Drill Bit Selection for Drilling a Target Well Based on Drilling Simulation of an Offset Well

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.

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.

an elevation view (partially cross sectional) of an example well system, according to some implementations. In particular,is a schematic diagram of a well systemthat includes a drill stringhaving a drill bitdisposed in a wellborefor drilling the wellborein the subsurface formation. 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 bitis an example drill bit for which simulation of abrasive wear and damage as described herein can be performed.

The well systemmay further include a drilling platformthat supports a derrickhaving a traveling blockfor raising and lowering the drill string. The drill stringmay include, but is not limited to, drill pipe, drill collars, and down hole tools. The down hole toolsmay 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 kellymay support the drill stringas it may be lowered through a rotary table. The drill bitmay include roller cone bits, polycrystalline diamond compact (PDC) bits, natural diamond bits, any hole openers, reamers, coring bits, and the like. As the drill bitrotates, it may crush or cut rock to create and extend a wellborethat penetrates various subterranean formations. The drill bitmay be rotated by various methods including rotation by a downhole mud motor and/or via rotation of the drill stringfrom the surfaceby the rotary table. Attributes of drilling the wellbore may be adjusted to increase, decrease, and/or maintain the rate of penetration (ROP) of the drill bitthrough the subsurface formation. Attributes may include weight-on-bit (WOB) and rotations-per-minute (RPM) of the drill string. In some embodiments, the drill bitmay become dull and lose efficiency, thus requiring more WOB and/or RPM to maintain a target ROP. A pumpmay circulate drilling fluid through a feed pipeto the kelly, downhole through interior of the drill string, through orifices in the drill bit, back to the surfacevia an annulus surrounding the drill string, and into a retention pit.

The well systemincludes a computerthat may be communicatively coupled to other parts of the well system. The computercan be local or remote to the drilling platform. A processor of the computermay perform simulations (as further described below). In some embodiments, the processor of the computermay control drilling operations of the well systemor subsequent drilling operations of other wellbores.

An example of the computeris now described.is a block diagram of an example computer, according to some implementations.depicts a computerthat includes a processor(possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computerincludes a memory. The memorymay be system memory or any one or more of the above already described possible realizations of machine-readable media. The computeralso includes a busand a network interface.

The computeralso includes a simulation processorand a controller. The simulation processorand the controllercan perform one or more of the operations described herein. For example, the simulation processorcan perform data processing and simulation operations as further described below. The controllermay perform various control operations to a wellbore operation based on the simulations. For example, the controllercan 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. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in(e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processorand the network interfaceare coupled to the bus. Although illustrated as being coupled to the bus, the memorymay be coupled to the processor.

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,is a graphical representation of a cutter of a drill bit, according to some implementations. In, a cutterincludes a cutting elementand a body. In some implementations, the cutting elementmay be composed of diamond. The bodymay 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 cuttersubstantially equaling the chamfer size. A critical wear depth (Wc) may be defined as the depth wherein the cutting elementis worn away to a point where the bodyis starting to be in contact with the formation being drilled.

To further illustrate,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.depicts a graphthat includes an x-axis that is the energy (E)of the drill bit and a y-axis that is the cutter wear volume (V)of the drill bit. The graphincludes a linethat starts at an Ec(when V is zero). A first partof the lineis based on μ (a constant), Ka (the rock abrasive factor), and Kb (the cutter wear resistance factor. A second partof the lineis 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 graphof). 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):

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

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):

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

wherein T is time.

Additionally, a cutter wear severity may be defined by a cutter wear depth. To illustrate,is a graphical representation of a cutter of a drill bit, according to some implementations.depicts a cutterhaving 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):

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 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 are now described.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 flowchartofare described in reference to the well systemofand the computerof. Operations of the flowchartstart at block.

At block, 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, the processormay 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,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,includes a graphhaving lines for the primary cutters, the backup cutters, and the DOCCs and blades.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,includes a graph.

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

In some implementations, TOB ratio may be determined based on Equation (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, operations of the flowchartcontinues at block.

At block, cutter forces (for at least one cutter of the drill bit) are determined based on the input drill bit energy. With reference to, the processormay make this determination. In some implementations, the processormay 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 processormay then determine the axial forces coefficient (ηa) based on the Equation (9):

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

is scared cutter axial force of cutter i

The processormay also determine a torque coefficient (ηd) based on Equation (11):