DETAILED ACTION
This office action is in response to application filed on July 7, 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 .
Priority
Applicant’s claim for the benefit of a prior-filed application under 35 U.S.C. 119(e) or under 35 U.S.C. 120, 121, 365(c), or 386(c) is acknowledged.
Information Disclosure Statement
The information disclosure statement (IDS) submitted on 07/07/2023 is in compliance with the provisions of 37 CFR 1.97. Accordingly, the information disclosure statement is being considered by the examiner.
Specification
The disclosure is objected to because it includes multiple informalities. The examiner has made an effort suggesting language to correct some informalities found in the disclosure. Applicant’s cooperation is kindly requested.
[0041]: Language “The term “subsurface model” as used herein refer to …” should read “The term “subsurface model” as used herein refers to …” in order to correct for minor informalities.
[0042]: Language “The term “geological model” as used herein refer to …” should read “The term “geological model” as used herein refers to …” in order to correct for minor informalities.
[0043]: Language “The term “reservoir model” as used herein refer to …” should read “The term “reservoir model” as used herein refers to …” in order to correct for minor informalities.
[0064]: Language “Further, in one or some embodiments, the interwell connectivity model, which may be indicative of the impact of injecting gas on the pressure system on one or more aspects of hydrocarbon extraction, may include use different physics equations …” should read “Further, in one or some embodiments, the interwell connectivity model, which may be indicative of the impact of injecting gas on the pressure system on one or more aspects of hydrocarbon extraction, may
[0073]: Language “… by way of numerical example, the well survey may indicate that the well is vertical at a given co-ordinate on the map (x, y) indicate from z = 0 to z = 8000 ft …” should read “… by way of numerical example, the well survey may indicate that the well is vertical at a given co-ordinate on the map (x, y) indicated from z = 0 to z = 8000 ft …” in order to correct for minor informalities.
[0083]: Language “Thus, in one or some embodiments, the methodology may determine the compression necessary to overwhelm well-to-well communication as a function of any one, any combination, or all of: pressure; fluid properties; or one or more aspects of the wells (e.g., layout or geometry) of the wells)” should read “Thus, in one or some embodiments, the methodology may determine the compression necessary to overwhelm well-to-well communication as a function of any one, any combination, or all of: pressure; fluid properties; or one or more aspects of the wells (e.g., layout or geometry[[)]] of the wells)” in order to correct for minor informalities (i.e., remove extra parenthesis).
[0084]: Language “In particular, the optimization algorithm analyzes the split of injected fluids in order to a maximum pressure needed in the one or more injector wells” should read “In particular, the optimization algorithm analyzes the split of injected fluids in order to determine a maximum pressure needed in the one or more injector wells” in order to correct for minor informalities.
[0087]: Language “FIG. 1B is a top view 150 of twelve horizontal hydraulically fractured wells in an interval 152 showing fluid transport from the injection wells, including, for example, well #16 for 30 days followed by well #14 for 30 days, to its neighboring wells based on stress orientation within the subsurface” should read “FIG. 1B is a top view 150 of twelve horizontal hydraulically fractured wells in an interval 152 showing fluid transport from the injection wells, including, for example, well #16 for 30 days followed by well #14 for 30 days, to [[its]]their neighboring wells based on stress orientation within the subsurface” in order to correct for minor informalities.
[0097]: Language “… with V1, V2, and V3 comprising control volumes represent parameters whose values that may be estimated based on primary depletion” should read “… with V1, V2, and V3 comprising control volumes represent parameters whose values may be estimated based on primary depletion” in order to correct for minor informalities.
[0102]: Language “Further, injecting into well #14 results in part of the injected fluid transports towards neighboring wells (well #13 as illustrated by arrow 166, well #15 as illustrated by arrow 168, well #2 as illustrated by arrow 170), and subsequently to nearby wells” should read “Further, injecting into well #14 results in part of the injected fluid transports towards neighboring wells (well #13 as illustrated by arrow 166, well #15 as illustrated by arrow 168, well #[[2]]3 as illustrated by arrow 170), and subsequently to nearby wells” in accordance with the details of Fig. 1B.
[0108]: Language “For example, the values for the input parameters may be varied in a systematic manner in to identify an improved or a “best solution,” based on the pre-defined objectives or metrics” should read “For example, the values for the input parameters may be varied in a systematic manner in order to identify an improved or a “best solution,” based on the pre-defined objectives or metrics” in order to correct for minor informalities.
[0109]: Language “In contrast, one or more wells (such as combinations of wells) further away from the corners of the boundary as identified at 152 (e.g., wells# 3, 4, 15, and 16) may be examined to determine the combinations of the wells, the rate of injection, and the duration of injection will yield the best results. As discussed above, the analysis for various aspects, including BHP (see FIGS. 3A-B), fluid leaking out of the area of interest (FIG. 4), and oil uplift (see FIGS. 5A-B)” should read “In contrast, one or more wells (such as combinations of wells) further away from the corners of the boundary as identified at 152 (e.g., wells# 3, 4, 15, and 16) may be examined to determine the combinations of the wells, the rate of injection, and the duration of injection that will yield the best results. As discussed above, the analysis is performed for various aspects, including BHP (see FIGS. 3A-B), fluid leaking out of the area of interest (FIG. 4), and oil uplift (see FIGS. 5A-B)” in order to correct for minor informalities.
[0110]: Paragraph should end with a period.
[0123]: Language “In this way, another variable in terms designing operations (e.g., controlling and selecting operations) may comprise whether to build-up or to draw down” should read “In this way, another variable in terms of designing operations (e.g., controlling and selecting operations) may comprise whether to build-up or to draw down” in order to correct for minor informalities.
[0159]: Language “… the models may consider may consider one or more time lags …” should read “… the models may consider
[0165]: Language “With regard to (2), the time shift needed to determine an improved/optimal timing for gas lift may be reflected in an expanded system models beyond Equations (4)-(10)” should read “With regard to (2), the time shift needed to determine an improved/optimal timing for gas lift may be reflected in an expanded system model beyond Equations (4)-(10)” in order to correct for minor informalities.
[0193]: Language “… the models may consider may consider one or more time lags …” should read “… the models may consider
[0210]: Language “Thus, the system model may comprise one or more models, which integrate the interwell connectivity model with the model of the one or aspects of the system …” should read “Thus, the system model may comprise one or more models, which integrate the interwell connectivity model with the model of the one or more aspects of the system …” in order to correct for minor informalities.
Appropriate correction is required.
Claim Objections
Claim 1 is objected to because of the following informalities:
Claim language “using the one or more aspects of one or both of control or configuration of the plurality of wells for hydrocarbon management of a reservoir” should read “using the one or more aspects of the one or both of the control or the configuration of the plurality of wells for hydrocarbon management of a reservoir” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 2 is objected to because of the following informalities:
Claim language should read “The method of claim 1, wherein determining the one or more aspects of the one or both of the control or the configuration of the plurality of wells comprises determining one or more aspects associated with one or both of a drilling phase or a construction phase of the hydrocarbon management” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 3 is objected to because of the following informalities:
Claim language should read “The method of claim 2, wherein the one or more aspects associated with the one or both of the drilling phase or the construction phase of the hydrocarbon management comprise one or more of: a number of the plurality of wells; a placement of the plurality of wells; fracturing associated with the plurality of wells; or at least one of a compressor for pumping plurality of wells or piping to the plurality of wells” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 4 is objected to because of the following informalities:
Claim language should read “The method of claim 1, wherein determining the one or more aspects of the one or both of the control or the configuration of the plurality of wells comprises determining one or more aspects associated with a primary depletion phase of the hydrocarbon management” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 5 is objected to because of the following informalities:
Claim language should read “The method of claim 4, wherein determining the one or more aspects associated with the primary depletion phase of the hydrocarbon management comprises determining a time when to end primary depletion” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 6 is objected to because of the following informalities:
Claim language should read “The method of claim 1, wherein determining the one or more aspects of the one or both of the control or the configuration of the plurality of wells comprises determining, based on the interwell connectivity model, one or both of whether or when to begin injecting gas into at least one of the plurality of wells” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 8 is objected to because of the following informalities:
Claim language should read “The method of claim 7, wherein the plurality of wells comprises one or more injector wells into which the gas is injected into the tubing; and wherein the interwell connectivity model in combination with the optimization model determine whether to inject the gas into the tubing by analyzing a time delay of an effect of injecting the gas into the one or more injector wells on one or more offset wells” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 10 is objected to because of the following informalities:
Claim language “The method of claim 7, wherein the plurality of wells comprises one or more injector wells into which gas is injected into the tubing and one or more offset wells in which gas is not injected into the tubing” should read “The method of claim 7, wherein the plurality of wells comprises one or more injector wells into which the gas is injected into the tubing and one or more offset wells in which the gas is not injected into the tubing” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 12 is objected to because of the following informalities:
Claim language “wherein the interwell connectivity model in combination with the optimization model are used to determine when to begin injecting gas into an annulus of the one or more offset wells based on the time delay of the effect of injecting the gas into the tubing of the one or more injector wells” should read “wherein the interwell connectivity model in combination with the optimization model are used to determine when to begin injecting the gas into [[an]]the annulus of the one or more offset wells based on the time delay of the effect of injecting the gas into the tubing of the one or more injector wells” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 14 is objected to because of the following informalities:
Claim language should read “The method of claim 13, wherein the time delay is indicative of an effect of injecting gas into at least a part of a well; and wherein updating the time delay of the interwell connectivity model comprises using production data and data indicative of previous injection of the gas into [[the]] at least [[a]]the part of the well” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 15 is objected to because of the following informalities:
Claim language should read “The method of claim 14, wherein hydrocarbon is extracted using a plurality of cycles of injecting the gas into [[the]] at least [[a]]the part of the well; and wherein the interwell connectivity model is updated based on the production data and the data from a previous cycle of injecting the gas into [[the]] at least [[a]]the part of the well” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 16 is objected to because of the following informalities:
Claim language “The method of claim 13, the interwell connectivity model includes …” should read “The method of claim 13, wherein the interwell connectivity model includes …” in order to correct for minor informalities.
Appropriate correction is required.
Claim 17 is objected to because of the following informalities:
Claim language should read “The method of claim 6, wherein the interwell connectivity model in combination with an optimization model are used to determine when to begin injecting the gas or how much of the gas to inject into at least a part of the reservoir” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 18 is objected to because of the following informalities:
Claim language should read “The method of claim 17, wherein the interwell connectivity model in combination with [[an]]the optimization model are used to determine in which one or more of the plurality of wells to inject the gas into tubing of the one or more of the plurality of wells in order to disperse the gas in at least [[a]]the part of the reservoir” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 19 is objected to because of the following informalities:
Claim language should read “The method of claim 18, wherein the one or more of the plurality of wells comprise one or more injector wells; wherein one or more offset wells comprise one or more remainder wells in which the gas is not injected into the tubing of the one or more offset wells; and wherein operation of at least one aspect of the one or more offset wells is performed based on injecting the gas into the tubing of the one or more injector wells” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 20 is objected to because of the following informalities:
Claim language should read “The method of claim 19, wherein artificial lift comprises injecting the gas in an annulus; wherein huffing comprises injecting the gas in the tubing; and wherein one or more aspects of the artificial lift in the one or more offset wells is determined based on the huffing in the one or more injector wells” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 23 is objected to because of the following informalities:
Claim language should read “The method of claim 1, wherein determining the one or more aspects of the one or both of the control or the configuration of the plurality of wells comprise determining two or more cycles of: injecting one or more gases into tubing of at least one of the plurality of wells; and injecting the one or more gases into an annulus of one or more of the plurality of wells” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim Rejections - 35 USC § 101
35 U.S.C. 101 reads as follows:
Whoever invents or discovers any new and useful process, machine, manufacture, or composition of matter, or any new and useful improvement thereof, may obtain a patent therefor, subject to the conditions and requirements of this title.
Claims 1-24 are rejected under 35 U.S.C. 101 because the claimed invention is directed to a judicial exception without significantly more.
Regarding claim 1, the examiner submits that under Step 1 of the 2024 Guidance Update on Patent Subject Matter Eligibility, Including on Artificial Intelligence (see also 2019 Revised Patent Subject Matter Eligibility Guidance) for evaluating claims for eligibility under 35 U.S.C. 101, the claim is to a process, which is one of the statutory categories of invention.
Continuing with the analysis, under Step 2A - Prong One of the test:
the limitation “determining, based on the interwell connectivity model, one or more aspects of one or both of control or configuration of the plurality of wells” is a process that, under its broadest reasonable interpretation in light of the specification, covers performance of the limitation using mathematical concepts to manipulate data and obtain additional information (see specification at [0054]-[0058], [0061]-[0064], [0086], [0095]-[0097], [0099]). Except for the recitation of the extra-solution activities (e.g., source/type of data being evaluated) and/or the particular technological environment or field of use, the limitation in the context of the claim mainly refers to applying mathematical concepts to transform data.
Therefore, the claim recites a judicial exception under Step 2A - Prong One of the test.
Furthermore, under Step 2A - Prong Two of the test, this judicial exception is not integrated into a practical application when considering the claim as a whole. In particular, the additional elements recited in the claim:
“A method for hydrocarbon extraction” generally links the use of the judicial exception to a particular technological environment or field of use (see MPEP 2106.05(h));
“accessing an interwell connectivity model that is indicative of fluid connectivity of a plurality of wells” adds extra-solution activities (e.g., mere data gathering, source/type of data to be manipulated, see specification at [0048]) (see MPEP 2106.05(g)); and
“using the one or more aspects of one or both of control or configuration of the plurality of wells for hydrocarbon management of a reservoir” recites steps at a high level of generality (see specification at [0047]; see also MPEP 2106.05(c)) while generally linking the use of the judicial exception to a particular technological environment or field of use (see MPEP 2106.05(h)).
Accordingly, these additional elements, when considered individually and in combination, do not integrate the judicial exception into a practical application because they do not impose any meaningful limits on practicing the abstract idea when considering the claim as a whole. The claim is directed to a judicial exception under Step 2A of the test.
Additionally, under Step 2B of the test, the claim, when considered as a whole, does not include additional elements that, when considered individually and in combination, are sufficient to amount to significantly more than the judicial exception because the additional elements:
generally link the use of the judicial exception to a particular technological environment or field of use (i.e., hydrocarbon extraction; using the one or more aspects of one or both of control or configuration of the plurality of wells for hydrocarbon management of a reservoir), which as indicated in the MPEP: “As explained by the Supreme Court, a claim directed to a judicial exception cannot be made eligible “simply by having the applicant acquiesce to limiting the reach of the patent for the formula to a particular technological use.” Diamond v. Diehr, 450 U.S. 175, 192 n.14, 209 USPQ 1, 10 n. 14 (1981). Thus, limitations that amount to merely indicating a field of use or technological environment in which to apply a judicial exception do not amount to significantly more than the exception itself, and cannot integrate a judicial exception into a practical application” (see MPEP 2106.05(h)) (see also MPEP 2106.05(c): “A transformation applied to a generically recited article or to any and all articles would likely not provide significantly more than the judicial exception” and “A transformation that contributes only nominally or insignificantly to the execution of the claimed method (e.g., in a data gathering step or in a field-of-use limitation) would not provide significantly more (or integrate a judicial exception into a practical application)”); and
recite extra-solution activities (e.g., mere data gathering by selecting a particular data source/type to be manipulated) (i.e., accessing an interwell connectivity model that is indicative of fluid connectivity of a plurality of wells), which as indicated in the MPEP: “Another consideration when determining whether a claim integrates the judicial exception into a practical application in Step 2A Prong Two or recites significantly more in Step 2B is whether the additional elements add more than insignificant extra-solution activity to the judicial exception. The term “extra-solution activity” can be understood as activities incidental to the primary process or product that are merely a nominal or tangential addition to the claim. Extra-solution activity includes both pre-solution and post-solution activity. An example of pre-solution activity is a step of gathering data for use in a claimed process” (see MPEP 2106.05(g)).
The claim, when considered as a whole, does not provide significantly more under Step 2B of the test.
Based on the analysis, the claim is not patent eligible.
With regards to the dependent claims they are also directed to the non-statutory subject matter because:
they just extend the abstract idea of the independent claims by additional limitations (Claims 2-18 and 21-24), that under the broadest reasonable interpretation in light of the specification, cover performance of the limitations using mental processes and/or mathematical concepts, and
the additional elements recited in the dependent claims, when considered individually and in combination, refer to extra-solution activities (e.g., mere data gathering using a data type or source) and/or a field of use (Claims 8-10, 12-13, 15 and 19-20), which as indicated in the Office’s guidance does not integrate the judicial exception into a practical application (Step 2A – Prong Two) and/or does not provide significantly more (Step 2B) when considering the claimed invention as a whole.
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.
Claims 1-3 and 13 are rejected under 35 U.S.C. 102(a)(1) as being anticipated by El-Bakry (US 20200209428 A1), hereinafter ‘El-Bakry’.
Regarding claim 1.
El-Bakry discloses:
A method for hydrocarbon extraction ([0002]: hydrocarbon recovery is achieved by monitoring, managing, initiating and/or regulating fluid injection in a reservoir (see also Abstract, Figs. 2 and 4)) comprising:
accessing an interwell connectivity model that is indicative of fluid connectivity of a plurality of wells ([0025]-[0027]: an injection surveillance system (see Figs. 2 and 4, item 200) uses reservoir models, field data and other information to generate fluid connectivity representations of wells (interwell connectivity model) (see Fig. 3; see also [0036]));
determining, based on the interwell connectivity model, one or more aspects of one or both of control or configuration of the plurality of wells ([0030]-[0032]: information from the injection surveillance system (see Fig. 4, item 200), such as the connectivity representations of wells, is used by an injection management system (see Fig. 4, item 400) to optimize fluid injection in the reservoir by determining injection allocation targets (see Fig. 4, item 420) (one or more aspects of one or both of control or configuration of the plurality of wells)); and
using the one or more aspects of one or both of control or configuration of the plurality of wells for hydrocarbon management of a reservoir ([0032]-[0033]: injection allocation targets are employed to improve production strategies (see Fig. 4, item 430; see also [0019], [0022], [0038])).
Regarding claim 2.
El-Bakry discloses all the features of claim 1 as described above.
El-Barky further discloses:
determining the one or more aspects of one or both of control or configuration of the plurality of wells comprises determining one or more aspects associated with one or both of a drilling phase or a construction phase of hydrocarbon management ([0038]: managing hydrocarbons (see also [0019]) based, at least in part, upon wellbore construction and/or operations is performed according to the analysis, which includes the determination of injection allocation targets).
Regarding claim 3.
El-Bakry discloses all the features of claim 2 as described above.
El-Barky further discloses:
the one or more aspects associated with one or both of the drilling phase or the construction phase of hydrocarbon management comprise one or more of: a number of the plurality of wells; a placement of the plurality of wells; fracturing associated with the plurality of wells; or at least one of a compressor for pumping regarding the wells or piping to the wells ([0019]: management of hydrocarbons includes identifying well locations).
Regarding claim 13.
El-Bakry discloses all the features of claim 1 as described above.
El-Barky further discloses:
responsive to receiving production data, updating one or more of parameters, bias or time delay of the interwell connectivity model ([0024]-[0029]: field data including production data is obtained to update the fluid connectivity representations of wells (see also [0022] and claim 1)).
Claim Rejections - 35 USC § 103
This application currently names joint inventors. In considering patentability of the claims the examiner presumes that the subject matter of the various claims was commonly owned as of the effective filing date of the claimed invention(s) absent any evidence to the contrary. Applicant is advised of the obligation under 37 CFR 1.56 to point out the inventor and effective filing dates of each claim that was not commonly owned as of the effective filing date of the later invention in order for the examiner to consider the applicability of 35 U.S.C. 102(b)(2)(C) for any potential 35 U.S.C. 102(a)(2) prior art against the later invention.
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 4-7, 10 and 16-24 are rejected under 35 U.S.C. 103 as being unpatentable over El-Bakry.
Regarding claim 4.
El-Bakry discloses all the features of claim 1 as described above.
El-Barky does not explicitly disclose:
determining the one or more aspects of one or both of control or configuration of the plurality of wells comprises determining one or more aspects associated with a primary depletion phase of hydrocarbon management.
However, El-Bakry teaches:
“Some reservoirs, at some times, may be under sufficient pressure to push hydrocarbons to the surface (e.g., through a wellbore). However, more typically, as the hydrocarbons are produced, the reservoir pressure will decline, and production will falter. Secondary recovery mechanism, and sometimes even tertiary mechanism, may be necessary to improve production. For example, gas, water, or other appropriate injection fluids may be injected into one or more wells to maintain reservoir pressure. Fluid injection is a widely-used secondary recovery mechanism in traditional reservoir management” ([0005]: primary depletion occurs when reservoirs, under sufficient pressure, push hydrocarbons to the surface, which results in reservoir pressure and production declining (analogous to determining one or more aspects associated with a primary depletion phase of hydrocarbon management); after primary depletion stage, additional recovery mechanisms, such as fluid injection, are applied to maintain reservoir pressure and improve production (see also [0023]-[0024] regarding field data including pressure and production data (which could also be measured during primary depletion stage) being used by the injection surveillance system)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to determine the one or more aspects of one or both of control or configuration of the plurality of wells by determining one or more aspects associated with a primary depletion phase of hydrocarbon management, in order to timely implement additional recovery mechanisms to improve reservoir production without unnecessary costs.
Regarding claim 5.
El-Bakry discloses all the features of claim 4 as described above.
El-Barky does not explicitly disclose:
determining the one or more aspects associated with the primary depletion phase of hydrocarbon management comprises determining a time when to end primary depletion.
However, El-Bakry teaches:
“Some reservoirs, at some times, may be under sufficient pressure to push hydrocarbons to the surface (e.g., through a wellbore). However, more typically, as the hydrocarbons are produced, the reservoir pressure will decline, and production will falter. Secondary recovery mechanism, and sometimes even tertiary mechanism, may be necessary to improve production. For example, gas, water, or other appropriate injection fluids may be injected into one or more wells to maintain reservoir pressure. Fluid injection is a widely-used secondary recovery mechanism in traditional reservoir management” ([0005]: primary depletion occurs when reservoirs, under sufficient pressure, push hydrocarbons to the surface, which results in reservoir pressure and production declining (analogous to determining a time when to end primary depletion); after primary depletion stage, additional recovery mechanisms, such as fluid injection, are applied to maintain reservoir pressure and improve production (see also [0023]-[0024] regarding field data including pressure and production data (which can also be measured during primary depletion stage) being used by the injection surveillance system)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to determine the one or more aspects associated with the primary depletion phase of hydrocarbon management by determining a time when to end primary depletion, in order to timely implement additional recovery mechanisms to improve reservoir production without unnecessary costs.
Regarding claim 6.
El-Bakry discloses all the features of claim 1 as described above.
El-Barky does not explicitly disclose:
determining the one or more aspects of one or both of control or configuration of the plurality of wells comprises determining, based on the interwell connectivity model, one or both of whether or when to begin injecting gas into at least one of the plurality of wells.
However, El-Bakry teaches:
“In some embodiments, injection management system 400 may determine injection allocation targets 420 that optimize certain identified objectives. For example, an identified objective may be to inject a set percentage (e.g., 100%, 80%, 70%, etc., as deemed appropriate by the reservoir engineer) of volume of fluid that is produced (i.e., voidage replacement). As another example, an identified objective may be to inject 80% of volume of fluid that is produced. As another example, an identified objective may be to maintain reservoir pressures above specified thresholds. As another example, an identified objective may be to minimize the rate at which water is produced from any or all of the wells” ([0031]: injection allocation targets include objectives such as the amount of volume to be injected, maintain reservoir pressures above specified thresholds (e.g., if pressure is above specified threshold, there is no need to inject gas, otherwise, injection should begin) or minimize the production rate (e.g., if production rate is increasing, injection is not needed) (analogous to determine whether or when to begin injecting gas) (see also [0007] regarding injection allocation impacting overall recovery, and [0036] regarding wells connectivity)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to determine the one or more aspects of one or both of control or configuration of the plurality of wells by determining, based on the interwell connectivity model, one or both of whether or when to begin injecting gas into at least one of the plurality of wells, in order to improve reservoir production without unnecessary costs by taking appropriate actions regarding fluid injections.
Regarding claim 7.
El-Bakry discloses all the features of claim 6 as described above.
El-Barky does not explicitly disclose:
the interwell connectivity model in combination with an optimization model are used to determine whether to inject the gas into tubing or into an annulus of one or more wells.
However, El-Bakry teaches:
“In some embodiments, injection management system 400 may determine injection allocation targets 420 that optimize certain identified objectives. For example, an identified objective may be to inject a set percentage (e.g., 100%, 80%, 70%, etc., as deemed appropriate by the reservoir engineer) of volume of fluid that is produced (i.e., voidage replacement). As another example, an identified objective may be to inject 80% of volume of fluid that is produced. As another example, an identified objective may be to maintain reservoir pressures above specified thresholds. As another example, an identified objective may be to minimize the rate at which water is produced from any or all of the wells” ([0031]: injection allocation targets optimize objectives such as the amount of volume to be injected, maintain reservoir pressures above specified thresholds or minimize the production rate (e.g., if injection is needed in any case, fluid would be injected; see also [0007] regarding injection allocation impacting overall recovery, [0036] regarding wells connectivity and [0038] regarding gas lift which introduces gas in the annulus of the wells)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to use the interwell connectivity model in combination with an optimization model to determine whether to inject the gas into tubing or into an annulus of one or more wells, in order to improve reservoir production by implementing different fluid injection techniques (e.g., injecting gas into tubing or into an annulus of one or more wells) when necessary.
Regarding claim 10.
El-Bakry discloses all the features of claim 7 as described above.
El-Barky further discloses:
the plurality of wells comprises one or more injector wells into which gas is injected into the tubing and one or more offset wells in which gas is not injected into the tubing ([0036]: injector wells are used for fluid injection to improve hydrocarbon production in production wells; examiner interprets injection to be done in the tubing (see also [0023])).
El-Barky does not explicitly disclose:
the interwell connectivity model in combination with the optimization model are used to determine for the one or more offset wells one or more aspects of injecting the gas into the annulus of the one or more offset wells based on the gas injected into the tubing of the one or more injector wells.
However, El-Barky teaches:
“In some embodiments, the above-described injection surveillance system 200 and/or injection management system 400 can be used for a field having a single reservoir with multiple wells or for a field having multiple reservoirs (with multiple wells) sharing common production facilities. In some embodiments, methods and systems described herein may be coupled with other production optimization workflows (such as gas-lift optimization, choke optimization, and routing optimization) in a system-wide production optimization workflow” ([0037]: fluid injection analysis (analogous to gas injected into the tubing of injector wells) can be coupled with gas-lift optimization (analogous to gas injected into the annulus) (see also [0007] regarding injection allocation impacting overall recovery, and [0038])).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to use the interwell connectivity model in combination with the optimization model to determine for the one or more offset wells one or more aspects of injecting the gas into the annulus of the one or more offset wells based on the gas injected into the tubing of the one or more injector wells, in order to improve reservoir production by implementing additional optimization techniques such as gas lift when needed to facilitate hydrocarbon recovery.
Regarding claim 16.
El-Bakry discloses all the features of claim 13 as described above.
El-Barky does not explicitly disclose:
the interwell connectivity model includes: (i) discrete or categorical variables; and (ii) continuous variables; and
wherein updating the interwell connectivity model includes updating both the discrete or categorical variables and the continuous variables.
However, El-Barky teaches:
“The field data 210 may be used with the reservoir model(s) 220 to generate flow diagnostics 230, such as a quantitative estimation of fluid connectivity between wells with multiphase simulations. For example, if reservoir model 220 is a discretized reservoir model, the flow diagnostics 230 may include a single-phase, steady-state flow solution though the reservoir. As another example, flow diagnostics 230 may include a more complicated dynamic multi-phase flow solution to infer fluid connectivity” ([0025]: a quantitative estimation of fluid connectivity between wells is generated from field data (analogous to discrete/categorical/continuous variables) and reservoir model (analogous to discrete/categorical/continuous variables) (see also [0022], [0027] and claim 1)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to implement the interwell connectivity model including: (i) discrete or categorical variables; and (ii) continuous variables; and wherein updating the interwell connectivity model includes updating both the discrete or categorical variables and the continuous variables, in order to take into account the impact of real-time conditions during fluid injection for efficient optimization of hydrocarbon recovery.
Regarding claim 17.
El-Bakry discloses all the features of claim 6 as described above.
El-Barky does not explicitly disclose:
the interwell connectivity model in combination with an optimization model are used to determine when to begin injecting gas or how much of the gas to inject into at least a part of the reservoir.
However, El-Bakry teaches:
“In some embodiments, injection management system 400 may determine injection allocation targets 420 that optimize certain identified objectives. For example, an identified objective may be to inject a set percentage (e.g., 100%, 80%, 70%, etc., as deemed appropriate by the reservoir engineer) of volume of fluid that is produced (i.e., voidage replacement). As another example, an identified objective may be to inject 80% of volume of fluid that is produced. As another example, an identified objective may be to maintain reservoir pressures above specified thresholds. As another example, an identified objective may be to minimize the rate at which water is produced from any or all of the wells” ([0031]: injection allocation targets include objectives such as the amount of volume to be injected (how much gas to inject), maintain reservoir pressures above specified thresholds (e.g., if pressure is above specified threshold, there is no need to inject gas, otherwise, injection should begin) or minimize the production rate (e.g., if production rate is increasing, injection is not needed) (analogous to determine when to begin injecting gas or how much of the gas to inject into at least a part of the reservoir) (see also [0007] regarding injection allocation impacting overall recovery, and [0036] regarding wells connectivity)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to use the interwell connectivity model in combination with an optimization model to determine when to begin injecting gas or how much of the gas to inject into at least a part of the reservoir, in order to timely and accurately implement injection techniques to improve reservoir production without unnecessary costs.
Regarding claim 18.
El-Bakry discloses all the features of claim 17 as described above.
El-Barky does not explicitly disclose:
the interwell connectivity model in combination with an optimization model are used to determine in which one or more of the plurality of wells to inject the gas into tubing of the one or more of the plurality of wells in order to disperse gas in at least a part of the reservoir.
However, El-Bakry teaches:
“In some embodiments, injection management system 400 may determine injection allocation targets 420 that optimize certain identified objectives. For example, an identified objective may be to inject a set percentage (e.g., 100%, 80%, 70%, etc., as deemed appropriate by the reservoir engineer) of volume of fluid that is produced (i.e., voidage replacement). As another example, an identified objective may be to inject 80% of volume of fluid that is produced. As another example, an identified objective may be to maintain reservoir pressures above specified thresholds. As another example, an identified objective may be to minimize the rate at which water is produced from any or all of the wells” ([0031]: injection allocation targets include objectives such as minimize the production rate from any well (analogous to determine in which one or more of the plurality of wells to inject the gas into tubing of the one or more of the plurality of wells in order to disperse gas in at least a part of the reservoir) (see also [0007] regarding injection allocation impacting overall recovery, and [0036] regarding wells connectivity)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to use the interwell connectivity model in combination with an optimization model to determine in which one or more of the plurality of wells to inject the gas into tubing of the one or more of the plurality of wells in order to disperse gas in at least a part of the reservoir, in order to accurately implement injection techniques to improve reservoir production without unnecessary costs.
Regarding claim 19.
El-Bakry discloses all the features of claim 18 as described above.
El-Barky further discloses:
the one or more of the plurality of wells comprise one or more injector wells ([0036]: injector wells are used for fluid injection to improve hydrocarbon production in production wells (see also [0023])); and
wherein one or more offset wells comprise one or more remainder wells in which gas is not injected into the tubing of the one or more offset wells ([0036]: injector wells are used for fluid injection to improve hydrocarbon production in production wells (one or more offset wells) (see also [0023])); and
wherein operation of at least one aspect of the one or more offset wells is performed based on injecting gas into the tubing of the one or more injector wells ([0036]: injector wells are used for fluid injection to improve hydrocarbon production (operation) in production wells (see also [0007] regarding injection allocation impacting overall recovery, [0023] and [0027])).
Regarding claim 20.
El-Bakry discloses all the features of claim 19 as described above.
El-Barky further discloses:
artificial lift comprises injecting the gas in an annulus ([0037]-[0038]: gas-lift optimization, which implies injecting gas in the annulus, is implemented during hydrocarbon recovery);
wherein huffing comprises injecting the gas in the tubing ([0034]: injection fluid cycling (huff and puff), which implies injecting gas in the tubing, is implemented during hydrocarbon recovery).
El-Barky does not explicitly disclose:
wherein one or more aspects of the artificial lift in the one or more offset wells is determined based on the huffing in one or more injector wells.
However, El-Bakry teaches:
“In some embodiments, methods and systems described herein may be coupled with other production optimization workflows (such as gas-lift optimization, choke optimization, and routing optimization) in a system-wide production optimization workflow” ([0037]: described fluid injection techniques can be combined with other techniques such as gas-lift optimization to improve production (see also [0005])).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to use the interwell connectivity model in combination with an optimization model to determine one or more aspects of the artificial lift in the one or more offset wells based on the huffing in one or more injector wells, in order to implement different injection techniques when necessary to improve reservoir production.
Regarding claim 21.
El-Bakry discloses all the features of claim 20 as described above.
El-Barky does not explicitly disclose:
one or both of a time to stop injecting the gas into the annulus of the one or more offset wells for the artificial lift or a volume of the gas injected into the annulus for the artificial lift is determined based on the injecting of gas into the tubing of the one or more injector wells.
However, El-Bakry teaches:
“In some embodiments, injection management system 400 may determine injection allocation targets 420 that optimize certain identified objectives. For example, an identified objective may be to inject a set percentage (e.g., 100%, 80%, 70%, etc., as deemed appropriate by the reservoir engineer) of volume of fluid that is produced (i.e., voidage replacement). As another example, an identified objective may be to inject 80% of volume of fluid that is produced. As another example, an identified objective may be to maintain reservoir pressures above specified thresholds. As another example, an identified objective may be to minimize the rate at which water is produced from any or all of the wells” ([0031]: injection allocation targets include objectives such as the amount of volume to be injected (analogous to determine volume of the gas injected into the annulus for the artificial lift), maintain reservoir pressures above specified thresholds (e.g., if pressure is above specified threshold, there is no need to inject gas – analogous to determine a time to stop injecting the gas into the annulus of the one or more offset wells for the artificial lift) or minimize the production rate (e.g., if production rate is increasing, injection is not needed – analogous to determine a time to stop injecting the gas into the annulus of the one or more offset wells for the artificial lift) (see also [0007] regarding injection allocation impacting overall recovery, [0036] regarding wells connectivity, and [0037]-[0038] regarding gas-lift optimization being also implemented)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to determine one or both of a time to stop injecting the gas into the annulus of the one or more offset wells for the artificial lift or a volume of the gas injected into the annulus for the artificial lift based on the injecting of gas into the tubing of the one or more injector wells, in order to efficiently complement implementation of different injection techniques for optimizing hydrocarbon recovery.
Regarding claim 22.
El-Bakry discloses all the features of claim 20 as described above.
El-Barky does not explicitly disclose:
determining the one or more aspects of the artificial lift based on the huffing in the one or more injector wells comprises:
determining a migration of the gas through the tubing in the one or more injector wells in the reservoir;
determining an effect of the migration of the gas in the reservoir on the one or more offset wells; and
selecting, based on the effect of the migration of the gas in the reservoir on the one or more offset wells, the one or more aspects of the artificial lift in the one or more offset wells.
However, El-Barky teaches:
“Injection allocation (i.e., distribution of the injection fluid across injection wells and across time) may impact the overall recovery of hydrocarbons from the reservoir” ([0007]: distribution (migration) of injection fluid across the injection wells impacts the overall recovery);
“One of the many potential advantages of the embodiments of the present disclosure is that fluid injection operations may be monitored in real time. Likewise, as the real-time impacts of fluid injection are monitored, injection allocation targets may be updated, and systems may be controlled and/or regulated to improve hydrocarbon recovery” ([0022]: real-time impacts of fluid injection are monitored in order to control and regulate hydrocarbon recovery accordingly (see also [0036] regarding wells connectivity, and [0037]-[0038] regarding gas-lift optimization being also implemented)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to determine the one or more aspects of the artificial lift based on the huffing in the one or more injector wells by: determining a migration of the gas through the tubing in the one or more injector wells in the reservoir; determining an effect of the migration of the gas in the reservoir on the one or more offset wells; and selecting, based on the effect of the migration of the gas in the reservoir on the one or more offset wells, the one or more aspects of the artificial lift in the one or more offset wells, in order to efficiently apply different injection techniques for optimizing hydrocarbon recovery.
Regarding claim 23.
El-Bakry discloses all the features of claim 1 as described above.
El-Barky does not explicitly disclose:
determining the one or more aspects of one or both of control or configuration of the plurality of wells comprise determining two or more cycles of: injecting one or more gases into tubing of at least one of the plurality of wells; and injecting the one or more gases into an annulus of one or more of the plurality of wells.
However, El-Barky teaches:
“Injection allocation target rate calculations may be likewise repeated for each of the injector wells” ([0036]: injection rates are repeatedly calculated for each injector well (analogous to injecting one or more gases into tubing/annulus of at least one of the plurality of wells; see also [0034] regarding fluid cycling which implies two or more cycles of fluid injection, and [0037]-[0038] regarding gas-lift optimization (analogous to injecting the one or more gases into an annulus of one or more of the plurality of wells) being also implemented))
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to determine the one or more aspects of one or both of control or configuration of the plurality of wells by determining two or more cycles of: injecting one or more gases into tubing of at least one of the plurality of wells; and injecting the one or more gases into an annulus of one or more of the plurality of wells, in order to efficiently complement different injection techniques for optimizing hydrocarbon recovery.
Regarding claim 24.
El-Bakry discloses all the features of claim 23 as described above.
El-Barky does not explicitly disclose:
the two or more cycles comprise: injecting the one or more gases into the tubing of a plurality of injector wells; and injecting the one or more gases into the annulus of one or more of the plurality of injector wells and one or more offset wells.
However, El-Barky teaches:
“Injection allocation target rate calculations may be likewise repeated for each of the injector wells” ([0036]: injection rates are repeatedly calculated for each injector well (analogous to injecting the one or more gases into the tubing of a plurality of injector wells; see also [0034] regarding fluid cycling which implies two or more cycles of fluid injection, and [0037]-[0038] regarding gas-lift optimization (analogous to injecting the one or more gases into the annulus of one or more of the plurality of injector wells and one or more offset wells))
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry to implement the two or more cycles by: injecting the one or more gases into the tubing of a plurality of injector wells; and injecting the one or more gases into the annulus of one or more of the plurality of injector wells and one or more offset wells, in order to efficiently complement different injection techniques for optimizing hydrocarbon recovery.
Claims 8-9, 11-12 and 14-15 are rejected under 35 U.S.C. 103 as being unpatentable over El-Bakry, in view of Lin (US 20130231867 A1), hereinafter ‘Lin’.
Regarding claim 8.
El-Bakry discloses all the features of claim 7 as described above.
El-Barky further discloses:
the plurality of wells comprises one or more injector wells into which gas is injected into the tubing ([0036]: injector wells are used for fluid injection to improve hydrocarbon production; examiner interprets injection to be done in the tubing (see also [0023])).
El-Barky does not disclose:
the interwell connectivity model in combination with the optimization model determine whether to inject the gas into tubing by analyzing a time delay of an effect of injecting the gas into the one or more injector wells on one or more offset wells.
Lin teaches:
“In one embodiment, to estimate the travel time, the water-flood reservoir can be modeled as a linear system by considering water injection rates as inputs and total fluid production rates as outputs. For example, in pulse testing, sensitive differential pressure gauges can be used to monitor the resulting pressure response at adjacent wells. In another embodiment, the reservoir can be treated as a multi-input and multi-output system and estimate all the inter-well response by the production rates. By using a capacitance model (CM), the relation between the injection production response and the “time delay” constant can be built. The relation between the injection-production response and the time delay is approximately proportional to the pressure wave propagation time. Therefore, the time delay can be estimated from the injection/production data” ([0043]-[0044]: travel time (time delay) of injected fluid between injector(s) and producer(s) can be modeled using injection rates as inputs and production rates as outputs (see also [0030]); examiner notes that one of ordinary skill in the art would consider this time delay when performing injection techniques for hydrocarbon recovery).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry in view of Lin to implement the interwell connectivity model in combination with the optimization model to determine whether to inject the gas into tubing by analyzing a time delay of an effect of injecting the gas into the one or more injector wells on one or more offset wells, in order to characterize fluid movement in the system for taking appropriate actions regarding fluid injections during hydrocarbon production.
Regarding claim 9.
El-Bakry in view of Lin discloses all the features of claim 8 as described above.
El-Barky further discloses:
the one or more injector wells comprises a first injector well and a second injector well ([0036]: injector wells are used for fluid injection to improve hydrocarbon production; examiner interprets injection to be done in the tubing (see also [0023])).
El-Barky does not disclose:
the interwell connectivity model in combination with the optimization model are used to determine, based on the time delay, one or both of a timing of injection of the gas into the tubing based on the gas injected into the tubing of the first injector well.
Lin teaches:
“In one embodiment, to estimate the travel time, the water-flood reservoir can be modeled as a linear system by considering water injection rates as inputs and total fluid production rates as outputs. For example, in pulse testing, sensitive differential pressure gauges can be used to monitor the resulting pressure response at adjacent wells. In another embodiment, the reservoir can be treated as a multi-input and multi-output system and estimate all the inter-well response by the production rates. By using a capacitance model (CM), the relation between the injection production response and the “time delay” constant can be built. The relation between the injection-production response and the time delay is approximately proportional to the pressure wave propagation time. Therefore, the time delay can be estimated from the injection/production data” ([0043]-[0044]: travel time (time delay) of injected fluid between injector(s) and producer(s) can be modeled using injection rates as inputs and production rates as outputs (see also [0030]); examiner notes that one of ordinary skill in the art would consider this time delay when performing injection techniques for hydrocarbon recovery (e.g., timing of gas injection based on gas already injected)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry in view of Lin to use the interwell connectivity model in combination with the optimization model to determine, based on the time delay, one or both of a timing of injection of the gas into the tubing based on the gas injected into the tubing of the first injector well, in order to characterize fluid movement in the system for taking appropriate actions regarding additional fluid injections during hydrocarbon production.
Regarding claim 11.
El-Bakry discloses all the features of claim 10 as described above.
El-Barky does not disclose:
the interwell connectivity model in combination with the optimization model are used to determine, based on a time delay of an effect of injecting the gas into the tubing of the one or more injector wells on the one or more offset wells, when to inject the gas into the annulus of the one or more offset wells.
Lin teaches:
“In one embodiment, to estimate the travel time, the water-flood reservoir can be modeled as a linear system by considering water injection rates as inputs and total fluid production rates as outputs. For example, in pulse testing, sensitive differential pressure gauges can be used to monitor the resulting pressure response at adjacent wells. In another embodiment, the reservoir can be treated as a multi-input and multi-output system and estimate all the inter-well response by the production rates. By using a capacitance model (CM), the relation between the injection production response and the “time delay” constant can be built. The relation between the injection-production response and the time delay is approximately proportional to the pressure wave propagation time. Therefore, the time delay can be estimated from the injection/production data” ([0043]-[0044]: travel time (time delay) of injected fluid between injector(s) and producer(s) can be modeled using injection rates as inputs and production rates as outputs (see also [0030]); examiner notes that one of ordinary skill in the art would consider this time delay when performing injection techniques, including gas lift (see El-Barky at [0007], [0037]-[0038]), for hydrocarbon recovery).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry in view of Lin to use the interwell connectivity model in combination with the optimization model to determine, based on a time delay of an effect of injecting the gas into the tubing of the one or more injector wells on the one or more offset wells, when to inject the gas into the annulus of the one or more offset wells, in order to characterize fluid movement in the system for taking appropriate actions regarding fluid injections, including the use of gas lift optimization, during hydrocarbon production.
Regarding claim 12.
El-Bakry in view of Lin discloses all the features of claim 11 as described above.
El-Barky further discloses:
hydrocarbons are extracted from a subsurface via the one or more offset wells ([0036]: injector wells are used for fluid injection to improve hydrocarbon production in production wells (offset wells)).
El-Barky does not disclose:
wherein the effect of injecting the gas into the tubing of the one or more injector wells comprises a mixing of the gas with the hydrocarbons in the subsurface;
wherein the interwell connectivity model in combination with the optimization model are used to determine when to begin injecting gas into an annulus of the one or more offset wells based on the time delay of the effect of injecting the gas into the tubing of the one or more injector wells.
Lin teaches:
“In one embodiment, to estimate the travel time, the water-flood reservoir can be modeled as a linear system by considering water injection rates as inputs and total fluid production rates as outputs. For example, in pulse testing, sensitive differential pressure gauges can be used to monitor the resulting pressure response at adjacent wells. In another embodiment, the reservoir can be treated as a multi-input and multi-output system and estimate all the inter-well response by the production rates. By using a capacitance model (CM), the relation between the injection production response and the “time delay” constant can be built. The relation between the injection-production response and the time delay is approximately proportional to the pressure wave propagation time. Therefore, the time delay can be estimated from the injection/production data” ([0043]-[0044]: travel time (time delay) of injected fluid (and eventually of the mixture of the injected fluid and the hydrocarbons) between injector(s) and producer(s) can be modeled using injection rates as inputs and production rates as outputs (see also [0030]); examiner notes that one of ordinary skill in the art would consider this time delay and the mixing of the gas with the hydrocarbons when performing injection techniques, including gas lift (see El-Barky at [0037]-[0038]), for hydrocarbon recovery).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry in view of Lin to implement the effect of injecting the gas into the tubing of the one or more injector wells comprising a mixing of the gas with the hydrocarbons in the subsurface; and wherein the interwell connectivity model in combination with the optimization model are used to determine when to begin injecting gas into an annulus of the one or more offset wells based on the time delay of the effect of injecting the gas into the tubing of the one or more injector wells, in order to characterize fluid mixture movement in the system for taking appropriate actions regarding fluid injections, including the use of gas lift optimization, during hydrocarbon production.
Regarding claim 14.
El-Bakry discloses all the features of claim 13 as described above.
El-Barky does not disclose:
the time delay is indicative of an effect of injecting gas into at least a part of a well; and
wherein updating the time delay of the interwell connectivity model comprises using production data and data indicative of previous injection of gas into the at least a part of the well.
Lin teaches:
“In one embodiment, to estimate the travel time, the water-flood reservoir can be modeled as a linear system by considering water injection rates as inputs and total fluid production rates as outputs. For example, in pulse testing, sensitive differential pressure gauges can be used to monitor the resulting pressure response at adjacent wells. In another embodiment, the reservoir can be treated as a multi-input and multi-output system and estimate all the inter-well response by the production rates. By using a capacitance model (CM), the relation between the injection production response and the “time delay” constant can be built. The relation between the injection-production response and the time delay is approximately proportional to the pressure wave propagation time. Therefore, the time delay can be estimated from the injection/production data” ([0043]-[0044]: travel time (time delay) of injected fluid between injector(s) and producer(s) can be modeled using injection rates as inputs and production rates as outputs for hydrocarbon recovery (see also [0030]; see also El-Barky at [0007] regarding injection allocation impacting overall recovery and [0022] regarding updating allocation targets based on fluid injection impacts)).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify El-Bakry in view of Lin to implement the time delay as indicative of an effect of injecting gas into at least a part of a well; and wherein updating the time delay of the interwell connectivity model comprises using production data and data indicative of previous injection of gas into the at least a part of the well, in order to take into account the impact of fluid injection for efficient optimization of hydrocarbon recovery.
Regarding claim 15.
El-Bakry in view of Lin discloses all the features of claim 14 as described above.
El-Barky further discloses:
wherein hydrocarbon is extracted using a plurality of cycles of injecting gas into the at least a part of the well ([0034]: injection fluid cycling is performed during hydrocarbon recovery); and
wherein the interwell connectivity model is updated based on the production data and the data from a previous cycle of injecting gas into the at least a part of the well ([0024]-[0029]: field data including production data is obtained to update the fluid connectivity representations of wells (see also [0022] and claim 1)).
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
Downey; Robert A., US 20210317733 A1, SYSTEM AND METHOD FOR OPTIMIZED PRODUCTION OF HYDROCARBONS FROM SHALE OIL RESERVOIRS VIA CYCLIC INJECTION
Reference discloses optimization of hydrocarbon production using cycling injection.
Elphick; Jonathan, US 7890264 B2, Waterflooding analysis in a subterranean formation
Reference discloses waterflooding analysis by identifying injectors and producers and corresponding information for adjusting wellsite operations.
Katterbauer; Klemens et al., US 20230229907 A1, SYSTEM AND METHOD FOR WATER INJECTION OPTIMIZATION IN A RESERVOIR
Reference discloses water injection by training models.
SAADATPOOR; EHSAN et al., US 20100100354 A1, DYNAMIC CALCULATION OF ALLOCATION FACTORS FOR A PRODUCER WELL
Reference discloses calculating producer wells based on well patterns including injector wells.
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/LINA CORDERO/Primary Examiner, Art Unit 2857