BIT DAMAGE INDICATOR

Description

TECHNICAL FIELD

This disclosure relates generally to earth-boring tools for use in drilling wellbores, to bottom-hole assemblies and systems incorporating earth boring tools. More specifically, this disclosure relates to methods and systems for monitoring wear and/or damage to drill bits for use in drilling wellbores.

BACKGROUND

Oil wells (wellbores) can be drilled with a drill string. The drill string includes a tubular member having a drilling assembly that includes a single drill bit at its bottom end. The drilling assembly typically includes devices and sensors that provide information relating to a variety of parameters relating to the drilling operations (“drilling parameters”), behavior of the drilling assembly (“drilling assembly parameters”) and parameters relating to the formations penetrated by the wellbore (“formation parameters”). A drill bit and/or reamer attached to the bottom end of the drilling assembly is rotated by rotating the drill string from the drilling rig and/or by a drilling motor (also referred to as a “mud motor”) in the bottom-hole assembly (“BHA”) to remove formation material to drill the wellbore. A large number of wellbores are drilled along non-vertical, contoured trajectories in what is often referred to as directional drilling. For example, a single wellbore may include one or more vertical sections, deviated sections and horizontal sections extending through differing types of rock formations. During drilling operations, a drill bit may become worn or damaged due to a variety of factors including one or more of the hardness of formation, the rate of penetration (“ROP”), the weight-on-bit (“WOB”), the rotational speed of the drill bit (RPMs), and the like.

BRIEF SUMMARY

In one aspect of the disclosure, a method of monitoring wear of a drill bit of a drilling system is provided. The method includes drilling into a formation using the drill bit of the drilling system and obtaining a weight-on-bit (“WOB”) from sensors of the drilling system. A first apparent rock strength of a formation is determined based on the WOB. The method further includes obtaining a torque-on-bit (“TOB”) from the sensors of the drilling system and determining a second apparent rock strength of the formation based on the TOB. A bit damage indicator (“BDI”) is determined that is correlated with the wear of the drill bit based on a relationship between the first apparent rock strength based on WOB and the second apparent rock strength based on TOB. The drill bit is removed from service based on the determined BDI.

In one aspect of the disclosure, a method of monitoring wear of a drill bit of a drilling system is provided. The method includes drilling into a formations using the drill bit of the drilling system, obtaining a weight-on-bit (“WOB”) from sensors of the drilling system, and obtaining a torque-on-bit (“TOB”) from the sensors of the drilling system. A bit damage indicator (“BDI”) is determined that is correlated with the wear of the drill bit based on a relationship between the WOB and the TOB.

In one aspect of the disclosure, a drilling system includes a drill string and a drill bit disposed at a distal end of the drill string. The drilling system also includes a rig disposed above a surface of a formation and at a proximal end of the drill string. The drilling system includes a drilling motor configured to rotate the drill bit at the distal end of the drill string and one or more sensors operable to measure weight-on-bit (“WOB”) and torque-on-bit (“TOB”) associated with the drill bit, and a two-way telemetry unit communicatively coupled to the one or more sensors. A surface control unit is communicatively coupled to the two-way telemetry unit. The surface control unit includes a processor configured to execute machine-readable instructions stored on a data storage device, which when executed cause the surface control unit to obtain the WOB from the one or more sensors via the two-way telemetry unit and obtain the TOB from the one or more sensors via the two-way telemetry unit. The surface control unit determines a bit damage indicator (“BDI”) correlated with the wear of the drill bit based on a relationship between the WOB and the TOB.

BRIEF DESCRIPTION OF THE DRAWINGS

To easily identify the discussion of any particular element or act, the most significant digit or digits in a reference number refer to the figure number in which that element is first introduced.

FIG. 1 is a schematic diagram of an example of a drilling system according to embodiments of the present disclosure.

FIG. 2 is a method of estimating bit damage in a drilling system according to embodiments of the present disclosure.

FIG. 3 is a method of estimating bit damage in a drilling system according to embodiments of the present disclosure.

FIG. 4A and FIG. 4B show exemplary data from a drilling operation illustrating a change in BDI over the course of the drilling operation according to embodiments of the present disclosure.

DETAILED DESCRIPTION

The illustrations presented herein are not actual views of any particular drilling system, drilling tool assembly, or component of such an assembly, but are merely idealized representations, which are employed to describe the present invention.

As used herein, the terms “bit” and “earth-boring tool” each mean and include earth-boring tools for forming, enlarging, or forming and enlarging a wellbore. Non-limiting examples of bits include fixed-cutter (drag) bits, fixed-cutter coring bits, fixed-cutter eccentric bits, fixed-cutter bicenter bits, fixed-cutter reamers, expandable reamers with blades bearing fixed cutters, and hybrid bits including both fixed cutters and movable cutting structures (roller cones).

As used herein, the term “fixed cutter” means and includes a cutting element configured for a shearing cutting action, abrasive cutting action or impact (percussion) cutting action and fixed with respect to rotational movement in a structure bearing the cutting element, such as, for example, a bit body, a tool body, or a reamer blade, without limitation.

As used herein, the terms “wear element” and “bearing element” respectively mean and include elements mounted to an earth-boring tool and which are not configured to substantially cut or otherwise remove formation material when contacting a subterranean formation in which a wellbore is being drilled or enlarged.

As used herein, the term “drilling element” means and includes fixed cutters, wear elements, and bearing elements. For example, drilling elements may include cutting elements, pads, elements making rolling contact, elements that reduce friction with formations, polycrystalline diamond compact (PDC) bit blades, cones, elements for altering junk slot geometry, etc.

As used herein, any relational term, such as “first,” “second,” “front,” “back,” etc., is used for clarity and convenience in understanding the disclosure and accompanying drawings, and does not connote or depend on any specific preference or order, except where the context clearly indicates otherwise.

As used herein, the term “substantially” in reference to a given parameter, property, or condition means and includes to a degree that one skilled in the art would understand that the given parameter, property, or condition is met with a small degree of variance, such as within acceptable manufacturing tolerances. For example, a parameter that is substantially met may be at least about 90% met, at least about 95% met, or even at least about 99% met.

FIG. 1 is a schematic diagram of an example of a drilling system 100 that may utilize the apparatuses and methods disclosed herein for drilling wellbores. FIG. 1 shows a wellbore 102 that includes an upper section 104 with a casing 106 installed therein and a lower section 108 that is being drilled with a drill string 110. The drill string 110 may include a tubular member 112 that carries a drilling assembly 114 at its bottom end. The tubular member 112 may be made up by joining drill pipe sections or it may be a string of coiled tubing. A drill bit 116 may be attached to the bottom end of the drilling assembly 114 for drilling the wellbore 102 of a selected diameter in a formation 118.

The drill string 110 may extend to a rig 120 at the surface 122. The rig 120 shown is a land rig 120 for ease of explanation. However, the apparatuses and methods disclosed equally apply when an offshore rig 120 is used for drilling wellbores under water. A rotary table 124 or a top drive may be coupled to the drill string 110 and may be utilized to rotate the drill string 110 and to rotate the drilling assembly 114, and thus the drill bit 116 to drill the wellbore 102. A drilling motor 126 (also referred to as “mud motor”) may be provided in the drilling assembly 114 to rotate the drill bit 116. The drilling motor 126 may be used alone to rotate the drill bit 116 or to superimpose the rotation of the drill bit 116 by the drill string 110. The rig 120 may also include conventional equipment, such as a mechanism to add additional sections to the tubular member 112 as the wellbore 102 is drilled. A surface control unit 128, which may be a computer-based unit, may be placed at the surface 122 for receiving and processing downhole data transmitted by sensors 140 in the drill bit 116 and sensors 140 in the drilling assembly 114, and for controlling selected operations of the various devices and sensors 140 in the drilling assembly 114. The sensors 140 may include one or more of sensors 140 that determine acceleration, weight-on-bit, torque, pressure, cutting element positions, rate of penetration, inclination, azimuth formation/lithology, etc. In some embodiments, the surface control unit 128 may include a processor 130 and a data storage device 132 (or a computer-readable medium) for storing data, algorithms, and computer programs 134. The data storage device 132 may be any suitable device, including, but not limited to, a read-only memory (ROM), a random-access memory (RAM), a Flash memory, a magnetic tape, a hard disk, and an optical disk. During drilling, a drilling fluid from a source 136 thereof may be pumped under pressure through the tubular member 112, which discharges at the bottom of the drill bit 116 and returns to the surface 122 via an annular space (also referred as the “annulus”) between the drill string 110 and an inside wall 138 of the wellbore 102.

The drilling assembly 114 may further include one or more sensors 140 including surface sensors 140 and downhole sensors 140 (collectively designated by numeral 140). The sensors 140 may include any number and type of sensors 140, including, but not limited to, sensors 140 generally known as the measurement-while-drilling (MWD) sensors 140 or the logging-while-drilling (LWD) sensors 140, and sensors 140 that provide information relating to the behavior of the drilling assembly 114, such as drill bit rotation (revolutions per minute or “RPM”), tool face, pressure, vibration, whirl, bending, torque, weight, stick-slip, etc. The drilling assembly 114 may further include a downhole controller unit 142 that controls the operation of one or more devices and sensors 140 in the drilling assembly 114. For example, the downhole controller unit 142 may be disposed within the drill bit 116 (e.g., within a shank and/or crown of a bit body of the drill bit 116). The downhole controller unit 142 may include, among other things, circuits to process the signals from sensors 140, a processor 144 (such as a microprocessor) to process the digitized signals, a data storage device 146 (such as a solid-state-memory), and a computer program 148. The processor 144 may process the digitized signals, control downhole devices and sensors 140, and communicate data information with the surface control unit 128 via a two-way telemetry unit 150.

The drill bit 116 may include a face section 152 (or bottom section). The face section 152 or a portion thereof may face the undrilled formation 118 in front of the drill bit 116 at the wellbore 102 bottom during drilling. In some embodiments, the drill bit 116 may include one or more cutting elements that may be extended and retracted from a surface, such as a surface over the face section 152, of the drill bit 116 and, more specifically, a blade projecting from the face section 152.

During a drilling operation, the drill bit 116 may become worn and/or damaged. The wear of the drill bit may be based on a number of factors including a hardness of the formation 118, the rotational speed (RPM) of the drill bit 116, a change in material of the formation 118 as the drill bit 116 moves through the formation 118, WOB, or the like. Accordingly, information about wear or damage of the drill bit 116 may be provided to operators of the drilling system 100.

Conventional methods for obtaining estimates of wear or damage to a drill bit (e.g., drill bit 116) suffer from several technical drawbacks. For example, many convention methods cannot provide estimates of wear or damage in real time. Such conventional methods may require data from off-set wells, may require comparison with historical data, such as “logging-while-drilling” (“LWD”) data, may require specially trained operators, or the like. Furthermore, in conventional methods, it may be difficult to determine exactly when a drill bit suffered damage during a post-run analysis of a drilling operation. In some conventional methods, it may be difficult to isolate potential wear on a drill bit from other drilling parameters such as a change in hardness of a rock formation.

FIG. 2 shows a method 200 of estimating bit damage in a drilling system according to embodiments of the present disclosure. The method 200 may allow an operator of a drilling system (e.g., drilling system 100) to monitor wear/damage of a drill bit (e.g., drill bit 116) in real time using existing available sensors (e.g., sensors 140) of the drilling system. The method 200 may be completed without the need for data from off-set wells, LWD data, or specially trained operators. The method 200 may further allow an operator to determine the wear of a drill bit independent and isolated from other factors such as a change in hardness of a rock formation.

It has been found that the wear and/or damage of a drill bit may be correlated to a ratio of a first apparent rock hardness estimate based on weight to a second apparent rock hardness estimate based on torque. For example, the wear and/or damage of the drill bit may be correlated to a ratio of the confined compressive strength (“CCS”) of a rock formation based on weight-on-bit (“WOB”) to the CCS of the rock formation based on torque-on-bit (“TOB”). As a drill bit wears or becomes damaged (e.g., as the bit develops wear flats), the WOB based CCS estimate increases at a greater rate than the TOB based CCS estimate. By comparing the WOB and the TOB CCS estimates, a value estimating an amount of wear or damage to the bit, hereinafter referred to as a bit damage indicator (“BDI”), may be provided.

The CCS estimates based on WOB and TOB may be obtained via WOB and TOB sensors located on the drilling system (e.g., sensors 140 of drilling system 100). Such sensors may be configured to provide WOB and TOB to a drilling operator in real time. Accordingly, using the TOB and WOB sensors on the drilling system may enable an operator to track the wear/damage of the drill bit in real time based on the WOB and TOB CCS estimates. Further, because the CCS estimates of both WOB and TOB are used to determine BDI, the BDI can be determined regardless of changes in hardness of a formation.

The CCS or apparent rock strength estimate based on TOB may be derived based on the mechanical specific energy (“MSE”) (i.e., the amount of work performed per unit volume of rock drilled), TOB sensors, a motor formula based on the differential pressure of the motor (e.g., drilling motor 126) ΔP, or surface torque plus torque and drag calculation. For example, the CCS based on torque may be calculated as follows:

C ⁢ C ⁢ S T = 4 ⁢ 8 ⁢ 0 ⁢ ( R ⁢ P ⁢ M ) ⁢ ( TOB ) ⁢ ( Eff ) D 2 ( ROP ) Equation ⁢ 1

• • where D is a drill bit diameter, RPM is revolutions per minute, ROP is a rate of penetration, and Eff is an efficiency factor.

The CCS based on TOB can also be estimated based on a motor formula as follows:

CCS T = M ⁡ ( 120 ⁢ π ) ⁢ ( RPM ) ⁢ ( Δ ⁢ P ) D 2 ( ROP ) Equation ⁢ 2

• • where M is a constant that may be experimentally adjusted based on drilling parameters of a particular drilling system, and ΔP is the differential pressure of a motor.

As mentioned above, the BDI is found based on a comparison of the CCS based on TOB to the CCS based on WOB. The CCS based on WOB may be derived as follows:

C ⁢ C ⁢ S W = K ⁡ ( 120 ⁢ π ) ⁢ ( RPM ) ⁢ ( WOB ) D ⁡ ( ROP ) Equation ⁢ 3

• • where K is a bit design-dependent factor that is a function of diameter, back rate, and cutter count.

The comparison of the CCS estimates based on WOB and TOB to determine BDI may be based on a subtraction comparison method. For example, the bit damage indicator may be calculated using the following equation:

BDI = ( C ⁢ C ⁢ S W - C ⁢ C ⁢ S T ) C ⁢ C ⁢ S T Equation ⁢ 4

By utilizing the above equations, the BDI may be more simply expressed as follows:

BDI = A ⁡ ( D ) ⁢ ( WOB ) 3 ⁢ 6 ⁢ ( TOB ) - 1 Equation ⁢ 5

Therefore, the BDI may be based on the relationship between bit diameter D, WOB, and TOB. The bit diameter is a known constant, and the WOB and TOB may be obtained by sensors on a drilling system. Because A, diameter D, and 36 are constants, equation 5 can be simplified and expressed as shown in Equation 6 below:

B ⁢ D ⁢ I = A ′ ( WOB ) T ⁢ O ⁢ B - 1 Equation ⁢ 6

The BDI may also be determined utilizing the differential pressure of the motor, ΔP, in place of the torque on bit as shown in Equation 7 below:

B ⁢ D ⁢ I = A ′ ( WOB ) Δ ⁢ P - 1 Equation ⁢ 7

The BDI may provide an accurate estimate of wear/estimate of a drill bit of a drilling system that is independent of rock-strength changes and that can be reported in real time to an operator based on sensor information available to the operator (e.g., WOB, TOB, and/or ΔP).

Returning to FIG. 2, in step 202, sensors (e.g., sensors 140 of the drilling system 100) are calibrated and or tared prior to a drilling operation. This may help to ensure accurate information is used to calculate the BDI indicating the wear/damage of the drill bit. For example, prior to a drilling operation when a drill bit is “off bottom,” the sensors measuring the WOB may be zeroed or tared. TOB may also be tared when not drilling. In some embodiments, torque and drag models may be used to calculate the TOB at the bit while subtracting the torque due to the drill string contact along the wellbore wall.

In step 204, a drilling operation commences. For example, an operator may utilize a surface control unit (e.g., surface control unit 128) to cause the drill bit (e.g., drill bit 116) to begin drilling into a formation (e.g., formation 118).

As the drilling operation commences, the BDI for the drill bit may be initially calibrated based in step 206. For example, based on the WOB and TOB received from sensors of the drilling system, the BDI may be calculated according to Equations 5-7 above. During an initial period of the drilling operation, it is known or assumed that the drill bit is not substantially damaged or worn. The BDI based on WOB and TOB may be calibrated by, for example, adjusting the variable A in Equation 5 or A′ in Equations 6 and/or 7 such that the BDI is set to be about 0 during the initial period of the drilling operation, indicating no wear/damage on the drill bit.

For example, with reference to FIG. 1, the processor 130 running the computer program 134 may be configured to monitor the BDI for the initial period of the drilling operation and may adjust the variable A in Equation 5 or variable A′ in Equations 6 and/or 7 such that the BDI is calibrated for the drilling operation. The initial period may be based on a predetermined amount of time at the beginning of the drilling operation or a predetermined amount of drill bit penetration at the beginning of the drilling operation. For example, the initial period may be for an initial drill bit penetration of about 10 feet or less into the formation 118. In other examples, the initial period may be for an initial drill bit penetration of about 50 feet or less into the formation 118. In other examples, the initial period may be for an initial drill bit penetration of about 100 feet or less into the formation 118. When the initial period is based on a predetermined amount of time, the initial period may be an initial drill bit penetration time of about 60 minutes or less. In some embodiments, the initial period may may be an initial drill bit penetration time of about 30 minutes or less.

In step 208, as a drilling operation is ongoing (e.g., as the drill bit 116 continues to drill into a formation 118 in FIG. 1), the BDI may be monitored as shown in Equations 4-7 above by comparing the apparent rock strength based on WOB with the apparent rock strength based on TOB. As mentioned above, as the drill bit begins to wear or become damaged, the change in apparent rock strength based on WOB increases more rapidly than the change in apparent rock strength based on TOB. Thus, as the drill bit beings to wear or becomes damaged, the BDI will begin to increase. Referring again to FIG. 1, The BDI may be monitored, for example, by the processor 130 running the computer program 134 receiving WOB and TOB information from the sensors 140 via the two-way telemetry unit 150. The BDI may also be monitored by the processor 144 of the downhole controller unit 142 receiving the WOB and TOB information from the sensors 140. In some examples, the BDI may be displayed on a user interface device of the surface control unit 128 to be monitored by an operator. In some examples, the BDI may be stored in a data storage device, such as data storage devices 132, 146. In step 208, it is determined whether the BDI is within a predetermined range. While the BDI is within the predetermined range, the method 200 may proceed to step 212. In step 212 with the BDI within the predetermined range, the drill bit is considered not worn/damaged. The method 200 may return to step 208 where the BDI is continuously monitored.

If in step 208 the BDI is determined to be outside or in excess of the predetermined range, the method 200 may proceed to step 210. In step 210, with the BDI being outside the predetermined range, it is determined that the drill bit is worn and/or damaged. When it is determined that the drill bit is worn and/or damaged, an operator of the drilling system 100 may be notified such as via a user interface device of the surface control unit 128. In some embodiments, the surface control unit 128 and/or the downhole controller unit 142 may be configured to take a specific action based on the indication that the drill bit is worn or damaged, such as generating an alert or an alarm, slowing or stopping a drilling operation, or the like. In some embodiments, the downhole controller unit 142 may be configured to take the specific action without communication to the surface, e.g., without communication to the surface control unit 128. In some embodiments, the drill bit may be removed from service based on the indication that the drill bit is worn or damaged.

The BDI not only may be used in real-time during a drilling operation, but also may be used to analyze a completed drilling operation (e.g., may be used in a “post-run” analysis). FIG. 3 shows a method 300 of estimating bit damage in a drilling system according to embodiments of the present disclosure. In the method 300, the BDI is estimated and analyzed post-run, i.e., after a drilling operation has been completed. In step 302, a data history of a drilling operation is obtained, such as at the surface control unit 128 or other electronic device. The data history may be stored in a data storage device 132 of the surface control unit 128 or may be stored in a data storage device 146 of the downhole controller unit 142. The data history may comprise WOB and TOB information from the drilling operation, along with other drilling parameters observed during the drilling operation. The data history may be obtained via sensors 140 conveyed to the surface control unit 128 via the two-way telemetry unit 150. The data history may further be obtained directly from a data storage device 146 disposed on a downhole controller unit 142 within the drill bit 116 after a completed drilling operation.

In step 304, the BDI is calculated over the course of the drilling operation. For example, utilizing one or more of Equations 4-7 above, the surface control unit 128 or other electronic device running a computer program 134 may calculate the BDI over the course of a drilling operation. In step 306, it is determined whether the BDI exceeded a predetermined threshold over the course of the drilling operation. If the BDI did not exceed the predetermined threshold, the method 300 proceeds to step 308 where it is determined that the drill bit was not worn or damaged during the drilling operation. If the BDI did exceed the predetermined threshold, the method 300 proceeds to step 310 where it is determined that the drill bit was worn and/or damaged during a drilling operation, and the increase of the BDI is correlated with one or more drilling parameters.

For example, in step 310, an increase in BDI may be associated with one or more drilling parameters to provide insight into a causation of the wear and/or damage to the drill bit. For example, an increase in BDI may be correlated to a depth of drill bit penetration within a formation that is associated with a change in rock hardness or that is associated with a drill bit going out of an intended drilling zone. The increase in BDI may also be associated with an RPM of the drill bit, an increase in weight on the drill bit, a change in a rate of drill bit penetration through a formation, vibrations detected at the drill bit, or the like.

FIGS. 4A and 4B show exemplary data from a drilling operation. In FIG. 4A, a CCS based on WOB, such as the CCS_W calculated in Equation 3 above, and a CCS based on TOB, such as the CCS_T calculated in Equation 1 or 2 above, are shown over the course of a drilling operation where the drill bit penetrates a surface at depths indicated. A formation hardness based on gamma ray measurements is also scaled over the depths of the drill bit. At a first depth 402, data shows that the drill bit encounters a relatively harder section within the formation indicated by the drop in the gamma ray measurements. At a second depth 404, data shows that the drill bit encounters another relatively harder section within the formation. As shown in FIG. 4A, after the drill bit encounters the relatively harder sections at the first depth 402 and second depth 404, the CCS based on WOB begins to increase faster than the CCS based on TOB, and a deviation between the CCS based on WOB and the CCS based on TOB can be seen in FIG. 4A. In FIG. 4B, this deviation is shown as an increase in the BDI, such as calculated by one or more of Equations 4-7 above. The increase in the BDI indicates that the drill bit is beginning to wear or become damaged.

At a third depth 406 in this example, a drill bit has been inadvertently steered out of an intended zone of the formation and encounters another relatively hard section of the formation. At increased depths after the third depth 406, it can be seen that the CCS based on WOB deviates more dramatically from the CCS based on TOB in FIG. 4A. This increased deviation would be shown as a further increase in the BDI, such as calculated by Equations 4-7 above and as shown in FIG. 4B. This further increase in the BDI would indicate that the drill bit has undergone increased wear and/or damage.

The above-described system and methods show that the BDI may be calculated based on the relationship between apparent rock strength as estimated by the WOB and the TOB. By utilizing the BDI based on the WOB and the TOB, an indication of the damage and/or wear to the drill bit may be provided in real time. In some embodiments, a BDI may be based on other methods of calculating apparent rock strength, such as using data from drill logs, gamma ray measurements, acoustic measurements, conducting drill-out tests, or the like. However, such methods of calculating BDI may not be able to provide the BDI in real time to an operator of a drilling system.

Utilizing BDI may provide other advantages as compared to conventional bit damage measurement systems. For example, the BDI as described herein may indicate wear and/or damage to a drill bit that is independent from rock hardness. Thus, a drill bit operator may easily determine the wear and/or damage of the drill bit in real time even when the drill bit encounters sections of a formation having different hardness.

The embodiments of the disclosure described above and illustrated in the accompanying drawings do not limit the scope of the disclosure, which is encompassed by the scope of the appended claims and their legal equivalents. Any equivalent embodiments are within the scope of this disclosure. Indeed, various modifications of the disclosure, in addition to those shown and described herein, such as alternate useful combinations of the elements described, will become apparent to those skilled in the art from the description. Such modifications and embodiments also fall within the scope of the appended claims and equivalents.