The use of automated drilling methods is becoming increasingly common in drilling subterranean wellbores. Such methods may be employed, for example, to control the direction of drilling based on various downhole feedback measurements, such as wellbore inclination and azimuth measurements made while drilling or logging while drilling measurements. For example, such methods may be intended to control the wellbore curvature such as the build rate or turn rate of the wellbore, or to control a complex curve while drilling.
One difficulty with implementing such automated drilling methods is accurately correlating time domain surveying measurements (e.g., wellbore inclination and azimuth) with an appropriate measured depth in the wellbore. The rate of penetration (ROP) of drilling is generally required to convert time domain measurements to the measured depth domain. While ROP is commonly measured at the surface, a suitable communications channel is not always available to downlink the ROP measurements.
A method for estimating a rate of penetration while drilling is disclosed. The method includes rotating a bottom hole assembly in a subterranean wellbore to drill, the drill string including a rotary steerable tool or a steerable drill bit. A first rate of penetration of drilling is measured using a first measurement method and a second rate of penetration of drilling is measured using a second measurement method. The first and second rates of penetration are combined to obtain a combined rate of penetration of drilling.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
For a more complete understanding of the disclosed subject matter, and advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
Methods for estimating a rate of penetration while drilling a subterranean wellbore are disclosed. In some embodiments, the methods include estimating a first rate of penetration while drilling using a first measurement method, estimating a second rate of penetration while drilling using a second measurement method, and combining the first and second rates of penetration to obtain a combined rate of penetration of drilling.
Embodiments of the present may provide various technical advantages and improvements over the prior art. For example, in some embodiments, the disclosed embodiments provide improved methods for making downhole estimates of the rate of penetration while drilling. The disclosed embodiments may provide improved accuracy and/or enable rate of penetration measurements to be made over an entire drilling operation including vertical, curved, and horizontal sections of the wellbore. Improving rate of penetration estimates may further provide for improved automated drilling methods with improved position control.
It will be understood by those of ordinary skill in the art that the deployment illustrated on
With continued reference to
The PowerDrive rotary steerable systems (available from Schlumberger) fully rotate with the drill string (i.e., the outer housing rotates with the drill string). The PowerDrive Xceed makes use of an internal steering mechanism that does not require contact with the wellbore wall and enables the tool body to fully rotate with the drill string. The PowerDrive X5, X6, and Orbit rotary steerable systems make use of mud actuated blades (or pads) that contact the wellbore wall. The extension of the blades (or pads) is rapidly and continually adjusted as the system rotates in the wellbore. The PowerDrive Archer rotary steerable system makes use of a lower steering section joined at a swivel with an upper section. The swivel is actively tilted via pistons so as to change the angle of the lower section with respect to the upper section and maintain a desired drilling direction as the bottom hole assembly rotates in the wellbore. Accelerometer and magnetometer sets may rotate with the drill string or may alternatively be deployed in an internal roll-stabilized housing such that they remain substantially stationary (in a bias phase) or rotate slowly with respect to the wellbore (in a neutral phase). To drill a desired curvature, the bias phase and neutral phase are alternated during drilling at a predetermined ratio (referred to as the steering ratio).
Turning now to
In method 100 the steering tool is actuated to drill a curved section of wellbore (i.e., a section of wellbore in which the wellbore attitude changes with measured depth). Wellbore attitude (wellbore inclination and wellbore azimuth) measurements are received at 104. Such wellbore surveying measurements may be received, for example, from a measurement while drilling tool deployed elsewhere in the drill string or from the steering tool. The wellbore surveying measurements are made in the steering tool, having a close proximity to the drill bit (e.g., using a triaxial magnetometer set and a triaxial accelerometer set deployed in the steering tool (e.g., a roll stabilized control unit of a rotary steerable tool). The wellbore inclination and wellbore azimuth measurements may also advantageously be made continuously while drilling, for example, as disclosed in commonly assigned U.S. Pat. No. 9,273,547 which is incorporated by reference in its entirety herein.
With continued reference to
ΔØ=cos−1[sin(Inc1)sin(Inc2)cos(Az2−Az1)+cos(inc1)cos(Inc2)] (1)
where Inc1 and Inc2 represent the wellbore inclination at first and second times and Az1 and Az2 represent the wellbore azimuth at the first and second times. These wellbore inclination and wellbore azimuth values may be obtained at substantially any suitable first and second times defining a time interval Δt=t2−t1. The rate of penetration while drilling ROP may then be computed from the overall angle change at 110, for example, as follows:
where ΔØ is defined above, Δt represents the time interval, and DLS represents the dogleg severity (the curvature) of the curved section of the wellbore in units of angle change per change in measured depth (e.g., DLS is often expressed in unites of degrees per 100 feet of wellbore length). Note that the rate of penetration ROP is proportional to the overall angle change ΔØ and inversely proportional to the time interval Δt (and therefore proportional to the ratio of the overall angle change to the time interval).
In certain rotary steerable tool embodiments, the dogleg severity may be defined as the product of the maximum dogleg severity of the tool and the steering ratio such that: DLS=DLSmax. SR. Those of ordinary skill in the art will readily appreciate that certain rotary steerable tools alternate between bias and neutral phases (essentially steering and non-steering phases) and that the steering ratio SR represents the fraction of time spent actively steering. For such systems, ROP may be computed from the overall angle change at 110, for example, as follows:
where DLSmax represents the maximum achievable dogleg severity of the steering tool in units of angle change per change in measured depth (e.g., degrees per 100 feet) and SR represents the steering ratio having a value between 0 and 1.
At 154 downhole pressure measurements and/or turbine voltage measurements are evaluated to determine time instances at which the surface pumps are shut down (turned off). The downhole pressure measurements or turbine voltage measurements may be processed at 156 to determine a time interval required to drill the length of the stand. For example, the “pumps off” events may be taken to represent the connection time at which a new stand is added to the drill string and the time interval between sequential pumps off events may be taken to represent the time interval required to drill the length of the stand. It will be understood the surface pumps may be shut down for reasons other than connecting a new stand to the drill string. As described in more detail below, the processing at 156 may therefore further include filters or logic intended to eliminate such time instances.
The time interval required to drill the length of the stand may be evaluated at 158 to compute the average rate of penetration over the length of the stand. For example, the rate of penetration may be computed as follows:
where L represents the length of the stand and Δt represents the time interval required to drill the length of the stand. The time interval Δt may be determined, for example, by subtracting the time at which the pumps are turned off from the previous time at which the pumps were turned on (e.g., as determined by downhole pressure and/or turbine voltage measurements). In practice it is sometimes only possible to record time stamps at which the pumps are on (or turned on). In such embodiments, the measured time interval Δtm may represent the time interval between sequential “pumps on” events and may therefore include the connection time required to connect the pipe stand. In such embodiments, the rate of penetration may be advantageously computed, for example, as follows:
where tconnect represents an approximate or average connection time. It will be understood that no drilling takes place during the connection time and that subtracting this time (or an estimate of the connection time) from the time interval may improve the accuracy of the computed ROP.
With continued reference to
With continued reference to
ROPcom=K·ROP1+(1−K)ROP2 (6)
where ROPcom represents the combined rate of penetration, ROP1 and ROP2 represent the first and second ROP measurements obtained in 204 and 206, and K represents a coefficient having a value from 0 to 1. The value of K may be selected, for example, based on the section of wellbore being drilled. For example, in embodiments in which methods 100 and 150 are used to obtain the first and second ROP measurements, K may be set to zero for vertical and horizontal sections of the wellbore. For curved sections of the wellbore the value of K may be close to or equal to unity (e.g., in a range from about 0.5 to about 1).
In another example embodiment, the second ROP measurement may be used to calibrate the first ROP measurement and to thereby obtain a calibrated ROP measurement (or to facilitate making subsequent calibrated ROP measurements). In one example embodiment, method 150 may be used to calibrate method 100. For example, an overall angle change ΔØ may be measured at 204 as described above in 104, 106, and 108 of
where ROP2 represents the second ROP measurement made in 204 and DLSmax-c represents a calibrated maximum dogleg severity. Such calibration may be advantageous in certain drilling operations since DLSmax is not generally a fixed value, but may depend on various operational parameters including the type of drill bit used, BHA characteristics, and formation properties.
Subsequent calibrated ROP measurements ROPcal may then be computed based on subsequent overall angle change measurements (using method 100 as described above with respect to
While method 200 is described above with respect to the use of methods 100 and 150 as first and second ROP measurement methods, it will be understood that the disclosed embodiments are not so limited. Substantially any suitable first and second ROP measurement methods may be utilized. For example, in certain embodiments, the first ROP measurement method may include method 100, while the second ROP measurement method may include substantially any suitable other downhole ROP measurement method. In addition to method 150 described above with respect
With further reference to
It will be appreciated that the disclosed methods may be configured for implementation via one or more controllers deployed downhole (e.g., in a rotary steerable tool such as one of the rotary steerable tools 50 described above with respect to
It will be understood that this disclosure may include numerous embodiments. These embodiments include, but are not limited to, the following embodiments.
A first embodiment may include a method for estimating a rate of penetration while drilling a subterranean wellbore. The method may include (a) rotating a bottom hole assembly in the subterranean wellbore to drill, the drill string including a rotary steerable tool or a steerable drill bit; (b) measuring a first rate of penetration of drilling in (a) using a first measurement method; (c) measuring a second rate of penetration of drilling in (a) using a second measurement method; and (d) combining the first rate of penetration and the second rate of penetration to obtain a combined rate of penetration of drilling in (a).
A second embodiment may include the first embodiment where (d) includes computing an average or weighted average of the first rate of penetration and the second rate of penetration to obtain the combined rate of penetration.
A third embodiment may include the first embodiment where (d) includes processing the second rate of penetration in combination with the first rate of penetration to obtain a calibrated first rate of penetration.
A fourth embodiment may include any one of the first three embodiments where: (a) includes rotating a bottom hole assembly in the subterranean wellbore to drill a curved section of the wellbore; and (b) includes (i) measuring wellbore inclination and wellbore azimuth while drilling in (a), (ii) processing the wellbore inclination measurements and the wellbore azimuth measurements to compute an overall angle change between first and second axially spaced positions in the curved section, and (iii) processing the overall angle change to compute the first rate of penetration.
A fifth embodiment may include the fourth embodiment where the first rate of penetration is proportional to a ratio of the overall angle change and the time interval required to drill between the first and second positions in the curved section.
A sixth embodiment may include the fourth or fifth embodiment where the first rate of penetration is computed using the following mathematical equation:
where ROP represents the first rate of penetration, ΔØ represents the overall angle change, Δt represents a time interval required to drill the curved section between the first and second positions in the curved section, DLSmax represents a maximum dogleg severity of the rotary steerable tool or steerable bit, and SR represents a steering ratio.
A seventh embodiment may include the sixth embodiment where (d) includes processing the second rate of penetration to compute a calibrated maximum dogleg severity.
An eighth embodiment may include the seventh embodiment where the calibrated maximum dogleg severity is computed using the following mathematical equation:
where DLSmax-c represents the calibrated maximum dogleg severity and ROP2 represents the second rate of penetration.
A ninth embodiment may include the eighth or ninth embodiment, where the method further includes: (e) obtaining calibrated rate of penetration measurements based on subsequent overall angle change measurements and the calibrated maximum dogleg severity.
A tenth embodiment may include any one of the first nine embodiments where (c) further includes (i) measuring times at which surface pumps are shut off while drilling in (a), (ii) processing the times at which the pumps are shut off to determine a time interval required to drill a length of a stand of drilling pipe, and (iii) processing the time interval and the length of the stand of drilling pipe to compute the second rate of penetration.
An eleventh embodiment may include the tenth embodiment where the second rate of penetration is computed by dividing the length of the stand by the time interval required to drill the length of the stand.
A twelfth embodiment includes a method for estimating a rate of penetration while drilling a subterranean wellbore. The method may include: (a) rotating a bottom hole assembly in the subterranean wellbore to drill, the drill string including a rotary steerable tool or a steerable drill bit; (b) measuring times at which surface pumps are shut off while drilling in (a); (c) processing the times at which the pumps are shut off to determine a time interval required to drill a length of a stand of drilling pipe, and (d) processing the time interval and the length of the stand of drilling pipe to compute the rate of penetration of drilling in (a).
A thirteenth embodiment may include the twelfth embodiment where (b) further includes making downhole pressure measurements or turbine voltage measurements to determine the times at which the surface pumps are shut off.
A fourteenth embodiment may include the twelfth or thirteen embodiment where (c) further includes evaluating the times at which the surface pumps are shut off to select the times at which a new stand of drill pipe is connected and processing the times at which a new stand of drill pipe is connect to compute the time interval.
A fifteenth embodiment may include any one of the twelfth through fourteenth embodiments where the rate of penetration is computed by dividing the length of the stand by the time interval required to drill the length of the stand.
A sixteenth embodiment may include the fifteenth embodiment where the rate of penetration is computed according to the following mathematical equation:
where ROP represents the rate of penetration, L represents the length of the stand, Δtm represents a time interval between sequential pumps on events, and tconnect represents an approximate or average time required to connect the stand of drill pipe.
A seventeenth embodiment includes a method for estimating a rate of penetration while drilling a subterranean wellbore. The method may include: (a) rotating a bottom hole assembly in the subterranean wellbore to drill a curved section of a wellbore; (b) measuring wellbore inclination and wellbore azimuth while drilling in (a); (c) processing the wellbore inclination measurements and the wellbore azimuth measurements to compute an overall angle change between first and second axially spaced positions in the curved section; and (d) processing the overall angle change to compute a rate of penetration of drilling in (a).
An eighteenth embodiment may include the seventeenth embodiment where the rate of penetration is proportional to a ratio of the overall angle change and a time interval required to drill between the first and second positions in the curved section.
A nineteenth embodiment may include the seventeenth or eighteenth embodiment where the rate of penetration is computed in (d) using the following mathematical equation:
where ROP represents the rate of penetration, ΔØ represents the overall angle change, Δt represents the time interval, and DLS represents a dogleg severity of the curved section drilled in (a).
A twentieth embodiment may include the seventeenth or eighteenth embodiment where the rate of penetration is computed in (d) using the following mathematical equation:
where ROP represents the rate of penetration, ΔØ represents the overall angle change, Δt represents the time interval, DLSmax represents a maximum dogleg severity of the rotary steerable tool or steerable bit, and SR represents a steering ratio.
Although a method for estimating the rate of penetration while drilling has been described in detail, it should be understood that various changes, substitutions and alterations may be made herein without departing from the spirit and scope of the disclosure. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein.
A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function.
The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.
This application is the National Stage Entry of International Application No. PCT/US2020/065814, filed Dec. 18, 2020, which claims the benefit of, and priority to, U.S. Patent Application No. 62/952,506, filed Dec. 23, 2019, which application is expressly incorporated herein by this reference in its entirety.
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