Patent Grant
10781642
The present disclosure relates generally to downhole drilling tools and, more particularly, to rotary drill bits and methods for designing rotary drill bits with multi-layer cutting elements.
Various types of downhole drilling tools including, but not limited to, rotary drill bits, reamers, core bits, and other downhole tools have been used to form wellbores in associated downhole formations. Examples of such rotary drill bits include, but are not limited to, fixed cutter drill bits, drag bits, polycrystalline diamond compact (PDC) drill bits, and matrix drill bits associated with forming oil and gas wells extending through one or more downhole formations. Fixed cutter drill bits such as PDC bits may include multiple blades that each include multiple cutting elements.
In typical drilling applications, a PDC bit may be used to drill through various levels or types of geological formations with longer bit life than non-PDC bits. Typical formations may generally have a relatively low compressive strength in the upper portions (e.g., lesser drilling depths) of the formation and a relatively high compressive strength in the lower portions (e.g., greater drilling depths) of the formation. Thus, it typically becomes increasingly more difficult to drill at increasingly greater depths. Additionally, cutting elements on the drill bit may experience increased wear as drilling depth increases.
A more complete understanding of the present disclosure and its features and advantages thereof may be acquired by referring to the following description, taken in conjunction with the accompanying drawings, in which like reference numbers indicate like features, and wherein:
Embodiments of the present disclosure and its advantages are best understood by referring to
Drilling system 100 may include drill string 103 associated with drill bit 101 that may be used to form a wide variety of wellbores or bore holes such as generally vertical wellbore 114a or generally horizontal wellbore 114b as shown in
BHA 120 may be formed from a wide variety of components configured to form a wellbore 114. For example, components 122a, 122b and 122c of BHA 120 may include, but are not limited to, drill bits (e.g., drill bit 101) drill collars, rotary steering tools, directional drilling tools, downhole drilling motors, drilling parameter sensors for weight, torque, bend and bend direction measurements of the drill string and other vibration and rotational related sensors, hole enlargers such as reamers, under reamers or hole openers, stabilizers, measurement while drilling (MWD) components containing wellbore survey equipment, logging while drilling (LWD) sensors for measuring formation parameters, short-hop and long haul telemetry systems used for communication, and/or any other suitable downhole equipment. The number of components such as drill collars and different types of components 122 included in BHA 120 may depend upon anticipated downhole drilling conditions and the type of wellbore that will be formed by drill string 103 and rotary drill bit 101. BHA 120 may also include various types of well logging tools (not expressly shown) and other downhole tools associated with directional drilling of a wellbore. Examples of such logging tools and/or directional drilling tools may include, but are not limited to, acoustic, neutron, gamma ray, density, photoelectric, nuclear magnetic resonance, rotary steering tools and/or any other commercially available well tool.
Wellbore 114 may be defined in part by casing string 110 that may extend from well surface 106 to a selected downhole location. Portions of wellbore 114 as shown in
Drilling system 100 may also include rotary drill bit (“drill bit”) 101. Drill bit 101, discussed in further detail in
Drilling system 100 may include one or more second layer cutting elements on a drill bit that are configured to cut into the geological formation at particular drilling depths and/or when first layer cutting elements experience sufficient wear. Thus, multiple layers of cutting elements may exist that engage with the formation at multiple drilling depths. Placement and configuration of the first layer and second layer cutting elements on blades of a drill bit may be varied to enable the different layers to engage at specific drilling depths. For example, configuration considerations may include under-exposure and blade placement of second layer cutting elements with respect to first layer cutting elements, and/or characteristics of the formation to be drilled. Cutting elements may be arranged in multiple layers on blades such that second layer cutting elements may engage the formation when the depth of cut is greater than a specified value and/or when first layer cutting elements are sufficiently worn. In some embodiments, the drilling tools may have first layer cutting elements arranged on blades in a single-set or a track-set configuration. Second layer cutting elements may be arranged on different blades that are track-set and under-exposed with respect to the first layer cutting elements. In some embodiments, the amount of under-exposure may be approximately the same for each of the second layer cutting elements. In other embodiments, the amount of under-exposure may vary for each of the second layer cutting elements.
Drill bit 101 may include one or more blades 126 (e.g., blades 126a-126g) that may be disposed outwardly from exterior portions of rotary bit body 124 of drill bit 101. Rotary bit body 124 may be generally cylindrical and blades 126 may be any suitable type of projections extending outwardly from rotary bit body 124. For example, a portion of blade 126 may be directly or indirectly coupled to an exterior portion of bit body 124, while another portion of blade 126 may be projected away from the exterior portion of bit body 124. Blades 126 formed in accordance with teachings of the present disclosure may have a wide variety of configurations including, but not limited to, substantially arched, helical, spiraling, tapered, converging, diverging, symmetrical, and/or asymmetrical.
In some embodiments, blades 126 may have substantially arched configurations, generally helical configurations, spiral shaped configurations, or any other configuration satisfactory for use with each downhole drilling tool. One or more blades 126 may have a substantially arched configuration extending from proximate rotational axis 104 of drill bit 101. The arched configuration may be defined in part by a generally concave, recessed shaped portion extending from proximate bit rotational axis 104. The arched configuration may also be defined in part by a generally convex, outwardly curved portion disposed between the concave, recessed portion and exterior portions of each blade which correspond generally with the outside diameter of the rotary drill bit.
Each of blades 126 may include a first end disposed proximate or toward bit rotational axis 104 and a second end disposed proximate or toward exterior portions of drill bit 101 (e.g., disposed generally away from bit rotational axis 104 and toward uphole portions of drill bit 101). The terms “uphole” and “downhole” may be used to describe the location of various components of drilling system 100 relative to the bottom or end of wellbore 114 shown in
Blades 126a-126g may include primary blades disposed about the bit rotational axis. For example, in
Each blade may have leading (or front) surface (or face) 130 disposed on one side of the blade in the direction of rotation of drill bit 101 and trailing (or back) surface (or face) 132 disposed on an opposite side of the blade away from the direction of rotation of drill bit 101. Blades 126 may be positioned along bit body 124 such that they have a spiral configuration relative to rotational axis 104. In other embodiments, blades 126 may be positioned along bit body 124 in a generally parallel configuration with respect to each other and bit rotational axis 104.
Blades 126 may include one or more cutting elements 128 disposed outwardly from exterior portions of each blade 126. For example, a portion of cutting element 128 may be directly or indirectly coupled to an exterior portion of blade 126 while another portion of cutting element 128 may be projected away from the exterior portion of blade 126. By way of example and not limitation, cutting elements 128 may be various types of cutters, compacts, buttons, inserts, and gage cutters satisfactory for use with a wide variety of drill bits 101.
Cutting elements 128 may be any suitable device configured to cut into a formation, including but not limited to, primary cutting elements, back-up cutting elements, secondary cutting elements or any combination thereof. Primary cutting elements may be described as first layer or second layer cutting elements. First layer cutting elements may be disposed on leading surfaces 130 of primary blades, e.g. blades 126a, 126c, and 126e. Second layer cutting elements may be disposed on leading surfaces 130 of secondary blades, e.g., blades 126b, 126d, 126f, and 126g.
Cutting elements 128 may include respective substrates with a layer of hard cutting material disposed on one end of each respective substrate. The hard layer of cutting elements 128 may provide a cutting surface that may engage adjacent portions of a downhole formation to form wellbore 114. The contact of the cutting surface with the formation may form a cutting zone associated with each of cutting elements 128. The edge of the cutting surface located within the cutting zone may be referred to as the cutting edge of a cutting element 128.
Each substrate of cutting elements 128 may have various configurations and may be formed from tungsten carbide or other suitable materials associated with forming cutting elements for rotary drill bits. Tungsten carbides may include, but are not limited to, monotungsten carbide (WC), ditungsten carbide (W2C), macrocrystalline tungsten carbide and cemented or sintered tungsten carbide. Substrates may also be formed using other hard materials, which may include various metal alloys and cements such as metal borides, metal carbides, metal oxides and metal nitrides. For some applications, the hard cutting layer may be formed from substantially the same materials as the substrate. In other applications, the hard cutting layer may be formed from different materials than the substrate. Examples of materials used to form hard cutting layers may include polycrystalline diamond materials, including synthetic polycrystalline diamonds.
In some embodiments, blades 126 may also include one or more depth of cut controllers (DOCCs) (not expressly shown) configured to control the depth of cut of cutting elements 128. A DOCC may include an impact arrestor, a back-up or second layer cutting element and/or a Modified Diamond Reinforcement (MDR). Exterior portions of blades 126, cutting elements 128 and DOCCs (not expressly shown) may form portions of the bit face.
Blades 126 may further include one or more gage pads (not expressly shown) disposed on blades 126. A gage pad may be a gage, gage segment, or gage portion disposed on exterior portion of blade 126. Gage pads may contact adjacent portions of wellbore 114 formed by drill bit 101. Exterior portions of blades 126 and/or associated gage pads may be disposed at various angles, positive, negative, and/or parallel, relative to adjacent portions of generally vertical wellbore 114a. A gage pad may include one or more layers of hardfacing material.
Uphole end 150 of drill bit 101 may include shank 152 with drill pipe threads 155 formed thereon. Threads 155 may be used to releasably engage drill bit 101 with BHA 120 whereby drill bit 101 may be rotated relative to bit rotational axis 104. Downhole end 151 of drill bit 101 may include a plurality of blades 126a-126g with respective junk slots or fluid flow paths 140 disposed therebetween. Additionally, drilling fluids may be communicated to one or more nozzles 156.
Drill bit operation may be expressed in terms of depth of cut per revolution as a function of drilling depth. Depth of cut per revolution, or “depth of cut,” may be determined by rate of penetration (ROP) and revolution per minute (RPM). ROP may represent the amount of formation that is removed as drill bit 101 rotates and may be in units of ft/hr. Further, RPM may represent the rotational speed of drill bit 101. For example, drill bit 101 utilized to drill a formation may rotate at approximately 120 RPM. Actual depth of cut (Δ) may represent a measure of the depth that cutting elements cut into the formation during a rotation of drill bit 101. Thus, actual depth of cut may be expressed as a function of actual ROP and RPM using the following equation:
Δ=ROP/(5*RPM).
Actual depth of cut may have a unit of in/rev.
Multiple formations of varied formation strength may be drilled using drill bits configured in accordance with some embodiments of the present disclosure. As drilling depth increases, formation strength may likewise increase. For example, a first formation may extend from the surface to a drilling depth of approximately 2,200 feet and may have a rock strength of approximately 5,000 pounds per square inch (psi). Additionally, a second formation may extend from a drilling depth of approximately 2,200 feet to a drilling depth of approximately 4,800 feet and may have rock strength of approximately 25,000 psi. As another example, a third formation may extend from a drilling depth of approximately 4,800 feet to a drilling depth of approximately 7,000 feet and may have a rock strength over approximately 20,000 psi. A fourth formation may extend from approximately 7,000 feet to approximately 8,000 feet and may have a rock strength of approximately 30,000 psi. Further, a fifth formation may extend beyond approximately 8,000 feet and have a rock strength of approximately 10,000 psi.
With increased drilling depth, formation strength or rock strength may increase or decrease and thus, the formation may become more difficult or may become easier to drill. For example, a drill bit including seven blades may drill through the first formation very efficiently, but a drill bit including nine blades may be desired to drill through the second and third formations.
Accordingly, as drill bit 101 drills into a formation, the first layer cutting elements may begin to wear as the drilling depth increases. For example, at a drilling depth of less than approximately 5,500 feet, the first layer cutting elements may have a wear depth of approximately 0.04 inches. At a drilling depth between approximately 5,500 feet and 8,500 feet, the first layer cutting elements may have an increased wear depth of approximately 0.15 inches. As first layer cutting elements wear, ROP of the drill bit may decrease, thus, resulting in less efficient drilling. Likewise, actual depth of cut for drill bit 101 may also decrease. Thus, second layer cutting elements that begin to cut into the formation when the first layer cutting elements experience a sufficient amount of wear may improve the efficiency of drill bit 101 and may result in drill bit 101 having a longer useful life.
Accordingly, to extend the bit life, it may be desired that (1) second layer cutting elements not cut into the formation until drill bit 101 reaches a particular drilling depth; (2) second layer cutting elements begin to cut into the formation at a particular drilling depth; (3) second layer cutting elements cut the formation effectively; and (4) approximately all second layer cutting elements cut into the formation substantially simultaneously. Hence, drill bit 101 optimized for maximizing drilling efficiency and bit life may include:
(a) first layer cutting elements that cut into the formation from the surface to a first drilling depth (DA);
(b) second layer cutting elements that begin to cut into the formation at DA
(c) second layer cutting elements that cut efficiently based on formation properties; and
(d) second layer cutting elements that cut substantially simultaneously.
Improvement of the design of a drill bit may begin with actual performance of the bit when drilled into an offset well with a similar formation and similar operational parameters.
In the current example, rock strength, shown as plot 310, remained substantially constant during drilling. RPM of the drill bit, which is the sum of RPM of the drill string and the RPM of the downhole motor, shown as plot 320, and ROP, shown as plot 330, decreased at a drilling depth of approximately 4,800 feet. Additionally, MSE may be calculated using the run information. MSE may be a measure of the drilling efficiency of drill bit 101. In the illustrated embodiment, MSE increases after drilling approximately 4,800 feet, which may indicate that the drilling efficiency of the drill bit may decrease at depths over approximately 4,800 feet. Thus, drilling to approximately 4,800 feet may be described as high efficiency drilling 350. MSE additionally increases again at approximately 5,800 feet. Drilling between approximately 4,800 feet and 5,800 feet may be described as efficiency drilling 360, and drilling at depths over approximately 5,800 feet may be described as low efficiency drilling 370. MSE may indicate a further drop in drilling efficiency. The data shown in
Using the gathered run information illustrated in
Similarly,
Wear (%)=(Cumwork/BitMaxWork)a*100%
where
Cumwork=f(drilling depth); and
a=wear exponent and is between approximately 0.5 and 5.0.
Using the above model, cutting element wear as a function of drilling depth for a drill bit may be estimated and utilized during downhole drilling. Once the wear characteristics are obtained from the model, the drilling depth at which the first layer cutting elements may be worn to the point that the second layer cutting elements begin to cut into the formation (DA) may be determined. For example, as illustrated in cutting element wear plot 510 in
Second layer cutting element critical depth of cut as a function of drilling depth may be shown by plot 520 and actual depth of cut as a function of drilling depth may be shown by plot 530. Second layer critical depth of cut if there was no first layer cutting element wear may be shown by plot 540. A comparison of second layer depth of cut and actual depth of cut may identify when second layer cutting elements may engage the formation. For example, second layer cutting elements may have an initial critical depth of cut (plot 520) that may be greater than the actual depth of cut (plot 530). At a particular drilling distance, DA, second layer cutting element critical depth of cut, plot 520, may intersect with the actual depth of cut, plot 530. At a target drilling depth, second layer cutting element critical depth of cut, plot 520, may be equal to approximately zero. Actual depth of cut, plot 530, may be generated based on field measurements in accordance with
In some embodiments, the second layer cutting elements may be under-exposed by any suitable amount such that first layer cutting elements cut into the formation from the surface to a first drilling depth (DA), and the second layer cutting elements begin to cut into the formation at DA as the first layer cutting elements become worn. An analysis of
Thus, to ensure that second layer cutting elements do not cut into the formation until a particular drilling depth DA, the under-exposure of second layer cutting elements may be set to provide a critical depth of cut for second layer cutting elements greater than the actual depth of cut. Further, a critical depth of cut for the second layer cutting elements as a function of the drilling distance may be obtained based on the first layer cutting element wear depth. The under-exposure of the second layer cutting elements may approximate the first layer cutting element wear depth at a target drilling distance.
Accordingly, determining the amount of wear the first layer cutting element undergoes before second layer cutting elements engage the formation may be useful. In order to determine when the second layer cutting element may begin to cut into the formation, a critical depth of cut curve (CDCCC) for PDC bits having second layer cutting elements may be determined.
Additionally, a location along the bit face of drill bit 601 shown in
The distance from the rotational axis of the drill bit 601 to a point in the xy-plane of the bit face of
r=√{square root over (x2+y2)}.
Additionally, a point in the xy-plane (of
θ=arctan(y/x).
As a further example, as illustrated in
Additionally, cutlet point 630a may have an angular coordinate (θ630a) that may be the angle between the x-axis and the line extending orthogonally from the rotational axis of drill bit 601 to cutlet point 630a (e.g., θ630a may be equal to arctan (X630a/Y630a)). Further, as depicted in
The cited coordinates and coordinate systems are used for illustrative purposes only, and any other suitable coordinate system or configuration, may be used to provide a frame of reference of points along the bit face profile and bit face of a drill bit associated with
Returning to
The critical depth of cut of drill bit 601 may be the point at which second layer cutting elements 638b begin to cut into the formation. Accordingly, the critical depth of cut of drill bit 601 may be determined for a radial location along drill bit 601. For example, drill bit 601 may include a radial coordinate RF that may intersect with the cutting edge of second layer cutting element 638b at control point P640b. Likewise, radial coordinate RF may intersect with the cutting edge of first layer cutting element 628a at cutlet point 630a.
The angular coordinates of cutlet point 630a θ630a and control point P640b θP640b may be determined. A critical depth of cut provided by control point P640b with respect to cutlet point 630a may be determined. The critical depth of cut provided by control point P640b may be based on the under-exposure (δ640b depicted in
For example, the depth of cut at which second layer cutting element 638b at control point P640b may begin to cut formation may be determined using the angular coordinates of cutlet point 630a and control point P640b (θ630a and θP640b, respectively), which are depicted in
Δ630aδ640b*360/(360−(θP640b−θ630a)); and
δ640b=Z630a−ZP640b.
In the first of the above equations, θP640b and θ630a may be expressed in degrees and “360” may represent a full rotation about the face of drill bit 601. Therefore, in instances where θP640b and θ630a are expressed in radians, the numbers “360” in the first of the above equations may be changed to “2π” Further, in the above equation, the resultant angle of “(θP640b and θ630a)” (Δθ) may be defined as always being positive. Therefore, if resultant angle Δ0 is negative, then Δθ may be made positive by adding 360 degrees (or 2π radians) to Δ0. Similar equations may be used to determine the depth of cut at which second layer cutting element 638a at control point P640b (Δ630a) may begin to cut formation in place of first layer cutting element 628a.
The critical depth of cut provided by control point P640b (ΔP640b) may be based on additional cutlet points along RF (not expressly shown). For example, the critical depth of cut provided by control point P640b (ΔP640b) may be based the maximum of Δ630a, Δ630c, Δ630e, and Δ630g and may be expressed by the following equation:
ΔP640b=max[Δ630a, Δ630c, Δ630e, Δ630g].
Similarly, the critical depth of cut provided by additional control points (not expressly shown) at radial coordinate RF may be similarly determined. For example, the overall critical depth of cut of drill bit 601 at radial coordinate RF (ΔRF) may be based on the minimum of ΔP640b, ΔP640d, ΔP640f, ΔP640h and may be expressed by the following equation:
ΔRF=min[ΔP640b, ΔP640d, ΔP640f, ΔP640h].
Accordingly, the critical depth of cut of drill bit 601 at radial coordinate RF (ΔRF) may be determined based on the points where first layer cutting elements 628 and second layer cutting elements 638 intersect RF. Although not expressly shown here, it is understood that the overall critical depth of cut of drill bit 601 at radial coordinate RF (ΔRF) may also be affected by control points P626i (not expressly shown in
To determine a CDCCC of drill bit 601, the overall critical depth of cut at a series of radial locations Rf(ΔRf) anywhere from the center of drill bit 601 to the edge of drill bit 601 may be determined to generate a curve that represents the critical depth of cut as a function of the radius of drill bit 601. In the illustrated embodiment, second layer cutting element 638b may be located in radial swath 608 (shown on
The cutting edges of first layer cutting element 628a may wear gradually with drilling distance. As a result the shape of cutting edges may be changed. The cutting edges of second layer cutting element 638b may also wear gradually with drilling distance and the shape of second layer cutting element 638b may also be changed. Therefore, both under-exposure δ640b and angle (θP640b-θP630a) between cutlet point 630a and control point P640b may be changed. Thus, the critical depth of cut for a drill bit may be a function of the wear of both first layer and second layer cutting elements. At each drilling depth, a critical depth of cut for a drill bit may be estimated if wear of the cutting elements are known
Modifications, additions or omissions may be made to
In the illustrated embodiment, the cutting structures of the drill bit, including at least the locations and orientations of all cutting elements and DOCCs, may have been previously designed. However in other embodiments, method 700 may include steps for designing the cutting structure of the drill bit. For illustrative purposes, method 700 is described with respect to drill bit 601 of
Method 700 may start, and at step 702, the engineering tool may select a radial swath of drill bit 601 for analyzing the critical depth of cut within the selected radial swath. In some instances the selected radial swath may include the entire face of drill bit 601 and in other instances the selected radial swath may be a portion of the face of drill bit 601. For example, the engineering tool may select radial swath 608 as defined between radial coordinates RA and RB and may include second layer cutting element 638b, as shown in
At step 704, the engineering tool may divide the selected radial swath (e.g., radial swath 608) into a number, Nb, of radial coordinates (Rf) such as radial coordinate RF described in
At step 706, the engineering tool may select a radial coordinate Rf and may identify control points (P1) at the selected radial coordinate Rf and associated with a DOCC, a cutting element, and/or a blade. For example, the engineering tool may select radial coordinate RF and may identify control point P640b associated with second layer cutting element 638b and located at radial coordinate RF, as described above with respect to
At step 708, for the radial coordinate Rf selected in step 706, the engineering tool may identify cutlet points (Cj) each located at the selected radial coordinate Rf and associated with the cutting edges of cutting elements. For example, the engineering tool may identify cutlet point 630a located at radial coordinate RF and associated with the cutting edges of first layer cutting element 628a as described and shown with respect to
At step 710 the engineering tool may select a control point Pi and may calculate a depth of cut for each cutlet point Cj as controlled by the selected control point Pi (ΔCj). For example, the engineering tool may determine the depth of cut of cutlet point 630a as controlled by control point P640b (Δ630a) by using the following equations:
Δ630a=δ640b*360/(360−(θP640b−θ630a)); and
δ640b=Z630a−ZP640b.
At step 712, the engineering tool may calculate the critical depth of cut provided by the selected control point (ΔPi) by determining the maximum value of the depths of cut of the cutlet points Cj as controlled by the selected control point Pi (ΔCj) and calculated in step 710. This determination may be expressed by the following equation:
ΔPi=max{ΔCj}.
For example, control point P340a may be selected in step 710 and the depths of cut for cutlet point 630a, 630c, 630e, and 630g (not expressly shown) as controlled by control point P640b (Δ630a, Δ630c, Δ630e, and Δ630g, respectively) may also be determined in step 710, as shown above. Accordingly, the critical depth of cut provided by control point P640b (ΔP640b) may be calculated at step 712 using the following equation:
ΔP640b=max [Δ630a, Δ630c, Δ630e, Δ630g].
The engineering tool may repeat steps 710 and 712 for all of the control points R identified in step 706 to determine the critical depth of cut provided by all control points Pi located at radial coordinate Rf. For example, the engineering tool may perform steps 710 and 712 with respect to control points P640c, P640e, and P640g (not expressly shown) to determine the critical depth of cut provided by control points P640c, P640e, and P640g with respect to cutlet points 630a, 630c, 630e, and 630g (not expressly shown) at radial coordinate RF shown in
At step 714, the engineering tool may calculate an overall critical depth of cut at the radial coordinate Rf (ΔRf) selected in step 706. The engineering tool may calculate the overall critical depth of cut at the selected radial coordinate Rf (ΔRf) by determining a minimum value of the critical depths of cut of control points Pi (ΔPi) determined in steps 710 and 712. This determination may be expressed by the following equation:
ΔRf=min {ΔPi}
For example, the engineering tool may determine the overall critical depth of cut at radial coordinate RF of
ΔRF=min [ΔP640b, ΔP640d, ΔP640f, ΔP640h].
The engineering tool may repeat steps 706 through 714 to determine the overall critical depth of cut at all the radial coordinates Rf generated at step 704.
At step 716, the engineering tool may plot the overall critical depth of cut (ΔRf) for each radial coordinate Rf, as a function of each radial coordinate Rf. Accordingly, a CDCCC may be calculated and plotted for the radial swath associated with the radial coordinates Rf. For example, the engineering tool may plot the overall critical depth of cut for each radial coordinate Rf located within radial swath 608, such that the CDCCC for swath 608 may be determined and plotted, as depicted in
Method 700 may be repeated at any specified drilling depth where cutting element wear may be estimated or measured. The minimum of the CDCCC at each specified drilling depth may represent the critical depth of cut of the drill bit. Additionally, modifications, additions, or omissions may be made to method 700 without departing from the scope of the present disclosure. For example, the order of the steps may be performed in a different manner than that described and some steps may be performed at the same time. Additionally, each individual step may include additional steps without departing from the scope of the present disclosure.
Accordingly,
The equation detailed above for critical depth of cut for first layer cutting elements 628i with cutlet points 630i may be rewritten more generally as:
Δ630i=δ640i*360/(360−(θP640i−θ630i); and
δ640i=Z630−ZP640i.
If the angular locations of cutlet points 630i (θ630i) are fixed, then critical depth of cut, Δ630i, becomes a function of two variables: under-exposure of second layer cutting elements at control points P640i (δ640i) and angular location of second layer cutting elements at control points P640i (θ640i). Thus, the equation for critical depth of cut, Δ630i, may be rewritten as:
Δ630i=δ640i*f(θP640i)
The first variable, under-exposure of second layer cutting elements at control point P640i (δ640i), may be determined by the wear depth of first layer cutting elements 628. Thus, an estimate of the wear depth of first layer cutting elements 628 may be determined as a function of drilling depth.
Additionally, the second variable, f(θP640i), may be written as:
f(θP640i)=360/(360−(θP640i−θ630i)).
Further, (θP640i−θ630i) may vary from approximately 10 to 350 degrees for most drill bits. Thus, f(θP640i) may vary from approximately 1.0286 to approximately 36. The above analysis illustrates that f(θp640i) may act as an amplifier to critical depth of cut Δ630i. Therefore, for a given under-exposure δ640i, it may be possible to choose an angular location to meet a required critical depth of cut Δ630i.
In
In
For each of the angular locations of second layer cutting elements 838 shown in
In the illustrated embodiment, the cutting structures of the drill bit, including at least the locations and orientations of all cutting elements and DOCCs, may have been previously designed. However in other embodiments, method 1000 may include steps for designing the cutting structure of the drill bit. For illustrative purposes, method 1000 is described with respect to drill bit 801a illustrated in
Method 1000 may start, and at step 1004, the engineering tool may determine a target critical depth of cut (Δ). The target may be based on formation characteristics, prior drill bit design and simulations, a CDCCC generated using method 700 shown in
At step 1006, the engineering tool may determine an initial under-exposure (δ) for second layer cutting elements. Initial under-exposure may be generated based on an existing drill bit design, formation characteristics, or any other suitable parameter. For example, initial under-exposure δ, for drill bit 801a may be defined as approximately 0.01 inches.
At step 1008, the engineering tool may layout second layer cutting elements based on the initial under-exposure and a predetermined blade configuration. For example, drill bit 801a may have second layer cutting elements 838b configured on blade 2 and first layer cutting elements 828a configured on blade 1 as illustrated in
At step 1010, the engineering tool may generate a CDCCC based on the initial second layer cutting element layout generated at step 1008. The CDCCC may be generated based on method 700 shown in
At step 1012, the engineering tool may analyze the CDCCC for each second layer cutting element and determine if the critical depth of cut for each second layer cutting element approximates the target critical depth of cut obtained in step 1004. For example, at an initial given under-exposure of approximately 0.01 inches for the first second layer cutting elements, the critical depth of cut may be less than 0.25 in/rev. If a target critical depth of cut is approximately 0.25 in/rev, the under-exposure of the first second layer cutting element may be adjusted. Step 1012 may be repeated for all second layer cutting elements.
If all second layer cutting elements have a critical depth of cut that approximates the target critical depth of cut from step 1004, the method ends. If any second layer cutting elements do not have a critical depth of cut that approximates the target critical depth of cut from step 1004, then the method continues to step 1014.
At step 1014, the engineering tool may adjust the under-exposure of any second layer cutting elements that did not have a critical depth of cut that approximated the target critical depth of cut obtained in step 1004. The process then returns to step 1008 until each of the second layer cutting elements achieves a critical depth of cut that approximates the target critical depth of cut obtained in step 1014. For example, the under-exposure for each second layer cutting element 1-6 may be adjusted in order to approximate a target critical depth of cut of 0.25 inches.
Modifications, additions, or omissions may be made to method 1400 without departing from the scope of the present disclosure. For example, the order of the steps may be performed in a different manner than that described and some steps may be performed at the same time. Additionally, each individual step may include additional steps without departing from the scope of the present disclosure.
Table 1 illustrates example under-exposures for simulations performed for each of the drill bit 801 configurations illustrated in
For example, the average under-exposure for drill bit 801a shown in
In some applications, multiple bits may be utilized to drill a wellbore with multiple types of formations. For example, a drill bit with four blades may be utilized to drill into a first formation down to a particular depth. The four bladed drill bit may drill at approximately 120 RPM and a ROP of approximately 120 ft/hr. When the four bladed drill bit reaches a second formation, the cutting elements may be worn to a depth of approximately 0.025 inches. A different bit with eight blades may be utilized to drill into the second formation. In order to minimize the need to change from a four bladed to an eight bladed drill bit, a drill bit with eight blades may be designed to drill through both the first formation and the second formation. For example, first layer cutting elements, e.g., located on blades 1, 3, 5 and 7 shown with reference to
In some embodiments, simulations may be conducted based on design parameters to determine a drill bit configuration, e.g., drill bits 801a-801i of
As another example, a formation may exist that is relatively soft and abrasive. When drilling into a soft and abrasive formation, a drill bit with few blades, e.g., a four bladed drill bit, may be effective. An abrasive formation may wear cutting elements at a greater rate than a non-abrasive formation. Thus, when the cutting elements on a four bladed drill bit become worn, the drill bit may not drill as efficiently, e.g., experience a higher MSE. For example, cutting elements drilling into a formation at approximately 120 RPM and an ROP of approximately 90 ft/hr may have a wear depth of approximately 0.1 inches at a particular first drilling depth. Below the first drilling depth, a new four bladed drill bit may be utilized. In some embodiments, use of two layers of cutting elements on an eight bladed drill bit may improve the efficiency of a drill bit drilling into a soft and abrasive formation. For example, first layer cutting elements, e.g., located on blades 1, 3, 5 and 7 shown with reference to
In some embodiments, a front track set configuration as shown in
In the illustrated embodiments, the cutting structures of the drill bit, including at least the locations and orientations of all first layer cutting elements, may have been previously designed and bit run data may be available. However in other embodiments, method 1100 may include steps for designing the cutting structure of the drill bit. For illustrative purposes, method 1100 is described with respect to a pre-existing drill bit; however, method 1100 may be used to determine layout of second layer cutting elements of any suitable drill bit. Additionally, method 1100 may be described with respect to a designed drill bit similar in configuration to drill bit 801 as shown in
Method 1100 may start, and at step 1102, the engineering tool may determine if a pre-existing drill bit exists that may be redesigned. If there is a pre-existing drill bit, method 1100 continues to step 1104. If no pre-existing drill bit exists, method 1100 continues to step 1112.
At step 1104, the engineering tool may obtain run information for the pre-existing drill bit. For example,
At step 1106, the engineering tool may generate a plot of the actual depth of cut as a function of drilling depth for the pre-existing drill bit. For example,
At step 1108, the engineering tool may estimate the average first layer cutting element wear as a function of drilling depth of the pre-existing drill bit. For example,
At step 1110, the engineering tool may generate a plot of the designed depth of cut as a function of drilling depth for second layer cutting elements of the pre-existing drill bit. The designed depth of cut may be based on the first layer cutting element wear estimated at step 1106. For example,
As noted above, if no pre-existing drill bit exists that may be redesigned at step 1102, method 1100 may continue to step 1112. At step 1112, the engineering tool may obtain the expected drilling depth, Dmax, for the wellbore based upon exploration activities and/or a drilling plan. At step 1114, the engineering tool may obtain the expected depth of cut as a function of drilling depth. For example,
At step 1116, the engineering tool may receive a cutting element wear model and may plot cutting element wear depth as a function of the drilling depth. For example,
Wear(%)=(Cumwork/BitMaxWork)a*100%
where
Cumwork=f(drilling depth); and
a=wear exponent and is between approximately 5.0 and 0.5.
At this point in method 1100, both step 1116 and step 1110 continue to step 1117. At step 1117, the engineering tool may determine an expected critical depth of cut for the second layer cutting elements. The critical depth of cut may be based on drilling parameters such as RPM and ROP. For example a critical depth of cut for second layer cutting elements for a drill bit operating at approximately 120 RPM with an ROP of 120 ft/hr may be approximately 0.20 in/rev. Additionally, second layer cutting elements may have an initial critical depth of cut that may be greater than the actual depth of cut or the expected depth of cut, as shown with reference to
At step 1118, the engineering tool may determine the drilling depth at which first layer cutting elements on the drill bit may be worn such that second layer cutting elements may begin to cut the formation based on bit wear and actual or expected ROP. This drilling depth may correspond to drilling depth DA.
At step 1120, the engineering tool may determine the under-exposure of second layer cutting elements for the drill bit. The under-exposure may be approximately the amount of wear first layer cutting elements may have experienced while drilling to drilling depth DA. For example,
At step 1122, the engineering tool may determine the optimal locations for second layer cutting elements and first layer cutting elements disposed on the drill bit. For example, based on the critical depth of cut for the second layer cutting elements and the under-exposure, a drill bit configuration may be selected from Table 1 shown above. As another example, the engineering tool may run multiple simulations to generate run information. Based on results of these simulations, the engineering tool may determine blade locations for both first layer cutting elements and second layer cutting elements.
At step 1124, the engineering tool may determine if the second layer cutting elements begin to cut formation at drilling depth DA. For example, the engineering tool may generate a designed critical depth of cut as a function of drilling depth for second layer cutting elements of the drill bit. The engineering tool may run a simulation of the cutting element layout determined in step 1122 to generate designed critical depth of cut as a function of drilling depth curve. For example, the engineering tool may determine that second layer cutting elements 838 may begin to cut into the formation at drilling depth DA of approximately 5,000 feet. If second layer cutting elements do not begin to cut formation at drilling depth DA, the process 1100 may return to step 1118 to reconfigure drill bit 801. If the second layer cutting elements begin to cut formation at drilling depth DA, then the process may continue to step 1126.
Based on these results, at step 1126, the engineering tool may adjust under-exposure of each second layer cutting element in order for each second layer cutting element to have the same minimal depth of cut of the new drill bit. Following step 1126, method 1100 may end.
Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the following claims. For example, although the present disclosure describes the configurations of blades and cutting elements with respect to drill bits, the same principles may be used to control the depth of cut of any suitable drilling tool according to the present disclosure. It is intended that the present disclosure encompasses such changes and modifications as fall within the scope of the appended claims.
This application is a Divisional Application of U.S. patent application Ser. No. 15/034,143 filed May 3, 2016, which is a U.S. National Stage Application of International Application No. PCT/US2013/073583 filed Dec. 6, 2013, which designates the United States, and which are incorporated herein by reference in their entirety.
| Number | Name | Date | Kind |
|---|---|---|---|
| 3153458 | Short | Oct 1964 | A |
| 4554986 | Jones | Nov 1985 | A |
| 4991670 | Fuller et al. | Feb 1991 | A |
| 5090492 | Keith | Feb 1992 | A |
| 5265685 | Keith et al. | Nov 1993 | A |
| 5549171 | Mensa-Wilmot et al. | Aug 1996 | A |
| 5551522 | Keith et al. | Sep 1996 | A |
| 5582261 | Keith et al. | Dec 1996 | A |
| 5595252 | O'Hanlon | Jan 1997 | A |
| 5607024 | Keith et al. | Mar 1997 | A |
| 6089336 | Nexton | Jul 2000 | A |
| 6109368 | Goldman et al. | Aug 2000 | A |
| 6298930 | Sinor et al. | Oct 2001 | B1 |
| 6408953 | Goldman et al. | Jun 2002 | B1 |
| 6460631 | Dykstra et al. | Oct 2002 | B2 |
| 6779613 | Dykstra et al. | Aug 2004 | B2 |
| 6935441 | Dykstra et al. | Aug 2005 | B2 |
| 7032689 | Goldman et al. | Apr 2006 | B2 |
| 7096978 | Dykstra et al. | Aug 2006 | B2 |
| 7261167 | Goldman et al. | Aug 2007 | B2 |
| 7357196 | Goldman et al. | Apr 2008 | B2 |
| 7360608 | Brackin et al. | Apr 2008 | B2 |
| 7464774 | Savignat et al. | Dec 2008 | B2 |
| 7624818 | McClain et al. | Dec 2009 | B2 |
| 7703557 | Durairajan et al. | Apr 2010 | B2 |
| 7762355 | McClain et al. | Jul 2010 | B2 |
| 7861809 | Gavia et al. | Jan 2011 | B2 |
| 7866413 | Stauffer et al. | Jan 2011 | B2 |
| 8863860 | Chen et al. | Oct 2014 | B2 |
| 8985244 | Patel | Mar 2015 | B2 |
| 20010030063 | Dykstra et al. | Oct 2001 | A1 |
| 20050010382 | Oliver et al. | Jan 2005 | A1 |
| 20050080595 | Huang | Apr 2005 | A1 |
| 20060278436 | Dykstra et al. | Dec 2006 | A1 |
| 20070078632 | Shen | Apr 2007 | A1 |
| 20070151770 | Ganz | Jul 2007 | A1 |
| 20070186639 | Spross et al. | Aug 2007 | A1 |
| 20070267227 | Mensa-Wilmot | Nov 2007 | A1 |
| 20080041629 | Aronstam et al. | Feb 2008 | A1 |
| 20080135297 | Gavia | Jun 2008 | A1 |
| 20090090556 | Chen | Apr 2009 | A1 |
| 20090166091 | Matthews et al. | Jul 2009 | A1 |
| 20090266619 | Durairajan et al. | Oct 2009 | A1 |
| 20100000800 | Chen et al. | Jan 2010 | A1 |
| 20100025121 | Schwefe | Feb 2010 | A1 |
| 20100089664 | Welch et al. | Apr 2010 | A1 |
| 20100193248 | Radford et al. | Aug 2010 | A1 |
| 20100263937 | Overstreet et al. | Oct 2010 | A1 |
| 20110030063 | Choi | Oct 2011 | A1 |
| 20120111630 | Chen et al. | May 2012 | A1 |
| 20120205163 | Azar | Aug 2012 | A1 |
| 20120312603 | Propes | Dec 2012 | A1 |
| 20130035903 | Prevost | Feb 2013 | A1 |
| 20130228378 | Chen et al. | Sep 2013 | A1 |
| 20130233621 | Chen et al. | Sep 2013 | A1 |
| 20130238245 | Chen et al. | Sep 2013 | A1 |
| 20130253836 | Chen et al. | Sep 2013 | A1 |
| 20140262536 | Azar | Sep 2014 | A1 |
| 20150122551 | Chen | May 2015 | A1 |
| 20150152689 | Chen et al. | Jun 2015 | A1 |
| Number | Date | Country |
|---|---|---|
| 2451714 | Oct 2001 | CN |
| 10427000 | May 2009 | CN |
| 101460701 | Jun 2009 | CN |
| 101611213 | Dec 2009 | CN |
| 102216554 | Oct 2011 | CN |
| 2498480 | Jul 2013 | GB |
| 2012064948 | May 2012 | WO |
| 2012064953 | May 2012 | WO |
| 2012064961 | May 2012 | WO |
| 2013180702 | Dec 2013 | WO |
| Entry |
|---|
| International Preliminary Report on Patentability of PCT/US2013/073583, dated Jun. 16, 2016, 9 pages. |
| European Extended Search Report of Application No. 12880858.1 dated Jan. 4, 2016, 5 pages. |
| International Preliminary Report on Patentability, PCT Application No. PCT/US2012/039977, 7 pages, dated Dec. 2, 2014. |
| International Search Report and Written Opinion, Application No. PCT/US2012/039977, 13 pages, dated Aug. 12, 2012. |
| Mensa-Wilmot, Graham, “Innovation Cutting Structure, With Staged ROP and Durability Characteristics, Extends PDC Bit Efficiency Into Chert/Pyrite/Conglomerate Applications,” Society of Petroleum Engineers 105320, 15th SPE Middle East Oil & Gas Show and Conference, Kingdom of Bahrain, Mar. 11-14, 2007. |
| International Preliminary Report on Patentability issued in PCT/US2012/053761; 6 pages, dated Jan. 13, 2015. |
| International Search Report and Written Opinion, Application No. PCT/US2012/053761, 17 pages, dated Feb. 4, 2013. |
| Canadian Office Action Application No. 2879046, dated Feb. 24, 2016, 4 pages, dated Feb. 24, 2016. |
| Canadian Office Action Application No. 2875021, dated Jan. 13, 2016, 4 pages, dated Jan. 13, 2016. |
| Examination Report, Application No. GB1420604.9; 3 pages, dated Jun. 26, 2016. |
| Chinese Office Action, Application No. 201280074423.7; with translation; 14 pages, dated Dec. 2, 2015. |
| Chinese Office Action Application No. 201280074423.7, dated Aug. 17, 2016, 13 pages. |
| Chinese Office Action Application No. 201280074423.7, dated Mar. 2, 2017; 7 pages. |
| Canadian Office Action Application No. 2929078, dated Apr. 3, 2017, 4 pages. |
| Canadian Office Action Application No. 2879046, dated Mar. 27, 2017, 4 pages. |
| Chinese Office Action Application No. 201380080165.8, dated May 3, 2017; 13 pages. |
| Office Action for Canadian Patent Application No. 2879046, dated Dec. 15, 2017; 4 pages. |
| Number | Date | Country | |
|---|---|---|---|
| 20190257157 A1 | Aug 2019 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 15034143 | US | |
| Child | 16405223 | US |
