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 .
DETAILED ACTION
The following NON-FINAL Office Action is in response to application 18/589,659 filed on 02/28/2024. This communication is the first action on the merits.
Drawings
The drawings were received on 02/28/2024. These drawings are acceptable.
Information Disclosure Statement
The information disclosure statement (IDS) submitted on 02/28/2024 has been considered by the examiner.
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
Claims 1-8, and 11-20 are rejected under 35 U.S.C. 103 as being unpatentable over US 20240241999 A1, Han (hereinafter Han) in view of WO 2008036154 A1, Searles et al. (hereinafter Searles).
Regarding Claim 1 and 13, Han discloses a method, comprising:
obtaining reservoir data for a first geological region of interest (Han, [0005] The computer system is configured to obtain a set of wellbore length compensating breakdown pressure correction curves, receive the plurality of observed rock parameters and observed wellbore parameters measurements taken in a laboratory-scale wellbore [0076] In step 604, an approximate breakdown pressure may be determined for a reservoir-scale wellbore in accordance with one or more embodiments. The approximate breakdown pressure may be based, at least in part, on measurements taken in a laboratory-scale wellbore. The measurements may include a plurality of observed rock parameters and observed wellbore parameters);
obtaining geological data regarding one or more formations in the first geological region of interest (Han, [0029] The wellbore path (102) may be a curved wellbore path, or a straight wellbore path. All or part of the wellbore path (102) may be vertical, and some wellbore paths may be deviated or have horizontal sections. The wellbore may traverse a plurality of overburden (114) layers and one or more cap-rock (116) layers to a hydrocarbon reservoir (105) within the subterranean region of interest (103));
performing, by a first drilling system comprising a drill bit (Han, Fig. 1 (104) Drill bit) and a drill string (Han, Fig. 1 (106) Drillstring), a first drilling operation to produce a first wellbore in the first geological region of interest (Han, Fig. 1, [0039] To start drilling, or “spudding in” the well, the hoisting system lowers the drillstring (106) suspended from the derrick (108) towards the planned surface location of the wellbore (117). An engine, such as a diesel engine, may be used to supply power to the top drive (110) to rotate the drillstring (106). The weight of the drillstring (106) combined with the rotational motion enables the drill bit (104) to bore the wellbore);
determining, by the computer processor, borehole stress data based on the first wellbore (Han, [0058] The stress state of the rock (200) may also affect its grains (202) and pores (204). The general state of stress at a point within a subterranean region of interest (103) may be characterized by independent shear and normal stress components, represented by a stress tensor. Further, the combination of the state of stress for every point in the subterranean region may be referred to as the stress field. For example, the in situ stress state may be the original stress status in the rock before excavations or other perturbations and may typically coincide with vertical and horizontal directions (components)), the reservoir data (Han, [0061] FIG. 3A depicts a rock sample (300) in accordance with one or more embodiments. The rock sample (300) may be characterized by its block length L (302), and width W (304). A wellbore (306), typically drilled into the center of the rock sample (300) is shown with wellbore diameter 2R (308), and wellbore length h (310)), and the geological data (Han, [0075] FIG. 6 shows a flowchart (600) in accordance with one or more embodiments. In Step 602 a set of wellbore length compensating breakdown pressure correction curves may be obtained. In some embodiments, the set of wellbore length compensating breakdown pressure correction curves may be determined using numerical simulation for a plurality of nominal rock parameters and nominal wellbore parameters. These nominal parameters may span the range of expected rock parameters and expected wellbore parameters and the values of each parameter may vary by equal intervals across the range. The set of nominal wellbore parameters may include a wellbore length h and a wellbore radius R. The set of nominal rock parameters may include tensile strength T, permeability k, storativity S, Poisson's ratios v.sub.u or v, Biot's modulus M, shear modulus G, Biot's coefficient of effective stress α, Young's modulus E, bulk compression modulus K, or stress conditions such as confining stresses or shear stresses (e.g., σ.sub.V, σ.sub.h, σ.sub.H));
determining, by the computer processor, a first wellbore breakdown pressure of the first geological region of interest (Han, [0064] Using these assumptions, Hubbert and Willis were able to obtain an elastic solution relating the hydraulic fracturing initiation pressure (breakdown pressure) and the two principal horizontal stresses, σ.sub.h, and σ.sub.H. That is, assuming zero p.sub.p in the rock sample (300), the H-W breakdown pressure model predicts that the breakdown pressure P.sub.b.sup.H-W for an impermeable wellbore) based on the geological data (Han, [0058] The stress state of the rock (200) may also affect its grains (202) and pores (204). The general state of stress at a point within a subterranean region of interest (103) may be characterized by independent shear and normal stress components, represented by a stress tensor. Further, the combination of the state of stress for every point in the subterranean region may be referred to as the stress field. For example, the in situ stress state may be the original stress status in the rock before excavations or other perturbations and may typically coincide with vertical and horizontal directions (components)), the borehole stress data (Han, [0061] FIG. 3A depicts a rock sample (300) in accordance with one or more embodiments. The rock sample (300) may be characterized by its block length L (302), and width W (304). A wellbore (306), typically drilled into the center of the rock sample (300) is shown with wellbore diameter 2R (308), and wellbore length h (310)), and the reservoir data (Han, [0075] FIG. 6 shows a flowchart (600) in accordance with one or more embodiments. In Step 602 a set of wellbore length compensating breakdown pressure correction curves may be obtained. In some embodiments, the set of wellbore length compensating breakdown pressure correction curves may be determined using numerical simulation for a plurality of nominal rock parameters and nominal wellbore parameters. These nominal parameters may span the range of expected rock parameters and expected wellbore parameters and the values of each parameter may vary by equal intervals across the range. The set of nominal wellbore parameters may include a wellbore length h and a wellbore radius R. The set of nominal rock parameters may include tensile strength T, permeability k, storativity S, Poisson's ratios v.sub.u or v, Biot's modulus M, shear modulus G, Biot's coefficient of effective stress α, Young's modulus E, bulk compression modulus K, or stress conditions such as confining stresses or shear stresses (e.g., σ.sub.V, σ.sub.h, σ.sub.H)); and
transmitting, by the computer processor, a first command to a stimulation control system based on the first wellbore breakdown pressure (Han, [0028] The term “well” may be used to include more than the wellbore. In particular, the well may include completion and stimulation elements [0028] Stimulation elements may include hydraulic fractures emanating from the wellbore into the surrounding formation to increase the ease with which fluid may flow into the wellbore),
wherein the stimulation control system performs a hydraulic stimulation operation at the first wellbore based on the first wellbore breakdown pressure and in response to the first command (Han, [0033] Prior to the commencement of drilling, a well construction plan may be generated. The well plan may include a wellbore plan, a completion plan, and a stimulation plan. The well construction plan may include each of these elements separately or may integrate each element into a single integrated well plan [0033] the stimulation plan may specify the pumping schedule for pressurizing the wellbore until a breakdown pressure is reached and a proppant material and pumping schedule for injecting proppant (sand) into the hydraulic fracture resulting from the breakdown of the formation).
Han does not disclose determining, by a computer processor, first time elapse data describing an amount of time between the first drilling operation and a first hydraulic stimulation operation;
determining, by the computer processor, thermal diffusivity data regarding one or more temperature fronts in the first geological region of interest based on the first time elapse data;
thermal diffusivity data;
However, Searles teaches determining, by a computer processor, first time elapse data describing an amount of time between the first drilling operation and a first hydraulic stimulation operation (Searles, [0045] The inputs may also include cycle data 210 and stimulation data 212. In various operations, including those involving employing a pressurized injectant, such as steam, injectant pressure 216 and injectant rate 218 may be read. The method may be designed to analyze the data collected over a specified period of time for a particular well and then proceed to analyze the data for another well, looping through the wells in turn. At block 220 it may be determined if there is a well to analyze. If there is no well to analyze or if all wells have already been analyzed, the method may stop or may proceed to block 222);
determining, by the computer processor, thermal diffusivity data regarding one or more temperature fronts in the first geological region of interest based on the first time elapse data (Searles, [0054] (i.e., Equation 6) where R.sub.T is the half-length of injection induced thermal extent in meters, A.sub.T is the area of thermal advancement in square meters, p is the density of injectant in kilograms per meter, h.sub.i is the enthalpy of injectant in kilojoules per kilogram, k is the thermal conductivity in watts per meter per degrees Celsius, α is the thermal diffusivity in square meters per second, and ΔT is (T.sub.inj-T.sub.res) or (T.sub.prod-T.sub.res), where, T.sub.inj is the injection temperature, T.sub.res is the initial reservoir temperature and T.sub.prod is the production temperature, all in degrees Celsius);
thermal diffusivity data (Searles, [0055] Similarly the gradient and vertical extents of the pressure and thermal fronts, relative to fracture surfaces, may also be evaluated on the basis of a semi-infinite medium according to the following (Equations 7 and 8): where D.sub.p is the pore fluid pressure diffusivity in square meters per second and D.sub.T is the thermal diffusivity in square meters per second);
Before the effective filing date of the claimed invention, It would have been obvious to one of ordinary skill in the art to combine Han and Searles teaching because Searles teaches determining thermal diffusivity data based on first time elapse data associated with drilling and hydraulic stimulation operations, while Han teaches determining wellbore breakdown pressure and controlling hydraulic stimulation operations using geological reservoir, and borehole stress data. One of ordinary skill in the art would have been motivated to integrate Searles’s thermal diffusivity analysis into Han’s stimulation control system to improve the accuracy and reliability of determining wellbore breakdown pressure by accounting for thermal effects within the geological formation, thereby improving the planning and execution of hydraulic stimulation operations.
Regarding Claim 2 and 15, Han in view of Searles teaches the method of claim 1, further comprising:
determining a change in pressure in the first geological region of interest based on the one or more temperature fronts diffusing throughout the first geological region of interest based on the amount of time between the first drilling operation and the first hydraulic stimulation operation (Searles, [0047] . At block 236, the pressure and temperature gradients may be evaluated starting from time-dependent (preferentially real-time) pressure and temperature measurements [0045] The inputs may also include cycle data 210 and stimulation data 212. In various operations, including those involving employing a pressurized injectant, such as steam, injectant pressure 216 and injectant rate 218 may be read. The method may be designed to analyze the data collected over a specified period of time for a particular well), and
wherein the first wellbore breakdown pressure is based on the change in pressure (Searles, [0053] The solutions to Equations 2 and 3 may be constrained according to whether there is enough pressure available within any time interval to overcome the minimum principal stress local to the point where a fracture may initiate and propagate)
Before the effective filing date of the claimed invention, It would have been obvious to one of ordinary skill in the art to combine Han and Searles teaching because Searles teaches determining changes in pressure based on temperature fronts diffusing over time following drilling and hydraulic stimulation operations, while Han teaches determining wellbore breakdown pressure for controlling hydraulic stimulation using geological, reservoir, and borehole stress data. One of ordinary skill in the art would have been motivated to integrate Searles’s pressure and thermal analysis into Han’s stimulation control method to improve the accuracy of determining wellbore breakdown pressure and to provide a more reliable basis for planning and controlling hydraulic stimulation operations.
Regarding Claim 3 and 16, Han discloses the method of claim 1, further comprising:
obtaining wellbore data regarding the first wellbore, wherein the wellbore data comprises a wellbore radius of the first wellbore (Han, [0024] Various factors influence the formation breakdown pressure, including but not limited to in-situ stresses and pore pressure, formation permeability, rock strength, the rate of fluid injection, and the length and radius of the wellbore interval being pressurized), inclination angle data of the first wellbore (Han, [0036] The wellbore plan may include wellbore geometry information such as wellbore diameter and inclination angle. If casing (124) is used, the wellbore plan may include casing type or casing depths. Furthermore, the wellbore plan may consider other engineering constraints such as the maximum wellbore curvature (“dog-log”) that the drillstring (106) may tolerate and the maximum torque and drag values that the drilling system (100) may tolerate), and an azimuth of the first wellbore (Han, [0038] The BHA (120) may further include measurement tools, such as a measurement-while-drilling (MWD) tool and logging-while-drilling (LWD) tool. MWD tools may include sensors and hardware to measure downhole drilling parameters, such as the azimuth and inclination of the drill bit, the weight-on-bit, and the torque);
determining a vertical stress on the first wellbore (Han, [0059] If the stresses acting on the rock (200) are normal or perpendicular to the rock (200), the stresses may be referred to as “principal stresses.” The principal in situ stress tensor may consist of a vertical stress σ.sub.V (e.g., the overburden stress), and two horizontal or axial stresses, σ.sub.h and σ.sub.H. For example, FIG. 2 shows principal stresses as one vertical stress σ.sub.V and two axial stresses, σ.sub.h and σ.sub.H, acting on the rock (200)), a maximum horizontal stress on the first wellbore (Han, [0063] A hydraulic fracture will then initiate and extend in the direction of the maximum horizontal stress, σ.sub.H.), and a minimum horizontal stress on the first wellbore using the wellbore data and the reservoir data (Han, [0063] In the elastic model, at the wellbore wall, the tangential stress at the two points aligned perpendicular to the minimum horizontal stress, σ.sub.h, will be the first to meet this criterion as the fluid pressure is raised);
determining a plurality of stress components of the first wellbore based on the inclination angle data (Han, [0036] The wellbore plan may include wellbore geometry information such as wellbore diameter and inclination angle. If casing (124) is used, the wellbore plan may include casing type or casing depths. Furthermore, the wellbore plan may consider other engineering constraints such as the maximum wellbore curvature (“dog-log”) that the drillstring (106) may tolerate and the maximum torque and drag values that the drilling system (100) may tolerate), the vertical stress (Han, [0059] If the stresses acting on the rock (200) are normal or perpendicular to the rock (200), the stresses may be referred to as “principal stresses.” The principal in situ stress tensor may consist of a vertical stress σ.sub.V (e.g., the overburden stress), and two horizontal or axial stresses, σ.sub.h and σ.sub.H. For example, FIG. 2 shows principal stresses as one vertical stress σ.sub.V and two axial stresses, σ.sub.h and σ.sub.H, acting on the rock (200)), the maximum horizontal stress (Han, [0063] Hubbert and Willis (H-W) developed the first realistic model relating recorded hydraulic fracturing test variables to the in situ state of stress in rock. This is the known as the Hubbert-Willis (H-W) model. In the elastic model, at the wellbore wall, the tangential stress at the two points aligned perpendicular to the minimum horizontal stress, σ.sub.h, will be the first to meet this criterion as the fluid pressure is raised), and the minimum horizontal stress (Han, [0063] A hydraulic fracture will then initiate and extend in the direction of the maximum horizontal stress, σ.sub.H); and
determining confining stress data for the first wellbore based on the plurality of stress components (Han, [0057] The shear modulus G, also referred to as the modulus of rigidity, may be characterize as the ability of a rock (200) to resist any change in its shape while maintaining its volume. G may be expressed by the ratio of shear stress to shear strain, defined as the alteration in the right angle between planes, whereon shear stresses are applied to two mutually orthogonal sites),
wherein the borehole stress data comprises the confining stress data (Han, [0060] Defining effective stress de using Equation (1) may be used to model an “isotropic” stress state of rock (200) as only one principal stress (i.e., confining stress σ.sub.c) is considered; however, an “anisotropic” stress state of a rock may be modeled by considering multiple principal stresses (e.g., confining stress σ.sub.V and axial stress σ.sub.h) when defining effective stress. An anisotropic stress state of in situ rock (200) may be mimicked in a laboratory setting, which may also allow for the determination of mechanical and hydraulic rock properties, such as permeability k or diffusivity).
Han does not disclose a plurality of borehole coordinates
However, Searles teaches a plurality of borehole coordinates (Searles, [0095] As depicted in Figure 13, an exemplary well log calculation module 1300, may be enabled when the analysis type is a multi-layered analysis. This module may permit the user to load log files from representative wells for use in evaluating the layered earth model and layer elastic properties. In this example, the stratified earth model is defined from the gamma ray log, although multiple logs or composites from multiple logs (e.g., bulk density, resistivity and sonic) may be used in defining the earth model. Once the earth model has been stratified via a convolution of the logs, then layer properties may be calculated using analytical relationships or empirical correlations known to those skilled in the art)
Before the effective filing date of the claimed invention, It would have been obvious to one of ordinary skill in the art to combine Han and Searles teaching because Searles teaches utilizing a plurality of borehole coordinates and well log information to characterize layered earth models and evaluate formation properties, while Han teaches determining wellbore geometry, stress components, borehole stress, and confining stress for estimating wellbore breakdown pressure. One of ordinary skill in the art would have been motivate to integrate Searles’s plurality of borehole coordinates into Han’s wellbore analysis to improve the spatial characterization of the geological formation and thereby provide more accurate stress and breakdown pressure determinations.
Regarding Claim 4, Han in view of Searles discloses the method of claim 3,
wherein the wellbore data comprises vertical stress data on the first wellbore (Han, [0059] If the stresses acting on the rock (200) are normal or perpendicular to the rock (200), the stresses may be referred to as “principal stresses.” The principal in situ stress tensor may consist of a vertical stress σ.sub.V (e.g., the overburden stress), and two horizontal or axial stresses, σ.sub.h and σ.sub.H. For example, FIG. 2 shows principal stresses as one vertical stress σ.sub.V and two axial stresses, σ.sub.h and σ.sub.H, acting on the rock (200)), minimum horizontal stress data on the first wellbore, and maximum horizontal stress data on the first wellbore (Han, [0063] Hubbert and Willis (H-W) developed the first realistic model relating recorded hydraulic fracturing test variables to the in situ state of stress in rock. This is the known as the Hubbert-Willis (H-W) model. In the elastic model, at the wellbore wall, the tangential stress at the two points aligned perpendicular to the minimum horizontal stress, σ.sub.h, will be the first to meet this criterion as the fluid pressure is raised)
Regarding Claim 5, Han in view of Searles discloses the method of claim 1,
wherein the reservoir data comprises reservoir pore pressure data (Han, [0049] Pore pressure (p.sub.p) may be defined as the pressure that the fluids saturating the pores (204) apply to the grains (202) of the rock (200) and may also be related to the confining stress. Confining stress σ.sub.c is typically the stress caused by the weight of overburden (114) rock. Effective stress σ.sub.e may control the mechanical behavior of the rock (200) and may be represented by a function of the pore pressure p.sub.p and the confining stress acting on the rock (200)) and reservoir temperature data (Han, [0090] An accurately predicted breakdown pressure is critical in determining a pumping schedule, which may include injection parameters and fluid properties, such as injection rates, fluid temperature, fluid type, or proppant information)
Regarding Claim 6 and 17, Han discloses the method of claim 1,
wherein the geological data comprises formation density data (Han, [0033] the wellbore plan may include specifications relating to the well trajectory, the density of drilling mud to be used, and the size of the drill bit and the resulting intended diameter (“caliper”) of the wellbore), Young's modulus data (Han, [0056] Young's modulus E, also referred to as the modulus of longitudinal elasticity, describes the resistance of a material to stretching or compression during elastic deformation. The modulus of elasticity is a set of physical quantities that characterize the ability of any solid body to be elastically deformed under conditions where force is applied to it. That is, Young's modulus may be defined as the ratio of uniaxial tensile/compressive stress σh a rock (200) to the resulting extensional/compressional strain of the rock (200) and may be measured in gigapascals (GPa)), Poisson's ratio data (Han, [0054] An externally applied mechanical stress can elastically and reversibly alter the grains (202) of a rock (200), which is referred to as strain. Poisson's ratio v is an elastic property of a material, such as rock (200). Specifically, Poisson's ratio describes the proportional decrease/increase in a lateral measurement to the proportional increase/decrease in length in a sample of material that is elastically stretched/compressed).
Han does not disclose thermal conductivity data, specific heat data, and thermal expansion coefficient data.
However, Searles teaches thermal conductivity data (Searles, [0054] k is the thermal conductivity in watts per meter per degrees Celsius), specific heat data (Searles, [0054] h.sub.i is the enthalpy of injectant in kilojoules per kilogram), and thermal expansion coefficient data (Searles, [0038] multi-well solution methods may be derived by superposing physics-based single-well solution methods of governing processes, such as poroelastic expansion or contraction, thermoelastic expansion or contraction, and dislocations or fractures).
Before the effective filing date of the claimed invention, It would have been obvious to one of ordinary skill in the art to combine Han and Searles teaching because Searles teaches utilizing a plurality of borehole coordinates and well log information to characterize layered earth models and evaluate formation properties, while Han teaches determining wellbore geometry, stress components, borehole stress, and confining stress for estimating wellbore breakdown pressure. One of ordinary skill in the art would have been motivated to integrate Searles plurality of borehole coordinates into Han’s wellbore analysis to improve the spatial characterization of the geological formation and thereby provide more accurate stress and breakdown pressure determinations.
Regarding Claim 7, Han in view of Searles teaches the method of claim 1, further comprising:
obtaining second time elapse data for a second drilling operation and a second hydraulic stimulation operation (Searles, [0045] The inputs may also include cycle data 210 and stimulation data 212. In various operations, including those involving employing a pressurized injectant, such as steam, injectant pressure 216 and injectant rate 218 may be read. The method may be designed to analyze the data collected over a specified period of time for a particular well and then proceed to analyze the data for another well, looping through the wells in turn. At block 220 it may be determined if there is a well to analyze. If there is no well to analyze or if all wells have already been analyzed, the method may stop or may proceed to block 222);
determining whether a second geological region of interest is disposed in a thermal steady state based on the second time elapse data (Searles, [0048] If both of these measurements are not available for injection, a suitable starting point may then become the isobaric or isothermal saturation values. For production, the pressure and temperature gradients may also be evaluated starting from time-dependent (preferentially real-time) pressure and temperature measurements. If these measurements are not available for production, then the starting point may be derived from a suitable convolution for the gradients in terms of isothermal bulk compressibility and reservoir heat loss due to production),
wherein the second geological region of interest surrounds a second wellbore that is drilled by the second drilling operation (Searles, [0082] A field model may consist of data that may be related to a plurality of single wells. Individual well performance and local displacements may be influenced by various factors, such as stresses, acting upon the formation due to other wells operating in the same formation); and
determining, in response to determining that the second geological region of interest being in the thermal steady state, a second wellbore breakdown pressure (Searles, [0053] The solutions to Equations 2 and 3 may be constrained according to whether there is enough pressure available within any time interval to overcome the minimum principal stress local to the point where a fracture may initiate and propagate.D41),
wherein the second wellbore breakdown pressure is time independent (Searles, [0059] The stress distribution σ.sub.ij should satisfy internal equilibrium conditions, and if the gravity stress field remains almost unaffected, then the equilibrium conditions should follow as σ.sub.ijj = 0.).
Before the effective filing date of the claimed invention, It would have been obvious to one of ordinary skill in the art to combine Han and Searles teaching because Searles teaches determining wellbore breakdown pressure using time elapsed data, thermal steady state conditions, and multiple well analysis, while Han teaches determining wellbore breakdown pressure based on geological, reservoir, and wellbore parameters for hydraulic stimulation planning. A person of ordinary skill in the art would have been motivated to integrate Searles’s multi-well evaluation techniques into Han’s wellbore breakdown pressure determination to improve the accuracy and reliability of predicting breakdown pressures for multiple wellbores under varying formation conditions.
Regarding Claim 8 and 18, Han discloses the method of claim 1, further comprising:
obtaining permeability data regarding the first geological region of interest (Han, [0075] The set of nominal rock parameters may include tensile strength T, permeability k, storativity S, Poisson's ratios v.sub.u or v, Biot's modulus M, shear modulus G, Biot's coefficient of effective stress α, Young's modulus E, bulk compression modulus K, or stress conditions such as confining stresses or shear stresses (e.g., σ.sub.V, σ.sub.h, σ.sub.H)); and
determining whether the permeability data satisfies a predetermined permeability
threshold (Han, [0075] The set of nominal rock parameters may include tensile strength T, permeability k, storativity S, Poisson's ratios v.sub.u or v, Biot's modulus M, shear modulus G, Biot's coefficient of effective stress α, Young's modulus E, bulk compression modulus K, or stress conditions such as confining stresses or shear stresses (e.g., σ.sub.V, σ.sub.h, σ.sub.H) [0024] During a hydraulic fracturing operation, the reservoir is stimulated by injecting fluid into finite length wellbore intervals in order to create fractures in the formation. Various factors influence the formation breakdown pressure, including but not limited to in-situ stresses and pore pressure, formation permeability, rock strength, the rate of fluid injection, and the length and radius of the wellbore interval being pressurized),
Han does not disclose wherein the first wellbore breakdown pressure is based on the permeability data satisfying the predetermined permeability threshold.
However, Searles teaches wherein the first wellbore breakdown pressure is based on the permeability data satisfying the predetermined permeability threshold (Searles, [0053] The solutions to Equations 2 and 3 may be constrained according to whether there is enough pressure available within any time interval to overcome the minimum principal stress local to the point where a fracture may initiate and propagate. Therefore, it may be expected that a fracture will initiate and propagate when the criterion given by Equation 4 is satisfied such that where P.sub.fp is the fracture propagation in pressure in pascals, P.sub.foc is the opening/closing pressure in pascals, S.sub.grad is the maximum principal stress gradient in pascals per meter, H is the source burial depth in meters and K.sub.IC is the formation fracture toughness).
Before the effective filing date of the claimed invention, It would have been obvious to one of ordinary skill in the art to combine Han and Searles teaching because Searles teaches determining fracturing initiation based on pressure constraints that satisfy predetermined formation conditions, including permeability related criteria, while Han teaches obtaining permeability data and using formation parameters to estimate wellbore breakdown pressure. One of ordinary skill in the art would have been motivated to integrate Searles’s threshold based fracture initiation criterion into Han’s breakdown pressure determination in order to improve the accuracy and predictability of hydraulic fracture initiation by ensuring that breakdown pressure is determined only when the permeability conditions are sufficient to initiate and propagate a fracture.
Regarding Claim 11 and 19, Han in view of Searles discloses the method of claim 1, further comprising:
acquiring temperature data for the first geological region of interest using a plurality of downhole temperature sensors disposed in the first wellbore (Han, [0099] A plurality of sensors (not pictured) is located throughout this equipment to send signals to the monitoring system (724). The monitoring system (724) may be used to control the volume of water, chemicals, and proppant used in the pumping operation);
acquiring pressure data for the first geological region of interest using a plurality of downhole pressure sensors disposed in the first wellbore (Han, [0062] Fluid may be pumped from the fluid reservoir, using the fluid pump (330), into the laboratory-scale wellbore (324) to increase the pressure within the laboratory-scale wellbore (324). The pressure within the laboratory-scale wellbore (324) may be monitored by one or more fluid pressure sensors, such as fluid pressure sensor (328)),
wherein the reservoir data comprises the temperature data and the pressure data (Han, [0090] An accurately predicted breakdown pressure is critical in determining a pumping schedule, which may include injection parameters and fluid properties, such as injection rates, fluid temperature, fluid type, or proppant information)
Regarding Claim 12 and 20, Han in view of Searles discloses the method of claim 1,
wherein the hydraulic stimulation operation sends a hydraulic fracturing fluid into the first wellbore at a predetermined flow rate using a pump system (Han, [0070] As seen in FIG. 4, the injection curve (400) may be adjusted by changing the rise-up time t.sub.0 (408) and the target injection rate Q.sub.0 (410). When modeling the effect of the injection rate in a particular wellbore, the wellbore injection discharge rate q.sub.0 may be determined, based on the target injection rate Q.sub.0 and the surface area of the wellbore (typically cylindrical) [0068] In order to plan for a hydraulic fracturing operation, fluid injection rates and times must be determined since during a hydraulic fracturing operation, fluid is typically injected into the wellbore at a particular rate for a particular interval of time),
wherein the hydraulic fracturing fluid comprises at least one propping agent (Han, [0090] A hydraulic fracture propagation model may be run to determine the fluid types and injection parameters required to first fracture the formation around the wellbore and then to achieve the optimum values of propped fracture length and fracture conductivity), and
wherein the hydraulic fracturing fluid produces a fracture network laterally from the first wellbore (Han, [0092] a hydraulic fracturing operation is performed by separating the wellbore into multiple packed wellbore lengths and fracturing each interval in “stages.” Further, the hydraulic fracturing operation may be performed on multiple wells that are geographically grouped. A single well may have anywhere from one to more than forty stages. Typically, each stage includes one perforation operation and one pumping operation. While one operation is occurring on one well, a second operation may be performed on the other well. As such, FIG. 7 shows a hydraulic fracturing operation occurring on a first well (702) and a second well (704). The first well (702) is undergoing the perforation operation and the second well (704) is undergoing the pumping operation [0093] The first well (702) and the second well (704) are horizontal wells meaning that each well includes a vertical section and a lateral section)
Regarding Claim 14, Han in view of Searles discloses the system of claim 13, further comprising:
a user device coupled to the stimulation control system (Han, [0113] There may be any number of computers (802) associated with, or external to, a computer system containing computer (802), wherein each computer (802) communicates over network (830). In some embodiments, steps 602-612 of FIG. 6 may be conducted using a first computer (802) and one or more first applications (807) while a fracturing operation, such as step 614 of FIG. 6, may be monitored using a second computer (802) (i.e., a monitoring system (724)), using one or more second applications (807)),
wherein the user device is configured to provide a graphical user interface for presenting a plurality of wellbore breakdown pressures (Han, [0103] the computer (802) may include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the computer (802), including digital data, visual, or audio information (or a combination of information), or a graphical user interface (GUI)), and
wherein the first wellbore breakdown pressure is selected among the plurality of
wellbore breakdown pressures (Han, [0005] systems including a laboratory-scale wellbore analysis system configured to measure a plurality of observed rock parameters and observed wellbore parameters of a laboratory-scale wellbore within a rock sample, and a computer system)
Claims 9-10 are rejected under 35 U.S.C. 103 as being unpatentable over US 20240241999 A1, Han (hereinafter Han) in view of WO 2008036154 A1, Searles et al. (hereinafter Searles), in further view of US 20180347355 A1, Haque et al. (hereinafter Haque).
Regarding Claim 9, Han in view of Searles discloses the method of claim 1, further comprising:
performing a second drilling operation at a second wellbore in the first geological region of interest (Han, [0029] FIG. 1 illustrates a drilling system (100) in accordance with one or more embodiments. As shown in FIG. 1, a wellbore path (102) may be drilled by a drill bit (104) attached by a drillstring (106) to a drill rig located on the surface (101) of the earth. The drill rig may include framework, such as a derrick (108) to hold drilling machinery. The top drive (110) sits at the top of the derrick (108) and provides clockwise torque via the drive shaft (112) to the drillstring (106) in order to drill the wellbore. The wellbore path (102) may be a curved wellbore path, or a straight wellbore path. All or part of the wellbore path (102) may be vertical, and some wellbore paths may be deviated or have horizontal sections. The wellbore may traverse a plurality of overburden (114) layers and one or more cap-rock (116) layers to a hydrocarbon reservoir (105) within the subterranean region of interest (103))
Han in view of Searles does not disclose , wherein the second drilling operation acquires a plurality of cuttings from drilling fluid circulated in the second wellbore during the second drilling operation; and
determining cutting data from the plurality of cuttings,
wherein a portion of the geological data is based on the cutting data.
However, Haque teaches, wherein the second drilling operation acquires a plurality of cuttings from drilling fluid circulated in the second wellbore during the second drilling operation (Haque, [0067] where the well assessment facility 160 is on-site, a fracture toughness log for a well 108 can be generated at the well assessment facility 160 during an ongoing drilling operation, using drill cutting specimens 172 prepared directly from drill cuttings 142 obtained from the drilling fluid 140 circulated during drilling of the wellbore 110 of the well 108); and
determining cutting data from the plurality of cuttings (Haque, [0066] In some embodiments, such testing and determinations of fracture toughness can be repeated for any number of drill cutting specimens 172 prepared from drill cuttings 142 obtained from a given depth in the formation 104 (or “formation depth”) to determine a corresponding fracture toughness of the formation 104 at the depth. Also, in some embodiments, such testing and determinations can be repeated for drill cutting specimens 172 prepared from drill cuttings 142 obtained from different depths in the wellbore 110 and the formation 104 to determine a corresponding fracture toughness of the formation 104 at each of the different depths. The fracture toughness determined for each of the different formation depths can be combined to generate a fracture toughness log 180 (see FIG. 1) for the well 108. The fracture toughness log 180 may include a mapping of fracture toughness of the formation 104 versus depth in the formation 104 or the wellbore 110)
wherein a portion of the geological data is based on the cutting data (Haque, [0039] Described are embodiments of systems and methods for determining fracture toughness of a subsurface geological formation using rock specimens fabricated from drill cuttings extracted during drilling of a wellbore into the formation. The techniques described can be employed, for example, over the course of a drilling operation to generate a log of fracture toughness across a depth interval of interest in the wellbore and the formation. With the combination of drill cuttings that are readily available, and the disclosed shaping and sizing of the specimens that can be formed from drill cuttings to accurately capture the properties of a KRS specimen)
Before the effective filing date of the claimed invention, It would have been obvious to one of ordinary skill in the art to combine Han in view of Searles and Haque teaching because Haque teaches acquiring drill cuttings from drilling fluid and determining cutting data to characterize formation properties, while Han teaches performing drilling operations in a geological region of interest and Searles teaches analyzing formation characteristics for evaluating well conditions. A person of ordinary skill in the art would have been motivated to integrate Haque’s drill cuttings analysis into Han’s drilling system to obtain geological data directly from readily available drill cuttings, thereby improving the accuracy and efficiency of formation characterization and wellbore breakdown pressure determinations.
Regarding Claim 10, Han in view of Searles in further view of Haque teaches the method of claim 1, further comprising:
acquiring, using a coring system comprising a coring tool (Haque, [0052] The well assessment facility 160 can include a fabrication system 162 and a testing system 164. The fabrication system 162 can include tools (for example, cutting and polishing devices) for fabricating and otherwise preparing drill cutting specimens 172 from samples of the drill cuttings 142 (or “drill cutting samples”), for testing by the testing system 164), one or more core samples from a second wellbore in the first geological region of interest (Haque, [0072] The fracture toughness of the drill cutting specimen 172 can be used, in turn, to determine a fracture toughness of the formation 104 at the depth from which the corresponding drill cutting 142 was removed from the wellbore 110 (for example, at the depth from which the drill cutting 142 from which the drill cutting specimen 172 was prepared, was removed from the wellbore 110)); and
determining core sample data using the one or more core samples, wherein a portion of the geological data is based on the core sample data (Haque, [0067] Given the ability to continually acquire drill cuttings 142 directly from the drilling fluid 140 while a drilling operation is in progress, and the ability to prepare and test the drill cutting specimens 172 to obtain accurate measures of fracture toughness, in some embodiments, the described operations can be performed during a drilling operation including drilling of a wellbore into a formation, to provide a real-time assessment of fracture toughness of the formation during the drilling operation).
Before the effective filing date of the claimed invention, It would have been obvious to one of ordinary skill in the art to combine Han in view of Searles and Haque teaching because Haque teaches obtaining and testing core samples to determinate formation properties, while Han teaches using geological and wellbore data to estimate wellbore breakdown pressure, and Searles teaches evaluating formation conditions for hydraulic stimulation analysis. A person of ordinary skill in the art would have been motivated to integrate Haque’s core sample testing into Han’s drilling and analysis system to provide more accurate geological data for predicting wellbore breakdown pressure and planning hydraulic stimulation operations.
Pertinent Prior Art
The prior art made of record and not relied upon is considered pertinent to applicant’s disclose:
-US 20250122789 A1, describing systems and methods for performing targeted stimulations of wells in subsurface hydrocarbon formation using diagnostic well logs, dynamic well testing, fracturing identification, and targeted hydraulic stimulation to improve hydrocarbon production.
-US 20160040524 A1, describing systems and methods for monitoring subterranean well operations using MEMS sensors to measure wellbore conditions, track well servicing compositions, and evaluate formation and well integrity parameters during drilling, completion, and treatment operations.
-US 20150292323 A1, describing systems and methods for integrated wellbore stress, stability, and strengthening analysis using geomechanical modeling to evaluate wellbore conditions, predict fracture behavior, determine drilling parameters, and improve wellbore integrity during drilling operations.
-US 20070131411 A1, describing systems and methods for producing hydrocarbons from subsurface formations using in situ thermal processing, wellbore monitoring formation characterization, and heating techniques to improve hydrocarbon recovery and treatment of hydrocarbon containing formations.
Conclusion
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/IBRAHIM NAGI SHOHATEE/
Examiner, Art Unit 2857
/SHELBY A TURNER/Supervisory Patent Examiner, Art Unit 2857
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