• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    Systems and methods for locating while drilling. Some embodiments of the method include drilling a borehole with a downhole assembly (BHA) attached to a drill bit, interrupting the drill to determine a drill bit reading position, obtaining measurements with BHA sensors during drilling, processing of BHA sensor measurements with a model being drilled to track a current bit position relative to the survey position, the model accounting for a deformation of the BHA, and the orientation of the BHA according to the current position of the trephine.
    公开号:FR3031132A1
    申请号:FR1561472
    申请日:2015-11-27
    公开日:2016-07-01
    发明作者:Jason D Dykstra；Yuzhen Xue；Fanping Bu
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    [0001] DRILLING CONTINUOUS LOCATION Background Directional drilling is the process of directing a borehole along a defined path. The deflection control during drilling is the process of keeping the borehole trajectory contained within specified limits, for example, limits on the tilt angle or the distance to the defined path. These last two have become important for hydrocarbon resource developers. Each Bottom-Hole Assembly (BHA) drilling a deflected borehole rests on the bottom side of the borehole, thereby experiencing a reaction force that causes the BHA to pull upward (increasing inclination of the borehole due to a fulcrum effect), tending downward (decreasing the borehole inclination due to a pendulum effect), or tending to neutral (maintaining inclination) . Even for the same BHA, directional trends may change due to formation effects, bit wear, tilt angle, and parameters that affect stiffness such as rotational speed, vibration, the weight on the bit (WOB for "weight-on-bit") and water leaks. The parameters that can be used to intentionally influence the directional trend include the number, the disposition, and the gauge of stabilizers, the angles of bending associated with the steering mechanism, the distance of the elbows by 3031132 compared to the bit, the speed of rotation, the WOB, and the speed of penetration (ROP for "Rate-Of-Penetration"). Various drill pipe orientation mechanisms exist to provide directional drilling: whipstock, crankcase mud motors, jet bits, adjustable gauge stabilizers, and rotary steer systems (RSS for Rotary Steering System). These techniques each employ the lateral force, tilt angle, or one of their combinations to orient the rotary and forward movement of the drill string. However, the actual curvature of the resulting borehole is not determined by these parameters alone, and it is often difficult to predict the location of the bit during drilling. Such difficulty requires slow drilling, frequent survey measurements, and in many cases, frequent movement of the drill string to the surface to adjust the directional tendency of the steering assembly. Such necessity produces undesirably undulating and tortuous boreholes and the many problems associated with them. Brief Description of the Drawings Accordingly, certain drilling location systems and methods are disclosed herein that provide continuous tracking while accounting for deformations of the downhole assembly. In the following detailed description of the various embodiments disclosed, reference will be made to the accompanying drawings in which: FIG. 1 is a schematic view of an illustrative location environment during drilling; Figure 2 is a block diagram of an illustrative location system being drilled; Fig. 3 is a schematic side view of an illustrative bit thrust orientation mechanism; Fig. 4 is a schematic side view of an illustrative pointing mechanism of the bit; Figure 5 is a perspective view of an illustrative downhole assembly (BHA) for use in a location environment while drilling; and Figure 6 is a flow diagram of an illustrative method of locating while drilling. It should be understood, however, that the specific embodiments given in the drawings and in the detailed description do not limit the disclosure. Rather, they lay the foundation for the skilled person to recognize variations of shapes, equivalents, and modifications that are encompassed together with one or more of the embodiments within the scope of the appended claims. Notation and Nomenclature Certain terms are used throughout the specification and subsequent claims to refer to particular system components and configurations. As will be appreciated by those skilled in the art, companies may designate a component by different names. This document does not intend to distinguish between components whose names differ but not the function. In the following discussion and in the claims, the terms "including", "comprising" and "including" are used in an open manner, and therefore must be interpreted as meaning "including, but not limited to". Similarly, the term "couple" or "couple" is meant to mean an indirect or direct electrical connection. Thus, if a first device couples to a second device, this connection can be via a direct electrical connection, or through an indirect electrical connection via other devices and connections. In addition, the term "fixed" is meant to mean an indirect or direct physical connection. Thus, if a first device is attached to a second device, this connection can be via a direct physical connection, or through an indirect physical connection via other devices and connections.
    [0002] Detailed Description The problems identified in the context are at least partially solved by location-based systems and methods while drilling. To provide a background, an illustrative location environment while drilling is shown in Fig. 1. A drilling platform 102 supports a drilling rig 104 having a movable muffle 106 for raising and lowering a drill string 108. A drive the top 110 supports and rotates the drill string 108 as it is lowered into a borehole 112. The rotary drill bit 108 and / or a downhole motor assembly 114 rotates a drill bit. When drilling bit 116 rotates, it extends probe hole 112 in a directed manner through various subterranean formations. The downhole assembly 114 includes an RSS 118 which, in conjunction with one or more outriggers 120, allows the drilling personnel 3031132 to orient the borehole in a desired path. A pump 122 circulates a drilling fluid through a feed pipe to the top drive, downhole through the interior of the drill string 108, through orifices in the drill bit. drilling 116, returning to the surface via the annular space around the drill string 108, and into a retention pit 124. The drilling fluid carries drill cuttings from the borehole into the retention pit 124 and helps maintain the integrity of the borehole. The drill bit 116 and the downhole motor assembly 114 form just a portion of the downhole assembly (BHA) which includes one or more rod weights (i.e. thick-walled steel) to provide weight and rigidity to assist the drilling process. Some of these drill collars have on-board logging tools for assembling measurements of various drilling parameters such as position, orientation, WOB, torque, vibration, borehole diameter, temperature and downhole pressure, etc. The tool orientation can be specified in terms of tool face angle (rotation orientation), inclination angle (slope), and compass direction, each of which can be derived from measurements. by magnetometers, inclinometers, and / or accelerometers, although other types of sensors such as gyroscopes may alternatively be used.
    [0003] In a specific embodiment, the tool comprises a 3-axis fluxgate magnetometer and a 3-axis accelerometer. The combination of these two sensor systems allows the measurement of the tool face angle, the tilt angle and the compass direction. One or more Logging While Drilling (LWD) tools may also be integrated into the BHA to measure parameters of formations that are drilled. When the drill bit 116 extends into the borehole 112 through the subterranean formations, the LWD tools rotate and collect measurements of these parameters such as resistivity, density, porosity, velocity of propagation of the acoustic wave, the radioactivity the attenuation of neutrons or gamma rays, the magnetic resonance decay rates, and in fact any physical parameter for which a measurement tool exists. A downhole control device associates the measurements with time and with a position and a tool orientation to establish a time and space dependence of the measurements. The measurements may be stored in an internal memory and / or communicated to the surface. An intermediate telemetry channel may be included in the downhole assembly to maintain a communication link with the surface. Sludge pulse telemetry is a common telemetry technique for transferring tool measurements to a surface interface 126 and for receiving commands from the surface interface, but other telemetry techniques can also be used. used. Typical telemetry data rates may range from less than one bit per minute to several bits per second, usually well below the bandwidth required to communicate all of the raw measurement data to the surface.
    [0004] The surface interface 126 is further coupled to various sensors on and around the drilling platform to obtain measurements of drilling parameters from the surface equipment, parameters such as a hook load, A penetration velocity, a torque, and revolutions per minute (RPM) of the drill string A processing unit, shown in FIG. 1 in the form of a digital tablet 128, communicates with the surface interface 126. via a wired or wireless network communication link 130, and provides a Graphical User Interface (GUI) or other form of interactive interface that allows a user to give and receive orders ( and optionally interacting with) a visual representation of the acquired measurements. The measurements may be in logarithmic form, for example, a graph of the borehole trajectory and / or parameters measured as a function of time and / or position along the borehole. The processing unit may adopt variant forms, including a desktop computer, a laptop, an integrated processor, a cloud computer, a central processing center accessible via the Internet, and combinations of which above. In addition to uphole and downhole drilling parameters and measured training parameters, the surface interface 126 or processing unit 128 may further be programmed with additional parameters relating to the process of drilling, which can be manually entered or retrieved from a configuration file. These additional parameters may include, for example, the specifications for the drill string and BHA, including tubular materials and drill collars, the diameters and positions of the stabilizer, and limits on lateral forces and severity of the dog's paw. The additional information may further include a desired borehole trajectory and deviation limits with respect to that trajectory. Experiments and logs from remote wells may also be included as part of the additional information. Figure 2 is a functional block diagram of an illustrative location system being drilled. One or more downhole tool controllers 202 collect measurements from a downhole sensor assembly 204, preferably but not necessarily including both drilling parameter sensors and transducer sensors. Training parameter, to be digitized and stored, with optional downhole processing to compress the data, improve the signal-to-noise ratio, and / or derive parameters of interest from the measurements. A telemetry system 208 routes at least a portion of the measurements or derived parameters to a surface treatment system 210, the upside-down system 210 collecting, recording and processing telemetry information from the downhole and also from a set of sensors 212 on and around the rig. The processing system 210 generates a display on an interactive interface 214 of relevant information, for example, the measurement logs, the borehole trajectory or extracted values such as directional trend and drill parameters recommended to achieve the desired orientation. The processing system 210 may further accept the inputs and the user commands and operate in response to these inputs to for example transmit commands and configuration information via the telemetry system 208 to the downhole processor 206. These commands can modify the settings of the orientation mechanism. FIG. 3 shows an illustrative RSS and a bit thrust type drill bit assembly 114, which employs a non-rotating sleeve with a thrust pad 118 which can press against a selected side of the borehole, serving as a mechanism eccentricity which introduces an adjustable eccentricity, thus undergoing a lateral force FS2. The bit 116 and the stabilizer 120 undergo lateral reaction forces FS1 and FS3. The balance of forces on the BHA introduces a certain degree of lateral cut by the bit and a certain degree of bit inclination, which combine to give a full running angle to the BHA. The total running angle is regulated by the thrust buffer 118 which allows the borehole to be oriented along a desired path. FIG. 4 shows an illustrative RSS and a bit-type downhole set of the bit, which employ a non-rotating housing that introduces an adjustable bend in the drill string, resulting in a bit tilt angle to be regulated. An eccentricity ring within the housing serves as an eccentric mechanism to provide the adjustable elbow. Attached to the housing is a stabilizer and a non-rotating pivot pad. In addition to an internal lateral force FS4 exerted by the housing on the drill string shaft, the drill bit, pivot pad, crankcase ends and stabilizer each undergo respective lateral forces FS1, FS2, FS3, FS5. , and FS6. The balance of these forces further influences the tilt angle of the bit and introduces a degree of lateral cut, which together provide a full BHA angle of travel. - The total operating angle is regulated by the eccentricity ring 10 to allow orientation of the borehole in a desired path. Fig. 5 shows the construction of an illustrative BHA model 502 for use in a location system during drilling 500. BHA 502, which includes bit 504, can be divided into a number of sections at locations such as BHA deformation of a bit 504 illustrated location, the BHA 502 is modeling purposes in the way that facilitates the drilling while. As divided into three rigid sections, ma, m2 and m3, of different lengths, but BHA 502 can be divided into a different number of sections of the same or different lengths in different embodiments. A steep change in the position of other spring constant force section of the BHA 502 indicates a suitable for a section break, although splitting schemes are possible. Each preferably includes a measuring tool 506, sometimes referred to as DrillDOC®, and optionally includes Drill string dynamics detection tools (DDSR) 508 positioned between two force measuring tools 506. When the deformation of BHA will be at least partially modeled as a localized bend between sections, one of the section breaks is preferably positioned at the geopilot 510 or other orientation mechanism. The position of the drill bit 504 during drilling can be calculated using a dead reckoning algorithm which accounts for the movement and deformation of the BHA 502. The esteem is the process of calculating the current position. bit by noting the previously determined and correct position of the bit, or reference point, and advancing this position according to one or more parameters collected during drilling. During drilling interruptions, which are usually spaced thirty feet apart due to new pipe sections added over the drill string, surveys can be conducted to obtain an updated landmark. In some cases, if double or triple sections are used, the surveys can be performed at intervals of sixty or ninety feet, respectively. These surveys, which provide the reference point, can not be made during drilling due to the movement and vibrations caused by the strong forces required to rotate the bit 504. However, the sensor measurements for the algorithm This can be collected during drilling, i.e., while the drill bit is rotating and engaged with the formation. These sensor measurements can be used to continuously locate drill bit 504 while drilling.
    [0005] The force measurement tools 506 include force measurement sensors for measuring the torsional, tensile, bending and compressive forces of the sections of the BHA 502 in which they are positioned.
    [0006] 3031132 12 The closest force measuring tool 506 to the bit can indirectly measure the WOB and Torque-On-Bit (TOB). The DDSRs 508 measure the acceleration and gravitational field along the BHA 502. The BHA 502 can also include gyro sensors for measuring angular rotation speed, rotary sensors for measuring the dot direction angle, and angle of bending in the BHA 502, magnetometric sensors for measuring the magnetic field, and pressure sensors for measuring the depth. Additional sensors in the geopilot 510 can measure the RPM of the bit 504. Each ml, m2, m3 section of the BHA 502 is modeled as a rigid body having six degrees of freedom from its adjacent sections. The xiyizi coordinates represent the fifth section of the BHA with an origin, oi, located at the beginning (hole up) of the section and xiyizi axes, aligned with the section. For example, the section m3 starts at the origin, 03, of the local coordinate system of x3, y3, z3. Thanks to the deformation measurements measured by the force measuring tool 506, the transformation of coordinates between the (i + 1) th and th local coordinates can be determined. In this way, the position of the bit 504 can be calculated from the coordinate transformation of the ml section of the BHA 502, where ml is the section of the BHA 502 closest to the bit 504. For example, a dynamic modeling of the BHA 502 can be written as follows: X (x, ux, Eq. (I, 2, 3) 1.7 MY, uy, wy) fz (z, uz where Ni, N represents the total number of sections in the BHA 502, w represents the noise, and u represents a combination of the input force from the drill string to the BHA 502, the bending force of the geopilot 510, and the reaction force of the rock at the Y and Z are defined similarly to X. The 3-axis accelerations of each section are measured by the corresponding DDSRs, and the 3-axis forces between two adjacent sections x. + 1, z [+ 11 are measured This dynamic modeling describes the relationship between the position of the sections. s and the effort measurements A linear approximation can be written as follows: AxX + Bxux + wx E = AyY ByTly Wy 3, 4, 5) - Az X + Bzuz wz 20 where the additional terms A and B are matrices with elements including the mass, spring constants and damping coefficients of each section of BHA 502.
    [0007] 3031132 14 Kinematic equation modeling of BHA 502 can be written as f (x, u) Eck. (6, 7) yh (xu) where k = [E1, Nb, h1, Al, ob, 1) h * t Jb, Lt`J is an internal state vector, Eb, Nb and Hb represent the position bit, 4,1Y1), and 14 represent the bit speed, Ob, 0, and * b represent bit attitudes (Euler angles), and w represents the gyroscopic and accelerometer sensor biasing vector and the bit speed derived from accelerometers and gyroscopes. The measurement output can be provided by the survey, and the system input u represents the measurements from the gyroscopes and accelerometers. The bit position can be calculated continuously during drilling since the model is updated with the sensor measurements. An iterative comparison between the calculated bit position and the intermittent survey measurements can be made as required, and a new survey can be initiated if an error, or deviation from the predicted bit position, is detected. above a threshold. The new survey can be triggered immediately or during the next scheduled interruption of drilling. The esteem algorithm can be implemented in a self-esteem model that models the BHA, drill bit, borehole, and training as desired. Likewise, as described above, the esteem model can be trained to account for noise and other uncertainties in the drilling process. In a training stage, a number of surveys are performed during drill interruptions and sensor measurements are collected during drilling. These data are used collectively as training data. Specifically, the dead reckoning algorithm is performed on the drive data, and the difference between calculated bit positions and known bit positions, or error, is returned to the model for tuning purposes. . In this way, a noise model and another uncertainty can be modeled. Fig. 6 is a flow diagram illustrating a location method during drilling. At 602, a borehole is drilled with a bottom hole assembly (BHA) terminating in a drill bit. BHA sensors can include force sensors and drill string dynamics sensors (DDSR). The force sensors measure the twisting, tensioning, bending and compressing forces of a section of the BHA. DDSRs measure acceleration and gravitational field along the BHA. The BHA may also include gyroscopic sensors such as Evader for measuring angular rotation speed, rotary sensors for measuring the stitch direction angle and angle of bending in the BHA, magnetometer sensors for measuring the field of view. magnetic and pressure sensors to measure the depth. At 604, drilling is interrupted to determine a reading position of the bit. During drilling interruptions, which are usually spaced thirty feet apart due to new pipe sections added over the drill string, surveys can be performed. These surveys can provide the position of the bit 3031132 as a benchmark in a dead reckoning algorithm. Surveys can not be performed during drilling due to interference caused by the strong forces required to rotate the bit. In 606, drilling is resumed and measurements are obtained with BHA sensors being drilled. At this point, a dead model can be trained using the BHA sensor measurements and one or more surveys as training data. Specifically, the dead reckoning algorithm is performed on the drive data, and the difference between calculated bit positions and known bit positions, or error, is returned to the model for development purposes. . In addition, a noise model can be created to account for noise received during sensor measurements. In 608, the BHA sensor measurements are processed with a recoil model while drilling to track a current bit position relative to the survey position. By modeling all of the BHA as a deformable body, accurate positioning data can be calculated. Specifically, the model estimates that it accounts for BHA deformation by modeling the BHA as a plurality of sections, each starting at a local origin and terminating at a point within a system. local coordinates. A plurality of coordinate transformations may be made, using kinematic or dynamic BHA modeling, to establish the overall coordinates, or position, of the bit. The model fully characterizes the kinematics of BHA while accounting for deformation, and the model can also determine a bit velocity vector being drilled. In at least one embodiment, the processing of the measurements may include filtering the measurements using a Kalman filtering system to provide a statistically optimal position and / or attitude determination. At 610, if a deflection greater than a threshold, which may be adjustable, is detected between the current bit position and the desired bit path, a new survey may be triggered at 604. For example, drilling may be interrupted, and a new survey can be done. In an alternative embodiment, a new survey may be performed during the next scheduled interruption of drilling. At 612, if a deviation has not been detected, the BHA is oriented according to the current position of the bit. Such an orientation can occur automatically, that is, without human input. A continuous location method during drilling includes drilling a borehole with a downhole assembly (BHA) terminating in a drill bit; interrupting the drilling to determine a bit reading position; obtaining measurements using BHA sensors while drilling; processing the BHA sensor measurements with a dead-recoil model for tracking a current bit position relative to the survey position, the esteem model accounting for BHA deformation; and orienting the BHA according to the current position of the bit. The method may include driving the esteem model to utilize the BHA sensor measurements to estimate current bit positions. Model 3031132 18 can model the BHA as a plurality of rigid bodies and computes a set of local coordinates for each of the plurality of rigid bodies. The model can determine a bit velocity vector being drilled. The method may include determining a tool arrangement that allows the BHA sensors to fully characterize the kinematics of the BHA while accounting for BHA deformation. BHA sensors may include force sensors, accelerometers and gyrometers. The method may include detecting a deviation, while drilling, between the current bit position and a desired bit position; and triggering, according to the deflection, a survey to be performed during the next drilling interruption. A location-drilling system includes a bottom hole assembly (BHA) terminating in a drill bit, including BHA sensors; and a processing unit which collects in-process measurement measurements (MWD) from the BHA sensors and uses the measurements in a dead reckoning model to track a current bit position with respect to a survey position, the esteem model accounting for a deformation of BHA.
    [0008] The processing unit may cause the current position to be displayed. The treatment unit can be downhole. The BHA may include an orientation mechanism that compares the current position to a desired position. The processing unit may cause the template to use the MWD measurements to estimate current bit positions. The model can model the BHA as a plurality of rigid bodies and calculate a set of local coordinates for each of the plurality of rigid bodies. The model can determine a bit velocity vector during drilling. The BHA can be assembled with a tool arrangement that allows the BHA sensors to fully characterize the kinematics of the BHA while accounting for BHA deformation. BHA sensors can include force sensors, accelerometers and gyrometers. The processing unit can detect a deviation, while drilling, between the current bit position and a desired bit position, and trigger, according to the deflection, a survey to be performed during the next drilling interruption. Although the present disclosure has been described with respect to a limited number of embodiments, one skilled in the art will appreciate that many modifications and variations are possible therefrom. The appended claims are intended to cover such modifications and variations.
    权利要求:
    Claims (11)
    [0001]
    REVENDICATIONS1. A method of continuously locating during drilling which comprises: drilling a borehole with a downhole assembly (BHA) attached to a drill bit; determining a bit reading position; obtaining measurements with the BHA sensors 10 as the drill bit rotates; processing the BHA sensor measurements with a model being drilled to track a current bit position relative to the survey position, the model accounting for a deformation of the BHA. 15
    [0002]
    The method of claim 1, further comprising driving the model to use the BHA sensor measurements to estimate current bit positions.
    [0003]
    The method of claim 1, wherein the model models the BHA as a plurality of rigid bodies and calculates a set of local coordinates for each of the plurality of rigid bodies.
    [0004]
    The method of claim 1, wherein the pattern determines a bit status vector during drilling. 30
    [0005]
    The method of claim 1, further comprising determining a tool arrangement that allows the BHA sensors to fully characterize the kinetics of the BHA while accounting for BHA deformation.
    [0006]
    The method of claim 1, wherein the BHA sensors include force sensors, accelerometers, magnetometers, and gyroscopes.
    [0007]
    The method of claim 1, further comprising detecting a deflection, while drilling, between the current bit position and a desired bit position; and triggering, according to the deviation, a survey to be performed during the next drilling interruption.
    [0008]
    8. A location tracking system that includes a BHA, attached to a drill bit, comprising BHA sensors; and a processing unit that collects Measurements while drilling (MWD) measurements from the BHA sensors and uses the measurements in a model to track a current bit position with respect to a position of the model accounting for BHA deformation.
    [0009]
    9. System according to claim 8, wherein the processing unit causes the display of the current position.
    [0010]
    10. System according to claim 8, wherein the processing unit is downhole. 3031132 22
    [0011]
    The system of claim 8, wherein the BHA includes an orientation mechanism that compares the current position to a desired position. The system of claim 8, wherein the processing unit causes the model to use the MWD measurements to estimate current bit positions. The system of claim 8, wherein the model models the BHA as a plurality of rigid bodies and calculates a set of local coordinates for each of the plurality of rigid bodies. The system of claim 8, wherein the model determines a bit velocity vector during drilling. The system of claim 8, wherein the BHA is assembled with a tool arrangement that allows the BHA sensors to fully characterize the kinematics of the BHA while accounting for BHA deformation. The system of claim 8, wherein the BHA sensors include force sensors, accelerometers, magnetometers, and gyroscopes. 17. The system of claim 8, wherein the processing unit detects a deflection, while drilling, between the current bit position and a desired bit position, and triggers, according to the deflection, a identified during the next drilling interruption. 18. A method of continuously locating during drilling which comprises: obtaining measurements with BHA sensors as a drill bit rotates; processing the BHA sensor measurements with a model being drilled to track a current position of the bit relative to a survey position, the model accounting for a deformation of the BHA; and the automatic orientation of the BHA based on the current bit position. 19. The method of claim 18, further comprising driving the model to use the BHA sensor measurements to estimate the current bit positions. 20. The method of claim 18, wherein the model models the BHA as a plurality of rigid bodies and calculates a set of local coordinates for each of the plurality of rigid bodies.
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    EP3721055A4|2017-12-04|2021-09-22|HRL Laboratories, LLC|Continuous trajectory calculation for directional drilling|
    RU2738227C2|2019-06-20|2020-12-09|Общество с ограниченной ответственностью "Интегра-Технологии"|Method of directed drilling with correction of well trajectory|
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    优先权:
    申请号 | 申请日 | 专利标题
    PCT/US2014/073025|WO2016108901A1|2014-12-31|2014-12-31|Continuous locating while drilling|
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