DRILL BIT SELECTION FOR DRILLING A TARGET WELL BASED ON DRILLING SIMULATION OF AN OFFSET WELL

Description

BACKGROUND

For drilling of a well, an increase of drilling efficiency (a higher rate of penetration (ROP) of a drill bit usually results in a decrease of durability (shorten period of usability) of the drill bit. Conversely, an increase of durability of the drill bit leads usually to a decrease in drilling efficiency. For drilling a wellbore, drilling engineers typically select a drill bit with a higher drilling efficiency. Drill bit engineers need to ensure that the selected drill bit can drill through a predefined section of a wellbore being drilled.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 an elevation view (partially cross sectional) of an example well system, according to some implementations.

FIG. 2 is a block diagram of an example computer, according to some implementations.

FIG. 3 is a graphical representation of a cutter of a drill bit, according to some implementations.

FIG. 4 is a graph defining an example relationship between the cutter wear volume and energy of a cutter of a drill bit.

FIG. 5 is a graphical representation of a cutter of a drill bit, according to some implementations.

FIG. 6 is a flowchart of example operations for determining a cutter wear severity for cutters of a drill bit during drilling of a wellbore.

FIG. 7 includes a graph 700 having lines for the primary cutters, the backup cutters, and the DOCCs and blades.

FIG. 8 is a graph of a ratio of WOB from the primary cutters to WOB at the bit wear level 1 to 10.

FIG. 9 is a graph illustrating bit energy in relation to drilling depth for a simulation.

FIG. 10 is a graph illustrating is a graph illustrating bit energy in relation to drilling depth for simulation.

FIGS. 11A-11B and FIGS. 12A-12B are graphs showing how some implementations may select a drill bit.

FIG. 13 is a block diagram showing operations to select or design a drill bit for predefined well section.

FIGS. 14-15 are block diagrams of a flowchart of an offset well simulation of drilling an offset well using a base drill bit, according to some embodiments.

FIGS. 16-17 are block diagrams of a flowchart of an offset well simulation of drilling using a new drill bit under the same or similar drilling conditions as the drilling of the offset well, according to some embodiments.

FIG. 18 (which is further described below) is an example table of the comparisons among the base drill bit and three example new drill bits.

FIGS. 19 and 20 are flow diagrams that illustrate example operations for simulating a drilling run of a drill bit under different conditions.

FIGS. 21A-21B are a bottom side view and a perspective view, respectively, of an example drill bit for drilling a well.

FIGS. 22-32 are graphs illustrating performance aspects of a drill bit for a drilling run.

DESCRIPTION

The description that follows includes example systems, methods, techniques, and program flows that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. In some instances, well-known instruction instances, protocols, structures, and techniques have not been shown in detail in order not to obfuscate the description.

Example implementations relate to selecting and using a drill bit for drilling of target well (or wellbore) based on drilling and simulations of drilling of an offset well have the same or similar drilling parameters and drilling conditions. Two important attributes of drilling of a wellbore may include efficiency of a drill bit (bit efficiency) and durability of the drill bit (bit durability). Bit efficiency may be measured using various parameters (such as Rate Of Penetration (ROP)). Similarly, bit durability may be measured using other parameters (such as the wear and/or dulling of cutters of the drill bit). It may be difficult to develop a drill bit with both high bit efficiency and high bit durability. In particular, as bit efficiency increases, bit durability may decrease. Conversely, as bit durability increases, bit efficiency may decrease.

However, example implementations may develop and use a drill bit to drill a predefined section of a target well such that there is both a high bit efficiency and a high bit durability. For example, some implementations may leverage the data measured and collected while drilling an offset well. Such data may include 1) one or more drilling parameters of the base drill bit used to drill the section of the offset well that was drilled and 2) one or more drilling conditions during drilling of this section of the offset well.

For instance, in-bit sensors within a drill bit (used in drilling the offset well) may measure different drill bit response data. Examples of such drill bit response data measured may include Weight On Bit (WOB), Torque On Bit (TOB), Rate Of Penetration (ROP), rotations per unit of time (e.g., Rotations Per Minute (RPM). Additionally, rock strength index and rock abrasiveness index along drilling depth may be available using logging while drilling (LWD) tools (such as gamma ray, sonic logging, etc.). Data regarding final cutter and bit dull of the drill bit after drilling may also be available. Using this different data as input, a bit-rock interaction simulation may be developed that simulates drilling along drilling depth of the offset well.

Example implementations may include four operations to set a best drill bit to be used for drilling a target well. First, using these drilling parameters and drilling conditions for drilling the offset well as input, a bit-rock interaction simulation of the offset well (known as the offset well simulation) may be developed. This simulation may include simulation at different distances (such as foot by foot) along the drilling depth of the section of the offset well that was drilled. The performance of the base drill bit (also referenced as a base drill bit performance) may be evaluated using this simulation. This simulation may include estimating energy input to the drill bit and energy required by the drill bit. This simulation may also include estimating a rock abrasiveness factor of the rock of the formation being drilled. The rock strength or the cutter axial force and drag force models may be calibrated. If evaluation of the rock strength trusted more than the cutter axial force and drag force models in terms of accuracy, the rock strength may be calibrated. Conversely, if evaluation of the cutter axial force and drag force models is trusted more than the rock strength evaluation in terms of accuracy, the cutter axial force and drag force models may be calibrated. This simulation may then be used to evaluate the drill bit performance. Thus, this first step may include evaluating the base drill bit performance. This first step may be known as “repeat drilling by model” operation.

Second, a design of an existing drill bit may be changed or a new drill bit (both referred to as the new drill bit) may be selected based on evaluation of the drill bit performance. For example, the new drill bit (as compared to the base drill bit) may be different in terms of the number and/or type of cutters, the cutter geometry, the composition of the drill bit (such as cobalt steel, carbide, diamond-coated, etc.), etc.

Third, using this updated current drill bit or a newly selected drill bit (referred to as the new drill bit), the offset well simulation may be executed using the same or similar inputs (which may include the drilling parameters and the drilling conditions) for the offset well. Fourth, the newly selected drill bit may then be evaluated based on this offset well simulation. If performance of this new drill bit is better than the base drill bit, the new drill bit may be used to drilling in conditions similar to those of the simulation. If the new drill bit does not perform better than the base drill bit, new parameters may be selected and additional simulations may be run. The second, third, and fourth operations may be repeated, if necessary, until an acceptable “better” drill bit has been determined. An acceptable “better” drill bit may be defined as a drill bit that may drill the predefined length of depth of the wellbore being drilled efficiently with a high durability. For example, a “better” drill bit includes a drill bit having a better drill bit efficiency (which may be evaluated in terms of ROP) and a better drill bit durability (which may be evaluated in terms of cutter level dull severities).

After selection of a new drill bit as the best drill bit using this offset well simulation, the new drill bit may be used in drilling a target well. For example, the offset well and the target well may be in a same or similar in terms of geographic location, type of rock being drilled, type of well (vertical, lateral, etc.), etc.

Example Well System

FIG. 1 an elevation view (partially cross sectional) of an example well system, according to some implementations. In particular, FIG. 1 is a schematic diagram of a well system 100 that includes a drill string 180 having a drill bit 112 disposed in a wellbore 106 for drilling the wellbore 106 in the subsurface formation 108. While depicted for a land-based well system, example embodiments can be used in subsea operations that employ floating or sea-based platforms and rigs. The drill bit 112 is an example drill bit for which simulation of abrasive wear and damage as described herein can be performed.

The well system 100 may further include a drilling platform 110 that supports a derrick 152 having a traveling block 114 for raising and lowering the drill string 180. The drill string 180 may include, but is not limited to, drill pipe, drill collars, and down hole tools 116. The down hole tools 116 may comprise any of a number of different types of tools including measurement while drilling (MWD) tools, logging while drilling (LWD) tools, mud motors, and others. A kelly 115 may support the drill string 180 as it may be lowered through a rotary table 118. The drill bit 112 may include roller cone bits, polycrystalline diamond compact (PDC) bits, natural diamond bits, any hole openers, reamers, coring bits, and the like. As the drill bit 112 rotates, it may crush or cut rock to create and extend a wellbore 106 that penetrates various subterranean formations. The drill bit 112 may be rotated by various methods including rotation by a downhole mud motor and/or via rotation of the drill string 180 from the surface 120 by the rotary table 118. Attributes of drilling the wellbore may be adjusted to increase, decrease, and/or maintain the rate of penetration (ROP) of the drill bit 112 through the subsurface formation 108. Attributes may include weight-on-bit (WOB) and rotations-per-minute (RPM) of the drill string 180. In some embodiments, the drill bit 112 may become dull and lose efficiency, thus requiring more WOB and/or RPM to maintain a target ROP. A pump 122 may circulate drilling fluid through a feed pipe 124 to the kelly 116, downhole through interior of the drill string 180, through orifices in the drill bit 112, back to the surface 120 via an annulus surrounding the drill string 180, and into a retention pit 128.

The well system 100 includes a computer 170 that may be communicatively coupled to other parts of the well system 100. The computer 170 can be local or remote to the drilling platform 110. A processor of the computer 170 may perform simulations (as further described below). In some embodiments, the processor of the computer 170 may control drilling operations of the well system 100 or subsequent drilling operations of other wellbores.

An example of the computer 170 is now described. FIG. 2 is a block diagram of an example computer, according to some implementations. FIG. 2 depicts a computer 200 that includes a processor 201 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer 200 includes a memory 207. The memory 207 may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer 200 also includes a bus 203 and a network interface 205.

The computer 200 also includes a simulation processor 211 and a controller 215. The simulation processor 211 and the controller 215 can perform one or more of the operations described herein. For example, the simulation processor 211 can perform data processing and simulation operations as further described below. The controller 215 may perform various control operations to a wellbore operation based on the simulations. For example, the controller 215 can modify a drilling operation based on the simulations.

Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 201. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 201, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 2 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor 201 and the network interface 205 are coupled to the bus 203. Although illustrated as being coupled to the bus 203, the memory 207 may be coupled to the processor 201.

Nonlinear Cutter Wear Model

Some implementations may include a nonlinear cutter wear model for at least one of step wear of a cutter and nonlinear velocity of a cutter during drilling. To illustrate, FIG. 3 is a graphical representation of a cutter of a drill bit, according to some implementations. In FIG. 3, a cutter 300 includes a cutting element 301 and a body 303. In some implementations, the cutting element 301 may be composed of diamond. The body 303 may be composed of other less costly material (such as carbide).

As shown, a critical cutter energy (Ec) may be defined as the energy associated with a wear depth of the cutter 300 substantially equaling the chamfer size. A critical wear depth (Wc) may be defined as the depth wherein the cutting element 301 is worn away to a point where the body 303 is starting to be in contact with the formation being drilled.

To further illustrate, FIG. 4 is a graph defining an example relationship between the cutter wear volume and energy of a cutter of a drill bit, according to some implementations. FIG. 4 depicts a graph 400 that includes an x-axis that is the energy (E) 402 of the drill bit and a y-axis that is the cutter wear volume (V) 404 of the drill bit. The graph 400 includes a line 405 that starts at an Ec 403 (when V is zero). A first part 407 of the line 405 is based on μ (a constant), Ka (the rock abrasive factor), and Kb (the cutter wear resistance factor. A second part 409 of the line 405 is based on μ, Ka, Kb, and Kc (cutter and body element wear resistance factor).

In some implementations, the nonlinear cutter wear model for a cutter of a drill bit may be defined as follows. If E is less than Ec, V=0 (as shown in the graph 400 of FIG. 4). However, if E is not less than Ec, a determination is made of whether the cutter wear depth (Wd) is less than Wc. If Wd is less than Wc, the cutter wear volume (V) may be defined by Equation (1):

V = μ ⁢ Ka ⁢ Kb ⁢ ( E - Ec ) ( 1 )

However, if Wd is not less than Wc, V may be defined by Equation (2):

V = μ ⁢ Ka ⁢ Kb ⁢ Kc ⁢ ( E - Ec ) ( 2 )

Also, as part of the nonlinear cutter wear model, a nonlinear velocity of the drill bit may be determined. A critical velocity (Vc) may be defined as the last cone cutter's velocity of the drill bit. Vc may be fixed in a simulation for a drill bit (even when drilling parameters are changed.

Cutter power (Pt) may be defined as follows. If the velocity (Vel) of the drill bit is less than or equal to Vc, P may be defined by Equation (3):

Pt = F * ( V m ) ( 3 )

wherein F is the force and m is a constant (0.5˜0.75). However, if Vel is not less than Vc, P may be defined by Equation (4):

Pt = F * ( V ) ( 4 )

Additionally, cutter energy (E) may be defined by Equation (5):

E = Pt * T ( 5 )

wherein T is time.

Additionally, a cutter wear severity may be defined by a cutter wear depth. To illustrate, FIG. 5 is a graphical representation of a cutter of a drill bit, according to some implementations. FIG. 5 depicts a cutter 500 having a cutter wear depth and at a back rake angle (BRa). A cutter wear depth may be a function of back rake angle, cutter diameter, chamfer size, cutter shape and cutter wear volume. For a cutter wear severity, a critical cutter wear severity (Sc) may be defined by Equation (6):

Sc ⁢ = 8 ⁢ ( Cutter ⁢ Wear ⁢ Depth / Diameter ) ( 6 )

If Sc=4, cutter wear depth=0.5 diameter. Therefore, Sc=4 may be defined as the maximal cutter wear severity. If Sc>4, the cutter may be considered lost.

Example Operations

Example operations are now described. First, example operations for determining a cutter wear severity based on input drill bit energy are described. Next, example operations for determining the input drill bit energy based on the cutter wear severity are described.

Example Operations for Determining Cutter Wear Severity

Example operations for determining cutter wear severity are now described. FIG. 6 is a flowchart of example operations for determining a cutter wear severity for cutters of a drill bit during drilling of a wellbore, according to some implementations. Operations of a flowchart 600 of FIG. 6 are described in reference to the well system 100 of FIG. 1 and the computer 200 of FIG. 2. Operations of the flowchart 600 start at block 602.

At block 602, an input drill bit energy is determined. For example, the input drill bit energy may include at least one of WOB, TOB, ROP, rotation speed, etc. of the drill bit. With reference to FIG. 2, the processor 201 may retrieve these measurements from one or more sensors positioned at the surface and/or downhole in the wellbore.

The energy input to the drill bit may include the primary cutters, backup cutters, Depth of Cut Controllers (DOCCs) and blades. However, the energy input to primary cutters may need to be determined. Accordingly, an estimation of how much at least one of WOB or TOB is applied to the primary cutters may be determined. To illustrate, FIG. 7 is a graph of weight on bit (WOB) contributed from primary cutters, backup cutters, Depth of Cut Controllers (DOCCs) and blades at a bit wear level 5, according to some implementations. In particular, FIG. 7 includes a graph 700 having lines for the primary cutters, the backup cutters, and the DOCCs and blades. FIG. 8 is a graph of a ratio of WOB from the primary cutters to WOB at the bit wear level 1 to 10, according to some implementations. In particular, FIG. 8 includes a graph 800.

In some implementations, WOB ratio may be determined based on Equation (7):

λ ⁢ w = WOB_p / WOB * 100 ⁢ % ( 7 )

In some implementations, TOB ratio may be determined based on Equation (8):

λ ⁢ t = TOB_p / TOB * 100 ⁢ % ( 8 )

Both λw and λt may depend on depth of cut (DOC) and bit wear. These ratios may be pre-calculated and saved for subsequent use. Returning to FIG. 6, operations of the flowchart 600 continues at block 604.

At block 604, cutter forces (for at least one cutter of the drill bit) are determined based on the input drill bit energy. With reference to FIG. 2, the processor 201 may make this determination. In some implementations, the processor 201 may retrieve pre-calculated scaled cutter axial and torque forces distributions for a given DOC and a bit wear level. In some implementations, the cutter forces being determined may be the axial force and the drag force for the at least one cutter.

The processor 201 may then determine the axial forces coefficient (ηa) based on the Equation (9):

η ⁢ a = WOB / ∑ 1 n ⁢ F a i ( 9 )

The processor 201 may then determine an axial force (Fa) for each cutter based on Equation (10):

Fa = η ⁢ a * F a i ( 10 )

F a i

is scared cutter axial force of cutter i

The processor 201 may also determine a torque coefficient (ηd) based on Equation (11):

η ⁢ d = TOB / ∑ 1 n ⁢ T d i ( 11 )

The processor 201 may then determine a torque (Td) for each cutter based on Equation (12):

Td = η ⁢ d * T d i ( 12 )

T d i

is scared cutter torque or cutter i

The processor 201 may determine a drag force (Fd) for each cutter based on Equation (13):

Fd = Td / Rc ( 13 )

wherein Rc is the cutter radial location on the drill bit. Accordingly, the processor 201 may determine the cutter forces for a given cutter of the drill bit (which may be a combination of the axial force and the drag force for the given cutter).

At block 606, cutter power (for the at least one cutter of the drill bit) is determined based on the cutter forces. With reference to FIG. 2, the processor 201 may make this determination. In some implementations, the processor 201 may determine cutter power (Pc) based on Equations (14)-(16):

Pa = Fa * Va ( 14 ) Pt = Fd * Vc ( 15 ) Pc = Pa + Pt ( 16 )

wherein Va and Vc are axial velocity and cutting velocity, respectively.

At block 608, cutter energy (for the at least one cutter of the drill bit) is determined based on the cutter power. With reference to FIG. 2, the processor 201 may make this determination. In some implementations, the processor 201 may determine cutter energy (Ec) based on Equation (17):

Ec = Pc * T ( 17 )

wherein T is the time.

At block 610, cutter wear volume (for the at least one cutter of the drill bit) is determined based on the cutter energy. With reference to FIG. 2, the processor 201 may make this determination. In some implementations, the processor 201 may determine cutter wear volume (Vc) based on Equation (18):

Vc = Vw = μ ⁢ Ka ⁢ KwEc ( 18 )

At block 612, cutter wear depth (for the at least one cutter of the drill bit) is determined based on the cutter wear volume. With reference to FIG. 2, the processor 201 may make this determination.

At block 614, cutter wear severity (for the at least one cutter of the drill bit) is determined based on the cutter wear depth. With reference to FIG. 2, the processor 201 may make this determination.

FIG. 9 is a graph illustrating bit energy in relation to drilling depth for a simulation. The graph 900 includes a curve 902 indicating bit energy (lb-inch) input into the primary cutters at drilling depths ranging from 2000 feet to 10,000 feet. Each point 904 indicates an amount of bit energy required for the primary cutters to reach a given bit wear level. For example, point 9 corresponding to a depth approximately 8700 feet indicates that the bit required energy has reached its maximum where bit wear level is at its maximum and the bit is unable to drill further. The line 906 indicates a threshold above which the corresponding amount of bit energy will cause excessive wear to the primary cutters. Given that the curve 902 includes values exceeding the threshold line 906, the bit energy has caused too much wear, so the drill bit is not durable enough for the conditions of this simulation.

FIG. 10 is a graph illustrating is a graph illustrating bit energy in relation to drilling depth for simulation. The graph 1000 includes a curve 1002 indicating bit energy (lb-inch) input into the primary cutters at drilling depths ranging from 2000 feet to 10,000 feet. Each point 1004 indicates an amount of bit energy required for the primary cutters to reach a given bit wear level. For example, at the end of drilling corresponding approximately to a depth at 5500 feet, the bit wear level is less than 7 indicating that the bit required energy is not at its maximum and the bit is able to drill further.

These following examples of FIGS. 11A-11B and FIGS. 12A-12B explain how some implementations may select a drill bit. Thus, for the first example (FIGS. 11A-11B), a new drill bit may be selected having greater durability but with a decreased drilling efficiency. In contrast, for the second example (FIGS. 12A-12B), a new drill bit may be selected having less durability but with an increased drilling efficiency.

FIGS. 11A depicts graphs 1100 and 1150. FIG. 11B depicts graph 1170. The graph 1100 includes an x-axis 1102 that is the bit wear level and a y-axis 1104 that is the bit required energy. The graph 1150 includes an x-axis 1152 that is the drill depth and a y-axis 1154 that is the input bit energy. The graph 1170 includes an x-axis 1172 that is the drill depth and a y-axis 1174 that is the bit wear level.

The graph 1100 includes a plot 1106 showing the required energy to wear the primary cutters of the drill bit at different bit wear levels. The plot 1106 includes a point 1108 (E_bit). As shown, the point 1108 corresponds to the bit required energy for a bit wear level of 10. The graph 1150 includes a plot 1156 showing the input energy into the primary cutters of the drill bit along different drilling depths. The plot 1156 includes a point 1158 that corresponds to the same energy as the point 1108. The point 1158 corresponds to the actual input energy into the primary cutters at a drilling depth of approximately 11000 feet. Thus, the maximal bit wear level of 10 is reached at approximately 11000 feet. The graph 1170 includes a plot 1176 showing different bit wear levels at different drilling depths based on being scaled by the E_bit. The plot 1176 includes different points (points 1177-1184) associated with different bit wear levels at different drilling depths. In this example of FIGS. 11A-11B, the life of the drill bit is too short-as a maximum drill bit level of 10 was reached at only 6000 ft (instead of 10000 ft). Accordingly, a new drill bit is needed to increase the drill bit durability.

An example where the bit input energy is lower than the bit required energy and the bit durability is high enough to drill the section of the well is now described in reference to FIGS. 12A-12C. FIG. 12A includes an example graph of a bit required energy versus a bit wear level for a second example of determining bit wear level in drilling, according to some embodiments. FIG. 12A also includes an example graph of an input bit energy versus a drill depth for the second example of determining bit wear level in drilling, according to some embodiments. FIG. 12B is an example graph of a bit wear level versus a drill depth for the second example of determining bit wear level in drilling, according to some embodiments.

FIGS. 12A-12B depict graphs 1200, 1250, and 1270. The graph 1200 of FIG. 12A includes an x-axis 1202 that is the bit wear level and a y-axis 1204 that is the bit required energy. The graph 1250 of FIG. 12A includes an x-axis 1252 that is the drill depth and a y-axis 1254 that is the input bit energy. The graph 1270 of FIG. 12B includes an x-axis 1272 that is the drill depth and a y-axis 1274 that is the bit wear level.

The graph 1200 includes a plot 1206 showing the required energy to wear the primary cutters of the drill bit at different bit wear levels. The plot 1206 includes a point 1208 (E_bit). As shown, the point 1208 corresponds to the bit required energy for a bit wear level of approximately 5.5. The graph 1250 includes a plot 1256 showing the input energy into the primary cutters of the drill bit along different drilling depths. The plot 1256 includes a point 1258 that corresponds to the same energy as the point 1208. The point 1258 corresponds to the actual input energy into the primary cutters at a drilling depth of approximately 10000 feet. Thus, the bit wear level of 5.5 is reached at approximately 10000 feet. The graph 1270 includes a plot 1276 showing different bit wear levels at different drilling depths based on being scaled by the E_bit. The plot 1276 includes different points (points 1277-1281) associated with different bit wear levels at different drilling depths. In this example of FIGS. 12A-12B, the life of the drill bit is sufficient to drill the section of the well to the intended depth (10000 ft) prior to reaching a maximum drill bit level of 10. Accordingly, this selected drill bit has sufficient drill bit durability to drill the section of the well. In this example, there may be unused durability of the drill bit because the drilling depth of 10000 ft was reached prior to the bit being worn out at bit wear level of 10. Thus, in this example, the bit efficiency could be increased to drill at a faster rate without wearing out the drill bit.

Hence, from the first example (FIGS. 11A-11B), a new drill bit may be selected having greater durability but with a decreased drilling efficiency. In contrast, from the second example (FIGS. 12A-12B), a new drill bit may be selected having less durability but with an increased drilling efficiency.

Example General Operations to Select/Design a Drill Bit for a Predefined Well Section

FIG. 13 is a block diagram showing operations to select or design a drill bit for predefined well section. The flowchart 1100 shows the example operations. The flowchart 1100 may be described with reference to the computer 200 of FIG. 2.

At block 1302, the simulation processor 211 pre-calculates bit characteristics of an offset bit (also referred to as a base bit) will be used in a simulation of an offset field drilling run of a well section.

At block 1304, the simulation processor 211 simulates the offset field drilling run of the base bit. The simulation may entail estimations of rock abrasiveness and rock strength for the well section. Additional aspects of such a simulation are described (below) with reference to FIGS. 12-13.

At block 1306, the simulation processor 211 selects or designs a new drill bit. The simulation processor 211 may select or design the new drill bit in an attempt to find a better performing drill bit.

At block 1308, the simulation processor 211 simulates the offset field drilling run with the new drill bit. The drilling conditions of the offset field drilling run are the same as those in the simulation performed at block 1304. Additional aspects of such a simulation are described (below) with reference to FIGS. 16-17.

At block 1310, the simulation processor 211 compares performance of the new bit to performance of the base bit. The comparison may entail comparisons of drilling efficiency and/or bit durability.

At block 1312, the simulation processor 211 determines whether the new bit performed better than the base bit. If the new bit performed better, operations continue at block 1114. Otherwise, operations continue at block 1306. In some implementations, the drill bit performs better by having better durability and/or better drilling efficiency.

At block 1314, the bit selection or bit design of the new bit is saved. Operations end after block 1314.

Example Operations of Simulation of an Offset Well-Base Drill Bit

FIGS. 14-15 are block diagrams of a flowchart of an offset well simulation of drilling an offset well using a base drill bit, according to some embodiments. Operations of a flowchart 1400 of FIG. 14 and a flowchart 1500 of FIG. 15 are described in reference to the well system 100 of FIG. 1 and the computer 200 of FIG. 2. Also, operations of the flowchart 1400 of FIG. 14 and the flowchart 1500 of FIG. 15 continue between each other through transition point A. Operations of the flowcharts 1400-1500 start at block 1402.

At block 1402, data regarding the drilling parameters and drilling conditions from the drilling of the section of the offset well is retrieved. For example, with reference to FIG. 2, the simulation processor 211 may retrieve the data from any type of machine-readable media (local or remote). For example, with reference to FIG. 1, the data may be related to drilling of the wellbore 106 (which may be an offset well). The data may include 1) a bit response (including WOB, TOB, RPM and ROP) by a base drill bit based on data derived from drilling a section of an offset well using the base drill bit, 2) a rock abrasiveness of the formation of the section of the offset well that was drilled, 3) a cutter dullness severity of the cutters of the base drill bit resulting from drilling the section of the offset well, and 4) a rock strength index of the formation of the section of the offset well that was drilled.

At block 1404, a drilling efficiency of the base drill bit is calculated. A bit drilling efficiency may be defined as DE=rock strength/MSE*100%. MSE is mechanical specific energy. For example, with reference to FIG. 2, the simulation processor 211 may perform this calculation. In some implementations, a bit efficiency (DE) may be determined using Equation 1:

DE = ( rock ⁢ strength / MSE ) * 100 ⁢ % ( Eq . 1 )

This computation may be used later when comparing the performance of two drill bits (such as at block 1310 of FIG. 13, at block 1704 of FIG. 17, or with other suitable processes).

At block 1406, an energy input into the base drill bit along the drilling depth is calculated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calculation. An energy input (E_input) to bit after drilling a distance S may be calculated using Equation 2:

E input = MSE * 3.14 * R ^ 2 * S ( Eq . 2 )

wherein R is the hole radius.

At block 1408, the following values at each bit wear level and at each depth of cut are pre-calculated: 1) WOB, 2) TOB, 3) drilling efficiency, 4) scaled cutter axial force and torque, 5) WOB to the primary cutters, and 6) TOB to the primary cutters. For example, with reference to FIG. 2, the simulation processor 211 may perform these pre-calculations. The cutter dull severity (Sd) may be estimated using Equation 3:

Sd = 8. * Wd / Dc ( Eq . 3 )

Wherein Dc is cutter diameter and Wd is cutter wear depth.

Sd=4 means that half of the PDC (Polycrystalline Diamond Compact) cutter is worn out.

The cutter wear depth (Wd) may be calculated using Equation 4:

Wd = Sd * Dc / 8. ( Eq . 4 )

wherein Dc is a cutter diameter (that may be measured in inches). In some implementations, Wd is the possible maximal cutter wear distribution (final bit wear level). Also, as part of the pre-calculation, the bit profile may be divided into N (N>1) bit wear levels.

At each bit wear level, and at each depth of cut, the following may be calculated: 1) WOB and TOB; 2) WOB_p and TOB_p (WOB for the primary cutter and the TOB for the primary cutter, respectively); scaled cutter axial forces; scaled cutter drag forces; drilling efficiency; and required bit energy at each bit wear level. At a given bit wear level, cutter wear depth is known, and cutter wear volume may be calculated. On the other hand, cutter wear volume is proportional to cutter energy. Therefore, the required cutter energy to wear a cutter to a wear depth may be calculated. The sum of the required energy of all cutters may be defined as the bit required energy. In some implementations, the bit wear levels may be defined from 0-8. In some implementations, the bit wear level and the depth of cut may be divided into 10 points or more than 10 points.

At block 1410, an estimated total energy input to the primary cutters of the base drill bit is calculated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calculation. In some implementations, the simulation processor 211 may perform this calculation of the estimated total energy input to the primary cutters based on the pre-calculated values (such as WOB_p and TOB_p) calculated as part of the operations at block 1408.

At block 1412, cutter wear volume based on the cutter input energy is calculated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calculation. Operations of the flowchart 1400 continue at transition point A, which continues at transition point A of the flowchart 1400 of FIG. 14. From transition point A of the flowchart 1400 of FIG. 14, operations continue at block 1402.

At block 1502, rock abrasiveness factors are calibrated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calibration. The rock abrasiveness may be calibrated by equaling the total input energy to the primary cutters to the required energy by the primary cutters at the drilling end of the offset well. In some implementations, the simulation processor 211 may perform this calibration of the rock abrasiveness factors based on the pre-calculated values calculated as part of the operations at block 1408.

At block 1503, rock strength along the drilling depth is estimated. For example, the simulation processor 211 may estimate rock strength along the drilling depth.

At block 1504, rock strength or cutter axial and drag force models are calibrated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calibration. In some implementations, rock strength or cutter axial and drag force models are calibrated using the measured downhole WOB and TOB and the calculated WOB and TOB from the drilling simulator. In some implementations, the simulation processor 211 may perform this calibration of the rock strength or cutter axial and drag force models based on measured bit response values and the pre-calculated values calculated as part of the operations at block 1408.

At block 1506, an offset well simulation of the section of the offset well using the base drill bit is performed. For example, with reference to FIG. 2, the simulation processor 211 may perform this operation. In some implementations, the simulation processor 211 may perform this offset well simulation of the section of the offset well based on the pre-calculated values calculated as part of the operations at block 1408. A result of the offset well simulation using the base drill bit may include an analysis of the base drill bit performance. For example, the base drill bit performance may include the ROP, the TOB, the drilling efficiency, the drilling depth vs. time, the input energy required to wear the primary cutters, the cutter dull severity vs. drilling depth, etc. Examples of such output from the simulation using the base drill bit are depicted in FIGS. 10A-10B and 11-19, which are further described below. Operations of the flowchart 1500 are complete.

Example Operations of Simulation of an Offset Well-New Drill Bit

FIGS. 16-17 are block diagrams of a flowchart of an offset well simulation of drilling using a new drill bit under the same or similar drilling conditions as the drilling of the offset well, according to some embodiments. Operations of a flowchart 1600 of FIG. 16 and a flowchart 1700 of FIG. 17 are described in reference to the well system 100 of FIG. 1 and the computer 200 of FIG. 2. Also, operations of the flowchart 1600 of FIG. 16 and the flowchart 1700 of FIG. 17 continue between each other through transition points B and C. Operations of the flowcharts 1600-1700 start at block 1602.

At block 1602, drilling conditions and drilling parameters from the offset well simulation (including bit characteristics, rock strength and rock abrasiveness factors) are retrieved. For example, with reference to FIG. 2, the simulation processor 211 may retrieve the data from any type of machine-readable media (local or remote). For example, with reference to FIG. 1, the data may be related to drilling of the wellbore 106 (which may be an offset well). The data may include 1) a bit response (including WOB, TOB, RPM and ROP) by a base drill bit based on data derived from drilling a section of an offset well using the base drill bit, 2) a rock abrasiveness of the formation of the section of the offset well that was drilled, 3) a cutter dullness severity of the cutters of the base drill bit resulting from drilling the section of the offset well, and 4) a rock strength index of the formation of the section of the offset well that was drilled.

At block 1604, a new drill bit is selected. For example, with reference to FIG. 2, the simulation processor 211 may perform this selection based on user input, results of the offset well simulation using the base drill bit, etc. In some implementations, this selection may be based on the graphs of FIGS. 6A-6C and 7A-7C that correlates the bit wear level to drilling depth for the offset well simulation using the base drill bit. For instance, for the example of FIGS. 6A-6C, a new drill bit may be selected having an increased drill durability (as compared to the offset (base) drill bit. For the example of FIGS. 7A-7C, a new drill bit may be selected to allow for an increased input energy for the drill bit.

At block 1606, an estimated total energy input to the primary cutters of the new drill bit to drill the section of the offset well based on the drilling conditions and drilling parameters from the offset well simulation is calculated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calculation.

At block 1608, an estimated energy required to wear the new drill bit to each bit wear level is calculated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calculation.

At block 1610, a determination is made of whether the maximum input energy into the new drill bit is greater than the required input energy into the new drill bit. For example, with reference to FIG. 2, the simulation processor 211 may make this determination. If the maximum input energy into the new drill bit is greater than the required input energy into the new drill bit, operations of the flowchart 1600 continue at block 1612. Otherwise, operations of the flowchart 1600 continue at block 1614.

At block 1612, a new drill bit to increase the bit durability is selected. For example, with reference to FIG. 2, the simulation processor 211 may perform this selection by selecting a new drill bit or modifying attributes of the currently selected new drill bit. Operations of the flowchart 1600 return to block 1606 to calculate an estimated total energy input to the primary cutters of the new drill bit to drill the section of the offset well based on the drilling conditions and drilling parameters from the offset well simulation.

At block 1614, the offset well simulation of the section of the offset well using the new drill bit and based on the offset well drilling conditions is performed. For example, with reference to FIG. 2, the simulation processor 211 may perform this offset well simulation.

At block 1616, a new drill bit performance based on the offset well simulation using the new drill bit is determined. For example, with reference to FIG. 2, the simulation processor 211 may make this determination. Operations of the flowchart 1600 continue at transition point B, which continues at transition point B of the flowchart 1700 of FIG. 17.

From the transition point B of the flowchart 1700, operations continue at block 1702.

At block 1702, the base drill bit performance is compared to the new drill bit performance as a function of drilling depth. For example, with reference to FIG. 2, the simulation processor 211 may perform this comparison. The comparison may be based on a combination of the drill bit efficiency and the drill bit durability. For example, the comparison may be based on the ROP (the drill bit efficiency) and cutter level dullness severity (the drill bit durability).

At block 1704, a determination is made of whether the new drill bit performance exceeds the base drill bit performance beyond a performance threshold. For example, with reference to FIG. 2, the simulation processor 211 may make this determination. If the new drill bit performance does not exceed the base drill bit performance beyond the performance threshold, operations of the flowchart 1700 continue at transition point C, which continues at transition point C of the flowchart 1800 (where a new drill bit is selected at block 1604). If the new drill bit performance does exceed the base drill bit performance beyond the performance threshold, operations of the flowchart 1700 continue at block 1706.

At block 1706, one of the new drill bits (that had been simulated) that has the best combination of drill bit efficiency and drill bit durability is selected for drilling a target well. For example, with reference to FIG. 2, the simulation processor 211 may make this selection. To help illustrate, FIG. 18 (which is further described below) is an example table of the comparisons among the base drill bit and three example new drill bits, wherein the 1^st example new drill bit is selected because this new drill bit had the highest drill bit efficiency (ROP=242.02 ft/hr) and the best drill bit durability (the lowest maximum cutter dull severity=1.5).

At block 1708, the section of the target well (that has the same or similar drilling conditions as the section of the offset well that was simulated) is drilled using the selected new drill bit that has the best combination of drill bit efficiency and drill bit durability. Operations of the flowchart 1700 are complete.

Example Operations of Simulation of a Drill Bit Run under Different Drilling Conditions

FIGS. 19 and 20 are flow diagrams that illustrate example operations for simulating a drilling run of a drill bit under different conditions. This simulation may use a drill from a previous simulation (such as a drill bit from a previous simulation performed according to the operations shown in FIGS. 16 and 17).

In FIG. 19, example operations for simulating, under different conditions, a drilling run of a drill bit begin at block 1902. At block 1902, drill bit characteristics are retrieved. The drill bit characteristics may be from a drill bit for which the simulation processor 211 has previously performed a simulation (such as a base bit). The drill bit characteristics may include WOB, TOB, DE, scaled axial force and torque, TOB to primary cutters and any other suitable characteristics of a drill bit for which there was a previous simulation. The drill bit characteristics may include a bit response (including WOB, TOB, RPM, ROP, etc.) by a base drill bit based on data derived from drilling a section of an offset well using the base drill bit. The simulation processor 211 may retrieve the data from any type of machine-readable media (local or remote). For example, with reference to FIG. 1, the data may be related to drilling of the wellbore 106 (which may be an offset well). Additionally, the simulation processor may retrieve data including 1) a rock abrasiveness of the formation of the section of the offset well that was drilled, 2) a cutter dullness severity of the cutters of the base drill bit resulting from drilling the section of the offset well, and 3) a rock strength index of the formation of the section of the offset well that was drilled.

At block 1906, an estimated total energy input to the primary cutters of the new drill bit to drill the section of the offset well based on the drilling conditions and drilling parameters from the offset well simulation is calculated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calculation.

At block 1908, an estimated energy required to wear the new drill bit to each bit wear level is calculated. For example, with reference to FIG. 2, the simulation processor 211 may perform this calculation.

At block 1910, a determination is made of whether the maximum input energy into the new drill bit is greater than the required input energy into the new drill bit. For example, with reference to FIG. 2, the simulation processor 211 may make this determination. If the maximum input energy into the new drill bit is greater than the required input energy into the new drill bit, operations of the flowchart 1600 continue at block 1612. Otherwise, operations of the flowchart 1600 continue at block 1614.

At block 1912, there is a reduction to WOB, ROP, and/or RPM associated with the drill bit. The simulation processor 211 may perform this operation. The operations continue at block 1906.

At block 1914, an offset well simulation of the offset well section is performed using the drill bit based on the given WOB and RPM in the drill bit characteristics (see block 1902).

At block 1916, comparison is made between drill bit performance in the base run (a previously run offset well simulation) and the simulation performed at block 1914 (the current offset well simulation). The performance comparison may compare ROP, drill bit drilling efficiency, drill bit durability (such as cutter dull severities), and or any other suitable aspects that may indicate comparative performance of the drill bits. Operations continue at block 2004 of FIG. 20.

In FIG. 20, at block 2004, a determination is made about whether the drill bit exceeds a performance threshold under the new conditions. The simulation processor 211 may perform this operation. If the drill bit exceeds the performance threshold, operations continue at block 2006. Otherwise, operations continue at block 2008.

At block 2006, a section of a well (such as the target well) is drilled using the drill bit. Alternatively, or in addition, the simulation processor 211 may transmit notifications indicating that the drill bit is suitable for particular sections of a particular well.

At block 2008, the WOB, ROP, and/or RPM are modified. This operation may be performed by the simulation processor 211. Operations continue at block 1906 of FIG. 19.

Example Drill Bits and Drill Bit Performance

FIGS. 21A-21B are a bottom side view and a perspective view, respectively, of an example drill bit for drilling a well. In particular, FIGS. 21A-21B include a bottom side view and a perspective view of a first example drill bit 2100 for which one or more simulations may be performed. As described here, some implementations perform a plurality of simulations, where each simulation simulates a drilling run with a different drill bit to determine which drill bit performs best on the drilling run (i.e., same conditions but different drill bits) (such as FIGS. 16-17). Some implementations may perform a plurality of simulations on the same drill bit, where each simulation exposes the drill bit to different conditions (i.e., same drill bit but different conditions) (such as in FIGS. 19-20).

FIGS. 22-32 are graphs illustrating performance aspects of a drill bit for a drilling run. The drill bit may be a base bit and the graphs may illustrate performance aspects of the base bit as determined via one or more simulations of the base bit. Some implementations may generate the performance aspects shown in FIGS. 22-30 by performing the operations described with reference to FIG. 13 and/or FIGS. 14-15.

While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. Many variations, modifications, additions, and improvements are possible.

Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.

Example Embodiments

Example embodiments are now described.

Embodiment #1: A method for selection of a target drill bit for drilling a section of a target well, the method comprising: performing an offset well of drilling a section of an offset well using a base drill bit based on data measurements of drilling parameters and drilling conditions measured during drilling of the offset well; determining a base drill bit performance based on the offset well simulation; selecting a new drill bit for the offset well simulation; performing the offset well simulation using the new drill bit based on the data measurements of drilling parameters and drilling conditions measured during drilling of the offset well; determining a new drill bit performance based on the offset well simulation using the new drill bit, wherein the base drill bit performance and the new drill bit performance are based on a drill bit efficiency and a drill bit durability; determining whether the new drill bit performance exceeds the base drill bit performance; and selecting the new drill bit as the target drill bit for drilling the target well in response to the new drill bit performance exceeding the base drill bit performance.

Embodiment #2: The method of Embodiment #1, further comprising: performing an offset well simulation using the base drill bit based on the data measurements of drilling parameters and different drilling conditions measured during drilling of the offset well; determining the base drill bit performs better for the different drilling conditions; and recommending the base drill bit for use in the different drilling conditions.

Embodiment #3: The method of any one or more of Embodiments #1-2, wherein the drill bit efficiency is derived from at least one of a Rate of Penetration (ROP) or a Torque On Bit (TOB).

Embodiment #4: The method of any one or more of Embodiments #1-3, wherein the drill bit durability is derived from a wear of one or more cutters of the base drill bit for the base drill bit performance and a wear of the one or more cutters of the new drill bit for the new drill bit performance.

Embodiment #5: The method of any one of Embodiments #1-4, wherein performing the offset well simulation comprises, determining, at different points of drilling of the section of the offset well, at least one drilling parameter that comprises at least one of a Torque On Bit (TOB), Weight On Bit (WOB), a Rate of Penetration (ROP), or rotations per unit of time; and determining, at the different points of drilling of the section of the offset well, an energy expended by the base drill bit or the new drill bit used for performing the offset well simulation based on the at least one drilling parameter.

Embodiment #6: The method of any one or more of Embodiments #1-5, wherein performing the offset well simulation comprises, determining, at different points of drilling of the section of the offset well, a condition of the base drill bit or the new drill bit used for performing the offset well simulation that comprises a dullness severity of at least one cutter; and determining, at the different points of drilling of the section of the offset well, an energy needed by the base drill bit or the new drill bit used for performing the offset well simulation based on the condition of the base drill bit or the new drill bit used for performing the offset well simulation.

Embodiment #7: The method of any one of Embodiments #1-6, wherein performing the offset well simulation comprises, determining cutter axial force and drag force models of the base drill bit during the drilling of the offset well; and calibrating a rock strength of a subsurface formation through which the offset well is drilled based on the cutter axial force and drag force models.

Embodiment #8: The method of any one of Embodiments #1-7, wherein performing the offset well simulation comprises, determining a rock strength of a subsurface formation through which the offset well; and calibrating cutter axial force and drag force models of the base drill bit during the drilling of the offset well based on the rock strength.

Embodiment #9: The method of any one of Embodiments #1-9 wherein the base drill bit performance and the new drill bit performance are based on a dullness of one or more cutters of the base drill bit and the new drill bit, respectively.

Embodiment #10: The method of any one of Embodiments #1-9 wherein performing selecting a new drill bit for offset well simulation, performing the offset well simulation using the new drill bit, determining the new drill bit performance, and determining whether the new drill bit performance exceeds the base drill bit performance until the new drill bit performance exceeds a performance threshold

Embodiment #11: The method of any one of Embodiments #1-10 wherein drilling the target well using the new drill bit that most exceeds the performance threshold.

Embodiment #12: A non-transitory, computer-readable medium having instructions stored thereon that are executable by a processor to perform operations for selection of a target drill bit for drilling a section of a target well, the operations comprising: performing an offset well simulation of drilling a section of an offset well using a base drill bit based on data measurements of drilling parameters and drilling conditions measured during drilling of the offset well; determining a base drill bit performance based on the offset well simulation; selecting a new drill bit for the offset well simulation; performing the offset well simulation using the new drill bit based on the data measurements of drilling parameters and drilling conditions measured during drilling of the offset well; determining a new drill bit performance based on the offset well simulation using the new drill bit, wherein the base drill bit performance and the new drill bit performance are based on a drill bit efficiency and a drill bit durability; determining whether the new drill bit performance exceeds the base drill bit performance; and selecting the new drill bit as the target drill bit for drilling the target well in response to the new drill bit performance exceeding the base drill bit performance.

Embodiment #13: The non-transitory, computer-readable medium of Embodiments #12 further comprising: performing an offset well simulation using the base drill bit based on the data measurements of drilling parameters and different drilling conditions measured during drilling of the offset well; determining the base drill bit performs better for the different drilling conditions; recommending the base drill bit for use in the different drilling conditions.

Embodiment #14: The non-transitory, computer-readable medium of Embodiment #13, wherein the drill bit efficiency is derived from at least one of a Rate of Penetration (ROP) or a Torque On Bit (TOB).

Embodiment #15: The non-transitory, computer-readable medium of any one or more of Embodiments #13-14, wherein the drill bit durability is derived from a wear of one or more cutters of the base drill bit for the base drill bit performance and a wear of the one or more cutters of the new drill bit for the new drill bit performance.

Embodiment #16: The non-transitory, computer-readable medium of any one or more of Embodiments #13-15, wherein performing the offset well simulation comprises, determining, at different points of drilling of the section of the offset well, a condition of the base drill bit or the new drill bit used for performing the offset well simulation that comprises a dullness severity of at least one cutter; and determining, at the different points of drilling of the section of the offset well, an energy needed by the base drill bit or the new drill bit used for performing the offset well simulation based on the condition of the base drill bit or the new drill bit used for performing the offset well simulation.

Embodiment #17: The non-transitory, computer-readable medium of any one or more of Embodiments #13-16, wherein the drilling conditions comprise a rock abrasiveness factor of a subsurface formation through which the offset well is drilled.

Embodiment #18: The non-transitory, computer-readable medium of any one or more of Embodiments #13-17 further comprising: determining cutter axial force and drag force models of the base drill bit during the drilling of the offset well; and calibrating a rock strength of a subsurface formation through which the offset well is drilled based on the cutter axial force and drag force models

Embodiment #19: The non-transitory, computer-readable medium of any one or more of Embodiments #13-18, wherein performing the offset well simulation comprises, determining a rock strength of a subsurface formation through which the offset well; and calibrating cutter axial force and drag force models of the base drill bit during the drilling of the offset well based on the rock strength.

Embodiment #20: The non-transitory, computer-readable medium of any one or more of Embodiments #13-19, wherein the base drill bit performance and the new drill bit performance are based on a dullness of one or more cutters of the base drill bit and the new drill bit, respectively.

Embodiment #21: An apparatus comprising: a processor; and a computer-readable medium having instructions stored thereon that are executable by the processor to cause the processor to, perform an offset well simulation of drilling a section of an offset well using a base drill bit based on data measurements of drilling parameters and drilling conditions measured during drilling of the offset well; determine a base drill bit performance based on the offset well simulation; select a new drill bit for the offset well simulation; perform the offset well simulation using the new drill bit based on the data measurements of drilling parameters and drilling conditions measured during drilling of the offset well; determine a new drill bit performance based on the offset well simulation using the new drill bit, wherein the base drill bit performance and the new drill bit performance are based on a drill bit efficiency and a drill bit durability; determine whether the new drill bit performance exceeds the base drill bit performance; and select the new drill bit as a target drill bit for drilling a target well in response to the new drill bit performance exceeding the base drill bit performance.

Embodiment #22: The apparatus of Embodiment #21 further comprising: instructions to: perform an offset well simulation using the base drill bit based on the data measurements of drilling parameters and different drilling conditions measured during drilling of the offset well; determine the base drill bit performs better for the different drilling conditions; recommend the base drill bit for use in the different drilling conditions.

Embodiment #23: The apparatus of any one or more of Embodiments #21-22, wherein the drill bit efficiency is derived from at least one of a Rate of Penetration (ROP) or a Torque On Bit (TOB).

Embodiment #24: The apparatus of any one or more of Embodiments #21-23, wherein the drill bit durability is derived from a wear of one or more cutters of the base drill bit for the base drill bit performance and a wear of the one or more cutters of the new drill bit for the new drill bit performance.

Embodiment #25: The apparatus of any one or more of Embodiments #21-24, wherein the instructions that are executable by the processor to cause the processor to perform the offset well simulation comprises instructions that are executable by the processor to cause the processor to, determine, at different points of drilling of the section of the offset well, at least one drilling parameter that comprises at least one of a Torque On Bit (TOB), Weight On Bit (WOB), a Rate of Penetration (ROP), or rotations per unit of time; and determine, at the different points of drilling of the section of the offset well, an energy expended by the base drill bit or the new drill bit used for performing the offset well simulation based on the at least one drilling parameter.

Embodiment #26: The apparatus of any one or more of Embodiments #21-25, wherein the instructions that are executable by the processor to cause the processor to perform the offset well simulation comprises instructions that are executable by the processor to cause the processor to, determine, at different points of drilling of the section of the offset well, a condition of the base drill bit or the new drill bit used for performing the offset well simulation that comprises a dullness severity of at least one cutter; and determine, at the different points of drilling of the section of the offset well, an energy needed by the base drill bit or the new drill bit used for performing the offset well simulation based on the condition of the base drill bit or the new drill bit used for performing the offset well simulation.

Embodiment #27: The apparatus of any one or more of Embodiments #21-26, wherein the drilling conditions comprise a rock abrasiveness factor of a subsurface formation through which the offset well is drilled.

Embodiment #28: The apparatus of any one or more of Embodiments #21-27, wherein the instructions that are executable by the processor to cause the processor to perform the offset well simulation comprises instructions that are executable by the processor to cause the processor to, determine cutter axial force and drag force models of the base drill bit during the drilling of the offset well; and calibrate a rock strength of a subsurface formation through which the offset well is drilled based on the cutter axial force and drag force models.

Embodiment #29: The apparatus of any one or more of Embodiments #21-28, wherein the instructions that are executable by the processor to cause the processor to perform the offset well simulation comprises instructions that are executable by the processor to cause the processor to, determine a rock strength of a subsurface formation through which the offset well; and calibrate cutter axial force and drag force models of the base drill bit during the drilling of the offset well based on the rock strength.

Embodiment #30: The apparatus of any one or more of Embodiments #21-29, wherein the base drill bit performance and the new drill bit performance are based on a dullness of one or more cutters of the base drill bit and the new drill bit, respectively.