Binning During Non-Rotation Drilling in a Wellbore

Abstract

A drilling rig apparatus is disclosed for improving slide drilling control by enabling use of azimuthal measurements while slide drilling to characterize and direct geosteering control. A bottom hole assembly controller receives RPM and gamma sensor data and transitions from a rotary, vertical binning mode to a slide drilling, horizontal binning mode when the RPM falls below a threshold. In the horizontal mode, the BHA controller tracks the hemisphere that the gamma sensors are in. As data from a gamma sensor is received from the upper hemisphere, it is associated with a top bin in a radial plot, and data from a gamma sensor in the lower hemisphere is associated with a bottom bin. The BHA controller estimates one or more bin values for bins falling between the top and bottom bins. The measured and estimated bin data is transmitted to the surface for image log creation and geosteering control.

Description

TECHNICAL FIELD

The present disclosure is directed to systems, devices, and methods for improving geosteering control during non-rotation drilling, such as during slide drilling. More specifically, the present disclosure is directed to improving slide drilling control by enabling use of azimuthal measurements while slide drilling to characterize and direct geosteering control.

BACKGROUND OF THE DISCLOSURE

Subterranean “sliding” drilling operations typically involve rotating a drill bit on a downhole motor at a remote end of a non-rotating drill pipe string. Drilling fluid forced through the drill pipe rotates the motor and bit. The assembly is directed or “steered” from a drill path in any number of directions, allowing the operator to guide the wellbore to desired underground locations. For example, to recover an underground hydrocarbon deposit, the operator may drill a vertical well to a point above the reservoir and then steer the wellbore to drill a deflected or “directional” well that penetrates the deposit. The well may pass through the deposit at a non-vertical angle, e.g. horizontally.

Azimuthal imaging is used to map sides of wellbores. In the past, this was used in vertical wellbores using wireline approaches. Data collected from the wellbore was referenced to north, hence the phrase “azimuthal imaging,” and the data was obtained after drilling was done. In the geosteering, directional drilling approaches today, reference is no longer to north in non-vertical drill paths but to “up,”—the side of the wellbore closest to the surface. However, these tools are still referred to as azimuthal measurement tools. Further, these tools may now be used in “logging while drilling” (LWD) scenarios to collect wellbore and formation characteristics during the drilling process.

An example of an azimuthal tool used in LWD scenarios is a gamma ray detector. Such detectors typically use Geiger-Müller tubes or scintillation detectors located on the bottom hole assembly (BHA). In rotational drilling scenarios, as the drill string (and thus the BHA with the detectors located symmetrically around the BHA) is rotated, the detectors read incoming radiation and bin them into some number of selected sectors (e.g., according to a radial plot). However, in slide drilling scenarios for directional drilling, the drill string does not rotate all the time that this type of drilling occurs. As a result, the detectors remain in a fixed position relative to the borehole and thus cannot cover all the bins of the radial plot corresponding to the circumference of the borehole. Because of this, data is not collected from all bins during slide drilling and the image at these times (constructed from the data) is lost, unavailable during slide drilling (non-rotating sections) of the wellbore.

The present disclosure is directed to systems, devices, and methods that overcome one or more of the shortcomings of the prior art.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic of an apparatus shown as an exemplary drilling rig according to one or more aspects of the present disclosure.

FIG. 2 is a block diagram of an apparatus shown as an exemplary control system according to one or more aspects of the present disclosure.

FIG. 3A is a diagram illustrating an exemplary bottom hole assembly apparatus according to one or more aspects of the present disclosure.

FIG. 3B is a diagram illustrating a cross section of an exemplary bottom hole assembly apparatus according to one or more aspects of the present disclosure.

FIG. 4A is a diagram illustrating an exemplary radial plot according to one or more aspects of the present disclosure.

FIG. 4B is a diagram illustrating an exemplary radial plot overlaid on a cross section of an exemplary bottom hole assembly apparatus according to one or more aspects of the present disclosure.

FIG. 5A is a diagram illustrating an exemplary radial plot according to aspects of the present disclosure.

FIG. 5B is a diagram illustrating an exemplary radial plot according to aspects of the present disclosure.

FIG. 5C is a diagram illustrating an exemplary radial plot according to aspects of the present disclosure.

FIG. 6 is a flow chart showing an exemplary process for binning azimuthal measurement data while slide drilling according to aspects of the present disclosure.

FIG. 7 is a flow chart showing an exemplary process for controlling drilling based on slide drilling azimuthal measurement data according to aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

Embodiments of the present disclosure include a drilling rig apparatus for improving slide drilling control by enabling use of azimuthal measurements while slide drilling to characterize and direct geosteering control.

In some examples, a bottom hole assembly (BHA) includes a BHA controller that receives sensor data from multiple sensors, including from RPM sensors and azimuthal measurement sensors, such as multiple gamma ray sensors spaced evenly around the circumference of the BHA. The BHA controller tracks the rotations detected from the RPM sensors while the drilling rig apparatus is engaged in rotary drilling (e.g., a vertical (or straight) drilling mode). This may correspond to a vertical binning mode, where as the gamma ray sensors rotate around on the BHA, the data collected therefrom is collected into logical bins of a logical radial plot of the wellbore.

As the drilling rig apparatus transitions to begin slide drilling, the BHA controller detects the dip of the RPM to below a threshold and transitions the BHA controller to a horizontal binning mode. This horizontal binning mode corresponds to slide drilling (and, therefore, “horizontal” may refer to any angular orientation that is offset from vertical while slide drilling) where the BHA does not rotate anymore. In order to be able to continue using the gamma ray sensors to collect data and characterize the wellbore while slide drilling, according to embodiments of the present disclosure the BHA controller notes what sector the gamma ray sensors stop at (i.e., in a two-sensor system spaced 180° apart) when rotation stops.

As the gamma ray sensors continue collecting data, the BHA controller notes the hemisphere (in the two-sensor example for ease of discussion) in which the data is collected. In that hemisphere, the data is associated with the peak bins (i.e., top-most for the upper hemisphere and bottom-most bins for the lower hemisphere) of the hemisphere. This is the case regardless of which bin or bins the azimuthal data was actually collected in. The BHA controller does this with the sensors in each hemisphere. With the resulting count data, the BHA controller estimates one or more intermediate bin values for one or more bins falling between the top and bottom bins of the radial plot. For example, the BHA controller may estimate left and right values and transmit up/down/left/right values to the surface. As another example, the BHA controller may estimate all the bins in between (e.g., where there are a total of 8 bins or 16 bins, all the bins that did not have the measurement data associated therewith).

The data, both measured and estimated, is transmitted to a surface controller of the drilling rig apparatus. A flag may also be asserted and associated therewith, identifying the data collected/estimated during slide drilling. This may occur in real time or after the drilling has completed. An image log is generated therefrom that is now able to include image data for the times that the wellbore is engaged in slide drilling. In real-time scenarios, this may be used to steer the BHA while drilling is occurring to improve the accuracy and location of the wellbore. In after-the-fact scenarios, this may be used to aid in re-geosteering efforts or in general formation characterization, to name a few examples.

Accordingly, embodiments of the present disclosure provide improvements to wellbore and formation characterization by enabling the image log to continue to produce relevant data, even during slide drilling portions of drilling. This, in turn, may improve the drilling rig apparatus' ability to remain within a pay zone and otherwise steer toward or away from given formations or zones. Thus, production may also be improved as existing faults/fractures may be identified and used when determining where and how to induce fractures in the formations, and to better assure equal hardness of the rocks when fracking in different locations. Generally, then, the efficiency of the drilling as well as subsequent production may be improved.

FIG. 1 is a schematic of a side view of an exemplary drilling rig 100 according to one or more aspects of the present disclosure. In some examples, the drilling rig 100 may form a part of a land-based, mobile drilling rig. However, one or more aspects of the present disclosure are applicable or readily adaptable to any type of drilling rig with supporting drilling elements, for example, the rig may include any of jack-up rigs, semisubmersibles, drill ships, coil tubing rigs, well service rigs adapted for drilling and/or re-entry operations, and casing drilling rigs, among others within the scope of the present disclosure.

The drilling rig 100 includes a mast 105 supporting lifting gear above a rig floor 110. The lifting gear may include a crown block 115 and a traveling block 120. The crown block 115 is coupled at or near the top of the mast 105, and the traveling block 120 hangs from the crown block 115 by a drilling line 125. One end of the drilling line 125 extends from the lifting gear to axial drive 130. In some implementations, axial drive 130 is a drawworks, which is configured to reel out and reel in the drilling line 125 to cause the traveling block 120 to be lowered and raised relative to the rig floor 110. The other end of the drilling line 125, known as a dead line anchor, is anchored to a fixed position, possibly near the axial drive 130 or elsewhere on the rig. Other types of hoisting/lowering mechanisms may be used as axial drive 130 (e.g., rack and pinion traveling blocks as just one example), though in the following reference will be made to axial drive 130 (also referred to simply as a drawworks herein) for ease of illustration.

A hook 135 is attached to the bottom of the traveling block 120. A drill string rotary device 140, of which a top drive is an example, is suspended from the hook 135. Reference will be made herein simply to top drive 140 for simplicity of discussion. A quill 145 extending from the top drive 140 is attached to a saver sub 150 configured according to embodiments of the present disclosure, which is attached to a drill string 155 suspended within a wellbore 160. The term “quill” as used herein is not limited to a component which directly extends from the top drive 140, or which is otherwise conventionally referred to as a quill. For example, within the scope of the present disclosure, the “quill” may additionally or alternatively include a main shaft, a drive shaft, an output shaft, and/or another component which transfers torque, position, and/or rotation from the top drive or other rotary driving element to the drill string, at least indirectly. Nonetheless, for the sake of clarity and conciseness, these components may be collectively referred to herein as the “quill.” It should be understood that other techniques for arranging a rig may not require a drilling line, and are included in the scope of this disclosure.

The drill string 155 includes interconnected sections of drill pipe 165, a BHA 170, and a drill bit 175 for drilling at bottom 173 of the wellbore 160. The BHA 170 may include a BHA controller 174 (e.g., coupled to or integrated therewith) as well as stabilizers, drill collars, and/or measurement-while-drilling (MWD), LWD, and/or wireline conveyed instruments, among other components. The drill bit 175 is connected to the bottom of the BHA 170 or is otherwise attached to the drill string 155. In the exemplary embodiment depicted in FIG. 1, the top drive 140 is utilized to impart rotary motion to the drill string 155. However, aspects of the present disclosure are also applicable or readily adaptable to implementations utilizing other drive systems, such as a power swivel, a rotary table, a coiled tubing unit, a downhole motor, and/or a conventional rotary rig, among others.

A mud pump system 180 receives the drilling fluid, or mud, from a mud tank assembly 185 and delivers the mud to the drill string 155 through a hose or other conduit 190, which may be fluidically and/or actually connected to the top drive 140. In some implementations, the mud may have a density of at least 9 pounds per gallon. As more mud is pushed through the drill string 155, the mud flows through the drill bit 175 and fills the annulus 167 that is formed between the drill string 155 and the inside of the wellbore 160, and is pushed to the surface. At the surface the mud tank assembly 185 recovers the mud from the annulus 167 via a conduit 187 and separates out the cuttings. The mud tank assembly 185 may include a boiler, a mud mixer, a mud elevator, and mud storage tanks. After cleaning the mud, the mud is transferred from the mud tank assembly 185 to the mud pump system 180 via a conduit 189 or plurality of conduits 189. When the circulation of the mud is no longer needed, the mud pump system 180 may be removed from the drill site and transferred to another drill site.

The drilling rig 100 also includes a control system 195 configured to control or assist in the control of one or more components of the drilling rig 100. For example, the control system 195 may be configured to transmit operational control signals to the drawworks 130, the top drive 140, the BHA 170 (e.g., the BHA controller 174) and/or the mud pump system 180. The control system 195 may be a stand-alone component installed somewhere on or near the drilling rig 100, e.g. near the mast 105 and/or other components of the drilling rig 100, or on the rig floor to name just a few examples. In some embodiments, the control system 195 is physically displaced at a location separate and apart from the drilling rig, such as in a trailer in communication with the rest of the drilling rig. As used herein, terms such as “drilling rig” or “drilling rig apparatus” may include the control system 195 whether located at or remote from the drilling rig 100.

According to embodiments of the present disclosure, the BHA controller 174 at the BHA 170 may include an interface to receive measurement data from one or more sensors e.g. that are configured to detect parameters relating to the drilling environment, the BHA 170 condition and orientation, and other information. For example, the BHA controller 174 may receive measurement data from multiple azimuthal measurement sensors, such as gamma ray detectors. The BAH controller 174 may also monitor rotation sensor data to determine whether the drilling rig 100 has transitioned from rotational drilling, also referred to herein as a vertical binning mode, to slide drilling, also referred to herein as a horizontal binning mode (though “horizontal” may simply refer to any angular orientation offset from vertical at which slide drilling begins).

When the BHA controller 174 determines that the drilling rig 100 has transitioned to a horizontal binning mode with slide drilling, the BHA controller 174 notes the last location that the azimuthal measurement sensors were in when rotation drilling stopped. Using a two-sensor example for ease and simplicity of illustration, the BHA controller 174 compares these locations to the upper and lower hemispheres of a radial plot (i.e., with the sides of the BHA 170 referenced to “up,” the top of the wellbore). Instead of binning the sensor data from these sensors in the bins that they currently reside in (within the radial plot), the BHA controller 174 approximates the measurements by assigning them to the uppermost bins of the upper hemisphere (for the sensor that was determined to lie within the upper hemisphere, ranging from 270° on the left of the radial plot to 90° on the right). Similarly, the BHA controller 174 approximates the measurements from the sensor determined to lie within the lower hemisphere (from 90° to 270°). Thus, for measurements from that sensor, the BHA controller 174 approximates them by assigning them to the lower-most bins of the lower hemisphere.

The BHA controller 174 counts the measurements from these two hemispheres and periodically uses these values to estimate count values for the intervening bins between the uppermost and lower-most bins. This may take the form of finding an average step value for each bin from the uppermost to the lower-most, which value is applied at each bin-step between the two. The BHA controller 174 may transmit these values to the surface, such as to the control system 195, for further processing, analysis, and use in steering the direction of the BHA 170 and to better understand the formations through which the BHA 170 is traversing. The values may reach the surface as real-time measurements or downloaded after-the-fact from the storage of BHA 170.

According to embodiments of the present disclosure, the control system 195 may include, among other things, an interface configured to display image logs and other borehole and/or formation characteristic data, as well as to potentially receive driller input during directional drilling to guide the wellbore in the target zones/formations. The control system 195 receives data used to produce the image logs and present the other formation characteristic data from the BHA controller 174.

Turning to FIG. 2, a block diagram of an exemplary control system configuration 200 according to one or more aspects of the present disclosure is illustrated. In some implementations, the control system configuration 200 may be described with respect to the drawworks 130, top drive 140, BHA 170, and control system 195. The control system configuration 200 may be implemented within the environment and/or the apparatus shown in FIG. 1.

The control system configuration 200 may include the BHA controller 174 at the BHA 170 as introduced in FIG. 1, a drawworks controller 255 at the drawworks 130, a controller 295 at the top drive system 140, and the control system 195. The control system 195 may include a controller 210 and may also include an interface system 224. Depending on the embodiment, these may be discrete components that are interconnected via wired and/or wireless means. In some embodiments, the interface system 224 and the controller 210 may be integral components of a single system that is in communication with the other controllers, including, for example, at least one or more of the BHA controller 174, the drawworks controller 255, and the controller 295.

The BHA controller 174 may include at least a memory 237, a processor 239, and a binning module 238. The memory 237 may include a cache memory (e.g., a cache memory of the processor), random access memory (RAM), magnetoresistive RAM (MRAM), read-only memory (ROM), programmable read-only memory (PROM), erasable programmable read only memory (EPROM), electrically erasable programmable read only memory (EEPROM), flash memory, solid state memory device, hard disk drives, other forms of volatile and non-volatile memory, or a combination of different types of memory. In some embodiments, the memory 237 may include a non-transitory computer-readable medium.

The memory 237 may store instructions. The instructions may include instructions that, when executed by the processor 239, cause the processor 239 to perform operations described herein with reference to the BHA controller 174 in connection with embodiments of the present disclosure. The terms “instructions” and “code” may include any type of computer-readable statement(s). For example, the terms “instructions” and “code” may refer to one or more programs, routines, sub-routines, functions, procedures, etc. “Instructions” and “code” may include a single computer-readable statement or many computer-readable statements.

The processor 239 may have various features as a specific-type processor. For example, these may include a central processing unit (CPU), a digital signal processor (DSP), an application-specific integrated circuit (ASIC), a controller, a field programmable gate array (FPGA) device, another hardware device, a firmware device, or any combination thereof configured to perform the operations described herein with reference to the BHA controller 174 of the BHA 170 introduced in FIG. 1 above. The processor 239 may also be implemented as a combination of computing devices, e.g., a combination of a DSP and a microprocessor, a plurality of microprocessors, one or more microprocessors in conjunction with a DSP core, or any other such configuration.

In addition to the BHA controller 174, the BHA 170 may include one or more sensors, typically a plurality of sensors, located and configured about the BHA 170 to detect parameters relating to the drilling environment, the BHA 170 condition and orientation, and other information. The BHA 170 may include additional sensors/components beyond those illustrated in FIG. 2, which is simplified for purposes of illustration. The sensors/components may provide information that may be considered by the BHA controller 174 and/or the control system 195, for example downhole WOB, downhole TOB, downhole AP, BHA rotations per minute (RPM), azimuthal measurement data, and/or other data.

In the embodiment shown in FIG. 2, the BHA 170 includes MWD sensors 230. For example, the MWD sensor 230 may include an MWD shock/vibration sensor that is configured to detect shock and/or vibration in the MWD portion of the BHA 170, and an MWD torque sensor that is configured to detect a value or range of values for torque applied to the bit by the motor(s) of the BHA 170 (referred to generally herein as downhole TOB). The MWD sensors 230 may also include an MWD RPM sensor that is configured to detect the RPM of the bit of the BHA 170. The MWD sensors 230 may also include a downhole mud motor AP (differential pressure) sensor 232 (referred to simply herein as a downhole AP sensor 232) that is configured to detect a pressure differential value or range across the mud motor of the BHA 170. This may be a value in reference to the pressure just off-bottom and pressure once the bit touches bottom and starts drilling and experiencing torque. The data from these sensors may be sent via electronic signal or other signal to the BHA controller 174 and/or control system 195 as well via wired and/or wireless transmission.

The BHA 170 may also include a BHA RPM sensor, such as part of the MWD sensors 230. This sensor may detect the RPM of the BHA 170 itself, instead of the bit specifically as the other sensor introduced above. The data from the BHA RPM sensor may be sent via electronic signal or other signal to the BHA controller 174 and/or control system 195 as well via wired and/or wireless transmission.

The BHA 170 may also include one or more toolface sensors 240, such as a magnetic toolface sensor and a gravity toolface sensor that are cooperatively configured to detect the current toolface orientation, such as relative to magnetic north. The gravity toolface may detect toolface orientation relative to the Earth's gravitational field. In an exemplary embodiment, the magnetic toolface sensor may detect the current toolface when the end of the wellbore is less than about 7° from vertical, and the gravity toolface sensor may detect the current toolface when the end of the wellbore is greater than about 7° from vertical.

The BHA 170 may also include an MWD weight on bit/torque on bit sensor 242 (referred to simply herein as a downhole WOB/TOB sensor 242) that is configured to detect a value or range of values for downhole WOB and TOB at or near the BHA 170. The data from the downhole WOB/TOB sensor 242 may be sent via electronic signal or other signal to the BHA controller 174 and/or control system 195 via wired and/or wireless transmission.

The BHA 170 may also include logging while drilling (LWD) sensors 245. In addition to the multiple sensors described above with respect to MWD tools, the LWD sensors 245 may include sensors such as azimuthal measurement sensors, neutron porosity sensors, resistivity sensors, sonic sensors, image sensors, magnetic resonance sensors, seismic sensors, etc. An example azimuthal measurement sensor is a gamma ray sensor (e.g., a Geiger-Müller tube, a scintillation detect, etc.), which may be configured to read incoming gamma radiation. For example, these sensors may count the radiation as it is received and report that count periodically or in stream to the BHA controller 174.

At the BHA controller 174, the counts from the gamma ray sensors may be tallied. In particular, in the horizontal binning mode the counts from the gamma ray sensors will be all occurring generally in the same bins at which the gamma ray sensors stopped (in terms of radial direction of the BHA 170 when rotary drilling stops in favor of slide drilling). Using again an example with a total of two gamma ray sensors spaced apart about the BHA 170, such as by 180° (see, e.g., FIG. 3B), the positions of these sensors may be noted at the time of transition to slide drilling. At the BHA controller 174, the BHA controller 174 assigns the counts from the gamma ray sensor falling with in the upper hemisphere as occurring at the top bins of the radial plot (instead, where applicable, to the bins associated with the actual locations of the gamma ray sensors). Likewise, the BHA controller 174 assigns the counts from the gamma ray sensor falling within the lower hemisphere as occurring at the bottom bins of the radial plot.

Although discussed with respect to two gamma ray sensors, it will be recognized that embodiments of the present disclosure may be implemented in systems with any number of gamma ray sensors (or any other azimuthal measurement sensors used in slide drilling operations). The assumptions may change depending on the number of sensors deployed. In embodiments where four gamma ray sensors are deployed, e.g. spaced apart by 90° around the circumference of the BHA 170, the assumptions may be applied with respect to quadrants instead of hemispheres of a radial plot, such as ranging from 315° to 45° as an upper quadrant, 45° to 135° for a right quadrant, 135° to 225° as a lower quadrant, and 225° to 315° as a left quadrant (again, with “upper” referring to the top of the borehole).

Other number of gamma ray sensors may likewise be handled with corresponding changes in approximation areas, wherever the area actually being measured by the sensors is smaller than the area trying to be filled by sensor data. The discussion herein will describe the two-sensor scenario for ease of reference and illustration, though embodiments of the present disclosure are not limited thereto.

For example, the binning module 238 may receive the counts as they arrive from the gamma ray sensors, or alternatively as interim totals after having been buffered briefly by the gamma ray sensors themselves.

The binning module 238 may include various hardware components and/or software components to implement the aspects of the present disclosure. For example, in some implementations the binning module 238 may include instructions stored in the memory 237 that causes the processor 239 to perform the operations described herein. In an alternative embodiment, the binning module 238 is a hardware module that interacts with the other components of the BHA controller 174 to perform the operations described herein.

The binning module 238 is used to assign counts to the top and bottom of the respective hemispheres, regardless of which bins in the radial plot the counts actually originated (aside from the general hemisphere). Further, the binning module 238 may be used to estimate intermediate bin values for those bins falling between the uppermost bins in the upper hemisphere to the lower-most bins in the lower hemisphere of the radial plot. The bin values thus assumed and estimated may be transmitted to the controller 210 at the surface for subsequent implementation as introduced above and discussed further below. The values may be transmitted per bin, i.e. 16 values in 16-bin implementations, or 8 values in 8-bin implementations, or 4 values in 4-bin implementations (also referred to as up/down/left/right implementations), etc. Other values may alternatively be used for the number of bins into which the radial plot is broken down.

For example, the binning module 238 may receive the count measurements that have been maintained in the buffer in the memory 237 (or in a buffer of the gamma ray sensors) over a prior period of time. The binning module 238 assigns the counts to the upper and lower bins, respectively, for the sensors situated in the upper and lower hemispheres during slide drilling. In some implementations, the binning module 238 further estimates the bin values for those bins falling between the upper and lower bins. For example, where the radial plot is subdivided into a total of 16 bins, the binning module 238 may estimate the intervening bin values by taking a difference from the value of the upper bin and the value of the lower bin, and dividing that resulting difference by the 6 bins therebetween (in the 16-bin example). The resulting value may be applied to each bin between the two ends—e.g., subtracted from the next-highest value when the upper bin has a higher count value than the lower bin, or added from the next lowest value when the upper bin has a lower count value than the upper bin (the adding or subtracting may be to the upper or lower values, though this example starts from the top bin and continues down).

The binning module 238 may estimate the intervening bin values, and/or sector (i.e., a number bins whose values are averaged together) for all the bins or sectors in the radial plot. For example, even though there may be 16 bins in the radial plot, the binning module 238 may take the individual estimated bin values and determine an average value for a select number of bins, e.g. in the 16-bin scenario the four bins that constitute the “right” quadrant of the radial plot, the four bins that constitute the “left” quadrant of the radial plot, the four bins that constitute the “up” quadrant of the radial plot, and the four bins that constitute the “down” quadrant of the radial plot. This may be done in embodiments where the transmission bandwidth of the data to the surface control system 195 is sought to be reduced, while in other embodiments all bin values may be transmitted in their own right.

For example, the transmission may occur via telemetry, mud pulse, EM, wired pipe, or other types of connections including for example local area network (LAN), wide area network (WAN), etc. These may be transmitted in real time as they are received/calculated. In other examples, these values may be stored, such as in memory 237, for later use such as after the BHA 170 has been tripped out of the wellbore 160. At the surface, the control system 195 may receive the data transmitted from the downhole components, including from the BHA controller 174 and, in some embodiments, one or more of the downhole sensors as well. The controller 210 of the control system 195 may use this data as discussed further herein.

The controller 210 includes a memory 212, a processor 214, a transceiver 216, and a control module 218. The memory 212 may include a cache memory (e.g., a cache memory of the processor 214), random access memory (RAM), magnetoresistive RAM (MRAM), read-only memory (ROM), programmable read-only memory (PROM), erasable programmable read only memory (EPROM), electrically erasable programmable read only memory (EEPROM), flash memory, solid state memory device, hard disk drives, other forms of volatile and non-volatile memory, or a combination of different types of memory. In some embodiments, the memory 212 may include a non-transitory computer-readable medium. The memory 212 may store instructions. The instructions may include instructions that, when executed by the processor 214, cause the processor 214 to perform operations described herein with reference to the controller 210 in connection with embodiments of the present disclosure.

The processor 214 may have various features as a specific-type processor. For example, these may include a central processing unit (CPU), a digital signal processor (DSP), an application-specific integrated circuit (ASIC), a controller, a field programmable gate array (FPGA) device, another hardware device, a firmware device, or any combination thereof configured to perform the operations described herein with reference to the aspects introduced in FIG. 1 above. The processor 214 may also be implemented as a combination of computing devices, e.g., a combination of a DSP and a microprocessor, a plurality of microprocessors, one or more microprocessors in conjunction with a DSP core, or any other such configuration.

The transceiver 216 may include a LAN, WAN, Internet, satellite-link, and/or radio interface to communicate bi-directionally with other devices, such as the top drive 140, drawworks 130, BHA 170, and other networked elements. For example, the transceiver 216 may include multiple ports corresponding to the different connections/access technologies used to communicate between components and locations (e.g., different ports for communication connections, as well as with different sensors that provide inputs into the controller 210 for control, etc.).

The control system 195 may also include an interface system 224. The interface system 224 includes a display 220 and a user interface 222. The interface system 224 may also include a memory and a processor as described above with respect to controller 210. In some implementations, the interface system 224 is separate from the controller 210, while in other implementations the interface system 224 is part of the controller 210. Further, the interface system 224 may include a user interface 222 with a simplified display 220 or, in some embodiments, not include the display 220.

The display 220 may be used for visually presenting information to the user in textual, graphic, or video form. The display 220 may also be utilized by the user to input drilling parameters, limits, or set point data in conjunction with the input mechanism of the user interface 222, such as a set point for a desired differential pressure, weight on bit, torque on bit, rate of penetration, etc., as well as for purposes of geosteering and formation characterization/analysis according to embodiments of the present disclosure. For example, the input mechanism may be integral to or otherwise communicably coupled with the display 220. The input mechanism of the user interface 222 may also be used to input additional settings or parameters.

The input mechanism of the user interface 222 may include a keypad, voice-recognition apparatus, dial, button, switch, slide selector, toggle, joystick, mouse, data base and/or other conventional or future-developed data input device. Such a user interface 222 may support data input from local and/or remote locations. Alternatively, or additionally, the user interface 222 may permit user-selection of predetermined profiles, algorithms, set point values or ranges, and well plan profiles/data, such as via one or more drop-down menus. The data may also or alternatively be selected by the controller 210 via the execution of one or more database look-up procedures. In general, the user interface 222 and/or other components within the scope of the present disclosure support operation and/or monitoring from stations on the rig site as well as one or more remote locations with a communications link to the system, network, LAN, WAN, Internet, satellite-link, and/or radio, among other means.

According to embodiments of the present disclosure, the control system 195 may receive the count values (actual and estimated) from the BHA 170 via telemetry in real time. This data may be analyzed, for example to generate one or more image logs, and presented to one or more users such as via the display 220 or other user interface. The user interface 222 may receive one or more commands from a user to dynamically (i.e., during drilling) geosteer the BHA 170 based on the data, such as to remain within a pay zone/formation, leave a formation, etc. The controller 210 may transmit commands, to geosteer the BHA 170, to the BHA 170 as slide drilling is occurring.

In other examples, the control system 195 may receive the data from the BHA 170 after the BHA 170 has been tripped out of the wellbore 160 and downloaded in aggregate from the memory 237. In these embodiments, the data may still be used to generate image logs that one or more users may use to determine other actions, such as generating a density image for use in determine whether and how to re-geosteer the well, formation characterization such as to identify existing faults and fractures to avoid water contamination, etc.

Turning to the top drive 140 components, the top drive 140 includes one or more sensors or detectors. The top drive 140 includes a rotary torque sensor 265 (also referred to herein as a torque sensor 265) that is configured to detect a value or range of the reactive torsion of the quill 145 or drill string 155. For example, the torque sensor 265 may be a torque sub physically located between the top drive 140 and the drill string 155. As another example, the torque sensor 265 may additionally or alternative be configured to detect a value or range of torque output by the top drive 140 (or commanded to be output by the top drive 140), and derive the torque at the drill string 155 based on that measurement. Detected voltage and/or current may be used to derive the torque at the interface of the drill string 155 and the top drive 140. The controller 295 is used to control the rotational position, speed and direction of the quill 145 or other drill string component coupled to the top drive 140 (such as the quill 145 shown in FIG. 1), shown in FIG. 2. The torque data may be sent via electronic signal or other signal to the controller 210 via wired and/or wireless transmission (e.g., to the transceiver 216).

The top drive 140 may also include a quill position sensor 270 that is configured to detect a value or range of the rotational position of the quill, such as relative to true north or another stationary reference. The top drive 140 may also include a hook load sensor 275 (e.g., that detects the load on the hook 135 as it suspends the top drive 140 and the drill string 155) and a rotary RPM sensor 290. The rotary RPM sensor 290 is configured to detect the rotary RPM of the drill string 155. This may be measured at the top drive or elsewhere, such as at surface portion of the drill string 155 (e.g., reading an encoder on the motor of the top drive 140). These signals, including the RPM detected by the RPM sensor 290, may be sent via electronic signal or other signal to the controller 210 via wired and/or wireless transmission.

The drive system represented by top drive 140 also includes a surface pump pressure sensor or gauge 280 (e.g., that detects the pressure of the pump providing mud or otherwise powering the down-hole motor in the BHA 170 from the surface), referred to as a surface differential pressure (AP) sensor 280. The surface AP sensor 280 is configured to detect a pressure differential value between the surface standpipe pressure while the BHA 170 is just off-bottom from bottom 173 and surface standpipe pressure once the bit of BHA 170 touches bottom 173 and starts drilling and experiencing torque (and generating cuttings). Typically, the surface AP detected by the surface AP sensor 280 represents how much pressure the mud motor at the BHA 170 is generating in the system, which is a function of mud motor torque. The drive system represented by top drive 140 may also include an MSE sensor 285. The MSE sensor 285 may detect the MSE representing the amount of energy required per unit volume of drilled rock to remove it, whether directly sensed or calculated based on sensed data.

The drawworks 130 may include one or more sensors or detectors that provide information to the controller 210. The drawworks 130 may include an RPM sensor 250. The RPM sensor 250 is configured to detect the rotary RPM of the drilling line 125, which corresponds to the speed of hoisting/lowering of the drill string 155. This may be measured at the drawworks 130. The RPM detected by the RPM sensor 250 may be sent via electronic signal or other signal to the controller 210 via wired or wireless transmission. The drawworks 130 may also include a controller 255. The controller 255 is used to control the speed at which the drill string 155 is hoisted or lowered, for example as dictated by the control system 195.

Returning to the controller 210, the control module 218 may be used for various aspects of the present disclosure. The control module 218 may include various hardware components and/or software components to implement the aspects of the present disclosure. For example, in some implementations the control module 218 may include instructions stored in the memory 212 that causes the processor 214 to perform the operations described herein. In an alternative embodiment, the control module 218 is a hardware module that interacts with the other components of the controller 210 to perform the operations described herein.

The control module 218 may be used to access the count data (detected and estimated) from the BHA 170, either in real time or after-the-fact. The control module 218 may further generate the image logs and other logs from the data, and receive the inputs from one or more users that is converted to commands for the other components of the system (including the top drive 140 and BHA 170) to geosteer during drilling.

FIG. 3A is a diagram illustrating a side view of an exemplary bottom hole assembly apparatus according to one or more aspects of the present disclosure. Specifically, the apparatus illustrated in FIG. 3A may be an example of the BHA 170 introduced in FIG. 1 and discussed further with respect to FIG. 2.

The BHA 170 has an outer surface 304. The BHA 170 also has a proximal end 306 extending in a proximal direction 307 and a distal end 308 extending in a distal direction 309. The proximal end 306 is the end of the BHA 170 closer along the drill string 155 to the top drive 140, while the distal end 308 is the end of the BHA 170 closer along the drill string to the drill bit 302 (further from the top drive 140).

As illustrated, the BHA 170 includes the downhole AP sensor 232 toward the distal end 308. Further, the BHA 170 includes the BHA controller 174, located in this illustration toward the proximal end 306. The BHA 170 also includes toolface sensors 240 (such as inclination sensors), WOB/TOB sensors 242, and LWD sensors 245 (e.g., azimuthal gamma ray sensors, etc.). Although illustrated in the general locations shown, the locations of the different elements of the BHA 170 may be situated in other general locations of the BHA 170 according to embodiments of the present disclosure. A cross section 310 is illustrated in FIG. 3A in the general location where the LWD sensors 245, and particularly where the gamma ray sensors, are located.

Cross section 310 is illustrated in FIG. 3B according to one or more aspects of the present disclosure. As illustrated, the cross section 310 shows the outer surface 304 of the BHA 170, that is for example in contact with drilling fluid in the annulus 167. Further, the BHA 170 includes the center fluid passage 316 of the BHA 170, through which the drilling mud flows to the bit 302.

Also shown are two gamma ray sensors 312 and 314 as examples of LWD sensors 245. As can be seen, two gamma ray sensors 312, 314 are located on sides of the BHA 170, spaced 180° apart from each other at opposing sides of the BHA 170. As noted above, any number of gamma ray sensors may be used, e.g. situated at equal distances apart along the circumference of the BHA 170, but two are used in the examples herein for ease of illustration.

In a vertical binning mode, the gamma ray sensors 312, 314 rotate along the full 360° of a radial plot, passing through all of the bins into which a radial plot has been divided. However, as noted above, when a horizontal binning mode, slide drilling, occurs, the gamma ray sensors 312, 314 stop rotating through the different sectors because the BHA 170 generally stops rotating. Embodiments of the present disclosure enable data to still be obtained and used for geosteering and other purposes.

An example of a radial plot is illustrated in FIG. 4A, according to one or more aspects of the present disclosure. The radial plot 400 in FIG. 4A is broken down into 16 bins of equal size (here, 22.5° per bin). Thus, with numbering of the bins starting at 0, bin 0 (illustrated as bin 402 of FIG. 4A) extends from 0° to 22.5°, bin 1 extends from 22.5° to 45°, bin 2 extends from 45° to 67.5°, and bin 3 (also referred to as bin 404 of FIG. 4A) extends from 67.5° to 90°. Further, bin 4 (also referred to as bin 406 of FIG. 4A) extends from 90° to 112.5°, bin 5 extends from 112.5° to 135°, bin 6 extends from 135° to 157.5°, and bin 7 (also referred to as bin 408 of FIG. 4A) extends from 157.5° to 180°. Bin 8 (also referred to as bin 410 of FIG. 4A) extends from 180° to 202.5°, bin 9 extends from 202.5° to 225°, bin 10 extends from 225° to 247.5°, and bin 11 (also referred to as bin 412 of FIG. 4A) extends from 247.5° to 270°. Bin 12 (also referred to as bin 414 of FIG. 4A) extends from 270° to 292.5°, bin 13 extends from 292.5° to 315°, bin 14 extends from 315° to 337.5°, and bin 15 (also referred to as bin 416 of FIG. 4A) extends from 337.5° to 360°.

Looking at the radial plot 400 in a clockwise fashion, according to embodiments of the present disclosure with two gamma ray detectors 312, 314 as an illustrative example, the upper hemisphere 418 includes bins ranging from bin 414 to bin 404 (bins 0-3 and 12-15). Further, the lower hemisphere 420 includes bins ranging from bin 406 to bin 412 (bins 4-11). As illustrated, the top 422 of the upper hemisphere 418 includes bins 416 and 402, while the bottom 424 of the lower hemisphere 420 includes bins 408 and 410.

Turning now to FIG. 4B, a diagram illustrating an exemplary radial plot overlaid on a cross section of an exemplary bottom hole assembly apparatus according to one or more aspects of the present disclosure. In particular, FIG. 4B illustrates the radial plot 400 overlaid on the cross section 310 of the BHA 170 from FIG. 3B.

In the illustrated example the gamma ray sensor 312 has stopped (e.g., for slide drilling purposes once the rotation of the drill string 155 falls below a threshold or stops) in the upper hemisphere 418, stopping in particular between the bins 14 and 15 (with a little overlap into bin 13 as well). Typically, counts would accrue to the bins through which the gamma ray sensor 312 passes during rotation, but when the rotation slows and/or stops, the gamma ray sensor 312 stops passing through all of the bins 0-15. Thus, according to embodiments of the present disclosure, the BHA controller 174 receives the counts from the gamma ray sensor 312 and attributes them to the bins at the top 422 of the radial plot 400, here bins 416 and 402.

Further, in this example gamma ray sensor 314 has stopped in the lower hemisphere 420, stopping in particular between the bins 6 and 7 (with a little overlap into bin 5 as well). Again, according to embodiments of the present disclosure, the BHA controller 174 (when slide drilling) receives the counts from the gamma ray module 314 and attributes them to the bins at the bottom 424 of the radial plot 400, here bins 408 and 410.

This is illustrated in the radial plot 500 of FIG. 5A. As shown, when counts from a gamma ray sensor (e.g., gamma ray sensor 312 from FIGS. 3B and 4B) are received while in the upper hemisphere 418 during slide drilling, they are attributed as count 502 for the upper bins 416 and 402. This occurs via the BHA controller 174, regardless of what bins in the upper hemisphere 418 the counts were actually attributable to. Likewise, when counts from a gamma ray sensor (e.g., gamma ray sensor 314 from FIGS. 3B and 4B) are received while in the lower hemisphere 420 during slide drilling, they are attributed as count 514 for the lower bins 408, 410.

As noted above, this describes the exemplary embodiment where two gamma ray sensors are used. As another example, four gamma ray sensors may be used with the radial plot 520 of FIG. 5B being split into quadrants instead of hemispheres (e.g., ranging from 315° to 45° as an upper quadrant, 45° to 135° for a right quadrant, 135° to 225° as a lower quadrant, and 225° to 315° as a left quadrant (again, with “upper” referring to the top of the borehole).

In the example of FIG. 5B, the counts for a gamma ray sensor that comes to stop in the upper quadrant may be attributed as counts 502 in the upper bins 402, 416. The counts for a gamma ray sensor that comes to stop in the right quadrant may be attributed as counts 508 in the right bins 404, 406. The counts for a gamma ray sensor that comes to stop in the lower quadrant may be attributed as counts 514 in the lower bins 408, 410. Finally, the counts for a gamma ray sensor that comes to stop in the left quadrant may be attributed as counts 516 in the left bins 412, 414.

After the BHA controller 174 attributes the counts to the relevant bins, whether according to the examples of FIGS. 5A, 5B, or some other number of gamma ray sensors and/or bins, the BHA controller 174 proceeds with estimating count values for one or more of the intervening bins between those bins that have had counts attributed to them.

This is illustrated in FIG. 5C, again according to the two-gamma-ray-sensor example for ease of discussion and according to aspects of the present disclosure. After counts from the gamma ray sensor 312 have been attributed as counts 502 at the top 422 of upper hemisphere 418, and the counts from the gamma ray sensor 314 have been attributed as counts 514 at the bottom 424 of the lower hemisphere 420, the BHA controller 174 begins estimating intervening bin values.

For example, to determine the count 508 that is estimated for bins 404 and 406 (as the “right” bins of the radial plot 530), the BHA controller 174 may take a difference between the count 502 and the count 514. For example, for discussion purposes only, if count 502 is at 100 and count 514 is at 25, then the difference value is 75. The BHA controller 174 may divide that value, 75, in half. That half value may be subtracted from the highest value to arrive at the count 508, which represents the intermediate value between the top and bottom bins. Where the value results in some fractional value, it may be rounded to the next whole number, and where the difference value is negative, its absolute value may be taken. Thus, in the example of 100 counts and 25 counts, the difference divided by 2 equals 37.5, or 38 when rounded up. Subtracting 38 from 100 results in a count value of 62 for count 508. The count 508 is thus determined for the right bins 404, 406; in this example with two gamma ray sensors, the same count 508 may be mirrored to the left bins 412, 414 because the same range of estimated values with extend along the left side between the top 422 and bottom 424.

In embodiments where the BHA controller 174 seeks to economize on use of transmission bandwidth to the surface control system 195, this may be the only value computed. Thus, the BHA controller 174 may transmit up/down/left/right values to the surface for creating the image log and for use in geosteering. In this particular example, those values would be 100/25/38/38 (though this is just one example for illustration).

In other embodiments, all bin values may be estimated as well as transmitted to the surface. For all of the counts ranging from count 502 to count 514, the BHA controller 174 may take the difference and calculate an incremental value by dividing by a number of intervening bins. Thus, again using the example of count 502 having a value of 100 and count 514 having a value of 25, with 16 total bins, the difference value 75 may be divided by 7, the number of intervening bins starting after bin 0 and ending with bin 7. This incremental value may be subtracted from each count starting with the bin with the highest count (here, bin 402 with count 502 at 100). This may iterate through each bin to the bottom bin 408. Again, this may be mirrored to the left bins (bin 14 ranging down to bin 9 in FIG. 5C) where two gamma ray sensors are used.

Accordingly, each bin has a value that may be transmitted to the surface, or even where bin values are calculated for each bin, averaged for left and right values which are transmitted to the surface. Thus, the surface controller 210 is able to generate image logs even while slide drilling, and thereby still provide actionable data for users in geosteering and other decisions.

FIG. 6 is a flow chart showing an exemplary process 600 for binning azimuthal measurement data while slide drilling according to aspects of the present disclosure. In some implementations, the method 600 may be performed, for example, by the BHA controller 174 of the BHA 170 discussed above. In other implementations, the method 600 may be performed by a controller located elsewhere including along the drill string 155 or otherwise disposed on (or associated with) the drilling rig apparatus 100. It is understood that additional steps can be provided before, during, and after the steps of method 600, and that some of the steps described can be replaced or eliminated from the method 600.

At block 602, the BHA controller 174 receives measurement values, i.e. counts, detected by the azimuthal measurement sensors (such as a gamma ray sensor) while the system is in a vertical binning mode as the BHA 170 rotates in a wellbore.

At block 604, the BHA controller 174 detects a BHA RPM value from an RPM sensor.

At block 606, the BHA controller 174 compares the BHA RPM value detected at block 604, and compares the BHA RPM value to a threshold RPM value. In some implementations, the threshold RPM value may be preprogrammed or may be preselected to distinguish between rotary and slide drilling operations. In some examples, this threshold RPM value is a first threshold RPM value.

At decision block 608, the BHA controller 174 determines whether the BHA RPM value is below the threshold RPM value (in some embodiments, at or below the threshold RPM value). Different values may be used for the threshold RPM value, for example 3 RPM or less as just one example. If the BHA RPM value is not below the threshold RPM value (or is greater than it), then the method 600 returns to block 602 and proceeds as laid out above and further below. If, instead, the BHA RPM value is below the threshold RPM value (or equal to it, in some embodiments), then the method 600 proceeds to block 610. This coincides with the BHA 170 stopping rotation to engage in slide drilling. In some implementations, an operator may make this determination via an input at the user interface 222.

At block 610, in response to the BHA RPM value falling below the threshold RPM value (or, where applicable, an operator input), the BHA controller 174 transitions to a horizontal binning mode from the vertical binning mode. As noted above, this coincides with a situation where the gamma ray sensors no longer pass through all of the bins assigned to a radial plot because the BHA 170 is no longer rotating.

At block 612, the BHA controller 174 may store the last known bin location(s) (e.g., where the gamma ray sensor is straddling multiple bins) of the gamma ray sensors so that the BHA controller 174 may know which hemispheres (in a binary gamma ray sensor configuration, which is what is discussed here for simplicity of illustration—other number of sensors may be employed according to embodiments of the present disclosure as noted above) the gamma ray sensors are located within during slide drilling in the horizontal binning mode.

At block 614, the BHA controller 174 receives measurement values, i.e. counts, detected by the gamma ray sensors while in the horizontal binning mode. As the values are received, or after a threshold number are received, the BHA controller 174 may proceed in method 600 to decision block 616.

At decision block 616, the BHA controller 174 determines what hemisphere the counts from the gamma ray sensors are located. For example, if a first gamma ray sensor was determined to have stopped in the upper hemisphere at block 612, then the BHA controller 174 identifies measurements from that first sensor to be in the upper hemisphere, and likewise the counts from the second gamma ray sensor to be in the lower hemisphere of a radial plot. Thus, at decision block 616 if the counts are in the upper hemisphere, then the method 600 proceeds to block 618 where the BHA controller 174 assigns the counts to the top-most bins of the upper hemisphere. Using FIG. 5C by way of exemplary reference, the counts are assigned to bins 416 and 402, even if the actual bin(s) was elsewhere in the upper hemisphere 418.

If, instead, it is determined at decision block 616 that the counts were not in the upper hemisphere, but rather determined to be in the lower hemisphere, then the method 600 proceeds from decision block 616 to block 620. At block 620, the BHA controller 174 assigns the counts to the lower-most bins of the lower hemisphere. Again referencing FIG. 5C, the counts are assigned to bins 408 and 410, even if the actual bin(s) was elsewhere in the lower hemisphere 420.

From either of block 618 or 620, the method 600 proceeds to block 622. At block 622, the BHA controller 174 estimates one or more intermediate bin values for the radial plot for the one or more bins between the top-most and lower-most bins of the two hemispheres. As discussed with respect to the other figures above, this may result in estimating two values for the left and right sides of the radial plot, 4 values where there are 8 total bins, or 12 values where there are 16 total bins to name just a few examples.

At block 624, the BHA controller 174 asserts a slide flag for the data assigned to the different bins of a radial plot during slide drilling. This identifies the data sent to the surface controller for image log processing and other tasks as having been estimated/approximated during slide drilling.

At decision block 626, if the BHA controller 174 is transmitting bin data to the surface in real time, then the method 600 proceeds to block 628.

At block 628, the BHA controller 174 transmits the bin data, both the measurements assigned to the top and bottom bins and the one or more estimated bin values, to the surface control system 195 using methods known in the art, for example some form of telemetry. This data may be temporarily buffered, such as in the memory 237, prior to transmission to the surface.

Returning to decision block 626, if instead the BHA controller 174 is not transmitting in real time, then the method 600 proceeds to block 630.

At block 630, the BHA controller 174 stores the bin data in memory 237 for later retrieval (e.g., after the BHA 170 has been tripped out of the borehole).

From either block 628 or 630, the method 600 proceeds to block 632. At block 632, the BHA controller 174 continues to monitor the BHA RPM value and detects a BHA RPM value from the RPM sensor.

At block 634, the BHA controller 174 compares the BHA RPM value detected at block 632, and compares the BHA RPM value to a threshold RPM value. In some examples, this threshold RPM value is a second threshold RPM value, and for example has a different value than the first threshold RPM value so as to introduce some hysteresis into the system between binning modes.

At decision block 636, if the threshold RPM value compared at block 634 is less than the second threshold RPM value, then the method 600 returns to block 614 as the BHA controller 174 remains in the horizontal binning mode. If instead the threshold RPM value compared at block 634 is greater than (or greater than or equal to) the second threshold RPM value, then the method 600 proceeds to block 638.

At block 638, the BHA controller 174 transitions to a vertical binning mode from the horizontal binning mode. From block 638, the method 600 returns to block 602 and may proceed as laid out above. Alternatively, the BHA controller 174 may return to the vertical binning mode after a hard reset such as a power cycle or express command from the surface, such as may occur after tripping out of some or all of the wellbore.

Turning now to FIG. 7, a flow chart showing an exemplary process 700 for controlling drilling based on slide drilling azimuthal measurement data according to aspects of the present disclosure is described. The method 700 may be performed, for example, with respect to the controller 210 of the surface control system 195 discussed above. It is understood that additional steps can be provided before, during, and after the steps of method 700, and that some of the steps described can be replaced or eliminated from the method 700.

At block 702, the controller 210 receives one or more bin values as bin data from the BHA controller 174.

At block 704, the controller 210 generates an image portion from the bin data. For example, if the controller 210 is receiving the bin data in real time, then the image portion constitutes that portion of the image after the last bin data and up to the last data just received at block 702. If, instead, it is not real time and the data is being downloaded from the BHA 170 after the fact, then the image portion constitutes the full image log from the bin data obtained from the BHA 170.

At decision block 706, if the controller 210 is receiving the bin data from the BHA controller 174 in real time (i.e., while the BHA 170 is still drilling), then the method 700 proceeds to block 708.

At block 708, the controller 210 determines how to steer the BHA 170 while slide drilling based on the image log and the bin data generally. For example, the controller 210 may receive a command from a user reviewing the image log to change direction to remain in (or enter) a desired formation. As another example, the controller 210 may analyze the bin data and determine without manual input how to steer the BHA 170 according to a well plan.

The method 700 proceeds from block 708 to block 710. At block 710, the controller 210 identifies a status of the slide flag from the bin data. For example, if the slide flag is asserted, then the controller 210 identifies the corresponding data as associated with data collected/estimated while the BHA 170 is slide drilling (is in a horizontal binning mode) and renders an indicator in the image log, while if the slide flag is not asserted, that may correspond to a vertical binning mode.

Returning to decision block 706, if the controller 210 is not receiving the bin data from the BHA controller 174 in real time, then the method 700 instead proceeds to block 710.

From block 710, the method 700 proceeds to block 712. At block 712, the controller 210 characterizes the formations in the wellbore based on the bin data and the image log generated at block 704. In real time, this may be characterized at the same time as the determination at block 708, or alternatively may be done after the image log is completed at a similar time as when the image log is created in non-real time alternatives. Characterizations may include a percentage of water in the wellbore, fault areas, fracture zones, etc.

At block 714, the controller 210 uses the image log to further determine whether to re-geosteer the wellbore. For example, the image log generated according to embodiments of the present disclosure may be of sufficient quality to use as a density image, such as to identify where to better position the well so as to ensure rock of equal hardness for equal fracking.

Accordingly, embodiments of the present disclosure provide improvements to wellbore and formation characterization by enabling the image log to continue to produce relevant data, even during slide drilling portions of drilling. This, in turn, may improve the drilling rig apparatus' ability to remain within a pay zone and otherwise steer toward or away from given formations or zones. Thus, production may also be improved as existing faults/fractures may be identified and used when determining where and how to induce fractures in the formations, and to better assure equal hardness of the rocks when fracking in different locations. Generally, then, the efficiency of the drilling as well as subsequent production may be improved.

In view of the above and the figures, one of ordinary skill in the art will readily recognize that the present disclosure introduces a bottom hole assembly comprising a plurality of sensors configured to detect azimuthal measurements while the bottom hole assembly is in a wellbore; a processor coupled to the plurality of sensors and configured to: place, during slide drilling operations, the detected azimuthal measurements from a first sensor of the plurality of sensors into a top portion of an upper hemisphere of a radial plot and the detected azimuthal measurements from a second sensor of the plurality of sensors into a bottom portion of a lower hemisphere of the radial plot; and generate a plurality of intermediate values between the top portion of the upper hemisphere and the bottom portion of the lower hemisphere corresponding to intermediate portions of the radial plot; and a transceiver configured to transmit the detected azimuthal measurements in the upper hemisphere, the intermediate values, and the detected azimuthal measurements in the lower hemisphere to a surface controller for image log generation used in controlling a direction of the bottom hole assembly.

The BHA assembly may include a rotation sensor configured to detect a rotation per minute (RPM) rate of the bottom hole assembly while drilling, wherein the processor is further configured to: compare the RPM rate to a first threshold RPM rate; and transition from a vertical binning mode to a horizontal binning mode in response to the RPM rate equaling or being less than the first threshold RPM rate, the horizontal binning mode corresponding to the slide drilling operations. The BHA assembly may also include wherein the processor is further configured to transition from the horizontal binning mode to the vertical binning mode in response to the RPM rate being greater than a second threshold RPM rate, the vertical binning mode corresponding to rotational drilling operations. The BHA assembly may also include wherein the plurality of sensors comprise gamma imaging sensors, and the plurality of gamma imaging sensors comprise two gamma imaging sensors spaced apart by 180 degrees along a circumference of the bottom hole assembly. The BHA assembly may also include wherein the processor is further configured to assert, during slide drilling operations, a flag that indicates that the azimuthal measurements are occurring during slide drilling operations, wherein the flag is included with the transmission from the transceiver. The BHA assembly may also include wherein the transceiver is further configured to transmit the detected azimuthal measurements in the upper hemisphere, the intermediate values, and the detected azimuthal measurements in the lower hemisphere to the surface controller in real time. The BHA assembly may also include a memory buffer configured to store data comprising the detected azimuthal measurements in the upper hemisphere, the intermediate values, and the detected azimuthal measurements in the lower hemisphere are retrieved from the bottom hole assembly, wherein the transmission comprises the data being retrieved from the memory buffer after tripping the bottom hole assembly out of the wellbore.

The present disclosure also includes a method comprising detecting, by a plurality of sensors of a bottom hole assembly in a wellbore, a first plurality of measurements from a first sensor of the plurality of sensors and a second plurality of measurements from a second sensor of the plurality of sensors; placing, by a controller of the bottom hole assembly, the first plurality of measurements into an upper portion of a first hemisphere of a radial plot and the second plurality of measurements into a lower portion of a second hemisphere of the radial plot; estimating, by the controller, a plurality of intermediate measurement values between the upper portion and the lower portion corresponding to intermediate portions of the first and second hemispheres; and transmitting, from the bottom hole assembly, the first plurality of measurements, the second plurality of measurements, and the plurality of intermediate measurement values to a surface controller for image log generation used in controlling a direction of the bottom hole assembly.

The method may include tracking, by a rotation sensor at the bottom hole assembly, a rotations per minute (RPM) rate of the bottom hole assembly while drilling; comparing, by the controller, the RPM rate to a first threshold RPM rate; and transitioning, by the controller, from a vertical binning mode to a horizontal binning mode in response to the RPM rate being equal to or less than the first threshold RPM rate, wherein the horizontal binning mode corresponds to slide drilling operations. The method may also include comparing, by the controller, the RPM rate to a second threshold RPM rate; and transitioning, by the controller, from the horizontal binning mode to the vertical binning mode in response to the RPM rate being greater than the second threshold RPM rate, the vertical binning mode corresponding to rotational drilling operations. The method may also include asserting, by the controller, a flag that indicates the first and second plurality of measurements are occurring during slide drilling operations and the controller is in a horizontal binning mode; and including, by the controller, the asserted flag with the transmitting during the horizontal binning mode. The method may also include wherein the transmitting further comprises transmitting, by the controller, the first plurality of measurements, the second plurality of measurements, and the plurality of intermediate measurement values in real time. The method may also include storing, by the controller during drilling, the first plurality of measurements, the second plurality of measurements, and the plurality of intermediate measurement values into a memory buffer of the bottom hole assembly, wherein the transmitting further comprises providing access to the memory buffer after tripping the bottom hole assembly out of the wellbore. The method may also include wherein the plurality of intermediate measurement values comprises a left value for the radial plot and a right value for the radial plot, and the transmitting further comprises transmitting the first plurality of measurements as an up value for the radial plot, the second plurality of measurements as a down value for the radial plot, and the left and right values.

The present disclosure also includes a non-transitory machine-readable medium having stored thereon machine-readable instructions executable to cause a machine to perform operations comprising receiving, from a plurality of sensors of a bottom hole assembly in a wellbore while in a horizontal binning mode, a plurality of measurements; associating a first measurement from the plurality of measurements with an upper bin of an upper hemisphere of a radial plot and a second measurement from the plurality of measurements with a lower bin of a lower hemisphere of the radial plot; estimating a plurality of intermediate values between the upper bin and the lower bin corresponding to intermediate bins of the upper and lower hemispheres; and transmitting the first measurement associated with the upper bin, the second measurement associated with the lower bin, and the plurality of intermediate values to a surface controller for use in controlling a direction of the bottom hole assembly while slide drilling.

The non-transitory machine-readable medium also includes operations further comprising transitioning from a vertical binning mode to the horizontal binning mode in response to a tracked rotation per minute (RPM) rate of the bottom hole assembly falling below a first threshold RPM rate, the horizontal binning mode corresponding to slide drilling operations. The non-transitory machine-readable medium may also include operations further comprising tracking the RPM rate of the bottom hole assembly with a rotation sensor; and comparing the RPM rate to the first threshold RPM rate. The non-transitory machine-readable medium may also include operations further comprising comparing the RPM rate to a second threshold RPM rate; and transitioning from the horizontal binning mode to the vertical binning mode in response to the RPM rate being greater than the second threshold RPM rate, the vertical binning mode corresponding to rotational drilling operations. The non-transitory machine-readable medium may also include operations further comprising including a flag that indicates, when asserted, that the first and second plurality of measurements are occurring during slide drilling operations and the controller is in a horizontal binning mode. The non-transitory machine-readable medium may also include operations further comprising transmitting the first measurement associated with the upper bin, the second measurement associated with the lower bin, and the plurality of intermediate values in real time.

The foregoing outlines features of several embodiments so that a person of ordinary skill in the art may better understand the aspects of the present disclosure. Such features may be replaced by any one of numerous equivalent alternatives, only some of which are disclosed herein. One of ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. One of ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Moreover, it is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the word “means” together with an associated function.

Claims

1. A bottom hole assembly comprising:

a plurality of sensors configured to detect azimuthal measurements while the bottom hole assembly is in a wellbore;

a processor coupled to the plurality of sensors and configured to: place, during slide drilling operations, the detected azimuthal measurements from a first sensor of the plurality of sensors into a top portion of an upper hemisphere of a radial plot and the detected azimuthal measurements from a second sensor of the plurality of sensors into a bottom portion of a lower hemisphere of the radial plot; and generate a plurality of intermediate values between the top portion of the upper hemisphere and the bottom portion of the lower hemisphere corresponding to intermediate portions of the radial plot; and

a transceiver configured to transmit the detected azimuthal measurements in the upper hemisphere, the intermediate values, and the detected azimuthal measurements in the lower hemisphere to a surface controller for image log generation used in controlling a direction of the bottom hole assembly.

2. The bottom hole assembly of claim 1, further comprising:

a rotation sensor configured to detect a rotation per minute (RPM) rate of the bottom hole assembly while drilling,

wherein the processor is further configured to:

compare the RPM rate to a first threshold RPM rate; and

transition from a vertical binning mode to a horizontal binning mode in response to the RPM rate equaling or being less than the first threshold RPM rate, the horizontal binning mode corresponding to the slide drilling operations.

3. The bottom hole assembly of claim 2, wherein the processor is further configured to:

transition from the horizontal binning mode to the vertical binning mode in response to the RPM rate being greater than a second threshold RPM rate, the vertical binning mode corresponding to rotational drilling operations.

4. The bottom hole assembly of claim 1, wherein:

the plurality of sensors comprise gamma imaging sensors, and

the plurality of gamma imaging sensors comprise two gamma imaging sensors spaced apart by 180 degrees along a circumference of the bottom hole assembly.

5. The bottom hole assembly of claim 1, wherein the processor is further configured to:

assert, during slide drilling operations, a flag that indicates that the azimuthal measurements are occurring during slide drilling operations, wherein the flag is included with the transmission from the transceiver.

6. The bottom hole assembly of claim 1, wherein the transceiver is further configured to:

transmit the detected azimuthal measurements in the upper hemisphere, the intermediate values, and the detected azimuthal measurements in the lower hemisphere to the surface controller in real time.

7. The bottom hole assembly of claim 1, further comprising:

a memory buffer configured to store data comprising the detected azimuthal measurements in the upper hemisphere, the intermediate values, and the detected azimuthal measurements in the lower hemisphere are retrieved from the bottom hole assembly,

wherein the transmission comprises the data being retrieved from the memory buffer after tripping the bottom hole assembly out of the wellbore.

8. A method comprising:

detecting, by a plurality of sensors of a bottom hole assembly in a wellbore, a first plurality of measurements from a first sensor of the plurality of sensors and a second plurality of measurements from a second sensor of the plurality of sensors;

placing, by a controller of the bottom hole assembly, the first plurality of measurements into an upper portion of a first hemisphere of a radial plot and the second plurality of measurements into a lower portion of a second hemisphere of the radial plot;

estimating, by the controller, a plurality of intermediate measurement values between the upper portion and the lower portion corresponding to intermediate portions of the first and second hemispheres; and

transmitting, from the bottom hole assembly, the first plurality of measurements, the second plurality of measurements, and the plurality of intermediate measurement values to a surface controller for image log generation used in controlling a direction of the bottom hole assembly.

9. The method of claim 8, further comprising:

tracking, by a rotation sensor at the bottom hole assembly, a rotations per minute (RPM) rate of the bottom hole assembly while drilling;

comparing, by the controller, the RPM rate to a first threshold RPM rate; and

transitioning, by the controller, from a vertical binning mode to a horizontal binning mode in response to the RPM rate being equal to or less than the first threshold RPM rate, wherein the horizontal binning mode corresponds to slide drilling operations.

10. The method of claim 9, further comprising:

comparing, by the controller, the RPM rate to a second threshold RPM rate; and

transitioning, by the controller, from the horizontal binning mode to the vertical binning mode in response to the RPM rate being greater than the second threshold RPM rate, the vertical binning mode corresponding to rotational drilling operations.

11. The method of claim 8, further comprising:

asserting, by the controller, a flag that indicates the first and second plurality of measurements are occurring during slide drilling operations and the controller is in a horizontal binning mode; and

including, by the controller, the asserted flag with the transmitting during the horizontal binning mode.

12. The method of claim 8, wherein the transmitting further comprises:

transmitting, by the controller, the first plurality of measurements, the second plurality of measurements, and the plurality of intermediate measurement values in real time.

13. The method of claim 8, further comprising:

storing, by the controller during drilling, the first plurality of measurements, the second plurality of measurements, and the plurality of intermediate measurement values into a memory buffer of the bottom hole assembly,

wherein the transmitting further comprises providing access to the memory buffer after tripping the bottom hole assembly out of the wellbore.

14. The method of claim 8, wherein:

the plurality of intermediate measurement values comprises a left value for the radial plot and a right value for the radial plot, and

the transmitting further comprises transmitting the first plurality of measurements as an up value for the radial plot, the second plurality of measurements as a down value for the radial plot, and the left and right values.

15. A non-transitory machine-readable medium having stored thereon machine-readable instructions executable to cause a machine to perform operations comprising:

receiving, from a plurality of sensors of a bottom hole assembly in a wellbore while in a horizontal binning mode, a plurality of measurements;

associating a first measurement from the plurality of measurements with an upper bin of an upper hemisphere of a radial plot and a second measurement from the plurality of measurements with a lower bin of a lower hemisphere of the radial plot;

estimating a plurality of intermediate values between the upper bin and the lower bin corresponding to intermediate bins of the upper and lower hemispheres; and

transmitting the first measurement associated with the upper bin, the second measurement associated with the lower bin, and the plurality of intermediate values to a surface controller for use in controlling a direction of the bottom hole assembly while slide drilling.

16. The non-transitory machine-readable medium of claim 15, the operations further comprising:

transitioning from a vertical binning mode to the horizontal binning mode in response to a tracked rotation per minute (RPM) rate of the bottom hole assembly falling below a first threshold RPM rate, the horizontal binning mode corresponding to slide drilling operations.

17. The non-transitory machine-readable medium of claim 16, the operations further comprising:

tracking the RPM rate of the bottom hole assembly with a rotation sensor; and

comparing the RPM rate to the first threshold RPM rate.

18. The non-transitory machine-readable medium of claim 17, the operations further comprising:

comparing the RPM rate to a second threshold RPM rate; and

transitioning from the horizontal binning mode to the vertical binning mode in response to the RPM rate being greater than the second threshold RPM rate, the vertical binning mode corresponding to rotational drilling operations.

19. The non-transitory machine-readable medium of claim 15, the operations further comprising:

including a flag that indicates, when asserted, that the first and second plurality of measurements are occurring during slide drilling operations and the controller is in a horizontal binning mode.

20. The non-transitory machine-readable medium of claim 15, the operations further comprising:

transmitting the first measurement associated with the upper bin, the second measurement associated with the lower bin, and the plurality of intermediate values in real time.