US20010045300A1 - Thruster responsive to drilling parameters - Google Patents
Thruster responsive to drilling parameters Download PDFInfo
- Publication number
- US20010045300A1 US20010045300A1 US09/271,947 US27194799A US2001045300A1 US 20010045300 A1 US20010045300 A1 US 20010045300A1 US 27194799 A US27194799 A US 27194799A US 2001045300 A1 US2001045300 A1 US 2001045300A1
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- United States
- Prior art keywords
- drill bit
- bha
- force
- pressure
- drilling
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- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
- E21B44/02—Automatic control of the tool feed
- E21B44/04—Automatic control of the tool feed in response to the torque of the drive ; Measuring drilling torque
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
- E21B44/005—Below-ground automatic control systems
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
- E21B7/04—Directional drilling
- E21B7/06—Deflecting the direction of boreholes
- E21B7/068—Deflecting the direction of boreholes drilled by a down-hole drilling motor
Definitions
- 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.
- BHA bottomhole assemblies
- mud motor drilling motor
- 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.
- a thruster is often utilized to exert axial force (force along the borehole longitudinal axis) on to the drill bit.
- 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.
- the telescopic member of the thruster 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.
- 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.
- 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.
- 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.
- this thruster cannot adjust the force on the bit as the drilling conditions change.
- 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.
- ROP rate of penetration
- 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.
- 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.
- 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.
- 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.
- 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.
- ROP rate of penetration
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- FIGS. 1 A- 1 C 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.
- FIGS. 2 A- 2 B is a sectional view of the drill string pressure modulation valve in the run-in position without the rig pump circulating.
- FIGS. 3 A- 3 B is the view of FIGS. 2 A-B with the pumps circulating, but the bit off bottom.
- FIGS. 4 A- 4 B is the view of FIGS. 3 A-B with the pumps running and the drill bit on bottom.
- FIGS. 5 A- 5 C is a schematic diagram of a bottomhole assembly with a thruster whose operation is controlled as a function of certain parameters of interest.
- FIG. 6 shows schematic diagram of a thruster according to one embodiment of the present invention.
- FIG. 7 shows schematic diagram of a device for controlling the flow of the drilling fluid through the thruster.
- FIG. 7A shows a graph depicting a constant pressure applied by the thruster while the mud motor pressure varies.
- FIG. 8 shows block diagram of an embodiment of an electrical control unit for use with the thrusters shown in FIGS. 5 - 7 .
- FIGS. 1 A- 1 C 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 .
- FIGS. 1 A-C also indicates an upper stabilizer 46 and a lower stabilizer 48 between which is a drilling motor 50 .
- bent subs 52 and 54 can also be employed in the bottomhole assembly.
- 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 .
- the thruster 34 adds an incremental force through the drilling motor 50 down to 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 .
- 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.
- 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 .
- the pressure adjacent lower end 56 will be referred to as P 1 ; the pressure adjacent the upper end will be referred to as P 2 ; and the annulus pressure outside the containment sub 1 will be referred to as P 3 .
- the objective is to keep P 2 as constant as possible.
- 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 .
- 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 .
- compensation spring 22 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.
- 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 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 3 as shown or to an external or internal reservoir. The reservoir can have a floating piston with one side exposed to P 3 through the filter 26 . This layout can reduce potential plugging problems in filter 26 .
- 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.
- 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 .
- the low pressure transfer tube 16 communicates with cavity 88 , which in turn through openings or ports 17 communicates with cavity 90 .
- the pressure P 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 1 acts on the area of the compensating piston 76 exposed to cavity 90 .
- a seal 92 retains the pressure P 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 1 , which exists in passage 94 and in low pressure transfer tube 16 , from pressure P 3 , which exists in cavity 82 .
- Seal 78 serves a similar purpose around the periphery of the needle 27 .
- FIGS. 2 A-B reflect the apparatus A in the condition with the surface pumps turned off.
- 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 .
- 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 .
- P 1 P 2 and the delay valve piston 9 is in fluid pressure balance.
- 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 1 until a predetermined level is exceeded.
- the pressure P 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 1 . Variations in pressure P 1 will occur as a result of the drilling activity being conducted with bit 40 .
- the pressure P 2 increases with respect to pressure P 3 as circulation is established.
- the pressure P 1 also increases with respect to pressure P 3 .
- cavity 82 communicates with pressure P 3 through the porous metal filter 26 .
- the pressure P 1 which exceeds the pressure P 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 .
- an imbalance of forces occurs on compensating piston 76 due to pressure P 1 in cavity 90 and P 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 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.
- 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.
- 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.
- the drilling with bit 40 begins. This puts an additional load on the motor 50 which in turn raises the pressure P 1 .
- 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 .
- the compensating piston 76 is immobilized against upward movement because the piston valve 15 has capped off the pressure P 1 from communicating with cavity 90 .
- the downward forces on needle 27 comprise the pressure P 3 acting on top of the needle 27 in cavity 82 in combination with the preload force from spring 22 .
- P 1 which exceeds P 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 .
- 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 2 remains nearly steady.
- 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 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 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.
- 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.
- 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 .
- the spring is the compensation spring 22
- 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.
- 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.
- 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 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.
- FIGS. 5 A- 5 C 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.
- 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 .
- 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.).
- a set of temperature sensors 520 a - 520 c respectively measure temperatures T 1 -T 3 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.
- 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.
- MWD measurement-while-drilling
- LWD logging-while-drilling
- 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).
- 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 .
- 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.
- 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).
- drill bit parameters drilling 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 annul
- 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 .
- 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.
- 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 .
- the thruster 501 of the present invention enables drilling of the wellbores by maintaining the desired parameters of interest within their limits.
- the WOB may be continuously or periodically determined by models and programs provided to the BHA.
- 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 .
- Pressure sensor 648 and volumetric sensor 650 respectively provide pressure P 1 , in and volume V 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 1 in the upper chamber 616 controls the force (weight on bit) on the drill bit 540 while the fluid volume V 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.
- 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 714 A 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 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.
- an electrical control unit 730 controls the operation of the spear 722 .
- 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.
- the graph of FIG. 7A shows that the pressure P exerted by the thruster 701 remains constant at P 1 over time T even when the mud motor differential pressure P m changes.
- Suitable sensors measure pressure P 3 applied to the bottomhole assembly section 715 and the pressure P 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 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 .
- 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 .
- FE formation evaluation
- Data and signals 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 .
- 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.
- 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.
- 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.
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.
Description
- This application takes priority from United States patent application Ser. No. 60/078,733 filed on Mar. 20, 1998.
- 1. Field of the Invention
- 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.
- 2. Description of the Related Art
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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:
- 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.
- FIGS.2A-2B is a sectional view of the drill string pressure modulation valve in the run-in position without the rig pump circulating.
- FIGS.3A-3B is the view of FIGS. 2A-B with the pumps circulating, but the bit off bottom.
- FIGS.4A-4B is the view of FIGS. 3A-B with the pumps running and the drill bit on bottom.
- 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.
- FIG. 6 shows schematic diagram of a thruster according to one embodiment of the present invention.
- FIG. 7 shows schematic diagram of a device for controlling the flow of the drilling fluid through the thruster.
- FIG. 7A shows a graph depicting a constant pressure applied by the thruster while the mud motor pressure varies.
- FIG. 8 shows block diagram of an embodiment of an electrical control unit for use with the thrusters shown in FIGS.5-7.
- FIGS.1A-1C illustrate a drill string modulation valve for use with a thruster in the
bottomhole assembly 100 according to the present invention. Atubing string 32, which can be rigid or coiled tubing, supports adrill string thruster 34. Thethruster 34 has anouter housing 36 and aninternal pipe 38. Theinternal pipe 38 is reciprocally mounted within theouter housing 36 and extends as thedrill bit 40 advances. Thethruster 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 theinternal 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 thebit 40. The bottomhole assembly of FIGS. 1A-C also indicates anupper stabilizer 46 and alower stabilizer 48 between which is adrilling motor 50. Optionally, to assist in drilling deviated wellbores,bent subs - 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 thedrill string 32. The weight or force on thedrill bit 40 is determined by the pressure difference internally to thethruster 34 atpoint 42 and the annular pressure outside atpoint 44. Thedrilling motor 50 is a variable resistance in this circuit in that the pressure drop across it is variable depending on the load imposed on themotor 50. For example, as drilling begins, thebit 40 causes an increase in load on thedrilling motor 50 which increases the pressure drop between thedrilling motor 50 and theannulus 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 atpoint 42 with respect to the pressure atpoint 44. As a result, thethruster 34 adds an incremental force through thedrilling motor 50 down tobit 40. As additional weight is put on thebit 40, thedrilling motor 50 increasingly bogs down to the point where this cycle continues until thedrill bit 40 stalls themotor 50 due to the extreme downward pressure that is brought to bear on thebit 40 from the ever increasing internal pressure atpoint 42 inside thethruster 34. Thethruster 34 instead of feeding out theinternal pipe 38 at a lower rate to compensate for the advancement of thebit 40, is urged by the rise in pressure internally atpoint 42 to feed out theinternal pipe 38 at a greater rate than the advancement of thebit 40, thus adding the force on bit, which in turn finally stalls thedrilling 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 theinternal point 42 of thethruster 34 despite variations in pressure drop that thedrilling motor 50 created during drilling. - Referring now to FIGS. 2A and B, the apparatus A has a containment sub1 which has a
lower end 56 which is oriented toward thedrilling motor 50, and anupper end 58, which is oriented toward thethruster 34. In order to describe the operation of the apparatus, the pressure adjacentlower 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. - The assembly shown in FIG. 2 starts near the upper end with lifting
head 2 which is supported from the containment sub 1 atthread 60. Attached to the lower end of the liftinghead 2 iscompressive pad 4, which in turn is secured to aporous metal filter 7. Below theporous metal filter 7, liquid that gets through it flows through mud flow port 6 to a cavity 62 abovedelay valve piston 9. Delayvalve piston 9 is sealed at its periphery byseal 64 to divide thedelay valve tube 8 into cavity 62 andcavity 66. Delay valve spring 10 resides incavity 66 and biases thedelay valve piston 9 toward theporous metal filter 7. A delay valve orifice assembly 12 is located at the lower end of thedelay valve tube 8. This is an orifice which, in essence, regulates the displacement of clean fluid incavity 66 intocavity 68. Those skilled in the art will appreciate that movement ofdelay valve piston 9 downhole toward thelower end 56 will result in displacement of clean fluid, generally an oil, fromcavity 66 through delay valve orifice block 11 intocavity 68 for ultimate displacement ofpiston valve 15.Piston valve 15 is sealed internally indelay valve tube 8 by seal 70. Thepiston valve 15 has a receptacle 72, which includes aseal 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 tocompensation tube body 20. Inside ofcompensation tube body 20 iscompensation spring 22.Spring 22 bears oncompensation piston 76 at one end and on the other end against modulatingram needle 27.Needle 27 is sealed internally in thecompensation tube body 20 byseal 78. The compensatingpiston 76 is also sealed within thecompensation tube body 20 by seal 80. Both the compensatingpiston 76 and theneedle 27 are movable within the compensatingtube body 20 for reasons which will be described below. In effect, thepiston 76 and theneedle 27 define acavity 82 within thecompensation tube body 20. The low pressure transfer tube 16 spans theentire cavity 82, but is not in fluid communication with that cavity. Avent port 23 is in fluid communication withcavity 82. Theport 23 is in fluid communication withcartridge vent port 24, which ultimately leads to transfergroove 25, which in turn leads to theporous metal filter 26. Accordingly, the pressure P3 is communicated into thecavity 82.Port 24 can be sized to makecavity 82 operate as a dampener on the movements ofneedle 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 thefilter 26. This layout can reduce potential plugging problems infilter 26. - Referring now toward the lower end of the
compensation tube body 20, theneedle 27 extends beyond an opening 84 and into therestrictor orifice 31. The preferred components for theneedle 27 and therestrictor 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 themotor 50 occurs fromupper end 58 throughpassage 86 down aroundneedle 27 and outlower end 56. - In the position shown in FIG. 2A, the low pressure transfer tube16 communicates with
cavity 88, which in turn through openings orports 17 communicates withcavity 90. Those skilled in the art will appreciate that as long as theseals 74 do not straddle the top end of the low pressure transfer tube 16, the pressure P1 at thelower end 56 communicates through low pressure transfer tube 16 throughcavity 88 and intocavity 90 so that the pressure P1 acts on the area of the compensatingpiston 76 exposed tocavity 90. A seal 92 retains the pressure P1 incavity 90 while, at the same time, allowing the compensatingpiston 76 to move with respect to the low pressure transfer tube 16. The low pressure transfer tube 16 is secured to theneedle 27 and is placed in alignment with a longitudinal passage 94 in theneedle 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 incavity 82.Seal 78 serves a similar purpose around the periphery of theneedle 27. - 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 thecompensation piston 76 againstdelay valve tube 8 and, at the same time, pushes theneedle 27 against the ledge formed by opening 84. At the same time the delay valve spring 10 pushes thedelay valve piston 9 against hydrostatic pressures applied through theupper end 58 through theporous metal filter 7 and mud flow port 6. At this point with no flow, P1=P2 and thedelay valve piston 9 is in fluid pressure balance. - 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 themotor 50 and any other variables downhole which have affected the pressure drop experienced in the region of thedrilling 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 theneedle 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 ofneedle 27 in response to fluctuations in the pressure P1. Variations in pressure P1 will occur as a result of the drilling activity being conducted withbit 40. Accordingly, with the surface pumps turned on and thebit 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 theporous metal filter 26. By proper configuration of the compensatingpiston 76, the pressure P1, which exceeds the pressure P3, communicates through the low pressure transfer tube 16 intocavity 88 throughports 17 and intocavity 90, and onto the top of compensatingpiston 76. Ultimately, an imbalance of forces occurs on compensatingpiston 76 due to pressure P1 incavity 90 and P3 incavity 82 which causespiston 76 to compress thecompensation spring 22. The compensatingpiston 76 is designed to complete its movement and reach an equilibrium position before thepiston valve 15 moves downward sufficiently to bring theseal 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 thebit 40 is off of bottom. However, the movement occurs sequentially so that thepiston 76 finds its preload position, shown in FIG. 3B, before movement ofpiston valve 15 occurs. Movement ofpiston 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 theporous metal filter 7 push on thedelay valve piston 9 and ultimately the delay valve spring 10 is compressed. As previously stated, thecavity 66 is filled with a clean oil which is ultimately forced through the orifice assembly 12 intocavity 68 by movement ofdelay valve piston 9. The orifice assembly 12 is designed to provide a sufficient time delay, generally 1 to 2 minutes, so that the compensatingpiston 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 thepiston valve 15 by virtue ofseal 74 until the compensatingpiston 76 has found its desirable position shown in FIG. 3B. In the position shown in FIG. 3B, the forces on the compensatingpiston 76 have reached equilibrium. Thus, the pressure P3 acting on the bottom of compensatingpiston 76 in conjunction with the force ofcompensation spring 22 becomes balanced with the pressure P1 that is acting in the now enlargedcavity 90. Ultimately, enough clean fluid passes through the delay valve orifice assembly 12 to urge thepiston valve 15 downward to the position shown in FIG. 3A such that theseal 74 straddles the low pressure transfer tube 16. As soon as this occurs, thecompensation piston 76 is in effect isolated from further fluctuations of the pressure P1. In effect, the pressure at thelower end 56 can no longer communicate with the top end of the compensatingpiston 76 because thepiston valve 15 has cutoff the access tocavity 90 by capping off the low pressure transfer tube 16. - After having attained the position shown in FIGS. 3A and B, the drilling with
bit 40 begins. This puts an additional load on themotor 50 which in turn raises the pressure P1. As the pressure P1 rises, theneedle 27 has a profile, which in turn decreases the pressure drop across therestrictor orifice 31 as theneedle 27 moves upwardly. Due to the profiles ofneedle 27 as the needle moves up the pressure drop change per unit of linear movement is increased. Thespring 22 resists upward movement of themodulation ram needle 27. At this point in time when thebit 40 contacts the bottom of the hole, the compensatingpiston 76 is immobilized against upward movement because thepiston valve 15 has capped off the pressure P1 from communicating withcavity 90. Since P2 is always greater than P1 due to frictional losses and the pressure drop across theorifice 31, the pressure incavity 68, which is P2 keeps thepiston valve 15 firmly bottomed in thedelay valve tube 8. As previously stated, the seal 70 prevents the pressure P2, which is incavity 68 in FIG. 4A from getting intocavity 90. Accordingly, the compensatingpiston 76 now is in a position where it supports thespring 22 with a given preload force on theneedle 27. As themotor 50 takes a greater pressure drop, which tends to increase P1, the upward forces onneedle 27 eventually exceed the downward forces onneedle 27. The downward forces onneedle 27 comprise the pressure P3 acting on top of theneedle 27 incavity 82 in combination with the preload force fromspring 22. Thus, an increase in the pressure P1 which exceeds P3 backs theneedle 27 out of theorifice 31 removing some of the pressure losses that had been previously taken across theorifice 31. Thus, the increase in pressure drop at themotor 50 is compensated for by a decrease in pressure drop at theorifice 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 theupper end 58 remains steady and all that desirably occurs is an increase in pressure drop through themotor 50 compensated for by a corresponding decrease in pressure drop across therestrictor orifice 31 with the net result that thethruster 34 sees little, if any, pressure change as indicated by the symbol P2. - 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 intocavity 66 fromcavity 68. Accordingly, when the spring 10 pushes thepiston 9 upwardly, it draws fluid through thecheck valve 13, which in turn draws fluid out ofcavity 68. The drawing of fluid out ofcavity 68 brings up thepiston valve 15 and ultimately takes theseal 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 intocavity 90 as previously described. Ultimately, with no fluid circulating, P3 will be equal to P1 and thespring 22 will bias the compensatingpiston 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 compensatingpiston 76 seeks a new equilibrium position fully compensating for any changes in condition in the circulating system from thedrilling motor 50 down to thebit 40. - 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 compensatingspring 22 to deliver a preload force on theneedle 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 theneedle 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 thethruster 34 and if extreme enough causing thethruster 34 to load thebit 40 to the extent that themotor 50 will bog down and stall. Thus, depending on the parameters of thedrilling motor 50 and thebit 40, the configurations of the compensatingpiston 76 andspring 22, as well as the profile of theneedle 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 compensatingpiston 76 to seek its neutral or steady state position before its position is immobilized as thepiston valve 15 caps off the low pressure transfer tube 16. In essence, what is created is a combination spring and damper acting on theneedle 27. The spring is thecompensation spring 22, while the damper is thecavity 82 which varies in volume as fluid is either pushed out or is sucked in throughport 24 or theporous metal filter 26 which can act as an orifice in the damper system. - 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 thethruster 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. - It should be noted that the normal pressure drop across the
orifice 31 with thebit 40 off of bottom is approximately 400 or 500 psi in the preferred embodiment. That pressure drop is reduced during operation as thedrilling motor 50 resistance increases which causes theneedle 27 to compensate by backing out of theorifice 31, thus reducing the pressure drop. It should also be noted that the amount of preload provided by thecompensation spring 22 needs to be moderated so as not to be excessive. Excessive preload on theneedle 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 theneedle 27 against thespring 22. Thus, a higher preload onspring 22 also reduces sensitivity. Those skilled in the art can use known techniques for adjusting the variables of preload and needle profile within anorifice 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 themodulation ram needle 27 inorifice 31 is achieved. - 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. Thebottomhole assembly 500 includes a thruster 501 (a force application device) that applies force to alower section 502 of thebottomhole assembly 500. Thelower section 502 includes amud motor 503 that contains alobed rotor 503 a that rotates inside a lobedelastomeric stator 503 b when drilling fluid 580 passes through progressive cavities 503 c formed between therotor 503 a andstator 503 b. Therotor 503 a is coupled to thedrill bit 540 via adrill shaft 504 that passes through a bearingassembly 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. Abent sub 554 between themud motor 503 and the bearingassembly 505 allows theBHA 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 bearingassembly 505 to provide lateral stability to thebottomhole assembly 500 near thedrill bit 540 and to provide a certain degree of steering of thedrill bit 540. Additional stabilizers, such asstabilizer 546, may be provided above themud motor 503 to provide lateral stability to thebottomhole assembly 500 during drilling. Anadjustable bend 552 may also be provided to drill shorter radius boreholes. - One or
more sensors 512 are included in thedrill bit 540 to provide measurements for certain drill bit parameters, including pressure at the drill bit bottom and wear of thedrill bit 540. Amodule 514 containing a plurality ofsensors 514 a provides measurements of various BHA physical or dynamics parameters. Themodule 514 is preferably provided near thedrill 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 thebottomhole assembly 500. For example, a group of BHAdynamic parameter sensors 545 may be located above themud motor 503 to provide measurements for the desired BHA dynamic parameters. Sensors 514 b disposed in the bearingassembly 505 measure the radial and axial displacement of thedrill shaft 504 and other desired physical bearing assembly parameters (e.g. leakage, oil level for sealed bearings, etc.). - A set of temperature sensors520 a-520 c, respectively measure temperatures T1-T3 of the elastomeric stator along its length while
pressure sensors 522 a below themud motor mud motor 503 provide differential pressure across themud motor 503. Adifferential pressure sensor 522 c instead may be used to determine the differential pressure across themud motor 503.Sensors 530 provide measurement for the rotational speed (rpm) of themud motor 503.Additional sensors 531 in themud motor 503 provide pressure of thedrilling fluid 580 in themud motor 503 and the annulus pressure. - The
thruster 501 has aforce application member 504 which strokes or reciprocates in anouter housing 536 between a retracted position and an extended position. When themember 504 extends, it moves toward thedrill bit 540, thereby moving thelower section 502 of thebottomhole assembly 500. Thedrill string 32 above thethruster 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 theforce application member 504 to exert force on thedrill bit 540. Athruster power unit 560 causes themember 504 to move downhole to exert the desired force on thedrill bit 540. Thepower unit 560 may be an electric motor, a hydraulic power unit, a pneumatic power unit or a combination thereof. Thepower unit 560 is adapted to cause thestroke member 504 to move in both the downhole and uphole directions as shown by thedouble arrow 504 a. A position sensor or adisplacement sensor 550 measures the displacement of thestroke member 504, which provides the rate of penetration (“ROP”) of thedrill bit 540. An electrical control circuit orunit 562 in the BHA controls the operation of thethruster power unit 560 as more fully described below in reference to FIG. 8. - Appropriate fluid paths (not shown) through the
thruster assembly 501 are provided to allow thedrilling fluid 580 to flow downhole to themud motor 503. Commonly utilized measurement-while-drilling (“MWD”) or logging-while-drilling (“LWD”)sensors 570 are provided at suitable location(s) in thebottomhole 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 themud motor 503. Accelerometers, magnetometers and gyroscopic devices are utilized as position/direction sensors. A two-way telemetry 572 enables thebottomhole assembly 500 to communicate with the surface unit (not shown). - 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 thecontrol 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 thecontrol unit 562. For simplicity, only oneelectrical 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. - 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. Thedrilling fluid 580 is pumped through thedrill string 32 from the surface. The flow rate and the pressure at the surface may also be communicated to thecontrol 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 thethruster 501 is also provided to thecontrol unit 562. - 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 thedrill bit 540 as a function of one or more parameters of interest that will provide enhanced drilling and extended life of thebottomhole assembly 500. Thecontrol unit 562 then causes thepower unit 560 to adjust the applied force accordingly. Thus, thethruster 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 thebottomhole assembly 500. For example, higher penetration rate may wear out thedrill bit 500 rapidly or cause damage to themud motor 503. Such drilling rates, though higher, would require tripping out thedrill 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. Thethruster 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. - FIG. 6 shows an embodiment of a
thruster 601 that utilizes a hydraulic power unit controlled by anelectrical control unit 660 for use with abottomhole assembly 600. Thethruster 601 includes a stroke member or reciprocating force member 610 (also referred to herein as a “force application member”) that reciprocates in ahousing 636. Thelower end 612 of thestroke member 610 is coupled to thelower section 615 of thebottomhole assembly 600, while the upper end terminates in apiston 614. Thepiston 614 reciprocates in upper and lowerfluid chambers Seals 622 provide seals between thestroke member 610 andfluid chambers upper end 630 of thethruster 601 is connected to theuphole section 670 of thedrill string 32. Drilling fluid 680 passes downhole to the mud motor (FIG. 5) via a throughpassageway 602 in thestroke member 610. Ahydraulic power unit 640 provides power to the reciprocatingmember 610. Thepower unit 640 supplies fluid, such as oil, under pressure from a source thereof 646 to theupper chamber 616 via aline 642 and aport 644. Afluid control valve 645 in theline 642 may be modulated to modulate the fluid supply to theupper chamber 616. Fluid from thesource 646 may also be provided to the lower chamber vialine 647 andport 649. Suitable fluid return paths (not shown) from thechambers source 646 are provided to bleed off the pressure. Thepower unit 640 may also be designed to maintain desired differential pressure between the twochambers -
Pressure sensor 648 andvolumetric sensor 650 respectively provide pressure P1, in and volume V1 of theupper chamber 616. Similar sensors may be used for thelower chamber 618. Adisplacement sensor 652 measures the displacement of thestroke member 610 from an initial or retracted position, which allows the operator or system to determine when to retract thestroke member 610 to repeat the cycle. It also provides a relatively precise measure of the rate of penetration. Acontrol unit 660, similar to thecontrol unit 560 described above (FIG. 5A), utilizes the pressure sensor, volumetric sensor and displacement sensor measurements and controls the operation of thehydraulics power unit 640 to maintain the desired force on the drill bit 540 (FIG. 5). The pressure P1, in theupper chamber 616 controls the force (weight on bit) on thedrill bit 540 while the fluid volume V1 in theupper chamber 616 controls the axial displacement (“D”) of thethruster 601. Thecontrol unit 640 controls thethruster 601 as a function of selected parameters of interest, as more fully described below in reference to FIG. 8. - FIG. 7 shows a schematic diagram of an alternative embodiment of a
thruster 701 of abottomhole assembly 700 which utilizesdrilling fluid 780 to exert the desired force on the drill bit 540 (FIG. 5). Thethruster 701 includes astroke member 710 that reciprocates or strokes in an outer housing 702. Thelower end 712 of thestroke member 710 is coupled to thelower portion 715 of thebottomhole assembly 700. Drill bit is attached to the bottomhole end of thelower section 715. The upper end 714 of thestroke member 710 has a valve opening orseat 718 that allows thedrilling fluid 780 to pass through thethruster 701. Thedrilling fluid 780 flows through thestroke member 710 via an opening 716. The flow of the fluid through the opening 716 is controlled by avalve assembly 720 that includes a conical member orspear 722 which can open and close the opening 716. The pressure of thedrilling fluid 780 is applied to theupper end 714A of thestroke member 710 at the flange 714 a. Theopening 724 between thespear 722 and theseat 718 defines the fluid flow path through thestroke member 710. Closing thevalve 718 will exert the maximum force on thestroke member 710. Bypass fluid flow paths through thethruster 701 tosection 715 of the bottomhole assembly (not shown) may be provided to ensure uninterrupted fluid flow to the drill bit. Completely opening of thevalve 718 will equalize the pressure on both sides of theopening 718. Thespear 722 may be operated by asuitable device 726 such as a stepper motor or a solenoid-controlled valve. - Still referring to FIG. 7, an
electrical control unit 730 controls the operation of thespear 722. To maintain a desired force on the drill bit, thecontrol 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 thethruster 701 remains constant at P1 over time T even when the mud motor differential pressure Pm changes. Suitable sensors measure pressure P3 applied to thebottomhole assembly section 715 and the pressure P4 above thethruster 701. Theelectrical control unit 730 includes a processor and other desired circuit to control the action of thevalve member 722 to maintain P3 at the desired valve during drilling of the wellbore. The length of thecylinder 730 between the flange 714 and the housing 702 defines the length of the stroke or travel for thethruster 701. - FIG. 8 is a functional block diagram of an
electrical control unit 800 for use in the present invention. Thecontrol unit 800 includes one ormore micro-processors 810, associatedmemory units 811 and other electrical circuits (not shown). Theprocessor 810 receives signals from the various downhole sensors in the bottomhole assembly described above. The sensor data includes signals fordrill bit parameters 814, bottomhole assemblydynamic parameters 816,drilling parameters 818, formation evaluation (“FE”)parameters 820,directional parameters 822 and otherdownhole parameters 824. Data and signals (surface parameters) may also be communicated to theprocessor 810 from asurface 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. Theprocessor 810 preferably is provided with one ormodels 812 that utilize data from the sensors and the surface suppliedparameters 840 to determine the force to be applied by thethruster power unit 850. - The
processor 810 then controls thepower unit 850 to apply the required power on thethruster stroke member 860. The actual values of thethruster parameters 862, such as the magnitude of the force and the thruster displacement are fed back to theprocessor 810. Theprocessor 810 continues to cause thethruster power unit 850 to adjust the applied force so as to maintain selected parameters within their desired limits. Theprocessor 810 may also be programmed to cause the thruster to apply constant force on the bit. In one aspect of the invention, themodels 812 provide the ranges or values of the selected parameters, such as the weight on bit, differential pressure across the mud motor, vibration, etc. Theprocessor 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, theprocessor 810 may be programmed to transmit signals to the surface to provide warning to the drilling operator or to utilize alternative models. Theprocessor 810 is preferably programmed to upgrade themodels 812 as the drilling conditions and the formation being penetrated change, making themodels 812 dynamic. - 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.
Claims (20)
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 , 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.
claim 1
3. The BHA of further comprising a sensor for determining the magnitude of the force actually applied by the force application device on the drill bit.
claim 2
4. The BHA of , 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.
claim 3
5. The BHA of , 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.
claim 1
6. The BHA of , wherein the processor determines the parameter of interest downhole during drilling of the wellbore.
claim 1
7. The BHA of 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.
claim 1
8. The BHA of , 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.
claim 1
9. The BHA of , wherein the force application device is one of a hydraulically-operated device, mechanically-operated device and an electro-mechanical device.
claim 1
10. The BHA of , 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.
claim 1
11. The BHA of , 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.
claim 1
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 , 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.
claim 12
14. The force application device of , 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.
claim 13
15. The force application device of , 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.
claim 13
16. The force application device of , 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.
claim 12
17. The force application device of further comprising a valve for controlling the flow of the fluid through the stroke member, thereby controlling the pressure on the force application member.
claim 16
18. The force application device of , wherein the control unit modulates the valve to control the force exerted by the stroke member on the drill bit.
claim 17
19. The force application device of , wherein the valve is operated by a device selected from a group consisting of (i) a stepper motor, and (ii) a solenoid.
claim 18
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.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
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US09/271,947 US20010045300A1 (en) | 1998-03-20 | 1999-03-18 | Thruster responsive to drilling parameters |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US7873398P | 1998-03-20 | 1998-03-20 | |
US09/271,947 US20010045300A1 (en) | 1998-03-20 | 1999-03-18 | Thruster responsive to drilling parameters |
Publications (1)
Publication Number | Publication Date |
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US20010045300A1 true US20010045300A1 (en) | 2001-11-29 |
Family
ID=22145899
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
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US09/271,947 Abandoned US20010045300A1 (en) | 1998-03-20 | 1999-03-18 | Thruster responsive to drilling parameters |
Country Status (3)
Country | Link |
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US (1) | US20010045300A1 (en) |
CA (1) | CA2266198A1 (en) |
GB (1) | GB2335450B (en) |
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Also Published As
Publication number | Publication date |
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GB2335450A (en) | 1999-09-22 |
GB2335450B (en) | 2000-11-22 |
CA2266198A1 (en) | 1999-09-20 |
GB9906462D0 (en) | 1999-05-12 |
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