
the temperature sensor cavities, wire pathways, and service bays of
the improved bit of the present invention are maintained at
atmospheric pressure during drilling operations.
[0141] 13. PREFERRED MANUFACTURING PROCEDURES: FIG. 25 is a flow
chart representation of the preferred manufacturing procedure of
the present invention. The process commences at block 801, and
continues at block 803, wherein the tri-tubes are placed in
position relative to the bit leg forgings. Next, in accordance with
block 805, the bit leg forgings are welded together. Then, in
accordance with block 807, the tri-tubes are butt-welded in place
relative to the bit leg assembly through the service bays. Then, in
accordance with block 809, the conductors are routed through the
bit and tri-tube assembly, as has been described in detail above.
Then, in accordance with block 811, the temperature sensors are
potted in a thermally conductive material. Next, in accordance with
block 813, the temperature sensors are placed in the temperature
sensor wells of the rock bit. Then, in accordance with block 815,
the temperature sensor leads are fed to the service bays. In
accordance with block 817, the temperature sensor leads are
soldered to the electronics module. Then in accordance with block
819, the electronics module is installed in the rock bit. Then in
accordance with block 821, the "starting loop" (loop 744 of FIG.
20) is pulled through a service bay cap. Next, in accordance with
block 823 the battery is connected to the electronics module. In
accordance with step 825, the service bay caps are installed. Then
in accordance with step 827, the assembly is pressure tested (as
discussed above in connection with FIG. 21). Then in accordance
with step 829, the pipe plugs are installed in the service bay
caps. Next, in accordance with step 831 the bit is filled with
potting material (as discussed in connection with FIG. 21). Then
the function of the assembly is tested in accordance with step 833,
and the process ends at step 835.
[0142] In the field, the improved rock bit of the present invention
is coupled to a drillstring. Before the bit is lowered into the
wellbore, the starting loop is cut, which switches the electronics
module from a low power consumption mode of operation to a
monitoring mode of operation. The bit is lowered into the wellbore,
and the formation is disintegrated to extend the wellbore, as is
conventional. During the drilling operations, the electronic
modules samples the temperature data and records the temperature
data. The data may be stored for retrieval at the surface after the
bit is pulled, or it may be utilized in accordance with the
monitoring system and/or communication system of the present
invention to detect likely bit failure and provide a signal which
warns the operator of likely bit failure.
[0143] 14. OVERVIEW OF THE ELECTRONICS MODULE: A brief overview of
the components and operation of the electronics module will be
provided with reference to FIGS. 26 and 27. In accordance with the
present invention, and as is shown in FIG. 26, the electronics
module of the present invention utilizes an oscillator 901 which
has its frequency of oscillation determined by a capacitor 903 and
a resistor 905. In accordance with the present invention, resistor
905 comprises the temperature sensor which is located in each bit
leg, and which varies its resistance with changes in temperature.
Accordingly, the frequency of oscillator 901 will vary with the
changes in temperature in the bit leg. The output of oscillator 901
is provided to a sampling circuit 907 and recording circuit 909
which determine and record a value which corresponds to the
oscillation frequency of oscillator 901, which in turn corresponds
to the temperature in the bit leg. Recording circuit 909 operates
to record these values in semiconductor memory 911.
[0144] FIG. 27 is a graphical representation of the relationship
between oscillator 901, capacitor 903 and resistor 905. In this
graph, the x-axis is representative of time, and the y-axis is
representative of amplitude of the output of oscillator 901. As is
shown, the frequency of oscillation is inversely proportional to
the product of the capacitance value for capacitor 903 and the
resistance value for resistor 905. As the value for resistor 905
(corresponding to the thermocouple temperature sensor) changes with
temperature, the oscillation frequency of oscillator 901 will
change. In FIG. 27, curve 917 represents the output of oscillator
901 for one resistance value, while curve 919 represents the output
of oscillator 901 for a different resistance value. Sampling
circuit 907 and recording circuit 909 can sample the frequency,
period, or zero-crossing of the output of oscillator 901 in order
to determine a value which can be mapped to temperature changes in
a particular bit leg. In accordance with the present invention,
since three different temperature sensors are utilized, a
multiplexing circuit must be utilized to multiplex the sensor data
and allow it to be sampled and recorded in accordance with the
present invention.
[0145] In accordance with the preferred embodiment of the present
invention, the monitoring, sampling and recording operations are
performed by a single application specific integrated circuit
(ASIC) which has been specially manufactured for use in wellbore
operations in accordance with a cooperative research and
development agreement (also known as a "CRADA") between Applicant
and Oak Ridge National Laboratory in Oak Ridge, Tenn. The details
relating to the construction, operation and overall performance of
this application specific integrated circuit are described and
depicted in detail in the enclosed paper by M. N. Ericson, D. E.
Holcombe, C. L. Britton, S. S. Frank, R. E. Lind, T. E. McKnight,
M. C. Smith and G. W. Turner, all of the Oak Ridge National
Laboratory, which is entitled An ASIC-Based Temperature Logging
Instrument Using Resistive Element Temperature Coefficient Timing.
A copy of a draft of this paper is attached hereto and incorporated
by reference as if fully set forth herein. The following is a
description of the basic operation of the ASIC, with reference to
FIGS. 30A through 30F, and quoting extensively from that paper.
[0146] A block diagram of the temperature-to-time converter
topology is shown in FIG. 29A. A step pulse 1511 is generated that
is differentiated using R.sub.1 and C.sub.1 resulting in pulse 1513
which is applied to amplifier 1515. The n-bit counter 1519 is
started from a reset state when the pulse is output. The
differentiated pulse is buffered and passed through another
differentiator formed by C.sub.2 and R.sub.sensor. This double
differentiation causes a bipolar pulse with a zero-crossing time
described by the equation shown in FIG. 29A, wherein {overscore
(o)}.sub.1 and {overscore (o)}.sub.2 are the time constants
associated with R.sub.1C.sub.1 and R.sub.sensorC.sub.2,
respectively. R.sub.sensor is a resistive sensor with a known
temperature coefficient. A zero-crossing comparator 1517 detects
the zero-crossing and outputs a stop signal to the counter 1519.
The final value of the counter is the digital representation of the
temperature. By proper selection of the timebase frequency, the
zero-crossing point is independent of signal amplitude thus
eliminating the need for a high accuracy voltage pulse source or
temperature stable power supply voltages. Additionally, any gain
stages used in the circuit are not required to have a precise gain
function over temperature.
[0147] As demonstrated in the equation of FIG. 29A, some
logarithmic compression is inherent in this measurement method
making it appropriate for wide-range measurements covering several
decades of resistance change. The resistance element type selection
will play a dominant role in both the measurement range and
resolution profile.
[0148] The circuit described in the previous section is integrated
into a measurement system in accordance with the present invention.
FIG. 29B outlines a block diagram of the system. This unit consists
of four front-end measurement channels 1521, 1523, 1525, 1527, a
digital controller 1529, two timebase circuits 1531, a startup
circuit 1533, a nonvolatile memory 1535, and power management
circuits 1537, 1539. The front end electronics were integrated onto
a single chip consisting of four measurement channels: three for
remote location temperature logging, and one for the electronics
unit temperature logging. The control for the system was integrated
onto another ASIC (HC_DC). The circuit was designed to allow for a
significant shelf life, both before and after use. Incorporation of
an "off" mode allows the unit to be installed and connected to a
battery while drawing less than 10{grave over (.sub.1)}A. Data
collection is initiated by breaking the startup loop (cutting the
wire in this case). The unit operates for 150 hours, taking samples
every 7.5 minutes, generating a 512 sample average for each
channel, and storing the average in a non-volatile memory 1529. A
sampling operation (generating a 512 sample average for each
channel) requires approximately 20 seconds. In the time between
taking samples (.about.410 seconds), the unit is placed in a
reduced power mode where the front end electronics 1521, 1523,
1525, 1527 are biased off, and the module sequencer 1541 only
counts the low frequency clock pulses. Two oscillator circuits are
used. A high frequency oscillator provides a 1 MHz clock for
counting the zero-crossing time. A low frequency oscillator
continuously running at 16 kHz provides the time base for the
system controller. After 150 hours of operation, the unit goes back
into sleep mode. Data is then retrieved at a later time from the
unit using the PC interface 1543. Using non-volatile memory 1529
allows years to retrieve the data and eliminates the need to
maintain unit power after data storage is completed.
[0149] The front end electronics consists of four identical
zero-crossing circuits 1551, 1553 (to simplify the description,
only two are shown) and a Vmid generator 1555, as shown in FIG.
29C. The output of the first differentiator 1557 is distributed to
all four channels. This signal is then buffered/amplified and
passed through another differentiator that produces the zero
crossing. A zero crossing comparator 1559, 1561 with .about.8 mV of
hysteresis produces a digital output when the signal crosses
through Vmid. Vmid is generated as the approximate midpoint between
Vdd and Vss using a simple resistance divider. Its value does not
have to be accurately generated and may drift with time and
temperature since each entire channel uses it as a reference.
Buffer amplifiers 1571, 1573, 1575, 1577 are used around each time
constant to prevent interaction.
[0150] The front end electronics were implemented as an ASIC and
functioned properly on first silicon. A second fabrication run was
submitted that incorporated two enhancements to improve the
measurement accuracy at long time constants and at elevated
temperatures. With large time constraints the zero crossing signal
can have a small slope making the zero crossing exhibit excessive
walk due to the hysteresis of the zero-crossing comparator.
Additionally, high impedance sensors result in a very shallow
crossing increasing susceptibility to induced noise. Gain was added
(3.times.) to increase both the slope and the depth of the
zero-crossing signal. At elevated temperatures, leakage currents
(dominated by pad protection leakage) and temperature dependent
opamp offsets add further error by adding a dc offset to the
zero-crossing signal. The autozero circuit 1581 shown in FIG. 29D
was also added to the original front end ASIC design to decrease
the effect of these measurement error sources. Consisting of a
simple switch and capacitor, the output voltage of the buffer
amplifier (which contains the offset errors associated with both
the buffer amplifier offset and the leakage current into the
temperature dependent resistive element) is stored on the capacitor
after the channel is biased "on" but before the start pulse is
issued. Microseconds before the start is issued the switch is
opened and the zero-crossing comparator references the
zero-crossing signal to the autozeroed value which effectively
eliminates the offset errors associated with the previous stage.
The ac coupling presented by each of the differentiators eliminates
the dc offsets from the input stages {overscore (o)}.sub.1,
provided the offset errors are not large enough to cause signal
limiting.
[0151] Low power operation is accomplished by providing an
individual bias control for each of the front end channels. This
allows the system controller to power down the entire front end
while in sleep mode, and power each channel separately in data
collection mode, thus keeping power consumption at a minimum. Since
the channels are biased "off" between measurements, leakage
currents can cause significant voltages to be generated at the
sensor node. This can be a problem when the sensor resistance is
large and can cause measurement delays when the channel is biased
"on" since time must be allowed for the node to discharge.
Incorporation of a low value resistor that can be switched in when
the channels are biased "off" (see R.sub.p0 and R.sub.p3 in Figure)
eliminated this difficulty.
[0152] All passive elements associated with {overscore (o)}1 and
{overscore (o)}2 were placed external to the ASIC due to the poor
tolerance control and high temperature coefficient of resistor
options available, and the poor tolerance control and limited value
range of double poly capacitors in standard CMOS processes. COG
capacitors were used for both {overscore (o)}1 and {overscore (o)}2
and a 1% thick film (100 ppm/.degree. C.) resistor was employed for
{overscore (o)}1.
[0153] The module sequencer 1541 (of FIG. 29B) is the system
control state machine and is responsible for a number of functions
including: determining when to perform measurements, enabling the
bias and pulsing each front end channels separately, enabling the
high frequency clock, controlling the data collection and
processing, and sequencing the non-volatile memory controller. FIG.
29E shows the basic state machine control associated with a single
channel conversion. R4BR and CHXBIAS are issued to properly reset
the amplifiers and turn on the bias to the front end. THERMSW is
then taken low which switches out the resistors in parallel with
the thermistors. The high speed clock is then started using HSCKEN,
the autozero function disabled (AZ) and the START PULSE is issued.
STOPENX is delayed slightly from the issue of the start pulse to
prevent false firing of the zero-crossing discriminators during the
issuing of the start pulse. After time has been allowed for the
zero-crossing to occur, R4BR and THERMSW are put back into the
initialization state, the autozero is enabled, and the oscillator
disabled. This function is performed for each of the four channels,
and then the cycle performed 256 times. As the sampling takes place
the average is generated and when complete the module sequencer
controls the writing of the packet NVRAM. Counters are used to
determine when sampling needs to be initiated, how many samples
have been applied towards an average value, and how many average
sample packets have been stored in memory. When the total number
average samples have been collected and stored, the unit disables
the low frequency oscillator and goes into a power down mode. At
this point, there is no need for power and the battery supply can
be removed without impact on the stored data.
[0154] The data collection module consists of four 10-bit counters
1591, 1593, 1595, 1597, a shared digital adder 1599, and the
necessary latches (accumulator) 1601 to store the data for
pipelined counting and averaging, as is shown in FIG. 29F. The
average is determined by taking the 10 most significant bits of the
256 sample sum. Each counter has an individual stop enable to
prevent erroneous stop pulses during the start pulse leading edge.
If a zero-crossing signal is not detected, the counters overflows
to an all-1's state.
[0155] 15. OPTIMIZING LUBRICATION SYSTEM MONITORING: It is another
objective of the present invention to provide a lubrication
monitoring system which optimizes the detection of degradation of
the lubrication system, far in advance of lubrication system
failure, which is relatively simple in its operation, but highly
reliable in use. The objective of such a system is to provide a
reliable indication of the rate of decline of the duty factor (also
known as "service life") of the improved rock bit of the present
invention. In order to determine the optimum lubrication monitoring
system, a variety of monitoring systems were empirically examined
to determine their relative sensor discrimination ability. Three
particular potential lubrication condition monitoring systems were
examined including:
[0156] (1) the ingress of drilling fluids into the lubrication
monitoring system;
[0157] (2) the detection of the presence of wear debris from the
bearing in the lubrication system; and
[0158] (3) the effects of working shear on the lubricant in the
lubrication system.
[0159] Another important objective of a lubrication monitoring
system is to have a system which operates, to the maximum extent
possible, similarly to the optimized temperature sensing system
described above.
[0160] FIG. 28 is a block diagram and circuit drawing
representation of this concept. As is shown, in oscillator 901 has
a frequency of oscillation which is determined by the capacitance
value of a variable capacitor 903 and a known resistance value for
resistor 905. In other words, it was one objective of the optimized
lubrication monitoring system of the present invention to provide a
monitoring system which can determine the decline in service life
of the lubrication system by monitoring the capacitance of an
electrical component embedded in the lubricant. In accordance with
this model, changes in the dielectric constant of the lubricant
will result in changes in the overall capacitance of variable
capacitor 903, which will result in changes in the frequency of the
output of oscillator 901. The output of oscillator 901 is sampled
by sampling circuit 907, and recorded into semiconductor memory 911
by recording circuit 909.
[0161] Early in the modeling process, it was determined that a
system that depended upon detection of the ingress of drilling
fluid into the lubrication system, or the presence of wear debris
in the bearing in the lubrication system did not, and would not,
provide a failure indication early enough to be of value.
Accordingly, the modeling effort continued by examining the optimum
discrimination ability of monitoring the effects of working shear
on the lubricant and the lubrication system. The modeling process
continued by examination of the following potential indicators of
degradation of the lubrication system due to the effects of working
shear on the lubricant:
[0162] (1) the presence or absence of organic compounds in the
lubricant, as determined from infrared spectrometry;
[0163] (2) the presence or absence of metallic components, as
determined from the emission spectra from the lubricant;
[0164] (3) the water content in the lubricant as determined from
Fisher analysis; and
[0165] (4) the total acid numbers for the lubricant.
[0166] It was determined that, if the grease monitoring capacitors
were sized to yield values of about 100 E-12 F (with standard
grease between the plates), then the temperature-measuring circuit
described above could be feasibly adapted for monitoring the
operating condition of the lubrication system.
[0167] A series of experiments was performed in which CA7000 grease
capacitance was determined as a function of drilling fluid
contamination (0.1 and 0.2 volume fraction oil-based and
water-based fluids), frequency (1 kHz-2 mHz) and temperature (68
F-300 F). Several conclusions as follows were drawn from the
tests:
[0168] (1) when CA7000 was contaminated with 0.1 volume fraction of
oil-based fluid, capacitance values increased by about 5% (relative
to pure CA7000). Increases of about 100% were recorded when 0.2
volume fraction of water-based fluid was added. Generally,
capacitance was inversely related to frequency; low frequencies are
preferred for maximum discrimination; and
[0169] (2) in the tests, repeatability and reproducibility
variations were less than about 1.5%; therefore, the variations
were small enough to suggest that grease capacitance measurements
may be a feasible way of judging grease contamination levels in
excess of 0.1 volume fraction of either oil or and water-based
fluid.
[0170] FIG. 30A is a graphical representation of capacitance change
versus frequency for a CA7000 grease contaminated with oil-based
muds and water-based muds, with the X-axis representative of
frequency in kilohertz, and with the Y-axis representative of
percentage of change of capacitance. Curve 1621 represents the data
for contamination of the grease with 0.1 volume fraction of an
oil-based drilling mud. Curve 1625 represents the data for
contamination of the grease with a 0.2 volume fraction of oil-based
mud. Curve 1625 represents the data for contamination of the grease
with a 0.1 volume fraction of water-based mud. Curve 1627
represents the data for contamination of the grease with a 0.1
volume fraction oil-based mud. All the measurements shown in the
graph of FIG. 30A are measurements which are relative to
uncontaminated grease. The data shows (1) that for the frequency
range tested, discrimination is maximum at one kilohertz; (2) that
about five percent discrimination (5% of the measured capacitance
of pure CA7000) is required to detect the presence of 0.1 volume
fraction of oil-based mud; and (3) that fifty percent
discrimination is required to detect 0.1 volume fraction of
water-based mud. The effect of water based mud contamination on
grease is certainly more pronounced than is the effect of
contamination by oil-based mud.
[0171] FIG. 30B is a graphical representation of frequency versus
percentage change in capacitance, with the X-axis representative of
frequency, and with the Y-axis representative of percentage of
change in capacitance. Curves 1631, 1633 are representative of the
data for the repeatability and reproducibility of the capacitance
measurements for 0.1 percent volume fraction contamination of the
grease by oil-based mud. The data is shown at a temperature of
50.degree. Centigrade. The data suggests that capacitance
measurements can be repeated and reproduced within about 1.5
percent variation. Therefore, since the
repeatability/reproducibility ranges are less than the minimum
discrimination, it seems feasible to detect 0.1 volume fraction of
contamination of the grease by oil-based drilling mud.
[0172] FIG. 30C is a graphical representation of the contamination
versus total acid number for both oil-based muds and water-based
muds. In this graph, the X-axis is representative of volume
fraction of contamination in CA7000 grease, while the Y-axis is
representative of total acid number in units of milligram per gram.
The results of this test indicate that total acid number will
likely provide an indication of contamination of the grease.
[0173] FIG. 31 is a simplified pictorial representation of the
placement of a capacitive sensor 903 within the lubricant 915 of
lubrication system reservoir 919. Lubricant 915 gets between the
plates of capacitor 903 and affects the capacitance of capacitor
903 as the total acid number of the lubricant changes due to
ingress and working shear during drilling operations. As is shown,
a conventional pressure bulk head 919 is utilized at the
lubrication system reservoir wall 917.
[0174] 16. FRODIBLE BALL WARNING SYSTEM: The preferred embodiment
of the improved drill bit of the present invention further includes
a relatively simple mechanical communication system which provides
a simple signal which can be detected at a surface location and
which can provide a warning of likely or imminent failure of the
drill bit during drilling operations. In broad overview, this
communication system includes at least one erodible, dissolvable,
or deformable ball (hereinafter referred to as an "erodible ball")
which is secured in position relative to the improved rock bit of
the present invention through an electrically-actuated fastener
system. Preferably, the erodible ball is maintained in a fixed
position relative to a flow path through the rock bit which is
utilized to direct drilling fluid from the central bore of the
drillstring to a bit nozzle on the bit. As is conventional, the bit
nozzle is utilized to impinge drilling fluid onto the bottom of the
borehole and the cutting structure to remove cuttings, and to cool
the bit.
[0175] FIG. 32A is a simplified and block diagram representation of
the erodible ball monitoring system of the present invention. As is
shown, an erodible ball communication system 1001 is provided
adjacent fluid flow path 1009 which supplies drilling fluid 1011 to
bit nozzle 1013 and produces a high pressure fluid jet 1015 which
serves to clean and cool the drill bit during drilling operations.
As is shown, erodible ball communication system 1001 includes an
erodible ball 1003 which is secured within a cavity 1007 located
adjacent to flow path 1009. The erodible ball 1003 is fixed in its
position within cavity 1007 by electrically-actuable fastener
system 1005, but erodible ball 1003 is also mechanically biased by
biasing member 1008 which can include a spring or other mechanical
device so that upon release of erodible ball 1003 by
electrically-actuable fastener system 1005, mechanical bias 1008
causes erodible ball 1003 to be passed into flow path 1009 and
pushed by drilling fluid 1011 into contact with bit nozzle 1013.
Erodible ball 1003 is adapted in size to lodge in position within
bit nozzle 1013 until the ball is either eroded, dissolved, or
deformed by pressure and or fluid impinging on the ball.
[0176] The electrically actuable fastener system 1005 is adapted to
secure erodible ball 1003 in position until a command signal is
received from a subsurface controller carried by the drillstring.
In simplified overview, the electrically-actuable fastener system
includes an input 1021 and electrically-actuated switch 1019, such
as a transistor, which can be electrically actuated by a command
signal to allow an electrical current to pass through a frangible
or fusible member 1017 which is within the current path, and which
is part of the mechanical system which holds erodible ball 1003 in
fixed position.
[0177] In accordance with one preferred embodiment of the present
invention, the electrically frangible or fusible connector 1017 may
comprise a Kevlar string which may be disintegrated by the
application of current thereto. Alternatively, the
electrically-frangible or fusible connector may comprise a fusible
mechanical link which fixes a cord in position relative to the
drill bit.
[0178] In the preferred embodiment of the present invention, the
erodible ball 1003 is adapted with a plurality of circumferential
grooves and a plurality of holes extending therethrough which allow
the drilling fluid 1011 to pass over and/or through the erodible
ball 1003 to cause it dissolve or disintegrate over a minimum time
interval.
[0179] FIG. 32B is a pictoral representation of erodible ball 1003
lodged in position relative to bit nozzle 1013. As is shown,
circumferential grooves 1031, 1033 are provided on the exterior
surface of erodible ball 1003. In the preferred embodiment of the
present invention, the circumferential grooves 1031, 1033 intersect
one another at predetermined positions; as is shown in FIG. 32B,
the preferred intersection is an orthogonal intersection. In
alternative embodiments, the circumferential grooves may be
provided in different arrangements or positions relative to one
another. Additionally, ports are provided which extend through
erodible ball 1003. In the view of FIG. 32B, ports 1035 and 1037
are shown as extending entirely through erodible ball 1003 and
intersecting one another at a midpoint within erodible ball 1003.
In the preferred embodiment of the present invention, three
mutually orthogonal ports are provided through erodible ball 1003.
In alternative designs, a lesser or greater number of ports may be
provided within erodible ball 1003 to obtain the erosion time
needed for the particular application.
[0180] FIGS. 32C and 32D provide detailed views of the preferred
embodiment of the erodible ball 1003 of the present invention. As
is shown in FIG. 32C, circumferential grooves 1031 and 1033 are
rather deep grooves. Preferably, each of the circumferential
grooves has a diameter of 0.32 inches. In the preferred embodiment,
the erodible ball 1003 has a diameter of 0.688 inches.
Additionally, the ports 1035, 1037 have a diameter of 0.063
inches.
[0181] As is shown in FIGS. 32C and 32D, the erodible ball 1003 has
three-fold symmetry. This symmetry is provided to ensure that
drilling fluid will flow through and over the ball irrespective of
the position that the ball lodges with respect to the bit nozzle.
The spherical shape for the erodible ball 1003 was selected because
its effectiveness is independent of lodging orientation. The
preferred embodiment of the erodible ball 1003 utilizes both the
circumferential grooves and the ports which extend through the
erodible ball 1003 as fluid flow paths. As the drilling fluid
passes over and through the erodible ball 1003, erosion occurs from
the outside-in as well as the inside-out. In the preferred
embodiment of the present invention, the erodible ball 1003 is
formed from a bronze material, and has the relative dimensions as
shown in FIG. 32D. This particular size, material composition and
configuration ensures a "residence time" of the erodible ball
within the bit nozzle of 300 seconds to 1200 seconds. The temporary
occlusion of at least one bit nozzle in the improved drill bit
generates a pressure change which is detectable at the surface on
most drilling installations as a pressure increase in the central
bore and/or pressure decrease in the annulus.
[0182] FIG. 32E is a graphical representation of a pressure
differential which can be detected at the surface of the drilling
installation utilizing conventional pressure sensors. As is shown,
the x-axis is representative of time, and the y-axis is
representative of the pressure differential sensed by the surface
pressure sensors. As is shown, two consecutive pressure surges
1041, 1043 are provided, each having a minimum residence time
duration of at least 300 seconds. If the release of the erodible
balls is properly timed, together, the consecutively deployed
erodible balls will provide a minimum interval of pressure change
of 600 seconds, which can be easily detected at the surface, and
which can be differentiated from other transient pressure
conditions which are due to drilling or wellbore conditions.
[0183] As is shown in FIG. 32E, all that is required is that the
change in pressure be above a pressure threshold, and that each
pressure surge 1041, 1043 have a minimum duration.
[0184] In accordance with the present invention, the preferred
fastener system comprises either a frangible material, such as a
Kevlar string, or a fusible metal link which serves to secure in
position a latch member, such as a fastener or cord. When a fusible
member is utilized, the improved drill bit of the present invention
can conserve power by utilizing a combination of (1) electrical
current, and (2) temperature increase in the drill bit due to the
likely bit failure, as a result of degradation of the journal
bearing or associated lubrication system, to trigger release of the
erodible ball.
[0185] For example, a fusible link may require a certain amount of
electrical energy to change the state of the link from a solid
metal to a liquid or semi-liquid state. A certain amount of
electrical energy that would otherwise be required to change the
state of the fusible link can be provided by an expected increase
in temperature in the component being monitored. For example, a
certain number of degrees increase in temperature can be attributed
to the condition being monitored, such as a degradation in the
journal bearing which causes an increase in local temperature in
that particular bit leg. The remaining energy can be provided by
supplying an electrical current to the fusible link to complete the
fusing operation.
[0186] 17. PERSISTENT PRESSURE CHANGE COMMUNICATION SYSTEM: FIGS.
33 and 34 are views of an alternative communication system which
utilizes an electrically-controllable valve to control or block
fluid flow between the central bore of the drillstring and the
annulus. FIG. 33 is a simplified view of the operation of the
persistent pressure change communication system of the present
invention. As is shown, bit body 2001 separates central flow path
2003 from return flowpath 2005. Central flowpath 2003 is a flowpath
defined within an interior space within bit body 2001. Typically,
central flowpath 2003 supplies drilling fluid to at least one bit
nozzle flowpath carried within bit body 2001 for jetting drilling
fluid into the wellbore for cooling the drill bit and for removing
cuttings from the bottom of the wellbore. Return flowpath 2005 is
disposed within annular region 2009 which is defined between the
bit body 2001 and the borehole wall (which is not shown in this
view). A signal flowpath 2011 is formed within bit body 2001 which
can be utilized to selectively allow communication of fluid between
central flowpath 2003 and return flowpath 2005. As is well known,
there is a pressure differential between the central flowpath 2003
and the return flowpath 2005 during drilling operations. The
present invention takes advantage of this pressure differential by
selectively allowing communication of fluid through signal flowpath
2011 when it is desirable to generate a persistent pressure change
which may be detected at the surface of the wellbore.
Selectively-actuable flow control device 2013 is disposed within
signal flowpath 2011 and provided for controlling the flow of fluid
through signal flowpath until a predetermined operating condition
is detected by the monitoring and control system. Preferably the
selectively-actuable flow control device 2013 is an
electrically-actuable device which may be disintegrated, dissolved,
or "exploded" when signaling is desired. The preferred embodiment
of the selectively-actuable flow control device 2013 is provided in
simplified and block diagram view of FIG. 33. As is shown,
selectively-actuable flow control device includes a plurality of
structural members 2015, 2017, 2019 which are held together in a
matrix of material 2021 which is in a solid state until thermally
activated or electrically activated to change phase to either a
liquid state, gaseous state, or which can be fractured or
fragmented by the application of electrical current to leads 2025,
2027 to heating element 2023. In operation, the matrix which blocks
the signal flowpath 2011 until an electrical current is supplied to
leads 2025, 2027 to fracture, fragment, or change the phase of the
matrix 2021, which will allow fluid to pass between the interior
region of the bit and the annular region.
[0187] FIG. 36 is a pictorial representation of the
selectively-actuable flow control device 3002 which may be utilized
to develop a persistent pressure change to communicate signals in a
wellbore. As is shown, the selectively-actuable device 3002 is
located on an upper portion of bit body 3001 and is utilized to
selectively allow communication of fluid between an interior region
3005 of bit body 3001 and an annular region surrounding the bit
body.
[0188] FIG. 37 is a cross-section view of the preferred components
which make use of this selectively-actuable device 3002. As is
shown, a nozzle retaining blank 3003 is adapted for securing in
position a diverter nozzle 3004 which is held in place by snap
rings 3009, 3011. The interface between the nozzle retaining blank
3003 and the diverter nozzle is sealed utilizing o-ring seal 3007.
A ruptured disc 3015 is carried between the diverter nozzle 3004
and the bit body 3001. As is shown, the rupture disc 3015 is
secured in place within rupture disc retaining bushing 3013.
Rupture disc retaining bush 3013 is secured in position relative to
nozzle retaining blank 3003 and sealed utilizing o-ring 3017. A
spacer ring 3019 secures the lower portion of rupture disc 3015.
O-ring seal 3021 is included at the interface of the rupture disc
3015, the bit body 3001, and the spacer ring 3019.
[0189] 18. ADAPTIVE CONTROL DURING DRILLING OPERATIONS: The present
invention may also be utilized to provide adaptive control of a
drilling tool during drilling operations. The purpose of the
adaptive control is to select one or more operating set points for
the tool, to monitor sensor data including at least one sensor
which determines the current condition of at least one controllable
actuator member carried in the drilling tool or in the bottomhole
assembly near the drilling tool which can be adjusted in response
to command signals from a controller. This is depicted in broad
overview in FIG. 35A. As is shown, a controller 2100 is provided
and carried in or near the drilling apparatus. A plurality of
sensors 2101, 2103, and 2105 are also provided for providing at
least one electrical signal to controller 2100 which relates to any
or all of the following:
[0190] (1) a drilling environment condition;
[0191] (2) a drill bit operating condition;
[0192] (3) a drilling operation condition; and
[0193] (4) a formation condition.
[0194] As is shown in FIG. 35A, controller 2100 is preferably
programmed with at least one operation set point. Furthermore,
controller 2100 can provide control signals to at least one
controllable actuator member such as actuator 2109 and 2113, or
open-looped controllable actuator 2111. The controllable actuator
member is carried on or near the bit body or the bottomhole
assembly and is provided for adjusting at least one of the
following in response to receipt of at least one control signal
from controller 2100:
[0195] (1) a drill bit operating condition; and
[0196] (2) a drilling operation condition.
[0197] One or more sensors (such as sensors 2107, 2115) are
provided which provide feedback to controller 2100 of the current
operating state of a particular one of the at least one
controllable actuator members 2109, 2111, 2113. An example of the
feedback provided by sensor 2017, 2115 is the physical position of
a particular actuator member relative to the bit body. In this
adaptive control system, the controller 2100 executes program
instructions which are provided for receiving sensor data from
sensors 2101, 2103, and 2105, and providing control signals to
actuators 2109, 2111, 2113, while taking into account the feedback
information provided by sensors 2107, 2115. In the preferred
embodiment of the present invention, controller 2100 reaches
particular conclusions concerning the drilling environment
conditions, the drill bit operating conditions, and the drilling
operation conditions. Controller 2100 then acts upon those
conclusions by adjusting one or more of actuators 2019, 2111, 2113.
In operation, the system can achieve and maintain some standard of
performance under changing environmental conditions as well as
changing system reliability conditions such as component
degradation. For example, controller 2100 may be programmed to
attempt to obtain a predetermined and desirable level of
rate-of-penetration. Ordinarily, this operation is performed at the
surface utilizing the relatively meager amounts of data which are
provided during conventional drilling operations. In accordance
with the present invention, the controller is located within the
drilling apparatus or near the drilling apparatus, senses the
relevant data, and acts upon conclusions that it reaches without
requiring any interaction with the surface location or the human
operator located at the surface location. Another exemplary
preprogrammed objective may be the avoidance of risky drilling
conditions if it is determined that the drilling apparatus has
suffered significant wear and may be likely to fail. Under such
circumstances, controller 2100 may be preprogrammed to adjust the
rate of penetration to slightly decrease the rate of penetration in
exchange for greater safety in operation and the avoidance of the
risks associated with operating a tool which is worn or somewhat
damaged.
[0198] FIGS. 35B through 351 are simplified pictorial
representations of a variety of types of controllable actuator
members which may be utilized in accordance with the present
invention. FIG. 35B is a pictorial representation of a rolling cone
cutter 2121 which is mechanically coupled through member 2123 to an
electrically-actuable electromechanical actuator 2125 which may be
utilized to adjust the position of the rolling cone cutters
relative to the bit body 2121.
[0199] FIG. 35C is a simplified pictorial representation of rolling
cutter 2129 which is mechanically coupled through linkage 2129 and
pivot point 2131 to electromechanical actuator 2133 which is
provided to adjust the relative angle of rolling cone cutters
relative to the bit body 2127.
[0200] FIG. 35D is a simplified pictorial representation of rolling
cone cutters relative to the bit body 2137, which is mechanically
coupled through bearing assembly 2139 to an electrically actuable
electromechanical rotation control system, which adjusts the rate
of rotation of the rolling cone cutters by increasing or decreasing
the rate slightly by adjusting the bearing assembly electrically or
mechanically. For example, magnetized components and
electromagnetic circuits can be utilized to "clutch" the cone.
Alternatively, the magnetorestrictive principle may be applied to
physically alter the components in response to a generated magnetic
field.
[0201] FIG. 35E is a simplified pictorial representation of a bit
nozzle. As is shown, a nozzle flowpath 2145 is provided through bit
body 2143. An electromechanical actuator 2147 may be provided in
the nozzle flowpath to adjust the amount of fluid allowed to pass
through the nozzle. Alternatively, the electromechanical device
2147 may be provided to adjust the angular orientation of the
output of the nozzle to redirect the jetting and cooling drilling
fluid.
[0202] FIG. 35F is a simplified representation of a drill bit 2151
connected to a drillstring 2153. Pads 2155, 2157 may be provided in
the bottomhole assembly and mechanically coupled to an
electrically-actuable controller member 2159, 2161 which may be
utilized to adjust the inward and outward position of pads 2155,
2157. FIG. 35G is a simplified pictorial representation of a drill
bit 2167 connected to a drilling motor 2169. A controller 2171 may
be provided for selectively actuating drilling motor 2169. In
accordance with the present invention, the adaptive control system
may be utilized to adjust the speed of the drilling motor which in
turn adjusts the speed of drilling and affects the rate of
penetration.
[0203] FIG. 35H is a simplified pictorial representation of a drill
bit 2185 connected to a steering subassembly 2183 and a drilling
motor 2181. In accordance with the present invention, the adaptive
control system may be utilized to control steering assembly 2183 to
adjust the orientation of the drill bit relative to the borehole,
which is particularly useful in directional drilling.
[0204] FIG. 35I is a simplified pictorial representation of drill
bit 2193 with a plurality of fixed or rolling cone cutting
structures such as cutting structure 2195 carried thereon. Drill
bit 2193 is connected to bottomhole assembly 2191. Gage trimmers
2197, 2199 are provided in upper portion of drill bit 2193. Gage
trimmers are connected to electromechanical members 2190, 2192
which may be utilized to adjust the inward and outward position of
gage trimmers 2197, 2199. The gage trimmers may be pushed outward
in order to expand the gage of the borehole. Conversely, the gage
trimmers may be pulled inward relative to the bit body in order to
reduce the gage of the borehole.
[0205] While the invention has been shown in only one of its forms,
it is not thus limited but is susceptible to various changes and
modifications without departing from the spirit thereof.
* * * * *