CTNF 18/631,971 CTNF 82150 DETAILED ACTION A. This action is in response to the following communications: Transmittal of New Application filed 04/10/2024. B. Claims 1-19 remains pending. Claim Rejections - 35 USC § 102 07-06 AIA 15-10-15 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. 07-07-aia AIA 07-07 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 – 07-08-aia AIA (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. 07-15-aia AIA Claim(s) 1-19 is/are rejected under 35 U.S.C. 102 (a)(1) as being anticipated by Thigpen, Brian L. et al. (US Pub. 2008/0262736 A1), herein referred to as “Thigpen” . As for claims 1 and 12 , Thigpen teaches. A method for producing fluid from a well using an electric submersible pump, a processor (par. 8 processor hardware), the method comprising: performing a portable separator rate test in the well to obtain an operating point for the electric submersible pump in the well (par. 7 an electrical submersible pump in a well that is producing fluids, wherein the method may include: determining an operating envelope for the electrical submersible pump that includes a maximum or optimal flow rate for the electrical submersible pump corresponding to the frequency and head over the electrical submersible pump; measuring an operating parameter of the electrical submersible using a sensor in the well; and altering an operation of the electrical submersible pump and/or another downhole device so as to operate the electrical submersible pump within the operating envelope or proximate the maximum flow rate.); receiving a performance curve for the electric submersible pump (par. 32 The system 200, in one aspect, may be configured to operate the ESP within an operating envelope 370 or substantially close to the maximum flow curve 350 shown in FIG. 3. FIG. 3 shows a plot 300 of the relationship of the flow rate or throughput (in barrels per day or “BPD”) and the head (in foot) corresponding to various frequencies (speeds) of an exemplary ESP installed in a well, such as well 50); adjusting the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well (par. 28 downhole sensor measurement data consists of a plurality of measurements, including gravity and viscosity of fluid; par. 29 the programs/models/algorithms 232 may be in the form of a well performance analyzer (WPA) that is used by the processor 152 to analyze some or all of the measurement data 222, 226, test data 224, information in the database 230 and any other desired information made available to the processor to estimate or predict one or more parameters of the well operation; par. 32 the system, as described in more detail later, attempts to operate the ESP in the envelope 370 and may attempt to operate substantially close to line 380); calculating a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test (par. 30 give multiple scenarios of tracked parameters from readings of a head on downhole sensor to make predictions and fix problems before they arise and also offer solutions that the system fails to predict; Therefore in many situations, a change in one or more parameters may necessitate taking one or more actions to mitigate the potential effects of such change. Also, it is desirable to predict or estimate when and the extent of changes and take actions to reduce or eliminate the detrimental affects of such a potential change, which will result in enhanced production of hydrocarbons from the well.); updating a model of the electric submersible pump by incorporating the calculated head correction (par. 29 and 34 programs/models and algorithms are used by the well performance analyzer (WPA) to analysis some or all of measurement data; par. 43 suggests forward looking models which are updated with new information from measurement data) ; and executing the model of the electric submersible pump to predict flow rates from the well at surface conditions (par. 34-35 utilizing model for predictions for measurement data including flow rates). As for claim 2 , Thigpen teaches. The method of claim 1, further comprising controlling the electric submersible pump based on the predicted flow rates (par 29 make predictions based upon measurement data; wherein measurement data consists of flow rates). As for claims 3 and 13 , Thigpen teaches. The method of claim 1, wherein receiving the performance curve for the electric submersible pump comprising receiving a nominal performance curve for the electric submersible pump (par. 32 Curve 380 correspond to the best or optimal operation of the ESP, which may be determined using any desired method or may be set arbitrarily based on the know behavior of the ESPs. In one aspect, the system, as described in more detail later, attempts to operate the ESP in the envelope 370 and may attempt to operate substantially close to line 380) . As for claims 4 and 14 , Thigpen teaches. The method of claim 1, wherein receiving the performance curve for the electric submersible pump comprising receiving a performance curve for the electric submersible pump updated from a nominal performance curve for the electric submersible pump (par. 32 updating the curve value which is displayed on a user interface). As for claims 5 and 15 , Thigpen teaches. The method of claim 1, wherein calculating a head correction comprises calculating a ratio between the retrieved pump curve and shifted pump curve (par. 32 FIG. 3 shows a plot 300 of the relationship of the flow rate or throughput (in barrels per day or “BPD”) and the head (in foot) corresponding to various frequencies (speeds) of an exemplary ESP installed in a well, such as well 50. The flow rate is shown along the horizontal axis, while the head is shown along the vertical axis. Each solid curve is a plot of the flow rate versus head corresponding to a particular operating frequency of the ESP. As for claims 6 and 16 , Thigpen teaches. The method of claim 5, wherein calculating the ratio between the retrieved pump curve and shifted pump curve comprises calculating the ratio graphically (par. 26 user interface for determining the desired actions and for monitoring the effects of taking the actions so as to recover the hydrocarbons at an enhanced or optimized rate from the well 50). As for claims 7 and 17 , Thigpen teaches. The method of claim 1, further comprising receiving operational data from the electric submersible pump (par. 26 various information is derived from pump sensors). As for claims 8 and 18 , Thigpen teaches. The method of claim 7, further comprising receiving pressure, temperature, and fluid properties from downhole sensors (par. 26 various information is derived from pump sensors). As for claims 9 and 19 , Thigpen teaches. The method of claim 8, further comprising sending control signals sent to the electric submersible pump (par. 26 operational commands can be sent to pump). As for claim 10 , Thigpen teaches. The method of claim 1, further comprising modeling current electric submersible pump production rates (par. 26; fig. 3 charting on user interface model). As for claim 11 , Thigpen teaches. The method of claim 1, wherein executing the model of the electric submersible pump comprises estimating water cut and fluid specific gravity (par. 22 and 28 estimating water cut information from sensor data). (Note :) It is noted that any citation to specific, pages, columns, lines, or figures in the prior art references and any interpretation of the references should not be considered to be limiting in any way. A reference is relevant for all it contains and may be relied upon for all that it would have reasonably suggested to one having ordinary skill in the art. In re Heck, 699 F.2d 1331, 1332-33, 216 USPQ 1038, 1039 (Fed. Cir. 1983) (quoting In re Lemelson, 397 F.2d 1006,1009, 158 USPQ 275, 277 (CCPA 1968)) . Conclusion 07-96 AIA The prior art made of record and not relied upon is considered pertinent to applicant's disclosure. MULTIPHASE FLOW INSTABILITY CONTROL Document ID US 20230408043 A1 Date Published 2023-12-21 Abstract A method can include detecting instability of multiphase fluid flow in a multiphase fluid production system using sensor measurements from the multiphase fluid production system; and, responsive to the detection of instability, increasing gas injection into the multiphase fluid production system until a variation metric of the sensor measurements decreases to a level indicative of stable multiphase fluid flow in the multiphase fluid production system. OPTIMIZING THE PERFORMANCE OF ELECTRICAL SUBMERSIBLE PUMPS (ESP) IN REAL TIME Document ID US 20230313807 A1 Date Published 2023-10-05 Abstract A system and method for controlling an electrical submersible pump (ESP) of a well, including a processor and a non-transitory computer-readable medium storing instructions that when executed by the processor cause the processor to perform operations. The operations include obtaining a well model corresponding to the well, obtaining a target well rate for the well, then receiving, from one or more data sources associated with one or more components of the well, operational data associated with the ESP operating at the target well rate within the well, determining a target efficiency of the ESP at the target well rate based on the well model, and then modifying, based on the operational data and the target efficiency an operating characteristic of the ESP. Inquires 07-100 AIA Any inquiry concerning this communication should be directed to NICHOLAS AUGUSTINE at telephone number (571)270-1056 . Examiner interviews are available via telephone, in-person, and video conferencing using a USPTO supplied web-based collaboration tool. To schedule an interview, applicant is encouraged to use the USPTO Automated Interview Request (AIR) at http://www.uspto.gov/interviewpractice. PNG media_image1.png 213 559 media_image1.png Greyscale /NICHOLAS AUGUSTINE/Primary Examiner, Art Unit 2178 April 2, 2026 Application/Control Number: 18/631,971 Page 2 Art Unit: 2178 Application/Control Number: 18/631,971 Page 3 Art Unit: 2178 Application/Control Number: 18/631,971 Page 4 Art Unit: 2178 Application/Control Number: 18/631,971 Page 5 Art Unit: 2178 Application/Control Number: 18/631,971 Page 6 Art Unit: 2178 Application/Control Number: 18/631,971 Page 7 Art Unit: 2178 Application/Control Number: 18/631,971 Page 8 Art Unit: 2178
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