DETAILED ACTION
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 .
Response to Arguments
Claims 1-21 are pending, independent claims 1 and 19 are amended.
Applicant’s arguments on pages 7-12, file 1/20/2026 with respect to U.S.C. 102(a)(1) and U.S.C. 103 rejection of claims 1-21 have been fully considered but they are not considered persuasive.
Applicant argues that Cohen does not teach all the limitations of the newly amended claims 1 and 19.
Examiner respectfully disagrees and directs applicant to the rejection of the new limitations below.
Specifically, Applicant argues that Cohen does not disclose "inducing one or more pressure changes at or in at least one well while the at least one well is producing hydrocarbons."
Examiner respectfully disagrees. Applicant is correct in acknowledging that Cohen is generally directed towards methods and systems for performing fracture operations, such as investigating subterranean formations and characterizing hydraulic fracture networks in a subterranean formation. However, Cohen does mention that their production operation used to analyze the fractures and formations can be used during hydrocarbon production in [0063] “The production operations may be simulated before, during (i.e., during hydrocarbon production) or after production is generated from a wellbore.” For at least these reasons, Applicant’s argument is unpersuasive.
Claim Rejections - 35 USC § 102
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) 1-9, 17, and 21 is/are rejected under 35 U.S.C. 102(a)(1) as being anticipated by Cohen et al. (US 2014/0151035 A1) hereinafter Cohen.
Regarding Claim 1, Cohen teaches inducing one or more pressure changes at or in at least one well while the at least one well is in producing hydrocarbons ([0071] “During the fracturing operation, fracturing fluid is pumped from the surface 311 into the treatment 301 causing the surrounding formation in a hydrocarbon reservoir 307 to fracture and form a hydraulic fracture network 308. Such fracturing produces microseismic events 310, which emit both compressional waves ( also referred to as primary waves or P-waves) and shear waves (also referred to as secondary waves or S-waves) (i.e., inducing types of pressure waves, pressure changes as the waves propagate) that propagate through the earth and are recorded by the geophone receiver array 305 of the monitoring well 303.”; [0057] “ Production may also include injection wells (not shown) for added recovery or for storage of hydrocarbons, carbon dioxide, or water, for example.”; [0063] “The production operations may be simulated before, during (i.e., during hydrocarbon production) or after production is generated from a wellbore.”); sensing data, from a monitor well exterior to the at least one well using at least one sensor indicative of an effect of the one or more pressure changes in the part of the subsurface ([0047] “the sensor (S) may be positioned in one or more locations in the drilling tools and/or at the rig (i.e., exterior to the at least one well) to measure drilling parameters, such as weight on bit, torque on bit, pressures, temperatures, flow rates, compositions, rotary speed and/or other parameters of the operation. Sensors (S) may also be positioned in one or more locations in the circulating system. ”, [0070] “The fracture site 300 can be located on land or in a water environment and includes a treatment well 301 extending into a subterranean formation as well as a monitoring well 303 extending into the subterranean formation and offset from the treatment well 301. The monitoring well 303 includes an array of geophone receivers 305 ( e.g., three component geophones) (i.e., sensors) spaced therein as shown.”, [0071] “Such fracturing produces microseismic events 310, which emit both compressional waves ( also referred to as primary waves or P-waves) and shear waves (also referred to as secondary waves or S-waves) that propagate through the earth and are recorded by the geophone receiver array 305 of the monitoring well 303.”) generating, using the data, information indicative of one or more locations where the effect of the one or more pressure changes at the at least one well are reflected quicker than in a surrounding reservoir in order to characterize the at least one of a part of the at least one well or the part of the subsurface ([0161] “FIGS. 11.1 and 11.2 are three dimensional graphs 1100.1 and 1100.2 depicting reservoir pressure P (z-axis) versus distance x (m) (x-axis) and distance y (m) (y-axis) for 1 and 365 days, respectively. This figure depicts pressure of the DFN (i.e., discrete fracture network is a part of the subsurface) and an initial reservoir pressure 1178 at two different times of production for a high-conductivity DFN. These and other depictions may be provided. The production operation may be adjusted based on the production estimates (i.e., where production estimates are a characterization).” Where the pressure changes the least in the middle and more on the edges over a year’s worth of time), wherein the pressure changes reflected quicker than in a surrounding reservoir are indicative of higher conductivity relative to the surrounding ([0094] “Darcy flow inside the fracture network may also be assumed.” Where Darcy flow is a mathematical equation that states the flow rate (i.e., conductivity) is directly proportional to the pressure difference across the medium, i.e., greater or quicker the changes in pressure the greater the greater the conductivity in a specific region of the surrounding reservoir); and using the information for hydrocarbon development ([0067] “The present disclosure provides an analytical solution over a range of fracture conductivity in cases of hydraulic fracturing in naturally fractured reservoirs (i.e., hydrocarbon development). Such simulation may apply to unconventional reservoirs, such as shale gas, although it can be applicable to other subterranean formations as well.”).
Regarding Claim 2, Cohen teaches the limitation of claim 1.
Cohen further teaches wherein the data sensed is using one or more sensors positioned or associated with a monitoring well ([0070] “The monitoring well 303 includes an array of geophone receivers (i.e., sensors) 305 ( e.g., three-component geophones) spaced therein as shown.”); and wherein the information indicative of the one or more locations where the effect of the one or more pressure changes are reflected quicker than in the surrounding reservoir are used to characterize at least one aspect of the one or more fractures ([0072] “The distance, azimuth angle and depth values of such micro seismic events (i.e., these events are caused by the rapid change in pressure due to the influx of fluid being injected into the system) 310 can be used to derive a geometric boundary (i.e., location) or profile of the fracturing caused by the fracturing fluid over time, such as an elliptical boundary defined by a height h, elliptic aspect ratio e and major axis a as illustrated in FIG. 3.”).
Regarding Claim 3, Cohen teaches the limitation of claim 2.
Cohen further teaches wherein the at least one aspect of the one or more fractures comprises conductivity of the one or more fractures ([0082] “The properties (i.e., aspects) at each fracture branch 544 (i.e., fractures) may be, for example, spatial coordinates at an extremity of the branch, the averaged conductivity, the averaged height, the averaged reservoir pressure at the branch location, and/or the averaged reservoir permeability at the branch location.”).
Regarding Claim 4, Cohen teaches the limitation of claim 3.
Cohen further wherein the conductivity above a predetermined amount is indicative that fluid is flowing through the one or more fractures ([0170] “the analysis above may be used on a single fracture branch of a DFN with low conductivity (or finite conductivity) (50 mD.ft (15.24 mD.ft)) (i.e., a predetermined amount)” where [0171] “FIG. 18 is a graph 1800 depicting cumulated production (y-axis) versus time (x-axis), resulting in a production curve 1884 that reaches toward a maximum recoverable volume 1882. This figure depicts cumulated production from a fracture branch versus time in case of low conductivities (i.e., fluid is flowing through one or more fractures).”) .
Regarding Claim 5, Cohen teaches the limitation of claim 3.
Cohen further teaches wherein the at least one aspect of the one or more fractures comprises one or both of a location or a length of the conductivity of the one or more fractures ([0082] “The properties at each fracture branch 544 may be, for example, spatial coordinates at an extremity of the branch (location of fracture extremity), the averaged conductivity, the averaged height, the averaged reservoir pressure at the branch location, and/or the averaged reservoir permeability at the branch location.”).
Regarding Claim 6, Cohen teaches the limitation of claim 5.
Cohen further teaches wherein one or more sensors comprise one or more gauges to sense the one or more pressure changes ([0047] “Sensors (S), such as gauges, may be positioned about the oilfield to collect data relating to various operations as described previously, where the gauges are “to measure fluid parameters, such as fluid composition, flow rates, pressures (i.e., sensing pressure means there is a change from the normal state or zeroed value of pressure), temperatures, and/or other parameters of the production operation” [0056]); and wherein the at least one aspect of the one or more fractures comprises the location of one or more conductive fractures relative to the one or more gauges ([0082] “The depth of the event 310 is constrained by using the P- and S-wave arrival delays between receivers (i.e., sensor or gauge) of the array 305. The distance, azimuth angle and depth values of such micro seismic events 310 can be used to derive a geometric boundary (i.e., location) or profile of the fracturing caused by the fracturing fluid over time (i.e., deriving the geometric boundary or profile of the fracturing would depend on the positioning of the sensors receiving the data. A point of initial reference, location of sensor, would be needed to derive geometric boundaries from the information the sensor receives), such as an elliptical boundary defined by a height h, elliptic aspect ratio e and major axis a as illustrated in FIG. 3.”)
Regarding Claim 7, Cohen teaches the limitation of claim 1.
Cohen further teaches wherein the information indicative of the one or more locations where the effect of the one or more pressure changes are reflected quicker than in the surrounding reservoir are used to characterize at least one aspect of the subsurface ([0072] “The distance, azimuth angle and depth values of such micro seismic events (i.e., these events are caused by the rapid change in pressure due to the influx of fluid being injected into the system, compared to other areas of the subsurface) 310 can be used to derive a geometric boundary (i.e., location) or profile of the fracturing caused by the fracturing fluid over time, such as an elliptical boundary defined by a height h, elliptic aspect ratio e and major axis a as illustrated in FIG. 3.”).
Regarding Claim 8, Cohen teaches the limitation of claim 7.
Cohen further teaches wherein the at least one aspect of the subsurface characterized comprises conductivity of one or more locations in the subsurface ([0082] “The properties at each fracture branch (i.e., an aspect of the subsurface) 544 may be, for example, spatial coordinates at an extremity of the branch, the averaged conductivity, the averaged height, the averaged reservoir pressure at the branch location, and/or the averaged reservoir permeability at the branch location.”).
Regarding Claim 9, Cohen teaches the limitation of claim 8.
Cohen further teaches wherein the conductivity of the one or more locations in the subsurface is greater than surrounding rock in the subsurface ([0158] “such as where production is done at a constant BHP and the conductivity is high (i.e., conductivity is greater than regions where conductivity is low, [0163]), the flow from the matrix may be based on the assumption that the pressure inside the fracture stays constant. But in reality, only a fraction of the fracture branches of the network may have high conductivities (i.e., the fluid moves more readily in this location than the surrounding subsurface area.”).
Regarding Claim 17, Cohen teaches the limitation of claim 1.
Cohen further teaches wherein the sensed data comprises pressure time series sensed at a plurality of gauges ([0034] “FIG. 17 is a graph of normalized pressure and time delay over time for a low conductivity DFN using an Unconventional Production Model (UPM);” where [0074] “A data processing system 309 is linked to the receivers (i.e., sensors/ gauges) of the array 305 of the monitoring well 303 and to the sensor S (e.g., flow sensor and downhole pressure sensor) of the treatment well 301.”); further comprising performing reservoir simulation in order to determine one or both of porosity or permeability of the subsurface ([0082] “The format of the DFN (i.e., reservoir simulation) 535 considers a unique averaged value for each property at each fracture branch (i.e., characterizing the environment of fracture, i.e., subspace) 544. The fracture branches 544 are defined as the plane that connects two intersections 536. These intersections 536 may be a fracture intersection, or a fracture intersection and a fracture tip. The properties at each fracture branch 544 may be, for example, spatial coordinates at an extremity of the branch, the averaged conductivity, the averaged height, the averaged reservoir pressure at the branch location, and/or the averaged reservoir permeability at the branch location.”); and wherein characterizing the at least one of a part of the at least one well or the part of the subsurface comprises: curve fitting, using the one or both of porosity or permeability of the subsurface, the pressure time series in order to generate the information indicative of one or more locations of conductive fractures in the subsurface ([0170] “To illustrate the mechanism behind this approach, the analysis above may be used on a single fracture branch of a DFN with low conductivity (or finite conductivity) (50 mD.ft (15.24 mD.ft)). This pressure variation may be seen on the pressure recorded in the fracture branch versus time as shown in FIG. 17. As shown in FIG. 17, where the pressure inside a selected fracture branch (such as the branch 1070 of FIG. 10) can be considered constant during ten years of production. This figure depicts a graph 1700 of normalized pressure (P m,0 -Pf) (left y-axis) and time delay T in days (right y-axis) over time tin days ( e.g., during three years of production) (x-axis) in a case of low conductivities. The resulting lines for normalized pressure 1780 and time delay 1781 incline.” where Fig. 17 pressure v time is a curve. The graph is formed by following the derivation of the equations 1-51 where porosity and permeability are taken into account.).
Regarding Claim 21, Cohen teaches the limitation of claim 1.
Cohen further teaches wherein the at least one sensor is disposed outside of the monitor well ([0047] “the sensor (S) may be positioned in one or more locations in the drilling tools and/or at the rig (i.e., exterior to the at least one well) to measure drilling parameters, such as weight on bit, torque on bit, pressures, temperatures, flow rates, compositions, rotary speed and/or other parameters of the operation. Sensors (S) may also be positioned in one or more locations in the circulating system.”).
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
Claim(s) 19 and 20 is/are rejected under 35 U.S.C. 103 as being unpatentable over Cohen in view of Hall (US 20150003200 A1).
Regarding Claim 19, Cohen teaches inducing one or more pressure changes at or in at least one well while the at least one well is in producing hydrocarbons ([0071] “During the fracturing operation, fracturing fluid is pumped from the surface 311 into the treatment 301 causing the surrounding formation in a hydrocarbon reservoir 307 to fracture and form a hydraulic fracture network 308. Such fracturing produces microseismic events 310, which emit both compressional waves ( also referred to as primary waves or P-waves) and shear waves (also referred to as secondary waves or S-waves) (i.e., types of pressure waves, pressure changes as the waves propagate) that propagate through the earth and are recorded by the geophone receiver array 305 of the monitoring well 303.”; [0057] “ Production may also include injection wells (not shown) for added recovery or for storage of hydrocarbons, carbon dioxide, or water, for example.”; [0063] “The production operations may be simulated before, during (i.e., during hydrocarbon production) or after production is generated from a wellbore.”), sensing data, from a monitor well exterior to the at least one well using at least one sensor, indicative of an effect of the one or more pressure changes in the subsurface ([0047] “the sensor (S) may be positioned in one or more locations in the drilling tools and/or at the rig (i.e., exterior to the at least one well) to measure drilling parameters, such as weight on bit, torque on bit, pressures, temperatures, flow rates, compositions, rotary speed and/or other parameters of the operation. Sensors (S) may also be positioned in one or more locations in the circulating system. ”, [0070] “The fracture site 300 can be located on land or in a water environment and includes a treatment well 301 extending into a subterranean formation as well as a monitoring well 303 extending into the subterranean formation and offset from the treatment well 301. The monitoring well 303 includes an array of geophone receivers 305 ( e.g., three component geophones) (i.e., sensors) spaced therein as shown.”, [0071] “Such fracturing produces microseismic events 310, which emit both compressional waves ( also referred to as primary waves or P-waves) and shear waves (also referred to as secondary waves or S-waves) that propagate through the earth and are recorded by the geophone receiver array 305 of the monitoring well 303.”); generating, using the data, information indicative of one or more locations where the effect of the one or more pressure changes at the at least one well are reflected quicker than in a surrounding reservoir in order to characterize the at least one of a part of the at least one well or the part of the subsurface ([0161] “FIGS. 11.1 and 11.2 are three dimensional graphs 1100.1 and 1100.2 depicting reservoir pressure P (z-axis) versus distance x (m) (x-axis) and distance y (m) (y-axis) for 1 and 365 days, respectively. This figure depicts pressure of the DFN (i.e., discrete fracture network is a part of the subsurface) and an initial reservoir pressure 1178 at two different times of production for a high-conductivity DFN. These and other depictions may be provided. The production operation may be adjusted based on the production estimates (i.e., where production estimates are a characterization).” Where the pressure changes the least in the middle and more on the edges over a year’s worth of time) ([0077] “423 generating a pressure profile (i.e., a graphical representation of pressure at different points or times) of the discrete fracture network based on the flow rate”), wherein the pressure changes reflected quicker than in a surrounding reservoir are indicative of higher conductivity relative to the surrounding reservoir ([0094] “Darcy flow inside the fracture network may also be assumed.” Where Darcy flow is a mathematical equation that states the flow rate (i.e., conductivity) is directly proportional to the pressure difference across the medium, i.e., greater or quicker the changes in pressure the greater the greater the conductivity in a specific region of the surrounding reservoir).
Cohen does not teach determining, based on the information, one or more positions for the one or more sensors and positioning, based on the one or more positions, the one or more sensors in the monitoring well.
Hall teaches determining, based on the information, one or more positions for the one or more sensors ([0009] “a method of determining the position of a sensor in seismic exploration is disclosed.”); and positioning, based on the one or more positions, the one or more sensors in the monitoring well ([0044] “Once the seismic processing tool has designated additional sensors or nodes as anchor points, method 200 may proceed to step 210 to survey the newly designated anchor points.”).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine the location determination of the sensors discussed in Hall to the method of characterizing a well system discussed in Cohen for the purpose of knowing the location of the placement of the sensors. This is advantageous because the position of a sensor is used when calculating the travel time from a source to a sensor (e.g., [0007], Hall).
Regarding Claim 20, Cohen teaches the limitation of claim 19.
Cohen further teaches one or more sensors receiving pressure data ([0074] “data processing system 309 is linked to the receivers of the array 305 of the monitoring well 303 and to the sensor S (e.g., flow sensor and downhole pressure sensor (i.e., downhole pressure sensor receives pressure data)) of the treatment well 301.”).
Cohen does not teach determining a time period in which to receive data from the one or more sensors; and determining the one or more positions of the one or more sensors
Hall teaches determining a time period in which to receive data from the one or more sensors ([0005] “The sensors typically receive data during the source's energy emission and during a subsequent "listening" interval”); and determining the one or more positions of the one or more sensors ([0009] “a method of determining the position of a sensor in seismic exploration.”).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine the location determination of the sensors discussed in Hall to the method of characterizing a well system discussed in Cohen for the purpose of knowing the location of the placement of the sensors. This is advantageous because the position of a sensor is used when calculating the travel time from a source to a sensor (e.g., [0007], Hall).
Claim(s) 10-11 is/are rejected under 35 U.S.C. 103 as being unpatentable over Cohen in view of Gu et al. (US 10400550 B2).
Regarding Claim 10, Cohen teaches the limitation of claim 1.
Cohen further teaches wherein inducing the one or more pressure changes is at or in an injector well ([0073] “The site 301 also includes a supply of fracturing fluid and pumping means (not shown) for supplying fracturing fluid under high pressure (i.e., inducing a change in pressure to the well by supplying high pressure fluid) to the treatment well 301.” Where [0078] “This fracture operation may be performed by actual injection of fluid as shown, for example, in FIG. 3. Hydraulic fracturing of the well (i.e., injector well) may also be simulated using hydraulic fracture simulators.”); the information indicative of the one or more locations where the effect of the one or more pressure changes at the injector well are reflected quicker than in the surrounding reservoir ([0072] “The distance, azimuth angle and depth values of such micro seismic events (i.e., these events are caused by the rapid change in pressure due to the influx of fluid being injected into the system) 310 can be used to derive a geometric boundary (i.e., location) or profile of the fracturing caused by the fracturing fluid over time, such as an elliptical boundary defined by a height h, elliptic aspect ratio e and major axis a as illustrated in FIG. 3.”).
Cohen does not teach further comprising training an analytical model using the data.
Gu teaches further comprising training an analytical model using the data (“The inputs and outputs are then used to train the neural network 142 in block 103.” Col 5 line 42-43, where the data used to train the neural network come from “a closed-form analytical solution may be expressed as” col 2 line 42).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine the training an analytic model discussed in Gu to the method of characterizing a well system discussed in Cohen for the purpose of having a model that can adept to different cases. This is advantageous because it allows for the optimization of analytical models across different well based formations.
Regarding Claim 11, Cohen teaches the limitation of claim 10.
Cohen further teaches and the information indicative of the one or more locations where the effect of the one or more pressure changes at the injector well are reflected quicker than in the surrounding reservoir by analyzing observed pressure variations ([0072] “The distance, azimuth angle and depth values of such micro seismic events (i.e., these events are caused by the rapid change in pressure due to the influx of fluid being injected into the system) 310 can be used to derive a geometric boundary (i.e., location) or profile of the fracturing caused by the fracturing fluid over time, such as an elliptical boundary defined by a height h, elliptic aspect ratio e and major axis a as illustrated in FIG. 3.”).
Gu teaches wherein the analytical model (“The two-dimensional (2D) analytical models illustrate the impact of elastic properties and completion parameters on fracture geometries but they assume fixed fracture height and constant elastic properties along the height,” col 3 line 42-46);
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine the training an analytic model discussed in Gu to the method of characterizing a well system discussed in Cohen for the purpose of having a model that can adept to different cases. This is advantageous because it allows for the optimization of analytical models across different well based formations.
Claim(s) 12-15 is/are rejected under 35 U.S.C. 103 as being unpatentable over Cohen and Gu in view of Alramadhan et al., (Numerical Approach in Analyzing Pressure Transient Responses in Dual-Porosity Dual-Permeability DPDP Reservoirs, 18-21 March 2019, Society of Petroleum Engineers, SPE-195004-MS, pages 1-25) hereinafter Alramadhan.
Regarding Claim 12, Cohen and Gu teaches the limitation of claim 11.
Cohen and Gu fail to teach, wherein the analytical model performs a nonlinear mathematical optimization to pressure time series obtained at the one or more pressure gauges by utilizing at least one of spatial distance from conductive fractures or reservoir input as independent variables.
Alramadhan teaches wherein the analytical model performs a nonlinear mathematical optimization to pressure time series obtained at the one or more pressure gauges by utilizing at least one of spatial distance from conductive fractures or reservoir input as independent variables (“The workflow to match the pressure transient behavior of the extended build-up test performed on this well using analytical models, e.g. single fault or two intersecting faults at any angle, as well as numerical well test models is shown in Fig. 6 (i.e., where in fig 6 the system optimizes itself be using revised inputs as it runs the workflow). The effect of the angle between the two intersecting faults is shown on the sensitivity plot on Fig. 7. The effect of the distance to the first and the second faults are shown on sensitivity plots in Figs. 8 and 9, respectively (i.e., the fit of Pressure v. Time is non-linear).” Pg. 6 paragraph 1).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine the nonlinear optimization discussed in Alramadhan to the method of characterizing a well system discussed in Cohen and Gu for the purpose of having a nonlinear system be optimized. This is advantageous because optimizing a nonlinear model reduces errors of the model and gives more accurate values.
Regarding Claim 13, Cohen, Gu and Alramadhan teaches the limitation of claim 12.
Cohen and Gu do not teach wherein the analytical model iteratively minimizes an error reduction objective function to match pressure and distances to conductive fractures with a data set used for the match.
Alramadhan teaches wherein the analytical model iteratively minimizes an error reduction objective function to match pressure and distances to conductive fractures with a data set used for the match (Figure 14 pg. 11 where there are iterative steps with revised inputs, thus lowering the error. Figure 16 pg. 12 then shows the pressure difference modeling that happens due to the iterative steps. Figure 6 discusses the iterative function with regards to distance then Figure 7 and 8 pg. 8 show two different differences with the iterative fitting. In both cases the steps of iterating the model until it fits the data minimizes errors in the function as it continues to run the algorithm until it fits the data.)
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine the error reduction discussed in Alramadhan to the method of characterizing a well system discussed in Cohen and Gu for the purpose of having an analytical model have less errors. This is advantageous because less errors of an analytical model of the model and gives more accurate values.
Regarding Claim 14, Cohen and Gu teaches the limitation of claim 11.
Cohen further teaches wherein the analytical model generates a spatially-distributed view of the one or more conductive fractures ([0076] “ The method involves 420 performing a fracture operation (actual or simulated), 422 generating a DFN (i.e., a discrete fracture network explicitly models each individual fracture, including its orientation, size, position, and other properties) about the wellbore, 424 generating a depth of drainage through the DFN, 426 defining at least one production parameter, and 428 performing a production operation.”).
Cohen and Gu do not teach teaches wherein the analytical model determines one or more conductive fractures in the at least one well.
Alramadhan teaches wherein the analytical model determines one or more conductive fractures in the at least one well (“The well is completed in an area where seismic data have shown indication of extensive faults. The purpose of the test is to confirm their presence, to investigate their conductive nature, and to assess their locations and extensions. Fig. 5 conceptualize the seismic interpreted faults to be characterized through pressure transient analysis in this generalized case study. Offset wells have been included in the investigation to assess their impact on the pressure transient response of the well. In addition, offset wells with valid and high-quality pressure transient test data were used to validate the extension of interpreted faults. The workflow to match the pressure transient behavior of the extended build-up test performed on this well using analytical models, e.g. single fault or two intersecting faults at any angle, as well as numerical well test models is shown in Fig. 6.” Pg 6 paragraph 1).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine an analytical model determining conductive fractures in a well discussed in Alramadhan to the method of characterizing a well system discussed in Cohen and Gu for the purpose of having an analytical model that detects if a fracture has conductive features. This is advantageous because it allows for the calculation of production amount that a well could produce.
Regarding Claim 15, Cohen, Gu and Alramadhan teaches the limitation of claim 14.
Cohen further teaches wherein the one or more conductive fractures are used for analysis of or optimization of a hydrocarbon development of the subsurface ([0067] “The present disclosure provides an analytical solution over a range of fracture conductivity (i.e., conductive fractures) in cases of hydraulic fracturing in naturally fractured reservoirs (i.e., hydrocarbon development). Such simulation may apply to unconventional reservoirs, such as shale gas, although it can be applicable to other subterranean formations as well.”).
Claim(s) 16 and 18 is/are rejected under 35 U.S.C. 103 as being unpatentable over Cohen in view of Akuanyionwu et al. (Examination of Hydraulic Fracture Production Modeling Techniques, 14-16 May 2012, Society of Petroleum Engineers, SPE 157045, pages 1-13) hereinafter Akuanyionwu.
Regarding Claim 16, Cohen teaches the limitation of claim 1.
Cohen further teaches wherein the information is indicative of conductive fractures in the subsurface ([0076] “The method involves 420 performing a fracture operation (actual or simulated), 422 generating a DFN about the wellbore, 424 generating a depth of drainage through the DFN (discrete fracture network), 426 defining at least one production parameter, and 428 performing a production operation.” Where DFN is a computational model that explicitly represents the geometry and properties (like fluid flow and conductivity) of individual fractures within a rock mass or subsurface).
Cohen does not teach wherein using the information for hydrocarbon development comprises modifying one or both of fracture completion or well spacing based on the information indicative of the conductive fractures in the subsurface.
Akuanyionwu teaches wherein using the information for hydrocarbon development comprises modifying one or both of fracture completion or well spacing based on the information indicative of the conductive fractures in the subsurface (“Fig.7 presents the results from the simulation runs for the different fractured completion options (vertical, slanted and horizontal) (modifying fracture completion).” Pg 6 paragraph 2 where the results showed “The base case is the fractured multilayered vertical well (with three separate fractures placed in the three different layers). The results suggest that multi-stage fracturing of the horizontal well returns more gains in production. It would seem that there is only marginal increase in productivity going from six to seven fractures (modifying well spacing) along the horizontal well. This is probably due to interference as the number of fractures increase resulting from more fractures competing for production from the same drainage area.” Pg 6 paragraph 2 where the “Explicit numerical modeling was applied in this case as a static reservoir model with most likely representation of subsurface properties was available (i.e., information for hydrocarbon development).” Pg 5 paragraph 2).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine modifying one or both of fracture completion or well spacing discussed in Akuanyionwu to the method of characterizing a well system discussed in Cohen for the purpose of analyzing the best way to approach fracture a well as it undergoes fracking to optimize production. This is advantageous because the investment commitment can be significant which often raises concerns about profitability especially when considering a longer duration of production (e.g., pg. 1 paragraph 4, Akuanyionwu).
Regarding Claim 18, Cohen teaches the limitation of claim 17. Cohen further teaches generating an output indicative of the information indicative of one or more locations of conductive fractures in the subsurface ([0080] “The DFN (i.e., a discrete fracture network explicitly models each individual fracture, including its orientation, size, position, and other properties) may be generated by extrapolation of fracture data (i.e., fracture data is date of fractures in the subsurface). The fracture data may be extrapolated from the hydraulic fracture simulation 530. This data may be exported automatically to form a production network visualization 532 as schematically depicted by arrow 533.”).
Cohen does not teach wherein using the information for hydrocarbon development comprises modifying one or both of fracture completion or well spacing based on the information indicative of the conductive fractures in the subsurface.
Akuanyionwu teaches wherein using the information for hydrocarbon development comprises modifying one or both of fracture completion or well spacing based on the information indicative of the conductive fractures in the subsurface (“Fig.7 presents the results from the simulation runs for the different fractured completion options (vertical, slanted and horizontal) (modifying fracture completion).” Pg 6 paragraph 2 where the results showed “The base case is the fractured multilayered vertical well (with three separate fractures placed in the three different layers). The results suggest that multi-stage fracturing of the horizontal well returns more gains in production. It would seem that there is only marginal increase in productivity going from six to seven fractures (modifying well spacing) along the horizontal well. This is probably due to interference as the number of fractures increase resulting from more fractures competing for production from the same drainage area.” Pg 6 paragraph 2 where the “Explicit numerical modeling was applied in this case as a static reservoir model with most likely representation of subsurface properties was available (i.e., information for hydrocarbon development).” Pg 5 paragraph 2).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention, to combine modifying one or both of fracture completion or well spacing discussed in Akuanyionwu to the method of characterizing a well system discussed in Cohen for the purpose of analyzing the best way to approach fracture a well as it undergoes fracking to optimize production. This is advantageous because the investment commitment can be significant which often raises concerns about profitability especially when considering a longer duration of production (e.g., pg. 1 paragraph 4, Akuanyionwu).
Conclusion
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/EMMA ALEXANDER/Patent Examiner, Art Unit 2863
/Catherine T. Rastovski/Supervisory Primary Examiner, Art Unit 2857