U.S. patent application number 09/271947 was filed with the patent office on 2001-11-29 for thruster responsive to drilling parameters.
Invention is credited to FINCHER, ROGER, FONTANA, PETER, KRUEGER, VOLKER, MAKOHL, FRIEDHELM.
Application Number | 20010045300 09/271947 |
Document ID | / |
Family ID | 22145899 |
Filed Date | 2001-11-29 |
United States Patent
Application |
20010045300 |
Kind Code |
A1 |
FINCHER, ROGER ; et
al. |
November 29, 2001 |
THRUSTER RESPONSIVE TO DRILLING PARAMETERS
Abstract
This invention provides a bottomhole assembly that contains a
thruster for applying an axial force on the drill bit during
drilling of the wellbore. The bottomhole assembly includes at least
one sensor which provides measurements for determining a parameter
of interest relating to the drilling of the wellbore. A power unit
supplies power to the thruster to move a member toward the drill
bit to apply the force on the drill bit. A processor operatively
coupled to the thruster controls the magnitude of the force
generated by the thruster in response to one or more parameters
interest.
Inventors: |
FINCHER, ROGER; (CONROE,
TX) ; KRUEGER, VOLKER; (CELLE, DE) ; FONTANA,
PETER; (HOUSTON, TX) ; MAKOHL, FRIEDHELM;
(HERMANNSBURG, DE) |
Correspondence
Address: |
PAUL S MADAN
MADAN, MOSSMAN & SRIRAM, PC
2603 AUGUSTA, SUITE 700
HOUSTON
TX
77057-1130
US
|
Family ID: |
22145899 |
Appl. No.: |
09/271947 |
Filed: |
March 18, 1999 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60078733 |
Mar 20, 1998 |
|
|
|
Current U.S.
Class: |
175/26 ; 175/27;
175/45; 175/61; 175/73 |
Current CPC
Class: |
E21B 7/068 20130101;
E21B 44/04 20130101; E21B 44/005 20130101 |
Class at
Publication: |
175/26 ; 175/27;
175/61; 175/45; 175/73 |
International
Class: |
E21B 007/04; E21B
044/00; E21B 047/02 |
Claims
What is claimed is:
1. A bottom hole assembly ("BHA") for use in drilling a wellbore in
a subsurface formation, said BHA comprising: (a) a drill bit at an
end of the BHA; (b) a force application device in the BHA applying
force having a magnitude on the drill bit during drilling of the
wellbore; (c) a sensor in the BHA providing measurements of a
parameter of interest relating to the drilling of the wellbore; and
(d) a processor determining the magnitude of the force in response
to said parameter of interest and causing the force application
device to apply said force having said magnitude on the drill bit
during drilling of the wellbore.
2. The BHA of claim 1, wherein the force application device further
comprises a force application member that extends toward the drill
bit relative to a stationary section of the force application
device to exert the force on the drill bit.
3. The BHA of claim 2 further comprising a sensor for determining
the magnitude of the force actually applied by the force
application device on the drill bit.
4. The BHA of claim 3, wherein the sensor is selected from a group
consisting of (i) a sensor measuring displacement of said force
application member from an initial position, and (ii) a pressure
sensor.
5. The BHA of claim 1, wherein the processor causes the thruster to
adjust the application of the force on the drill bit to maintain
the parameter of interest within a predetermined range.
6. The BHA of claim 1, wherein the processor determines the
parameter of interest downhole during drilling of the wellbore.
7. The BHA of claim 1 further comprising at least one model
utilized by said processor to compute the parameter of interest and
the magnitude of the force to be applied to the drill bit.
8. The BHA of claim 1, wherein the processor adjusts the magnitude
of the axial force exerted by the force application member in
response to the measurement of the parameter of interest.
9. The BHA of claim 1, wherein the force application device is one
of a hydraulically-operated device, mechanically-operated device
and an electro-mechanical device.
10. The BHA of claim 1, wherein the parameter of interest is
selected from a group consisting of (i) rotational speed of the
drill bit, (ii) rotational speed of a drill collar rotating said
drill bit from a surface location, (iii) weight-on-bit, (iv)
pressure differential between the pressure in the BHA and an
annulus between the BHA and the wellbore, (v) pressure at a
selected location in the BHA, (vi) drop differentially across a mud
motor in the BHA, rotating said drill bit, (vii) torque, (viii)
rate of penetration ("ROP") of the drill bit in the subsurface
formation, (viii) vibration, (ix) whirl, (x) bit bounce, (xi) stick
slip, (xii) rock matrix of the formation, (xiii) a formation
characteristic; rotational speed of the drill bit.
11. The BHA of claim 1, wherein the sensor is selected from a group
consisting of (a) an rpm sensor, (b) a pressure sensor for
determining at least one of, the pressure in the BHA, pressure in
an annulus between the BHA and the formation, differential pressure
across a drilling motor associated with the BHA, (c) a sensor for
determining the weight-on-bit, (d) a sensor for determining the
rate of penetration of the drill bit in the formation, (e) a
temperature sensor, (f) a vibration sensor, (h) a displacement
measuring sensor, and (i) a formation evaluation sensor.
12. A force application device for applying force to a drill bit
coupled thereto during the drilling of a wellbore, said force
application device comprising: (a) a stroke member movable between
a first position and a second position, said stroke member adapted
to apply a predetermined force on the drill bit when said stroke
member is moved from the first position toward the second position;
(b) a power unit supplying power to the stroke member to cause the
stroke member to move from the first position to the second
position to apply the predetermined force on the drill bit; and (c)
a control unit controlling the operation of the power unit in
response to a parameter of interest determined at least in part
based on a measurement made in the wellbore during drilling of the
wellbore to maintain the force on the drill bit within a
predetermined range.
13. The force application device of claim 12, wherein the stroke
member reciprocates in a chamber and the power unit supplies a
fluid under pressure to the chamber to cause the stroke member to
move from the first position to the second position.
14. The force application device of claim 13, wherein the power
unit supplies fluid under pressure to the chamber in a reverse
direction to move the stroke member from the second position to the
first position.
15. The force application device of claim 13, wherein the parameter
of interest is selected from a group consisting of (i) rotational
speed of the drill bit, (ii) rotational speed of a drill collar
rotating said drill bit from a surface location, (iii)
weight-on-bit, (iv) pressure differential between the pressure in
the BHA and an annulus between the BHA and the wellbore, (v)
pressure at a selected location in the BHA, (vi) drop
differentially across a mud motor in the BHA, rotating said drill
bit, (vii) torque, (viii) rate of penetration ("ROP") of the drill
bit in the subsurface formation, (viii) vibration, (ix) whirl, (x)
bit bounce, (xi) stick slip, (xii) rock matrix of the formation,
(xiii) a formation characteristic; rotational speed of the drill
bit.
16. The force application device of claim 12, wherein the force
application member has a through opening allowing fluid flow
therethrough and the force applied on the drill bit being
responsive to the pressure of the fluid on the force application
member.
17. The force application device of claim 16 further comprising a
valve for controlling the flow of the fluid through the stroke
member, thereby controlling the pressure on the force application
member.
18. The force application device of claim 17, wherein the control
unit modulates the valve to control the force exerted by the stroke
member on the drill bit.
19. The force application device of claim 18, wherein the valve is
operated by a device selected from a group consisting of (i) a
stepper motor, and (ii) a solenoid.
20. A method of drilling a wellbore in a subsurface formation by a
drilling assembly that includes a drill bit and a thruster which
exerts force on the drill bit during drilling of the wellbore, said
method, comprising: (a) conveying the drilling assembly into the
wellbore; (b) rotating the drill bit to cause the drill bit to
penetrate the formation; (c) operating the thruster to apply a
predetermined force on the drill bit; (d) determining at least
periodically at least one parameter of interest downhole during
drilling of the wellbore relating to the drilling of the wellbore;
and (e) altering the force applied by the thruster in response to
the determined at least one parameter of interest.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application takes priority from United States patent
application Ser. No. 60/078,733 filed on Mar. 20, 1998.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] This invention relates generally to drill strings for
drilling boreholes for the production of hydrocarbons and more
particularly to thrusters to provide force to the drill bit during
drilling of the boreholes, especially for drilling deviated and
horizontal boreholes with bottomhole assemblies using drilling
motors.
[0004] 2. Description of the Related Art
[0005] To obtain hydrocarbons such as oil and gas, boreholes or
wellbores are drilled by rotating a drill bit attached to a drill
string. A substantial proportion of the current drilling activity
involves directional drilling, i.e., drilling deviated and
horizontal boreholes, to increase the hydrocarbon production from
the earth formations. Modern directional drilling systems generally
employ bottomhole assemblies ("BHA") or drilling assemblies that
include a drill bit rotated by a drilling motor (commonly referred
to as the "mud motor") in the BHA. The BHA is conveyed into the
wellbore by a tubing, such as drill pipe or coiled tubing. Drilling
fluid (commonly referred to as the "mud") is circulated through the
drill string under pressure. The drilling fluid passes through the
mud motor, rotating the mud motor and thus the drill bit. A certain
amount of weight on bit ("WOB") must be maintained to cause the
drill bit to penetrate the formation. Weight on bit cannot be
properly applied by the drill string during horizontal drilling or
when coiled tubing is used as the tubing. In such applications, a
thruster is often utilized to exert axial force (force along the
borehole longitudinal axis) on to the drill bit.
[0006] Commonly used thrusters are telescopic tubular arrangements.
A thruster is usually disposed in or incorporated into the
bottomhole assembly above the drilling motor. A telescopic or
stroke member extending from the thruster applies force on the
drill bit, causing the drill bit to advance into or penetrate the
borehole while the tubing above the thruster is held stationary.
When the telescopic member of the thruster has fully extended, it
is retracted to its initial or unextended position. Additional
length of the tubing is then inserted into the borehole to continue
drilling.
[0007] During drilling, pressure across the drilling motor varies
as the drilling conditions change. Fluctuations in the pressure
drop across the mud motor can impede the function of the thruster.
Thrusters have been designed that respond to the changes in the mud
motor differential pressure instead of attempting to maintain a
constant force on the drill bit and hence a constant weight on bit.
The inability of such thrusters to exert relatively constant force,
regardless of the amount of work the drilling motor is required to
do, reduces the effectiveness of the drilling operations. What
occurs is a pressure buildup due to higher load on the mud motor as
drilling begins. The higher pressure is sensed at the thruster,
causing the telescopic portion to extend further to exert greater
force on the bit. This, in turn, increases the weight on bit.
Ultimately, with increasing weight on bit, the motor can stall and
no longer turn the bit.
[0008] In these types of applications, the weight on bit is a
function of the pressure difference between inside and outside the
thruster. The greater the difference, the more the force on the bit
exerted by the thruster. As a result, assemblies using thrusters
with downhole motors have not gained great commercial success.
[0009] In one embodiment, this invention provides a BHA with a
thruster and a pressure modulation valve between the thruster and
the mud motor to compensate for the flow resistance changes
experienced in the mud motor due to changes in the drilling
conditions. Such a thruster system is operable efficiently and
reliably without the above-noted problems when used in conjunction
with the drilling motor. Use of the pressure modulation valve
exerts a constant weight on the bit since variations in the
pressure drop in the drilling motor do not affect the relative
force exerted on the bit. However, this thruster cannot adjust the
force on the bit as the drilling conditions change.
[0010] The number of horizontal wellbores drilled has been steadily
increasing. The trend seems to be toward drilling an increasing
number of relatively complex (extended reach horizontal wellbores
and curved wellbores in and around subsurface formations)
wellbores. The drilling assemblies used for such wellbores utilize
a variety of sensors that provide measurements of various
parameters relating the bottomhole assembly, wellbore conditions,
drilling operations and the formations being penetrated.
[0011] As noted above, bottomhole assemblies used for drilling such
wellbores often use mud motors and thrusters to provide force or
the weight on bit. The weight on bit and the mud motor speed (which
usually is the drill bit rotational speed), to a large extent,
control the rate of penetration ("ROP") of the wellbore or the
wellbore drilling rate and the operating life of the drilling
assembly. Excessive WOB can wear the drill bit prematurely. The
output power of a mud motor is a function of the differential
pressure across the motor. The mud motor operates most efficiently
in a certain range of the differential pressure. Excessive
differential pressure across the mud motor can deteriorate the mud
motor performance and damage the motor. Additionally, drilling
assembly parameters, such as vibration, whirl, radial and axial
displacements of the drive shaft and various other wellbore and
drilling assembly parameters can adversely affect the drilling
efficiency. It also is desirable to determine the nature of the
formation being drilled and adjust the ROP that is most appropriate
for such formation and the drilling assembly being utilized.
Drilling can be accomplished at higher ROP in soft formations.
Weight on bit can influence one or more of the above-noted
parameters. Thus, it is desirable to adjust the thruster force to
achieve such higher rates without adversely affecting the drilling
assembly health. Accordingly, there is a need to provide thrusters
for use with drilling assemblies that can adjust the applied force
as a function of one or more parameters of interest computed during
the drilling of the wellbores.
[0012] The present invention provides thrusters for use in drilling
assemblies wherein the force applied on the drill bit can be
adjusted as a function of one or more parameters of interest. The
system of the present invention utilizes one or more models which
determine the desired thruster force based upon certain parameters
computed downhole and/or transmitted to the bottomhole assembly
from the surface. Such models are dynamic, in that they may be
updated as the downhole conditions change during the drilling of
the wellbore.
SUMMARY OF THE INVENTION
[0013] This invention provides a bottomhole assembly that contains
a thruster for applying force on the drill bit during drilling of
the wellbore. The bottomhole assembly includes at least one sensor
which provides measurements for determining a parameter of interest
relating to the drilling of the wellbore. A power unit supplies
power to the thruster to move a force application member axially
toward the drill bit to apply predetermined force on the drill bit.
A processor operatively coupled to the thruster controls the
magnitude of the axial force generated by the thruster in response
to one or more of the parameters of interest.
[0014] The parameters of interest may be selected from (a)
weight-on-bit, (b) pressure differential between the pressure in
the BHA and an annulus between the BHA and the subsurface
formation, (c) pressure at a selected location in the BHA, (d)
pressure drop across a mud motor in the BHA, (e) rotational speed
of the drill bit, (f) torque, (g) rate of penetration ("ROP") of
the drill bit in the subsurface formation, (h) vibration, (i)
whirl, (j) bit bounce, (j) stick slip, and (k) one or more
characteristics of the formation being penetrated.
[0015] The sensors may include (a) an rpm sensor, (b) a pressure
sensor for determining at least one of the pressure in BHA,
pressure in an annulus between the BHA and the formation,
differential pressure across the drilling motor, (c) a sensor for
determining the weight-on-bit, (d) a sensor for determining the
rate of penetration of the drill bit in the formation, (e) a
temperature sensor, (f) a vibration sensor, (h) a displacement
measuring sensor, and (i) a formation evaluation sensor.
[0016] The processor determines the parameter(s) of interest
downhole during drilling of the wellbore. One or more dynamic
models are provided to the processor. The processor utilizing these
models computes the desired force to be applied to the drill bit
based on predetermined criteria. The processor controls the
magnitude of the axial force exerted by the thruster in response to
the determined parameters of interest.
[0017] In one embodiment of the present invention, the thruster
includes a stroke member which reciprocates between a first
(retracted) position and a second (extended) position. The stroke
member applies force on the drill bit when it is moved axially
toward the drill bit. A power unit supplies power (hydraulic or
electric) to the stroke member to cause the stroke member to move
toward the drill bit. A control unit controls the amount of the
hydraulic power supplied by the power unit in response to one or
more parameters of interest.
[0018] In another embodiment of the present invention, the thruster
includes a stroke member that reciprocates axially along the
wellbore between a first (retracted) and a second (extended)
position when the drilling fluid under pressure is applied to the
stroke member. A fluid flow control valve assembly in the thruster
controls the supply of the drilling fluid to the stroke member. The
valve is preferably a stepper motor-controlled or a
solenoid-controlled. The valve is modulated to compensate for the
pressure changes downhole.
[0019] This invention also provides a pressure modulation valve
which is used in combination with a downhole drilling motor and a
drill string thruster to compensate for changes in pressure drop
through the drilling motor which normally occur during drilling.
When conditions change during drilling, which in turn changes the
pressure drop through the drilling motor, the drill string pressure
modulation valve compensates for such changes to minimize the
effect of such changes on the operation of the thruster. The
modulation valve has a feature which allows it to find
automatically a preload condition for the main needle valve each
time the rig pumps are turned off and then turned on. The
modulation valve is fully self-contained, and is assembled as part
of the bottomhole assembly. The device senses the no-load pressure
drop in the system and sets itself each time the rig pumps are
turned on to compensate for any change in the no-load pressure drop
experienced below the device which could be attributable to such
things as motor wear, bit nozzle plugging, or changes in the flow
rate. Accordingly, the hydraulic thrusting force remains constant
over a wide range of drilling environments. As the drilling
conditions change and the pressure drop in the downhole motor
increases, the needle valve shifts to compensate for such
additional pressure drop with a resultant small or no effect on the
thruster located upstream.
[0020] Examples of the more important features of the invention
thus have been summarized rather broadly in order that the detailed
description thereof that follows may be better understood, and in
order that the contributions to the art may be appreciated. There
are, of course, additional features of the invention that will be
described hereinafter and which will form the subject of the claims
appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
[0021] For detailed understanding of the present invention,
references should be made to the following detailed description of
the preferred embodiment, taken in conjunction with the
accompanying drawings, in which like elements have been given like
numerals and wherein:
[0022] FIGS. 1A-1C illustrates a bottomhole assembly in sectional
and elevational views showing the layout of the components, as well
as a possible location for a measurement-while-drilling system
which can be used in tandem with the apparatus.
[0023] FIGS. 2A-2B is a sectional view of the drill string pressure
modulation valve in the run-in position without the rig pump
circulating.
[0024] FIGS. 3A-3B is the view of FIGS. 2A-B with the pumps
circulating, but the bit off bottom.
[0025] FIGS. 4A-4B is the view of FIGS. 3A-B with the pumps running
and the drill bit on bottom.
[0026] FIGS. 5A-5C is a schematic diagram of a bottomhole assembly
with a thruster whose operation is controlled as a function of
certain parameters of interest.
[0027] FIG. 6 shows schematic diagram of a thruster according to
one embodiment of the present invention.
[0028] FIG. 7 shows schematic diagram of a device for controlling
the flow of the drilling fluid through the thruster.
[0029] FIG. 7A shows a graph depicting a constant pressure applied
by the thruster while the mud motor pressure varies.
[0030] FIG. 8 shows block diagram of an embodiment of an electrical
control unit for use with the thrusters shown in FIGS. 5-7.
DESCRIPTION OF THE PREFERRED EMBODIMENT
[0031] FIGS. 1A-1C illustrate a drill string modulation valve for
use with a thruster in the bottomhole assembly 100 according to the
present invention. A tubing string 32, which can be rigid or coiled
tubing, supports a drill string thruster 34. The thruster 34 has an
outer housing 36 and an internal pipe 38. The internal pipe 38 is
reciprocally mounted within the outer housing 36 and extends as the
drill bit 40 advances. The thruster 34 is responsive to the
pressure difference between the inside of the bottomhole assembly,
referred to as 42, and an annulus around the assembly, referred to
as 44. The apparatus A is connected to the internal pipe 38. Below
the apparatus A, a measurement while drilling system can be
inserted to supply data to the surface regarding formation
conditions and/or the orientation of the advancement of the bit 40.
The bottomhole assembly of FIGS. 1A-C also indicates an upper
stabilizer 46 and a lower stabilizer 48 between which is a drilling
motor 50. Optionally, to assist in drilling deviated wellbores,
bent subs 52 and 54 can also be employed in the bottomhole
assembly.
[0032] This type of a bottomhole assembly is typically used for
deviated wellbores. The drilling motor 50 can be a progressive
cavity type of a motor which is actuated by circulation from the
surface through the drill string 32. The weight or force on the
drill bit 40 is determined by the pressure difference internally to
the thruster 34 at point 42 and the annular pressure outside at
point 44. The drilling motor 50 is a variable resistance in this
circuit in that the pressure drop across it is variable depending
on the load imposed on the motor 50. For example, as drilling
begins, the bit 40 causes an increase in load on the drilling motor
50 which increases the pressure drop between the drilling motor 50
and the annulus 44. That increase in pressure drop raises the
pressure difference across the thruster 34 (if the apparatus A is
not used) by raising the pressure at point 42 with respect to the
pressure at point 44. As a result, the thruster 34 adds an
incremental force through the drilling motor 50 down to bit 40. As
additional weight is put on the bit 40, the drilling motor 50
increasingly bogs down to the point where this cycle continues
until the drill bit 40 stalls the motor 50 due to the extreme
downward pressure that is brought to bear on the bit 40 from the
ever increasing internal pressure at point 42 inside the thruster
34. The thruster 34 instead of feeding out the internal pipe 38 at
a lower rate to compensate for the advancement of the bit 40, is
urged by the rise in pressure internally at point 42 to feed out
the internal pipe 38 at a greater rate than the advancement of the
bit 40, thus adding the force on bit, which in turn finally stalls
the drilling motor 50. This had been the problem and the apparatus
A of the present invention, when inserted in the bottomhole
assembly, as shown in FIG. 1B, addresses this problem. The
apparatus A acts as a compensation device, which, as its objective,
keeps the pressure as constant as possible at the internal point 42
of the thruster 34 despite variations in pressure drop that the
drilling motor 50 created during drilling.
[0033] Referring now to FIGS. 2A and B, the apparatus A has a
containment sub 1 which has a lower end 56 which is oriented toward
the drilling motor 50, and an upper end 58, which is oriented
toward the thruster 34. In order to describe the operation of the
apparatus, the pressure adjacent lower end 56 will be referred to
as P.sub.1; the pressure adjacent the upper end will be referred to
as P.sub.2; and the annulus pressure outside the containment sub 1
will be referred to as P.sub.3. Again, the objective is to keep
P.sub.2 as constant as possible.
[0034] The assembly shown in FIG. 2 starts near the upper end with
lifting head 2 which is supported from the containment sub 1 at
thread 60. Attached to the lower end of the lifting head 2 is
compressive pad 4, which in turn is secured to a porous metal
filter 7. Below the porous metal filter 7, liquid that gets through
it flows through mud flow port 6 to a cavity 62 above delay valve
piston 9. Delay valve piston 9 is sealed at its periphery by seal
64 to divide the delay valve tube 8 into cavity 62 and cavity 66.
Delay valve spring 10 resides in cavity 66 and biases the delay
valve piston 9 toward the porous metal filter 7. A delay valve
orifice assembly 12 is located at the lower end of the delay valve
tube 8. This is an orifice which, in essence, regulates the
displacement of clean fluid in cavity 66 into cavity 68. Those
skilled in the art will appreciate that movement of delay valve
piston 9 downhole toward the lower end 56 will result in
displacement of clean fluid, generally an oil, from cavity 66
through delay valve orifice block 11 into cavity 68 for ultimate
displacement of piston valve 15. Piston valve 15 is sealed
internally in delay valve tube 8 by seal 70. The piston valve 15
has a receptacle 72, which includes a seal 74, which ultimately
straddles the low-pressure transfer tube 16, as shown by comparing
FIG. 2A to FIG. 3A. The low pressure transfer tube 16 extends to
compensation tube body 20. Inside of compensation tube body 20 is
compensation spring 22. Spring 22 bears on compensation piston 76
at one end and on the other end against modulating ram needle 27.
Needle 27 is sealed internally in the compensation tube body 20 by
seal 78. The compensating piston 76 is also sealed within the
compensation tube body 20 by seal 80. Both the compensating piston
76 and the needle 27 are movable within the compensating tube body
20 for reasons which will be described below. In effect, the piston
76 and the needle 27 define a cavity 82 within the compensation
tube body 20. The low pressure transfer tube 16 spans the entire
cavity 82, but is not in fluid communication with that cavity. A
vent port 23 is in fluid communication with cavity 82. The port 23
is in fluid communication with cartridge vent port 24, which
ultimately leads to transfer groove 25, which in turn leads to the
porous metal filter 26. Accordingly, the pressure P.sub.3 is
communicated into the cavity 82. Port 24 can be sized to make
cavity 82 operate as a dampener on the movements of needle 27. It
can be directly connected to P.sub.3 as shown or to an external or
internal reservoir. The reservoir can have a floating piston with
one side exposed to P.sub.3 through the filter 26. This layout can
reduce potential plugging problems in filter 26.
[0035] Referring now toward the lower end of the compensation tube
body 20, the needle 27 extends beyond an opening 84 and into the
restrictor orifice 31. The preferred components for the needle 27
and the restrictor orifice 31 is a carbide material. As illustrated
in FIG. 2B, the pressure at the inlet of the drilling motor 50 (see
FIG. 1B) is the pressure P1, which is also illustrated in FIG. 2B.
Normal flow to the motor 50 occurs from upper end 58 through
passage 86 down around needle 27 and out lower end 56.
[0036] In the position shown in FIG. 2A, the low pressure transfer
tube 16 communicates with cavity 88, which in turn through openings
or ports 17 communicates with cavity 90. Those skilled in the art
will appreciate that as long as the seals 74 do not straddle the
top end of the low pressure transfer tube 16, the pressure P.sub.1
at the lower end 56 communicates through low pressure transfer tube
16 through cavity 88 and into cavity 90 so that the pressure
P.sub.1 acts on the area of the compensating piston 76 exposed to
cavity 90. A seal 92 retains the pressure P.sub.1 in cavity 90
while, at the same time, allowing the compensating piston 76 to
move with respect to the low pressure transfer tube 16. The low
pressure transfer tube 16 is secured to the needle 27 and is placed
in alignment with a longitudinal passage 94 in the needle 27. A
seal 96 separates the pressure P.sub.1, which exists in passage 94
and in low pressure transfer tube 16, from pressure P.sub.3, which
exists in cavity 82. Seal 78 serves a similar purpose around the
periphery of the needle 27.
[0037] The significant components of the apparatus now having been
described, its operation will be reviewed in more detail. FIGS.
2A-B reflect the apparatus A in the condition with the surface
pumps turned off. In that condition, the spring 22 pushes the
compensation piston 76 against delay valve tube 8 and, at the same
time, pushes the needle 27 against the ledge formed by opening 84.
At the same time the delay valve spring 10 pushes the delay valve
piston 9 against hydrostatic pressures applied through the upper
end 58 through the porous metal filter 7 and mud flow port 6. At
this point with no flow, P.sub.1=P.sub.2 and the delay valve piston
9 is in fluid pressure balance.
[0038] When the surface pumps are turned on, the first objective of
the apparatus A of the present invention is to obtain a preload
force on the needle 27 which actually compensates for the
mechanical condition of the motor 50 and any other variables
downhole which have affected the pressure drop experienced in the
region of the drilling motor 50 and the assembly since the last
time the pumps were operated from the surface. The desired preload
acts to put a force on the needle 27 which will prevent it from
rising on increasing pressure P.sub.1 until a predetermined level
is exceeded. Stated in general terms, the pressure P.sub.2 is
maintained as close as possible to a desirable level by modulation
of the position of needle 27 in response to fluctuations in the
pressure P.sub.1. Variations in pressure P.sub.1 will occur as a
result of the drilling activity being conducted with bit 40.
Accordingly, with the surface pumps turned on and the bit 40 off of
bottom, meaning that there is no drilling going on, the pressure
P.sub.2 increases with respect to pressure P.sub.3 as circulation
is established. When this occurs, the pressure P.sub.1 also
increases with respect to pressure P.sub.3. As previously stated,
cavity 82 communicates with pressure P.sub.3 through the porous
metal filter 26. By proper configuration of the compensating piston
76, the pressure P.sub.1, which exceeds the pressure P.sub.3,
communicates through the low pressure transfer tube 16 into cavity
88 through ports 17 and into cavity 90, and onto the top of
compensating piston 76. Ultimately, an imbalance of forces occurs
on compensating piston 76 due to pressure P.sub.1 in cavity 90 and
P.sub.3 in cavity 82 which causes piston 76 to compress the
compensation spring 22. The compensating piston 76 is designed to
complete its movement and reach an equilibrium position before the
piston valve 15 moves downward sufficiently to bring the seal 74
over the upper end of the low pressure transfer tube 16. FIGS. 3A
and B show the conclusion of all the movements when the pumps on
the surface are turned on and the bit 40 is off of bottom. However,
the movement occurs sequentially so that the piston 76 finds its
preload position, shown in FIG. 3B, before movement of piston valve
15 occurs. Movement of piston valve 15 occurs as the pressure
P.sub.2 ultimately communicates with cavity 62, as described
previously. The fluids in the well, which have been passed through
the porous metal filter 7 push on the delay valve piston 9 and
ultimately the delay valve spring 10 is compressed. As previously
stated, the cavity 66 is filled with a clean oil which is
ultimately forced through the orifice assembly 12 into cavity 68 by
movement of delay valve piston 9. The orifice assembly 12 is
designed to provide a sufficient time delay, generally 1 to 2
minutes, so that the compensating piston 76 can find its steady
state position. Those skilled in the art will appreciate that when
the surface pumps are turned on and flow is initiated, it takes a
little time for the circulating system to stabilize. Thus, one of
the desirable functions of the apparatus A is that the low pressure
transfer tube 16 is not capped by the piston valve 15 by virtue of
seal 74 until the compensating piston 76 has found its desirable
position shown in FIG. 3B. In the position shown in FIG. 3B, the
forces on the compensating piston 76 have reached equilibrium.
Thus, the pressure P.sub.3 acting on the bottom of compensating
piston 76 in conjunction with the force of compensation spring 22
becomes balanced with the pressure P.sub.1 that is acting in the
now enlarged cavity 90. Ultimately, enough clean fluid passes
through the delay valve orifice assembly 12 to urge the piston
valve 15 downward to the position shown in FIG. 3A such that the
seal 74 straddles the low pressure transfer tube 16. As soon as
this occurs, the compensation piston 76 is in effect isolated from
further fluctuations of the pressure P.sub.1. In effect, the
pressure at the lower end 56 can no longer communicate with the top
end of the compensating piston 76 because the piston valve 15 has
cutoff the access to cavity 90 by capping off the low pressure
transfer tube 16.
[0039] After having attained the position shown in FIGS. 3A and B,
the drilling with bit 40 begins. This puts an additional load on
the motor 50 which in turn raises the pressure P.sub.1. As the
pressure P.sub.1 rises, the needle 27 has a profile, which in turn
decreases the pressure drop across the restrictor orifice 31 as the
needle 27 moves upwardly. Due to the profiles of needle 27 as the
needle moves up the pressure drop change per unit of linear
movement is increased. The spring 22 resists upward movement of the
modulation ram needle 27. At this point in time when the bit 40
contacts the bottom of the hole, the compensating piston 76 is
immobilized against upward movement because the piston valve 15 has
capped off the pressure P.sub.1 from communicating with cavity 90.
Since P.sub.2 is always greater than P.sub.1 due to frictional
losses and the pressure drop across the orifice 31, the pressure in
cavity 68, which is P.sub.2 keeps the piston valve 15 firmly
bottomed in the delay valve tube 8. As previously stated, the seal
70 prevents the pressure P.sub.2, which is in cavity 68 in FIG. 4A
from getting into cavity 90. Accordingly, the compensating piston
76 now is in a position where it supports the spring 22 with a
given preload force on the needle 27. As the motor 50 takes a
greater pressure drop, which tends to increase P.sub.1, the upward
forces on needle 27 eventually exceed the downward forces on needle
27. The downward forces on needle 27 comprise the pressure P.sub.3
acting on top of the needle 27 in cavity 82 in combination with the
preload force from spring 22. Thus, an increase in the pressure
P.sub.1 which exceeds P.sub.3 backs the needle 27 out of the
orifice 31 removing some of the pressure losses that had been
previously taken across the orifice 31. Thus, the increase in
pressure drop at the motor 50 is compensated for by a decrease in
pressure drop at the orifice 31 with the net result being that very
little, if any, pressure change occurs as P.sub.2 remains nearly
steady. In other words, the system pressure drops upstream of the
upper end 58 remains steady and all that desirably occurs is an
increase in pressure drop through the motor 50 compensated for by a
corresponding decrease in pressure drop across the restrictor
orifice 31 with the net result that the thruster 34 sees little, if
any, pressure change as indicated by the symbol P.sub.2.
[0040] When the pumps are again turned off at the surface, the
apparatus A quickly resets itself. As the pumps are turned off at
the surface P.sub.2 decreases, thus reducing the pressure in cavity
62. A check valve 13 allows flow into cavity 66 from cavity 68.
Accordingly, when the spring 10 pushes the piston 9 upwardly, it
draws fluid through the check valve 13, which in turn draws fluid
out of cavity 68. The drawing of fluid out of cavity 68 brings up
the piston valve 15 and ultimately takes the seal 74 off of the top
of the low pressure transfer tube 16. When this occurs, P.sub.1 can
then communicate through the low pressure transfer tube 16 and into
cavity 90 as previously described. Ultimately, with no fluid
circulating, P.sub.3 will be equal to P.sub.1 and the spring 22
will bias the compensating piston 76 back to its original position
shown in FIG. 2B. Therefore, the next time the surface pumps are
started, the process will repeat itself as the compensating piston
76 seeks a new equilibrium position fully compensating for any
changes in condition in the circulating system from the drilling
motor 50 down to the bit 40.
[0041] Those skilled in the art will appreciate that the
configuration of the compensating piston 76 is selected in
combination with a particular spring rate for the compensating
spring 22 to deliver a preload force on the needle 27 within a
limited range. Too little preload is undesirable in the sense that
minor pressure fluctuations in P.sub.1 during drilling will cause
undue oscillation of the needle 27. On the other hand, if the
preload force is too great, the system becomes too insensitive to
changes in P.sub.1, thus adversely affecting the operation of the
thruster 34 and if extreme enough causing the thruster 34 to load
the bit 40 to the extent that the motor 50 will bog down and stall.
Thus, depending on the parameters of the drilling motor 50 and the
bit 40, the configurations of the compensating piston 76 and spring
22, as well as the profile of the needle 27 can be varied to obtain
the desired performance characteristics. Similarly, the orifice
assembly 12 can be designed to provide the necessary delay in the
capping of the low pressure transfer tube 16 to allow the system to
stabilize before the low pressure transfer tube 16 is capped. This,
in turn, allows the compensating piston 76 to seek its neutral or
steady state position before its position is immobilized as the
piston valve 15 caps off the low pressure transfer tube 16. In
essence, what is created is a combination spring and damper acting
on the needle 27. The spring is the compensation spring 22, while
the damper is the cavity 82 which varies in volume as fluid is
either pushed out or is sucked in through port 24 or the porous
metal filter 26 which can act as an orifice in the damper
system.
[0042] Those skilled in the art will now appreciate that the
apparatus A provides several important benefits. It is
self-contained and it is a portion of the assembly. Each time the
surface pumps are turned on the compensating feature adjusts the
preload on the needle 27 to account for variations within the
circulating system. Once in operation during drilling, the system
acts to smooth out pressure fluctuations caused by changes in the
drilling activity so that the pressure fluctuations are isolated as
much as possible from the thruster 34. With these features in
place, drilling can occur using a downhole motor. Downhole motors
are desirable when using coiled tubing or when the string, even
though it is rigid tubing, is sufficiently long and flexible to the
extent that a downhole motor becomes advantageous. The system using
the apparatus A resets quickly using the check valve feature and
stands ready for a repetition of the process the next time the
surface pumps are turned on.
[0043] It should be noted that the normal pressure drop across the
orifice 31 with the bit 40 off of bottom is approximately 400 or
500 psi in the preferred embodiment. That pressure drop is reduced
during operation as the drilling motor 50 resistance increases
which causes the needle 27 to compensate by backing out of the
orifice 31, thus reducing the pressure drop. It should also be
noted that the amount of preload provided by the compensation
spring 22 needs to be moderated so as not to be excessive.
Excessive preload on the needle 27 reduces the sensitivity of the
apparatus A in that it requires the pressure P.sub.1 to rise to a
higher level prior to the apparatus reacting by moving the needle
27 against the spring 22. Thus, a higher preload on spring 22 also
reduces sensitivity. Those skilled in the art can use known
techniques for adjusting the variables of preload and needle
profile within an orifice 31 to obtain not only the desired
pressure compensation result but the appropriate first, second, and
higher order responses of the control system so that a stable
operation of the modulation ram needle 27 in orifice 31 is
achieved.
[0044] FIGS. 5A-5C is a schematic diagram of a bottomhole assembly
500 with a thruster whose operation is controlled as a function of
one or more parameters of interest determined downhole and/or
provided from the surface during drilling of a wellbore according
to one embodiment of the present invention. The bottomhole assembly
500 includes a thruster 501 (a force application device) that
applies force to a lower section 502 of the bottomhole assembly
500. The lower section 502 includes a mud motor 503 that contains a
lobed rotor 503a that rotates inside a lobed elastomeric stator
503b when drilling fluid 580 passes through progressive cavities
503c formed between the rotor 503a and stator 503b. The rotor 503a
is coupled to the drill bit 540 via a drill shaft 504 that passes
through a bearing assembly 505. Drilling motors and bearing
assemblies are known in the art and are not described in detail
herein, except for the placement of certain sensors for use in the
present invention. A bent sub 554 between the mud motor 503 and the
bearing assembly 505 allows the BHA 500 to drill curved wellbores.
A stabilizer 548a, preferably having a plurality of adjustable pads
or ribs 548a.sub.1-548a.sub.n is disposed on the bearing assembly
505 to provide lateral stability to the bottomhole assembly 500
near the drill bit 540 and to provide a certain degree of steering
of the drill bit 540. Additional stabilizers, such as stabilizer
546, may be provided above the mud motor 503 to provide lateral
stability to the bottomhole assembly 500 during drilling. An
adjustable bend 552 may also be provided to drill shorter radius
boreholes.
[0045] One or more sensors 512 are included in the drill bit 540 to
provide measurements for certain drill bit parameters, including
pressure at the drill bit bottom and wear of the drill bit 540. A
module 514 containing a plurality of sensors 514a provides
measurements of various BHA physical or dynamics parameters. The
module 514 is preferably provided near the drill bit 540. The BHA
dynamic parameters include weight on bit, torque on bit, whirl,
vibration, bit bounce and stick-slip. The BHA dynamic parameter
sensors may be located at any other suitable locations in the
bottomhole assembly 500. For example, a group of BHA dynamic
parameter sensors 545 may be located above the mud motor 503 to
provide measurements for the desired BHA dynamic parameters.
Sensors 514b disposed in the bearing assembly 505 measure the
radial and axial displacement of the drill shaft 504 and other
desired physical bearing assembly parameters (e.g. leakage, oil
level for sealed bearings, etc.).
[0046] A set of temperature sensors 520a-520c, respectively measure
temperatures T.sub.1-T.sub.3 of the elastomeric stator along its
length while pressure sensors 522a below the mud motor 503 and 522b
above the mud motor 503 provide differential pressure across the
mud motor 503. A differential pressure sensor 522c instead may be
used to determine the differential pressure across the mud motor
503. Sensors 530 provide measurement for the rotational speed (rpm)
of the mud motor 503. Additional sensors 531 in the mud motor 503
provide pressure of the drilling fluid 580 in the mud motor 503 and
the annulus pressure.
[0047] The thruster 501 has a force application member 504 which
strokes or reciprocates in an outer housing 536 between a retracted
position and an extended position. When the member 504 extends, it
moves toward the drill bit 540, thereby moving the lower section
502 of the bottomhole assembly 500. The drill string 32 above the
thruster 501 is held stationary or anchored in the wellbore by any
suitable device, such as a retractable anchor or a packer (not
shown) to cause the force application member 504 to exert force on
the drill bit 540. A thruster power unit 560 causes the member 504
to move downhole to exert the desired force on the drill bit 540.
The power unit 560 may be an electric motor, a hydraulic power
unit, a pneumatic power unit or a combination thereof. The power
unit 560 is adapted to cause the stroke member 504 to move in both
the downhole and uphole directions as shown by the double arrow
504a. A position sensor or a displacement sensor 550 measures the
displacement of the stroke member 504, which provides the rate of
penetration ("ROP") of the drill bit 540. An electrical control
circuit or unit 562 in the BHA controls the operation of the
thruster power unit 560 as more fully described below in reference
to FIG. 8.
[0048] Appropriate fluid paths (not shown) through the thruster
assembly 501 are provided to allow the drilling fluid 580 to flow
downhole to the mud motor 503. Commonly utilized
measurement-while-drilling ("MWD") or logging-while-drilling
("LWD") sensors 570 are provided at suitable location(s) in the
bottomhole assembly 500. The MWD/LWD sensors are known in the art
and may include resistivity sensors, sensors for determining the
formation porosity, formation density measuring sensors, and
nuclear magnetic resonance sensors. Sensors for determining the
position, azimuth and orientation (collectively represented by
numeral 514b) are preferably located below the mud motor 503.
Accelerometers, magnetometers and gyroscopic devices are utilized
as position/direction sensors. A two-way telemetry 572 enables the
bottomhole assembly 500 to communicate with the surface unit (not
shown).
[0049] The control unit 562 contains one or more micro-processors,
one or memory devices and other electronic control circuits. The
circuitry for such control units is known in the art and is not
described in detail herein. The operation and function of the
control unit 562 as it applies to the present invention, however,
is described below in reference to FIG. 8. The sensors described
above provide measurements to the control unit 562. For simplicity,
only one electrical control unit 562 is shown. The functions of the
control unit described herein, however, may be distributed among
more than one processor or circuits. Such methods are known in the
art and are not described in detail herein.
[0050] Signals from the various sensors are processed to compute
the values of the various parameters of interest, which, as
described above, may include the drill bit parameters (drill bit
wear, pressure at the drill bit bottom, etc.), drilling assembly
physical parameters or BHA dynamic parameters (vibration,
pressures, temperature, radial and axial displacement, whirl, stick
slip, bit bounce, etc.), mud motor parameters (differential
pressure or pressure drop across the mud motor, stator wear
condition, pressure differential between the mud motor and the
annulus pressure, fluid flow rate through the motor, motor rpm,
etc.), and thruster parameters (displacement, applied force one the
drill bit, pressures and temperatures). The drilling parameters
such as the weight on bit ("WOB"), rate of penetration ("ROP"),
hook load, and the drilling fluid flow rate are determined from the
measurements of the appropriate sensors in the bottomhole assembly
500 or at the surface. The drilling fluid 580 is pumped through the
drill string 32 from the surface. The flow rate and the pressure at
the surface may also be communicated to the control unit 562. The
formation evaluation or MWD sensors determine various
characteristics (formation evaluation parameters) of the formation
penetrated by the wellbore. The formation evaluation parameters
include, formation resistivity, formation porosity, density,
permeability, water saturation and the rock matrix type.
Information, such as the type of formation (rock matrix) being
drilled, which may be relevant to the determination of the force to
be generated by the thruster 501 is also provided to the control
unit 562.
[0051] As more fully described below in reference to FIG. 8, the
control unit 562 determines the desired amount of the force to be
applied to the drill bit 540 as a function of one or more
parameters of interest that will provide enhanced drilling and
extended life of the bottomhole assembly 500. The control unit 562
then causes the power unit 560 to adjust the applied force
accordingly. Thus, the thruster 501 automatically adjusts the
weight on bit as the drilling conditions change to achieve higher
drilling efficiency, which is usually considered to be the higher
drilling rate over a given time period. It should be noted that it
is possible to achieve higher drilling rates over relatively short
periods of time at the expense of the health of one or more
components of the bottomhole assembly 500. For example, higher
penetration rate may wear out the drill bit 500 rapidly or cause
damage to the mud motor 503. Such drilling rates, though higher,
would require tripping out the drill string 32 to replace the
damaged or worn components, which can be very time consuming,
expensive and may reduce the overall drilling efficiency. Greater
drilling efficiency can be obtained by adjusting the drilling
parameters, including the WOB, in a manner that will simultaneously
maintain a number of parameters within their respective desired
limits. The thruster 501 of the present invention enables drilling
of the wellbores by maintaining the desired parameters of interest
within their limits. In the present invention, the WOB may be
continuously or periodically determined by models and programs
provided to the BHA.
[0052] FIG. 6 shows an embodiment of a thruster 601 that utilizes a
hydraulic power unit controlled by an electrical control unit 660
for use with a bottomhole assembly 600. The thruster 601 includes a
stroke member or reciprocating force member 610 (also referred to
herein as a "force application member") that reciprocates in a
housing 636. The lower end 612 of the stroke member 610 is coupled
to the lower section 615 of the bottomhole assembly 600, while the
upper end terminates in a piston 614. The piston 614 reciprocates
in upper and lower fluid chambers 616 and 618. Seals 622 provide
seals between the stroke member 610 and fluid chambers 616 and 618.
The upper end 630 of the thruster 601 is connected to the uphole
section 670 of the drill string 32. Drilling fluid 680 passes
downhole to the mud motor (FIG. 5) via a through passageway 602 in
the stroke member 610. A hydraulic power unit 640 provides power to
the reciprocating member 610. The power unit 640 supplies fluid,
such as oil, under pressure from a source thereof 646 to the upper
chamber 616 via a line 642 and a port 644. A fluid control valve
645 in the line 642 may be modulated to modulate the fluid supply
to the upper chamber 616. Fluid from the source 646 may also be
provided to the lower chamber via line 647 and port 649. Suitable
fluid return paths (not shown) from the chambers 616 and 618 to the
source 646 are provided to bleed off the pressure. The power unit
640 may also be designed to maintain desired differential pressure
between the two chambers 616 and 618.
[0053] Pressure sensor 648 and volumetric sensor 650 respectively
provide pressure P.sub.1, in and volume V.sub.1 of the upper
chamber 616. Similar sensors may be used for the lower chamber 618.
A displacement sensor 652 measures the displacement of the stroke
member 610 from an initial or retracted position, which allows the
operator or system to determine when to retract the stroke member
610 to repeat the cycle. It also provides a relatively precise
measure of the rate of penetration. A control unit 660, similar to
the control unit 560 described above (FIG. 5A), utilizes the
pressure sensor, volumetric sensor and displacement sensor
measurements and controls the operation of the hydraulics power
unit 640 to maintain the desired force on the drill bit 540 (FIG.
5). The pressure P.sub.1, in the upper chamber 616 controls the
force (weight on bit) on the drill bit 540 while the fluid volume
V.sub.1 in the upper chamber 616 controls the axial displacement
("D") of the thruster 601. The control unit 640 controls the
thruster 601 as a function of selected parameters of interest, as
more fully described below in reference to FIG. 8.
[0054] FIG. 7 shows a schematic diagram of an alternative
embodiment of a thruster 701 of a bottomhole assembly 700 which
utilizes drilling fluid 780 to exert the desired force on the drill
bit 540 (FIG. 5). The thruster 701 includes a stroke member 710
that reciprocates or strokes in an outer housing 702. The lower end
712 of the stroke member 710 is coupled to the lower portion 715 of
the bottomhole assembly 700. Drill bit is attached to the
bottomhole end of the lower section 715. The upper end 714 of the
stroke member 710 has a valve opening or seat 718 that allows the
drilling fluid 780 to pass through the thruster 701. The drilling
fluid 780 flows through the stroke member 710 via an opening 716.
The flow of the fluid through the opening 716 is controlled by a
valve assembly 720 that includes a conical member or spear 722
which can open and close the opening 716. The pressure of the
drilling fluid 780 is applied to the upper end 714A of the stroke
member 710 at the flange 714a. The opening 724 between the spear
722 and the seat 718 defines the fluid flow path through the stroke
member 710. Closing the valve 718 will exert the maximum force on
the stroke member 710. Bypass fluid flow paths through the thruster
701 to section 715 of the bottomhole assembly (not shown) may be
provided to ensure uninterrupted fluid flow to the drill bit.
Completely opening of the valve 718 will equalize the pressure on
both sides of the opening 718. The spear 722 may be operated by a
suitable device 726 such as a stepper motor or a
solenoid-controlled valve.
[0055] Still referring to FIG. 7, an electrical control unit 730
controls the operation of the spear 722. To maintain a desired
force on the drill bit, the control valve 720 is modulated to
compensate for the affects of the pressure changes in the mud motor
and changes in the downhole conditions, which allows maintaining
the thruster force to any desired value while compensating for the
downhole pressure changes. As an example, the graph of FIG. 7A
shows that the pressure P exerted by the thruster 701 remains
constant at P.sub.1 over time T even when the mud motor
differential pressure P.sub.m changes. Suitable sensors measure
pressure P.sub.3 applied to the bottomhole assembly section 715 and
the pressure P.sub.4 above the thruster 701. The electrical control
unit 730 includes a processor and other desired circuit to control
the action of the valve member 722 to maintain P.sub.3 at the
desired valve during drilling of the wellbore. The length of the
cylinder 730 between the flange 714 and the housing 702 defines the
length of the stroke or travel for the thruster 701.
[0056] FIG. 8 is a functional block diagram of an electrical
control unit 800 for use in the present invention. The control unit
800 includes one or more micro-processors 810, associated memory
units 811 and other electrical circuits (not shown). The processor
810 receives signals from the various downhole sensors in the
bottomhole assembly described above. The sensor data includes
signals for drill bit parameters 814, bottomhole assembly dynamic
parameters 816, drilling parameters 818, formation evaluation
("FE") parameters 820, directional parameters 822 and other
downhole parameters 824. Data and signals (surface parameters) may
also be communicated to the processor 810 from a surface computer
840 via a two-way telemetry 830. Such data may include the surface
fluid pressure, drilling fluid flow rate, drilling fluid
properties, such as the density and viscosity, effective
circulating density, rock matrix type, hook load, etc. The
processor 810 preferably is provided with one or models 812 that
utilize data from the sensors and the surface supplied parameters
840 to determine the force to be applied by the thruster power unit
850.
[0057] The processor 810 then controls the power unit 850 to apply
the required power on the thruster stroke member 860. The actual
values of the thruster parameters 862, such as the magnitude of the
force and the thruster displacement are fed back to the processor
810. The processor 810 continues to cause the thruster power unit
850 to adjust the applied force so as to maintain selected
parameters within their desired limits. The processor 810 may also
be programmed to cause the thruster to apply constant force on the
bit. In one aspect of the invention, the models 812 provide the
ranges or values of the selected parameters, such as the weight on
bit, differential pressure across the mud motor, vibration, etc.
The processor 810 adjusts the thruster force so as to maintain
these parameters at their desired values. Thus, if the mud motor
pressure differential is outside the allowed limits, the thruster
force is adjusted (within its own limits) until the mud motor
pressure is within the allowed limits. Similarly, if the vibrations
are excessive, perhaps due to bit bounce, the thruster increases
the weight on the bit to reduce the vibrations. If the thruster
adjustments cannot maintain the selected parameters within or at
their respective desired values, the processor 810 may be
programmed to transmit signals to the surface to provide warning to
the drilling operator or to utilize alternative models. The
processor 810 is preferably programmed to upgrade the models 812 as
the drilling conditions and the formation being penetrated change,
making the models 812 dynamic.
[0058] The foregoing description is directed to particular
embodiments of the present invention for the purpose of
illustration and explanation. It will be apparent, however, to one
skilled in the art that many modifications and changes to the
embodiment set forth above are possible without departing from the
scope and the spirit of the invention. It is intended that the
following claims be interpreted to embrace all such modifications
and changes.
* * * * *