DETAILED ACTION
Claims 1-23 are presented for examination. This office action is response to the submission on 6/9/2023.
Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Information Disclosure Statement
The information disclosure statement (IDS) submitted on 8/3/2023 is in compliance with the provisions of 37 CFR 1.97. Accordingly, the information disclosure statement is being considered by the examiner.
Drawings
The drawings filed on 6/9/2023 are acceptable for examination proceedings.
Claim Rejections - 35 USC § 112
The following is a quotation of 35 U.S.C. 112(b):
(b) CONCLUSION.—The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the inventor or a joint inventor regards as the invention.
The following is a quotation of 35 U.S.C. 112 (pre-AIA ), second paragraph:
The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the applicant regards as his invention.
Claim 1 recites the limitation "the first surface control variable" in line 8. There is insufficient antecedent basis for this limitation in the claim.
Claim 4 recites the limitation "the second surface control variable" in line 6. There is insufficient antecedent basis for this limitation in the claim.
Claim 13 recites the limitation "the plurality of surface control variables" in line 8. There is insufficient antecedent basis for this limitation in the claim.
Claim 13 is unclear because the limitation “computing a desired respective surface control variable value corresponding to each of the plurality of desired first downhole response variable values” seems to indicate that a single surface control variable may correspond to a plurality of downhole response values, while the limitation “setting each of the plurality of surface control variables respectively to the desired surface control variable values;” seems to indicate that a different surface control variable is required for each downhole response value. For the purposes of examination, examiner interprets the claim such that a single surface control variable may only correspond to a single downhole response value.
Claims 2-3 and 5-12 are rejected under 35 U.S.C. 112, second paragraph, for being dependent upon rejected base claim 1.
Claims 14-21 are rejected under 35 U.S.C. 112, second paragraph, for being dependent upon rejected base claim 13.
Claim Rejections - 35 USC § 102
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 (i.e., changing from AIA to pre-AIA ) 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.
The following is a quotation of the appropriate paragraphs of 35 U.S.C. 102 that form the basis for the rejections under this section made in this Office action:
A person shall be entitled to a patent unless –
(a)(1) the claimed invention was patented, described in a printed publication, or in public use, on sale, or otherwise available to the public before the effective filing date of the claimed invention.
(a)(2) the claimed invention was described in a patent issued under section 151, or in an application for patent published or deemed published under section 122(b), in which the patent or application, as the case may be, names another inventor and was effectively filed before the effective filing date of the claimed invention.
Claims 1-3 and 6-10 are rejected under 35 U.S.C. 102(a)(1) as being anticipated by Jones et al. (US20170254190A1).
Claim 1:
Jones teaches “A method for controlling a downhole tool in a drilling operation, the method comprising the steps of: selecting a desired first downhole response variable value;” (Jones teaches commanding a toolface value i.e. a selected downhole response variable value in Jones [0050] "For example, continuing the exemplary embodiment described above, to send the command “Modify toolface, coarse and fine values are being sent, 90° Left, −15°”, where the code value for “coarse 90° Left” for C3 is represented by RPM value 360 c and the code value for “fine −15°” for C4 is represented by RPM value 370 e, drill string 20 may be rotated at RPM value 360 c for duration d3 during drill string rotation step t2 as depicted in FIG. 3D and subsequently rotated at RPM value 370 e for duration d4 during drill string rotation step t3 as depicted in FIG. 3E."
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“computing a desired first surface control variable value corresponding to the desired first downhole response variable value according to a preset mathematical relationship wherein the preset mathematical relationship is accessible by one or more surface and/or downhole controllers;” (Jones teaches determining a drill string RPM i.e. first surface control variable in order to send the toolface value command in Jones [0047-0048] "In some embodiments, depending on the code value of code C2 to be sent, drill string 20 may be rotated at the determined RPM value for code C1, here 320 a, for the duration d1 corresponding to the code value to be sent. Therefore, for example, in order to send the encoded message for the command “Modify toolface, coarse and fine values are being sent”, drill string 20 may be rotated at RPM value 320 a for duration 350 b during drill string rotation step t1 as depicted in FIG. 3C. Any additional codes of the encoded message may be likewise encoded onto RPM values or durations for subsequent time periods. For example, FIG. 3D depicts code C3 assigned to RPM values 360 a-f, each representing a different code value of code C3 to be transmitted in drill string rotation step t2. RPM values 360 a-f may be determined relative to set point RPM 310."),
“setting the first surface control variable to the desired first surface control variable value;” (Jones teaches that the drill string will be rotated at the determined RPM values in Jones [0050] "For example, continuing the exemplary embodiment described above, to send the command “Modify toolface, coarse and fine values are being sent, 90° Left, −15°”, where the code value for “coarse 90° Left” for C3 is represented by RPM value 360 c and the code value for “fine −15°” for C4 is represented by RPM value 370 e, drill string 20 may be rotated at RPM value 360 c for duration d3 during drill string rotation step t2 as depicted in FIG. 3D and subsequently rotated at RPM value 370 e for duration d4 during drill string rotation step t3 as depicted in FIG. 3E."; Jones describes setting the drill RPM in Jones [0038] "The set point RPM may thus be used as a baseline from which the RPM values of the drill string rotation steps are offset. Once the set point RPM is selected, the RPM at which to rotate drill string 20 during each drill string rotation step may be determined based on the offset from the selected set point RPM, depicted as determine RPM values (209) in FIG. 2. The set point RPM and encoded message may then be used to command rotation controller 36 to rotate drill string 20 to communicate the command to the downhole tool. In some embodiments, the drill string 20 may be rotated at or substantially at the set point RPM at a first drill string rotation step (211) to establish the set point RPM with downhole tool 60 as described herein below. The encoded message may then be transmitted by rotating drill string 20 consistent with each code value of the encoded message for each drill string rotation step in the encoded message (213)."),
“measuring the first surface control variable at a bottom hole assembly and obtaining a plurality of measured values of the first surface control variable;” (Jones teaches a rotation rate sensor 32 to determine rotation rate of the drill string in Jones [0053] "In some embodiments, downhole tool 60 may include one or more rotation rate sensors 32. Rotation rate sensors 32 may be used to measure the rotation rate of drill string 20 at the location of rotation rate sensor 32 along drill string 20."; Jones teaches interpreting measured RPM values i.e. a plurality of measured values of the first surface control variable in Jones [0058] "In some embodiments, rotation rate sensor 32 may be in data connection with downhole decoder 33. Downhole decoder 33 may measure drill string rotation from rotation rate sensor 32. In some embodiments, downhole decoder 33 may be configured to receive and interpret the command of the encoded message as described herein above based on measured RPM values of drill string 20."),
“processing the plurality of measured values to determine a representative value for the first surface control variable;” (Jones teaches filtering the sensor data i.e. it determines a representative value of the RPM by filtering out some of the sensed values in Jones [0056] "In some embodiments, the measured RPM value from rotation rate sensor 32 may be filtered to, for example, suppress noise and other erroneous values from the RPM values measured including, for example and without limitation, stick-slip and torsional vibration. Such filtering may, in some embodiments, be accomplished by one or more of an analog filter, a digital filter, or combinations thereof. In some embodiments, the filter may include, for example and without limitation, one or more of a non-linear filter such as a median filter, a linear filter such as an infinite impulse response (IIR) filter or a finite impulse response (FIR) filter), or combinations thereof."), and
“computing a first downhole response variable value corresponding to the representative value for the first surface control variable of the plurality of measured surface control values according to the preset mathematical relationship; and, controlling the downhole tool according to the computed first downhole response variable value.” (Jones teaches that the downhole decoder 33 will decode the received code i.e. compute a desired toolface orientation in step 413 and then execute the command in step 415 in Jones [0061-0062] "Once downhole decoder 33 determines that a code has been received, downhole decoder 33 may decode the received code (409). Downhole decoder 33 may repeat the procedure for each code received until the execute RPM is determined to have been received (411). Downhole decoder 33 may then assemble the received codes and identify the received command (413). Downhole decoder 33 may then execute the command (415). In some embodiments, downhole decoder 33 may decode the received code by comparing the RPM value of the received code with the identified set point RPM. In some embodiments, downhole decoder 33 may establish an RPM window for each possible code to be received for each drill string rotation step. As an example, FIGS. 5A-5E depict an exemplary representation of a decoding operation for a message consistent with embodiments as described herein.”).
Claim 2:
Jones teaches “The method according to claim 1 wherein determining the representative value is based on those of the plurality of measured values of the first surface control variable associated with a first window.” (Jones teaches that downhole decoder 33 repeats the determination of a code until an execute RPM is received i.e. the values are associated with a first window in Jones [0061] "Once downhole decoder 33 determines that a code has been received, downhole decoder 33 may decode the received code (409). Downhole decoder 33 may repeat the procedure for each code received until the execute RPM is determined to have been received (411). Downhole decoder 33 may then assemble the received codes and identify the received command (413)."; Jones teaches that when sending the command, it determines a time period for the command to be sent in Jones [0041] "FIG. 3A depicts that, at a first drill string rotation step, depicted as to, drill string 20 may be rotated at set point RPM 310 for a first duration do. In some embodiments, set point RPM 310 may be recognized by downhole tool 60 when drill string 20 is rotated at an RPM for a predetermined duration. The rotation rate of drill string 20 may be limited to a particular range to be considered a set point RPM, for instance and without limitation, between 20 and 200 RPM, or between 60 and 160 RPM. The predetermined set point time period may range from at least 30 seconds to at least three minutes, or from at least one minute to at least two minutes, or at least about 1 minute 15 seconds. In certain embodiments, the set point RPM is not predefined, i.e., it may be set by the operator based on considerations such as current operating conditions of drilling system 12."; Jones teaches that steering ratio i.e. steering rate may be the controlled variable in Jones [0025] "Although described with respect to offset, one having ordinary skill in the art with the benefit of this disclosure will understand that the parameter referred to herein as offset is equally applicable to steerable systems which define the magnitude of the change in direction of drilling of wellbore 14 as “steering ratio (proportion)”. As understood in the art, the steering ratio (SR) corresponds to how steep the curve is measured relative to the maximum curvature able to be imparted by the steerable system. For example, SR=0%, 50%, and 100% correspond to neutral drilling (no curvature), 50% of the maximum curvature (or maximum dogleg), and the maximum curvature (maximum dogleg), respectively."; Jones teaches that mud flow rate may be modulated to send a message in Jones [0057] "In some embodiments, where downhole tool 60 is a powered RSS, motor-assisted RSS, turbine assisted RSS, or gear-reduced turbine assisted RSS, a flow-modulated downlink signal may be received from the shaft RPM changes at downhole tool 60. In such an embodiment, rotation of drill string 20 as discussed herein may refer to the rotation of a drive shaft below a mud motor, turbine, or gear-reduced turbine, wherein the message is modulated onto a drilling mud flow rate at surface 5. In some embodiments, such flow rate may be computer-controlled by equipment located at surface 5. In some embodiments, messages may be sent while conventional mud pulse telemetry is in operation for uplinking, without interrupting uplink communications, which may allow simultaneous uplink and downlink communications.").
Claim 3:
Jones teaches “The method according to claim 2 wherein determining the representative value comprises processing the plurality of those of the measured values of the first surface control variable corresponding to the first window to remove outliers and determining the representative value for the remaining ones of the measured values of the surface control variable corresponding to the first window.” (Jones teaches filtering the sensor data i.e. it determines a representative value of the RPM by filtering out erroneous values in Jones [0056] "In some embodiments, the measured RPM value from rotation rate sensor 32 may be filtered to, for example, suppress noise and other erroneous values from the RPM values measured including, for example and without limitation, stick-slip and torsional vibration. Such filtering may, in some embodiments, be accomplished by one or more of an analog filter, a digital filter, or combinations thereof. In some embodiments, the filter may include, for example and without limitation, one or more of a non-linear filter such as a median filter, a linear filter such as an infinite impulse response (IIR) filter or a finite impulse response (FIR) filter), or combinations thereof.").
Claim 6:
Jones teaches “The method according to claim 1 wherein the representative value is an (Jones teaches filtering the sensor data i.e. it determines a representative value of the RPM and that it may use a median filter i.e. the representative value is a median value in Jones [0056] "In some embodiments, the measured RPM value from rotation rate sensor 32 may be filtered to, for example, suppress noise and other erroneous values from the RPM values measured including, for example and without limitation, stick-slip and torsional vibration. Such filtering may, in some embodiments, be accomplished by one or more of an analog filter, a digital filter, or combinations thereof. In some embodiments, the filter may include, for example and without limitation, one or more of a non-linear filter such as a median filter, a linear filter such as an infinite impulse response (IIR) filter or a finite impulse response (FIR) filter), or combinations thereof.").
Claim 7:
Jones teaches “The method according to claim 1 wherein the first downhole response variable corresponds to a toolface angle of a drill bit.” (Jones teaches that toolface, which may be the first downhole response variable as described in claim 1 may refer to the angular direction of a drill bit 18 in Jones [0024] "As used herein and understood in the art, “toolface” refers to the direction in which wellbore 14 is being drilled. In some embodiments, toolface may refer to the angular direction that drill bit 18 is pushing or pointing with respect to the Earth's gravity field.").
Claim 8:
Jones teaches “The method according to claim 1 wherein the first downhole response variable is a steering rate of the downhole tool.” (Jones teaches that steering ratio i.e. steering rate may be the controlled variable in Jones [0025] "Although described with respect to offset, one having ordinary skill in the art with the benefit of this disclosure will understand that the parameter referred to herein as offset is equally applicable to steerable systems which define the magnitude of the change in direction of drilling of wellbore 14 as “steering ratio (proportion)”. As understood in the art, the steering ratio (SR) corresponds to how steep the curve is measured relative to the maximum curvature able to be imparted by the steerable system. For example, SR=0%, 50%, and 100% correspond to neutral drilling (no curvature), 50% of the maximum curvature (or maximum dogleg), and the maximum curvature (maximum dogleg), respectively.").
Claim 9:
Jones teaches “The method according to claim 1 wherein the first surface control variable is a rotational speed of a drill string of a drill rig.” (Jones teaches determining a drill string RPM i.e. first surface control variable in order to send the toolface value command in Jones [0047-0048] "In some embodiments, depending on the code value of code C2 to be sent, drill string 20 may be rotated at the determined RPM value for code C1, here 320 a, for the duration d1 corresponding to the code value to be sent. Therefore, for example, in order to send the encoded message for the command “Modify toolface, coarse and fine values are being sent”, drill string 20 may be rotated at RPM value 320 a for duration 350 b during drill string rotation step t1 as depicted in FIG. 3C. Any additional codes of the encoded message may be likewise encoded onto RPM values or durations for subsequent time periods. For example, FIG. 3D depicts code C3 assigned to RPM values 360 a-f, each representing a different code value of code C3 to be transmitted in drill string rotation step t2. RPM values 360 a-f may be determined relative to set point RPM 310.").
Claim 10:
Jones teaches “The method according to claim 9 wherein the mathematical relationship comprises a mapping between a range of values of a toolface angle and a range of values of the rotational speed of the drill string.” (Jones teaches a mapping of RPM to toolface direction in Jones [0050] "For example, continuing the exemplary embodiment described above, to send the command “Modify toolface, coarse and fine values are being sent, 90° Left, −15°”, where the code value for “coarse 90° Left” for C3 is represented by RPM value 360 c and the code value for “fine −15°” for C4 is represented by RPM value 370 e, drill string 20 may be rotated at RPM value 360 c for duration d3 during drill string rotation step t2 as depicted in FIG. 3D and subsequently rotated at RPM value 370 e for duration d4 during drill string rotation step t3 as depicted in FIG. 3E.").
Claim 22 is rejected under 35 U.S.C. 102(a)(1) as being anticipated by Baron et al. (US20050001737A1).
Claim 22:
Baron teaches “An analog method of downlinking a toolface angle to a bottom hole assembly during a drilling operation, the method comprising the steps of: selecting a desired toolface angle value;” (Baron teaches that commands may be transmitted from the surface to direct the path of the borehole in Baron [0020] "As described in more detail below with respect to FIGS. 2A and 2B, downhole device 108 includes a sensor for measuring the rotation rate of the drill string 102. Downhole device 108 may further optionally include a trajectory control mechanism that is responsive to commands transmitted from the surface to direct the projected path of the borehole 104 during drilling."; Baron teaches the commands may be a desired tool face direction i.e. toolface angle in Baron [0046] "An exemplary encoding scheme of the present invention provides an operator with, for example, control of a directional drilling downhole tool similar to tool 200 described in conjunction with FIG. 2A. In such an exemplary embodiment, commands from the surface are received by the directional drilling tool 200 to determine the projected trajectory of an Earth bore as the bore is being drilled. Directional commands from the surface are in the form of a desired tool face and offset for the drilling tool 200."),
“computing a rotational speed of a drill string (RPM) corresponding to the desired toolface angle value according to a preset mathematical relationship;” (Baron teaches computing a desired RPM corresponding to a tool face i.e. a toolface angle value in Baron [0052] "Tables 4 and 5 above assign a plurality of tool face options to unique combinations of codes C3 and C4 for command types 1 through 4. In the exemplary embodiment shown, tool face options are available in 10-degree increments ranging from 0 to 350 degrees. Command types 1 and 3 define tool face values ranging from 270 to 80 degrees (270 to 440 degrees), while command types 2 and 4 define tool face values ranging from 90 to 260 degrees. In the embodiment shown, acceptable values of code C3 are either in the range from 30 to 59 seconds or in the range from 60 to 89 seconds."; Baron teaches a transmission system 300 that may translate commands into rotation-encoded data in Baron [0029] "Alternatively, with reference to FIG. 3, aspects of this invention may include a transmission system 300 to translate commands from an operator into rotation-encoded data and to transmit the commands to the downhole tool. An exemplary transmission system 300 may include a rotation rate controller 310 that is under the control of a processor 306 via path 308."
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“rotating the drill string at the computed rotational speed;” (Baron teaches adjusting the RPM of the drill string in order to send messages in Baron [0033] "Various alternative exemplary embodiments of encoding schemes, in accordance with the present invention, are described, in conjunction with FIGS. 4A through 4D. FIGS. 4A through 4D show waveforms 400, 430, 450, and 480, each of which represents on exemplary embodiment of rotation-encoded data. The vertical scale indicates the rotation rate of the drill string measured in rotations per minute (RPM). The horizontal scale indicates relative time in seconds measured from an arbitrary reference."),
“measuring RPM of the drill string at the bottom hole assembly to obtain a sequence of measured RPM values;” (Baron teaches measuring RPM for the duration of a pulse i.e. it takes a plurality of measurements of the surface control value in Baron [0039] "Exemplary embodiments may, for example, predefine the interval for measuring the duration to be delineated by the point in time 404 in which the rotation rate increases more than 10 RPM above base 403 and the point in time 407 in which the rotation rate drops to a level within 10 RPM of base 403. In such embodiments, the duration of pulse shown in FIG. 4A would be approximately 360 seconds. Another encoding scheme may, for example, predefine the interval for measuring the duration may be delineated by the point in time 405 in which the rotation rate reaches the elevated level 411 and the point in time 406 in which the rotation rate is detected to drop 10 RPM from the elevated level 411. In such embodiments, the duration of pulse shown in FIG. 4A, for determining code CY, would be approximately 290 seconds."),
“computing a representative value of the plurality of time-stamped RPM values obtained in a first window;” (Baron teaches that the difference of the RPM and the length of the pulse both may be used to determine a code and that the pulse is required to remain in a predefined tolerance range i.e. a representative value will be calculated as long as the pulse stays within a tolerance range in Baron [0036] "With reference now to FIG. 4A, one exemplary embodiment of rotation-encoded data is represented by waveform 400, which is in the form of a pulse. A pulse, in this exemplary embodiment, is predefined as a transitory divergence from a base rotation rate 403. During a portion of each transitory divergence, the pulse is required to remain at a constant rotation rate, within a predefined tolerance range. In the particular encoding scheme illustrated, a pulse is defined as an increase in the rotation rate from the base level 403 to faster rotation rate referred to as the elevated level 411, for a specified amount of time, followed by a return to the base level 403. Alternative embodiments may define a pulse as a decrease in the rotation rate to a reduced level, for a specified amount of time, followed by a return to the base level 403. In the embodiment shown, the pulse provides two parameters for encoding data: duration and rotation rate. Waveform 400 on FIG. 4A illustrates a first code CY that is defined as a function of the measured duration and a second code CX that is defined as a function of the difference between the rotation rate at the elevated level and the base level."),
“computing a toolface angle corresponding to the representative value according to the preset mathematical relationship;” (Baron teaches computing a tool face angle based on the measured RPM in Baron [0052] "Tables 4 and 5 above assign a plurality of tool face options to unique combinations of codes C3 and C4 for command types 1 through 4. In the exemplary embodiment shown, tool face options are available in 10-degree increments ranging from 0 to 350 degrees. Command types 1 and 3 define tool face values ranging from 270 to 80 degrees (270 to 440 degrees), while command types 2 and 4 define tool face values ranging from 90 to 260 degrees. In the embodiment shown, acceptable values of code C3 are either in the range from 30 to 59 seconds or in the range from 60 to 89 seconds. Acceptable values of code C4 are at increments of 10 RPM in the range from 20 to 100 RPM. Tool commands may be advantageously predefined with respect to codes C3 and C4 to substantially minimize errors in programming the directional drilling tool."), and
“and, setting a toolface angle of a steering system to the computed toolface angle value.” (Baron teaches applying the decoded command in Baron [0066] "Otherwise, STATE is set to 13 at 625 and the decoded command (comprising the command type and one or two parameters) is applied to the directional drilling tool at 626. The program (i.e., the control loop) is then returned to step 501 on FIG. 5A to re-establish BASE and to wait for the next code sequence to be detected.").
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 for establishing a background for determining obviousness under 35 U.S.C. 103 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.
Claims 4-5 and 11 are rejected under 35 U.S.C. 103 as being unpatentable over Jones et al. (US20170254190A1), in view of Baron et al. (US20050001737A1).
Claim 4:
Jones teaches “The method of claim 2” as described above.
Nunn does not appear to explicitly teach “further comprising the steps of: selecting a desired second downhole response variable value;”, “computing a desired second surface control variable value corresponding to the desired second downhole response variable value according to a second preset mathematical relationship;”, “setting the second surface control variable to the desired second surface control variable value;”, “measuring the second surface control variable at the bottom hole assembly and obtaining a plurality of measured second surface control values;”, “computing over a second window that is the same as or different from the first window a representative value of the plurality of second surface control variable values;”, “computing a second downhole response variable value corresponding to the representative value of the plurality of measured second surface control variable values according to the second preset mathematical relationship;”, or “and, setting the second downhole response variable to the computed second downhole response variable value.” However, Baron does teach these claim limitations.
Baron teaches “further comprising the steps of: selecting a desired second downhole response variable value;” (Baron teaches that commands may be transmitted from the surface to direct the path of the borehole in Baron [0020] "As described in more detail below with respect to FIGS. 2A and 2B, downhole device 108 includes a sensor for measuring the rotation rate of the drill string 102. Downhole device 108 may further optionally include a trajectory control mechanism that is responsive to commands transmitted from the surface to direct the projected path of the borehole 104 during drilling."; Baron teaches the commands may be a desired tool face direction and offset i.e. offset may be the second downhole response variable value in Baron [0046] "An exemplary encoding scheme of the present invention provides an operator with, for example, control of a directional drilling downhole tool similar to tool 200 described in conjunction with FIG. 2A. In such an exemplary embodiment, commands from the surface are received by the directional drilling tool 200 to determine the projected trajectory of an Earth bore as the bore is being drilled. Directional commands from the surface are in the form of a desired tool face and offset for the drilling tool 200."),
“computing a desired second surface control variable value corresponding to the desired second downhole response variable value according to a second preset mathematical relationship;” (Baron teaches a transmission system 300 to translate commands from an operator i.e. desired tool face and offset into rotation-encoded data in Baron [0029] "Turning now to FIG. 3, a block diagram of a transmission system 300 suitable for rotation speed controller 120 (FIG. 1) is illustrated. As described above with respect to FIG. 1, the rotation speed controller 120 may include, for example, a knob for manually setting the rotation rate of the drill string 102. Rotation-encoded data, in accordance with this invention, may be simply and efficiently transmitted by manually adjusting the knob. Alternatively, with reference to FIG. 3, aspects of this invention may include a transmission system 300 to translate commands from an operator into rotation-encoded data and to transmit the commands to the downhole tool. An exemplary transmission system 300 may include a rotation rate controller 310 that is under the control of a processor 306 via path 308.”),
“setting the second surface control variable to the desired second surface control variable value;” (Baron teaches adjusting the RPM of the drill string i.e. a second surface control variable in order to send messages in Baron [0033] "Various alternative exemplary embodiments of encoding schemes, in accordance with the present invention, are described, in conjunction with FIGS. 4A through 4D. FIGS. 4A through 4D show waveforms 400, 430, 450, and 480, each of which represents on exemplary embodiment of rotation-encoded data. The vertical scale indicates the rotation rate of the drill string measured in rotations per minute (RPM). The horizontal scale indicates relative time in seconds measured from an arbitrary reference."),
“measuring the second surface control variable at the bottom hole assembly and obtaining a plurality of measured second surface control values;” (Baron teaches measuring RPM for the duration of a pulse i.e. it takes a plurality of measurements of the surface control value in Baron [0039] "Exemplary embodiments may, for example, predefine the interval for measuring the duration to be delineated by the point in time 404 in which the rotation rate increases more than 10 RPM above base 403 and the point in time 407 in which the rotation rate drops to a level within 10 RPM of base 403. In such embodiments, the duration of pulse shown in FIG. 4A would be approximately 360 seconds. Another encoding scheme may, for example, predefine the interval for measuring the duration may be delineated by the point in time 405 in which the rotation rate reaches the elevated level 411 and the point in time 406 in which the rotation rate is detected to drop 10 RPM from the elevated level 411. In such embodiments, the duration of pulse shown in FIG. 4A, for determining code CY, would be approximately 290 seconds."),
“computing over a second window that is the same as or different from the first window a representative value of the plurality of second surface control variable values;” (Baron teaches that the difference of the RPM and the length of the pulse both may be used to determine a code and that the pulse is required to remain in a predefined tolerance range i.e. a representative value will be calculated as long as the pulse stays within a tolerance range in Baron [0036] "With reference now to FIG. 4A, one exemplary embodiment of rotation-encoded data is represented by waveform 400, which is in the form of a pulse. A pulse, in this exemplary embodiment, is predefined as a transitory divergence from a base rotation rate 403. During a portion of each transitory divergence, the pulse is required to remain at a constant rotation rate, within a predefined tolerance range. In the particular encoding scheme illustrated, a pulse is defined as an increase in the rotation rate from the base level 403 to faster rotation rate referred to as the elevated level 411, for a specified amount of time, followed by a return to the base level 403. Alternative embodiments may define a pulse as a decrease in the rotation rate to a reduced level, for a specified amount of time, followed by a return to the base level 403. In the embodiment shown, the pulse provides two parameters for encoding data: duration and rotation rate. Waveform 400 on FIG. 4A illustrates a first code CY that is defined as a function of the measured duration and a second code CX that is defined as a function of the difference between the rotation rate at the elevated level and the base level."),
“computing a second downhole response variable value corresponding to the representative value of the plurality of measured second surface control variable values according to the second preset mathematical relationship;” (Baron teaches computing a tool offset i.e. a second downhole response variable value based on the measured RPM i.e. measured second surface control variable values in Baron [0052] "Table 6 above assigns a plurality of offset options to unique combinations of codes C5 and C6 for command types 1 and 2 or to unique combinations of codes C3 and C4 for command type 5. Codes C5 and C3 select a base offset option and codes C6 and C4 represent an additional amount that is added to the base offset option to determine the selected tool offset option. Valid rotation rate values for codes C6 and C4 are in the range from 20 to 100 RPM relative to the base level. Each 10-RPM increment above a value of 20 RPM increases the offset by an additional 0.04 inches. For example an offset value of 0.04 inches may be encoded via pulse that has a rotation rate of 30 RPM (over the base level) and a 30 to 59 second duration. It will be appreciated that base offset options selected by codes C5 and C3 are staggered by 0.01 inches to result in negligible programming errors due to small errors in codes C5 and C3, which are defined as a function of duration."
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“and, setting the second downhole response variable to the computed second downhole response variable value.” (Baron teaches applying the decoded command in Baron [0066] "Otherwise, STATE is set to 13 at 625 and the decoded command (comprising the command type and one or two parameters) is applied to the directional drilling tool at 626. The program (i.e., the control loop) is then returned to step 501 on FIG. 5A to re-establish BASE and to wait for the next code sequence to be detected.").
Jones and Baron are analogous art because they are from the same field of endeavor of downlinking commands. It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, having teachings of Jones and Baron before him/her, to modify the teachings of a System and method for downlink communication of Jones to include the control of a second downhole variable via a second surface control variable of Baron because adding the Drill string rotation encoding of Baron would allow for quick and accurate communication with a downhole device as described in Baron [0023] “With continued reference to FIG. 1, aspects of the present invention are particularly well suited to (although expressly not limited to) applications in which the downhole device 108 receiving information from the surface is a directional drilling tool. Directional drilling tools commonly require substantially real-time adjustment to properly control the trajectory of the borehole. One advantage of certain aspects of this invention is that the surface to downhole communication may be accomplished without interrupting the drilling process. Additionally, the optimal rotation rate of a drill string 102 typically varies from one operation to the next due to variations in the strata being drilled and to changes in the type of drill bit being used. The present invention may advantageously be utilized at substantially any conventional rotation rate being employed to drill the borehole 104. Moreover, aspects of this invention enable quick and accurate communication with a downhole device 108. This is particularly advantageous when communicating with a directional drilling tool, such as a three-dimensional rotary steerable tool, since errors in directional commands may result in drilling a borehole in the wrong direction.”
Claim 5:
Jones in view of Baron teaches “The method according to claim 4 wherein the second downhole response variable is a steering rate of the downhole tool,” (Jones teaches that steering ratio i.e. steering rate may be the controlled variable in Jones [0025] "Although described with respect to offset, one having ordinary skill in the art with the benefit of this disclosure will understand that the parameter referred to herein as offset is equally applicable to steerable systems which define the magnitude of the change in direction of drilling of wellbore 14 as “steering ratio (proportion)”. As understood in the art, the steering ratio (SR) corresponds to how steep the curve is measured relative to the maximum curvature able to be imparted by the steerable system. For example, SR=0%, 50%, and 100% correspond to neutral drilling (no curvature), 50% of the maximum curvature (or maximum dogleg), and the maximum curvature (maximum dogleg), respectively."), and
“the second surface control variable is a drilling fluid flow rate (Jones teaches that mud flow rate may be modulated to send a message in Jones [0057] "In some embodiments, where downhole tool 60 is a powered RSS, motor-assisted RSS, turbine assisted RSS, or gear-reduced turbine assisted RSS, a flow-modulated downlink signal may be received from the shaft RPM changes at downhole tool 60. In such an embodiment, rotation of drill string 20 as discussed herein may refer to the rotation of a drive shaft below a mud motor, turbine, or gear-reduced turbine, wherein the message is modulated onto a drilling mud flow rate at surface 5. In some embodiments, such flow rate may be computer-controlled by equipment located at surface 5. In some embodiments, messages may be sent while conventional mud pulse telemetry is in operation for uplinking, without interrupting uplink communications, which may allow simultaneous uplink and downlink communications.").
Claim 11:
Jones in view of Baron teaches “The method according to claim 10 wherein the range of values of the toolface angle exceeds one full revolution.” (Baron teaches adjusting the tool face angle up to 440 degrees i.e. greater than one full revolution in Baron [0052] "Tables 4 and 5 above assign a plurality of tool face options to unique combinations of codes C3 and C4 for command types 1 through 4. In the exemplary embodiment shown, tool face options are available in 10-degree increments ranging from 0 to 350 degrees. Command types 1 and 3 define tool face values ranging from 270 to 80 degrees (270 to 440 degrees), while command types 2 and 4 define tool face values ranging from 90 to 260 degrees.").
Claim 12 is rejected under 35 U.S.C. 103 as being unpatentable over Jones et al. (US20170254190A1), in view of Parkin et al. (US20160145992A1).
Claim 12:
Jones teaches “The method according to claim 1” as described above.
Parkin does not appear to explicitly teach “wherein the mapping is a repeating function with dead bands.” However, Parkin does teach this claim limitation (Parkin teaches a repeating function with deadbands to map a drill string RPM to a rate of penetration of a downhole tool in Parkin [0024] "Using a repeating and/or periodic relationship enables a single drilling value to be encoded using a plurality of drilling parameter values (e.g., using one drilling parameter value in each period of the relationship). Thus the desired drill string rotation rate for the drilling process may be selected from any of a number of nominal RPM values. The ROP may then be encoded within the corresponding RPM window (period) via making relatively small variations to the RPM (in accordance with the established relationship between ROP and RPM). The dead band regions 148 provide a buffer between adjacent RPM windows and may be used, for example, for reaming and other non-downlinking operations."
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Jones and Parkin are analogous art because they are from the same field of endeavor of downlinking signals. It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, having teachings of Jones and Parkin before him/her, to modify the teachings of a System and method for downlink communication of Jones to include the control of a repeating relationship with deadbands of Parkin because adding the Continuous Downlinking While Drilling of Parkin would allow for the drilling parameter to be grossly changed while optimizing the drilling process as described in Parkin [0025] “It will be understood that the use of a repeating and/or periodic relationship to encode the drilling value advantageously enables the controlled drilling parameter (in this case the RPM) to be grossly changed while drilling to optimize the drilling process (e.g., to change the ROP or to mitigate adverse drilling dynamics conditions) without changing the encoded drilling value (in this case ROP). For example, in an event in which reducing RPM is desired, the RPM may be reduced from N to N−1 or N−2 (and so on) without changing the encoded ROP value. Conversely, the RPM may be increased from N to N+1 or N+2 (and so on) without changing the encoded ROP value. In the depicted embodiment the RPM windows may be spaced in any suitable RPM interval, for example, in a range from about 10 to about 50 RPM.”
Claims 13-21 and 23 are rejected under 35 U.S.C. 103 as being unpatentable over Baron et al. (US20050001737A1), in view of Jones et al. (US20170254190A1).
Claim 13:
Baron teaches “An analog method of downlinking a plurality of downhole response variables to a bottom hole assembly during a drilling operation, the method comprising the steps of: selecting a desired plurality of downhole response variable values;” (Baron teaches that commands may be transmitted from the surface to direct the path of the borehole in Baron [0020] "As described in more detail below with respect to FIGS. 2A and 2B, downhole device 108 includes a sensor for measuring the rotation rate of the drill string 102. Downhole device 108 may further optionally include a trajectory control mechanism that is responsive to commands transmitted from the surface to direct the projected path of the borehole 104 during drilling."; Baron teaches the commands may be a desired tool face direction in Baron [0046] "An exemplary encoding scheme of the present invention provides an operator with, for example, control of a directional drilling downhole tool similar to tool 200 described in conjunction with FIG. 2A. In such an exemplary embodiment, commands from the surface are received by the directional drilling tool 200 to determine the projected trajectory of an Earth bore as the bore is being drilled. Directional commands from the surface are in the form of a desired tool face and offset for the drilling tool 200."; Baron teaches that a user may specify a desired offset and tool face i.e. a plurality of downhole response variable values in Baron [0049] "Tables 1 and 2 above relate a first pulse to one of six command types via first and second codes C1 and C2. As shown in Table 1, command types 1 and 2 specify a desired tool face and a desired offset. As described above, offset specifies the distance between the longitudinal axis of the tool and the longitudinal axis of the borehole. Tool face defines the angular direction of the offset relative to a reference (such as the high side) and may range from 0° to 350° degrees in this exemplary embodiment."),
“computing a desired respective surface control variable value corresponding to each of the plurality of desired first downhole response variable values according to respective preset mathematical relationships, wherein the mathematical relationships are accessible by one or more surface and/or downhole controllers;” (Baron teaches computing a desired RPM i.e. surface control variable value corresponding to a tool face i.e. a first downhole response variable in Baron [0052] "Tables 4 and 5 above assign a plurality of tool face options to unique combinations of codes C3 and C4 for command types 1 through 4. In the exemplary embodiment shown, tool face options are available in 10-degree increments ranging from 0 to 350 degrees. Command types 1 and 3 define tool face values ranging from 270 to 80 degrees (270 to 440 degrees), while command types 2 and 4 define tool face values ranging from 90 to 260 degrees. In the embodiment shown, acceptable values of code C3 are either in the range from 30 to 59 seconds or in the range from 60 to 89 seconds."; Baron teaches computing a desired RPM i.e. a surface control variable value corresponding to a tool offset i.e. a second downhole response variable in Baron [0053] "Table 6 above assigns a plurality of offset options to unique combinations of codes C5 and C6 for command types 1 and 2 or to unique combinations of codes C3 and C4 for command type 5. Codes C5 and C3 select a base offset option and codes C6 and C4 represent an additional amount that is added to the base offset option to determine the selected tool offset option. Valid rotation rate values for codes C6 and C4 are in the range from 20 to 100 RPM relative to the base level. Each 10-RPM increment above a value of 20 RPM increases the offset by an additional 0.04 inches. For example an offset value of 0.04 inches may be encoded via pulse that has a rotation rate of 30 RPM (over the base level) and a 30 to 59 second duration. It will be appreciated that base offset opt