DETAILED ACTION
A. This action is in response to the following communications: Amendment filed: 08/03/2026. This action is made Final.
B. Claims 1-19 remain pending.
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.
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)).
Response to Arguments
Applicant's arguments filed 08/03/2026 have been fully considered but they are not persuasive.
A1. Applicant argues that Thigpen does not teach “adjusting the performance curve for the electric submersible pump based on specific gravity and viscosity of fluid being produced from the well; calculating a head correction necessary to shift the adjusted performance curve to pass through the operating point obtained from the portable separator rate test; updating a model of the electric submersible pump by incorporating the calculated head correction.”
R1. Examiner does not agree, Thigpen specifically teaches in paragraphs 28-34 of a user interface that is able to adjust, calculate and update. Thigpen is concerned with a novel system and method for monitoring physical condition of production well equipment and controlling well production. Thigpen achieves this by similar means outlined by current claim limitations. Turning to paragraph 28 the processor 152 of system 200 may periodically or continually access the downhole sensor measurement data 222, surface measurement data 226 and any other desired information or measurements 228 and downhole sensor measurement data consists of a plurality of measurements, including but are not limited to: information relating to water content or water cut; resistivity; density; viscosity; sand content; flow rates; pressure; temperature; chemical characteristics or compositions of fluids, including the presence, amount and location of corrosion, scale, paraffin, hydrate and asphaltene; gravity; inclination; electrical and electromagnetic measurements; oil/gas and oil/water ratios; and choke and valve positions. In paragraph 29 the system includes programs, models and algorithms embedded in computer readable media that when accessed by processor execute instructions continued in programs wherein the processor may utilize one or more programs, models and algorithms to perform various functions and methods described herein. One of the programs can be in form of a well performance analyzer (WPA) that is used by processor to analyze some or all measurements described in paragraph 28, including gravity and viscosity of fluid. The processor will be able to estimate/predict one or more parameters of the well operation. The system 200 using the WPA 260 may be configured to provide a closed-loop system for monitoring the health of the equipment and providing solutions that will tend to enhance, optimize or maximize production from the well. Paragraph 34 details various performance curve adjustments. Without other functional limitations that details the performance curve and its adjustments; the broadest reasonable interpretation is given “universal way to visualize how any system behaves as conditions change”. Thus paragraphs 34 displays to the user various changing conditions during operations of the ESP and suggests changing parameters based upon models and algorithm to make impactful predictions for prolong operation. The specification suggests that a performance curve adjustment is to aid in the life of the ESP. Paragraph 35 of Thigpen states the same “In one aspect, WPA may utilize models, algorithms that use multiple input parameters and provide a set of actions, which actions when executed will provide extended life of the ESP and enhanced production form the well.”.
In overview paragraph 29 teaches 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.
In paragraph 30 discusses 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. In paragraph 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.
Lastly in paragraphs 34 and 29 programs/models and algorithms are used by the well performance analyzer (WPA) to analysis some or all of measurement data and paragraph 43 suggests forward looking models which are updated with new information from measurement data.
Thigpen currently describes the current limitations as outlined above, but amendments could be made that would overcome Thigpen, such as the specifics of figure 6 that discusses the user interface in a novel way over the prior art and thereby Examiner recommends a clarifying amendment, one that clarifies how the performance curve is adjusted, how calculating is performed and the visual difference with updating a model on the user interface; these are just a few examples of possible ways to clarify over the prior arts.
Conclusion
THIS ACTION IS MADE FINAL. 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.
Inquires
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.
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/NICHOLAS AUGUSTINE/Primary Examiner, Art Unit 2178 September 29, 2026
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