Notice of Pre-AIA or AIA Status
Claims 1, 4-6, 9-11, 14-22 and 24-26 are currently presented for Examination
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 Amendment
4. The amendment filed on April 15, 2024 has been entered and considered by the examiner.
By the amendment, claims 1, 11 and 20 are amended. The prior art rejection is still maintained in view of the amendments made. See office action.
Response to prior art arguments
Applicant arguments
Applicant respectfully submits that the claims as amended are not obvious over the cited references alone or in combination. Parkin models three discrete points (upper stabilizer center, lower stabilizer center, bit center) at a given averaged tilt (y) to fit one circle (radius r) for DLS. There is no disclosure in Parkin of a locus (line) of high-side contact points or a locus (line) of low-side contact points fixed to a common center; instead, Parkin treats two instantaneous angular positions (β1, β2) to compute an average tilt y, then fits a single circle through three points. That is not "contact points along a curvature line" as claimed. Further, Parkin explicitly rotates the tilt angle around the wellbore, causing the contact points to rotate around the circumference (upper/lower stabilizers switch sides as tool face rotates), the opposite of the claimed subject matter where the high-side and low-side loci are fixed on opposite sides relative to the general curvature and do not switch sides during the modeling step that defines the curvature lines. Also, Parkin's "two angles"(β1/β2are not radii of separate curvature lines, and Parkin never computes two radii (Rhigh, Rlow) then averages them to obtain a general curvature radius as recited in 10, 19, and 25. The Office Action's reading that averaging β1 and β2 helps to determine the average radii" is a non-sequitur; Parkin averages angles to get y and then fits one circle. The claims recite deriving two radii from two distinct curvature lines and then averaging those radii, which is not taught or suggested by Parkin. Therefore, Parkin's 3-point circle fitting cannot reasonably be stretched into two curvature lines comprised of sets of contact points on the high/low sides with a common center and different radii. Additionally, the claims recite a "fixed bend angle comprising a focal point" (i.e., classic bent housing/fixed bend) and a modeling flow that modifies that fixed bend angle in the contact model based on angular rotation from the beam model. Parkin's tool actively tilts the lower tool body with pistons (RSS behavior) and measures tilt to compute DLS; there's no fixed bend housing with a focal point that is being "modified" in the model. The Office Action attempts to treat Parkin's measured tilt as the claimed "modified fixed bend angle," but Parkin does not start from a fixed bend tool-it starts from a tilt-actuated tool and simply calculates DLS. That is a different paradigm. Additionally, specifically with respect to claim 11, the Office Action misinterprets Parkin. The Office Action interprets Parkin's FIG. 7 to the claimed "previously undefined contact point." but Parkin's "point (L, -L sin(a/2))" is a derived geometric center, not a contact point as claimed. The claims recite defining a first contact point that is the previously undefined contact point. Parkin does not teach this recitation
.
Examiner response
Examiner arguments on Parkin is not persuasive. It is the examiner position that Parkin fig 4, 6-7 represents low-side contact points are along a low-side curvature line and high-side contact points are along a high-side curvature line and that both curvature lines are oriented with respect to a common center point (a, b). See Parkin fig 2, 4 and 4, 6-7 and para 34-37- The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points). Those of ordinary skill will readily appreciate that there are many suitable ways to determine the equation of a circle that passes through three defined points. For example, the coordinates of the points may be substituted into the general form of a circle to solve for the coefficients using various numerical methods (the general form of the circle being: x2+y2+Dx+Ey+F=0). Alternatively, one may use the center radius form of the circle and the fact that each point on a circle is equidistant from the center. Using the three points defined above (0, 0), (L, 0), and (L+B cos γ, B sin γ). See also para 0046-0047)
It is the Examiner position that these three points lie in the curvature plane used in Parking’s circle computation. Parkin’s three modeled points corresponds to locations where the BHA geometry interacts with or defines contact behavior within the borehole. Stabilizer and the bit represent contact defining elements of the tool. (see instant specification [0015]) These elements define where the tool is located within the borehole, which in turn determines where the tool is contacting the formation -i.e., the effective high-side and low-side contact positions that govern curvature. Thus, Applicant’s “static geometry” distinction is not persuasive. Further Parkin derives effective tilt angle from the angular inputs β1 and β2 before performing the curvature calculation. This corresponds to the claimed modified fixed angle. Applicant asserts that Parkin cannot teach high-side and low-side curvature lines because the BHA model “rotates around the borehole”. This argument attacks features not recited in claim 1, which contains no prohibition on tool face rotation, no requirement of static or time-fixed contact lines, and no requirement that the high-side/low-side relationship persist beyond the modeling step. Parkin’s modeled points-offset using γ -clearly satisfy this requirement by placing one point closer to the curvature center (high side) and another radially farther (low-side). Whether the BHA could rotate during drilling is irrelevant to the claimed geometry. Contact points in a plane extending from the center of curvature is supported by the Parkin’s equation of the circle operates on points that are co-planar in the curvature plane. The three points described in fig 6-7 all lie in this plane. Parkin explains that depending on the tilt and tool face orientation, the BHA make high-side contact (direction of maximum upward curvature) and low-side contact (direction of maximum downward curvature). Stabilizers and bit centers shift relative to the curvature direction according to γ. This produces distinct positions on the high-side and low-side of the curvature plane forming curvature lines as the geometry is evaluated. Parking modeled offset (L+B cos γ, B sin γ) places the high-side points radially inward (close to the circle center) and low-side point radially outward relative to the fitted curvature. Further claim 1 does not require computing two radii and claim 1 only recites deriving a radius of a circle based on contact points lying along high-side and low-side curvature lines.
Parkin tilt measurement corresponds to the “modified bend angle” om the context of the modeling process. Although Parking physically actuates the tilt, the computational steps disclosed accomplish the same purpose as modifying a fixed bend angle in the claimed method. The geometric center identified by Parkin represents a mathematically derived contact point for modeling purposes. While Applicant distinguished it as “previously undefined”, Parkin’s point functions identically within the modeling method, providing the necessary reference for computation of a curvature.
Applicant arguments
The Office Action cites Noynaert generally and then infers the claimed: " Solving for angular rotation at the focal point of a fixed bend by superimposing bending moments due to WOB and distributed load, with two non-collinear load directions; " Inputting that rotation as a modified fixed bend angle into a contact model that uses your curvature line construct.
However, Noynaert does not identify a "focal point" of a fixed bend housing nor describe modifying a fixed bend angle in the sense the claims require. Instead, Noynaert solves beam deflection broadly; it does not teach the claimed two-stage coupling (beam -- modified fixed bend --curvature-line contact model).
Examiner response
Examiner respectively disagrees. As shown in equation 1 and 2 in Noynaert, in the context of Euler-Bernoulli beam theory, concepts applicable to deriving angular rotation and deflection due to bending effects from applied loads. The diagram (fig 25-26) illustrates an element with applied forces and moments, and the equation (Eq. 2) relates derivatives of moment and deflection to distributed loads (γ), and end loads (F1x) related to weight on bit, which are the fundamental relationships used in beam bending models to solve for deflection (v) and subsequently angular rotation. The principles of superposition are commonly used with such linear elastic models to combine effects from different loads, such as weight on bit and distributed load. In beam theory, solving this type of differential equation allows for the determination of the beam's deflection curve and its first derivative, which represents the angular rotation (slope). (see static finite element model When Eq. 1 is solved for v(x), the result is a curve which describes the deflection in the y direction in Fig. 25.) The diagram in Fig. 26 illustrates the forces and moments acting on the element, which are the components needed for such an analysis. Thus, Noynaert/Samuel still teaches deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior.
Claim Rejections - 35 USC § 103
5. 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 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.
6. 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.
7. The factual inquiries for establishing a background for determining obviousness under 35 U.S.C. 103 are summarized as follows:
1. Determining the scope and contents of the prior art.
2. Ascertaining the differences between the prior art and the claims at issue.
3. Resolving the level of ordinary skill in the pertinent art.
4. Considering objective evidence present in the application indicating obviousness or nonobviousness.
8. Claims 1, 4-6, 9-11, 14, 16-22 and 24-26 are rejected under 35 U.S.C. 103 as being unpatentable over Parkin et al. (PUB NO: US 20160102543 A1), hereinafter Parkin, in view of Oliver et al., (PUB NO: US 20060149518 A1), hereinafter Oliver and further in view of Samuel et al. ((azimuth and inclination modeling in real time): a method for prediction of dog-leg severity based on mechanical specific energy. Diss. 2013.)
Regarding claim 1
Parkin teaches a drilling tool, where the drilling tool contacts the borehole, including low-side contact points, high-side contact points, or combination thereof, and a fixed bend angle comprising a focal point for drilling a borehole; (see para 40 and fig 1- FIG. 4 depicts a schematic of a downhole tool deployed in a deviated wellbore suitable for implementing the method depicted on FIG. 3. For example, the upper and lower stabilizers 62 and 64 and upper and lower tool body sections 52 and 54 are depicted as stick figures in wellbore 40. See also para 27- With continued reference to FIG. 4, tilting the lower tool body section 54 with respect to the upper tool body section 52 may cause the upper and lower stabilizers 62 and 64 to contact the wellbore wall on the opposite sides of the wellbore. As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore. See para 22-The tool 50 may further include one or more motors or pistons (not shown) configured to actively tilt the lower tool body section 54 about the universal joint 56 with respect to the upper tool body section 52.)
Examiner note: Contact points of the upper stabilizers corresponds to the high-side and the contact points of the lower stabilizers corresponds to the low-side contact points.
an angular rotation causes a drill bit of the drilling tool to change direction by effectively modifying the fixed bend angle depending on contact of the contact points with the borehole; (see para 22- The tool 50 may further include one or more motors or pistons (not shown) configured to actively tilt the lower tool body section 54 about the universal joint 56 with respect to the upper tool body section 52. For example, pistons acting on the periphery of the lower tool body section 54 may be employed to tilt the lower tool body section 54 (and the drill bit 32 connected thereto) with respect to the upper tool body section 52. In rotary steerable embodiments, such pistons may be sequentially actuated while rotating the drill string such that the tilt of the drill bit is actively maintained in the desired direction (toolface) with respect to the formation being drilled. see para 31-32 and fig 5-6-The tilt angle between the lower tool body section and the upper tool body section is measured at 154 at a first angular position (e.g., when the tilt angle is oriented at a first rotational position such as high side, low side, left side, or right side of the wellbore). The tilt angle between the lower tool body section and the upper tool body section is then measured at 156 when the tilt angle is rotated to a second angular position (e.g., 180 degrees offset from the first angular position). These tilt angles may be measured, for example, using strain gauges deployed in (or near to) the universal joint. The tilt angles are processed at 158 to compute an average (mean) of the two which is in turn processed at 160 to compute the dogleg severity. The solid lined depiction shows the tool when the tilt angle is rotated to a first angular position (at 154) in the direction of the wellbore curvature and the dashed line depiction shows the tool when the tilt angle is rotated to a second angular position (at 156) opposed to the wellbore curvature (180 degrees offset from the wellbore curvature).)
inputting the angular rotation into a contact model as a modified fixed bend angle, wherein the contact model includes the contact points; (see para 31- the tilt angle between the lower tool body section and the upper tool body section is measured at 154 at a first angular position (e.g., when the tilt angle is oriented at a first rotational position such as high side, low side, left side, or right side of the wellbore). The tilt angle between the lower tool body section and the upper tool body section is then measured at 156 when the tilt angle is rotated to a second angular position (e.g., 180 degrees offset from the first angular position). These tilt angles may be measured, for example, using strain gauges deployed in (or near to) the universal joint. The tilt angles are processed at 158 to compute an average (mean) of the two which is in turn processed. See para 34-37- The center of the wellbore at the drill bit may then be defined as being located at (L+B cos gamma, B sin .gamma.), where B represents the axial separation distance between the lower stabilizer and the drill bit and .gamma. represents the average tilt angle. The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points alternatively, one may use the center radius form of the circle and the fact that each point on a circle is equidistant from the center. Using the three points defined above (0, 0), (L, 0), and (L+B cos .gamma., B sin .gamma.), the following equality may be defined:).
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Examiner note: Examiner consider the contact model is the equation 4 which is performed by fitting a circle to the three defined borehole contact points and computing the center of the circle.
deriving a radius of a circle passing through a general curvature of the drilling tool based on the at least three contact points from the contact model using the modified fixed bend angle; (see para 38-The radius of the circle r (and therefore the radius of curvature) is defined as the distance between any one of the three points defined above and the center of the circle (e.g., as in Equation 4) and may be expressed mathematically, for example, as follows
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wherein the contact points are in a plane extending from a center point of the circle through the general curvature such that the low-side contact points are along a low-side curvature line and the high-side contact points are along a high-side curvature line, the high-side curvature line being closer to the center point than the low- side curvature line; (see fig 2, 4, 6-7 and para 0034-0038 The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points). Those of ordinary skill will readily appreciate that there are many suitable ways to determine the equation of a circle that passes through three defined points. For example, the coordinates of the points may be substituted into the general form of a circle to solve for the coefficients using various numerical methods (the general form of the circle being: x2+y2+Dx+Ey+F=0). Alternatively, one may use the center radius form of the circle and the fact that each point on a circle is equidistant from the center. Using the three points defined above (0, 0), (L, 0), and (L+B cos γ, B sin γ). See also para 0046-0047)
inputting the radius into a DLS model; and deriving the modeled the DLS of the borehole. (SEE para 39- The dogleg severity DLS may be expressed in terms of the radius in wellbore units of degrees per 100 feet of wellbore measured depth, for example, as follows:
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Examiner note: Examiner consider the model in the form of formula or equations. The current application has expressed all the models in terms of formula or equation and thus the examiner interprets the equation as modeled DLS.
Parkin does not teach
a method of building a drilling tool for drilling a borehole with a desired dogleg severity (DLS) as part of a drilling operation;
modeling a modeled DLS of the borehole drillable with the drilling tool comprising:
inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior;
comparing the modeled DLS with the desired DLS and if there is a difference, adjusting at least one of the drilling tool parameters or the load parameters based on the difference between the modeled DLS and the desired DLS until the modeled DLS confirms that drilling tool having the drilling tool parameters and the load parameters can provide the desired DLS for the drilling operation; and building the drilling tool according to the drilling tool parameters and the load parameters that can provide the desired DLS.
In the related field of invention, Oliver teaches a method of building a drilling tool for drilling a borehole with a desired dogleg severity (DLS) as part of a drilling operation, (see para 92-The invention also facilitates designing a drilling tool assembly having enhanced drilling performance, and may be used determine optimal drilling operating parameters for improving the drilling performance of a selected drilling tool assembly. See claim 2-wherein the desired wellbore trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
modeling a modeled DLS of the borehole drillable with the drilling tool, (see abstract-A drilling simulation is performed to determine the dynamic response of the drilling tool assembly during a drilling operation. See para 82 and fig 13B, 15-A scale 570 is used to quantify the dogleg severity of the well bore 571.) comprising:
comparing the modeled DLS with the desired DLS and if there is a difference, adjusting at least one of the drilling tool parameters or the load parameters based on the difference between the modeled DLS and the desired DLS until the modeled DLS confirms that drilling tool having the drilling tool parameters and the load parameters can provide the desired DLS for the drilling operation (see fig 15 and para 61-64 - This iterative process of obtaining post-run drilling information and evaluating it to define additional solutions may be repeated to further improve drilling performance with each use of a solution to drill a well. In one embodiment, the post-run drilling information may be compared to the drilling simulation to calibrate the model. FIG. 15 shows a tabular output of the well bore geometry from the drilling simulation(see dogleg severity data) The data in FIG. 15 is compared to the previously entered offset well data in FIG. 13. FIG. 16 graphs depth versus inclination angle. The target is to be less than 5 degrees at 5,000 feet. The prediction from the drilling simulation shows that the well bore would have a 6.7 degree inclination at 5,000 feet, which means that potential solutions are needed by the drilling operator to drill the desired well bore. See para 89-Potential solution may be to only adjust drilling operating parameters, such as RPM and WOB, to achieve the desired drilling performance. See claim 2-wherein the desired wellborn trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
and building the drilling tool according to the drilling tool parameters and the load parameters that can provide desired DLS. (See para 60-The potential solution resulting in a simulated response that best satisfies the selected drilling performance criterion is selected and proposed as the solution for improving drilling performance. Typically, at least one drilling performance criterion is selected from drilling performance parameters and used as a metric for the solutions defined from the analysis of drilling information. See para 79-A method for evaluating drilling information to improve drilling performance is used to predict the direction of drilling and adjustments are made to the proposed drilling tool assembly to obtain a desired well trajectory. see para 92-The invention also facilitates designing a drilling tool assembly having enhanced drilling performance, and may be used determine optimal drilling operating parameters for improving the drilling performance of a selected drilling tool assembly. See claim 2-wherein the desired wellborn trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
Therefore, it would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify the methods for Estimating Wellbore Gauge and Dogleg Severity as disclosed by Parkin to include modeling a modeled DLS of the borehole drillable with the drilling tool comprising: comparing the modeled DLS with the desired DLS and if different, adjusting at least one of the drilling tool parameters or the load parameters until the modeled DLS satisfies the desired DLS and building the drilling tool according to the drilling tool parameters and the load parameters that can provide the desired DLS as taught by Oliver in the system of Parkin for improving drilling performance of a drilling tool assembly in a series of wells, it may later be determined that drilling problems may have been better corrected by changing other parameters of the drilling tool assembly, such as operating parameters for drilling or the makeup of the BHA to avoid or minimize vibration modes of the drilling tool assembly during drilling. (See Abstract and para 15, Oliver)
However, the combination of Parkin and Oliver does not teach inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior;
In the related field of invention, Samuel teaches inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior; (See Samuel page 30- For their model, Murphy and Cheatham used elastic beam-column theory and the anisotropic formation work from Lubinski and Woods to find the equilibrium angle. They then expanded the analysis to include the rate of angle change, thus going beyond the constant angle analysis of earlier publications. They included formation heterogeneity characteristics, drill collar dimensions (and thus drill collar stiffness), drill collar – wellbore clearance and WOB. See also Page 64-72 and fig 25-26-The report on the proposed model can be broken into three parts. The first portion covers a static BHA model which was developed based on finite element analysis theory. The static model is intended to be used in both slide and rotation course lengths if necessary. Finally, the model is optimized while drilling ahead to further refine the directional response. In Eq. 2, F1x is the applied end load, γ is the distributed load and β is the inclination of the element relative to vertical as illustrated in Fig. 26. In order to evaluate the BHA’s deformation as a function of its weight and an applied axial load in the form of WOB, the finite element method is used, allowing the BHA to be divided into smaller intervals called elements. Finite element modeling can easily handle complex or changing element geometries as well as producing a more stable solution. Finite element theory allows for an evenly distributed load (drill collar weight in this case) to be replaced with equivalent point loads at the end of an element. Thus, for an inclined beam with a distributed load, Eq. 3 which is based on Fig. 26.)
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While model accuracy is desired, the program is intended for eventual field use. Thus, the model should be able to accurately function with basic inputs from field operations. The model inputs include basic BHA, survey and wellbore information as well as advanced inputs such as Young’s Modulus. The basic information is required from the user every time the program is run, while the advanced inputs are set at standard values with should not need to be changed for most operations. see page 64-72-When Eq. 1 is solved for v(x), the result is a curve which describes the deflection in the y direction in Fig. 25. The assumptions for this theory include that rotation of the beam is much smaller than the translation of the beam, the cross-section of the beam at any point is always at a right angle to the axis at that point)
Therefore, it would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify the method of determining the modeled dogleg severity as disclosed by Parkin and Oliver to include inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior as taught by Samuel in the system of Parkin and Oliver in order to research into the effect of mechanical specific energy or MSE on the overall wellbore direction change or dog-leg severity. Using published experimental data, a correlation was developed which shows a clear relationship between the dog-leg severity, rate of penetration (ROP) and MSE. The correlation requires only a few hundred feet of drilling before it is able to be tuned to match an individual well’s results. With minimal tuning throughout the drilling of a well, very good results can be obtained with regards to forecasting dog-leg severity as the wellbores were drilled ahead. The correlation was tested using data from multiple, geo-steered wells drilled in a shale reservoir. The analysis of the correlation using real-world data proved it to be a robust and accurate method of predicting the magnitude of dog-leg severity. The use of this correlation results in a smoother wellbore, drilled with a faster overall ROP with a better chance of staying within the geologic targets. (See Abstract, Samuel)
Regarding claim 4 and 14
Parkin further teaches drilling the borehole using the drilling tool. (see para 18-FIG. 1 depicts a drilling rig 20 suitable for using various method embodiments disclosed herein. A semisubmersible drilling platform 12 is positioned over an oil or gas formation (not shown) disposed below the sea floor 16. A subsea conduit 18 extends from deck 20 of platform 12 to a wellhead installation 22. The platform may include a derrick and a hoisting apparatus for raising and lowering a drill string 30, which, as shown, extends into wellbore 40 and includes a drill bit 32 and a downhole tool 50 (such as a rotary steerable))
Regarding claim 5 and 16
Parkin further teaches wherein the tool parameters comprise a diameter of the drill bit coupled to the drilling tool, a diameter of the drilling tool, a diameter of the drilling tool at a first contact point, a diameter of the drilling tool at a second contact point, a distance from a focal point of drilling tool to a bit box, a length of the drill bit, a distance between the first contact point to the focal point, an angular inclination of the drill bit from the focal point, an angular inclination of the second contact point from the focal point, or any subset thereof.(see para 25- the lower tool body section may be tilted towards a first toolface direction such as high side, low side, left side, or right side of the wellbore with respect to the upper tool body section). The axial direction is then measured at 106 when the universal joint is tilted to a second cross-axial angular position (e.g., when the lower tool body section is tilted towards a toolface angle 180 degrees offset from the first angular position in 104). These axial directions may be measured for example using conventional wellbore inclination and wellbore azimuth measurements. see para 46- Assuming that the upper and lower stabilizers have equal diameters, the center of the lower stabilizer may be defined as being horizontally offset from the center of the upper stabilizer by a distance L (the axial separation distance between the stabilizers) and vertically offset from the center of the upper stabilizer by a distance -L sin(.alpha./2) at (L, -L sin(.alpha./2)) where a represents the change in axial direction of the upper tool body section (see FIG. 7). The center of the drill bit may then be defined as being located at (L+B cos .gamma., B sin .gamma.-L sin(.alpha./2)), where, as defined above, B represents the axial separation distance between the lower stabilizer and the drill bit and .gamma. Represents the average tilt angle.
Regarding claim 6 and 17
Parkin does not teach wherein the load parameters comprise a density of the drilling tool material, a density of drilling fluid used, a cross-sectional area of the drilling tool, an area moment of inertia of the drilling tool, a hole-inclination degree, or any subset thereof.
However, Oliver further teaches wherein the load parameters comprise a density of the drilling tool material, a density of drilling fluid used, a cross-sectional area of the drilling tool, an area moment of inertia of the drilling tool, a hole-inclination degree, or any subset thereof. (See para 48- Examples of drilling performance parameters include rate of penetration (ROP), rotary torque required to turn the drilling tool assembly, rotary speed at which the drilling tool assembly is turned, drilling tool assembly lateral, axial, or torsional vibrations induced during drilling, weight on bit (WOB), forces acting on components of the drilling tool assembly, and forces acting on the drill bit and components of the drill bit (e.g., on blades, cones, and/or cutting elements). Drilling performance parameters may also include the inclination angle and azimuth direction of the borehole being drilled. See also para 53-Examples of drilling tool assembly design parameters include the type, location, and number of components included in the drilling tool assembly; the length, ID, OD, weight, and material properties of each component; the type, size, weight, configuration, and material properties of the drill bit; and the type, size, number, location, orientation, and material properties of the cutting elements on the drill bit. Material properties in designing a drilling tool assembly may include, for example, the strength, elasticity, and density of the material. It should be understood that drilling tool assembly design parameters may include any other configuration or material parameter of the drilling tool assembly without departing from the scope of the invention.)
Regarding claim 9, 18 and 21
Parkin further teaches wherein the DLS model defines DLS as a function of the radius. (See para 39 and equation 6)
Regarding claim 10 and 19
Parkin further teaches generating the general curvature comprises:
determining the first curvature line defined by the center point of a first circle passing through contact points on the low-side contact points; and determining the high side curvature line defined by the center point of a second circle passing through the high-side contact points; (see para 32-38 and fig6- the upper and lower stabilizers 62 and 64 and upper and lower tool body sections 52 and 54 are depicted as stick figures in wellbore 40. The solid lined depiction shows the tool when the tilt angle is rotated to a first angular position (at 54) in the direction of the wellbore curvature and the dashed line depiction shows the tool when the tilt angle is rotated to a second angular position (at 56) opposed to the wellbore curvature (180 degrees offset from the wellbore curvature). With continued reference to FIG. 6, tilting the lower tool body section 54 with respect to the upper tool body section 52 may cause the upper and lower stabilizers 62 and 64 to contact the wellbore wall on the opposite sides of the wellbore. As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore (yet continue to contact the wellbore wall on opposite sides of the wellbore). Owing to the clearance between the lower stabilizer 64 and the wellbore wall (i.e., since the lower stabilizer is slightly under gauge) rotation of the tilt angle causes a change in the magnitude of the tilt angle (the tilt angles are denoted as beta1 and beta2 in FIG. 6). As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore. See also para 46-47)
Examiner note: Examiner consider the upper stabilizer 62 when the tilt angle is rotated to a first angular position (at 54) in the direction of the wellbore curvature corresponds to the first curvature and lower stabilizer 64 tool when the tilt angle is rotated to a second angular position (at 56) opposed to the wellbore curvature (180 degrees offset from the wellbore curvature corresponds to the second curvature see fig 6.
deriving the radius of the general curvature comprises:
determining a first radius of the low-side curvature line; determining a second radius of the high-side curvature line; and determining the average of the first and second radii. (See para 34-39 -As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore (yet continue to contact the wellbore wall on opposite sides of the wellbore). Owing to the clearance between the lower stabilizer 64 and the wellbore wall (i.e., since the lower stabilizer is slightly under gauge) rotation of the tilt angle causes a change in the magnitude of the tilt angle (the tilt angles are denoted as beta1 and beta2 in FIG. 6). The center of the wellbore at the drill bit may then be defined as being located at (L+B cos .gamma., B sin .gamma.), where L represents an axial length of the first tool body section, B represents the axial separation distance between the lower stabilizer and the drill bit and .gamma. Represents the average tilt angle as indicated above. The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points. )
Examiner note: Under the broadest reasonable sense, examiner consider the first curvature with the beta1 angle helps to determine the first curvature radius and the second curvature with the beta2 angle corresponds to the second curvature radius. The average of beta1 and beta2 is the tilt angle (gamma) which helps to determine the average radii.
Regarding claim 11
Parkin teaches a drilling tool including the defined contact points and an undefined contact points wherein the drilling tool contact the borehole include low-side contact points, high-side contact points, or combination thereof and for drilling a borehole; (see fig 1-2, 4 see para 41- the upper and lower stabilizers are not always on opposite sides of the wellbore; for example, in a high dogleg section there may be sufficient bending moment in the upper tool body section 52 (depending on the stiffness of the BHA) such that the upper stabilizer may be constrained to remain on the outside of the curve (e.g., as depicted on FIG. 7). See para 46-The center of the lower stabilizer may be defined as being horizontally offset from the center of the upper stabilizer by a distance L (the axial separation distance between the stabilizers) and vertically offset from the center of the upper stabilizer by a distance -L sin(.alpha./2) at (L, -L sin(.alpha./2)) where a represents the change in axial direction of the upper tool body section (see FIG. 7). The center of the drill bit may then be defined as being located at (L+B cos .gamma., B sin .gamma.-L sin(.alpha./2)),))
Examiner note: Examiner consider the fig 7 is the condition of undefined contact points since there is no stabilizer attached to the upper curve. Examiner consider the point (L, -L sin(.alpha./2)) is the first contact point which is obtained through previously undefined contact points of upper curve.
defining a first contact point of the drilling tool, wherein the first contact point is the previously undefined contact point;( see para 41- the upper and lower stabilizers are not always on opposite sides of the wellbore; for example, in a high dogleg section there may be sufficient bending moment in the upper tool body section 52 (depending on the stiffness of the BHA) such that the upper stabilizer may be constrained to remain on the outside of the curve (e.g., as depicted on FIG. 7). See para 46-The center of the lower stabilizer may be defined as being horizontally offset from the center of the upper stabilizer by a distance L (the axial separation distance between the stabilizers) and vertically offset from the center of the upper stabilizer by a distance -L sin(.alpha./2) at (L, -L sin(.alpha./2)) where a represents the change in axial direction of the upper tool body section (see FIG. 7). The center of the drill bit may then be defined as being located at (L+B cos .gamma., B sin .gamma.-L sin(.alpha./2)),)
Examiner note: Examiner consider the fig 7 is the condition of undefined contact points since there is no stabilizer attached to the upper curve. Examiner consider the point (L, -L sin(.alpha./2)) is the first contact point which is obtained through previously undefined contact points of upper curve.
determining a length between the first contact point and a focal point of a fixed angle of the drilling tool; (see para 31- the tilt angle between the lower tool body section and the upper tool body section is measured at 154 at a first angular position (e.g., when the tilt angle is oriented at a first rotational position such as high side, low side, left side, or right side of the wellbore). The tilt angle between the lower tool body section and the upper tool body section is then measured at 156 when the tilt angle is rotated to a second angular position (e.g., 180 degrees offset from the first angular position). These tilt angles may be measured, for example, using strain gauges deployed in (or near to) the universal joint. The tilt angles are processed at 158 to compute an average (mean) of the two which is in turn processed. SEE PARA 46-B represents the axial separation distance between the lower stabilizer and the drill bit.)
an angular rotation causes a drill bit of the drilling tool to change direction by effectively modifying the fixed bend angle depending on contact of the contact points with the borehole; (see para 22- The tool 50 may further include one or more motors or pistons (not shown) configured to actively tilt the lower tool body section 54 about the universal joint 56 with respect to the upper tool body section 52. For example, pistons acting on the periphery of the lower tool body section 54 may be employed to tilt the lower tool body section 54 (and the drill bit 32 connected thereto) with respect to the upper tool body section 52. In rotary steerable embodiments, such pistons may be sequentially actuated while rotating the drill string such that the tilt of the drill bit is actively maintained in the desired direction (toolface) with respect to the formation being drilled. see para 31-32 and fig 5-6-The tilt angle between the lower tool body section and the upper tool body section is measured at 154 at a first angular position (e.g., when the tilt angle is oriented at a first rotational position such as high side, low side, left side, or right side of the wellbore). The tilt angle between the lower tool body section and the upper tool body section is then measured at 156 when the tilt angle is rotated to a second angular position (e.g., 180 degrees offset from the first angular position). These tilt angles may be measured, for example, using strain gauges deployed in (or near to) the universal joint. The tilt angles are processed at 158 to compute an average (mean) of the two which is in turn processed at 160 to compute the dogleg severity. The solid lined depiction shows the tool when the tilt angle is rotated to a first angular position (at 154) in the direction of the wellbore curvature and the dashed line depiction shows the tool when the tilt angle is rotated to a second angular position (at 156) opposed to the wellbore curvature (180 degrees offset from the wellbore curvature).)
inputting the angular rotation into a contact model as a modified fixed bend angle, wherein the contact model includes the contact points; (see para 31- the tilt angle between the lower tool body section and the upper tool body section is measured at 154 at a first angular position (e.g., when the tilt angle is oriented at a first rotational position such as high side, low side, left side, or right side of the wellbore). The tilt angle between the lower tool body section and the upper tool body section is then measured at 156 when the tilt angle is rotated to a second angular position (e.g., 180 degrees offset from the first angular position). These tilt angles may be measured, for example, using strain gauges deployed in (or near to) the universal joint. The tilt angles are processed at 158 to compute an average (mean) of the two which is in turn processed. see para 34-37- The center of the wellbore at the drill bit may then be defined as being located at (L+B cos gamma, B sin .gamma.), where B represents the axial separation distance between the lower stabilizer and the drill bit and .gamma. represents the average tilt angle. The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points alternatively, one may use the center radius form of the circle and the fact that each point on a circle is equidistant from the center. Using the three points defined above (0, 0), (L, 0), and (L+B cos .gamma., B sin .gamma.), the following equality may be defined:).
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Examiner note: Examiner consider the contact model is the equation 4 which is performed by fitting a circle to the three points and computing the center of the circle.
deriving a radius of a circle passing through a general curvature of the drilling tool based on the at least three contact points from the contact model using the modified fixed bend angle; (see para 38-The radius of the circle r (and therefore the radius of curvature) is defined as the distance between any one of the three points defined above and the center of the circle (e.g., as in Equation 4) and may be expressed mathematically, for example, as follows
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wherein the contact points are in a plane extending from a center point of the circle through the general curvature such that the low-side contact points are along a low-side curvature line and the high-side contact points are along a high-side curvature line, the high-side curvature line being closer to the center point than the low- side curvature line; (see fig 2, 4, 6-7 and para 0034-0038 The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points). Those of ordinary skill will readily appreciate that there are many suitable ways to determine the equation of a circle that passes through three defined points. For example, the coordinates of the points may be substituted into the general form of a circle to solve for the coefficients using various numerical methods (the general form of the circle being: x2+y2+Dx+Ey+F=0). Alternatively, one may use the center radius form of the circle and the fact that each point on a circle is equidistant from the center. Using the three points defined above (0, 0), (L, 0), and (L+B cos γ, B sin γ). See also para 0046-0047)
inputting the radius into a DLS model; and deriving the modeled the DLS of the borehole.(SEE para 39- The dogleg severity DLS may be expressed in terms of the radius in wellbore units of degrees per 100 feet of wellbore measured depth, for example, as follows:
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Examiner note: Examiner consider the model in the form of formula or equations. The current application has expressed all the models in terms of formula or equation and thus the examiner interprets the equation as modeled DLS.
Parkin does not teach
a method of building a drilling tool for drilling a borehole with a desired dogleg severity (DLS) as part of a drilling operation;
modeling a modeled DLS of the borehole drillable with the drilling tool comprising:
inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior;
comparing the modeled DLS with the desired DLS and if there is a difference, adjusting at least one of the drilling tool parameters or the load parameters based on the difference between the modeled DUS and the desired DLS until the modeled DLS confirms that drilling tool having the drilling tool parameters and the load parameters can provide the desired DLS for the drilling operation; and building the drilling tool according to the drilling tool parameters and the load parameters that can provide the desired DLS.
In the related field of invention, Oliver teaches a method of building a drilling tool for drilling a borehole with a desired dogleg severity (DLS) as part of a drilling operation, (see para 92-The invention also facilitates designing a drilling tool assembly having enhanced drilling performance, and may be used determine optimal drilling operating parameters for improving the drilling performance of a selected drilling tool assembly. See claim 2-wherein the desired wellbore trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
modeling a modeled DLS of the borehole drillable with the drilling tool, (see abstract-A drilling simulation is performed to determine the dynamic response of the drilling tool assembly during a drilling operation. See para 82 and fig 13B, 15-A scale 570 is used to quantify the dogleg severity of the well bore 571.) comprising:
comparing the modeled DLS with the desired DLS and if there is a difference, adjusting at least one of the drilling tool parameters or the load parameters based on the difference between the modeled DUS and the desired DLS until the modeled DLS confirms that drilling tool having the drilling tool parameters and the load parameters can provide the desired DLS for the drilling operation; (see fig 15 and para 61-64 - This iterative process of obtaining post-run drilling information and evaluating it to define additional solutions may be repeated to further improve drilling performance with each use of a solution to drill a well. In one embodiment, the post-run drilling information may be compared to the drilling simulation to calibrate the model. FIG. 15 shows a tabular output of the well bore geometry from the drilling simulation(see dogleg severity data) The data in FIG. 15 is compared to the previously entered offset well data in FIG. 13. FIG. 16 graphs depth versus inclination angle. The target is to be less than 5 degrees at 5,000 feet. The prediction from the drilling simulation shows that the well bore would have a 6.7 degree inclination at 5,000 feet, which means that potential solutions are needed by the drilling operator to drill the desired well bore. See para 89-Potential solution may be to only adjust drilling operating parameters, such as RPM and WOB, to achieve the desired drilling performance. See claim 2-wherein the desired wellborn trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
and building the drilling tool according to the drilling tool parameters and the load parameters that can provide desired DLS. (See para 60-The potential solution resulting in a simulated response that best satisfies the selected drilling performance criterion is selected and proposed as the solution for improving drilling performance. Typically, at least one drilling performance criterion is selected from drilling performance parameters and used as a metric for the solutions defined from the analysis of drilling information. See para 79-A method for evaluating drilling information to improve drilling performance is used to predict the direction of drilling and adjustments are made to the proposed drilling tool assembly to obtain a desired well trajectory. see para 92-The invention also facilitates designing a drilling tool assembly having enhanced drilling performance, and may be used determine optimal drilling operating parameters for improving the drilling performance of a selected drilling tool assembly. See claim 2-wherein the desired wellborn trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
Therefore, it would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify the methods for Estimating Wellbore Gauge and Dogleg Severity as disclosed by Parkin to include modeling a modeled DLS of the borehole drillable with the drilling tool comprising: comparing the modeled DLS with the desired DLS and if different, adjusting at least one of the drilling tool parameters or the load parameters until the modeled DLS satisfies the desired DLS and building the drilling tool according to the drilling tool parameters and the load parameters that can provide the desired DLS as taught by Oliver in the system of Parkin for improving drilling performance of a drilling tool assembly in a series of wells, it may later be determined that drilling problems may have been better corrected by changing other parameters of the drilling tool assembly, such as operating parameters for drilling or the makeup of the BHA to avoid or minimize vibration modes of the drilling tool assembly during drilling. (See Abstract and para 15, Oliver)
However, the combination of Parkin and Oliver does not teach inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior;
In the related field of invention, Samuel teaches inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior; (See Samuel page 30- For their model, Murphy and Cheatham used elastic beam-column theory and the anisotropic formation work from Lubinski and Woods to find the equilibrium angle. They then expanded the analysis to include the rate of angle change, thus going beyond the constant angle analysis of earlier publications. They included formation heterogeneity characteristics, drill collar dimensions (and thus drill collar stiffness), drill collar – wellbore clearance and WOB. See also Page 64-72 and fig 25-26-The report on the proposed model can be broken into three parts. The first portion covers a static BHA model which was developed based on finite element analysis theory. The static model is intended to be used in both slide and rotation course lengths if necessary. Finally, the model is optimized while drilling ahead to further refine the directional response. In Eq. 2, F1x is the applied end load, γ is the distributed load and β is the inclination of the element relative to vertical as illustrated in Fig. 26. In order to evaluate the BHA’s deformation as a function of its weight and an applied axial load in the form of WOB, the finite element method is used, allowing the BHA to be divided into smaller intervals called elements. Finite element modeling can easily handle complex or changing element geometries as well as producing a more stable solution. Finite element theory allows for an evenly distributed load (drill collar weight in this case) to be replaced with equivalent point loads at the end of an element. Thus, for an inclined beam with a distributed load, Eq. 3 which is based on Fig. 26.)
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While model accuracy is desired, the program is intended for eventual field use. Thus, the model should be able to accurately function with basic inputs from field operations. The model inputs include basic BHA, survey and wellbore information as well as advanced inputs such as Young’s Modulus. The basic information is required from the user every time the program is run, while the advanced inputs are set at standard values with should not need to be changed for most operations. See also page 64-72-When Eq. 1 is solved for v(x), the result is a curve which describes the deflection in the y direction in Fig. 25. The assumptions for this theory include that rotation of the beam is much smaller than the translation of the beam, the cross-section of the beam at any point is always at a right angle to the axis at that point)
Therefore, it would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify the method of determining the modeled dogleg severity as disclosed by Parkin and Oliver to include inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior as taught by Samuel in the system of Parkin and Oliver in order to research into the effect of mechanical specific energy or MSE on the overall wellbore direction change or dog-leg severity. Using published experimental data, a correlation was developed which shows a clear relationship between the dog-leg severity, rate of penetration (ROP) and MSE. The correlation requires only a few hundred feet of drilling before it is able to be tuned to match an individual well’s results. With minimal tuning throughout the drilling of a well, very good results can be obtained with regards to forecasting dog-leg severity as the wellbores were drilled ahead. The correlation was tested using data from multiple, geo-steered wells drilled in a shale reservoir. The analysis of the correlation using real-world data proved it to be a robust and accurate method of predicting the magnitude of dog-leg severity. The use of this correlation results in a smoother wellbore, drilled with a faster overall ROP with a better chance of staying within the geologic targets. (See Abstract, Samuel)
Regarding claim 15
Parkin further teaches wherein defining the first contact point comprises: determining the first contact point from the radius of the circle. (See para 36- using three points defined (0, 0), (L, 0) and
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The combination of Parkin and Oliver does not teach determining a known or selected diameter of the drilling tool.
In the related of field of invention, Samuel further teaches determining a known or selected diameter of the drilling tool. (see page 28-For various values of WOB (lines on graph), one can determine whether the BHA should build, hold or drop. One of the primary findings was that the use of the largest possible OD (outer diameter) drill collars was the recommended way to reduce overall DLS and maintain a near-vertical well. The large OD, and thus less flexible drill collars, increased the distance from the point of tangency to the bit, thus reducing the build tendency.)
Regarding claim 20
Parkin teaches a drilling tool with a fixed bend angle comprising a focal point for drilling a borehole; (see para 40 and fig 1- FIG. 4 depicts a schematic of a downhole tool deployed in a deviated wellbore suitable for implementing the method depicted on FIG. 3. For example, the upper and lower stabilizers 62 and 64 and upper and lower tool body sections 52 and 54 are depicted as stick figures in wellbore 40. See also para 27- With continued reference to FIG. 4, tilting the lower tool body section 54 with respect to the upper tool body section 52 may cause the upper and lower stabilizers 62 and 64 to contact the wellbore wall on the opposite sides of the wellbore. As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore. See para 22-The tool 50 may further include one or more motors or pistons (not shown) configured to actively tilt the lower tool body section 54 about the universal joint 56 with respect to the upper tool body section 52.)
obtaining contact points where the drilling tool contacts the borehole relative to an origin defined on the tool body, wherein the contact points include low-side contact points, high-side contact points, or combination thereof and for drilling a borehole;; (see fig 1-2, 4 and para 33-34- With continued reference to FIG. 6, tilting the lower tool body section 54 with respect to the upper tool body section 52 may cause the upper and lower stabilizers 62 and 64 to contact the wellbore wall on the opposite sides of the wellbore. As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore. For example, the average angle may be processed to define three points along the axis of the wellbore. These points may be defined in substantially any coordinate system. For example, a two-dimensional coordinate system may be defined in which the center of the wellbore at the upper stabilizer is defined as being at the origin (0, 0). The center of the wellbore at the lower stabilizer may then be defined as being horizontally offset from the center of the upper stabilizer by a distance L (the axial separation distance between the stabilizers) at (L, 0).)
an angular rotation causes a drill bit of the drilling tool to change direction by effectively modifying the fixed bend angle depending on contact on the contact points with the borehole; (see para 22- The tool 50 may further include one or more motors or pistons (not shown) configured to actively tilt the lower tool body section 54 about the universal joint 56 with respect to the upper tool body section 52. For example, pistons acting on the periphery of the lower tool body section 54 may be employed to tilt the lower tool body section 54 (and the drill bit 32 connected thereto) with respect to the upper tool body section 52. In rotary steerable embodiments, such pistons may be sequentially actuated while rotating the drill string such that the tilt of the drill bit is actively maintained in the desired direction (toolface) with respect to the formation being drilled. see para 31-32 and fig 5-6-The tilt angle between the lower tool body section and the upper tool body section is measured at 154 at a first angular position (e.g., when the tilt angle is oriented at a first rotational position such as high side, low side, left side, or right side of the wellbore). The tilt angle between the lower tool body section and the upper tool body section is then measured at 156 when the tilt angle is rotated to a second angular position (e.g., 180 degrees offset from the first angular position). These tilt angles may be measured, for example, using strain gauges deployed in (or near to) the universal joint. The tilt angles are processed at 158 to compute an average (mean) of the two which is in turn processed at 160 to compute the dogleg severity. The solid lined depiction shows the tool when the tilt angle is rotated to a first angular position (at 154) in the direction of the wellbore curvature and the dashed line depiction shows the tool when the tilt angle is rotated to a second angular position (at 156) opposed to the wellbore curvature (180 degrees offset from the wellbore curvature).)
inputting the angular rotation into a contact model as a modified fixed bend angle, where the contact model includes the contact points; (see para 31- the tilt angle between the lower tool body section and the upper tool body section is measured at 154 at a first angular position (e.g., when the tilt angle is oriented at a first rotational position such as high side, low side, left side, or right side of the wellbore). The tilt angle between the lower tool body section and the upper tool body section is then measured at 156 when the tilt angle is rotated to a second angular position (e.g., 180 degrees offset from the first angular position.) These tilt angles may be measured, for example, using strain gauges deployed in (or near to) the universal joint. The tilt angles are processed at 158 to compute an average (mean) of the two which is in turn processed. see para 34-37- The center of the wellbore at the drill bit may then be defined as being located at (L+B cos gamma, B sin .gamma.), where B represents the axial separation distance between the lower stabilizer and the drill bit and .gamma. represents the average tilt angle. The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points alternatively, one may use the center radius form of the circle and the fact that each point on a circle is equidistant from the center. Using the three points defined above (0, 0), (L, 0), and (L+B cos .gamma., B sin .gamma.), the following equality may be defined:).
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Examiner note: Examiner consider the contact model is the equation 4 which is performed by fitting a circle to the three points and computing the center of the circle.
deriving a radius of a circle passing through a general curvature of the drilling tool formed at least three of the contact points from the contact model using the modified fixed bend angle; (see para 38-The radius of the circle r (and therefore the radius of curvature) is defined as the distance between any one of the three points defined above and the center of the circle (e.g., as in Equation 4) and may be expressed mathematically, for example, as follows
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wherein the contact points are in a plane extending from a center point of the circle through the general curvature such that the low-side contact points are along a low-side curvature line and the high-side contact points are along a high-side curvature line, the high-side curvature line being closer to the center point than the low- side curvature line; (see fig 2, 4, 6-7 and para 0034-0038 The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points). Those of ordinary skill will readily appreciate that there are many suitable ways to determine the equation of a circle that passes through three defined points. For example, the coordinates of the points may be substituted into the general form of a circle to solve for the coefficients using various numerical methods (the general form of the circle being: x2+y2+Dx+Ey+F=0). Alternatively, one may use the center radius form of the circle and the fact that each point on a circle is equidistant from the center. Using the three points defined above (0, 0), (L, 0), and (L+B cos γ, B sin γ). See also para 0046-0047)
inputting the radius into a DLS model; and deriving the modeled the DLS of the borehole.(SEE para 39- The dogleg severity DLS may be expressed in terms of the radius in wellbore units of degrees per 100 feet of wellbore measured depth, for example, as follows:
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Examiner note: Examiner consider the model in the form of formula or equations. The current application has expressed all the models in terms of formula or equation and thus the examiner interprets the equation as modeled DLS.
drilling the borehole using the drilling tool. (see para 18-FIG. 1 depicts a drilling rig 20 suitable for using various method embodiments disclosed herein. A semisubmersible drilling platform 12 is positioned over an oil or gas formation (not shown) disposed below the sea floor 16. A subsea conduit 18 extends from deck 20 of platform 12 to a wellhead installation 22. The platform may include a derrick and a hoisting apparatus for raising and lowering a drill string 30, which, as shown, extends into wellbore 40 and includes a drill bit 32 and a downhole tool 50 (such as a rotary steerable))
Parkin does not teach
a method of building and using a drilling tool for drilling a borehole with a desired dogleg severity (DLS) as part of a drilling operation;
modeling a modeled DLS of the borehole drillable with the drilling tool comprising:
inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit and distributed load of the drilling tool into a beam bending model, the beam bending model models bending effects of the drilling tool during the drilling operation to solve for angular rotation at the focal point by superimposing bending moments due to weight on bit and distributed load of the drilling tool based on beam deflection behavior; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior; comparing the modeled DLS with the desired DLS and if there is a difference, adjusting at least one of the drilling tool parameters or the load parameters based on the difference between the modeled DUS and the desired DLS until the modeled DLS confirms that drilling tool having the drilling tool parameters and the load parameters can provide the desired DLS for the drilling operation; and building the drilling tool according to the drilling tool parameters and the load parameters that can provide the desired DLS.
In the related field of invention, Oliver teaches a method of building and using a drilling tool for drilling a borehole with a desired dogleg severity (DLS) as part of a drilling operation, (see para 92-The invention also facilitates designing a drilling tool assembly having enhanced drilling performance, and may be used determine optimal drilling operating parameters for improving the drilling performance of a selected drilling tool assembly. See claim 2-wherein the desired wellbore trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
modeling a modeled DLS of the borehole drillable with the drilling tool, (see abstract-A drilling simulation is performed to determine the dynamic response of the drilling tool assembly during a drilling operation. See para 82 and fig 13B, 15-A scale 570 is used to quantify the dogleg severity of the well bore 571.) comprising:
comparing the modeled DLS with the desired DLS and if there is a difference, adjusting at least one of the drilling tool parameters or the load parameters based on the difference between the modeled DUS and the desired DLS until the modeled DLS confirms that drilling tool having the drilling tool parameters and the load parameters can provide the desired DLS for the drilling operation; (see fig 15 and para 61-64 - This iterative process of obtaining post-run drilling information and evaluating it to define additional solutions may be repeated to further improve drilling performance with each use of a solution to drill a well. In one embodiment, the post-run drilling information may be compared to the drilling simulation to calibrate the model. FIG. 15 shows a tabular output of the well bore geometry from the drilling simulation(see dogleg severity data) The data in FIG. 15 is compared to the previously entered offset well data in FIG. 13. FIG. 16 graphs depth versus inclination angle. The target is to be less than 5 degrees at 5,000 feet. The prediction from the drilling simulation shows that the well bore would have a 6.7 degree inclination at 5,000 feet, which means that potential solutions are needed by the drilling operator to drill the desired well bore. See para 89-Potential solution may be to only adjust drilling operating parameters, such as RPM and WOB, to achieve the desired drilling performance. See claim 2-wherein the desired wellborn trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
and building the drilling tool according to the drilling tool parameters and the load parameters that satisfy the desired DLS. (See para 60-The potential solution resulting in a simulated response that best satisfies the selected drilling performance criterion is selected and proposed as the solution for improving drilling performance. Typically, at least one drilling performance criterion is selected from drilling performance parameters and used as a metric for the solutions defined from the analysis of drilling information. See para 79-A method for evaluating drilling information to improve drilling performance is used to predict the direction of drilling and adjustments are made to the proposed drilling tool assembly to obtain a desired well trajectory. see para 92-The invention also facilitates designing a drilling tool assembly having enhanced drilling performance, and may be used determine optimal drilling operating parameters for improving the drilling performance of a selected drilling tool assembly. See claim 2-wherein the desired wellborn trajectory is defined by at least one of a build angle, a dogleg severity, and a walk rate.)
Therefore, it would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify the methods for Estimating Wellbore Gauge and Dogleg Severity as disclosed by Parkin to include modeling a modeled DLS of the borehole drillable with the drilling tool comprising: comparing the modeled DLS with the desired DLS and if different, adjusting at least one of the drilling tool parameters or the load parameters until the modeled DLS satisfies the desired DLS
and building the drilling tool according to the drilling tool parameters and the load parameters that satisfy the desired DLS as taught by Oliver in the system of Parkin for improving drilling performance of a drilling tool assembly in a series of wells, it may later be determined that drilling problems may have been better corrected by changing other parameters of the drilling tool assembly, such as operating parameters for drilling or the makeup of the BHA to avoid or minimize vibration modes of the drilling tool assembly during drilling. (See Abstract and para 15, Oliver)
However, the combination of Parkin and Oliver does not teach inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation to solve for angular rotation at the focal point by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior;
In the related field of invention, Samuel teaches inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation to solve for angular rotation at the focal point by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior; (See Samuel page 30- For their model, Murphy and Cheatham used elastic beam-column theory and the anisotropic formation work from Lubinski and Woods to find the equilibrium angle. They then expanded the analysis to include the rate of angle change, thus going beyond the constant angle analysis of earlier publications. They included formation heterogeneity characteristics, drill collar dimensions (and thus drill collar stiffness), drill collar – wellbore clearance and WOB. See also Page 64-72 and fig 25-26-The report on the proposed model can be broken into three parts. The first portion covers a static BHA model which was developed based on finite element analysis theory. The static model is intended to be used in both slide and rotation course lengths if necessary. Finally, the model is optimized while drilling ahead to further refine the directional response. In Eq. 2, F1x is the applied end load, γ is the distributed load and β is the inclination of the element relative to vertical as illustrated in Fig. 26. In order to evaluate the BHA’s deformation as a function of its weight and an applied axial load in the form of WOB, the finite element method is used, allowing the BHA to be divided into smaller intervals called elements. Finite element modeling can easily handle complex or changing element geometries as well as producing a more stable solution. Finite element theory allows for an evenly distributed load (drill collar weight in this case) to be replaced with equivalent point loads at the end of an element. Thus, for an inclined beam with a distributed load, Eq. 3 which is based on Fig. 26.)
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While model accuracy is desired, the program is intended for eventual field use. Thus, the model should be able to accurately function with basic inputs from field operations. The model inputs include basic BHA, survey and wellbore information as well as advanced inputs such as Young’s Modulus. The basic information is required from the user every time the program is run, while the advanced inputs are set at standard values with should not need to be changed for most operations. see page 64-72-When Eq. 1 is solved for v(x), the result is a curve which describes the deflection in the y direction in Fig. 25. The assumptions for this theory include that rotation of the beam is much smaller than the translation of the beam, the cross-section of the beam at any point is always at a right angle to the axis at that point)
Therefore, it would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to modify the method of determining the modeled dogleg severity as disclosed by Parkin and Oliver to include inputting a set of drilling tool parameters comprising dimensions of the drilling tool and load parameters comprising weight on bit in a first direction and distributed load in a second direction of the drilling tool into a beam bending model which models bending effects of the drilling tool during the drilling operation to solve for angular rotation at the focal point by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior, wherein the first direction and the second direction are angled with respect to each other; deriving an angular rotation of the drilling tool due to the bending effects from the beam bending model by superimposing bending moments due to the weight on bit and the distributed load of the drilling tool based on beam deflection behavior as taught by Samuel in the system of Parkin and Oliver in order to research into the effect of mechanical specific energy or MSE on the overall wellbore direction change or dog-leg severity. Using published experimental data, a correlation was developed which shows a clear relationship between the dog-leg severity, rate of penetration (ROP) and MSE. The correlation requires only a few hundred feet of drilling before it is able to be tuned to match an individual well’s results. With minimal tuning throughout the drilling of a well, very good results can be obtained with regards to forecasting dog-leg severity as the wellbores were drilled ahead. The correlation was tested using data from multiple, geo-steered wells drilled in a shale reservoir. The analysis of the correlation using real-world data proved it to be a robust and accurate method of predicting the magnitude of dog-leg severity. The use of this correlation results in a smoother wellbore, drilled with a faster overall ROP with a better chance of staying within the geologic targets. (See Abstract, Samuel)
Regarding claim 22
Parkin further teaches wherein the general curvature is defined by the center point of the circle passing through the contact points.(see para 31- The tilt angle between the lower tool body section and the upper tool body section is measured at 54 at a first angular position (e.g., when the tilt angle is oriented at a first rotational position such as high side, low side, left side, or right side of the wellbore. See also- The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points))
Regarding claim 24
Parkin further teaches finding the general curvature comprises:
finding the low-side curvature line defined by the center point of a first circle passing through the low-side contact points; and finding the high-side curvature line defined by the center point of a second circle passing through the high-side contact points; (see para 32-38 and fig6- the upper and lower stabilizers 62 and 64 and upper and lower tool body sections 52 and 54 are depicted as stick figures in wellbore 40. The solid lined depiction shows the tool when the tilt angle is rotated to a first angular position (at 54) in the direction of the wellbore curvature and the dashed line depiction shows the tool when the tilt angle is rotated to a second angular position (at 56) opposed to the wellbore curvature (180 degrees offset from the wellbore curvature). With continued reference to FIG. 6, tilting the lower tool body section 54 with respect to the upper tool body section 52 may cause the upper and lower stabilizers 62 and 64 to contact the wellbore wall on the opposite sides of the wellbore. As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore (yet continue to contact the wellbore wall on opposite sides of the wellbore). Owing to the clearance between the lower stabilizer 64 and the wellbore wall (i.e., since the lower stabilizer is slightly under gauge) rotation of the tilt angle causes a change in the magnitude of the tilt angle (the tilt angles are denoted as beta1 and beta2 in FIG. 6). As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore. See also para 46-47)
Examiner note: Examiner consider the upper stabilizer 62 when the tilt angle is rotated to a first angular position (at 54) in the direction of the wellbore curvature corresponds to the first curvature and lower stabilizer 64 tool when the tilt angle is rotated to a second angular position (at 56) opposed to the wellbore curvature (180 degrees offset from the wellbore curvature corresponds to the second curvature see fig 6.
Regarding claim 25
Parkin further teaches determining the radius of the general curvature comprises:
determining a first radius of the low-side curvature line; determining a second radius of the high-side curvature line; and determining the average of the first and second radii. (See para 34-38 and fig 6 -As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore (yet continue to contact the wellbore wall on opposite sides of the wellbore). Owing to the clearance between the lower stabilizer 64 and the wellbore wall (i.e., since the lower stabilizer is slightly under gauge) rotation of the tilt angle causes a change in the magnitude of the tilt angle (the tilt angles are denoted as beta1 and beta2 in FIG. 6). The center of the wellbore at the drill bit may then be defined as being located at (L+B cos .gamma., B sin .gamma.), where L represents an axial length of the first tool body section, B represents the axial separation distance between the lower stabilizer and the drill bit and .gamma. Represents the average tilt angle as indicated above. The dogleg severity may then be computed, for example, by fitting a circle to the three points and computing the radius of the circle (the radius giving the radius of curvature of the three points)
Examiner note: Under the broadest reasonable sense, examiner consider the first curvature with the beta1 angle helps to determine the first curvature radius and the second curvature with the beta2 angle corresponds to the second curvature radius. The average of beta1 and beta2 is the tilt angle (gamma) which helps to determine the average radii.
Regarding claim 26
Parkin further teaches finding a previously undefined contact point of the drilling tool using the general curvature. (see para 33-tilting the lower tool body section 54 with respect to the upper tool body section 52 may cause the upper and lower stabilizers 62 and 64 to contact the wellbore wall on the opposite sides of the wellbore. As the tilt angle rotates around the wellbore (e.g., via rotating the force direction in the pistons), the contact points of the upper and lower stabilizers also rotate around the wellbore (yet continue to contact the wellbore wall on opposite sides of the wellbore). In the depicted embodiment, deflection of the lower tool body section 54 in the direction of the curvature (the solid lines) increases the magnitude of the tilt angle while deflection in the opposite direction of the curvature of the hole (the dashed lines) decreases the magnitude of the tilt angle. See also para 46- Assuming that the upper and lower stabilizers have equal diameters, the center of the lower stabilizer may be defined as being horizontally offset from the center of the upper stabilizer by a distance L (the axial separation distance between the stabilizers) and vertically offset from the center of the upper stabilizer by a distance -L sin(.alpha./2) at (L, -L sin(.alpha./2)) where a represents the change in axial direction of the upper tool body section (see FIG. 7).)
Examiner note: Examiner consider the previously undefined point is the assumed point in the stabilizers before the tilt angle rotates which is obtained by using the general curvature as shown in fig 7.
Conclusion
9. Claims 1, 4-6, 9-11, 14-22 and 24-26 are rejected.
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure:
US 20130304384 A1 Rabinovich et al.
Discussing the method for estimating a parameter of interest of an earth formation involving alignment information between non-collocated oriented receivers and their corresponding non-collocated oriented transmitters.
US 20110015911 A1 Chen.
ii. Discussing a method to simulate forming a wellbore in subterranean formations having a combination of soft, medium and hard formation materials, multiple layers of formation materials, relatively hard stringers disposed throughout one or more layers of formation material, and/or concretions (very hard stones) disposed in one or more layers of formation materials.
THIS ACTION IS MADE FINAL. Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
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/PURSOTTAM GIRI/Examiner, Art Unit 2186
/RENEE D CHAVEZ/Supervisory Patent Examiner, Art Unit 2186
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