DRILLING EFFICIENCY EVALUATION

BACKGROUND

In conventional oil and gas operations, a wellbore is drilled to a desired path with a thousand lengths of drill string, which include drill pipe and a bottom hole assembly (BHA). Throughout the drilling process, several operational parameters are set to affect Rate of Penetration (ROP). These parameters may include surface weight on bit (WOB), rotations per minute (RPM), flow rate, standard pipe pressure, etc. The drilling performance and true downhole drilling parameters may be monitored during the drilling operation to ensure the drilling is in the right direction under correct safety protocols. The attainment of a higher ROP is sought as it can lead to lower overall drilling costs and faster production time.

ROP optimization is one of the most challenging tasks in drilling a wellbore. Drilling mechanics involves numerous quasi-static and dynamic processes that are non-local, non-linear, coupled, with non-trivial boundary conditions (bit-rock interface, BHA-well bore contacts, etc.). In most cases, surface measurements represent the primary source of data acquisition but are commonly associated with low sampling rates, poor resolution, and noisy, unfiltered data. Additionally, any downhole measurements are subject to telemetry bandwidth and latency inherent for any downhole to surface communications.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of the disclosure may be better understood by referencing the accompanying drawings.

FIG. 1 is an elevation view of a drilling system used to form a wellbore in a subsurface formation, according to some implementations.

FIG. 2 is an example model of this drilling system used for performing a drilling efficiency evaluation, according to some implementations.

FIGS. 3-4 are flowcharts of example operations for performing a drilling efficiency evaluation, according to some implementations.

FIGS. 5-7 are example graphs of data from a tag bottom event that includes hook load, torque, and rate of penetration, respectively, according to some implementations.

FIGS. 8-10 are graphs that depict a bit response in different spaces relative to the weight on bit (w), torque on bit (t), and depth of cut, according to some implementations.

FIG. 11 is an example graph of mapping a model predication in the space of operating parameters, according to some implementations.

FIG. 13 is an example graph of a map of a model predication in the space of operating parameters, according to some implementations.

FIG. 15 is a first interpretation of a bit response that shows a change of rock strength (wherein increase in rock strength leads to a drop in ROP, according to some implementations.

FIGS. 18-19 are flowcharts of example operations for determining a performance index for qualifying a drilling efficiency, according to some implementations.

FIG. 20 is an example graph of a signature of a drilling operation in Regimes I-III in the torque on bit and weight on bit space, according to some implementations.

FIG. 21 is a block diagram of an example computer, according to some implementations.

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 may improve drilling efficiency of drilling a wellbore based on estimating downhole (at-bit) parameters (such as at bit WOB, at bit torque on bit (TOB), depth of cut, etc.) by using measurements made at the surface of the wellbore. These estimated downhole (at-bit) parameters may then be used to determine the drilling efficiency of the drilling of the wellbore using a bit-rock interaction model to estimate true at bit drilling parameters. In some implementations, drilling parameter adjustments may be recommended and/or performed in response to this downhole estimation.

Example implementations may map out a signature of the drilling system response, wherein the signature may be defined by the relationship between the input and output parameters. In some implementations, the signature may be defined by varying the input parameters. Examples of the input parameters may include a weight on bit (WOB), hook load, rotations per minute (RPM), flow rate of the drilling mud, etc. Examples of output parameters may include rate of penetration (ROP), torque on bit (TOB), (and surface torque), stand pipe pressure etc. As further described below, input and output parameters at a surface of the wellbore may be used to infer measurements of parameters at or near the drill bit (such as WOB, TOB, rate of penetration, etc.).

Example implementations may be data driven and supported by simple yet robust models. Example operations may process and analyze the data in real-time to estimate the at-bit parameters and may provide a reasonable recommendation to improve drilling efficiency. In some implementations, recommendations to improve the drilling efficiency may be provided and/or actually implemented. For example, drilling parameters of a current drilling operation may be changed based on these recommendations. The at-bit parameters may be input into the models of the drilling operation. The models may relate drilling operations parameters measured at the surface (such as surface WOB, rotations of the drill string per unit of time (e.g., rotations per minute (RPM)), drilling fluid flow rate, etc.) to performance variables (such as rate of penetration (ROP), torque on bit (TOB), standpipe pressure (SPP), etc.) as a function of wellbore geometry, attributes of the drill string, attributes of the bottom hole assembly (BHA), attributes of the drill bit, properties of the rock being drilled, properties of the drilling fluid, etc.

The raw data analysis may include filtering, calibration, and correction of several spurious effects. These operations may be needed to provide a reliable estimate of the at-bit parameters. The real time analysis may attempt to identify performance limitations, including bit wear, bit cleaning problem, vibrations, and bit or BHA design, etc. Some implementations may rely on specific drilling events (such as tagging bottom when the drill bit is lowered until its contact the bottom of the wellbore and start propagating the wellbore) to map the bit-rock drilling signature (“drilling signature”). Some implementations may also track while drilling how a drill bit response diverges from either or both the current drilling signature or last drilling signature. In some implementations, if there is a divergence, a new mapping test may be performed (take off bottom and tag again or drill off). The analysis may also track how key model parameters evolve over time from stand to stand (such as drilling efficiency, relative state of wear, etc.).

In some implementations, objectives of post job analysis may include (1) comparison of performances objectively after a thorough quality control of the data and (2) relating drilling performance to other measurements related to rock properties (wireline data, core data) or related to bit wear (dull grade), downhole vibrations (downhole recorded accelerations), (3) documenting know-how with objective facts but also tune real time algorithms settings.

Example implementations may quantitatively determine the drilling efficiency through statistical analysis of bit-rock drilling response through surface drilling operation data. The performance of a drilling operation (typically characterized by its drilling speed) may be influenced by one or more factors. These factors may include both surface drilling parameters (such as WOB, RPM, flow rate, etc.) and downhole at bit situations (such as true at bit WOB transmitted to the bit, bit state of wear, bit cleaning efficiency, vibrations, etc.).

Thus, example implementations may be in contrast to conventional approaches to determining drilling efficiency that are based on Mechanical Specific Energy (MSE) and/or Drilling Specific Energy (DSE). These conventional approaches determine the amount of work performed for a given drilling operation. This amount of work is divided by the volume of rock removed for a given unit of time. This provides the energy needed to remove this volume of rock. However, these conventional approaches (in contrast to example implementations) are unable to identify the underlying problem that may be causing the change in drilling efficiency. For example, these conventional approaches (in contrast to example implementations) are not able to identify if the change in drilling efficiency is due to insufficient cleaning downhole, changes in the type of rock being drilled, the drill bit is wearing out, etc. These conventional approaches may only identify that more energy is needed to remove a given volume of rock for a given unit of time. Additionally, instead of using bit-rock interaction models, these conventional approaches are just looking at a final value that is often compared to an arbitrary threshold value derived from wireline logs. Therefore, these conventional approaches are unable to determine how or why the MSE or DSE arrived at their final values, without relying on extra-assumptions, observations or data.

In contrast, example implementations may use an actual bit rock interaction model to derive various components and may use data driven techniques to ascertain the current level of drilling performance. Example implementations may estimate actual at-bit parameters but also may periodically check against the fitted model for any variation from the current actual bit rock interaction model.

Thus, some implementations may use the interaction between the drill bit and the rock of the surrounding formation into which the wellbore is being drilled (the bit-rock interaction) to determine drilling efficiency. The bit-rock interaction may be defined on different drilling characteristics (such as a depth of cut, a weight-on-bit (WOB), a torque-on-bit (TOB), etc.).

Some implementations may include a ROP optimization to improve downhole drilling performance in both real-time and post-analysis settings. Some implementations may be used to assess the drilling efficiency and provide a comprehensive performance index in terms of performance targets, limits, dysfunctions, and recommendations for improving overall performance.

Some implementations may quantify the drilling efficiency using a performance index (PI). Some implementations may derive the drilling performance index (PI) based on a drill bit-rock interface response (bit response). Building upon the assessment of drilling efficiency through the analysis of the bit response, example implementations may also provide a quantitative index. The utilization of a quantitative index may enhance the robustness and reliability of the evaluation process, as such utilization may allow for a systematic and data-driven analysis of the drilling performance. Example implementations may represent a significant advancement in the field, offering a real-time and a more comprehensive and accurate understanding of the efficiency of drilling operations based on the parameters derived from the bit response.

Example System

FIG. 1 is an elevation view of a drilling system used to form a wellbore in a subsurface formation, according to some implementations. A drilling platform 102 supports a derrick 104 having a traveling block 106 for raising and lowering a drill string 108. A kelly 110 supports the drill string 108 as it is lowered through a rotary table 112. A drill bit 114 is driven by a downhole motor and/or rotation of the drill string 108. As the drill bit 114 rotates, it creates a wellbore 116 that passes through various formations 118. A pump 120 circulates drilling fluid through a feed pipe 122 to the kelly 110, downhole through the interior of the drill string 108, through orifices in the drill bit 114, back to the surface via the annulus around the drill string 108, and into a retention pit 124. The drilling fluid transports cuttings from the borehole into the retention pit 124 and aids in maintaining the borehole integrity.

A computer 132 at the surface of the wellbore 116 may detect various drilling operational parameters at the surface of the drilling operation. Examples of such drilling operational parameters detected at the surface may include WOB, rotations of the drill string per unit of time (such as rotations per minute (RPM), a flow rate of the drilling fluid flow into and/or out of the wellbore, etc.). An example of the computer 132 is depicted in FIG. 18, which is further described below.

A logging tool 126 can be integrated into a bottom hole assembly (BHA) 128 near the drill bit 114. As the drill bit 114 extends the wellbore 116 through the formations 118, the BHA 128 may collect measurements relating to various formation properties and information regarding tool orientation and various other drilling conditions.

Example Operations
Drilling Efficiency Evaluation

Example implementations may use different drilling operational parameters at the surface of a wellbore being drilled to determine parameters downhole at the drill bit used for drilling the wellbore (at-bit parameters). Evaluation of a drilling efficiency of the drilling of the wellbore may be based on these at-bit parameters. Example drilling operational parameters may include various operational parameters at the surface of the wellbore being drilled. For example, the drilling operational parameters may include hook load (H), rate of penetration at the surface of the wellbore (ROP) (Vs), a rotations per unit of time (e.g., RPM), a surface Rate of Penetration (ROP) at the surface (Vs), etc. Example at bit parameters may include different parameters at the drill bit (such as Weight on Bit (WOB) at the drill bit, ROP at the bit (Vb), Torque on Bit (TOB), a depth of cut, etc.

To illustrate, FIG. 2 is an example model of this drilling system used for performing a drilling efficiency evaluation, according to some implementations. A model 200 of FIG. 2 includes a drill string 205 (that may include a collection of steel rods and a drill bit). As shown, the drill string 205 may be modeled as an equivalent linear elastic structure with axial compliance K 207. A soft string model or finite element model (torque and drag model) may be used to estimate the stiffness.

Also as shown, surface measurements may be estimated—including a hook load (H) 202, a surface torque, a rotations per unit of time (e.g., RPM), and a surface Rate of Penetration (ROP) at the surface (Vs) 204. Additionally, the at bit parameters may be determined—including Weight on Bit (WOB) (or W) 208, ROP at the bit (Vb) 206, Torque on Bit (TOB), and a depth of cut.

The bit-rock interface (the interface between the drill bit and the rock being drilled) may be modeled by a relationship between axial force (weight-on-bit) and depth of cut (equal to ROP divided by RPM) (as defined by Equation 1):

$\begin{matrix} \frac{2 π}{K} \frac{\partial W}{\partial d} \frac{\partial d}{\partial τ} = Ω (d_{s} - d_{b}) & (1) \end{matrix}$

- wherein K is the stiffness of the drill string, W is the WOB, d is the depth of cut, d_sis the “depth of cut at the surface” defined as

$(d_{s} = \frac{2 π V_{s}}{Ω})$

and d_bis depth of cut at the bit

$d_{b} = 2 π \frac{V_{b}}{Ω},$

τ is the time, and Ω is the RPM at the bit.

The depth of cut d_sat surface and d_bat the bit and defined by Equation (2):

$\begin{matrix} d_{s (b)} = 2 π \frac{V_{s (b)}}{Ω} & (2) \end{matrix}$

A change

$(\frac{\partial W}{\partial d})$

In the WOB (W) in relation to the change in depth of cut d (depth of cut at the bit, we drop the subscript for the sake of simplicity) may be defined by either Equations (3) and (4)—depending on whether the depth of cut (d) is less than or greater than d custom-character (which is the depth of cut where the drilling operations move from Regime I to Regime II (which is further described below)):

$\begin{matrix} \frac{\partial W}{\partial d} = S_{*} if d < d_{*} & (3) \end{matrix}$

$\begin{matrix} \frac{\partial W}{\partial d} = ζε if d \geq d_{*} & (4) \end{matrix}$

where ε is a measure of the rock apparent strength (function of the rock strength, mud and pore pressure as well as bit design). The number ζ (characterizes ratio between weight and torque for an ideally sharp bit (no chamfer nor wear flat at the tip of the cutting elements). The parameter S custom-character characterizes the relation between weight-on-bit and depth of cut in regime I, and is controlled by not only the apparent rock strength but also the bit state of wear (wear flat or chamfer), S>ζε.

Equation (1) may be solved (combined with torque vs depth of cut and torque vs weight-on-bit relations) to derive an estimate of the bit rock interaction model parameters. In particular, the following may be solved: 1) w custom-character that relates to the bit state of wear and 2) w or onset of poor bit cleaning (founder point) And 3) the apparent rock strength, ε

Example operations for performing a drilling efficiency evaluation are now described. FIGS. 3-4 are flowcharts of example operations for performing a drilling efficiency evaluation, according to some implementations. Operations of flowcharts 300-400 of FIGS. 3-4 can be performed by software, firmware, hardware, or a combination thereof. Operations of the flowcharts 300-400 continue between each other through transition points A-B. Operations of the flowcharts 300-400 are described in reference to FIG. 1. However, other systems and components can be used to perform the operations now described. The operations of the flowchart 300 start at block 302.

At block 302, drilling of the wellbore is calibrated while tripping the drill string in hole. For example, with reference to FIG. 1, the computer 132 may perform this calibration while the drill string 108 is being positioned downhole in the wellbore 116. In some implementations, attributes of the drilling that are being calibrated may include a set of coefficients that are applied to raw measurements to correct for any spurious processes that may affect the measured variables, including sheave effect, hydraulic lift, effect of RPM on off bottom torque, top drive weight, etc. The sheave effect may be defined as the frictional loss in the sheave that leads to hysteresis effect on the hook load estimate. The hydraulic lift may be defined as the effect of drilling fluid or mud flow on the hook load due to buoyancy. The RPM effect may be defined as an effect of rotations per unit of time (e.g., RPMs) on off bottom torque. The top drive weight is essential for torque and drag simulation.

At block 304, tagging bottom evaluation is performed. For example, with reference to FIG. 1, tagging the bottom may be defined as lowering the drill bit 114 along with the drill string 108 into the wellbore 116 with the drilling fluid flowing in the wellbore 116 and the drill string 108 rotating at a given steady RPM onto a bottom of the wellbore 116 to resume drilling.

Data of different drilling attributes may be measured during the tag bottom event. To illustrate, FIGS. 5-7 are example graphs of data from a tag bottom event that includes hook load, torque, and rate of penetration, respectively, according to some implementations. FIG. 5 is a graph 500 that includes a hook load 502 of the drill string (along a y-axis) over time 504 (along an x-axis) during the tag bottom event. The hook load 502 may be defined as the force acting on the drill string equal to the submerged weight of the drilling assembly minus the weight-on-bit and any frictional losses to contact between the drill string and the borehole wall. In the graph 500, initially, the hook load 502 is a constant in a range 510. A point 512 represents a time when the drill bit gets in contact with the bottom of the wellbore being drilled. From the point 512 and over time, the hook load 502 reduces until an equilibrium is reached (see a range 514) where the hook load 502 may remain substantially constant.

FIG. 6 is a graph 600 that includes a measured torque 602 of the drill string (along a y-axis) over time 604 (along an x-axis) during the tag bottom event. The torque 602 may be defined as the rotational force applied to the drill string during drilling of the wellbore. In the graph 600, initially, the torque 602 is a constant in a range 610. A point 612 represents a time when the drill bit encounters the bottom of the wellbore being drilled. From the point 612 and over time, the torque 602 increases until an equilibrium is reached (see a range 614) where the torque 602 may remain substantially constant.

FIG. 7 is a graph 700 that includes a measured rate of penetration (ROP) 702 of the drilling (along a y-axis) over time 704 (along an x-axis) during the tag bottom event. In the graph 700, initially, the ROP 702 is a constant in a range 710. A point 712 represents a time when the drill bit encounters the bottom of the wellbore being drilled. From the point 712 and over time, the ROP 702 increases until an equilibrium is reached (see a range 714) where the ROP 702 may remain substantially constant.

In some implementations, in order to harmonize drill bits of different diameters and geometry (such as size, shape, quantity of cutting blades, etc.), a further scaling may be implemented—whereby the measured value of WOB and TOB at surface custom-character is converted to scaled WOB(w, w, w (which are further described below)) and scaled TOB(t, t, t (which are further described below)). To accomplish this the actually bit geometry may be transformed to an equivalent bit with an equivalent single cutter of unit length. The measured parameters of WOB and TOB are now transformed to scaled WOB (which is the equivalent vertical force per unit length) and scaled TOB (which is the horizontal force per unit length). The computer 132 may calculate this scaling based on actual geometry of actual tools used. In this way results between different drilling operations may be compared and assessed in harmonized way.

At block 306, the torque-weight-depth of cut (t-w-d) signature is mapped based on tagging bottom evaluation to create the t-w-d signature for the drilling operation. For example, with reference to FIG. 1, the computer 132 may perform this mapping. As the drill bit 114 hits the bottom of the wellbore 116, the WOB, TOB, and depth of cut may gradually increase from which the bit-rock drilling response may be mapped (referred to as the t-w-d signature).

In particular, in some implementations, a drilling operation may be postulated into two independent processes—frictional contact and cutting. Therefore, the torque on the drill string (t) and WOB (w) may be decomposed as follows in Equations (5) and (6), respectively:

$\begin{matrix} t = t_{f} + t_{c} & (5) \end{matrix}$

$\begin{matrix} w = w_{f} + w_{c} & (6) \end{matrix}$

- wherein t_fis the torque caused by friction, t_cis the torque caused by cutting, w_fis the weight from friction and w_cis the weight from cutting. The t_fmay be related to the w_fbased on Equation (7):

$\begin{matrix} t_{f} = μγ w_{f} & (7) \end{matrix}$

- wherein μ is the coefficient of friction at the wear flat-rock interface and γ is a drill bit constant related to the bit profile.

The cutting components may be related to the depth of cut (d) based on Equations (8) and (9) as follows:

$\begin{matrix} t_{c} = ε d & (8) \end{matrix}$

$\begin{matrix} w_{c} = ζε d & (9) \end{matrix}$

- wherein ε is the intrinsic specific energy (or “apparent rock strength”) and ζ may be the value in the range of [0.5, 0.8].

With the known ζ and μγ, the bit response may be defined by Equations (10)-(13) as follows:

$\begin{matrix} t_{c} = \frac{t - μγω}{1 - β} & (10) \end{matrix}$

$\begin{matrix} w_{c} = ζ t_{c} & (11) \end{matrix}$

$\begin{matrix} w_{f} = \frac{w - ζ t}{1 - β} & (12) \end{matrix}$

$\begin{matrix} t_{f} = μγ w_{f} & (13) \end{matrix}$

wherein β=μγζ

In some implementations, the bit response model may assume that there exist three distinct operating regimes (Regime I, Regime II, and Regime III) that may be directly associated with the contact force with the depth of cut.

To illustrate, FIGS. 8-10 are graphs that depict a bit response in different spaces relative to the weight on bit (w), torque on bit (t), and depth of cut, according to some implementations. FIG. 8 is a graph that depicts a bit response in the depth of cut (d) and the weight on bit (w) space, according to some implementations. In FIG. 8, a graph 800 includes a y-axis 802 that is the depth of cut and an x-axis 804 that is the weight on bit. The graph 800 includes a Regime I 806, a Regime II 808, and a Regime III 810.

In Regime I 806, the initial drilling may be characterized by a progressive increase of force with depth of cut. In Regime I 806, the contact force (w_f) increases with depth of cut until conformal contact between the wear flat or chamfers and the rock occurs (onset of regime II). In Regime II 808, the contact forces may be fully mobilized and may not be increased any more since the contact force has reached a maximum value. Also, in Regime II 808, the response is incrementally similar to the response of an ideally sharp tool. The offset (or intercept along the w axis) or onset of regime II are controlled by the bit state of wear. In some implementations, it is necessary to keep the drilling operation in Regime II 808 to realize the optimized result. As shown, in the Regime II 808, a small increase in the weight on bit 804 results in a large increase in the depth of cut 802.

In Regime III 810, there may be a lack of uniqueness in the bit response. In Regime III 810, there is a path A and a path B. With the path A, the drilling operation may be under kinematic control—with the contact force increasing rapidly while depth of cut increasing slowly. With the path B, the drilling operation may be under force control—with the depth of cut decreasing as the contact force is increasing. In some implementations, path B may be a result of lack of cleaning of cuttings at or near the drill bit. The combinations of μ, γ, and ε represent the slope of different Regimes in the t-w-d space, which may be further employed to determine the specific regime the current drilling operations are within (as shown in FIGS. 8-9).

Also shown in the graph 800 of FIG. 8, d custom-character is the depth of cut where the drilling operations move from the Regime I 806 to the Regime II 808. Additionally, w may be defined as the amount of WOB needed to mobilize the drill bit to overcome the frictional component. The w may be defined as the amount of WOB corresponding to d custom-character , which is the depth of cut where the drilling operations move from the Regime II 808 to the Regime III 810 (where there may not be sufficient cleaning of the cuttings at or near the drill bit).

The Regime I 806 may be defined as the frictional contact regime, which ends at w custom-character . The WOB (w_f) is the amount of weight applied to the drill bit that is carried by the wear flat. The slope (S is the slope in the Regime I 806. In the Regime II 808, the slope of the line ζε (E. This slope of the line may also represent a measure of the rock strength (rock's resistance to drilling).

FIG. 9 is a graph that depicts a bit response in the depth of cut (d) and the torque on bit (t) space, according to some implementations. In FIG. 9, a graph 900 includes a y-axis 902 that is the depth of cut and an x-axis 904 that is the torque on bit. The graph 900 includes the Regime I 806, the Regime II 808, and the Regime III 810 (as described above in reference to FIG. 8). The graph 900 also includes the path A and the path B in the Regime III 810 (as described above in reference to FIG. 8).

FIG. 10 is a graph that depicts a bit response in the torque on bit and the weight on bit space, according to some implementations. In FIG. 10, a graph 1000 includes a y-axis 1002 that is the torque on bit 1002 (along a y-axis) and a weight on bit (WOB) 1004 (along an axis).

Based on the determined drilling efficiency derived from the calculated bit-response model, a corresponding decision may be made to improve the drilling performance. If it is detected that the drilling is in the Regime I 806, WOB may be increased to move the drilling into the Regime II 808 to provide a better ROP. If it is detected that the drilling is within the Regime II 808, then the current parameter settings may be maintained or adjusted to move closer to the founder point. If it is detected that the drilling is within the Regime III 810, then at least one of the WOB or the RPM may be decreased to move the drilling operation back to the Regime II 808. Alternatively or in addition, the flow rate of the drilling fluid in the wellbore may be increased to move the drilling operation back to the Regime II 808.

Returning to the operations of the flowchart 300, after mapping the t-w-d signature at block 306, operations continue at block 308.

At block 308, key model parameters (such as rock strength (ζε), relative state of wear, founder point, etc.) are estimated and the bit response model is built. For example, with reference to FIG. 1, the computer 132 may perform this operation. For instance, the computer 132 may extract these key model parameters from the t-w-d signature. For instance, the computer 132 may extract the rock strength (ζε) from the slope of the line through the Regime II 808 of the graph 800 of FIG. 8. The computer 132 may extract the relative state of wear (W custom-character ) from the point along the x-axis 804 of the graph 800 of FIG. 8 where the drilling operation changes from the Regime I 806 to the Regime II 808. The computer 132 may extract the founder point which may be the point between the Regime 808 II and the Regime III 810. The founder point may be defined as w custom-character −d. In some implementations, the w (WOB), the t (TOB), and the expected d (DOC) (the most optimal parameters for drilling) may be determined from the founder point.

At block 310, the drilling response is constructed in the space of operating parameters (WOB, RPM) with isoline of ROP based on the bit response model. For example, with reference to FIG. 1, the computer 132 may perform this operation.

To illustrate, FIG. 11 is an example graph of mapping a model predication in the space of operating parameters, according to some implementations. In FIG. 11, a graph 1100 is a WOB-RPM map. The graph 1100 includes an x-axis (WOB) 1102 and a y-axis (RPM) 1104. As shown, several system and operational limits (top drive power limit, drill string buckling limit, downhole equipment load limit (weight-torque), and vibrations dominated regions) have been added to the WOB-RPM map.

The graph 1100 also includes a number of ROP lines 1106-1118. The graph 1100 also includes a line 1126 which is the top drive limit. The graph 1100 includes a line 1128 which is the drill string buckling limit. The graph 1100 also includes the Regime III 1130, the Regime II 1132, and Regime I 1134. As shown in the graph 1100, above a certain WOB, the drilling operation falls into the Regime III 1130 where the bit response is different (less efficient) than in the Regime II 1132. The graph 1100 also includes a region 1155 where there may be lateral vibration of the drill string. As shown, the region 1155 generally occurs where the RPMs are high and the WOB is low. The graph 1100 includes a region 1157 where there may be torsional vibration of the drill string. As shown, the region 1157 generally occurs where the RPMs are relatively lower and WOB higher.

At block 312, the wellbore is drilled for a defined depth. For example, with reference to FIG. 1, the wellbore 116 may be drilled to a depth of the new rods of drill pipe added to the drill string at the surface of the wellbore (known as “drilling the stand”). The drill bit 114 may be moved off bottom so that the depth of cut, WOB and TOB are zero. The new rods may be added, and the drill string lowered and rotated to engage a bottom of the wellbore 116 to continue drilling the wellbore 116. The drilling of the wellbore 116 may continue until the new rods are within the wellbore 116.

At block 314, a determination is made of whether the response to drilling the wellbore diverges from the previous t-w-d signature (but not beyond a divergence threshold). For example, with reference to FIG. 1, the computer 132 may perform this determination. For instance, the current response may deviate from the previous t-w-d signature but still be less than a significant divergence (less than a defined divergence threshold) such that the current t-w-d signature may be modified and still be used to determine a drilling efficiency of the current drilling operation without having to create a new t-w-d signature. If the response to drilling the wellbore diverges from the previous t-w-d signature (but not beyond a divergence threshold), operations of the flowchart 300 continue at block 316. Otherwise, operations of the flowchart 300 continue at block 318.

At block 316, the current bit response model is adjusted based on estimated new key model parameters. For example, with reference to FIG. 1, the computer 132 may perform this adjustment. Operations of the flowchart 300 continue at transition point A, which continues at transition point A of the flowchart 400 (which is described in more detail below).

At block 318, a determination is made of whether the response to drilling the wellbore diverges beyond a divergence threshold. For example, with reference to FIG. 1, the computer 132 may perform this determination. For instance, the current response may deviate from the previous t-w-d signature beyond a defined divergence threshold such that the current t-w-d signature may not be usable to determine a drilling efficiency of the current drilling operation without having to create a new t-w-d signature. If the response to drilling the wellbore diverges from the previous t-w-d signature beyond a divergence threshold, operations of the flowchart 300 continue at block 320. Otherwise, operations of the flowchart 300 continue at transition point A, which continues at transition point A of the flowchart 400 (which is described in more detail below).

At block 320, a drill off test (hook position on surface is locked and the system let to drill) or a new tag bottom event is performed to derive the new bit-rock response model from drill bit. For example, with reference to FIG. 1, the drill string 108 may be pulled upward out of the wellbore 116 such that the drill bit 114 is not touching the bottom of the wellbore 116, and lowered back until the bit resumes drilling. Operations of the flowchart 300 return to block 304 to again perform tagging bottom evaluation.

Operations continue at the flowchart 400 of FIG. 4. From the transition point A, operations of the flowchart 400 continue at block 402.

At block 402, the drilling efficiency of the drilling of the wellbore for the defined depth is determined. For example, with reference to FIG. 1, the computer 132 may perform this determination. For example, the computer 132 may track performance between drilling from stand to stand. The computer 132 may analyze the model parameters and drilling efficiency with the intention to pick up occurrence of abrupt event excessive wear or vibrations or a steady vibration.

At block 404, a determination is made of whether the drilling operation should be updated based on the drilling efficiency. For example, with reference to FIG. 1, the computer 132 may make this determination. For instance, based on the determined drilling efficiency derived from the calculated bit-response model, the computer 132 may determine that at least one parameter of the drilling operation may be updated to improve the drilling performance. For example, returning to FIGS. 8-9, if it is detected that the drilling is in the Regime I 806, at least one of the WOB or the RPMs may be increased to move the drilling into the Regime II 808 to provide a better ROP. If it is detected that the drilling is within the Regime II 808, then the current parameter settings may be maintained or adjusted to move closer to the founder point. If it is detected that the drilling is within the Regime III 810, then at least one of the WOB or the RPM may be decreased to move the drilling operation back to the Regime II 808. Alternatively or in addition, the flow rate of the drilling fluid in the wellbore may be increased to move the drilling operation back to the Regime II 808. If it is determined that the drilling operation should be updated, operations of the flowchart 300 continue at block 306. Otherwise, operations of the flowchart 300 at block 308 (which is further described below).

At block 406, the drilling operation is updated. For example, with reference to FIG. 1, the computer 132 may perform this update. For instance, at least one of the WOB, RPM, or the flow rate of the drilling fluid may be adjusted (as described above in reference to block 304.

At block 408, a determination is made of whether drilling of the wellbore is complete. For example, with reference to FIG. 1, the computer 132 may make this determination. For instance, the drilling of the wellbore may be completed after a given depth is reached, a number of drill pipes have been added to the drill string as part of the drilling operation, etc.

If the drilling of the wellbore is not complete, operations of the flowchart 400 continue at transition B, which continues at transition B of the flowchart 300, which continues at block 312, where the wellbore is again drilled for a defined depth. If the drilling of the wellbore is complete, operations of the flowchart 400 are complete.

Thus, once the calibration has been completed, the tag bottom event may be expected to occur right after a connection. From the data recorded during this event, the bit-rock interface model parameters may be derived—which allows for identification of the extent of the drilling regimes (I inefficient, II efficient, III founder) and relate weight-on-bit, torque-on-bit and rate of penetration (or depth of cut). From the model parameters, isoline of constant rate of penetration in the space of operating parameters (WOB-RPM) may be constructed, in which system and context limiters such as top drive limit, buckling limit, vibrations zones are added (as shown in FIG. 11).

Also, once drilling starts, the drilling response may be monitored while the stand is drilled (drilling for a defined depth) against the response derived during the tag bottom event. If the response drifts too far from the response, one or more drilling parameters (e.g., WOB, RPM, flow rate of drilling fluid, etc.) may be adjusted to assess the drift: change of formation, founder point, etc. Then from stand to stand, the performances may be tracked by interpreting variations in the system response to infer slow variation in system response (wear, hole cleaning, bit cleaning, etc.).

Example implementations may rely on specific drilling events—tagging bottom, drill off, etc.—to map the bit-rock drilling signature, and track while drilling how the response diverges from the current/last signature, requesting then the driller to run a new “mapping test” (drill off). The analysis may also track how key model parameters evolve over time (from stand to stand) such as drilling efficiency, relative state of wear, etc.

FIG. 12 is an example data flow diagram, wherein data from a tag bottom event is processed to derive bit-rock model parameters to build a bit response model (in the t-w-d space), according to some implementations. A data flow diagram 1200 of FIG. 12 includes a tag bottom event 1202, deriving of bit-rock model parameters 1204, and a mapping of model predication in space of operating parameters 1206. An output of the tag bottom event 1202 may be an input into the deriving of bit-rock model parameters 1204. An output of the deriving of bit-rock model parameters 1204 may be an input into the mapping of model predication in space of operating parameters 1206.

In some implementations, the output from the tag bottom event 1202 may include values of drilling parameters (such as hook load, torque, and ROP) over time during a tag bottom event 1202 when the drill bit interacts with a bottom of the wellbore. In this example, the output of the tag bottom event 1202 includes a graph 1208 of the hook load over time, a graph 1210 of the torque of the drill string over time, and a graph 1212. Another example of the graph 1208 is depicted in FIG. 4 (described above). Another example of the graph 1210 is depicted in FIG. 5 (described above). Another example of the graph 1212 is depicted in FIG. 6 (described above). Equation (1) (see above) may be solved on data pertaining to a tag bottom event. The advantage of tag bottom event is that weight-on-bit and thus depth of cut vary from zero to a target value thus mapping out the drilling response.

The deriving of the bit-rock model parameters 1204 may include graphs 1214-1218. The graph 1214 may map the torque on bit (along a y-axis) to weight on bit (WOB) (along an x-axis) across Regions I, II, and III. An example of the graph 1214 is depicted in FIG. 10 (described above). The graph 1216 may map the depth of cut (along a y-axis) to a WOB (along the x-axis) across Regions I, II, and III. An example of the graph 1216 is depicted in FIG. 8 (described above). The graph 1218 may map the depth of cut (along a y-axis) to a torque on bit (along the x-axis) across Regions I, II, and III. An example of the graph 1218 is depicted in FIG. 9 (described above). Equation (1) (see above) may be solved (combined with torque on bit versus depth of cut and torque on bit versus WOB relations) to derive the bit rock interaction model parameters (including w custom-character that relates to the bit state of wear, w or onset of poor bit cleaning (founder point), a measure of apparent rock strength, etc.). In some implementations, a Markov Chain based method may be used to derive a probability distribution of the model parameters (mean and standard deviation).

With model parameters, a map 1220 of the drilling response (ROP) in the space of controlling parameters (WOB, RPM) may be generated. The map 1220 may include isolines of ROP and allow for prediction in terms of performance. An example of the map 1220 is depicted in FIG. 13. In particular, FIG. 13 is an example graph of a map of a model predication in the space of operating parameters, according to some implementations. A graph 1300 of FIG. 13 includes a WOB-RPM map. The graph 1300 includes an x-axis (RPM) 1302 and a y-axis (WOB) 1304. The graph 1300 also includes a number of ROP lines.

FIG. 14 is another example data flow diagram, wherein data from a tag bottom event is processed to derive bit-rock model parameters to build a bit response model (in the t-w-d space), according to some implementations. A data flow diagram 1400 of FIG. 14 includes a tag bottom event 1402, deriving of bit-rock model parameters 1404, and interpretations 1406. An output of the tag bottom event 1402 may be an input into the deriving of bit-rock model parameters 1404. An output of the deriving of bit-rock model parameters 1404 may be an input into the interpretations 1406.

In some implementations, the output from the tag bottom event 1402 may include values of drilling parameters (such as hook load, torque, and ROP) over time during a tag bottom event 1402 when the drill bit interacts with a bottom of the wellbore. In this example, the output of the tag bottom event 1402 includes a graph 1408 of the hook load over time, a graph 1410 of the torque of the drill string over time, and a graph 1412. Another example of the graph 1408 is depicted in FIG. 4 (described above). Another example of the graph 1410 is depicted in FIG. 5 (described above). Another example of the graph 1412 is depicted in FIG. 6 (described above). Equation (1) (see above) may be solved on data pertaining to a tag bottom event.

After tagging bottom, drilling may be resumed. As shown in graphs 1408-1412, the drilling response moves from the tag bottom target value to a new operational point. For example, in the graph 1408, the hook load response moves from the tag bottom event 1452 to a new operational point 1453. In the graph 1410, the torque response moves from the tag bottom event 1454 to a new operational point 1455. In the graph 1412, the ROP response moves from the tag bottom event 1456 to a new operational point 1457. In some implementations, operations may compare the current response (at the new operational point) with the model prediction. If the two differ, operations may try to adjust the model parameters by still solving Equation (1).

As the range of parameters varies over a much lower range when drilling (as compared to when tagging bottom), the new estimate may be less reliable (as compared to tag bottom). In some implementations, when deviation between prediction and model is larger than a threshold, a tag bottom event may be re-executed to re-derive the model parameters. This approach may also be combined with automation and control, whereby the control parameters may be varied as required to derive robust estimate of the model parameters. An algorithm may be used to identify the range of variations.

The deriving of the bit-rock model parameters 1204 may include graphs 1414-1418. The graphs 1414-1418 depict the drilling response moving away from the reference signature derived during the tag bottom event. The graph 1414 may map the torque on bit (along a y-axis) to weight on bit (WOB) (along an x-axis) across Regions I, II, and III. As shown, the graph 1414 includes a point 1458 associated with the tag bottom event and a point 1459 associated with the new operational point. The graph 1416 may map the depth of cut (along a y-axis) to a WOB (along the x-axis) across Regions I, II, and III. The graph 1416 includes a point 1460 associated with the tag bottom event and a point 1460 associated with the new operational point. The graph 1418 may map the depth of cut (along a y-axis) to a torque on bit (along the x-axis) across Regions I, II, and III. The graph 1418 includes a point 1462 associated with the tag bottom event and a point 1463 associated with the new operational point.

With model parameters, multiple interpretations may be generated. For example, a first interpretation 1470 and a second interpretation 1472 may be generated. An example of the first interpretation 1470 is depicted in FIG. 15. An example of the second interpretation 1472 is depicted in FIG. 16.

The first interpretation 1470 and the second interpretation 1472 may include different graphs of a bit response—including 1) a graph that depicts a bit response in the torque on bit and the weight on bit, 2) a graph that depicts a bit response that includes a depth of cut and the weight on bit, and 3) a graph that depicts a bit response that includes a depth of cut and the torque on bit.

FIG. 15 is a first interpretation of a bit response that shows a change of rock strength (wherein increase in rock strength leads to a drop in ROP, according to some implementations. In FIG. 15, a first interpretation 1500 includes a graph 1502 that depicts a bit response in the torque on bit and the weight on bit, a graph 1504 that depicts a bit response that includes a depth of cut and the weight on bit, and a graph 1506 that depicts a bit response that includes a depth of cut and the torque on bit.

As shown, the graph 1502 includes a line 1512 associated with the tag bottom event and a line 1514 associated with the new operational point. The graph 1504 includes a line 1516 associated with the tag bottom event and a line 1518 associated with the new operational point. The graph 1506 includes a line 1520 associated with the tag bottom event and a line 1522 associated with the new operational point.

FIG. 16 is a second interpretation of a bit response where the bottom shows occurrence of Regime 3 (accumulation of debris around the bit cutting structure that leads to a drop in ROP, according to some implementations. In FIG. 16, a second interpretation 1600 includes a graph 1602 that depicts a bit response in the torque on bit and the weight on bit, a graph 1604 that depicts a bit response that includes a depth of cut and the weight on bit, and a graph 1606 that depicts a bit response that includes a depth of cut and the torque on bit.

As shown, the graph 1602 includes a line 1612 associated with the tag bottom event and a point 1614 associated with the new operational point. The graph 1604 includes a line 1616 associated with the tag bottom event and a point 1618 associated with the new operational point. The graph 1606 includes a line 1620 associated with the tag bottom event and a point 1622 associated with the new operational point.

FIG. 17 is an example data flow diagram that includes data flow from calibration through tracking performance and interpretation of evolution of drilling response from drill stand to drill stand, according to some implementations. A data flow diagram 1700 of FIG. 17 includes a calibration of sheave, hydraulic lift, and TQ-RPM, followed by a tag bottom event to derive drilling response parameters. The data flow diagram 1700 includes a drilling of the stand event during which the performance is tracked to identify cause of drift. The data flow diagram 1700 includes tracking performance and interpretation evolution of drilling response from stand to stand. The data flow diagram 1700 may also include a post mortem quality control and analysis of the data.

Performance Index to Qualify Drilling Efficiency

FIGS. 18-19 are flowcharts of example operations for determining a performance index for qualifying a drilling efficiency, according to some implementations. Operations of flowcharts 1800-1900 of FIGS. 18-19 can be performed by software, firmware, hardware, or a combination thereof. Operations of the flowcharts 1800-1900 continue between each other through transition points A-B. Operations of the flowcharts 1800-1900 are described in reference to FIG. 1. However, other systems and components can be used to perform the operations now described. The operations of the flowchart 1800 start at block 1802.

At block 1802, a determination is made of whether the drilling operation is only in Regime I. For example with reference to FIG. 1, the computer 132 may make this determination. To help illustrate, FIG. 20 is an example graph of a signature of a drilling operation in Regimes I-III in the torque on bit and weight on bit space, according to some implementations. In FIG. 20, a graph 2000 includes a y-axis 2002 that is the torque on bit (TOB) and an x-axis 2004 that is the weight on bit (WOB). The graph 2000 includes a Regime I 2006, a Regime II 2008, and a Regime III 2010.

Returning to operations of the flowchart 1800, if the drilling operation is only in Regime I, operations continue at block 1804. Otherwise, operations of the flowchart 1800 continue at block 1806.

At block 1804, the performance index (q) for drilling efficiency is defined by Equation (14):

$\begin{matrix} η = 0 & (14) \end{matrix}$

For example, with reference to FIG. 1, the computer 132 may perform this operation. Operations of the flowchart 1800 continue at transition point B, which continues at transition point B of the flowchart 1800, which completes operations of the flowchart 1800.

At block 1806, a determination is made of whether the drilling operation is in Regime III. For example with reference to FIG. 1, the computer 132 may make this determination. If the drilling operation is in the Regime III 2010, operations of the flowchart 1800 continue at transition point A, which continues at transition point A of the flowchart 1800. Otherwise, operations of the flowchart 1800 continue at block 1808.

At block 1808, a determination is made of whether the drilling operation is in both Regime I and Regime II. For example, with reference to FIG. 1, the computer 132 may make this determination. If the drilling operation is in both the Regime I 2006 and the Regime II 2008, operations of the flowchart 1800 continue at block 1810. Otherwise, operations of the flowchart 1800 continue at transition point B, which continues at transition point B of the flowchart 1800.

At block 1810, the performance index (q) for drilling efficiency is defined by Equation (15):

$\begin{matrix} η = \frac{ζε}{S} & (15) \end{matrix}$

- where

$S = \frac{w}{d}$

2006. The efficiency can also be read as the ratio of the current depth of cut to the depth of cut if the bit was sharp (no chamfer, no wear flat). For example, with reference to FIG. 1, the computer 132 may perform this operation. Operations of the flowchart 1800 continue at transition point B, which continues at transition point B of the flowchart 1900, which completes operations of the flowchart 1900.

If the result of the analysis reveals that the drilling response is characterized by Regimes III, then consider that for a point representative of regime, part of the weight on bit beyond the onset of the Regime III 2010, (w−w custom-character ) corresponds to an increase of the apparent weight mobilized by frictional contact (w+Δw) due to the accumulation of debris around the bit body or shock arrestors touching the formation see Equation (16):

$\begin{matrix} w - w_{**} = κ (w_{*} + Δ w) & (16) \end{matrix}$

The parameter κ provides the information about the type of Regime III. In some implementations, Regime III may be one of three types. Operations of the flowchart 1800 continue at transition point A, which continues at transition point A of the flowchart 1900. Operations of the flowchart 1900 are now described. From transition point A, operations of the flowchart 1900 continue at block 1902.

At block 1902, a determination is made of whether κ<=1. For example with reference to FIG. 1, the computer 132 may make this determination. If κ<=1, operations of the flowchart 1900 continue at block 1904. Otherwise, operations of the flowchart 1900 continue at block 1906.

At block 1904, it is determined that Regime III is of type A wherein excess WOB (w−w custom-character ) beyond Regime III threshold caused by an increase of the weight mobilized by frictional contact (an extension of Regime I) caused for example by shock arrestor or secondary cutting structure. For example, with reference to FIG. 1, the computer 132 may perform this operation.

At block 1906, a determination is made of whether κ>1. For example, with reference to FIG. 1, the computer 132 may make this determination. If κ>1, operations of the flowchart 1900 continue at block 1908. Otherwise, operations of the flowchart 1900 are complete.

At block 1908, it is determined that Regime III is of type B—part of the WOB associated with Regime II is transferred to Regime I (part of Regime II transferred to Regime I) associated with excessive bit cleaning issue that leads to a drop in rate of penetration when

$κ > \frac{1}{1 - μγξ}$

For example with reference to FIG. 1, the computer 132 may perform this operation. Otherwise, operations of the flowchart 1900 are complete.

Beside the performance index for tag on bottom event, drilling on bottom performance index may also defined based on the location of the operating point in the t-w space when the model cannot be efficiently inverted while drilling the stand. During the tag on bottom event, it is observed that the depth of cut at the bit ramps up from 0 to the target value and may provide a complete map of the bit-rock interface signature. However, when drilling in the steady state condition, it may become challenging to replicate the entire bit response, making it nearly impossible to calculate the performance index by ratio between the Regime II and the Regime I. Despite this limitation, valuable insights may still be derived from the contrasting characteristics of the bit-rock interface signature (the value of μγ′ and 1/ζ exhibit distinct characteristics). As a result, it is feasible to partition the t-w space into distinct regions to evaluate the drilling efficiency effectively.

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. In general, example implementations as described herein may be implemented with facilities consistent with any hardware system or hardware systems. 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.

The flowcharts are provided to aid in understanding the illustrations and are not to be used to limit scope of the claims. The flowcharts depict example operations that can vary within the scope of the claims. Additional operations may be performed; fewer operations may be performed; the operations may be performed in parallel; and the operations may be performed in a different order. It will be understood that each block of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by program code. The program code may be provided to a processor of a general-purpose computer, special purpose computer, or other programmable machine or apparatus.

Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed. As used herein, the term “or” is inclusive unless otherwise explicitly noted. Thus, the phrase “at least one of A, B, or C” is satisfied by any element from the set {A, B, C} or any combination thereof, including multiples of any element.

As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.

Any combination of one or more machine-readable medium(s) may be utilized. The machine-readable medium may be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium may be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine-readable storage medium would include the following: a portable computer diskette, a hard disk, a random-access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine-readable storage medium may be any tangible medium that can contain or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium.

A machine-readable signal medium may include a propagated data signal with machine readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A machine-readable signal medium may be any machine-readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device.

Program code embodied on a machine-readable medium may be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing.

Computer program code for carrying out operations for aspects of the disclosure may be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language; and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code may execute entirely on a stand-alone machine, may execute in a distributed manner across multiple machines, and may execute on one machine while providing results and or accepting input on another machine.

The program code/instructions may also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks.

Example Computer

FIG. 21 is a block diagram of an example computer, according to some implementations. FIG. 21 depicts a computer 2100 that includes a processor 2101 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer 2100 includes a memory 2107. The memory 2107 may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer 2100 also includes a bus 2103 and a network interface 2105. The computer 2100 also includes a signal processor 2111 and a controller 2115. The signal processor 2111 and the controller 2115 can perform one or more of the operations described herein.

Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 2101. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 2101, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 21 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor 2101 and the network interface 2105 are coupled to the bus 2103. Although illustrated as being coupled to the bus 2103, the memory 2107 may be coupled to the processor 2101.

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. In general, techniques for simulating drill bit abrasive wear and damage during the drilling of a wellbore as described herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.

Example Implementations

Implementation #1: A method comprising: measuring, at a surface of a wellbore during drilling of the wellbore, at least one drilling operational parameter; determining at least one at-bit model parameter, at a drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore; and determining a drilling efficiency based on the at least one at-bit model parameter.

Implementation #2: The method of Implementation #1, further comprising: transforming the at least one drilling operational parameter to at least one scaled drilling operational parameter based on transformation of the drill bit to an equivalent singular blade at unit length.

Implementation #3: The method of any one of Implementations #1-2, wherein determining the at least one at-bit parameter, at the drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore comprises: creating a bit-rock interaction model.

Implementation #4: The method of any one of Implementations #1-3, wherein determining the at least one at-bit parameter, at the drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore comprises: performing the following during drilling of the wellbore, monitoring, during drilling of the wellbore, whether the bit-rock interaction model is changing based on the at least one drilling operational parameter; and in response to the bit-rock interaction model changing, adjusting the bit-rock interaction model based on changes to the at least one drilling operational parameter.

Implementation #5: The method of any one of Implementations #1-4, wherein the at least one drilling operational parameter comprises at least one of weight on bit, rotations per unit of time of the drill string, or a flow rate of a drilling mud.

Implementation #6: The method of any one of Implementations #1-5, wherein the at least one at-bit parameter comprises at least one of weight on bit, torque on bit, or depth of cut.

Implementation #7: The method of any one of Implementations #1-6 further comprising: modifying at least one operational attribute of the drilling of the wellbore based on the drilling efficiency, wherein the at least one operational attribute of the drilling of the wellbore comprises at least one of weight on bit, rotations of a drill string used for drilling the wellbore per unit of time, or a flow rate of a drilling fluid flowing in the wellbore.

Implementation #8: The method of any one of Implementations #1-7, further comprising: determining at least one of different drilling regimes, a founder point, or a limiter point based on the bit-rock interaction model; and classifying the drilling of the wellbore based on the at least one of the different drilling regimes, the founder point, or the limiter point; and determining a current weight on bit (WOB) of the drilling of the wellbore; comparing the current WOB of the drilling of the wellbore to at least one of the founder point or the limiter point; calculating a performance index for drilling the wellbore based on the comparing; and modifying an operation of the drilling of the wellbore based on the different drilling regimes and based on the performance index.

Implementation #9: The method of any one of Implementations #1-8, further comprising: performing a postmortem analysis of the drilling of the wellbore based on previously recorded at least one drilling operational parameter.

Implementation #10: The method of any one of Implementations #1-9, further comprising: using the postmortem analysis to inform decisions on drilling of a different wellbore to be drilled, in response to determining that at least one condition of the wellbore and the different wellbore are the same or substantially the same.

Implementation #11: The method of any one of Implementations #1-10, further comprising: logging, into a database, at least one of the informing of decisions on the drilling of the different wellbore, the at least one drilling operational parameter measured during drilling of the wellbore, and the performance index calculated for the drilling of the wellbore; and assessing overall metrics of effectivity of automated decision making with respect to the drilling efficiency.

Implementation #12: The method of any one of Implementations #1-11, further comprising: tracking and classifying, over a defined depth of the drilling of the wellbore, the drilling efficiency; and displaying the tracking and classifying, over the defined depth of the drilling of the wellbore, of the drilling efficiency in a form of at least one of a bar chart, a stacked bar chart, or a histogram.

Implementation #13: A non-transitory, computer-readable medium having instructions stored thereon that are executable by a processor, the instructions comprising: instructions to measure, at a surface of a wellbore during drilling of the wellbore, at least one drilling operational parameter; instructions to determine at least one at-bit parameter, at a drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore; and instructions to determine a drilling efficiency based on the at least one at-bit parameter.

Implementation #14: The non-transitory, computer-readable medium of Implementation #13, wherein the instructions comprise, instructions to transform the at least one drilling operational parameter to at least one scaled drilling operational parameter based on transformation of the drill bit to an equivalent singular blade at unit length.

Implementation #15: The non-transitory, computer-readable medium of any one of Implementations #13-14, wherein the instructions to determine the at least one at-bit parameter, at the drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore comprises: instructions to create a bit-rock interaction model.

Implementation #16: The non-transitory, computer-readable medium of any one of Implementations #13-15, wherein the instructions to determine the at least one at-bit parameter, at the drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore comprise: instructions to perform the following during drilling of the wellbore, instructions to monitor, during drilling of the wellbore, whether the bit-rock interaction model is changing based on the at least one drilling operational parameter; and in response to the bit-rock interaction model changing, instructions to adjust the bit-rock interaction model based on changes to the at least one drilling operational parameter.

′ Implementation #17: 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, measure, at a surface of a wellbore during drilling of the wellbore, at least one drilling operational parameter; determine at least one at-bit parameter, at a drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore; and determine a drilling efficiency based on the at least one at-bit parameter.

Implementation #18: The apparatus of Implementation #17, wherein the instructions comprise instructions executable by the processor to cause the processor to, transform the at least one drilling operational parameter to at least one scaled drilling operational parameter based on transformation of the drill bit to an equivalent singular blade at unit length.

Implementation #19: The apparatus of any one of Implementations #17-18, wherein the instructions executable by the processor to cause the processor to determine the at least one at-bit parameter, at the drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore comprises: instructions executable by the processor to cause the processor to create a bit-rock interaction model.

Implementation #20: The apparatus of any one of Implementations #17-19, wherein the instructions executable by the processor to cause the processor to determine the at least one at-bit parameter, at the drill bit used for drilling the wellbore, based on the at least one drilling operational parameter measured at the surface of the wellbore comprise instructions executable by the processor to cause the processor to, perform the following during drilling of the wellbore, monitor, during drilling of the wellbore, whether the bit-rock interaction model is changing based on the at least one drilling operational parameter; and in response to the bit-rock interaction model changing, adjust the bit-rock interaction model based on changes to the at least one drilling operational parameter.

DRILLING EFFICIENCY EVALUATION

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