Patent Application
20250034980
Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. Wellbores used to produce or extract fluids may be formed in earthen formations using earth-boring tools such as drill bits for drilling wellbores and reamers for enlarging the diameters of wellbores.
Planning for the positioning and trajectory of wellbores is a critical for successful exploration and production operations. Conventional trajectory planning may include manual and/or iterative calculation, modeling, and adjustments which may be time-consuming and prone to error. Additionally, trajectory planning typically involves interdisciplinary collaboration which may be cumbersome and inefficient. Conventional methods may further lack the flexibility of accounting for real-time drilling conditions and operational constrains.
Improved systems for trajectory planning may overcome these deficiencies by leveraging advanced modeling, data analytics, and real-time monitoring to optimize the determining of wellbore trajectories. These improved systems may incorporate interdisciplinary considerations through a comprehensive set of parameters and considerations such as geological information, drilling objectives, equipment capabilities, wellbore stability, environmental factors, etc. By integrating these elements into a cohesive and intelligent system, optimal wellbore paths may be achieved to maximize reservoir exposure while minimizing drilling risks, thereby enhancing overall drilling efficiency.
In some embodiments, a method of operating a downhole system includes receiving trajectory data, the trajectory data including a trajectory for steering a downhole tool toward a downhole target, the downhole tool operating in a borehole within an earth formation. The method includes identifying downhole tool data for the downhole tool. The method includes, based on the trajectory and the downhole tool data, predicting one or more engineering metrics associated with an implementation of the trajectory. The method includes determining a coherency for the trajectory including determining whether the engineering metrics are within one or more predetermined thresholds. The method includes generating a report of at least some of the one or more engineering metrics including a value of each engineering metrics and an indication of whether the value is within one or more of the predetermined thresholds. In some embodiments, the method may be performed by a system. In some embodiments, the method may be implemented as instructions stored on a computer-readable storage medium.
This summary is provided to introduce a selection of concepts that are further described in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.
In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:
This disclosure generally relates to systems and methods for determining and validating trajectories for a downhole (e.g., drilling) system. For example, a downhole steering system may be implemented on one or more computing devices associated with the downhole system. The downhole steering system may receive sensor data from one or more downhole sensors and may generate a model of the subsurface geology of an earth formation. Based on the model, the downhole system may identify one or more downhole targets and/or may determine one or more trajectories for reaching the downhole target(s) with a downhole tool.
The downhole steering system may receive downhole tool data which may identify various properties, configurations, and limits of the downhole tools, among other information. Based on the downhole tool data, the downhole steering system may determine one or more engineering metrics associated with an (e.g., potential) application of the downhole tool in accordance with the trajectory. The downhole steering system may verify a coherency of the trajectory with one or more downhole subsystems or plans of the downhole system. This may include verifying whether the engineering metrics are within one or more predetermined thresholds. Based on validating the trajectory, the downhole system may generate a report. The report may include the trajectory along with the associated engineering metrics and an indication of whether the engineering metrics are within the predetermined thresholds. In some embodiments, the downhole steering system facilitates implementing the trajectory in connection with an operation of the downhole system.
As will be discussed in further detail below, the present disclosure includes a number of practical applications having features described herein that provide benefits and/or solve problems associated with determining a trajectory for a downhole tool. Some example benefits are discussed herein in connection with various features and functionalities provided by a downhole steering system implemented on one or more computing devices. It will be appreciated that benefits explicitly discussed in connection with one or more embodiments described herein are provided by way of example and are not intended to be an exhaustive list of all possible benefits of the downhole steering system.
For example, geosteering of a downhole tool generally involves a geoscience team analyzing expected features of the formation and predicting the features ahead of the bit. The system described generates and evaluates a geological model based on real-time data to analyze the subsurface geology of an earth formation ahead of the downhole tool. This allows the downhole steering system to accurately and efficiently identify the most promising zones for hydrocarbon production in order to determine the best trajectory for the downhole tool to reach these zones. By measuring and analyzing factors such as structural and stratigraphic features of the target zone, properties of the rock formations, geological risks and uncertainties associated with the drilling operation, the downhole steering system can facilitate making informed decisions about the trajectory in real time and based on actual geological conditions encountered during drilling. By continuously updating the trajectory planning as the drilling progresses, the downhole steering system can facilitate a more efficient operation of the downhole system by ensuring that the position of a downhole tool is maintained within productive and stable formations.
In addition to forward planning generally, the downhole steering system may generate detailed (e.g., 3D) models of the formation in order to plan an optimal path for the wellbore. Respective detailed models may be generated based on a variety of data sources including downhole sensor data, offset well data, 3D seismic cube and facies distribution, geological maps, etc. Based on this data, the downhole steering system may create a detailed model of the subsurface geology including the location and characteristics of underground reservoirs, faults, and other geological features. The mapping and visualization of the subsurface geology may be leveraged to achieve increased efficiency and accuracy in wellbore planning.
Additionally, the downhole steering system may facilitate incorporating interdisciplinary considerations into wellbore planning. For example, based on the model, the downhole steering system may simulate various drilling scenarios in order to evaluate the performance of a candidate trajectory with respect to different drilling strategies (e.g., with respect to sub-components of the drilling plan). For example, the downhole steering system may simulate a candidate trajectory with respect to the location of the reservoir, geological risks, environmental considerations, drilling equipment to be used, casing and completion design, etc. Conventionally, wellbore planning and subsequent validation for interdisciplinary considerations are performed as discrete processes that may take a considerable amount of time and correspondence between personnel of the various disciplines. By incorporating trajectory planning and coherency validation into one workflow, the downhole steering system enhances collaboration and enables multidisciplinary experts to work more effectively to design wellbore trajectories. This substantially changes and improves the way that well paths are planned and designed, as candidate trajectories can be more efficiently selected and implemented, all while increasing accuracy, safety, and performance of the wellbore.
In one example, trajectory planning and engineering validation is incorporated into a single workflow. As candidate trajectories may be determined in real time based on the real time updates of the geological model, the downhole steering system may provide near-real time validation of engineering metrics associated with the candidate trajectories. For example, the downhole steering system may apply a model to accurately predict engineering metrics for the candidate trajectories in the context of the earth model in 60 seconds or less, providing an effective solution for efficiently determining and implementing trajectory changes to the downhole operation. In this way, candidate trajectories may quickly and accurately be simulated and evaluated to ensure coherency with operational limits of the downhole tools. This facilitates quick and easy validation and authorization by drilling engineers as opposed to, for example, conventional methods which rely on engineering experts to model and evaluate candidate trajectories to ensure coherency with the drilling tools.
Additionally, the downhole steering system may be implemented across one or more cloud devices in order to leverage cloud computing resources for implementing sophisticated models to accurately and efficiently predict performance (e.g., engineering metrics). The disaggregation of the downhole steering system to the cloud may also further facilitate the collaboration of the downhill steering system with other systems and domains for coherency determination with those systems and domains.
Additional details will now be provided regarding systems described herein in relation to illustrative figures portraying example implementations. For example,
The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 further includes additional downhole drilling tools and/or components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.
The BHA 106 may include the bit 110, other downhole drilling tools, or other components. An example BHA 106 may include additional or other downhole drilling tools or components (e.g., coupled between to the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing.
In general, the downhole system 100 may include other downhole drilling tools, components, and accessories such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the downhole system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106, depending on their locations in the downhole system 100.
The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to the surface, or may be allowed to fall downhole. The bit 110 may include one or more cutting elements for degrading the earth formation 101.
The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, and/or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory. The RSS may steer the bit 110 in accordance with or based on a trajectory for the bit 110. For example, a trajectory may be determined for directing the bit 110 toward one or more subterranean targets such as an oil or gas reservoir.
The downhole system 100 may be operated in accordance with a drilling plan. For example, a drilling plan may include instructions, plans, procedures, designs, objectives etc. for directing the operation of the various subsystems, processes, and objectives of the downhole system 100. The downhole system 100 may include one or more client devices 112 with a downhole steering system 120 implemented thereon (e.g., implemented on one, several, or across multiple client devices 112). The downhole steering system 120 may facilitate determining and incorporating one or more changes to the drilling plan. For example, the downhole steering system 120 may determine and incorporate one or more trajectories for steering the bit 110 (or other downhole tool).
The client device 112 may refer to various types of computing devices. For example, one or more client devices 112 may include a mobile device such as a mobile telephone, a smartphone, a personal digital assistant (PDA), a tablet, a laptop, or any other portable device. Additionally, or alternatively, the client devices 112 may include one or more non-mobile devices such as a desktop computer, server device, surface or downhole processor or computer (e.g., associated with a sensor, system, function, etc. of the downhole system), or other non-portable device. In one or more implementations, the client devices 112 include graphical user interfaces (GUI) thereon (e.g., a screen of a mobile device). In addition, or as an alternative, one or more of the client devices 112 may be communicatively coupled (e.g., wired or wirelessly) to a display device having a graphical user interface thereon for providing a display of system content. The server devices(s) 114 may similarly refer to various types of computing devices. Each of the devices of the environment 200 may include features and functionalities described below in with
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By way of example, one or more of the data receiving, gathering, and/or storing features of the data manager 122 may be delegated to other components of the downhole steering system 120. As another example, while verification and validation of engineering metrics may be performed by a coherency manager 128, in some instances, some or all of these features may be performed by a report engine 130 (or other component of the downhole steering system 120). Indeed, it will be appreciated that some or all of the specific components may be combined into other components and specific functions may be performed by one or across multiple of the components 122-124 of the downhole steering system 120.
Additionally, while
In some embodiments, operating of a downhole system (e.g., drilling) is performed in accordance with a drilling plan 154. The drilling plan 154 may be a comprehensive plan outlining the objective, procedures, and logistics for the downhole system. The drilling plan 154 may include instructions, directions, procedures, designs, strategies, etc. to plan for the various subsystems, processes, and operations of the downhole system. For example, the drilling plan 154 may include details regarding the configurations of downhole tools (e.g., BHA) to be implemented, and may inform an operation of the downhole tools. The drilling plan 154 may include details regarding the earth formation and maintaining a structural integrity of the wellbore. The drilling plan 154 may include details regarding completion strategies, casing design, recovery techniques, or any other subsystem, process, or operation of the downhole system. In this way, the drilling plan 154 may serve as a roadmap and/or a guide for the steps to be followed, equipment to be used, and safety protocols to follow throughout the downhole operation, among other considerations.
In some embodiments, the downhole steering system 120 facilitates determining and incorporating changes to the drilling plan 154. For example, as described herein, the downhole steering system 120 may determine one or more candidate trajectories for steering a downhole tool. The downhole steering system 120 may predict one or more engineering metrics for validating a coherency of the trajectories with the various sub-plans of the drilling plan 154 associated with different downhole subsystems or domains of the downhole system. The downhole steering system 120 may incorporate a new trajectory into the drilling plan 154 in order that the trajectory may be implemented in the downhole system.
As mentioned above, the downhole steering system 120 includes a data manager 122. The data manager 122 may receive and manage a variety of types of data of the downhole steering system 120. For example, as shown in
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The trajectory manager 124 may model the earth formation based on the sensor data. For example, measurements from gamma ray sensors, resistivity sensors, neutron density sensors, porosity sensors, acoustic sensors, etc. may facilitate identifying, locating, and measuring subsurface features in order that the trajectory manager 124 may model them. The trajectory manager 124 may incorporate any of the formation data (e.g., surveys, maps, offset well data etc.) in order to model the earth formation. In some embodiments, the trajectory manager 124 incorporates user input, or any other data in order to model the earth formation.
Modeling the earth formation may facilitate the trajectory manager 124 identifying one or more downhole targets, as well as properties of those downhole targets. For example, an objective of the downhole system may be to locate, access, and recover hydrocarbons, and the trajectory manager 124 may identify a subsurface hydrocarbon reservoir as a target for the downhole system to reach. The trajectory manager 124 may identify one or more properties of the reservoir such as the boundaries (e.g., upper, lower, lateral) of the reservoir, the makeup of the reservoir, the location and composition of fluids (e.g., hydrocarbons, water, etc.) in the reservoir, or any other property. The trajectory manager 124 may identify properties of the formation surrounding the reservoir, such as the material and makeup up of the surrounding rock. The trajectory manager 124 may incorporate user input, for example, from a geoscientist, geomechanical engineer, or other relevant expert or operator in order to model and identify downhole targets and associated properties. In this way, the trajectory manager 124 may identify a downhole target such as a hydrocarbon reservoir and may also identify properties of the target in order to facilitate making steering decisions with respect to the target.
In some embodiments, the trajectory manager 124 determines a trajectory for a downhole tool to reach and or access a downhole target. For example, based on the model (and more specifically, the identified properties associated with a downhole target represented in the model), the trajectory manager 124 may identify promising zones for hydrocarbon production and may determine an optimal well path for a downhole tool to enter, traverse, access, or remain within those target zones. The trajectory manager 124 may incorporate various considerations when determining the trajectory, such as the location of the reservoir, structural and stratigraphic features of the target zones, properties of the rock formations, geological risks and uncertainties associated with the reservoir, the drilling equipment to be used, environmental considerations, an overall strategy or plan of the downhole system, other wellbores accessing the reservoir, or any other consideration, and combinations thereof. The trajectory manager 124 may determine the trajectory based on the model and/or any of the data accessible to the downhole steering system 120.
In some embodiments, the trajectory manager 124 incorporates the trajectory into the model. For example, as shown in
As mentioned above, the trajectory manager 124 may model the formation based on sensor data received, for example, by the data manager 122. In some embodiments, the sensor data is measured and received continuously and in real time. For example, the various sensors (e.g., associated with MWD and LWD tools) may take and record measurements every 1-3 seconds. The data manager 122 may continuously receive and update the trajectory data 138 in the data storage 136. In some embodiments, the trajectory manager 124 periodically updates the model based on the real time, updated trajectory data 138. In this way, the model may continually present a detailed, real-time representation of the formation that the downhole tools are encountering or will encounter. More specifically, the model may represent a real-time, updated view of the formation ahead of the downhole tools. This may facilitate making informed, real-time decisions regarding the trajectory of the downhole tools. For example, the trajectory manager 124 may determine a trajectory based on the predicted or expected properties of the formation represented in the model, and based on updates or changes in the model, the trajectory manager 124 may update or determine a new trajectory to reflect the geological conditions the downhole tool will encounter based on the updated model. By determining a trajectory and continuously updating it as drilling progresses, the downhole steering system 120 may facilitate maintaining the well path within a reservoir. This functionality may minimize the risk of drilling into unproductive or unstable formations. In this way, the downhole steering system 120 may provide real-time, forward planning for determining a trajectory for a downhole tool to reach a target.
In some embodiments, the trajectory manager 124 determines multiple candidate trajectories. For example, based on the model and the geological conditions at the location of the downhole tool, there may be several viable well paths for obtaining a downhole target. The trajectory manager 124 may accordingly determine several candidate trajectories as options for proceeding to or within the target. For example, the trajectory manager may determine candidate trajectories having different depths, inclinations, azimuths, angles, dog leg severities (DLS), and combinations thereof. The trajectory manager 124 may model these candidate trajectories, either separately (e.g., in separate instances of the model) or together within a same model.
The trajectory manager 124 determining several candidate trajectories may facilitate selecting a trajectory based on the trajectory being coherent with other subsystems or domains of the downhole system. For example, a candidate trajectory determined by the trajectory manager 124 to be optimal for accessing a reservoir may not be feasible, possible, or desirable to implement when considering mechanical and dynamic factors of the downhole system (e.g., dynamics on the downhole tools). In another example, an optimal candidate trajectory may not be consistent with a completion or production plan of the downhole system. The trajectory manager 124 providing several candidate trajectories for coherency validation against the other domains of the downhole system may facilitate more efficiently selecting a trajectory that is overall the most optimal for achieving the objectives of the downhole system. Additionally, the trajectory manager 124 may continually provide updated or new sets of candidate trajectories in order to achieve the benefits of the real-time forward planning discussed above. The trajectory manager 124 may store any of a selected trajectory, candidate trajectory, formation model, and trajectory model to the data storage 136 as trajectory data 138.
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In some embodiments, the engineering manager 126 determines the engineering metrics in real-time for representing a present or current condition of the downhole system. For example, the engineering manager 126 may receive sensor data from one or more downhole sensors and may calculate one or more of the engineering metrics based on the sensor data. In this way, the engineering metrics may represent a present state of the downhole system.
In some embodiments, the engineering manager 126 predicts the engineering metrics, or determines the engineering metrics for a future or a proposed operation of the downhole tools. For example, in some embodiment the engineering manager 126 receives the trajectory data 138 including one or more candidate trajectories for implementing in connection with the downhole tools. Based on the candidate trajectory(s), the engineering manager 126 may predict the engineering metrics in order to simulate the dynamics and/or conditions that the downhole tools will encounter for a given trajectory. The engineering manager 126 may incorporate any of the data accessible to the downhole steering system 120 to predict the engineering metrics. For example, the engineering manager 126 may incorporate the tool data, the formation data, the sensor data, and/or user input described herein (and combinations thereof). In this way, the engineering manager 126 may simulate the downhole tools implementing one or more trajectories in order to predict how the downhole system will behave and respond.
The engineering manager 126 may implement any of a variety of techniques for predicting the engineering metrics. For example, the engineering manager 126 may implement one or more algorithms for outputting one or more engineering metrics based on input data (e.g., based on the trajectory data, tool data, etc.). Additionally or alternatively, the engineering manager 126 may implement one or more machine learning models trained to predict specific engineering metrics based on specific input data. For example, the engineering manager 126 may apply a machine learning model to a candidate trajectory identified in the trajectory data 138. The engineering manager 126 may input or incorporate tool data and formation data which may define relevant properties and parameters of the downhole tools and of the formation. The machine learning model may be trained to predict, based on these inputs, one or more engineering metrics such as torque and drag, bending stress, or surface torque (or any other parameter) that the downhole tools will experience by implementing the candidate trajectory defined in the trajectory data 138. The engineering manager 126 predicting the engineering metrics for a given trajectory in this way may facilitate validating the coherency of the trajectory with one or more engineering limits or thresholds associated with the downhole system.
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In accordance with at least one embodiment of the present disclosure, the coherency manager 128 may verify that the trajectory is consistent with an engineering plan for an engineering domain of the drilling plan 154. The engineering plan may include or define one or more thresholds or engineering limits for various components of the downhole system. In some embodiments, the engineering limits are associated with operational limits or factors of safety limits, for example, within which a component may operate without failing or yielding. For example, the engineering plan may define a threshold or acceptable amount of torque for a component to experience. In another example, the engineering plan may define a threshold or acceptable amount of drag that a component may experience. The engineering plan may define a threshold or acceptable amount of bending, stress, strain, pressure, vibration, DLS, inclination, or azimuth, that a component may experience, or any other dynamic or property consistent with the present disclosure. In some embodiments, the engineering limits include one or more user-defined limits. For example, the engineering plan may define a minimum distance to be maintained from a geological feature, nearby wellbore, or any other point of reference. In some embodiments, the engineering plan includes or defines one or more thresholds or engineering limits for the wellbore, such as structural limits to prevent collapse of the wellbore. The engineering limits may include any other limits consistent with the present disclosure. In this way, the engineering plan may define one or more limits for the use and operation of one or more components to ensure that the downhole system may function properly and efficiently.
In some embodiments, one or more of the thresholds or engineering limits correspond to the engineering metrics determined or predicted by the engineering manager 126. The coherency manager 128 may determine whether each of the engineering metrics is within a corresponding engineering limit of the engineering plan. For example, the coherency manager 128 may analyze the engineering metrics predicted by the engineering manager 126 corresponding to a candidate trajectory determined by the trajectory manager 124. The coherency manager 128 may thereby determine whether each of the predicted engineering metrics is within the engineering limits defined by the engineering plan. The coherency manager 128 may save these determinations to the data storage 136 as part of the report data 144.
In some embodiments, in addition to determining whether the engineering metrics are within the engineering limits, the coherency manager 128 generates an electronically generated flag, or an indication that may be stored and retrieved, associated with each engineering metric in relation to the associated limit. For example, the coherency manager 128 may determine that an engineering metric is within a corresponding engineering limit and may accordingly generate a positive or good flag, or indication corresponding with the positive or good nature of engineering metric. The positive indication may be an indication incorporated in the report data 144, or may be a visual representation presented in connection with a graphical representation of the report data as discussed herein below. The positive indication may be a check, green flag, or other similar indication to proceed. In another example, the coherency manager 128 may determine that an engineering metric is not within a corresponding engineering limit and may accordingly generate a bad or negative flag, or indication corresponding with the bad or negative nature of the engineering metric. The negative indication may similarly be an indication incorporated in the report data 144, or may be a visual representation presented in connection with the graphical representation of the report data as discussed herein below. The negative indication may be an X, red flag, or other similar indication to stop or not proceed. In another example, the coherency manager 128 may determine that an engineering metric is within a corresponding engineering limit, but is close to or within a threshold range of the limit. The coherency manager 128 may accordingly generate a warning flag, or warning indication corresponding with the engineering metric being close to the limit. The warning indication may similarly be an indication incorporated in the report data 144 or may be a visual representation presented in connection with the graphical representation of the report data as discussed herein below. The warning indication may be an “!”, yellow flag, or other similar indication to proceed with caution. The warning indication may be stored in a payload portion of a data flag data packet and retrieved to present the warning indication. In this way, the coherency manager 128 may provide a simple indication of the nature of the engineering metrics with respect to the engineering limits, as well as the associated value of the engineering metrics. This may facilitate, for example, more efficiently determining the coherency of a corresponding trajectory with the engineering plan.
As discussed herein, the engineering data 140 may include engineering metrics associated with a set of multiple candidate trajectories for implementation in the downhole system. In accordance with that just discussed, the coherency manager 128 may determine whether the engineering metrics are within the engineering limits for each of the candidate trajectories. Additionally, the coherency manager 128 may generate flags or indications associated with the engineering metrics for each of the candidate trajectories. In this way, the coherency manager 128 may facilitate determining a coherency of multiple candidate trajectories with the engineering plan. Additionally, the coherency manager 128 analyzing and determining all of this information at once for the multiple candidate trajectories may facilitate efficiently comparing the candidate trajectories in order to determine which candidate trajectory is most consistent with the drilling plan 154 and/or best suited for implementation in the downhole system.
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In some embodiments, the report engine 130 generates an engineering report based on the engineering data 140. For example, the report engine 130 may electronically generate and store the engineering report to be electronically retrieved and/or presented.
In some embodiments, the report engine 130 generates a report based on the trajectory data 138 the engineering data 140. For example,
In some embodiments, one or more of the features of the engineering manager 126, the coherency manager 128, and/or the report engine 130 are performed by or on a remote device. For example, some or all of these components may be implemented as a cloud computing function of the downhole steering system 120. This may facilitate providing additional resources (e.g., computing and/or memory resources) to the downhole steering system 120 for performing the features described herein that may not otherwise be available or feasible, for example, on a local client device. This may provide the benefit of utilizing sophisticated and/or resource heavy techniques such as machine learning models, in order to more accurately model the formation, predict the engineering metrics, verify coherency, etc. Additionally, disaggregating one or more components of downhole steering system 120 to the cloud, such as the coherency manager 128 may facilitate validating coherency between multiple downhole subsystems. For example, as discussed herein, the downhole steering system 120 may be implemented on one or more devices that are connected via a (e.g., cloud) network to other devices, and these other devices may be associated with other domains of the downhole system. The coherency manager 128 may communicate with these other downhole subsystems over the cloud, which may facilitate validating the coherency of a candidate trajectory with one or more of the downhole subsystems.
Further, implementing the downhole steering system 120 within a cloud infrastructure may provide additional efficiency benefits. For example, by disaggregating one or more components to the cloud, the downhole steering system 120 may quickly and efficiently perform the features and functionalities described herein, even those that are resource heavy (e.g., memory, storage, processing heavy). In some embodiments, the downhole steering system performs one or more functions in real time or near-real time. For example, as mentioned above, the trajectory manager 124 may continuously update and provide updated candidate trajectories in real time. The downhole steering system 120 may utilize cloud computing in order to provide the predicted engineering metrics, coherency validation, and/or report generation features in near-real time. For instance, in some embodiments, after determining one or more candidate trajectories, the downhole steering system 120 predicts the engineering metrics, validate coherency, and generate a report within 60 seconds or less. In some embodiments, the downhole steering system 120 performs these functions in less than 60 seconds, such as within 20, 30, 40, or 50 seconds. This may facilitate making near-real time informed decisions for operating the downhole system efficiently and effectively.
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As discussed above, the downhole steering system 120 may determine one or more candidate trajectories, predict engineering metrics for verifying a coherency of the candidate trajectories, and generate reports comparing the candidate trajectories. In some embodiments, the drilling plan manager 134 facilitates selecting a trajectory from the candidate trajectories. For example, based on the engineering metrics and/or the coherency associated with each candidate trajectory, the drilling plan manager 134 may determine which candidate trajectory is best suited for the downhole system in accordance with the drilling plan 154. In some embodiments, the drilling plan manager 134 makes this determination automatically. In some embodiments the drilling plan manager 134 makes this determination based on user input. For example, the drilling plan manager 134 may present any of the information discussed herein to a user and may prompt the user to select, one of the trajectories. In some embodiments, the drilling plan manager 134 selects a trajectory and prompts a user to approve or authorize the selection. Based on a selected trajectory (either automatically or with user input), the drilling plan manager 134 may update a steering plan of the drilling plan 154 with the new trajectory.
In some embodiment, the drilling plan manager 134 does not select a trajectory of the candidate trajectories. For example, in some situations the drilling plan manager 134 may determine that one or more of the candidate trajectories is not suitable for implementation in the downhole system. For instance, the coherency manager 128 may indicate that a trajectory is not coherent with the drilling plan 154 (e.g., with one or more downhole subsystem plans). In some instances, the coherency manager may indicate that some or all of the engineering metrics are not within the engineering limits. For example, one or more of the engineering metrics (or a given combination of engineering metrics) may be essential, and failure of the engineering metrics to meet the engineering limits may render the associated trajectory unacceptable. In some embodiments, the drilling plan manager 134 causes the downhole steering system 120 to determine one or more additional trajectories, and accordingly verify a coherency (e.g., predict corresponding engineering metrics) of the additional trajectory(s). The downhole steering system 120 may iterate this process until the drilling plan manager 134 determines that one or more trajectories are acceptable. In this way, the drilling plan manager 134 may facilitate selecting a trajectory for implementing in the downhole system.
In some embodiments, the drilling plan manager 134 facilitates implementing the trajectory. For example, the drilling plan manager 134 may generate one or more steps, procedures, or directions for operating the downhole system in accordance with the trajectory. For example, the drilling plan manager 134 may direct a depth, azimuth, inclination, or DLS for the downhole system to adjust the steering of a downhole tool. In some embodiments, the drilling plan manager 134 automatically adjusts the steering of the downhole tool. In some embodiments, the drilling plan manager 134 prompts or may provide instructions for a user or operator to adjust the steering of the downhole system. In this way, the drilling plan manager 134 may facilitate implementing a trajectory in order for the downhole system to reach a downhole target in accordance with the techniques discussed herein.
In some embodiments, the method 900 includes an act 910 of receiving trajectory data. The trajectory data may include a trajectory for steering a downhole tool toward a downhole target. For example, a downhole steering system may receive the trajectory data from one or more downhole sensors, from one or more downhole subsystems, from user input, or from a database maintained and accessible to the downhole steering system (and combinations thereof). In some embodiments, the downhole steering system receives formation data from one or more downhole sensors. The downhole steering system may receive the formation data in real time. The downhole sensors may include one or more LWD tools of the downhole system. The downhole sensors may include gamma ray sensors, resistivity sensors, neutron density sensors, porosity sensors, and acoustic sensors. Based on the formation data, the downhole steering system may generate a subsurface geology model for a subsurface geology in which the drilling tool is implemented. The downhole tool may operate in a borehole in an earth formation.
In some embodiments, the method 900 includes an act 920 of identifying downhole tool data for the downhole tool.
In some embodiments, the method 900 includes an act 930 of, based on the trajectory data and the downhole tool data, predicting one or more engineering metrics associated with an implementation of the trajectory. The engineering metrics may include one or more downhole tool metrics associated with an operation of the downhole tool in accordance with the trajectory. The engineering metrics may include one or more completion metrics associated with a completion of the borehole at the downhole target. The engineering metrics may additionally be determined based on the formation data.
In some embodiments, the method 900 includes an act 940 of determining a coherency for the trajectory including determining whether the engineering metrics are within one or more predetermined thresholds. In some embodiments, determining the coherency includes determining whether the trajectory is consistent with a completion plan for the borehole, and/or a casing plan and/or a BHA plan for the downhole system. In some embodiments, determining the coherency includes determining whether the trajectory is consistent with offset well data for an offset well.
In some embodiments, the method 900 includes an act 950 of generating a report of at least some of the one or more engineering metrics. The report may include an indication of the coherency of the trajectory. For example, the report may indicate a coherency of the trajectory in association with one or more downhole subsystems or domains of the downhole system, and/or in associated with the downhole system generally. The report may include a value of each engineering metric and an indication of whether the value is within one or more of the predetermined thresholds. In some embodiments, the report is presented via a GUI of a user device. For example, the report may include a graphical representation of the trajectory in connection with the associated engineering metrics. In some embodiments, the downhole steering system determines a plurality of trajectories, and the report may present (e.g., a graphical representation of) each of the plurality of trajectories. In some embodiments, the report presents the plurality of trajectories (and associated engineering metrics) on a same screen. This may facilitate comparing the trajectories.
In some embodiments, predicting the engineering metrics, determining the coherency, and generating the report are performed in near-real time, such as within 60 seconds or less. In some embodiments, one or more acts of the method 900 are performed while drilling with the downhole tool.
In some embodiments, the method 900 includes causing the trajectory to be implemented in connection with the downhole system, for example, based on determining that one or more of the engineering metrics are within the predetermined thresholds. The downhole steering system may indicate one or more instructions or details for adjusting the operation of the downhole system to incorporate the trajectory.
In some implementations, the downhole steering system may determine that one or more of the engineering metrics associated with the trajectory are not within the one or more predetermined thresholds, and the downhole system may determine a second trajectory for the downhole tool to reach the downhole target. The downhole steering system may predict one or more second engineering metrics for an application of the second trajectory including one or more second downhole tool metrics associated with an operation of the downhole tool in accordance with the second trajectory and one or more second completion metrics associated with a second completion of the borehole at the downhole target in accordance with the second trajectory. The downhole system may verify whether the second engineering metrics are within the one or more predetermined thresholds. The downhole system may generate a second report of at least some of the second engineering metrics including, for each of at least some of the second engineering metrics, a value of the engineering metric and an indication of whether the value is within the one or more predetermined thresholds. In some embodiments, report includes the second report. The method may further include implementing the second trajectory in connection with the downhole system.
Turning now to
The computer system 1000 includes a processor 1001. The processor 1001 may be a general-purpose single- or multi-chip microprocessor (e.g., an Advanced RISC (Reduced Instruction Set Computer) Machine (ARM)), a special purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc. The processor 1001 may be referred to as a central processing unit (CPU). Although just a single processor 1001 is shown in the computer system 1000 of
The computer system 1000 also includes memory 1003 in electronic communication with the processor 1001. The memory 1003 may include computer-readable media and can be any available media that can be accessed by a general purpose or special purpose computer system. Computer-readable media that store computer-executable instructions are non-transitory computer-readable media (device). Computer-readable media that carry computer-executable instructions are transmission media. Thus, by way of example and not limitations, embodiment of the present disclosure can comprise at least two distinctly different kinds of computer-readable media: non-transitory computer-readable media (devices) and transmission media.
Both non-transitory computer-readable media (devices) and transmission media may be used temporarily to store or carry software instructions in the form of computer readable program code that allows performance of embodiments of the present disclosure. Non-transitory computer-readable media may further be used to persistently or permanently store such software instructions. Examples of non-transitory computer-readable storage media include physical memory (e.g., RAM, ROM, EPROM, EEPROM, etc.), optical disk storage (e.g., CD, DVD, HDDVD, Blu-ray, etc.), storage devices (e.g., magnetic disk storage, tape storage, diskette, etc.), flash or other solid-state storage or memory, or any other non-transmission medium which can be used to store program code in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer, whether such program code is stored or in software, hardware, firmware, or combinations thereof.
Instructions 1005 and data 1007 may be stored in the memory 1003. The instructions 1005 may be executable by the processor 1001 to implement some or all of the functionality disclosed herein. Executing the instructions 1005 may involve the use of the data 1007 that is stored in the memory 1003. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 1005 stored in memory 1003 and executed by the processor 1001. Any of the various examples of data described herein may be among the data 1007 that is stored in memory 1003 and used during execution of the instructions 1005 by the processor 1001.
A computer system 1000 may also include one or more communication interfaces 1009 for communicating with other electronic devices. The communication interface(s) 1009 may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 1009 include a Universal Serial Bus (USB), an Ethernet adapter, a wireless adapter that operates in accordance with an Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, a Bluetooth® wireless communication adapter, and an infrared (IR) communication port.
The communication interfaces 1009 may connect the computer system 1000 to a network. A “network” or “communications network” may generally be defined as one or more data links that enable the transport of electronic data between computer systems and/or modules, engines, and/or other electronic devices. When information is transferred or provided over a communication network or another communications connection (either hardwired, wireless, or a combination of hardwired or wireless) to a computing device, the computing device properly views the connection as a transmission medium. Transmission media can include a communication network and/or data links, carrier waves, wireless signals, and the like, which can be used to carry desired program or template code means or instructions in the form of computer-executable instruction or data structures and which can be accessed by a general purpose or special purpose computer.
A computer system 1000 may also include one or more input devices 1011 and one or more output devices 1013. Some examples of input devices 1011 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices 1013 include a speaker and a printer. One specific type of output device that is typically included in a computer system 1000 is a display device 1015. Display devices 1015 used with embodiments disclosed herein may utilize any suitable image projection technology, such as liquid crystal display (LCD), light-emitting diode (LED), gas plasma, electroluminescence, or the like. A display controller 1017 may also be provided, for converting data 1007 stored in the memory 1003 into text, graphics, and/or moving images (as appropriate) shown on the display device 1015.
The various components of the computer system 1000 may be coupled together by one or more buses, which may include a power bus, a control signal bus, a status signal bus, a data bus, etc. For the sake of clarity, the various buses are illustrated in
The techniques described herein may be implemented in hardware, software, firmware, or any combination thereof, unless specifically described as being implemented in a specific manner. Any features described as modules, components, or the like may also be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be realized at least in part by a non-transitory processor-readable storage medium comprising instructions that, when executed by at least one processor, perform one or more of the methods described herein. The instructions may be organized into routines, programs, objects, components, data structures, etc., which may perform particular tasks and/or implement particular data types, and which may be combined or distributed as desired in various embodiments.
Further, upon reaching various computer system components, program code in the form of computer-executable instructions or data structures can be transferred automatically or manually from transmission media to non-transitory computer-readable storage media (or vice versa). For example, computer executable instructions or data structures received over a network or data link can be buffered in memory (e.g., RAM) within a network interface module (NIC), and then eventually transferred to computer system RAM and/or to less volatile non-transitory computer-readable storage media at a computer system. Thus, it should be understood that non-transitory computer-readable storage media can be included in computer system components that also (or even primarily) utilize transmission media.
The following are example embodiments of the downhole steering system as described herein, and are non-limiting.
The embodiments of the downhole steering system have been primarily described with reference to wellbore drilling operations; the downhole steering system described herein may be used in applications other than the drilling of a wellbore. In other embodiments, the downhole steering system according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, the downhole steering system of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.
One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.
A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.
The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.
The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.
