US20090138242A1 - Minimizing stick-slip while drilling - Google Patents

Minimizing stick-slip while drilling Download PDF

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Publication number
US20090138242A1
US20090138242A1 US11/945,589 US94558907A US2009138242A1 US 20090138242 A1 US20090138242 A1 US 20090138242A1 US 94558907 A US94558907 A US 94558907A US 2009138242 A1 US2009138242 A1 US 2009138242A1
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United States
Prior art keywords
cutters
drill bit
rotary drill
medium
drilling
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Abandoned
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US11/945,589
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English (en)
Inventor
Jahir A. Pabon
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Schlumberger Technology Corp
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Schlumberger Technology Corp
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Publication date
Application filed by Schlumberger Technology Corp filed Critical Schlumberger Technology Corp
Priority to US11/945,589 priority Critical patent/US20090138242A1/en
Assigned to SCHLUMBERGER TECHNOLOGY CORPORATION reassignment SCHLUMBERGER TECHNOLOGY CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: PABON, JAHIR A.
Priority to PCT/US2008/077692 priority patent/WO2009070372A2/fr
Priority to CA2677785A priority patent/CA2677785C/fr
Priority to EP08853872.3A priority patent/EP2212508B1/fr
Publication of US20090138242A1 publication Critical patent/US20090138242A1/en
Priority to US14/063,926 priority patent/US9353577B2/en
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00—Drill bits
    • E21B10/42—Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits
    • E21B10/43—Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00—Drill bits
    • E21B10/46—Drill bits characterised by wear resisting parts, e.g. diamond inserts
    • E21B10/54—Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits
    • G—PHYSICS
    • G06—COMPUTING; CALCULATING OR COUNTING
    • G06F—ELECTRIC DIGITAL DATA PROCESSING
    • G06F30/00—Computer-aided design [CAD]

Definitions

  • This invention relates generally to drilling. More specifically, the invention relates to cutter placement on a drill bit to minimize stick-slip occurrences.
  • Drill bits particularly Polycrystalline Diamond Composite (PDC) drill bits commonly used for drilling earthen formations, typically exhibit blades of cutters that are nearly uniformly distributed around the bit axis of rotation. The cutters on the face of such drill bits will therefore evenly share the cutting load of the medium into which they are applied. In theory, by equally distributing the cutting load onto all cutters, the life of the drill bit should be maximized, with all bits wearing evenly until the end of their useful life.
  • PDC Polycrystalline Diamond Composite
  • such a symmetric drill bit may experience sticking and slipping of the drill bit in the medium when the drill bit either “bites” too much or to little of the medium to cause further boring into the medium.
  • each of the symmetrically cutters is engaging too much medium without enough torque to cause the medium to either be sheared or otherwise removed from the cavity.
  • the path of least resistance for the drill bits may be to skip over the medium rather than remove material from the cavity.
  • Rippling caused by each symmetric cutter on the face of the bore hole may also result in each cutter arriving at the same time at the location of a ripple left by the previous cutter on the drill bit. This may happen repeatedly as the drill bit rotates against the face of the bore hole, causing both stick and slip conditions. Both stick and slip occurrences will cause torsional vibrations in the drillstring connecting the drill bit to drill's rotational power source.
  • axial vibrations may occur from the drill bit being forced into a medium it is not actually cutting (sticking) or retreating from the medium, albeit slightly, when it is slipping. These torsional and axial vibrations can reduce the life of the drill bit and associated drilling equipment such as the rotational power source.
  • a rotary drill bit for drilling a cavity in a medium.
  • the rotary drill bit may include a bit body and a plurality of cutters coupled with a drilling face of the bit body.
  • the bit body may include a distal end having the drilling face, and a proximal end having a rotational power source coupling mechanism.
  • the plurality of cutters is coupled with the drilling face of the bit body and includes a plurality of groups of cutters. Each group of cutters is substantially aligned along a different radius of the drilling face. The azimuthal distribution of said groups of cutters is non-symmetric around the axis of the drilling face.
  • the plurality of cutter may include at least six groups of cutters and the radius along which the second group of cutters may be substantially aligned may be substantially a first angle (A) in pitch from the radius along which the first group of cutters may be substantially aligned.
  • the radius along which the third group of cutters may be substantially aligned may be substantially the first angle (A) minus a second angle ( ⁇ ), (A ⁇ ), in pitch from the radius along which the second group of cutters may be substantially aligned.
  • the radius along which the fourth group of cutters may be substantially aligned may be substantially the first angle (A) plus the second angle ( ⁇ ), (A+ ⁇ ), in pitch from the radius along which the second group of cutters may be substantially aligned.
  • the radius along which the fifth group of cutters may be substantially aligned may be substantially the first angle (A) in pitch from the radius along which the fourth group of cutters may be substantially aligned.
  • the radius along which the sixth group of cutters may be substantially aligned may be substantially the first angle (A) minus two times the second angle ( ⁇ ), (A ⁇ 2 ⁇ ), degrees in pitch from the radius along which the fifth group of cutters may be substantially aligned.
  • the second angle ⁇ may be substantially greater than zero degrees.
  • the plurality of cutter may include at least eight groups of cutters and the radius along which the second group of cutters may be substantially aligned may be substantially a first angle (A) in pitch from the radius along which the first group of cutters may be substantially aligned.
  • the radius along which the third group of cutters may be substantially aligned may be substantially the first angle (A) minus a second angle ( ⁇ ), (A ⁇ ), in pitch from the radius along which the second group of cutters may be substantially aligned.
  • the radius along which the fourth group of cutters may be substantially aligned may be substantially the first angle (A) in pitch from the radius along which the third group of cutters may be substantially aligned.
  • the radius along which the fifth group of cutters may be substantially aligned may be substantially the first angle (A) plus the second angle ( ⁇ ), (A+ ⁇ ), in pitch from the radius along which the fourth group of cutters may be substantially aligned.
  • the radius along which the sixth group of cutters may be substantially aligned in may be substantially the first angle (A) in pitch from the radius along which the fifth group of cutters may be substantially aligned.
  • the radius along which the seventh group of cutters may be substantially aligned may be substantially the first angle (A) minus two times the second angle ( ⁇ ), (A ⁇ 2 ⁇ ), degrees in pitch from the radius along which the sixth group of cutters may be substantially aligned.
  • the radius along which the eighth group of cutters may be substantially aligned may be the first angle (A) in pitch from the radius along which the seventh group of cutters may be substantially aligned.
  • the second angle ⁇ may be substantially greater than zero degree.
  • a method for designing a rotary drill bit for drilling a cavity in a medium may include determining a characteristic of a drillstring with which the rotary drill bit is coupled. The method may also include determining an initial number of groups of cutters for the rotary drill bit, where each group of cutters includes a plurality of cutters substantially aligned along a different radius of the drilling face. The method may moreover include determining a characteristic of the medium relative to a characteristic of the cutters. The method may additionally include determining a characteristic of a rotational motion source used to rotate the rotary drill bit. The method may further include determining the angles of pitch between each of the groups of cutters to minimize an amount of sticking or slipping of the rotary drill bit in the medium during a drilling operation.
  • FIG. 1A is a side view of the cutters of a symmetrical circular drill bit, shown linearly with respect to the curvature of the drill bit for explanatory purposes only, as the drill bit cuts through a medium;
  • FIG. 1B is a side view the same drill bit shown in FIG. 2A , except incrementally later in the drilling process, after a ripple has been caused in the drilling process;
  • FIG. 1C is a side view the same drill bit shown in FIG. 2B , except incrementally later in the drilling process, after the ripple is first being encountered by the cutters during rotation;
  • FIG. 1D is a side view the same drill bit shown in FIG. 2C , except incrementally later in the drilling process, after another ripple is created;
  • FIG. 2A is a representation of a drill face with six groups of cutters non-symmetrically aligned
  • FIG. 2B is a representation of a drill face with eight groups of cutters non-symmetrically aligned
  • FIG. 3 is a graphical representation of a typical drilling system for the purposes of simulation
  • FIG. 4 is a typical representation of angular velocity versus torque for a rotational motion source
  • FIG. 5 is a typical representation of force versus depth of cut for the interaction between a rotary drill bit and a drilling medium
  • FIG. 6 is a typical representation of torque versus depth of cut for the interaction between a rotary drill bit and a drilling medium
  • FIG. 7 is a graphical representation of the differential form of a mathematical depth of cut expression
  • FIG. 8 is a typical representation of rate of progress and rotations per minute versus weight on bit for “hard” rock
  • FIG. 9 is set of graphs showing time transient results of a simulation of a symmetrical six cutter drill bit
  • FIG. 10 is a representation of the roots of the system simulated in FIG. 9 ;
  • FIG. 11 is a representation of the roots of the system simulated in FIG. 9 when delay terms are introduced into the simulation
  • FIG. 12 is a closer view of the bit RPM versus time graph shown in FIG. 9 ;
  • FIG. 13 is a representation of the roots of the system simulated in FIG. 9 except having a symmetrical eight cutter drill bit;
  • FIG. 14 is set of graphs showing time transient results of a simulation of the symmetrical six cutter drill bit of FIG. 13 ;
  • FIG. 15A is a representation of the roots of the system with difficult drilling conditions using a symmetrical six cutter drill bit
  • FIG. 15B is a representation of the roots of the system with difficult drilling conditions of FIG. 15A using a symmetrical thirty-four cutter drill bit;
  • FIG. 17 is a set of graphs showing time transient results of a simulation of the asymmetrical six cutter drill bit of FIG. 16C .
  • a process may correspond to a method, a function, a procedure, a subroutine, a subprogram, etc. When a process corresponds to a function, its termination corresponds to a return of the function to the calling function or the main function.
  • embodiments of the invention may be implemented, at least in part, either manually or automatically.
  • Manual or automatic implementations may be executed, or at least assisted, through the use of machines, hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof.
  • the program code or code segments to perform the necessary tasks may be stored in a machine readable medium.
  • a processor(s) may perform the necessary tasks.
  • a rotary drill bit for drilling a cavity in a medium.
  • the medium may be any material, and in some embodiments may be an earthen formation.
  • the rotary drill bit may include a bit body and a plurality of cutters coupled with a drilling face of the bit body.
  • the bit body may include a distal end having the drilling face, and a proximal end having a rotational power source coupling mechanism.
  • the plurality of cutters may be coupled with the drilling face of the bit body, and may include a plurality of groups of cutters. Each group of cutters may be substantially aligned along a different radius of the drilling face. The different groups of cutters may be non-symmetrically aligned on the drilling face.
  • the phrases “groups of cutters,” “cutting blades,” and/or “blades of cutters” may be used interchangeably, and may refer to groups of cutters substantially aligned along a different radius of the drilling face.
  • FIGS. 1A-1D show an example of a drill bit 125 with symmetrically aligned cutters 140 cutting through a medium.
  • cutters 140 on a circular drill bit 125 are shown linearly with respect to the curvature of drill bit 125 for explanatory purposes only.
  • directional arrow 130 shows the direction of spin of the cutters 140 .
  • Directional arrow 150 shows the direction of axial penetration into the medium 160 .
  • Dashed lines 170 show the anticipated path of cutters 140 through medium 160 if the rate of drill bit rotation and rate of penetration remain constant.
  • FIG. 1B is a side view of drill bit 125 shown in FIG. 1A , except incrementally later in the drilling process, after a ripple 175 has been caused in the drilling process. Ripple may have been cause by drill bit 125 pressing too hard into the medium, and temporarily slowing down rotationally, thereby causing each cutter 140 to leave a ripple 175 in its path.
  • FIG. 1C is a side view of drill bit 125 shown in FIG. 1B , except incrementally later in the drilling process, after ripple 175 is first being encountered by the evenly spaced cutters 140 during rotation. As is shown, all of cutters 140 have encountered the ripple 175 at the same time. This results in a transient decrease in the amount of medium to be cut, speeding up drill bit 125 temporarily.
  • FIG. 1D is a side view of drill bit 125 shown in FIG. 1C , except incrementally later in the drilling process, after another ripple 180 is created.
  • the transient speed of drill bit 125 as it encountered the previous ripple 175 has caused a new ripple 180 to be created.
  • This process of ripple creation may thus repeat as each set of ripples is again each encountered by an evenly spaced cutter 140 .
  • the size of successive ripples may, under some circumstances grow and cause a stick slip condition.
  • each cutter may arrive at different times at the location of a ripple left by the previous cutter on the drill bit.
  • the tendency of an unsymmetrical drill bit to speed up or slow down may be reduced since only one cutter at a time may encounter a ripple, rather than all cutters on a symmetric bit encountering all ripples at the same time, over and over again as the drill bit rotates through the medium.
  • FIG. 2A a representation of a drill face 100 with groups of cutters 110 non-symmetrically aligned is shown.
  • six groups of cutters are represented, referenced respectively 110 A to 110 F.
  • the first group of cutters 110 A may lie on a particular radius.
  • the radius along which the second group of cutters 110 B may be substantially aligned may be substantially a first angle A in pitch from the radius along which the first group of cutters may be substantially aligned 110 A.
  • the first angle A may be 60 degrees.
  • the radius along which the third group of cutters 110 C may be substantially aligned may be substantially the first angle (A) minus a second angle ⁇ , (A ⁇ ), or (60 ⁇ ) degrees in pitch from the radius along which the second group of cutters 110 B may be substantially aligned.
  • the radius along which the fourth group of cutters 110 D may be substantially aligned may be substantially angle of (A+ ⁇ ) or (60+ ⁇ ) degrees in pitch from the radius along which the second group of cutters 110 C may be substantially aligned.
  • the radius along which the fifth group of cutters 110 E may be substantially aligned may be substantially first angle A in pitch from the radius along which the fourth group of cutters 110 D may be substantially aligned.
  • the radius along which the sixth group of cutters 110 F may be substantially aligned may be substantially angle of (A ⁇ 2 ⁇ ) or (60 ⁇ 2 ⁇ ) degrees in pitch from the radius along which the fifth group of cutters 110 E may be substantially aligned.
  • FIG. 2B a representation of another drill face 201 with non-symmetrically aligned cutters 210 is shown.
  • eight groups of cutters are represented, referenced respectively 210 A to 210 H.
  • the first group of cutters 210 A may like on a particular radius.
  • the first angle A may be 45 degrees.
  • the radius along which the second group of cutters 210 B may be substantially aligned may be substantially 45 degrees in pitch from the radius along which the first group of cutters may be substantially aligned 210 A.
  • the radius along which the third group of cutters 210 C may be substantially aligned may be substantially (45 ⁇ ) degrees in pitch from the radius along which the second group of cutters 210 B may be substantially aligned.
  • the radius along which the fourth group of cutters 210 D may be substantially aligned may be substantially the angle A, 45 degrees, in pitch from the radius along which the third group of cutters 210 C may be substantially aligned.
  • the radius along which the fifth group of cutters 210 E may be substantially aligned may be substantially (45+ ⁇ ) degrees in pitch from the radius along which the fourth group of cutters 210 D may be substantially aligned.
  • the radius along which the sixth group of cutters 210 F may be substantially aligned in may be substantially 45 degrees in pitch from the radius along which the fifth group of cutters 210 E may be substantially aligned.
  • the radius along which the seventh group of cutters 210 G may be substantially aligned may be substantially (45 ⁇ 2 ⁇ ) degrees in pitch from the radius along which the sixth group of cutters 210 E may be substantially aligned.
  • the radius along which the eighth group of cutters 210 H may be substantially aligned may be the angle A or 45 degrees in pitch from the radius along which the seventh group of cutters 210 G may be substantially aligned.
  • ⁇ may be substantially greater than zero.
  • the second angle ⁇ may be five degrees, ten degrees, fifteen degrees, or twenty degrees.
  • the second angle ⁇ may, merely by way of example, be five degrees, ten degrees, or fifteen degrees.
  • the second angle ⁇ may be determined in an iterative manner based at least in part on any one or more of the following: the characteristics of a bottom hole assembly (“BHA”) coupled with the bit body, the characteristics of a lengthwise element coupling the BHA with a rotational motion source, the characteristics of the interaction between the rotary drill bit and the medium, and the characteristics of the rotational motion source.
  • FIG. 3 shows a graphical representation of such a drilling system 300 .
  • System 300 may include a rotational motion source 310 , a lengthwise element 320 coupling motion source 310 to a bottom hole assembly (“BHA”) 330 , and a drill bit head 340 coupled therewith.
  • BHA bottom hole assembly
  • drill bit head 340 coupled therewith.
  • a cavity in medium 350 is being excavated by system 300 .
  • lengthwise element 320 is shown as multiple segments of drill pipe, though in other embodiments, drill tube or other connective elements could also be used.
  • the second angle ⁇ may be selected and/or determined to maximize a rate of progress (“ROP”) of the rotary drill bit in the medium. In these or other embodiments, the second angle ⁇ may also be selected to minimize a sticking and/or a slipping of the rotary drill bit in the medium during a drilling operation.
  • ROP rate of progress
  • Mathematical constructs are discussed below which are capable of determining whether a given configuration of exemplary system 300 is stable, and therefore subject to a lessened number of stick-slip occurrences during drilling operations. These constructs may be employed in methods of the invention for designing a rotary bit for drilling cavities in mediums. These methods may determine pertinent drilling system characteristics and then apply of the principles discussed below to both select the number of cutters on the designed rotary drill, and the pitch angles between the cutters.
  • characteristics of rotational motion source 310 may include:
  • T Top ⁇ ⁇ force
  • FIG. 4 A typical representation of torque versus angular velocity is shown in FIG. 4 .
  • additional control hardware and software may be included at the surface, and may be aimed at reducing the stick/slip tendencies of the drilling tool, for instance by regulating the applied torque.
  • that control may act only after the stick/slip condition downhole is severe enough to reach the surface.
  • Such an additional control may work either independent or in tandem with the systems and methods discussed herein.
  • characteristics of lengthwise element 320 may include:
  • characteristics of BHA 330 may include:
  • characteristics of the interaction between the rotary drill bit 340 and the medium 350 may include:
  • DoC Depth of Cut
  • mm/rev millimeters per revolution
  • the linear position of lengthwise element 320 may be described as z 1 .
  • the linear velocity of lengthwise element 320 may be described as v 1 .
  • the angular position of lengthwise element 320 may be described as ⁇ 1 .
  • the angular velocity of lengthwise element 320 may be described as ⁇ 1 . Note that these descriptions assume one continuous lengthwise element 320 . Multiple lengthwise elements in series may be described by multiple state variables, each having a progressively higher subscript.
  • the equations of motion for system 300 may be,
  • ⁇ may be a time delay which represents the time it takes to turn the rotary drill bit by an angle (2 ⁇ )/n b , where n b may be equal to the number of cutting blades on the rotary drill bit.
  • FIG. 8 plots the steady state values of axial drilling speed (ROP given in ft/hr) and angular rotation speed (in RPM), as a function of the applied top force.
  • ROP axial drilling speed
  • RPM angular rotation speed
  • FIG. 8 plots the steady state values of axial drilling speed (ROP given in ft/hr) and angular rotation speed (in RPM), as a function of the applied top force.
  • ROP axial drilling speed
  • RPM angular rotation speed
  • Laplace Transform approach may be employed as follows.
  • the stability of system 300 may be determined by the roots of,
  • FIG. 10 shows the location of the roots of the above system, when the time delay term in the expression giving the DoC is ignored.
  • the system is shown as stable because all roots have a negative real part.
  • FIG. 11 shows that additional roots are added to the system, a pair of them in particular having a positive real part, indicating system instability.
  • FIG. 12 shows that the frequency of the bit RPM similarly matches the frequency of the additional roots in FIG. 11 .
  • the number of cutting blades may be increased. Increasing the number of cutting blades from six to eight yields the results shown in FIG. 13 . As can be seen in FIG. 13 , all roots now have a negative real part, and the system has been stabilized. The results of a time transient simulation of the new drill bit is shown in FIG. 14 .
  • FIGS. 16A-16C show the results of the above equations in altering ⁇ .
  • ⁇ 0 degrees
  • there remains one pair of roots with a positive real part only the positive side of the complex plane is presented in the figure as the negative side is the mirror image of that positive side
  • the drill bit is unstable.
  • FIG. 17 shows a time transient simulation of such a drill bit, demonstrating that stick-slip instability has been at least greatly reduced.
  • a method for designing a rotary drill bit for drilling a cavity in a medium may include determining a characteristic of a drillstring with which the rotary drill bit is coupled. The method may also include determining an initial number of cutting blades for the rotary drill bit, where each cutting blade includes a plurality of cutters substantially aligned along a different radius of the drilling face. The method may moreover include determining a characteristic of the medium relative to a characteristic of the cutters. The method may additionally include determining a characteristic of a rotational motion source used to rotate the rotary drill bit.
  • the method may further include determining the angles of pitch between each of the cutting blades to minimize an amount of sticking or slipping of the rotary drill bit in the medium during a drilling operation.
  • the calculations and simulations described above may be utilized to make any one or more of the above determinations.

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Application Number Priority Date Filing Date Title
US11/945,589 US20090138242A1 (en) 2007-11-27 2007-11-27 Minimizing stick-slip while drilling
PCT/US2008/077692 WO2009070372A2 (fr) 2007-11-27 2008-09-25 Minimisation du broutage durant le perçage
CA2677785A CA2677785C (fr) 2007-11-27 2008-09-25 Minimisation du broutage durant le percage
EP08853872.3A EP2212508B1 (fr) 2007-11-27 2008-09-25 Minimisation du broutage durant le perçage
US14/063,926 US9353577B2 (en) 2007-11-27 2013-10-25 Minimizing stick-slip while drilling

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US20110147083A1 (en) * 2009-12-22 2011-06-23 Precision Energy Services, Inc. Analyzing Toolface Velocity to Detect Detrimental Vibration During Drilling
US9353577B2 (en) 2007-11-27 2016-05-31 Schlumberger Technology Corporation Minimizing stick-slip while drilling
US9567844B2 (en) 2013-10-10 2017-02-14 Weatherford Technology Holdings, Llc Analysis of drillstring dynamics using angular and linear motion data from multiple accelerometer pairs
US10480304B2 (en) 2011-10-14 2019-11-19 Weatherford Technology Holdings, Llc Analysis of drillstring dynamics using an angular rate sensor

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US9353577B2 (en) 2016-05-31
EP2212508B1 (fr) 2013-08-28
US20140048337A1 (en) 2014-02-20
CA2677785A1 (fr) 2009-06-04
CA2677785C (fr) 2014-04-15
EP2212508A2 (fr) 2010-08-04
WO2009070372A3 (fr) 2009-11-26

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