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Publication numberUS20010045300 A1
Publication typeApplication
Application numberUS 09/271,947
Publication dateNov 29, 2001
Filing dateMar 18, 1999
Priority dateMar 20, 1998
Also published asCA2266198A1
Publication number09271947, 271947, US 2001/0045300 A1, US 2001/045300 A1, US 20010045300 A1, US 20010045300A1, US 2001045300 A1, US 2001045300A1, US-A1-20010045300, US-A1-2001045300, US2001/0045300A1, US2001/045300A1, US20010045300 A1, US20010045300A1, US2001045300 A1, US2001045300A1
InventorsRoger Fincher, Volker Krueger, Peter Fontana, Friedhelm Makohl
Original AssigneeRoger Fincher, Volker Krueger, Peter Fontana, Friedhelm Makohl
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Thruster responsive to drilling parameters
US 20010045300 A1
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.
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Claims(20)
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 P1; the pressure adjacent the upper end will be referred to as P2; and the annulus pressure outside the containment sub 1 will be referred to as P3. Again, the objective is to keep P2 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 P3 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 P3 as shown or to an external or internal reservoir. The reservoir can have a floating piston with one side exposed to P3 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 P1 at the lower end 56 communicates through low pressure transfer tube 16 through cavity 88 and into cavity 90 so that the pressure P1 acts on the area of the compensating piston 76 exposed to cavity 90. A seal 92 retains the pressure P1 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 P1, which exists in passage 94 and in low pressure transfer tube 16, from pressure P3, 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, P1=P2 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 P1 until a predetermined level is exceeded. Stated in general terms, the pressure P2 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 P1. Variations in pressure P1 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 P2 increases with respect to pressure P3 as circulation is established. When this occurs, the pressure P1 also increases with respect to pressure P3. As previously stated, cavity 82 communicates with pressure P3 through the porous metal filter 26. By proper configuration of the compensating piston 76, the pressure P1, which exceeds the pressure P3, 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 P1 in cavity 90 and P3 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 P2 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 P3 acting on the bottom of compensating piston 76 in conjunction with the force of compensation spring 22 becomes balanced with the pressure P1 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 P1. 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 P1. As the pressure P1 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 P1 from communicating with cavity 90. Since P2 is always greater than P1 due to frictional losses and the pressure drop across the orifice 31, the pressure in cavity 68, which is P2 keeps the piston valve 15 firmly bottomed in the delay valve tube 8. As previously stated, the seal 70 prevents the pressure P2, 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 P1, the upward forces on needle 27 eventually exceed the downward forces on needle 27. The downward forces on needle 27 comprise the pressure P3 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 P1 which exceeds P3 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 P2 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 P2.

[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 P2 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, P1 can then communicate through the low pressure transfer tube 16 and into cavity 90 as previously described. Ultimately, with no fluid circulating, P3 will be equal to P1 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 P1 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 P1, 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 P1 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 503 a that rotates inside a lobed elastomeric stator 503 b when drilling fluid 580 passes through progressive cavities 503 c formed between the rotor 503 a and stator 503 b. The rotor 503 a 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 548 a, preferably having a plurality of adjustable pads or ribs 548 a 1-548 a 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 514 a 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 514 b 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 520 a-520 c, respectively measure temperatures T1-T3 of the elastomeric stator along its length while pressure sensors 522 a below the mud motor 503 and 522 b above the mud motor 503 provide differential pressure across the mud motor 503. A differential pressure sensor 522 c 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 504 a. 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 514 b) 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 P1, in and volume V1 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 P1, in the upper chamber 616 controls the force (weight on bit) on the drill bit 540 while the fluid volume V1 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 714 a. 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 P1 over time T even when the mud motor differential pressure Pm changes. Suitable sensors measure pressure P3 applied to the bottomhole assembly section 715 and the pressure P4 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 P3 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.

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Classifications
U.S. Classification175/26, 175/61, 175/45, 175/27, 175/73
International ClassificationE21B7/06, E21B44/04, E21B44/00
Cooperative ClassificationE21B44/005, E21B44/04, E21B7/068
European ClassificationE21B44/04, E21B7/06M, E21B44/00B
Legal Events
DateCodeEventDescription
May 28, 1999ASAssignment
Owner name: BAKER HUGHES INCORPORATED, TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:FINCHER, ROGER;KRUEGER, VOLKER;FONTANA, PETER;AND OTHERS;REEL/FRAME:009985/0275;SIGNING DATES FROM 19990427 TO 19990505