DETAILED ACTION
1. Claims 1-2, 4-17, and 19-20 have been presented for examination.
Claims 3 and 18 have been cancelled.
Notice of Pre-AIA or AIA Status
2. The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
PRIORITY
3. Acknowledgment is made that this application is a continuation of 16/619,381 filed 12/04/2019 now issued patent PAT 11454106. 16/619,381 is a 371 of PCT/US2018/031176 filed 05/04/2018. PCT/US2018/031176 has claimed priority to provisional application 62/520,287 filed. 06/15/2017
Response to Arguments
4. Applicant's arguments filed 12/15/25 have been fully considered but they are not persuasive.
i) Following Applicants amendments the claim objections have been WITHDRAWN.
ii) Following Applicants amendments the previously presented 101 rejections have been WITHDRAWN.
iii) Following Applicants amendments an additional art has been provided in the 103 rejection below.
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
The factual inquiries set forth in Graham v. John Deere Co., 383 U.S. 1, 148 USPQ 459 (1966), that are applied for establishing a background for determining obviousness under 35 U.S.C. 103(a) are summarized as follows:
1. Determining the scope and contents of the prior art.
2. Ascertaining the differences between the prior art and the claims at issue.
3. Resolving the level of ordinary skill in the pertinent art.
4. Considering objective evidence present in the application indicating obviousness or nonobviousness.
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
5. Claims 1-2, 4-6, 8-10, 12-17, and 20 are rejected under 35 U.S.C. 103 as being unpatentable over Chen et al. U.S. Patent Publication No. 20140309978, hereafter Chen in view of Chau et al. U.S. Patent No. 6438495, hereafter Chau.
Regarding Claim 1: The reference discloses A computer-implemented method of drilling a wellbore, the method comprising:
generating, by the computer system during drilling of the wellbore, a representation of a first portion of a wellbore path, wherein the representation of the first portion of the wellbore path is responsive to the first set of parameters and one or more of: (Chen. “[0094] Representative results that are produced by the simulation include accelerations at the bit, reamer, stabs and other locations; velocities at the bit, reamer, stabs and other locations; displacements at the bit, reamer, stabs, and other locations; the trajectory of the bit, reamer, stabs, and other locations; torque of the bit, reamer, stabs, and other locations; and contact force of the bit, reamer, stabs, and other locations. Any or all of these results may be produced in the form of a time history, box and whisker plots, 2D or 3D animations and pictures.”)
bottom hole assembly (BHA) data; (Chen. “[0095] Specifically, with respect to steerability, the well path trajectory, the well bore diameter, the inclination angle, the azimuthal angle, the tool face angle, the build up rate, and the drill string length/bend may be analyzed. With respect to the robustness, the stress along the BHA, the internal force along the BHA (such as bending moment, torque, and axial force) may be reviewed. With respect to measurement quality, as noted above, the sensor location acceleration, velocity, displacement, and center trajectory may be analyzed.”)
operating parameters data; or (Chen. “[0095] Specifically, with respect to steerability, the well path trajectory, the well bore diameter, the inclination angle, the azimuthal angle, the tool face angle, the build up rate, and the drill string length/bend may be analyzed. With respect to the robustness, the stress along the BHA, the internal force along the BHA (such as bending moment, torque, and axial force) may be reviewed. With respect to measurement quality, as noted above, the sensor location acceleration, velocity, displacement, and center trajectory may be analyzed.”)
rock formation data; (Chen. “[0077] Well bore parameters may include the geometry of a well bore and formation material properties. The trajectory of a well bore in which the drilling tool assembly is to be confined also is defined along with an initial well bore bottom surface geometry. Because the well bore trajectory may include either straight, curved, or a combination of straight and curved sections, well bore trajectories, in general, may be defined by parameters for each segment of the trajectory. For example, a well bore may be defined as comprising N segments characterized by the length, diameter, inclination angle, and azimuth direction of each segment and an indication of the order of the segments (i.e., first, second, etc.). Well bore parameters defined in this manner may then be used to mathematically produce a model of the entire well bore trajectory. Formation material properties at various depths along the well bore may also be defined and used. One of ordinary skill in the art will appreciate that well bore parameters may include additional properties, such as friction of the walls of the well bore and well bore fluid properties.”)
generating, by the computer system, during drilling of the wellbore responsive to data received from a survey corresponding to the first portion of the wellbore path for the first set of parameters, a second set of parameters; and (Chen. “[0128] FIGS. 8A-8C, therefore, can provide useful comparison for BHA packages on the measurement quality. By decreasing the sag, or reducing the dynamic bending angle variation, more precise measurements can be made when either performing a static survey (i.e., when no movement of the BHA is occurring), or a real-time survey (i.e., when the drill string is moving).”)
generating, by the computer system, a representation of a second portion of the wellbore path responsive to the second set of parameters. (Chen. “[0094] Representative results that are produced by the simulation include accelerations at the bit, reamer, stabs and other locations; velocities at the bit, reamer, stabs and other locations; displacements at the bit, reamer, stabs, and other locations; the trajectory of the bit, reamer, stabs, and other locations; torque of the bit, reamer, stabs, and other locations; and contact force of the bit, reamer, stabs, and other locations. Any or all of these results may be produced in the form of a time history, box and whisker plots, 2D or 3D animations and pictures.” “[0220] In selected embodiments, the present disclosure allows a BHA designer to investigate the performance of multiple BHA's having a dynamic input. A dynamic input is an input that varies during the course of a simulation. For example, the RPM may be varied with the bit either drilling or not drilling, to determine a critical speed to be avoided during drilling. Similarly, the weight on bit may be varied over the course of the simulation from 0 to a selected value, or between two higher values. Similarly, the rate of penetration of the BHA may be entered as a dynamic input, and allowed to change over the course of the simulation. By having a dynamic input, selected embodiments of the present disclosure may allow a BHA designer to suggest operating parameters to be avoided, or to be used by a driller when actually drilling a well.”)
generating a reconstructed trajectory of the wellbore path based on a calculated build up rate (BUR) (Chen. “[0095] Specifically, with respect to steerability, the well path trajectory, the well bore diameter, the inclination angle, the azimuthal angle, the tool face angle, the build up rate, and the drill string length/bend may be analyzed. With respect to the robustness, the stress along the BHA, the internal force along the BHA (such as bending moment, torque, and axial force) may be reviewed. With respect to measurement quality, as noted above, the sensor location acceleration, velocity, displacement, and center trajectory may be analyzed.”) and calculated turn rate (TR) (“[0095] Specifically, with respect to steerability, the well path trajectory, the well bore diameter, the inclination angle, the azimuthal angle, the tool face angle, the build up rate, and the drill string length/bend may be analyzed. With respect to the robustness, the stress along the BHA, the internal force along the BHA (such as bending moment, torque, and axial force) may be reviewed. With respect to measurement quality, as noted above, the sensor location acceleration, velocity, displacement, and center trajectory may be analyzed.”) of a drill string coupled to the drilling rig and the first set of parameters;
receiving actual BUR and actual TR corresponding to the first portion of the wellbore path; (Chen. “[0015] The method used to obtain the measurements needed to calculate and plot a 3D well path is called a directional survey. Three parameters are measured at multiple locations along the well path--MD, inclination, and hole direction. MD is the actual depth of the hole drilled to any point along the wellbore or to total depth, as measured from the surface location. Inclination is the angle, measured in degrees, by which the wellbore or survey-instrument axis varies from a true vertical line. An inclination of 0.degree. would be true vertical, and an inclination of 90.degree. would be horizontal.” “[0128] FIGS. 8A-8C, therefore, can provide useful comparison for BHA packages on the measurement quality. By decreasing the sag, or reducing the dynamic bending angle variation, more precise measurements can be made when either performing a static survey (i.e., when no movement of the BHA is occurring), or a real-time survey (i.e., when the drill string is moving).”)
generating a reconstructed actual trajectory of the first portion of the wellbore path based on an actual BUR and actual TR of the drill string; (Chen. “[0015] The method used to obtain the measurements needed to calculate and plot a 3D well path is called a directional survey. Three parameters are measured at multiple locations along the well path--MD, inclination, and hole direction. MD is the actual depth of the hole drilled to any point along the wellbore or to total depth, as measured from the surface location. Inclination is the angle, measured in degrees, by which the wellbore or survey-instrument axis varies from a true vertical line. An inclination of 0.degree. would be true vertical, and an inclination of 90.degree. would be horizontal.” “[0128] FIGS. 8A-8C, therefore, can provide useful comparison for BHA packages on the measurement quality. By decreasing the sag, or reducing the dynamic bending angle variation, more precise measurements can be made when either performing a static survey (i.e., when no movement of the BHA is occurring), or a real-time survey (i.e., when the drill string is moving).”)
Chen does not explicitly recite receiving, by a computer system coupled to a drilling rig drilling a wellbore, a first set of parameters for drilling and at least two of the following: bottom hole assembly data, operating parameters data, and rock formation data;
altering, during drilling of the wellbore, one or more drilling parameters based on the reconstructed actual trajectory; and
drilling the second portion of the wellbore with the one or more altered drilling parameters.
However Chau recites receiving, by a computer system coupled to a drilling rig drilling a wellbore, a first set of parameters for drilling and at least two of the following: bottom hole assembly data, operating parameters data, and rock formation data; (Chau. Column 8, Lines 42-51, “(9) The next step in the invention is to create a numerical drill string model 22 in order to predict the direction and inclination of the wellbore being drilled. Once fed with the static data of the bottom hole assembly (BHA) and the wellbore geometry, and with the real-time data, tool description and initial drilling parameters, the numerical model will calibrate the formation stiffness, hole enlargement and bit anisotropy index, based on continuous measurements of inclination and azimuth in the previously drilled wellbore sections.”)
receiving actual BUR and actual TR corresponding to the first portion of the wellbore path; (Chau. Column 6, Lines 47-61, “(33) The present invention uses the availability of real-time and continuous direction and inclination (D&I) measurements of the drilling assembly from the MWD or rotary steerable systems. These D&I measurements, coupled with drilling mechanics measurements, and the overall history of the well trajectory enable the parameters in the numerical models to be calibrated in real-time, and thus give more accurate predictions of both the bit location and the tendency of the wellbore beyond the current bit location. The continuous data will be used in conjunction with the accepted survey measurements (which occur less frequently than the continuous inclination and direction measurements) so that the optimum slide and rotation ratio between well sections can be selected, and drilling targets can be more accurately reached.)
altering, during drilling of the wellbore, one or more drilling parameters based on the reconstructed actual trajectory; and (Chau. Column 7, Lines 37-54, “(2) The present invention describes a technique that uses the continuous inclination, direction and tool face information supplied from either an MWD tool and/or a rotary steerable drilling system, and/or other downhole equipment, e.g., the at-bit inclination measurement (AIM), to give a prediction of the tendency of a wellbore being drilled by a rotary, steerable, or rotary steerable system. These continuous inclination and direction and tool face information measurements are used with a finite element mathematical model of the drilling process to continually calibrate the drilling parameters (HE, FS and BAI) not obtainable from measurements, and to refine the tendency prediction of the wellbore in real-time. The continuous data is used in conjunction with the accepted survey measurements (which occur less frequently than the continuous inclination and direction measurements) so that the optimum slide and rotation ratio between continuous well sections can be selected, and drilling targets can be more accurately reached.”)
drilling the second portion of the wellbore with the one or more altered drilling parameters. (Chau. Figure 5)
It would have been obvious to one of ordinary skill in the art before the effective filing date of the invention to utilize the actual parameters to alter drilling parameters as per Chau with the simulation aspect of Chen since it allows for Chen in [220] “By having a dynamic input, selected embodiments of the present disclosure may allow a BHA designer to suggest operating parameters to be avoided, or to be used by a driller when actually drilling a well” as well as Chau, Column 1, Lines 6-11, “for predicting the direction and inclination of a drilling assembly during the process of drilling a wellbore in an earth formation and in particular to a method for predicting the direction and inclination tendencies of a drilling assembly in real-time using continuous data.”
Regarding Claim 2: The reference discloses The computer-implemented method of claim 1, wherein the first set of parameters comprises one or more of: quantifying bit steerability; (Chen. [0234] “In other embodiments, performance criteria may be selected and/or generated by the executed simulation. Performance criteria may include one or more of stability, robustness, measurement quality, and steerability of the BHA package for example. Those of ordinary skill would appreciate that other performance criteria may be selected and/or generated.”) walk; a coefficient of friction; (“[0120] There is a frictional force generated due to the contact. The magnitude of the force is the normal force multiplied by the friction coefficient. The direction of the frictional force is opposite to the speed of the node relative to wellbore. By increasing friction, more drag force from the wellbore will result on the drill string. This may cause more vibrations, increased torque to the surface, etc. Sometimes in the field, the wellbore may have local doglegs, or ledges. Those imperfections will generate more drag to the drillstring. The higher friction coefficient can be used to simulate those conditions.”) or overgauge borehole information.
Regarding Claim 4: The reference discloses The computer-implemented method of claim 1, wherein: generating the reconstructed trajectory of the wellbore path further comprises calculating the calculated BUR and calculated TR based on the first set of parameters; and generating the reconstructed actual trajectory of the wellbore path further comprises: receiving actual BUR and actual TR corresponding to the first portion of the wellbore path; calibrating the first set of parameters based on the actual BUR and the actual TR to generate the second set of parameters; and modifying a predicted trajectory based on the second set of parameters to generate the actual trajectory. (Chen. “[0097] Turning to FIG. 5, an overview of the simulation capabilities is shown. Specifically, in FIG. 5, a number of uses of the simulation is shown at 502. Various objectives, including stability, steerability, durability, and measurement quality are shown at 504. A number of modeling factors are shown at 506. In one embodiment, the simulation may be used 502, to select or design one or more cutting tools, such as reamers, or drill bits. The simulation may also be used to optimize a BHA design. The simulation can be used to provide a "map" of drilling parameters (i.e., to produce predicted drilling behavior for a given BHA under a range of parameters). The simulation may also be used to troubleshoot problems that have developed in the field (i.e., to perform an "autopsy" of drilling performance, to predict what caused a drill bit, or a component of the BHA to fail). The simulation may also be used to plan a well (i.e., to suggest to a drilling operator how to drill a well, what components to include in the BHA, to suggest one or more suitable drill bits, and how to target a production zone).”)
Regarding Claim 5: The reference discloses The computer-implemented method of claim 1, wherein generating the reconstructed actual trajectory of the wellbore path further comprises: calculating a sag correction; and applying the sag correction to the representation of the wellbore path; and generating a calibrated wellbore path in response to applying the sag correction. (Chen. “[0093] For example, the directional sensors in MWD measures inclination and azimuth angle of the well. The directional sensor does not measure the angle of the well directly. Instead, the directional sensor measures the angle of the MWD collar. When the collar sags due to gravity, or bends due to dynamics, the angle of the collar can vary. The measurement of the well by measuring the collar will introduce more errors if sag/bend is more severe. As another example, LWD tools measuring formation density can be affected by the gap between the sensor and the wellbore. If the gaps keep changing, it can effect the density measurements. Thus, in one or more embodiments, one or more BHA's may be simulated according to one or more drilling scenarios to analyze sag of the MWD or other measurement tools and/or to consider changes in the distance between the MWED or other measurement tool and the wellbore wall.”)
Regarding Claim 6: The reference discloses The computer-implemented method of claim 1, wherein generating the representation of the second portion of the wellbore path further comprises: receiving actual build up rate (BUR) and actual turn rate (TR) corresponding to the first portion of the wellbore path; calibrating the first set of parameters based on the actual BUR and the actual TR to generate the second set of parameters; and generating the representation of the second portion of the wellbore path based on the second set of parameters. (Chen. “[0220] In selected embodiments, the present disclosure allows a BHA designer to investigate the performance of multiple BHA's having a dynamic input. A dynamic input is an input that varies during the course of a simulation. For example, the RPM may be varied with the bit either drilling or not drilling, to determine a critical speed to be avoided during drilling. Similarly, the weight on bit may be varied over the course of the simulation from 0 to a selected value, or between two higher values. Similarly, the rate of penetration of the BHA may be entered as a dynamic input, and allowed to change over the course of the simulation. By having a dynamic input, selected embodiments of the present disclosure may allow a BHA designer to suggest operating parameters to be avoided, or to be used by a driller when actually drilling a well.”)
Regarding Claim 8: The reference discloses A drilling system comprising: a computer system comprising a processor; and a memory coupled to the processor, the memory storing a program that, when executed by the processor, causes the processor to: receive, by the computer system coupled to a drilling rig drilling a wellbore, a first set of parameters for drilling and at least two of the following: bottom hole assembly data, operating parameters data, and rock formation data; generate during drilling of the wellbore a representation of a first portion of a wellbore path, wherein the representation of the first portion of the wellbore path is responsive to the first set of parameters and one or more of: bottom hole assembly (BHA) data received from the BHA; operating parameters data; or rock formation data; generate, during drilling of the wellbore, responsive to data received from a survey corresponding to the first portion of the wellbore path for the first set of parameters, a second set of parameters; and generate, during drilling of the wellbore, responsive to the second set of parameters, a representation of a second portion of the wellbore paths generate a reconstructed trajectory of the wellbore path based on a calculated buildup rate (BUR) and calculated turn rate (TR) of a drill string coupled to the drilling rig and the first set of parameters; receive actual BUR and actual TR corresponding to the first portion of the wellbore path; calibrate the first set of parameters based on the actual BUR and the actual TR to generate the second set of parameters; modify a predicted trajectory based on the second set of parameters to generate an actual trajectory; alter, during drilling of the wellbore, one or more drilling parameters based on the predicted trajectory; and drill the second portion of the wellbore with the one or more altered drilling parameters. (See rejection for claim 1)
Regarding Claim 9: The reference discloses The drilling system of claim 8, wherein the first set of parameters comprises one or more of: quantifying bit steerability; walk; a coefficient of friction; or overgauge borehole information. (See rejection for claim 2)
Regarding Claim 10: The reference discloses The drilling system of claim 8, wherein the program for generating the representation of the second portion of the wellbore path further causes the processor to: modify, based on data received from the survey, the first set of parameters to generate the second set of parameters; and generating the actual trajectory of the wellbore path in the first portion of the wellbore path by applying the second set of parameters. (Chen. “[0094] Representative results that are produced by the simulation include accelerations at the bit, reamer, stabs and other locations; velocities at the bit, reamer, stabs and other locations; displacements at the bit, reamer, stabs, and other locations; the trajectory of the bit, reamer, stabs, and other locations; torque of the bit, reamer, stabs, and other locations; and contact force of the bit, reamer, stabs, and other locations. Any or all of these results may be produced in the form of a time history, box and whisker plots, 2D or 3D animations and pictures.” “[0220] In selected embodiments, the present disclosure allows a BHA designer to investigate the performance of multiple BHA's having a dynamic input. A dynamic input is an input that varies during the course of a simulation. For example, the RPM may be varied with the bit either drilling or not drilling, to determine a critical speed to be avoided during drilling. Similarly, the weight on bit may be varied over the course of the simulation from 0 to a selected value, or between two higher values. Similarly, the rate of penetration of the BHA may be entered as a dynamic input, and allowed to change over the course of the simulation. By having a dynamic input, selected embodiments of the present disclosure may allow a BHA designer to suggest operating parameters to be avoided, or to be used by a driller when actually drilling a well.”)
Regarding Claim 12: The reference discloses The drilling system of claim 11 further comprising: a display device coupled to the computer system; and wherein the program further causes the processor to render for display on the display device, the actual trajectory of the first portion of the wellbore path and the second portion of the wellbore path. (Chen. “[0083] The outputs may include tabular data of one or more performance parameters. Additionally, the outputs may be in the form of graphs of a performance parameter, with respect to time, or with respect to location along the BHA, for example. When the outputs are given based on location along the BHA the outputs may be presented as an average value for each location as well as other percentages, such as 5%, 10%, 25%, 75%, 90%, and 95%. Other plots may include presentation of the results at a minimum or maximum value, or any combination of those results. A graphical visualization of the drill bit, drill string, and/or the drilling tools (e.g., a hole opener) may also be output. The graphical visualization (e.g., 2-D, 3-D, or 4-D) may include a color scheme for the drill string and BHA to indicate performance parameters at locations along the length of the drill string and bottom hole assembly.”)
Regarding Claim 13: The reference discloses The drilling system of claim 8, wherein the program for generating the representation of the second portion of the wellbore path further causes the processor to: calibrate the first set of parameters based on an actual build up rate (BUR) and turn rate (TR) to generate a second set of parameters; calculate a sag correction; and apply the sag correction and second set of parameters to the representation of the wellbore path to generate a calibrated wellbore path. (See rejection for claim 5)
Regarding Claim 14: The reference discloses The drilling system of claim 13, further comprising: a display device coupled to the computer system, wherein the program further causes the processor to render for display on the display device, the calibrated wellbore path. (Chen. “[0083] The outputs may include tabular data of one or more performance parameters. Additionally, the outputs may be in the form of graphs of a performance parameter, with respect to time, or with respect to location along the BHA, for example. When the outputs are given based on location along the BHA the outputs may be presented as an average value for each location as well as other percentages, such as 5%, 10%, 25%, 75%, 90%, and 95%. Other plots may include presentation of the results at a minimum or maximum value, or any combination of those results. A graphical visualization of the drill bit, drill string, and/or the drilling tools (e.g., a hole opener) may also be output. The graphical visualization (e.g., 2-D, 3-D, or 4-D) may include a color scheme for the drill string and BHA to indicate performance parameters at locations along the length of the drill string and bottom hole assembly.”)
Regarding Claim 15: The reference discloses The drilling system of claim 13, wherein the program further causes the processor to: generate a second portion of the wellbore path by applying the second set of parameters. (Chen. “[0094] Representative results that are produced by the simulation include accelerations at the bit, reamer, stabs and other locations; velocities at the bit, reamer, stabs and other locations; displacements at the bit, reamer, stabs, and other locations; the trajectory of the bit, reamer, stabs, and other locations; torque of the bit, reamer, stabs, and other locations; and contact force of the bit, reamer, stabs, and other locations. Any or all of these results may be produced in the form of a time history, box and whisker plots, 2D or 3D animations and pictures.” “[0220] In selected embodiments, the present disclosure allows a BHA designer to investigate the performance of multiple BHA's having a dynamic input. A dynamic input is an input that varies during the course of a simulation. For example, the RPM may be varied with the bit either drilling or not drilling, to determine a critical speed to be avoided during drilling. Similarly, the weight on bit may be varied over the course of the simulation from 0 to a selected value, or between two higher values. Similarly, the rate of penetration of the BHA may be entered as a dynamic input, and allowed to change over the course of the simulation. By having a dynamic input, selected embodiments of the present disclosure may allow a BHA designer to suggest operating parameters to be avoided, or to be used by a driller when actually drilling a well.”)
Regarding Claim 16: The reference discloses A directional drilling system configured to steer a bottom hole assembly (BHA) comprising: a drill string comprising the BHA, the BHA being coupled to a distal end of the drill string; an electronic drilling recorder (EDR) coupled to the BHA; and a computer system coupled to the EDR comprising: a processor; and a memory coupled to the processor, the memory storing a program that, when executed by the processor, causes the processor to: receive, by the computer system coupled to a drilling rig drilling a wellbore, a first set of parameters for drilling and at least two of the following: bottom hole assembly data, operating parameters data, and rock formation data; generate during drilling of the wellbore a representation of a first portion of a wellbore path responsive to a first set of parameters and one or more of: bottom hole assembly (BHA) data received from the BHA; operating parameters data; or rock formation data; generate, during drilling of the wellbore, responsive to data received from a survey corresponding to the first portion of the wellbore path for the first set of parameters, a second set of parameters; and generate, during drilling of the wellbore, responsive to the second set of parameters, a representation of a second portion of the wellbore path; generate a reconstructed trajectory of the wellbore path based on a calculated buildup rate (BUR) and calculated turn rate (TR) of a drill string coupled to the drilling rig and the first set of parameters; receive actual BUR and actual TR corresponding to the first portion of the wellbore path; generate a reconstructed actual trajectory of the first portion of the wellbore path based on an actual BUR and actual TR of the drill string and the first set of parameters; calibrate the first set of parameters based on the actual BUR and the actual TR to generate the second set of parameters; and modify a predicted trajectory based on the second set of parameters to generate the reconstructed actual trajectory; and alter, during drilling of the wellbore, one or more drilling parameters based on the second portion of the wellbore path; and drill the second portion of the wellbore with the one or more altered drilling parameters. (See rejection for claim 1)
Regarding Claim 17: The reference discloses The directional drilling system of claim 16, wherein the first set of parameters comprises one or more of: quantifying bit steerability; walk; a coefficient of friction; or overgauge borehole information. (See rejection for claim 2)
Regarding Claim 20: The reference discloses The directional drilling system of claim 16, wherein responsive to the processor generating the reconstructed trajectory of the wellbore path, the program further causes the processor to: calculate a sag correction; apply the sag correction to the representation of the wellbore path; and generate a calibrated wellbore path in response to applying the sag correction. (See rejection for claim 5)
6. Claim(s) 7, 11, and 19 are rejected under 35 U.S.C. 103 as being unpatentable over Chen in view of Chau further in view of Tang, X. M., Y. Zheng, and D. Patterson. "Processing array acoustic-logging data to image near-borehole geologic structures." Geophysics 72.2 (2007): E87-E97, hereafter Tang.
Regarding Claim 7: Chen discloses The computer-implemented method of claim 6, wherein generating the representation of the second portion of the wellbore path further comprises: receiving measured depth, inclination, (“[0015] The method used to obtain the measurements needed to calculate and plot a 3D well path is called a directional survey. Three parameters are measured at multiple locations along the well path--MD, inclination, and hole direction. MD is the actual depth of the hole drilled to any point along the wellbore or to total depth, as measured from the surface location. Inclination is the angle, measured in degrees, by which the wellbore or survey-instrument axis varies from a true vertical line. An inclination of 0.degree. would be true vertical, and an inclination of 90.degree. would be horizontal.”) and azimuth data from a survey, ([0059] “Drilling performance parameters may also include the inclination angle and azimuth direction of the borehole being drilled.”) corresponding to the first portion of the wellbore path; calibrating the second set of parameters based on the actual rock formation data to generate a third set of parameters; and generating the representation of the second portion of the wellbore path based on the third set of parameters. (“[0220] In selected embodiments, the present disclosure allows a BHA designer to investigate the performance of multiple BHA's having a dynamic input. A dynamic input is an input that varies during the course of a simulation. For example, the RPM may be varied with the bit either drilling or not drilling, to determine a critical speed to be avoided during drilling. Similarly, the weight on bit may be varied over the course of the simulation from 0 to a selected value, or between two higher values. Similarly, the rate of penetration of the BHA may be entered as a dynamic input, and allowed to change over the course of the simulation. By having a dynamic input, selected embodiments of the present disclosure may allow a BHA designer to suggest operating parameters to be avoided, or to be used by a driller when actually drilling a well.”)
Chen and Chau do not explicitly disclose receiving, from an acoustic logger, actual rock formation data corresponding to the first portion of the wellbore path.
However Tang discloses receiving, from an acoustic logger, actual rock formation data corresponding to the first portion of the wellbore path. (Tang. E96, Left column, 1st full paragraph, “This example shows the feasibility of drilling steering using LWD acoustic data. The image was not obtained during drilling but was the result of post processing after retrieving the tool from the well. If the real-time acoustic image can be obtained and viewed while drilling, a decision can then be made whether to steer the drill bit toward or away from the imaged geologic boundary ahead of the drill bit. Therefore, real-time data processing and result visualization need to be developed for the LWD drilling steering application.”)
It would have been obvious to one of ordinary skill in the art before the effective filing date of the invention to utilize an acoustic logger for subsurface formation data as per Tang for the wellbore system of Chen and Chau in order to allow for deciding “whether to steer the drill bit toward or away from the imaged geologic boundary ahead of the drill bit” Tang. E96, left column, 1st full paragraph and “to obtain an image of formation structural changes away from the borehole” Tang, E87, left column, 1st paragraph.
Regarding Claim 11: The reference discloses The drilling system of claim 10, wherein the program further causes the processor to: receive, from an acoustic logger, actual rock formation data corresponding to the first portion of the wellbore path; determine that a difference between the rock formation data and the actual rock formation data is above a predetermined threshold; calibrate the second set of parameters based on the actual rock formation data to generate a third set of parameters; and generate the representation of the second portion of the wellbore path by applying the third set of parameters. (See rejection for claim 7)
Regarding Claim 19: The reference discloses The directional drilling system of claim 16, wherein responsive to the processor generating a second portion of the wellbore path, the program further causes the processor to: receive, from an acoustic logger, actual rock formation data corresponding to the first portion of the wellbore path; determine that a difference between the rock formation data and the actual rock formation is above a predetermined threshold; calibrate the second set of parameters based on the actual rock formation data to generate a third set of parameters; and generate a second portion of the wellbore path based on the third set of parameters. (See rejection for claim 7)
Conclusion
7. Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
8. All Claims are rejected.
9. The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
i) Rommetveit, Rolv, Knut Bjorkevoll, and Sven Inge Ødegård. "Real-time, 3D visualization drilling supervision system targets ECD, downhole pressure control." Drilling contractor (2008).
ii) Sarker, Mejbahul, D. Geoff Rideout, and Stephen D. Butt. "Dynamic model for 3D motions of a horizontal oilwell BHA with wellbore stick-slip whirl interaction." Journal of Petroleum Science and Engineering 157 (2017): 482-506.
iii) Inaba, Mitsuru, et al. "Wellbore imaging goes live." Oilfield Review 15.1 (2003): 24-37.
10. Any inquiry concerning this communication or earlier communications from the examiner should be directed to Saif A. Alhija whose telephone number is (571) 272-8635. The examiner can normally be reached on M-F, 10:00-6:00.
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SAA
/SAIF A ALHIJA/Primary Examiner, Art Unit 2188