Patent Application
20250237143
This application is directed, in general, to analyzing formations, reservoirs, or boreholes and, more specifically, to using downhole probes to collect sensor data.
In borehole development, such as drilling operations, hydrocarbon extraction operations, or scientific operations, gathering information about the surrounding subterranean formation is an important task. The information can be on the fluid in the subterranean formation, the geological characteristics of the subterranean formation, or other information. Creating a high-quality seal between the sensor and the subterranean formation is important to keep out other borehole fluids from the sensor and subsequent analysis. The operators, technicians, or other types of users can use this information to make further decisions regarding the operations at the borehole. Currently, sensors are positioned against the inner borehole surface of the subterranean formation. It would be beneficial to increase the accuracy of sensor collected parameters by improving the seal of the sensor against the subterranean formation.
Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
Developing a borehole, such as for scientific or hydrocarbon production purposes, can utilize data collected during borehole operations, such as drilling operations, for example, measuring while drilling (MWD), logging while drilling (LWD), seismic while drilling (SWD), and other types of drilling operations. Other borehole operations can be a completed borehole, production operations, production testing operations, interception operations, slickline or wireline operations, coiled tubing remediation, seismic profiling, and other types of borehole operations. The borehole operations can be to produce oil or gas products, or for scientific purposes, research, testing, or other non-hydrocarbon related purpose.
Various types of sensors and tools can be utilized to collect the data, such as magnetic resonance sensors, resistivity sensors, acoustic sensors, nuclear sensors, temperature sensors, pressure sensors, seismic sensors, and other types of sensors. The data can be utilized by various borehole systems. For example, to adjust drilling parameters, modify pumped borehole fluid, e.g., mud, adjust operations of a geo-steering system for a drilling assembly, adjust production pump-out operations, such as adjusting for a change in reservoir drainage, activating or closing zones, or other uses by systems at the borehole.
Data collected from downhole sensors, tool sensors, or surface sensors can be used to analyze the current borehole operation. The analysis can be used to modify operations, alert systems for remediation actions, or trigger alarms for systems or users. The data can be collected and analyzed using algorithms determined by a user or a borehole operation system.
To collect data from downhole sensors (which can include tools, sensors, or sensor strings), the downhole sensor can be part of a probe inserted into a borehole and moved through the borehole to the specified position. The probe can be part of a downhole tool such as a drilling assembly, a bottom hole assembly (BHA), a downhole tool assembly, a permeability tool, a reservoir description tool (RDT), a mini-drill stem tester (DST), or other types of borehole tools. The downhole tools can be attached to a drill string, a pipe, a tube, a wireline, or other types of conveyances used in borehole operations.
The downhole tool can cause the included or attached probe to extend to form a seal between the sensor internal of the probe and an inside surface of the borehole, e.g., the subterranean formation. The quality of the seal is an important factor, e.g., how well the seal prevents borehole fluids or materials from interfering with the sensor collecting data from the subterranean formation. For example, if the sensor is attempting to measure the fluid pressure of a hydrocarbon fluid within the subterranean formation, the quality of the data collected increases as the effects of other borehole fluids on the sensor data are reduced. The seal quality can be affected by various factors, such as the borehole wall being an uneven surface so that the probe does not sit flush with the borehole wall. It would be beneficial to be able to improve the quality of the seal of the probe against the subterranean formation or to be able to position the probe to improve sensor data collection.
This disclosure presents systems, apparatuses, and processes for being able to improve the positioning of a probe against the wall of a borehole, e.g., against the subterranean formation. In some aspects, the probe, (containing the sensor, sensor string, or tool), can be rotated 1800 (degrees) in one or more directions. In some aspects, the probe can be rotated up to 360°. The probe (and the sensor) is of a non-circular shape since rotation would not be helpful for a circular shape. In some aspects, the probe can rotate axially along the connection point between the probe and the downhole tools.
In some aspects, the probe can measure the quality of the seal between the inner portion of the probe where the sensor is located, and the borehole, where borehole fluid and other borehole material are present. In some aspects, the quality of the seal can be measured by the amount of fluid that can pass the seal. In some aspects, the quality of the seal can be measured by the amount of solids that can pass the seal. In some aspects, the quality of the seal can be measured by the amount of acoustic waves that can pass the seal. In some aspects, the quality of the seal can be measured by the amount of magnetic force that can pass the seal.
The sensor is intended to collect data on one or more characteristics of the subterranean formation and the presence of the borehole fluid or other borehole material can interfere with that collection of data. In some aspects, a user or controller can provide a tool-formation quality threshold that can be used to compare against the measured quality of the seal. When the tool-formation quality threshold is not satisfied as to the measured quality of the seal, the probe can rotate a set number of degrees, for example, 0.5° or 3.0°. In some aspects, the probe can rotate incrementally until the tool-formation quality threshold is satisfied.
In some aspects, if the tool-formation quality threshold is not met after proceeding through the available degrees of rotation, a smaller increment of degree rotation can be used. In some aspects, if the tool-formation quality threshold is not met after proceeding through the available degrees of rotation, the probe can be rotated to the best rotational position to provide the highest threshold quality. In some aspects, the system can be instructed on which rotational degree to utilize when a tie occurs at different degrees of rotation.
In some aspects, the probe is to be rotated a specified amount of degrees to provide a different perspective of the characteristics of the subterranean formation. For example, an increase in the reliability of an oil-water barrier detection can be achieved by collecting data from a sensor in more than one orientation. In some aspects, a user or a controller can specify one or more degrees of rotation to be applied to the probe.
In some aspects, the tool-formation quality threshold can relate to a characteristic quality parameter, where the characteristic quality relates to a characteristic of the subterranean formation as detected by the sensors. In some aspects, the tool-formation quality threshold can relate to the quality of a permeability characteristic quality threshold. In some aspects, the tool-formation quality threshold can relate to the quality of a wettability characteristic quality threshold. In some aspects, the tool-formation quality threshold can relate to other types of downhole characteristic quality thresholds.
In some aspects, the probe is an elliptical shape. In some aspects, the probe is a rectangular shape. Other shapes can be utilized as well. In some aspects, the probe can include one or more sensors. For example, the probe can include a fluid pressure sensor, a temperature sensor, a geological formation survey sensor (such as a nuclear magnetic resonance (NMR) sensor, an acoustic sensor, an optical sensor, an electromagnetic (EM) sensor, a seismic sensor, an electrode sensor (for example, to detect water chemistry, water pH, CO2 presence, H2S presence, or other chemical compounds), or other types of sensors, sensor strings, or tools.
In some aspects, between the probe and the inner surface of the borehole can be a casing. The disclosed aspects apply to cased sections of the borehole as well, where the intention is to place the probe against the inner diameter of the casing. In some aspects, the casing could be damaged or uneven, and so lowering the quality of the seal of the probe against the otherwise relatively uniform surface of the casing. The probe can be rotated to compensate for the damage or uneven inner surface of the casing. In some aspects, a sensor or tool can be placed at a position on the casing. A probe can be rotated to avoid the sensor or tool on the casing thereby not allowing the sensor or tool to adversely affect the quality of the seal.
In some aspects, the sensor can evaluate corrosive water conditions before the intersection with the borehole. In some aspects, the sensor can detect CO2 or water floods before the intersection with the completion zone. In some aspects, the sensor can detect pressure changes or point temperature measurements. In some aspects, the sensor can collect resistivity measurements to evaluate changes further out into the subterranean formation. In some aspects, the sensor can evaluate caking in a near proximal position to the sensor, for example, triangulated by +/−30 feet or another distance parameter. In some aspects, the sensor can be operable to detect ambient acoustic noise to detect fluid flow and approaching fluid flow from a distance. In some aspects, the sensor can detect casing issues or damage.
In some aspects, the sensor can make hydraulic contact with the subterranean formation. In some aspects, the sensor can be fitted with a tube or other mechanism to sample fluid from deeper into the subterranean formation. In some aspects, the tube can be fitted with a valve able to couple with a mating end that is part of the sensor or probe. In some aspects, the tube can be fitted with a check valve to allow automatic opening with sufficient pressure differential not less than the differential between the borehole and the subterranean formation. In some aspects, the sensor can include an indicator that when set to a predetermined value, fluid from the tube can be released into the borehole or the subterranean formation directly. In some aspects, the tube port can be a direct access point to sample the fluid at a distance in the formation or measure pressure directly.
In some aspects, a tracer can be used by the sensor. For example, the sensor can release a tracer into the subterranean formation using the fluid tube. As the tracer moves through the reservoir of hydrocarbons, the sensor or other sensors such as those located at the surface, can monitor the movement. In some aspects, the tracer can be released into the subterranean formation to trace other characteristics, such as water breakthrough. More than one type of tracer can be released, such as from the same sensor or from different sensors located proximate or distant from each other.
In some aspects, the tracer can be released with other tracers to form a binary code and to allow ratioing or distribution analysis to guard against concentration changes in the tracer. In some aspects, the tracers can be released in sufficient condition to allow detection by a surface controller, such as a surface sensor or other detection system. In some aspects, the tracer can be released on a timed schedule or by receiving instruction at the sensor to improve the analysis of the detected tracers by the detection system. In some aspects, the subterranean formation fluid, for example, reservoir fluid, can be sampled and analyzed for the tracers, such as using a tube attached to the sensor to draw in the fluid. In some aspects, a collected sample of fluid can allow the use of a mass spectrometry detection device, which can enable very low detection limits. In some aspects, tracers can be dyes, isotopes, organometallics, or other unique elemental or molecular combinations that are durable and detectable. In some aspects, analytical instrumentation capable of detecting the tracers can include optical instrumentation, chromatography instrumentation, mass spectrometry instrumentation, or other types of analytical instrumentation for selected tracers.
In some aspects, the probe and sensors can be controlled by a probe controller, by a controller included with the downhole tools, by a surface controller (such as a well site controller), or other types of controllers. In some aspects, the data collected by the sensor can be stored in a memory or transmitted to a device located within the borehole, such as a communication junction device or a logging tool. In some aspects, the data collected by the sensor can be communicated to a surface controller, such as a well site controller, a reservoir controller, a computing system, or other surface controllers.
Turning now to the figures,
Extending below derrick 105 is a borehole 110 with downhole tools 120 at the end of a drill string 115. Downhole tools 120 can include various downhole tools, such as a formation tester or a bottom-hole assembly (BHA). At the bottom of downhole tools 120 is a drilling bit 122. Other components of downhole tools 120 can be present, such as a local power supply (e.g., generators, batteries, or capacitors), telemetry systems, sensors, transceivers, and control systems. Borehole 110 is surrounded by subterranean formation 150. Downhole tools 120 includes at least one probe with a sensor where the probe is to form a seal of a specified quality level against the casing or the subterranean formation.
Well site controller 107, or computing system 108 (e.g., surface controllers) which can be communicatively coupled to well site controller 107, can be utilized to communicate with downhole tools 120 (e.g., downhole controllers), such as sending and receiving acoustic data, telemetry, data, instructions, subterranean formation measurements, and other information. Computing system 108 can be proximate to well site controller 107 or be a distance away, such as in a cloud environment, a data center, a lab, or a corporate office. Computing system 108 can be a laptop, smartphone, PDA, server, desktop computer, cloud computing system, other computing systems, or a combination thereof, that are operable to perform the processes described herein.
Well site operators, engineers, and other personnel can send and receive data, instructions, measurements, and other information by various conventional means, now known or later developed, with computing system 108 or well site controller 107. Well site controller 107 or computing system 108 can communicate with downhole tools 120 using conventional means, now known or later developed, to direct operations of downhole tools 120. For example, a specified degree of rotation can be communicated to the sensor or a specified quality of seal threshold. Casing 130 can act as a barrier between subterranean formation 150 and the fluids and material internal to borehole 110, as well as drill string 115.
In some aspects, the sensor included with the probe can be coupled using a wire or wirelessly to a wire, cable, power junction device, or other device in borehole 110 to provide power to the probe and sensor. In some aspects, the probe or sensor can include one or more batteries to supply power. In some aspects, the probe or sensor can be coupled to a communication device, such as a wire, a cable, or a communication junction in borehole 110. This communication can allow the probe or sensor to communicate with well site controller 107, computing system 108, or other computing systems, devices, tools, or controllers.
In some aspects, the sensor data can be used to generate a notification or alarm which can be communicated to another system, such as computing system 108 or well site controller 107, where actions can be taken on the notification, trigger, or alarm. For example, a change in the flow rate or direction of drainage of a reservoir can be implemented. In some aspects, corrective action or preventive action can be scheduled for the borehole operation to reduce the risk as identified to improve operations, such as to improve reservoir drainage operations.
In some aspects, computing system 108 can collect the sensor data and perform the analysis to determine the type of notifications to be sent and what other systems, controllers, or processes are to receive the analysis. In some aspects, well site controller 107 can collect the sensor data and implement the analysis process. In some aspects, the analysis process can be partially included with well site controller 107 and partially located with computing system 108. In some aspects, the analysis process can be performed downhole, such as at the sensor, the probe, the downhole tools, or other locations. In some aspects, the analysis can be partially performed by a downhole computing system and partially by a surface computing system. In some aspects, the analysis process can be located in another system, for example, a data center, a lab, a corporate office, or another location.
Well controller 207 is placed in a cabinet 206 inside a control room 204 on an offshore platform 205, such as an oil rig, above water surface 244. Well controller 207 is operable to adjust the operations of ESP motor 214 to improve well productivity. In the illustrated aspect, ESP motor 214 is a two-pole, three-phase squirrel cage induction motor that operates to turn ESP pump 224. ESP motor 214 is located near the bottom of ESP assembly 220, just above downhole sensors within borehole 210. A power/communication cable 230 extends from well controller 207 to ESP motor 214. A fluid pipe 232 fluidly couples equipment located on offshore platform 205 and ESP pump 224.
In some aspects, ESP pump 224 can be a horizontal surface pump, a progressive cavity pump, a subsurface compressor system, or an electric submersible progressive cavity pump. A motor seal section and intake section may extend between ESP motor 214 and ESP pump 224. A riser 215 separates ESP assembly 220 from water 240 until sub-surface 242 is encountered, and a casing 216 can separate borehole 210 from subterranean formation 245 at and below sub-surface 242. Perforations in casing 216 can allow the fluid of interest from subterranean formation 245 to enter borehole 210.
Probes with sensors can be located with ESP assembly 220, along borehole 210, riser 215, or at points between the various identified tools, such as to monitor the pressure and temperature of the fluid in the subterranean formation. Data from one or more of these sensors can be communicated to the analysis process and used as inputs to selected sensor evaluation algorithms.
One or more sensors 260 can be placed along the inner surface of casing 216. In some aspects, sensors 260 can be coupled using a wire or wirelessly to a wire, cable, power junction device, or other device in borehole 210 to provide power to sensors 260, such as power/communication cable 230. In some aspects, sensors 260 can include one or more batteries to supply power. In some aspects, sensors 260 can be coupled to a communication device, such as a wire, a cable, or a communication junction in borehole 210, such as power/communication cable 230. This communication can allow sensors 260 to communicate with well controller 207, or other computing systems, devices, tools, or controllers.
Parameters (e.g., data) collected from sensors 260 can be communicated to a computing system (such as a controller) to perform the analysis process (e.g., performed by one or more processors, such as a downhole controller or a surface controller) to produce results, such as notifications, alarms, or triggers. The results can be communicated to one or more other systems, such as well controller 207. In some aspects, the sensor data can be transmitted to another system, such as well controller 207. Well controller 207 can implement the analysis process or include a probe processor or analyzer, or can be a probe controller. In some aspects, the probe analyzer or the probe processor, or the probe controller, can be partially in well controller 207, partially in another computing system, or various combinations thereof.
The results of the probe analyzer, probe processor, or probe controller can be used to generate one or more alerts, triggers, or notifications, sent to one or more of a user, a controller, a computing system, or a borehole system. For example, an alarm can be specified on a temperature measured at a specified location. If the threshold for that temperature parameter is exceeded, then an alert can be communicated to a user or user group. An alert can be sent to a borehole system to take corrective action to lower the risk of a potential event or to improve operations, such as maintaining a consistent reservoir drainage rate.
In some aspects, downhole tool 315 can be lowered into position within a borehole 310 by a wireline 305 attached to downhole tool 315. In some aspects, downhole tool 315 can be attached to a drill string, a cable, a pipe, a tube, and other support mechanisms. Borehole 310 can be one of various types of boreholes, such as those illustrated in
In some aspects, probe placement system 320 can collect subterranean formation data using probes. In some aspects, probe placement system 320 can include a processor or processors, or a controller capable of directing the operations of probe placement system 320, such as probe system 600 of
Probe placement system 320 has an articulation arm 325 with a seal 327 and a sensor 329. In other aspects, seal 327 can be attached to an arm or a piston, which can then be pushed out or extended from the tool to seal against the formation. Articulation arm 325 can place seal 327 along an exposed area of inside surface 306 or along an inside surface of the casing. Seal 327 is capable of creating at least a partial seal with the subterranean formation or casing, such as a hydraulic seal, a fluidic seal, an acoustic seal, a magnetic seal, or other types of seals. Seal 327 is shown as a rectangular shape, and in other aspects, can use other types of non-circular shapes, such as being elliptically shaped.
In some aspects, the sensors placed in the hole can utilize one or more tracers or fluids. The tracers or fluids can be stored with the sensor or can be stored in the probe placement system 320. Injectable fluid storage 330a, injectable fluid storage 330b, and injectable fluid storage 330c (collectively injectable fluid storages 330) can each hold one of various types of injectable fluids, for example a water, chemicals that can be mixed with the water, a hydrocarbon, tracers, or other fluid types. In some aspects, the sensors can extract fluid from the subterranean formation and can provide the fluid to an analyzing system, such as through a tube and valve system. A sample storage 335 can hold fluid or core samples taken from the subterranean formation for analysis by probe placement system 320 or for transportation to the surface where other systems can perform the analysis. In some aspects, there can be fewer or additional storage systems for storing injectable fluids or storing retrieved fluids. In some aspects, there can be separate storage areas for core samples.
Probe placement system 320 has previously placed a probe 420 along inside surface 306. There can be zero or more additional sensors located at one or more azimuths or depths along borehole 310. Probe 420 can be rotated to a specified degree offset from the initial position, probe 420 can be rotated until a seal quality threshold is satisfied, or probe 420 can be rotated until a determined seal quality is achieved if the threshold is not met. A rotated probe 425 demonstrates one type of degree of axial rotation of probe 420. Data can be collected immediately or over various time periods, for example, minutes, days, weeks, or months. For example, a change in drainage of a reservoir can be monitored over weeks or months. In some aspects, various combinations of the above aspects can be utilized.
Method 500 starts at a step 505 and proceeds to a step 510. In step 510, a probe can be part of a downhole tool, for example, a BHA, RDT, DST, a drilling assembly, or other types of downhole tools. The downhole tool can be inserted into a borehole and moved to a specified position within the borehole. This section of the borehole can be cased or uncased. The probe can include one or more sensors, such as a pressure sensor, a temperature sensor, a fluid composition sensor, or other types of sensors.
In a step 515, the probe can be extended from the downhole tool such that the probe can form a seal with an inside surface of the borehole or the casing. In a step 520, the probe is rotated a specified number of degrees and the seal is made between the probe and the inside surface. The number of degrees the probe is rotated can be specified by a controller or a user. The degree of rotation is from the current orientation. For example, if the probe is to be rotated a certain number of degrees to allow the sensor to collect data using a different orientation, then the degree offset from the initial position can be 30.0°, 45.0°, or other degree offsets. In these aspects, method 500 proceeds to a step 595 and ends. If the probe is searching for an optimal seal quality, then the probe can be rotated 0.5°, 1.0°, 5.0°, or other degree offset values, at each increment. Each subsequent rotation is from the then current orientation of the probe. In these aspects, method 500 proceeds to an optional step 525.
In step 525, the probe can measure the seal quality parameter, e.g., the seal may be a partial seal. The seal can be one or more of a fluid seal, a hydraulic seal, a magnetic seal, an acoustic seal, an optical seal, or other types of seals. The seal quality parameter can represent the amount that the borehole fluids, solids, materials, or equipment are interfering with the measurements the sensor is collecting. For example, a fluid seal can represent the amount of borehole fluid leaking into the probe and sensor area, or an acoustic seal can represent the amount the borehole and equipment sounds are being dampened by the seal.
In a decision step 530, the seal quality parameter can be compared to a seal quality threshold. The seal quality threshold can be specified by a controller or a user as an input parameter. If the seal quality threshold is satisfied, then method 500 proceeds to step 595. If the seal quality threshold is not satisfied, then method 500 proceeds to a decision step 535.
In decision step 535, a determination is made whether the probe has more degrees of rotation available. If the next increment of degree offset would bring the probe to a stop point, for example, at 180° or at 360° of rotation, e.g., at the halfway point or completing a full rotation, then the process can either change the number of degrees for each rotational step, or make a determination at which degree offset provided the best or optimal seal quality and use that degree offset. The direction of rotation can also be changed by a determination of the probe controller or logic. For example, if 5.0° was used as the incremental degree offset for each rotation and measuring step, then the probe can be directed to rotate at 2.0°. The smaller increment may lead to a degree offset with a seal quality that satisfies the threshold. The best or optimal seal quality can be determined by comparing the seal quality parameter measured at each degree offset rotation, where a tie can be determined by the probe, a controller, or a user. If the decision is “Yes”, then method 500 proceeds to step 520 for an increment to the degree of offset and rotating the probe accordingly. If the decision is “No”, then method 500 proceeds to a step 540.
In step 540, the probe can be rotated to the determined degree offset from the initial position. For example, the probe can be rotated to the degree offset that corresponds to the most optimal seal quality parameter as previously measured. Method 500 ends at step 595.
Probe system 600, or a portion thereof, can be implemented as an application, a code library, a dynamic link library, a function, a module, other software implementation, or combinations thereof. In some aspects, probe system 600 can be implemented in hardware, such as a ROM, a graphics processing unit, or other hardware implementation. In some aspects, probe system 600 can be implemented partially as a software application and partially as a hardware implementation. Probe system 600 is a functional view of a portion of the disclosed processes and an implementation can combine or separate the described functions in one or more software or hardware systems, such as using a separate probe placement system to position the probes.
Probe system 600 includes a data transceiver 610, probe 620, and a result transceiver 630. The results, e.g., the collected sensor data from probe 620 can be communicated to a data receiver, such as one or more of a user or user system 660, a computing system 662, a well site controller 664, or other processing or storage systems 666. The results can be used as inputs into a well site controller or other borehole systems, such as a borehole operation system, where decisions on future stages of the operation plan can be made, for example, updates or adjustments to the plan can be made.
Data transceiver 610 can receive input parameters, such as parameters to direct the operation of the probe 620, for example, a specified degree of rotation from an initial position, a seal quality threshold parameter, a specified step of degrees to rotate between each seal evaluation, or a direction of rotation. The specified degree of rotation can be 0-360° or can be 0-180° with additional information on the direction of rotation. In some aspects, data transceiver 610 can be part of probe 620.
Result transceiver 630 can communicate one or more results, analysis, or interim outputs, to one or more data receivers, such as user or user system 660, computing system 662, well site controller 664, storage system 666, e.g., a data store or database, or other related systems, whether located proximate result transceiver 630 or distant from result transceiver 630. Data transceiver 610, probe 620, and result transceiver 630 can be, or can include, conventional interfaces configured for transmitting and receiving data. In some aspects, probe 620 can be a machine learning system, such as applying learned analyzation models to the collected sensor data to improve the determination of the notifications to be sent or whether an alarm should be triggered.
Probe 620 (e.g., one or more processors such as processor 730 of
Probe controller 700 can be operable to perform the various functions disclosed herein including receiving input parameters, collecting sensor data, and generating results from an execution of the methods and processes described herein, such as collecting sensor data that can be used as inputs into other systems, such as to determine if adjustments are needed to later stages of a borehole operation plan. Probe controller 700 includes a communications interface 710, a memory 720, and a processor 730.
Communications interface 710 is operable to transmit and receive data. For example, communications interface 710 can receive the input parameters, sensor data, and evaluation algorithms. Communications interface 710 can transmit the results, data from the input parameters, or interim outputs. In some aspects, communications interface 710 can transmit a status, such as a success or failure indicator of probe controller 700 regarding receiving the various inputs, transmitting the generated results, or producing the results.
In some aspects, communications interface 710 can receive input parameters from a machine learning system, for example, where the sensor data is processed using one or more filters and algorithms and the machine learning system uses prior learned analyzation models to improve the fidelity of the collected sensor data.
In some aspects, the machine learning system can be implemented by processor 730 and perform the operations as described by probe 620. Communications interface 710 can communicate via communication systems used in the industry. For example, wireless or wired protocols can be used. Communication interface 710 is capable of performing the operations as described for data transceiver 610 and result transceiver 630 of
Memory 720 can be operable to store a series of operating instructions that direct the operation of processor 730 when initiated, including the code representing the algorithms for determining and processing the collected data. Memory 720 is a non-transitory computer-readable medium. Multiple types of memory can be used for data storage and memory 720 can be distributed.
Processor 730 can be operable to produce the results (e.g., rotating the probe to the appropriate degree offset from an initial starting position, collecting the sensor data and using it as inputs into other processes and systems), one or more interim outputs, and statuses utilizing the received inputs. Processor 730 can be operable to direct the operation of probe controller 700. Processor 730 includes the logic to communicate with communications interface 710 and memory 720, and perform the functions described herein, such as one or more of the steps of method 500. Processor 730 is capable of performing or directing the operations as described by probe 620 of
Various figures and descriptions can demonstrate a visual display of the acoustic data and the resulting analysis of the acoustic data. In some aspects, the visual display can be utilized by a user to determine the next steps of the analysis. In some aspects, the visual display does not need to be generated, and a system, such as a machine learning system, can perform the analysis using the received data. In some aspects, a visual display and a machine learning system can be utilized. In some aspects, the acoustic data or partially analyzed acoustic data can be transmitted to one or more surface computing systems, such as a well site controller, a computing system, or other processing system. The surface controller, e.g., surface system or surface systems, can perform the analysis and can communicate the results to one or more other systems, such as a well site controller, a well site operation planner, a geo-steering system, or another borehole system.
A portion of the above-described apparatus, systems or methods may be embodied in or performed by various analog or digital data processors, wherein the processors are programmed or store executable programs of sequences of software instructions to perform one or more of the steps of the methods. A processor may be, for example, a programmable logic device such as a programmable array logic (PAL), a generic array logic (GAL), a field programmable gate arrays (FPGA), or another type of computer processing device (CPD). The software instructions of such programs may represent algorithms and be encoded in machine-executable form on non-transitory digital data storage media, e.g., magnetic or optical disks, random-access memory (RAM), magnetic hard disks, flash memories, and/or read-only memory (ROM), to enable various types of digital data processors or computers to perform one, multiple or all of the steps of one or more of the above-described methods, or functions, systems or apparatuses described herein.
Portions of disclosed examples or embodiments may relate to computer storage products with a non-transitory computer-readable medium that have program code thereon for performing various computer-implemented operations that embody a part of an apparatus, device or carry out the steps of a method set forth herein. Non-transitory used herein refers to all computer-readable media except for transitory, propagating signals. Examples of non-transitory computer-readable media include, but are not limited to: magnetic media such as hard disks, floppy disks, and magnetic tape; optical media such as CD-ROM disks; magneto-optical media such as floppy disks; and hardware devices that are specially operable to store and execute program code, such as ROM and RAM devices. Operable or configured to means, for example, designed, constructed, or programmed, with the necessary logic, circuitry, or features for performing a task or tasks. Examples of program code include both machine code, such as produced by a compiler, and files containing higher level code that may be executed by the computer using an interpreter.
In interpreting the disclosure, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms “comprises” and “comprising” should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that the referenced elements, components, or steps may be present, or utilized, or combined with other elements, components, or steps that are not expressly referenced.
Those skilled in the art to which this application relates will appreciate that other and further additions, deletions, substitutions, and modifications may be made to the described embodiments. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting, since the scope of the present disclosure will be limited only by the claims. Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure belongs. Although any methods and materials similar or equivalent to those described herein can also be used in the practice or testing of the present disclosure, a limited number of the exemplary methods and materials are described herein.
Aspects disclosed herein include:
Each of the aspects disclosed in the Aspects A, B, and C can have one or more of the following additional elements in combination. Element 1: Element 1: wherein the probe rotates axially along a connection point to the downhole tool. Element 2: wherein the probe comprises one or more sensors capable of collecting data. Element 3: wherein the probe rotates a specified number of degrees from an initial position as specified by a probe controller. Element 4: wherein the probe is further operable to form at least a partial fluidic seal with the first inside surface. Element 5: wherein the probe utilizes an elliptical shape. Element 6: wherein the probe is further operable to form a seal with one of the first inside surface or a second inside surface of a casing. Element 7: wherein the probe rotates a specified number of degrees. Element 8: wherein the one or more sensors measure a fluid pressure, a fluid temperature, a fluid density, or a fluid composition. Element 9: wherein the probe is extended from the downhole tool and forms a fluid seal with the first inside surface or the second inside surface. Element 10: wherein the probe is rotated a specified number of degrees until a tool-formation quality threshold is satisfied. Element 11: wherein the tool-formation quality threshold is not satisfied and a probe controller directs the probe to rotate to a specified degree offset from the initial position. Element 12: further comprising a probe controller, operable to direct operations of the probe, to analyze collected sensor data, and to communicate the collected sensor data to one or more other computing systems. Element 13: wherein the probe controller comprises one or more processors. Element 14: wherein the probe controller is part of a surface controller, a well site controller, a reservoir controller, a computing system, or the downhole tool. Element 15: wherein the probe controller is operable to direct an adjustment of a borehole operation by directing the operations of downhole tools using the collected sensor data. Element 16: further comprising measuring a characteristic quality parameter between the probe and one of the first inside surface or the second inside surface. Element 17: Further comprising rotating the probe a specified number of degrees from a current orientation of the probe when the characteristic quality parameter does not satisfy a tool-formation quality threshold and the probe has available degrees of rotation. Element 18: wherein the probe passes through or stops at the initial position, further comprising rotating the probe to a determined degree offset from the initial position. Element 19: wherein the determined degree offset corresponds to a best seal quality parameter. Element 20: wherein a probe controller selects the determined degree offset.
