DETAILED ACTION
This communication is a final office action on the merits and in response to amendments filed on 12/2/2025. All currently pending claims have been considered below. The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Response to Amendment
The amendments to claim 1 are sufficient to overcome the prior art rejection of claim 1. New grounds necessitated by amendment respectfully follow.
The amendments to claim 13 are sufficient to obviate the prior rejection and require a new interpretation of US 2006/0212224 (Jogi). The amendments recite "responsive to determining the geological formation includes at least one of the fault zone, the geological stress zone, or the rock type, modifying at least one of the set of drilling parameters, wherein the at least one of the set of drilling operation parameters comprises mechanical specific energy". As supported by the two NPLs included with this action, "mechanical specific energy" is calculated by weight on bit, torque, rotary speed, and rate of penetration. Jogi discloses "adjust[ing] drilling parameters 24" which includes torque, weight on bit, and RPM of the drill bit" (¶ 31, as well as element 24, fig 1). Adjusting any of these is "modifying mechanical specific energy" as claimed, per the art definitions thereof. In other words, "adjusting ['modifying'] ROP" or "adjusting WOB" (24, fig 1 of Jogi) is changing / "modifying… mechanical specific energy" as now claimed.
The amendments to claim 27 are sufficient to overcome the prior art grounds of rejection.
Claim Objections
Claim 27 is objected to because of the following informalities: The phrase "wherein determining the geological stress zone or the fault zone is based at least in part on at least rates of deviation in rotary drift" (emphasis added). The examiner suggests the phrase be amended to read "wherein determining the geological stress zone or the fault zone is based at least in part on
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.
Claims 1 & 32-36 are rejected under 35 U.S.C. 103 as being unpatentable over US 2006/0212224 (Jogi) in view of US 2006/0074561 (Xia), in further view of WO 88/03222 (Falgout). A copy of Falgout is included with this action.
Independent claim 1. Jogi discloses a system for controlling a drilling of a wellbore ("A drilling system provides indications of the lithology of the formation being drilled by dynamically measuring at least one parameter of interest that is affected by the lithology of the formation being drilled… The lithological indications provided by the processor can be used to adjust drilling parameters, steer the BHA, monitor BHA health, and provide depth locations for bed boundaries and formation interfaces" - abstract) in real-time ("…being drilled" - abstract; "…BHA during drilling" - ¶ 31; continuous computer implementation) based on at least one or more geological formation characteristics (abstract), comprising:
a processor ("processor (surface and/or downhole)" 12, fig 1);
a memory coupled to the processor ("The processor(s) 70 can be microprocessor that uses a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. Other equipment such as power and data buses, power supplies, and the like will be apparent to one skilled in the art." - ¶ 37; "instructions loaded into a memory module (not shown) of the processor 12" - ¶ 40; conventional computer system) and storing instructions (ibid) executable by the processor (ibid), the instructions perform operations comprising:
during drilling of the wellbore ("The sensors 14 include one or more sensors that can dynamically measure drilling parameters such as instantaneous torque, weight on bit, and RPM of the drill bit. By "dynamic" measurements, it is meant measurement of a parameter at a specific point in time rather than measurement over a period of time. For example, over a five-second period, the measured RPM of a drill string may be one hundred RPM. In contrast, "dynamic" measurements of RPM over that same five-second interval could include five measurements taken at one second intervals (e.g., ninety RPM, one hundred ten RPM, one hundred five RPM, ninety five RPM, and one hundred RPM). Thus, dynamic measurements can provide greater details as to the behavior of a drill bit, drill string, or BHA during drilling" - ¶ 31) with a bottom hole assembly ("…BHA during drilling" - ibid), coupled to a drilling rig (fig 2), monitoring, by the system (fig 1 is a schematic computer system; ¶s 37, 40), a set of drilling operation parameters (via "sensors 14" - fig 1; a set of "drilling operation parameters" are clearly shown, including surface measurement of WOB, RPM, and ROP, and downhole parameters, including rate of penetration, torque on bit, weight on bit, RPM, vibration, and drill bit noise) wherein monitoring the set of drilling operation parameters comprises monitoring at least one of a variation in a drilling efficiency (Any and/or all of the "downhole parameters" listed under element 14 in fig 1 can reasonably be called "drilling efficiencies"; these parameters are monitored for changes: ¶ 40 & figs 3A-6E. For example, a change in "rate of penetration" is clearly and reasonably a "variation in drilling efficiency". Same for the other downhole parameters), a rate of deviation in rotary drift (the claim only requires "one or more of…" these features and therefore does not need to disclose rotary drift as currently worded), or an effective build rate of a mud motor (the claim only requires "one or more of…" these features and therefore does not need to disclose an effective build rate of a mud motor);
during drilling of the wellbore ("…during drilling" - ¶ 31), correlating, by the system (fig 1), the set of drilling operation parameters with geological formation information (via "lithology models 16… can be theoretically or empirically derived expressions that can be used to evaluate the measured data and determine whether the measured data indicates a change in formation lithology" - ¶ 32) regarding the geological formation being drilled ("…during drilling" - ¶ 31), wherein correlating the set of drilling operation parameters comprises:
obtaining, by the system, the geological formation information ("lithology models 16… can be theoretically or empirically derived expressions that can be used to evaluate the measured data and determine whether the measured data indicates a change in formation lithology" - ¶ 32);
identifying, by the system and during drilling ("…during drilling" - ¶ 31; fig 1), the variation in the drilling efficiency (Any and/or all of the "downhole parameters" listed under element 14 in fig 1 can reasonably be called "drilling efficiencies"; these parameters are monitored for changes: ¶ 40 & figs 3A-6E. For example, a change in "rate of penetration" is clearly and reasonably a "variation in drilling efficiency", and figs 3A-6E show them as being "identified" by the system. Same for the other downhole parameters), the rate of deviation in rotary drift, or the effective build rate of the mud motor (the claim only requires "one or more of…" these features and therefore does not need to disclose rotary drift or an effective build rate of a mud motor), and
comparing, by the system (fig 1), at least one of the set of drilling operation parameters to the geological formation information ("process the sensor measurements to ascertain the lithological nature of the formation… [T]he models 16 can be theoretically or empirically derived expressions that can be used to evaluate the measured data and determine whether the measured data indicates a change in formation lithology… The BHA database 18 can also include data for determining whether the processed measured data indicates a change in lithology" - ¶ 32. "[T]he processors 12 use the pre-programmed lithology indication models 16 that use measurements of one or more parameters that can be affected by the lithology of the formation being drilled… The models 16, either separately or cooperatively, process the measured data to ascertain changes in the lithological formation of the drilled formation. Measurements of such parameters react differently to different lithologies while drilling" - ¶ 40); and
determining, by the system and based at least in part on the comparison, that the one or more geological formation includes a geological feature comprising at least one of a fault zone ("The lithological indications provided by the processor can be used to adjust drilling parameters (e.g., drilling mud weight), steer to a productive formation, steer away from an fault [sic] or other undesirable region" - ¶ 12), a geological stress zone ("faults [or] high-pressure zones" - ¶ 33), or a rock type ("Change in lithology" - ¶ 32);
responsive to determining the geological feature includes at least one of the fault zone, the geological stress zone, or the rock type ("indication of formation lithology 22" - fig 1; "The processor(s) 12 outputs an indication 22 of the lithology, which can serve a number of purposes. As shown in block 24, the indication 18 can be used to optimize or adjust drilling parameters, to issue drilling alerts relating to faults, high-pressure zones, to geosteer the BHA, to correct or supplement surface seismic data, etc" - ¶ 33), modifying one or more of the set of drilling operations parameters ("Adjust drilling parameters 24" which includes WOB - fig 1. "The lithological indications provided by the processor can be used to adjust drilling parameters (e.g., drilling mud weight), steer to a productive formation, steer away from an fault or other undesirable region…" - ¶ 12; "The processor(s) 12 outputs an indication 22 of the lithology, which can serve a number of purposes. As shown in block 24, the indication 18 can be used to optimize or adjust drilling parameters, to issue drilling alerts relating to faults, high-pressure zones, to geosteer the BHA, to correct or supplement surface seismic data, etc" - ¶ 33)
While Jogi discusses using the sensor feedback and geological formation information to make geosteering decisions (abstract; ¶s 12 & 33 as cited above) which necessarily requires some idea of the current position of the bit / BHA, Jogi does not explicitly disclose determining a location of the BHA based at least in part on a drilling operation parameter of the set of drilling operation parameters and the geological formations. Further, Jogi does not explicitly disclose "modifying a rate of mud flow" responsive to the geological feature as one of the options for modifying one or more of a set of drilling operation parameters.
However Xia discloses a system for controlling drilling of a wellbore (¶ 9; claim 9) comprising determining, automatically by a processor ("the invention may be implemented on virtually any type of computer regardless of the platform used. For example, as shown in FIG. 14, a computer system 400 includes a processor 402…" - ¶ 73) and without human involvement (as previously discussed in the Final Action mailed 6/6/2025, the only human involvement taught by Xia in this process is the display on a computer monitor. As also previously discussed, the examiner does not view as failing the negative limitation of "without human involvement" because the location is "determined" by the computer before it is displayed, as a matter of logical progression. In other words, the location is not "determined" only upon being viewed by a human), a location of the BHA ("…methods that use a combination of judiciously selected 2-dimensional displays to convey to the operator the precise location of a drill bit or wellbore in a 3-dimensional sense. For example, in a particular embodiment, four different 2-dimensional views: azimuth view, plan view, inversion canvas, and curtain section display, are used to indicate the location and orientation of a drill bit (or sensor) in the formation in a 3D sense. Methods of the invention may also be used to improve an initial earth model, which may be created, for example, based on offset well measurements and static geological information" - ¶ 31; "A curtain section view and an inversion canvas can easily show the location of the drill bit… Thus, a judicious combination of these displays can inform a user about the location of the sensor (hence the drill bit) in the 3D space, the azimuthal orientation of the sensor, the distances to the nearby formation bedding boundaries, the trend of the well path, etc" - ¶ 70; "a user can quickly comprehend the information contents, e.g., the bit location, the direction of the progressing well, etc" - ¶ 76; figs 1, 4B, 8; see also ¶s 35, 43, 60) based at least in part on drilling operation parameters ("Other parameters that can provide benefit to the well operator include, but are not limited to: … weight-on-bit, torque…" - ¶ 74. "Embodiments of the invention can use various types of logging data obtained with various types of tools, which include, but are not limited to: surface sensors (such as weight-on-bit, torque, flowrate-in, flowrate-out, standpipe pressure, temperature relative to bit depth)… measurement-while-drilling (MWD) sensors (such as borehole annular pressure, downhole weight-on-bit and torque…)" - ¶ 75; claim 6) and geological features ("Other parameters that can provide benefit to the well operator include, but are not limited to: … formation density, gamma ray… formation sonic velocity, formation pressure, thermal neutron porosity, epithermal neutron porosity, and magnetic resonance bound fluid volume, free fluid volume, porosity, and T2 spectrum. Parameters are not limited to individual, direct measurements. Parameters may also be the result of computations made with one or more sensor measurements, such as fluid (water, oil, and gas) saturation, formation pressure, fracture pressure, and permeability" - ¶ 74. "…downhole LWD sensors (such as gamma ray, resistivity, density, porosity, sonic velocity…)" - ¶ 75; "formation boundaries" - title & abstract; see also ¶s 34).
Xia further teaches that toolface orientation is used in this determination ("…methods that use a combination of judiciously selected 2-dimensional displays to convey to the operator the precise location of a drill bit or wellbore in a 3-dimensional sense. For example, in a particular embodiment, four different 2-dimensional views: azimuth view, plan view, inversion canvas, and curtain section display, are used to indicate the location and orientation of a drill bit (or sensor) in the formation in a 3D sense" - ¶ 31; "A curtain section view and an inversion canvas can easily show the location of the drill bit… Thus, a judicious combination of these displays can inform a user about the location of the sensor (hence the drill bit) in the 3D space, the azimuthal orientation of the sensor, the distances to the nearby formation bedding boundaries, the trend of the well path, etc" - ¶ 70; "a user can quickly comprehend the information contents, e.g., the bit location, the direction of the progressing well, etc" - ¶ 76; figs 1, 4B, 8; see also ¶s 35, 43, 60).
Therefore it would have been obvious to one of ordinary skill in the art at the time of filing to determine the location of the BHA based at least in part on drilling operation parameters and geological formations as taught by Xia in the method taught by Jogi. "Geosteering often requires quick decisions. Therefore, it is very important that the relevant information is presented in an intuitive manner. Relevant information needed for accurate well placement may include azimuthal dependence of the directional measurements, inverted distances to bed boundaries, and an improved earth model. During a geosteering job, the geosteering engineer shall be able to assess easily from various displays the distances between the tool and the nearby bed boundaries, and the trend of the well path, i.e., whether the tool gets closer to or farther away from a bed boundary. This kind of visualization capability will allow geosteering engineers to make accurate decisions about adjusting the well path while drilling" (¶ 9).
While Jogi teaches adjusting drilling operation parameters responsive to the geological feature ("indication of formation lithology 22" - fig 1; "The processor(s) 12 outputs an indication 22 of the lithology, which can serve a number of purposes. As shown in block 24, the indication 18 can be used to optimize or adjust drilling parameters, to issue drilling alerts relating to faults, high-pressure zones, to geosteer the BHA, to correct or supplement surface seismic data, etc" - ¶ 33), including steering responsive to the geological feature (abstract; "steer away from an fault or other undesirable region" - ¶ 12), Jogi does not explicitly disclose modifying a rate of mud flow responsive to the geological feature.
However Falgout discloses an apparatus for controlling the operation of a downhole tool (title) that steers the drilling that is effected by modifying a drilling operation parameter comprising a rate of mud flow ("When it is desired to change the direction of the well bore, control valve 90 will be actuated in the manner described above by decreasing and then increasing the rate of flow of the drilling fluid…" - ¶ bridging pages 12 & 13).
Therefore it would have been obvious to PHOSITA at the time of filing to use the geosteering method taught by Falgout (modifying the rate of mud flow to actuate downhole elements to effect directional drilling change - ¶ bridging pages 12 & 13) to effect the steering change already taught by Jogi. Jogi expressly teaches "steer[ing] away from an fault or other undesirable region" (¶ 12) but does not disclose details on how to effect that change on a mechanical level, thus forcing the reader to look elsewhere for a more detailed disclosure. Falgout teaches that the adjustment of the rate of drilling mud can be used to actuate downhole elements to effect directional drilling changes. Jogi teaches doing this responsive to identifying a geological feature, as discussed above.
Claim 32. The system of claim 1, wherein correlating the set of drilling operation parameters with the geological formation information (Jogi: via "lithology models 16… can be theoretically or empirically derived expressions that can be used to evaluate the measured data and determine whether the measured data indicates a change in formation lithology" - ¶ 32) is carried out at a first time (inherent) and generates a first determination of a first set of geological formations ("…determine whether the measured data indicates a change in formation lithology" - ¶ 32), and wherein the operations further comprise:
correlating, at a second time (the method is performed continuously: "The processor(s) 12 continuously or periodically processes surface data and downhole data, including dynamic measurements, to determine whether the formation being drilled by the drill bit 56 has a lithological make-up different from the formation already drilled " - ¶ 72; figs 3A-6C; "…being drilled" - abstract; "…BHA during drilling" - ¶ 31; continuous computer implementation), the set of drilling operation parameters with the geological formation information to generate a second determination of a second set of geological formations ("The processor(s) 12 continuously or periodically processes surface data and downhole data, including dynamic measurements, to determine whether the formation being drilled by the drill bit 56 has a lithological make-up different from the formation already drilled " - ¶ 72);
generating a mapping of drilling efficiencies (fig 3E shows a "map" of "rate of penetration - ¶ 58; figs 4A-4C show "maps" axial acceleration and strain - ¶ 59; figs 5A-5C show "maps" of stick-slip, max RPM, and min RPM - ¶ 60), trajectory deviations, or hardness gradients ("or" - only one of these alternatives need be taught), based, at least in part on the first set of geological formations and the second set of geological formations (all of figs 3-5 are "based on" the measured geological formation information); and
determining a second location of the BHA based at least in part on the mapping (Xia discloses continuously determining the location of the BHA: ¶s 31, 72; figs 1, 4B, 8).
Claim 33: The system of claim 1, the operations further comprising:
determining, by the processor (Both Jogi & Xia are computer implemented. Jogi: 24, fig 1 & ¶ 12; Xia: ¶s 9 & 29), a vertical position of the geological feature (Jogi: "provide depth locations for bed boundaries and formation interfaces" - abstract. "The lithological indications provided by the processor… provide precise depth locations for bed boundaries and formation interfaces" - ¶ 12. Figs 6A-6C & ¶ 57. Xia: fig 1 & ¶ 34; figs 10 & 12) at least in part on a trajectory of the bit (Jogi: "indication of formation lithology 22" "provide precise depth locations for bed boundaries and formation interfaces" - ¶ 12. This "indication of formation lithology" is produced by the processor 12 based off feedback from the trajectory indicated by sensors 14: fig 1. Xia: "the distances from the tool to the upper and lower bed boundaries may be displayed graphically on a master canvas, as shown in FIG. 10. In the inversion canvas shown in FIG. 10, the vertical axis is the true vertical depth and the horizontal axis is the true horizontal length" - ¶ 58. Trajectory of the bit is used to indicate formation boundaries: abstract, fig 1, & ¶ 58); and
transmitting, by the processor, the vertical position to a user device for presentation (Xia: "displaying objects representing a bed boundary along the trajectory" - abstract).
Claim 34: The system of claim 33, wherein the geological formation information further includes indication of an event associated with a transition between a first layer and a second layer of the one or more geological formations (Jogi: "provide depth locations for bed boundaries and formation interfaces" - abstract & ¶s 12 & 73; "[T]his lithological indication can be obtained relatively quickly, i.e., as the drill bit 56 enters the new lithology" - ¶ 72. Xia: title, abstract).
Claim 35: The system of claim 34, wherein the event is identified based at least in part on a difference in the set of drilling operation parameters of the first layer and the set of drilling operation parameters of the second layer (Jogi: "The models 16, either separately or cooperatively, process the measured data to ascertain changes in the lithological formation of the drilled formation. Measurements of such parameters react differently to different lithologies while drilling. Accordingly, the models 16 can utilize a variety of schemes or methodologies to quantify changes in measured values of these parameters (e.g., magnitude, slope, maxima, minima, etc.)" - ¶ 40. "It has been shown that rock strength is a function of .sigma. and the normalized torque is a function of [.sigma. over .tau.] Therefore, both these parameters are functions of lithological change. It has also been shown that changes in the bit torque to weight ratio, and drillability, can be used to classify porous, shaly or hard formations" - ¶ 41. "Changing lithologies can also cause changes in bit noise (also called SNAP) in terms of frequency and amplitude. This can further help in the process of lithological identification" - ¶ 44. "Instantaneous downhole RPM (when compared to the mean), like torque, can also show significant changes due to differences in stick-slip patterns in changing lithologies" - ¶ 45. "The processor(s) 12 continuously or periodically processes surface data and downhole data, including dynamic measurements, to determine whether the formation being drilled by the drill bit 56 has a lithological make-up different from the formation already drilled. Advantageously, this lithological indication can be obtained relatively quickly, i.e., as the drill bit 56 enters the new lithology" - ¶ 72).
Claim 36: The system of claim 35, further comprising:
modifying the at least one drilling operation parameter based at least in part on the indication of the event (Jogi: "The lithological indications provided by the processor can be used to adjust drilling parameters (e.g., drilling mud weight), steer to a productive formation, steer away from an fault or other undesirable region…" - ¶ 12; "Adjust drilling parameters 24" - fig 1; " The processor(s) 12 outputs an indication 22 of the lithology, which can serve a number of purposes. As shown in block 24, the indication 18 can be used to optimize or adjust drilling parameters, to issue drilling alerts relating to faults, high-pressure zones, to geosteer the BHA, to correct or supplement surface seismic data, etc" - ¶ 33).
Claim 12 is rejected under 35 U.S.C. 103 as being unpatentable over the combination of US 2006/0212224 (Jogi), US 2006/0074561 (Xia), & WO 88/03222 (Falgout), in further view of US 7,814,989 (Nikolakis).
Claim 12. The combination discloses all the limitations of parent claim 1, and further discloses adjusting a well plan for drilling the wellbore to improve the drilling efficiency based on the determined location of the BHA and the geological feature (Jogi: "The lithological indications provided by the processor can be used to adjust drilling parameters, steer the BHA, monitor BHA health, and provide depth locations for bed boundaries and formation interfaces" - abstract; block 24, fig 1 & ¶s 12 & 33. Xia: "This kind of visualization capability will allow geosteering engineers to make accurate decisions about adjusting the well path while drilling" - ¶ 9; ¶ 29). The combination does not disclose that this is done automatically by the computer processor and without human involvement.
However Nikolakis discloses a system and method for performing a drilling operation in an oilfield (title), that is computer implemented with a processor ("processor 418" - fig 5 & col 6:22-39. "The controller (414) may be provided with an actuation mechanism that can perform drilling operations, such as steering, advancing, or otherwise taking action at the wellsite. Commands may be generated based on logic of the processor (418), or by commands received from other sources. The processor (418) is preferably provided with features for manipulating and analyzing the data. The processor (418) may be provided with additional functionality to perform oilfield operations." - second full ¶ of col 11), that adjusts, automatically and without human involvement (col 6:19 and col 6:35-36; sentence bridging cols 16 & 17), the well plan for drilling the wellbore ("A processor may be provided to analyze the data (locally or remotely) and make the decisions to actuate the controller. In this manner, the oilfield may be selectively adjusted based on the data collected. These adjustments may be made automatically based on computer protocol, or manually by an operator. In some cases, well plans and/or well placement may be adjusted to select optimum operating conditions, or to avoid problems." - col 6:30-39) in response to measured data (ibid).
Therefore it would have been obvious to one having ordinary skill in the art at the time of filing to automate the corrections of the combination as taught by Nikolakis. First, Nikolakis teaches that both automatic adjustments and manual adjustments may be performed (ibid), thus showing them to be known variations of each other. Second, using a computer to implement a previously manual process is precedentially established as having a high level of obviousness (MPEP 2144.04, subsection III - "Automating a manual activity" - and In re Venner, 262 F.2d 91, 95, 120 USPQ 193, 194 (CCPA 1958)). Finally, having a computer automatically adjust the plan potentially allows for quicker corrections than would be possible with a human user. The examiner also notes that this modification does not exclude manual adjustment as well, just adding automatic adjustment. Nikolakis teaches both.
Claims 13, 15, & 37-40 are rejected under 35 U.S.C. 103 as being unpatentable over US 2006/0212224 (Jogi) in view of US 2006/0074561 (Xia).
Independent claim 13: Jogi discloses a method for drilling a well (abstract) comprising:
drilling a wellbore (abstract, ¶ 31) with a BHA ("…BHA during drilling" - ¶ 31) coupled to a drilling rig ("a conventional rig 22" - fig 2 & ¶ 34);
during the drilling of the wellbore ("The sensors 14 include one or more sensors that can dynamically measure drilling parameters such as instantaneous torque, weight on bit, and RPM of the drill bit. By "dynamic" measurements, it is meant measurement of a parameter at a specific point in time rather than measurement over a period of time. For example, over a five-second period, the measured RPM of a drill string may be one hundred RPM. In contrast, "dynamic" measurements of RPM over that same five-second interval could include five measurements taken at one second intervals (e.g., ninety RPM, one hundred ten RPM, one hundred five RPM, ninety five RPM, and one hundred RPM). Thus, dynamic measurements can provide greater details as to the behavior of a drill bit, drill string, or BHA during drilling" - ¶ 31), monitoring, by a computer system ("processor (surface and/or downhole)" 12, fig 1; "The processor(s) 70 can be microprocessor that uses a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. Other equipment such as power and data buses, power supplies, and the like will be apparent to one skilled in the art." - ¶ 37; "instructions loaded into a memory module (not shown) of the processor 12" - ¶ 40; conventional computer system), a set of drilling operation parameters (via "sensors 14" - fig 1; a set of "drilling operation parameters" are clearly shown, including surface measurement of WOB, RPM, and ROP, and downhole parameters, including rate of penetration, torque on bit, weight on bit, RPM, vibration, and drill bit noise), wherein monitoring the set of drilling operation parameters comprises monitoring at least one of a variation in drilling efficiency (Any and/or all of the "downhole parameters" listed under element 14 in fig 1 can reasonably be called "drilling efficiencies"; these parameters are monitored for changes: ¶ 40 & figs 3A-6E. For example, a change in "rate of penetration" is clearly and reasonably a "variation in drilling efficiency". Same for the other downhole parameters), a rate of deviation in rotary drift (the claim only requires "one or more of…" these features and therefore does not need to disclose rotary drift as currently worded), or an effective build rate of a mud motor (ibid);
during drilling of the wellbore ("…during drilling" - ¶ 31), correlating, by the computer system (fig 1), the set of drilling operation parameters with geological formation information regarding the one or more geological formations being drilled (via "lithology models 16… can be theoretically or empirically derived expressions that can be used to evaluate the measured data and determine whether the measured data indicates a change in formation lithology" - ¶ 32), wherein correlating the set of drilling operation parameters comprises:
obtaining, by the computer system, the geological formation information ("lithology models 16… can be theoretically or empirically derived expressions that can be used to evaluate the measured data and determine whether the measured data indicates a change in formation lithology" - ¶ 32);
identifying, by the computer system and during drilling ("…during drilling" - ¶ 31), the variation in the drilling efficiency (Any and/or all of the "downhole parameters" listed under element 14 in fig 1 can reasonably be called "drilling efficiencies"; these parameters are monitored for changes: ¶ 40 & figs 3A-6E. For example, a change in "rate of penetration" is clearly and reasonably a "variation in drilling efficiency", and figs 3A-6E show them as being "identified" by the system. Same for the other downhole parameters), the rate of deviation in rotary drift, or the effective build rate of the mud motor (the claim requires "or" between these features and therefore does not need to disclose rotary drift or an effective build rate of a mud motor),
comparing, by the computer system (fig 1), at least one of the set of drilling operation parameters to the geological formation information (("process the sensor measurements to ascertain the lithological nature of the formation… [T]he models 16 can be theoretically or empirically derived expressions that can be used to evaluate the measured data and determine whether the measured data indicates a change in formation lithology… The BHA database 18 can also include data for determining whether the processed measured data indicates a change in lithology" - ¶ 32. "[T]he processors 12 use the pre-programmed lithology indication models 16 that use measurements of one or more parameters that can be affected by the lithology of the formation being drilled… The models 16, either separately or cooperatively, process the measured data to ascertain changes in the lithological formation of the drilled formation. Measurements of such parameters react differently to different lithologies while drilling" - ¶ 40); and
determining, by the computer system and based at least in part on the comparison, that the one or more geological formations includes a geological feature comprising at least one of a fault zone ("The lithological indications provided by the processor can be used to adjust drilling parameters (e.g., drilling mud weight), steer to a productive formation, steer away from an fault [sic] or other undesirable region" - ¶ 12), a geological stress zone ("faults [or] high-pressure zones" - ¶ 33), or a rock type ("Change in lithology" - ¶ 32);
responsive to determining the geological feature including at least one of the fault zone, the geological stress zone, or the rock type ("indication of formation lithology 22" - fig 1; "The processor(s) 12 outputs an indication 22 of the lithology, which can serve a number of purposes. As shown in block 24, the indication 18 can be used to optimize or adjust drilling parameters, to issue drilling alerts relating to faults, high-pressure zones, to geosteer the BHA, to correct or supplement surface seismic data, etc" - ¶ 33), modifying at least one of the set of drilling operation parameters ("Adjust drilling parameters 24" which includes WOB and ROP - fig 1, which is directly after step 22 in fig 1. "The lithological indications provided by the processor can be used to adjust drilling parameters (e.g., drilling mud weight), steer to a productive formation, steer away from an fault or other undesirable region…" - ¶ 12; "The processor(s) 12 outputs an indication 22 of the lithology, which can serve a number of purposes. As shown in block 24, the indication 18 can be used to optimize or adjust drilling parameters, to issue drilling alerts relating to faults, high-pressure zones, to geosteer the BHA, to correct or supplement surface seismic data, etc" - ¶ 33), wherein the at least one of the set of drilling operation parameters comprises mechanical specific energy (as supported by the two NPL glossary definitions for "mechanical specific energy", changing WOB and/or ROP is changing mechanical specific energy).
While Jogi discusses using the sensor feedback and geological formation information to make geosteering decisions (abstract; ¶s 12 & 33 as cited above) which necessarily requires some idea of the current position of the bit / BHA, Jogi does not explicitly disclose determining a location of the BHA based at least in part on a drilling operation parameter of the set of drilling operation parameters and the geological formations.
However Xia discloses a method for drilling a well (¶ 9; claim 9) comprising determining, by a computer system ("the invention may be implemented on virtually any type of computer regardless of the platform used. For example, as shown in FIG. 14, a computer system 400 includes a processor 402…" - ¶ 73), a location of the BHA ("…methods that use a combination of judiciously selected 2-dimensional displays to convey to the operator the precise location of a drill bit or wellbore in a 3-dimensional sense. For example, in a particular embodiment, four different 2-dimensional views: azimuth view, plan view, inversion canvas, and curtain section display, are used to indicate the location and orientation of a drill bit (or sensor) in the formation in a 3D sense. Methods of the invention may also be used to improve an initial earth model, which may be created, for example, based on offset well measurements and static geological information" - ¶ 31; "A curtain section view and an inversion canvas can easily show the location of the drill bit… Thus, a judicious combination of these displays can inform a user about the location of the sensor (hence the drill bit) in the 3D space, the azimuthal orientation of the sensor, the distances to the nearby formation bedding boundaries, the trend of the well path, etc" - ¶ 70; "a user can quickly comprehend the information contents, e.g., the bit location, the direction of the progressing well, etc" - ¶ 76; figs 1, 4B, 8; see also ¶s 35, 43, 60) based at least in part on drilling operation parameters ("Other parameters that can provide benefit to the well operator include, but are not limited to: … weight-on-bit, torque…" - ¶ 74 - both of which are factors in MSE as discussed above. "Embodiments of the invention can use various types of logging data obtained with various types of tools, which include, but are not limited to: surface sensors (such as weight-on-bit, torque, flowrate-in, flowrate-out, standpipe pressure, temperature relative to bit depth)… measurement-while-drilling (MWD) sensors (such as borehole annular pressure, downhole weight-on-bit and torque…)" - ¶ 75; claim 6) and geological features ("Other parameters that can provide benefit to the well operator include, but are not limited to: … formation density, gamma ray… formation sonic velocity, formation pressure, thermal neutron porosity, epithermal neutron porosity, and magnetic resonance bound fluid volume, free fluid volume, porosity, and T2 spectrum. Parameters are not limited to individual, direct measurements. Parameters may also be the result of computations made with one or more sensor measurements, such as fluid (water, oil, and gas) saturation, formation pressure, fracture pressure, and permeability" - ¶ 74. "…downhole LWD sensors (such as gamma ray, resistivity, density, porosity, sonic velocity…)" - ¶ 75; "formation boundaries" - title & abstract; see also ¶s 34); and
transmitting, by the computer system, the determined location to a user device for presentation (abstract, ¶s 9, 76, claim 1).
Therefore it would have been obvious to one of ordinary skill in the art at the time of filing to determine the location of the BHA based at least in part on drilling operation parameters and geological formations as taught by Xia in the method taught by Jogi. "Geosteering often requires quick decisions. Therefore, it is very important that the relevant information is presented in an intuitive manner. Relevant information needed for accurate well placement may include azimuthal dependence of the directional measurements, inverted distances to bed boundaries, and an improved earth model. During a geosteering job, the geosteering engineer shall be able to assess easily from various displays the distances between the tool and the nearby bed boundaries, and the trend of the well path, i.e., whether the tool gets closer to or farther away from a bed boundary. This kind of visualization capability will allow geosteering engineers to make accurate decisions about adjusting the well path while drilling" (¶ 9).
Claim 15. The method of claim 13, further comprising: adjusting, by the computer system (discussed at the end of the claim), an orientation of the BHA (Jogi: "steer away from an fault or other undesirable region" - ¶ 12. Xia: "This kind of visualization capability will allow geosteering engineers to make accurate decisions about adjusting the well path while drilling" - ¶ 9; ¶ 29) based on the geological feature (Jogi: "The lithological indications provided by the processor can be used to adjust drilling parameters, steer the BHA, monitor BHA health, and provide depth locations for bed boundaries and formation interfaces" - abstract; block 24, fig 1 & ¶s 12 & 33. Xia: "This kind of visualization capability will allow geosteering engineers to make accurate decisions about adjusting the well path while drilling" - ¶ 9; ¶ 29).
Both Jogi and Xia teach "adjusting an orientation of the BHA" by the computer system (Jogi: 24, fig 1 & ¶ 12; Xia: ¶s 9 & 29. Even if a user is entering the changes as taught by Xia in ¶s 9 & 29, the change is still computer implemented: Jogi - "The processor(s) 70 can be microprocessor that uses a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. Other equipment such as power and data buses, power supplies, and the like will be apparent to one skilled in the art." - ¶ 37; "instructions loaded into a memory module (not shown) of the processor 12" - ¶ 40. Xia - "the invention may be implemented on virtually any type of computer regardless of the platform used. For example, as shown in FIG. 14, a computer system 400 includes a processor 402…" - ¶ 73. In other words, the user isn't rotating the BHA by hand. They are using a computer control system at the surface to change the orientation via the computer. "Adjusting by-wire" so to speak. The examiner notes that claim 15 does not exclude human interaction, but even then, automating a previously manual activity is precedentially held as having a high level of obviousness. MPEP 2144.04, subsection III).
Claim 37: The method of claim 13, the operations further comprising:
determining, by the processor (Both Jogi & Xia are computer implemented. Jogi: 24, fig 1 & ¶ 12; Xia: ¶s 9 & 29), a vertical position of the geological feature (Jogi: "provide depth locations for bed boundaries and formation interfaces" - abstract. "The lithological indications provided by the processor… provide precise depth locations for bed boundaries and formation interfaces" - ¶ 12. Figs 6A-6C & ¶ 57. Xia: fig 1 & ¶ 34; figs 10 & 12) at least in part on a trajectory of the bit (Jogi: "indication of formation lithology 22" "provide precise depth locations for bed boundaries and formation interfaces" - ¶ 12. This "indication of formation lithology" is produced by the processor 12 based off feedback from the trajectory indicated by sensors 14: fig 1. Xia: "the distances from the tool to the upper and lower bed boundaries may be displayed graphically on a master canvas, as shown in FIG. 10. In the inversion canvas shown in FIG. 10, the vertical axis is the true vertical depth and the horizontal axis is the true horizontal length" - ¶ 58. Trajectory of the bit is used to indicate formation boundaries: abstract, fig 1, & ¶ 58); and
transmitting, by the processor, the vertical position to a user device for presentation (Xia: "displaying objects representing a bed boundary along the trajectory" - abstract).
Claim 38: The method of claim 37, wherein the geological formation information further includes indication of an event associated with a transition between a first layer and a second layer of the one or more geological formations (Jogi: "provide depth locations for bed boundaries and formation interfaces" - abstract & ¶s 12 & 73; "[T]his lithological indication can be obtained relatively quickly, i.e., as the drill bit 56 enters the new lithology" - ¶ 72. Xia: title, abstract).
Claim 39: The method of claim 38, wherein the event is identified based at least in part on a difference in the set of drilling operation parameters of the first layer and the set of drilling operation parameters of the second layer (Jogi: "The models 16, either separately or cooperatively, process the measured data to ascertain changes in the lithological formation of the drilled formation. Measurements of such parameters react differently to different lithologies while drilling. Accordingly, the models 16 can utilize a variety of schemes or methodologies to quantify changes in measured values of these parameters (e.g., magnitude, slope, maxima, minima, etc.)" - ¶ 40. "It has been shown that rock strength is a function of .sigma. and the normalized torque is a function of [.sigma. over .tau.] Therefore, both these parameters are functions of lithological change. It has also been shown that changes in the bit torque to weight ratio, and drillability, can be used to classify porous, shaly or hard formations" - ¶ 41. "Changing lithologies can also cause changes in bit noise (also called SNAP) in terms of frequency and amplitude. This can further help in the process of lithological identification" - ¶ 44. "Instantaneous downhole RPM (when compared to the mean), like torque, can also show significant changes due to differences in stick-slip patterns in changing lithologies" - ¶ 45. "The processor(s) 12 continuously or periodically processes surface data and downhole data, including dynamic measurements, to determine whether the formation being drilled by the drill bit 56 has a lithological make-up different from the formation already drilled. Advantageously, this lithological indication can be obtained relatively quickly, i.e., as the drill bit 56 enters the new lithology" - ¶ 72).
Claim 40: The method of claim 13, further comprising:
determining, by the computer system (Both Jogi & Xia are computer implemented. Jogi: 24, fig 1 & ¶ 12; Xia: ¶s 9 & 29), a vertical position of the geological formations (Jogi: "provide depth locations for bed boundaries and formation interfaces" - abstract. "The lithological indications provided by the processor… provide precise depth locations for bed boundaries and formation interfaces" - ¶ 12. Figs 6A-6C & ¶ 57. Xia: fig 1 & ¶ 34; figs 10 & 12) based at least in part on a trajectory of the bit (Jogi: "indication of formation lithology 22" "provide precise depth locations for bed boundaries and formation interfaces" - ¶ 12. This "indication of formation lithology" is produced by the processor 12 based off feedback from the trajectory indicated by sensors 14: fig 1. Xia: "the distances from the tool to the upper and lower bed boundaries may be displayed graphically on a master canvas, as shown in FIG. 10. In the inversion canvas shown in FIG. 10, the vertical axis is the true vertical depth and the horizontal axis is the true horizontal length" - ¶ 58. Trajectory of the bit is used to indicate formation boundaries: abstract, fig 1, & ¶ 58); and
transmitting, by the computer system (Both Jogi & Xia are computer implemented. Jogi: 24, fig 1 & ¶ 12; Xia: ¶s 9 & 29), the vertical position to the user device for presentation (Xia: "displaying objects representing a bed boundary along the trajectory" - abstract).
Allowable Subject Matter
Claims 27, 30, 41-44 are allowed.
Reasons for indicating allowable matter: The amendments to claim 27 filed 12/2/2025 require "determining the geological stress zone or the fault zone is based at least in part on
"The geological drift estimator 1112 receives external input representing geological information and provides outputs to the geo modified well planner 1104, slide planner 1114, and tactical solution planner 1118. During drilling, drift may occur as the particular characteristics of the formation affect the drilling direction. More specifically, there may be a trajectory bias that is contributed by the formation as a function of drilling rate and BHA. The geological drift estimator 1112 is configured to provide a drift estimate as a vector. This vector can then be used to calculate drift compensation parameters that can be used to offset the drift in a control solution."
However this is not commensurate with using this drift information to "determine a geological stress zone or fault zone" as recited in claim 27.
Conclusion
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.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to Blake Michener whose telephone number is (571)270-5736. The examiner can normally be reached Approximately 9:00am to 6:00pm CT.
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/BLAKE MICHENER/
Primary Examiner, Art Unit 3676