SYSTEMS AND METHODS FOR DETECTING DRILL BREAK

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. Provisional Patent Application No. 63/643,468, filed on May 7, 2024, which are hereby incorporated by reference in their entireties.

BACKGROUND

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.

Downhole tools may encounter and progress through a variety of different formations during a downhole operation. Different formations may exhibit different physical properties, and the downhole system may need to be adjusted based on the different formation in order to operate efficiently and safely. Additionally, certain subterranean targets or resources may be located within specific formations. Thus, it may be advantageous to identify when a downhole tool transitions from one formation to the next.

SUMMARY

In some embodiments, a method of determining drill break of a downhole system includes receiving downhole data associated with a downhole tool implemented in a wellbore, the downhole data including rate of penetration (ROP) data of the downhole tool. The method further includes, based on the downhole data, determining a baseline ROP. The method further includes identifying a threshold change of the ROP data from the baseline ROP, wherein the threshold change is based on a dynamic threshold. The method further includes generating an indication of the threshold change. In some embodiments, the method may be implemented by a system. In some embodiments, the method may be performed as instructions included in 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.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other features of the disclosure may 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:

FIGS. 1-1 and 1-2 are examples of a downhole system, according to at least one embodiment of the present disclosure;

FIG. 2-1 illustrates an example environment in which a drill break system is implemented, according to at least one embodiment of the present disclosure;

FIG. 2-2 illustrates an example implementation of a drill break system as described herein, according to at least one embodiment of the present disclosure;

FIG. 3 is an example of downhole data, according to at least embodiment of the present disclosure;

FIGS. 4-1 through 4-4 illustrate examples of baseline ROP and localized average ROP, according to embodiments of the present disclosure;

FIG. 5 illustrates example downhole data in association with the drill break system identifying a drill break, according to at least one embodiment of the present disclosure;

FIG. 6 illustrates a flow diagram for a method of a series of acts for determining drill break as described herein, according to at least one embodiment of the present disclosure; and

FIG. 7 illustrates certain components that may be included within a computing system.

DETAILED DESCRIPTION

This disclosure generally relates to systems and methods for determining drill breaks of a downhole system. A computer implemented drill break system receives downhole data including, among others, rate of penetration data. The downhole data may also include flow rate data, torque data, weight on bit data, and depth data. Based on the downhole data, the drill break system determines that the downhole system is operating in a drilling state. For example, the drill break system determines that some or all of the downhole data is substantially constant and/or determines that specific types of the downhole data, such as the torque data, the weight on bit data, etc., are operating at values consistent with the drilling state of the downhole system.

Based on determining that the downhole system is drilling, the drill break system determines a baseline rate of penetration, representing an average or expected rate of penetration for the downhole system. The drill break system monitors the rate of penetration data against the baseline rate of penetration to identify any changes to the rate of penetration data that indicate drill break. For example, the drill break system may determine a localized average rate of penetration for comparing against the baseline rate of penetration.

The drill break system may identify drill break based on the localized average rate of penetration exhibiting a threshold change with respect to the baseline rate of penetration. The threshold change may be based on a dynamic threshold of the localized average rate of penetration. For example, the threshold change may dynamically change depending on the underlying baseline rate of penetration. For instance, for a relatively low baseline rate of penetration the dynamic threshold may require a more substantial change to the localized average rate of penetration than for a relatively high baseline rate of penetration. In this way, the dynamic threshold may be applicable for identifying drill break, but may adapt to different downhole conditions, circumstances, or drilling parameters which may exhibit different baseline rates of penetration.

The drill break system may generate an indication of the drill break, such as a flag, alert, data object etc. In some embodiments, the drill break system may cause one or more drilling parameters to be adjusted based on the downhole system encountering a different formation and/or may cause one or more additional measurements to be taken.

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 identifying drill breaks. Some example benefits are discussed herein in connection with various features and functionalities provided by a drill break 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 drill break system.

In many cases, it may be difficult, to identify transitions of the downhole system between formations. For example, downhole tools may be implemented a significant distance below the earth, and communication with the downhole tools may be limited. Additionally, in many cases, detailed information about the formations and/or makeup of the earth through which a downhole tool is progressing may not be available or may be unreliable. The drill break system described herein may determine drill break based on information that is generally readily available at the surface of a wellbore. For example, the drill break system may identify drill break based on identifying changes in rate of penetration, which is a metric that may be observed based on the rotation imparted by the drill rig at the surface. This may facilitate not only determining drill break more efficiently and in a simple manner, but may also allow for the techniques described herein to be performed in real time such that informed decisions may be made in a timely manner with respect to the operation of the downhole system. Further, the drill break system may accurately identify drill break without relying on formation evaluation information such as formation logs, 3D models, seismic data, etc., which may often not be available. Indeed, the drill break system may automatically identify and indicate transitions between formations without user input, offering significant advantages over conventional techniques which may employ experienced and skilled drilling engineers to read and interpret data to identify drill breaks.

Additionally, the drill break system identifies drill breaks based on identifying threshold changes in the rate of penetration data with a dynamic threshold. The dynamic threshold may dictate or define different thresholds for different downhole situations and circumstances. For instance, the dynamic threshold may incorporate the relationship that for low rates of penetration, a larger change may be required to accurately determine drill break while at higher rates of penetration, drill breaks may be identified based on smaller changes. In contrast, conventional techniques may identify drill break based on inaccurate heuristics such as based on a static threshold that is the same for any and all behaviors of the downhole system.

Further, identifying drill breaks may facilitate operating the downhole system in an efficient and safe manner. For instance, identifying positive and/or negative drill breaks, corresponding to transitions to softer and/or harder formations may inform the parameters with which to operate the downhole system, what operations to perform, how to steer a downhole tool etc. Indeed, certain types of formations may be associated with pay zones, underground reservoirs, or other resources or targets, and by identifying transitions to certain formation the downhole system may be effectively operated to reach or access these targets. Further, in many cases, certain formations such as softer formations may be associated with pressure fluctuations, fluid influxes, well control issues, and other risks which require timely action to avoid catastrophic results. Thus, by identifying when transitions to these formations occur, the drill break system may facilitate taking remedial actions to operate the downhole system safely and effectively.

Additional details will now be provided regarding systems described herein in relation to illustrative figures portraying example implementations. For example, FIG. 1-1 shows one example of a downhole system 100 for drilling an earth formation 101 to form a wellbore 102. The downhole system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110, attached to the downhole end of the drill string 105.

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 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 111 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 one or more of gravity, magnetic north, 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 include or may be associated with a client device 112 with a drill break system 120 implemented thereon (e.g., or with a client application implemented thereon for accessing the drill break system 120 as described herein). The drill break system 120 may facilitate identifying or detecting drill breaks of the downhole system 100, such as when the BHA 106, the bit 110, etc. encounters a sudden change between formations exhibiting different properties.

For example, while performing a downhole operation, the bit 110 (e.g., and the BHA 106) may encounter several different formations. For instance, as shown in FIG. 1-2, the bit 110 may encounter and/or progress through a first formation 113-1 and a second formation 113-2. The bit 110 may progress through any number of formations. The various formations may be different formations with different physical properties, different dimensions, may contain different downhole targets or resources, etc. For instance, different downhole tools and/or different drilling parameters may be implemented for different formations. In another example, certain formations may be associated with downhole resources such as a subterranean reservoir. Thus, it may be advantageous to identify when the bit 110 passes from one formation to the next.

The drill break system 120 as described herein may be implemented to facilitate determining when the bit 110 encounters a transition from one formation to another. For instance, a third formation 113-3 may be positioned below or adjacent to the second formation 113-2. The bit 110 may progress through the second formation 113-2 and the drill break system 120 may identify when the bit 110 passes from the second formation 113-2 to the third formation 113-3. For example, the drill break system 120 may identify that a sudden change in the rate of penetration (ROP) of the bit 110 is a result of a change in formation. The change may be of a threshold amount, which may be a dynamic or changing threshold as described herein. In this way, the drill break system 120 may facilitate quickly identifying drill break in order that appropriate action may be taken. As used herein, a “drill break” is intended to refer to a sudden observable change in the behavior of a downhole tool (e.g., in rate of penetration) indicating that the downhole tool is or has transitioned from one formation to another.

FIG. 2-1 illustrates an example environment 200 in which a drill break system 120 is implemented in accordance with one or more embodiments describe herein. As shown in FIG. 2-1, the environment 200 includes a server device 114. The server device 114 may include one or more computing devices (e.g., including processing units, data storage, etc.) organized in an architecture with various network interfaces for connecting to and providing data management and distribution across one or more client systems. As shown in FIG. 2-1, the server device 114 may be connected to and may communicate with (either directly or indirectly) a client device 112 through a network 116. The network 116 may include one or multiple networks and may use one or more communication platforms and/or technologies suitable for transmitting data. The network 116 may refer to any data link that enables transport of electronic data between devices of the environment 200. The network 116 may refer to a hardwired network, a wireless network, or a combination of a hardwired network and a wireless network. In one or more embodiments, the network 116 includes the internet. The network 116 may be configured to facilitate communication between the various computing devices via well-site information transfer standard markup language (WITSML) or similar protocol, or any other protocol or form of communication.

The client device 112 may be representative of one or multiple client devices, and may refer to various types of computing devices. For example, the client device 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 device 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, or function of the downhole system), or other non-portable device. In one or more implementations, the client device 112 includes 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 device 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 device 114 may similarly refer to various types of computing devices. Each of the devices of the environment 200 may include features and/or functionalities described below in connection with FIG. 7.

As shown in FIG. 2-1, the environment 200 may include a drill break system 120 implemented on the server device 114. While shown on the server device 114, the drill break system 120 may be implemented wholly or in part on the client device 112, across the server device 114 and the client device 112, or on or across one or more additional devices, such that different portions or components of the drill break system 120 are implemented on different computing devices in the environment 200. The client device 112 may include a client application 118. The client application 118 may include an application or interface for interacting with and/or receiving the features of the drill break system 120 as described herein. In some embodiments, one or more of the functionalities or features of the drill break system 120 may be carried out or performed on or by the client application 118. In this way, the environment 200 may be a cloud computing environment, and the drill break system 120 may be implemented across one or more devices of the cloud computing environment in order to leverage the processing capabilities, memory capabilities, connectivity, speed, etc., that such cloud computing environments offer in order to facilitate the features and functionalities described herein.

FIG. 2-2 illustrates an example implementation of the drill break system 120 as described herein, according to at least one embodiment of the present disclosure. The drill break system 120 may include a data manager 122, a ROP manager 124, and a threshold manager 126. The drill break system 120 may also include a data storage 130 having downhole data 132 and drill break indications 134 stored thereon. While one or more embodiments described herein describe features and functionalities performed by specific components 122-126 of the drill break system 120, it will be appreciated that specific features described in connection with one component of the drill break system 120 may, in some examples, be performed by one or more of the other components of the drill break system 120.

By way of example, one or more of the data receiving, gathering, or storing features of the data manager 122 may be delegated to other components of the drill break system 120. As another example, while one or more dynamic thresholds may be determined and monitored by the threshold manager 126, in some instances, some or all of these features may be performed by the ROP manager 124 (or other component of the drill break 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 components 122-126 of the drill break system 120.

Additionally, while FIG. 1-1, for example, depicts the drill break system 120 implemented on a client device 112 of the downhole system, it should be understood that some or all of the features and functionalities of the drill break system 120 may be implemented on or across multiple client devices 112 and/or server devices 114. For example, data may be input and/or received by the data manager 122 on a (e.g., local) client device, and the determinations of drill break may be performed on one or more of a remote, server, or cloud device. Indeed, it will be appreciated that some or all of the specific components 122-126 may be implemented on or across multiple client devices 112 and/or server devices 114, including individual functions of a specific component being performed across multiple devices.

As mentioned above, the drill break system 120 includes a data manager 122. The data manager 122 may receive a variety of types of data associated with the downhole system and may store the data to the data storage 130. The data manager 122 may receive the data from a variety of sources, such as from sensors, surveying tools, downhole tools, other (e.g., client) devices, libraries, databases, user input, etc.

In some embodiments, the data manager 122 receives downhole data 132. The downhole data 132 may include measurements associated with a downhole tool implemented in wellbore. For example, the downhole data 132 may include measurements taken downhole by one or more downhole sensors. The downhole data 132 may include data taken at the surface.

In some embodiments, the downhole data 132 includes measurements related to drilling parameters or a downhole behavior of a downhole too. For instance, the downhole data 132 may include ROP data. The ROP data may be measured (e.g., directly) by a downhole tool, or may be determined or inferred from the surface. For example, the downhole data 132 may include block position data of a block of a drill rig. Based on a position or movement of the block, the data manager 122 may generate the ROP data for representing the rate at which a downhole tool is progressing (e.g., drilling) through the earth. In some embodiments, the ROP data may indicate an instantaneous ROP of the downhole tool. In some embodiments the ROP data my indicate one or more average ROPs of the downhole tool, such as a baseline ROP and/or a localized average ROP as described herein. In this way, the ROP data may indicate an instantaneous and/or historic characterization of a behavior of a downhole tool with respect to a formation. For example, in many cases, the ROP may be related to and/or influenced by a formation in which the downhole tool is positioned. For example, a relatively low ROP may correspond with the downhole tool progressing through a harder and/or stronger formation, and a relatively high ROP may correspond with the downhole tool progressing through a softer and/or weaker formation. In this way, the ROP data may be useful for characterizing a formation of a wellbore and/or for identifying a transition to a different formation, as described herein.

In some embodiments, the downhole data 132 includes measurements of other drilling parameters. For example, the downhole data 132 may indicate weight on bit (WOB) data of the downhole tool. The WOB data may be (e.g., directly) measured by a downhole sensor, or may be determined or inferred from surface measurements, such as a hookload. In some embodiments, the downhole data 132 includes torque data indicating a level of torque imparted on the downhole tool and/or imparted by the downhole tool to form the wellbore. The torque data may be measured by a downhole sensor, or may be determined based on a surface torque applied at the drill rig. In some embodiments, the downhole data 132 includes a flow rate and/or a pressure of drilling mud and/or hydraulic fluids. In some embodiments, the downhole data 132 includes measures of other drilling parameters such as a surface rotational speed (RPM), a downhole RPM, temperatures, pressures, or any other relevant drilling parameters. The downhole data 132 may indicate current and/or past measurement depths (MDs) of the downhole tool. For instance, the downhole tool may measure and/or track a distance which it has traveled beneath and/or through the earth, or the MD may be determined, calculated, and/or inferred by surface components based on one or more other measurements. In some embodiments, the downhole data 132 may include sensor and/or measurement data from MWD tools, LWD tools, and/or one or more other downhole tools or subs. For example, the downhole data 132 may include resistivity measurements, porosity measurements, gamma ray measurements, acoustic measurements, electromagnetic measurements, etc. In this way, the data manager 122 may receive, collect, and maintain the downhole data 132, which may include a variety of measurements associated with a position, operation, behavior, performance, etc. of the downhole tool in order to facilitate the drill break detection functionalities described herein.

In some embodiments, one or more values or measurements from one or more of the sources of data that the data manager 122 receives or has access to may be incomplete, may be missing, or may otherwise not be available. For instance, one or more signals or data channels may become interrupted, lost, distorted, or may otherwise not be available, either temporarily or permanently. The data manager 122 may be configured to determine or supplement these missing values. For example, the data manager 122 may supplement the missing data with a past measured value or an average value. The data manager 122 may provide missing data values in this way for a threshold amount of time, such as for a data interruption of 5 minutes.

In some embodiments, the data manager 122 may not receive, (e.g., or may receive but may not specifically implement in connection with detecting drill breaks) formation data. For example, the drill break system 120 may determine drill breaks without respect to or independent of formation data that may indicate specific details about a formation, transition between formations, etc. For instance, the drill break system 120 may not incorporate lithology data, formation evaluation logs, coring data, mud logs, formation pressure data, seismic data, cutting analysis, or other information related to or known about a formation in which the downhole tool is implemented. As described herein, while the drill break system 120 may collect or cause to be collected some or all of this formation information as a response to detecting drill break, in some embodiments, the drill break system 120 may advantageously be configured to detect drill break without knowing specific details regarding the formation, but rather based on detecting ROP changes as described herein.

In addition to receiving data such as measurement data, in some embodiments the data manager 122 may calculate or determine one or more metrics or values based on some or all of the data it receives. For example, the data manager 122 may facilitate determining a baseline ROP and/or a localized average ROP as described herein. In some embodiments, the data manager 122 may determine a formation strength. For example, the formation strength may be determined based on multiplying the WOB by the rotational speed and normalizing (e.g., dividing) by the ROP. In some embodiments, the data manager 122 may determine an average, mean, and/or median formation strength as determined over a given distance. For example, the data manager 122 may determine a median formation strength for a given interval, such as a 5 meter rolling interval. The median formation strength may be based on a median WOB and median rotational speed over the 5 meter rolling interval and normalized over a median or average ROP over 5 the interval.

In some embodiments, the data manager 122 may determine and record a minimum, maximum, range, local minima, local maxima, or any other statistical determination for one or more measurements over a given interval or distance. For example, the data manager 122 may maintain a record of a maximum and/or minimum for the formation strength, over the past 2 meters (or another interval). In some embodiments, the data manager 122 may determine and maintain statistics for a previous stand or previous section of drill pipe of the downhole system. For example, the data manager 122 may determine and record the average ROP for the previous stand. The data manager 122 may determine and record the minimum and maximum formation strength for the previous stand. The data manager 122 may determine and record any measurement or statistical values for any type of data or measurement in this way, and may do so with respect to any interval, such as a rolling interval of a given distance uphole of the bit, for the last stand, etc.

FIG. 3 illustrates example downhole data 300 that the data manager 122 may receive. As shown, the downhole data may indicate flow rate and flow pressure, torque, hookload, WOB, block position, instantaneous ROP, and bit depth.

As shown in FIG. 3, in many cases the downhole data 300 may be collected and/or received as time-series data. In some embodiments, the data manager 122 may translate, transform, or otherwise convert the time-series measurements to a depth domain. For instance, based on the ROP (e.g., instantaneous ROP, average ROP, etc.) the data manager 122 may normalize the time-series data to indicate the associated measurements with respect to depth. This depth-dependent downhole data may facilitate the drill break detection techniques described herein. For example, the ROP manager 124 may determine, monitor, and/or generate one or more values based on a specific MD with respect to the downhole data 132. For instance, a baseline ROP may be determined and updated over a specified depth or range of depths of the wellbore. Thus, the data manager 122 may convert time-series data to be depth-dependent in order that the downhole data 132 may be useful for identifying drill breaks as described herein.

In some embodiments, the data manager 122 may determine a rig state of a drill rig of the downhole system. For example, the drill rig may operate in many different states such as tripping into or out of the wellbore, drilling, reaming, connection, transport, circulating, logging, well control, or any other rig state. The data manager 122 may determine the rig state based on some or all of downhole data 132. For instance, the data manager 122 may identify a tripping in or out drill state based on an increase in the block position and/or depth without initiation of one or more other drilling parameters such as RPM, flow rate, torque, etc. In another example, the data manager 122 may identify a circulation rig state based on a flow rate and/or flow pressure of a certain value without other corresponding drilling parameters such as RPM, torque, etc.

In some embodiments, the data manager 122 may identify a drilling state of the downhole system. For example, the data manager 122 may identify an increase in the WOB and/or a decrease in the hookload indicating that the downhole tool is engaging the bottom of the wellbore. The data manager 122 may identify an increase in the torque produced by the rig and/or imparted to the downhole tool indicating that the downhole tool is engaging the wellbore. The data manager may identify a certain value or range of a flowrate indicating that drilling mud is circulating as part of a drilling operation. The data manager 122 may identify the drilling state based on any other measurement and/or characteristic of the downhole data 132. In some embodiments, the data manager 122 may determine that the downhole system is operating in a drilling state based on one or more measurements of the downhole data 132 being substantially constant or uniform. For example, at the initiation of a drilling operation, it may take some time for certain parameters to ramp up, level off, or reach equilibrium. In some embodiments, the data manager 122 may identify and differentiate an initiation stage of a drilling state from a working or operational stage of a drilling state based on identifying one or more constant, uniform, or equilibrium values of the downhole data 132. Identification of the (e.g., constant) drilling state by the data manager 122 may facilitate the drill break determination techniques of the drill break system 120. For example, as described herein, identifying when the downhole data 132 is constant may facilitate determining a baseline ROP, localized average ROP, and/or may facilitate identifying a drill break event from the downhole data 132.

In some embodiments, the data manager 122 receives user input. The data manager 122 may receive the user input, for example, via any of the client devices 112 and/or server devices 114. Any of the data described herein may be input or augmented via the user input. For example, in some instances, some or all of the downhole data 132 is received by the data manager 122 as user input. The user input may be received in association with one or more functions or features of the drill break system 120, such as part of determining thresholds, identifying threshold changes, notifying or acting on alerts, or any other feature described herein.

The data manager 122 may store any of the data it receives, generates, manipulates, etc., to the data storage 130 as downhole data 132. Additionally, the data manager 122 may receive and/or modify any of the data in real time in order to facilitate a real-time identification of drill breaks by the drill break system 120.

As mentioned above, the drill break system 120 includes an ROP manager 124. The ROP manager 124 may facilitate generating one or more values, metrics, or averages of the ROP data to facilitate identifying drill breaks. For instance, based on the downhole data 132, the ROP manager 124 may determine a baseline ROP as well as a localized average ROP that the drill break system 120 may monitor against the baseline ROP to identify when a downhole tool encounters a transition from one formation to another based on a dynamic threshold change in the ROP. The ROP manager 124 may provide one or more of these metrics in order to facilitate the drill break system 120 identifying drill breaks. FIGS. 4-1 through 4-4 illustrate examples of baseline ROP and localized average ROP, according to embodiments of the present disclosure.

As just mentioned, the ROP manager 124 may determine a baseline ROP. The baseline ROP may represent an average, expected, recent, and/or reference ROP for the downhole tool. For instance, the baseline ROP may be based on previous ROP measurements taken uphole of the current MD, or may be based on previous ROP measurements from a previous downhole operation in the same or different wellbore. The baseline ROP may be determined based on (e.g., calculations from) formation evaluation logs, or formation models.

In some embodiments, the baseline ROP may be an average of the ROP data over a baseline distance. For example, the baseline distance may be a set (e.g., constant) distance or interval over which the baseline ROP is calculated. As shown in FIG. 4-1, the baseline ROP 140-1 may be calculated over a set baseline distance at time t=1. At time t=2, the downhole tool has progressed somewhat through the formation, and the baseline ROP 140-1 may be calculated based on the same set baseline distance (e.g., same length), but advanced according to the advancement of the downhole tool at time t=2. In this way, while the baseline distance may be a set or constant distance, it may be a rolling interval such that the baseline ROP 140-1 is a rolling average that progresses as the MD of the downhole tool increases. The baseline distance may be 1 meter, 2 meters, 3 meters, 4 meters, 5 meters, 10 meters, or any other distance. In this way, the baseline ROP 140-1 may provide a reference ROP for a somewhat recent distance through which the downhole tool has progressed.

In some embodiments, the baseline distance may not be a set distance or interval, but may be an increasing interval based on a specific MD or a specific position in the wellbore. As shown in FIG. 4-2, a baseline ROP 140-2 may be calculated at a time t=1 as an average over a baseline distance that extends back to an MD of interest 150. At time t=2, the downhole tool has progressed somewhat through the formation, and the baseline ROP 140-2 may be calculated as an average over a (e.g., larger) baseline distance that extends back to the same MD of interest 150. In this way, as the downhole tool progresses through the formation, the baseline distance over which the baseline ROP 140-2 is calculated and updated may accordingly increase. In this way, the baseline ROP 140-2 may represent a reference ROP for the downhole tool from some point of interest in the wellbore.

In some embodiments, the MD of interest 150 (e.g., the point back to which the baseline ROP 140-2 is calculated) may correspond to an identified threshold between formations. For example, the drill break system 120 may identify that the downhole tool transitions from one formation to another, and may set the MD of interest 150 at a point associated with the transition between formations. In this way, the baseline ROP 140-2 may represent an average, expected, or reference ROP for how the downhole tool is or has behaved in that formation.

In some embodiments, the MD of interest 150 may correspond to a point at which the drill break system 120 identifies that the downhole system is operating in a drilling state. For example, the MD of interest 150 may correspond to a point at which one or more drilling parameters of the downhole data have been identified as being substantially constant or uniform. In this way, the baseline ROP 140-2 may be representative of an average, expected, of reference ROP for the downhole tool under the constant and/or uniform conditions indicated by the (e.g., constant) drilling parameters such that any identified threshold change in the ROP may be more confidently attributed to a change in the formation, or drill break (e.g., rather than a change in parameters). The MD of interest 150 may be at any other position in the wellbore and/or may be based on any other identified condition or event. For example, in some embodiments, the MD of interest 150 may be at the surface such that the baseline ROP is an average ROP of the downhole tool calculated over an entirety of the length of the wellbore.

As described herein, the drill break system 120 may monitor the ROP data against the baseline ROP in order to identify changes in the ROP data of a threshold amount. In some embodiments, the ROP data (e.g., an instantaneous ROP) may exhibit one or more measurement errors, stochastic spikes, outliers, noise, etc. As mentioned above, the ROP manager 124 may determine a localized average ROP in order to smooth or average out some of the data artifacts in the ROP data that may not necessarily characterize an actual behavior of the downhole tool.

The localized average ROP may be an average of the ROP data calculated over a localized distance. The localized distance may be any distance such as a distance of greater than 1 meter. The localized distance may be 1.1 meters, 1.5 meters, 2 meters, 3 meters, 4 meters, 5 meters, 10 meters, or any other distance. For example, as shown in FIG. 4-3, the localized average ROP 142-3 may be an average of the ROP data calculated over a set interval or distance from a (e.g., current) MD of the downhole tool. The localized distance may be a rolling interval of a constant length that progresses in accordance with the progression of the downhole tool, similar to that discussed in connection with the baseline ROP 140-1 of FIG. 4-1. In some embodiments, the localized average ROP 142-3 may be calculated over a non-set, increasing interval extending back to a measurement depth of interest, similar to that discussed in connection with the baseline ROP 140-2 of FIG. 4-2. In this way, the ROP data may be monitored via the localized average ROP in order to more accurately characterize the current ROP behavior of the bit based on how the bit has behaved as it progressed through a recent distance of the formation.

In some embodiments, the baseline ROP may be calculated over a baseline distance that overlaps at least somewhat with the localized distance over which the localized average ROP is determined. For example, as shown in FIG. 4-3, both the baseline ROP 140-3 and the localized average ROP 142-3 may be calculated over intervals that extend from a current MD of the downhole tool. The baseline distance may be greater than the localized distance and in this way the baseline ROP 140-3 may characterize an average or expected behavior for the ROP of the downhole tool, and the localized average ROP 142-3 may represent a more current or active ROP behavior of the downhole tool. One or both of the localized distance and the baseline distance may be static, set intervals that roll with the progression of the downhole tool as described herein, or one or both may be non-set, increasing intervals that increase with the progression of the downhole tool as described herein.

In some embodiments, the baseline ROP may be calculated over a baseline distance that does not overlap with the localized distance over which the localized average ROP is determined. For example, as shown in FIG. 4-4, the localized average ROP 142-4 may be calculated over an interval that extends from a MD of the downhole tool. The baseline ROP 140-4 may be calculated over an interval that prior to, uphole of, or before the localized distance. For instance, the baseline distance may be an interval immediately prior to or adjacent the localized distance. In another example, there may be a gap between the baseline distance and the localized distance. In some embodiments, the localized distance and the baseline distance may be the same sized interval or length. In some embodiments, the localized distance and the baseline distances may have different lengths. One or both of the localized distance and the baseline distance may be static, set intervals that roll with the progression of the downhole tool as described herein, or one or both may be non-set, increasing intervals that increase with the progression of the downhole tool as described herein.

The ROP manager 124 may determine a localized average ROP and a baseline ROP through various techniques in order to facilitate identifying changes in the ROP data. For example, the ROP manager 124 may determine the localized average ROP and baseline ROP in real time as the data manager 122 receives the downhole data in real time.

As mentioned above, the drill break system 120 includes a threshold manager 126. The threshold manager 126 may monitor the ROP data in order to identify drill breaks based on identifying corresponding changes in the ROP data. For example, the threshold manager 126 may compare the ROP data against the baseline ROP in order to identify a change or difference between the ROP data and the baseline ROP that indicates a drill break. In some embodiments, the threshold manager 126 may identify drill break based on changes in the instantaneous ROP against the baseline ROP. In some embodiments, the threshold manager 126 may identify drill break based on changes in the localized average ROP against the baseline ROP.

In some embodiments, the threshold manager 126 may determine, identify, or define one or more thresholds for identifying drill break based on changes in the ROP data. For example, the threshold may be a difference or change of ROP (e.g., instantaneous ROP or localized average ROP) of a certain value, as compared to the baseline ROP, such as a change in ROP of 5 m/hr (meters/hour), 10 m/hr, 25 m/hr, 50 m/hr, or any other value. In some embodiments, the threshold may be a proportionate difference or change in ratio of the ROP as compared to the baseline ROP, such as an ROP that is 1.5 times, 2 times, 2.5 times, 2.7 time, 3 times, 5 times, or 10 times the baseline ROP, or any other proportion or ratio. In this way, based on identifying that the localized average ROP (or instantaneous ROP) surpasses a corresponding threshold, the threshold manager 126 may determine a drill break of the downhole tool, and that the downhole tool is transitioning from one formation to another.

In some embodiments, the threshold manager 126 may determine a dynamic threshold. For example, the dynamic threshold may not be constant or static for all situations, circumstances, or baseline ROP values (or ranges). For instance, the dynamic threshold may define a threshold change in ROP for a certain value (or range) of baseline ROP, and may define a different threshold change in ROP for one or more other values (or ranges of baseline ROP). As an illustrative example, the dynamic threshold may define a first threshold for baseline ROPs that are relatively low, and a second threshold for a baseline ROPs that are relatively high (and/or any number of thresholds for any number of relative levels of baseline ROP). The multiple thresholds of the dynamic threshold may be changes of a certain value, changes of a certain ratio with respect to the baseline ROP, or combinations of both. In some embodiments, the dynamic threshold may be inversely related to the baseline ROP such that at lower baseline ROPs, the threshold may require a more substantial change to the ROP to indicate drill break than at higher baseline ROPs. For instance, at a baseline ROP of 1 m/hr, the dynamic threshold may define that a localized average ROP of 10 m/hr or more indicates drill break, while at a baseline ROP of 75 m/hr, the dynamic threshold may define that a localized average ROP of 78 m/hr or more indicates drill break. In this way, the dynamic threshold may define several thresholds for applying to different downhole situations exhibiting different baseline ROPs. The dynamic threshold may incorporate any number of thresholds for any number of baseline ROP values. Additionally, the dynamic threshold may define one or more threshold based on any metric, circumstance, or behavior of the downhole tool, for example, in addition or as an alternative to thresholds based on the baseline ROP.

In some embodiments, the dynamic threshold may include many discrete thresholds for segmenting the (e.g., potential) baseline ROPs into several, discrete ranges, with each range having a corresponding threshold. In some embodiments, the dynamic threshold may include a progressive or continuous scale such that an associated threshold may be determined or calculated for any baseline ROP. For example, the thresholds may be determined based on a linear relationship or function of the baseline ROP, such as by multiplying the baseline ROP by a coefficient. The thresholds may be based on any other relationship or function of the baseline ROP such as based on a quadratic, exponential, logarithmic, piecewise, trigonometric, or differential relationship, or based on any other relationship or function. In this way, the dynamic threshold may be tailored to apply to different downhole situations (e.g., exhibiting different baseline ROPs) in order to accurately identify changes in the formation based on changes in the localized average ROP.

Based on the monitoring the ROP data (e.g., the instantaneous and/or localized average ROP) against the baseline ROP, and based on identifying that the ROP data exceeds one or more associated thresholds with respect to the baseline ROP, the threshold manager 126 may accordingly determine that the downhole system is experiencing drill break. For instance, based on identifying an increase to the ROP passed a given threshold, the threshold manager 126 may identify a positive drill break, which may correspond with the downhole tool transitioning into a softer formation. In another example, based on identifying a decrease to the ROP passed a given threshold, the threshold manager 126 may identify a negative drill break, which may correspond with the downhole tool transitioning into a harder formation.

In some embodiments, the threshold manager 126 may confirm that the threshold change in the ROP data may be confidently associated to the downhole tool transitioning between formations. For example, the threshold manager 126 may verify that some or all of the downhole data is constant, indicating that the change in ROP is not falsely attributed to drill break when in fact it may be a result of changes to one or more drilling parameters.

In some embodiments, the threshold manager 126 may determine drill break based on comparing the localized average ROP to one or more metrics as an alternative to or in addition to baseline ROP. For example, the threshold manager 126 may compare the localized average ROP to a minimum or maximum ROP as determined over an interval prior to or uphole from the downhole tool and/or from an interval over which the localized average ROP is determined. For example, the localized average ROP may be an ROP over the most recent 5 meters, and the threshold manager 126 may determine drill break based on identifying a change in the localized average ROP over a minimum or maximum ROP from a previous interval. For instance, the previous interval (e.g., over which the minimum ROP is determined) may be an interval, such as 2 meters, before the 5-meter interval of the localized average ROP. In some embodiments, the threshold manager 126 may determine drill break based on the localized average ROP changing by a threshold amount over an average ROP of the previous stand of drill pipe. For instance, the threshold manager 126 may determine drill break based on a change of a factor of 2, a factor of 2.7 or some other factor.

In some embodiments, the threshold manager 126 may determine drill break based on formation strength. For example, as described above, the data manager 122 may calculate and record formation strength based on the WOB, rotational speed, and ROP data that it receives. The threshold manager 126 may determine drill break based on monitoring the formation strength to identify one or more threshold changes in the formation strength. For example, the threshold manager 126 may implement any of the techniques described herein with respect to the ROP (e.g., the baseline ROP, localized average ROP, etc.) and may determine similar metrics for the formation strength. Based on identifying changes in the formation strength of a threshold degree, the threshold manager 126 may determine that that observed change in formation strength is associated with a change in the formation and may accordingly determine that the downhole tool has experienced a drill break.

In some embodiments, the threshold manager 126 may generate an indication of a detected drill break. For example, the threshold manager 126 may generate an alert, alarm, flag, data object, or otherwise may indicate that drill break has occurred. The indication may identify at what time or location the drill break occurred. The threshold manager 126 may alert drilling personnel to the drill break, such as by presenting the indication via a graphical user interface. In some embodiments, the threshold manager 126 may generate an indication in the downhole data 132 of where and/or when drill break has been detected.

In some embodiments, the threshold manager 126 may facilitate adjusting one or more drilling parameters in response to detecting drill break. For example, based on detecting (positive or negative) drill break, the threshold manager 126 may suggest or indicate for one or more changes to be implemented to one or more drilling parameters, for example, to more efficiently drill through the new formation. In another example, the threshold manager may indicate to perform one or more steering maneuvers, such as to remain within a producing formation. In some embodiments, the threshold manager 126 may automatically adjust one or more of these (or other) parameters, such as without user input.

In some embodiments, the threshold manager 126 may cause one or more (e.g., additional) measurements to be taken based on detecting drill break. For example, the threshold manager 126 may cause an LWD, MWD, a tool sub, or other downhole measurement tool to begin (or continue) taking measurements with respect to the new formation. For example, the threshold manager 126 may cause resistivity measurements, gamma ray measurements, EM measurements, porosity measurements, or other formation evaluation measurements to be taken. In some embodiments, the threshold manager 126 may indicate for cuttings and/or gas to be analyzed (e.g., at the surface) corresponding to the location where drill break was detected.

In this way, the drill break system 120 may monitor the downhole data in order to determine drill breaks corresponding to a transition of the downhole tool between formations. This may be advantageous for identifying a formation in which an underground target is located. For example, it may be known that a current formation in which the downhole tool is located is adjacent or above a formation of interest, such as above a formation containing an underground reservoir. By identifying when a transition out of the current formation and into the next formation occurs, the downhole system may be operated to access the target reservoir. In another example, the hardness of a formation may influence how and/or with what parameters the downhole system is operated. By identifying a transition from one formation to another with different properties (e.g., hardness), the drill break system 120 may facilitate drilling more efficiently and/or optimally. In another example, certain (e.g., softer) formations may be associated with more pressure fluctuations, fluid influx, and/or well control issues. By identifying when a downhole tool encounters a softer formation, the drill break system 120 may facilitate taking appropriate and timely corrective or remedial action in order to mitigate or avoid downtime, damage to one or more downhole tools, catastrophic failures, and even injury to personnel.

FIG. 5 illustrates example downhole data 500 in association with the drill break system identifying a drill break, according to at least one embodiment of the present disclosure. The downhole data may include various measurements associated with the operation of a downhole tool. For example, the downhole data 500 may indicate a flow rate, torque, WOB, ROP (e.g., instantaneous), block position, and depth associated with the downhole tool. The downhole data 500 may be collected with respect to time. As described herein, the drill break system 120 may convert or transform some or all of the downhole data 132 to a depth domain. The drill break system 120 may convert the data to be represented with respect to depth, as shown in FIG. 5, and/or may otherwise consider the downhole data 500 with respect to depth when performing the calculations, determinations, and features described herein for determining drill breaks.

At a measurement depth MD1, the drill break system 120 may identify that the downhole system is operating in a drilling state. For example, the drill break system 120 may identify that the flow rate, the torque, and the WOB are each substantially uniform. Additionally, the torque data may indicate that the downhole system is generating torque and the WOB data may indicate that downward force is being applied to a bit. Thus, the drill break system 120 may determine that the downhole system is in a drilling state.

As described herein, the drill break system 120 may determine and/or calculate a baseline ROP for comparing against an active ROP to identify drill break. For instance, the baseline ROP may be determined based on a predefined baseline distance that may be a rolling interval with the progression of the downhole tool. In other examples, the baseline ROP may be determined over an increasing baseline distance, such as an interval extending back to MD1 and increasing with the progression of the downhole tool, or an interval extending back to any other MD.

Similarly, the drill break system 120 may determine and/or calculate a localized average ROP for comparing to the baseline ROP. The drill break system 120 may continually update the baseline ROP and/or localized average ROP to identify if and/or when the localized average ROP reaches a level that surpasses a dynamic threshold in order to determine that a drill break has occurred.

For example, at measurement depth MD2, the drill break system 120 may determine that a baseline ROP is around 4 m/hr. Additionally, the drill break system 120 may determine that the localized average ROP is also around 4 m/hr. Thus, the drill break system 120 may determine that, given the constant nature of other drilling parameters of the downhole data, and given that the localized average ROP is substantially the same as the baseline ROP, that no drill break has occurred, and accordingly that the downhole tool has not transitioned to a different formation.

At a measurement depth of MD3, the drill break system 120 may determine an updated baseline ROP that is still around 4 m/hr. However, at MD3 the drill break system 120 may determine an updated localized average ROP with an increased value, such as 40 or more m/hr (e.g., corresponding with the observed increase to the instantaneous ROP increasing to about 40 m/hr for several meters). Thus, the drill break system may identify, at MD3, that a drill break has occurred, that the downhole tool has transitioned to a different formation, and in this case, that the new formation is a softer formation. The drill break system may confirm this identification of drill brake by confirming that one or more other parameters of the downhole data 500 have remained constant such that the change in ROP may not be attributed to a change in drilling parameters.

The drill break system 120 may provide an indication of the identified drill break. For example, the drill break system 120 may generate a flag or other data object in the downhole data 500 indicating the drill break. The drill break system 120 may generate an alarm or alert for presenting to a user. In some embodiments, the drill break system 120 may adjust or may indicate to adjust one or more drilling, steering, or other parameters based on identifying the drill break at MD3.

FIG. 6 illustrates a flow diagram for a method 600 or a series of acts for determining drill break of a downhole system as described herein, according to at least one embodiment of the present disclosure. While FIG. 6 illustrates acts according to one embodiment, alternative embodiments may add to, omit, reorder, or modify any of the acts of FIG. 6. The acts of FIG. 6 may be performed as a method, may be implemented by a system, and/or may be performed as instructions stored on a computer-readable storage medium.

In some embodiments the method 600 includes an act 610 of receiving downhole data associated with a downhole tool implemented in a wellbore. The downhole data may include rate of penetration (ROP) data. The downhole data may include one or more of torque data, hookload data, flow rate data, or WOB data.

In some embodiments, the method 600 includes an act 620 of, based on the downhole data, determining a baseline ROP. The baseline ROP may be an average of the ROP data over a baseline distance. For example, the baseline distance may be based on an identified formation in which the downhole tool is located. In another example, the baseline distance is based on identifying that the downhole system is operating in a drilling state.

In some embodiments, the method 600 includes an act 630 of identifying a threshold change of the ROP data from the baseline ROP. The threshold change may be based on a dynamic threshold.

In some embodiments, identifying the change of the ROP data includes determining a localized average ROP and identifying a change in the localized average ROP from the baseline ROP, wherein the localized average ROP is an average of the ROP data over a localized distance from a measurement depth of the downhole tool. In some embodiments, the localized distance may be greater than 1 meter. For example, the localized distance may be 5 meters. In some embodiments, the baseline distance and the localized distance have the same length. In some embodiments, the threshold change may be an increase in the ROP data from the baseline data indicating a softer formation.

In some embodiments the dynamic threshold is based on the baseline ROP. For example, the dynamic threshold may be inversely related to the baseline ROP. In some embodiments, the threshold change is a change in a ratio of the localized average ROP to the baseline ROP. In some embodiments, identifying the threshold change is based on determining that the downhole system is operating in a drilling state based on identifying that at least some of the downhole data is substantially constant. In some embodiments, the downhole data is time-series data, and depth-dependent downhole data may be generated by normalizing the downhole data based on the ROP data. Determining the baseline ROP and identifying the threshold change may be based on the depth-dependent downhole data.

In some embodiments, the method 600 includes an act 640 of generating an indication of the threshold change. In some embodiments, the method 600 includes automatically adjusting one or more drilling parameters based on the indication. In some embodiments the method 600 includes causing one or more additional measurements to be taken based on the indication, including one or more of resistivity measurements, porosity measurements, gamma ray measurements, cuttings analysis, or gas analysis. In some embodiments, the threshold change is identified and the indication is generated without using formation information.

Turning now to FIG. 7, this figure illustrates certain components that may be included within a computer system 700. One or more computer systems 700 may be used to implement the various devices, components, and systems described herein.

The computer system 700 includes a processor 701. The processor 701 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 701 may be referred to as a central processing unit (CPU). Although just a single processor 701 is shown in the computer system 700 of FIG. 7, in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.

The computer system 700 also includes memory 703 in electronic communication with the processor 701. The memory 703 may include computer-readable storage media and may be any available media that may 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 may 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 may be used to store program code in the form of computer-executable instructions or data structures and which may 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 705 and data 707 may be stored in the memory 703. The instructions 705 may be executable by the processor 701 to implement some or all of the functionality disclosed herein. Executing the instructions 705 may involve the use of the data 707 that is stored in the memory 703. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 705 stored in memory 703 and executed by the processor 701. Any of the various examples of data described herein may be among the data 707 that is stored in memory 703 and used during execution of the instructions 705 by the processor 701.

A computer system 700 may also include one or more communication interfaces 709 for communicating with other electronic devices. The communication interface(s) 709 may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 709 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 709 may connect the computer system 700 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, or other electronic devices, or combinations thereof. 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 may include a communication network and/or data links, carrier waves, wireless signals, and the like, which may be used to carry desired program or template code means or instructions in the form of computer-executable instruction or data structures and which may be accessed by a general purpose or special purpose computer.

A computer system 700 may also include one or more input devices 711 and one or more output devices 713. Some examples of input devices 711 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices 713 include a speaker and a printer. One specific type of output device that is typically included in a computer system 700 is a display device 715. Display devices 715 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 717 may also be provided, for converting data 707 stored in the memory 703 into one or more of text, graphics, or moving images (as appropriate) shown on the display device 715.

The various components of the computer system 700 may be coupled together by one or more buses, which may include one or more of a power bus, a control signal bus, a status signal bus, a data bus, other similar components, or combinations thereof. For the sake of clarity, the various buses are illustrated in FIG. 7 as a bus system 719.

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 may 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 may 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 may be included in computer system components that also (or even primarily) utilize transmission media.

INDUSTRIAL APPLICABILITY

In some embodiments, a downhole system is described for drilling an earth formation to form a wellbore. The downhole system includes a drill rig used to turn a drilling tool assembly which extends downward into the wellbore. The drilling tool assembly may include a drill string 105, a bottomhole assembly (“BHA”), and a bit, attached to the downhole end of the drill string.

The drill string may include several joints of drill pipe connected end-to-end through tool joints. The drill string transmits drilling fluid through a central bore and transmits rotational power from the drill rig to the BHA. In some embodiments, the drill string further includes additional downhole drilling tools and/or components such as subs, pup joints, etc. The drill pipe 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 for the purposes of cooling the bit and cutting structures thereon, and for lifting cuttings out of the wellbore as it is being drilled.

The BHA may include the bit, other downhole drilling tools, or other components. An example BHA may include additional or other downhole drilling tools or components (e.g., coupled between the drill string and the bit). 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 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 may be considered a part of the drilling tool assembly, the drill string, or a part of the BHA, depending on their locations in the downhole system.

The bit in the BHA may be any type of bit suitable for degrading downhole materials. For instance, the bit may be a drill bit suitable for drilling the earth formation. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit may be used with a whipstock to mill into casing lining the wellbore. The bit may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore, 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 may include one or more cutting elements for degrading the earth formation.

The BHA may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit, 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 one or more of gravity, magnetic north, or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit, change the course of the bit, and direct the directional drilling tools on a projected trajectory. The RSS may steer the bit in accordance with or based on a trajectory for the bit. For example, a trajectory may be determined for directing the bit toward one or more subterranean targets such as an oil or gas reservoir.

The downhole system may include or may be associated with a client device with a drill break system implemented thereon (e.g., or with a client application implemented thereon for accessing the drill break system as described herein). The drill break system may facilitate identifying or detecting drill breaks of the downhole system, such as when the BHA, the bit, etc. encounters a sudden change between formations exhibiting different properties.

For example, while performing a downhole operation, the bit (e.g., and the BHA) may encounter several different formations. For instance, the bit may encounter and/or progress through a first formation and a second formation. The bit may progress through any number of formations. The various formations may be different formations with different physical properties, different dimensions, may contain different downhole targets or resources, etc. For instance, different downhole tools and/or different drilling parameters may be implemented for different formations. In another example, certain formations may be associated with downhole resources such as a subterranean reservoir. Thus, it may be advantageous to identify when the bit passes from one formation to the next.

The drill break system as described herein may be implemented to facilitate determining when the bit encounters a transition from one formation to another. For instance, a third formation may be positioned below or adjacent to the second formation. The bit may progress through the second formation and the drill break system may identify when the bit passes from the second formation to the third formation. For example, the drill break system may identify that a sudden change in the rate of penetration (ROP) of the bit is a result of a change in formation. The change may be of a threshold amount, which may be a dynamic or changing threshold as described herein. In this way, the drill break system may facilitate quickly identifying drill break in order that appropriate action may be taken. As used herein, a “drill break” is intended to refer to a sudden observable change in the behavior of a downhole tool (e.g., in rate of penetration) indicating that the downhole tool is or has transitioned from one formation to another.

In some embodiments, an environment is described in which a drill break system is implemented in accordance with one or more embodiments describe herein. The environment includes a server device. The server device may include one or more computing devices (e.g., including processing units, data storage, etc.) organized in an architecture with various network interfaces for connecting to and providing data management and distribution across one or more client systems. The server device may be connected to and may communicate with (either directly or indirectly) a client device through a network. The network may include one or multiple networks and may use one or more communication platforms and/or technologies suitable for transmitting data. The network may refer to any data link that enables transport of electronic data between devices of the environment. The network may refer to a hardwired network, a wireless network, or a combination of a hardwired network and a wireless network. In one or more embodiments, the network includes the internet. The network may be configured to facilitate communication between the various computing devices via well-site information transfer standard markup language (WITSML) or similar protocol, or any other protocol or form of communication.

The client device may be representative of one or multiple client devices, and may refer to various types of computing devices. For example, the client device 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 device 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, or function of the downhole system), or other non-portable device. In one or more implementations, the client device includes 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 device 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 device may similarly refer to various types of computing devices. Each of the devices of the environment may include features and/or functionalities described below.

The environment may include a drill break system implemented on the server device. While described as implemented on the server device, the drill break system may be implemented wholly or in part on the client device, across the server device and the client device, or on or across one or more additional devices, such that different portions or components of the drill break system are implemented on different computing devices in the environment. The client device may include a client application. The client application may include an application or interface for interacting with and/or receiving the features of the drill break system as described herein. In some embodiments, one or more of the functionalities or features of the drill break system may be carried out or performed on or by the client application. In this way, the environment may be a cloud computing environment, and the drill break system may be implemented across one or more devices of the cloud computing environment in order to leverage the processing capabilities, memory capabilities, connectivity, speed, etc., that such cloud computing environments offer in order to facilitate the features and functionalities described herein.

In some embodiments, an example implementation of the drill break system is described herein, according to at least one embodiment of the present disclosure. The drill break system may include a data manager, a ROP manager, and a threshold manager. The drill break system may also include a data storage having downhole data and drill break indications stored thereon. While one or more embodiments described herein describe features and functionalities performed by specific components of the drill break system, it will be appreciated that specific features described in connection with one component of the drill break system may, in some examples, be performed by one or more of the other components of the drill break system.

By way of example, one or more of the data receiving, gathering, or storing features of the data manager may be delegated to other components of the drill break system. As another example, while one or more dynamic thresholds may be determined and monitored by the threshold manager, in some instances, some or all of these features may be performed by the ROP manager (or other component of the drill break system). 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 components of the drill break system.

Additionally, while the drill break system is described as being implemented on a client device of the downhole system, it should be understood that some or all of the features and functionalities of the drill break system may be implemented on or across multiple client devices and/or server devices. For example, data may be input and/or received by the data manager on a (e.g., local) client device, and the determinations of drill break may be performed on one or more of a remote, server, or cloud device. Indeed, it will be appreciated that some or all of the specific components may be implemented on or across multiple client devices and/or server devices, including individual functions of a specific component being performed across multiple devices.

As mentioned above, the drill break system includes a data manager. The data manager may receive a variety of types of data associated with the downhole system and may store the data to the data storage. The data manager may receive the data from a variety of sources, such as from sensors, surveying tools, downhole tools, other (e.g., client) devices, libraries, databases, user input, etc.

In some embodiments, the data manager receives downhole data. The downhole data may include measurements associated with a downhole tool implemented in wellbore. For example, the downhole data may include measurements taken downhole by one or more downhole sensors. The downhole data may include data taken at the surface.

In some embodiments, the downhole data includes measurements related to drilling parameters or a downhole behavior of a downhole too. For instance, the downhole data may include ROP data. The ROP data may be measured (e.g., directly) by a downhole tool, or may be determined or inferred from the surface. For example, the downhole data may include block position data of a block of a drill rig. Based on a position or movement of the block, the data manager may generate the ROP data for representing the rate at which a downhole tool is progressing (e.g., drilling) through the earth. In some embodiments, the ROP data may indicate an instantaneous ROP of the downhole tool. In some embodiments the ROP data my indicate one or more average ROPs of the downhole tool, such as a baseline ROP and/or a localized average ROP as described herein. In this way, the ROP data may indicate an instantaneous and/or historic characterization of a behavior of a downhole tool with respect to a formation. For example, in many cases, the ROP may be related to and/or influenced by a formation in which the downhole tool is positioned. For example, a relatively low ROP may correspond with the downhole tool progressing through a harder and/or stronger formation, and a relatively high ROP may correspond with the downhole tool progressing through a softer and/or weaker formation. In this way, the ROP data may be useful for characterizing a formation of a wellbore and/or for identifying a transition to a different formation, as described herein.

In some embodiments, the downhole data includes measurements of other drilling parameters. For example, the downhole data may indicate weight on bit (WOB) data of the downhole tool. The WOB data may be (e.g., directly) measured by a downhole sensor, or may be determined or inferred from surface measurements, such as a hookload. In some embodiments, the downhole data includes torque data indicating a level of torque imparted on the downhole tool and/or imparted by the downhole tool to form the wellbore. The torque data may be measured by a downhole sensor, or may be determined based on a surface torque applied at the drill rig. In some embodiments, the downhole data includes a flow rate and/or a pressure of drilling mud and/or hydraulic fluids. In some embodiments, the downhole data includes measures of other drilling parameters such as a surface rotational speed (RPM), a downhole RPM, temperatures, pressures, or any other relevant drilling parameters. The downhole data may indicate current and/or past measurement depths (MDs) of the downhole tool. For instance, the downhole tool may measure and/or track a distance which it has traveled beneath and/or through the earth, or the MD may be determined, calculated, and/or inferred by surface components based on one or more other measurements. In some embodiments, the downhole data may include sensor and/or measurement data from MWD tools, LWD tools, and/or one or more other downhole tools or subs. For example, the downhole data may include resistivity measurements, porosity measurements, gamma ray measurements, acoustic measurements, electromagnetic measurements, etc. In this way, the data manager may receive, collect, and maintain the downhole data, which may include a variety of measurements associated with a position, operation, behavior, performance, etc. of the downhole tool in order to facilitate the drill break detection functionalities described herein.

In some embodiments, one or more values or measurements from one or more of the sources of data that the data manager receives or has access to may be incomplete, may be missing, or may otherwise not be available. For instance, one or more signals or data channels may become interrupted, lost, distorted, or may otherwise not be available, either temporarily or permanently. The data manager may be configured to determine or supplement these missing values. For example, the data manager may supplement the missing data with a past measured value or an average value. The data manager may provide missing data values in this way for a threshold amount of time, such as for a data interruption of 5 minutes.

In some embodiments, the data manager may not receive, (e.g., or may receive but may not specifically implement in connection with detecting drill breaks) formation data. For example, the drill break system may determine drill breaks without respect to or independent of formation data that may indicate specific details about a formation, transition between formations, etc. For instance, the drill break system may not incorporate lithology data, formation evaluation logs, coring data, mud logs, formation pressure data, seismic data, cutting analysis, or other information related to or known about a formation in which the downhole tool is implemented. As described herein, while the drill break system may collect or cause to be collected some or all of this formation information as a response to detecting drill break, in some embodiments, the drill break system may advantageously be configured to detect drill break without knowing specific details regarding the formation, but rather based on detecting ROP changes as described herein.

In addition to receiving data such as measurement data, in some embodiments the data manager may calculate or determine one or more metrics or values based on some or all of the data it receives. For example, the data manager may facilitate determining a baseline ROP and/or a localized average ROP as described herein. In some embodiments, the data manager may determine a formation strength. For example, the formation strength may be determined based on multiplying the WOB by the rotational speed and normalizing (e.g., dividing) by the ROP. In some embodiments, the data manager may determine an average, mean, and/or median formation strength as determined over a given distance. For example, the data manager may determine a median formation strength for a given interval, such as a 5 meter rolling interval. The median formation strength may be based on a median WOB and median rotational speed over the 5 meter rolling interval and normalized over a median or average ROP over 5 the interval.

In some embodiments, the data manager may determine and record a minimum, maximum, range, local minima, local maxima, or any other statistical determination for one or more measurements over a given interval or distance. For example, the data manager may maintain a record of a maximum and/or minimum for the formation strength, over the past 2 meters (or another interval). In some embodiments, the data manager may determine and maintain statistics for a previous stand or previous section of drill pipe of the downhole system. For example, the data manager may determine and record the average ROP for the previous stand. The data manager may determine and record the minimum and maximum formation strength for the previous stand. The data manager may determine and record any measurement or statistical values for any type of data or measurement in this way, and may do so with respect to any interval, such as a rolling interval of a given distance uphole of the bit, for the last stand, etc.

In some embodiments, the downhole data may indicate flow rate and flow pressure, torque, hookload, WOB, block position, instantaneous ROP, and bit depth. In many cases the downhole data may be collected and/or received as time-series data. In some embodiments, the data manager may translate, transform, or otherwise convert the time-series measurements to a depth domain. For instance, based on the ROP (e.g., instantaneous ROP, average ROP, etc.) the data manager may normalize the time-series data to indicate the associated measurements with respect to depth. This depth-dependent downhole data may facilitate the drill break detection techniques described herein. For example, the ROP manager may determine, monitor, and/or generate one or more values based on a specific MD with respect to the downhole data. For instance, a baseline ROP may be determined and updated over a specified depth or range of depths of the wellbore. Thus, the data manager may convert time-series data to be depth-dependent in order that the downhole data may be useful for identifying drill breaks as described herein.

In some embodiments, the data manager may determine a rig state of a drill rig of the downhole system. For example, the drill rig may operate in many different states such as tripping into or out of the wellbore, drilling, reaming, connection, transport, circulating, logging, well control, or any other rig state. The data manager may determine the rig state based on some or all of downhole data. For instance, the data manager may identify a tripping in or out drill state based on an increase in the block position and/or depth without initiation of one or more other drilling parameters such as RPM, flow rate, torque, etc. In another example, the data manager may identify a circulation rig state based on a flow rate and/or flow pressure of a certain value without other corresponding drilling parameters such as RPM, torque, etc.

In some embodiments, the data manager may identify a drilling state of the downhole system. For example, the data manager may identify an increase in the WOB and/or a decrease in the hookload indicating that the downhole tool is engaging the bottom of the wellbore. The data manager may identify an increase in the torque produced by the rig and/or imparted to the downhole tool indicating that the downhole tool is engaging the wellbore. The data manager may identify a certain value or range of a flowrate indicating that drilling mud is circulating as part of a drilling operation. The data manager may identify the drilling state based on any other measurement and/or characteristic of the downhole data. In some embodiments, the data manager may determine that the downhole system is operating in a drilling state based on one or more measurements of the downhole data being substantially constant or uniform. For example, at the initiation of a drilling operation, it may take some time for certain parameters to ramp up, level off, or reach equilibrium. In some embodiments, the data manager may identify and differentiate an initiation stage of a drilling state from a working or operational stage of a drilling state based on identifying one or more constant, uniform, or equilibrium values of the downhole data. Identification of the (e.g., constant) drilling state by the data manager may facilitate the drill break determination techniques of the drill break system. For example, as described herein, identifying when the downhole data is constant may facilitate determining a baseline ROP, localized average ROP, and/or may facilitate identifying a drill break event from the downhole data.

In some embodiments, the data manager receives user input. The data manager may receive the user input, for example, via any of the client devices and/or server devices. Any of the data described herein may be input or augmented via the user input. For example, in some instances, some or all of the downhole data is received by the data manager as user input. The user input may be received in association with one or more functions or features of the drill break system, such as part of determining thresholds, identifying threshold changes, notifying or acting on alerts, or any other feature described herein.

The data manager may store any of the data it receives, generates, manipulates, etc., to the data storage as downhole data. Additionally, the data manager may receive and/or modify any of the data in real time in order to facilitate a real-time identification of drill breaks by the drill break system.

As mentioned above, the drill break system includes an ROP manager. The ROP manager may facilitate generating one or more values, metrics, or averages of the ROP data to facilitate identifying drill breaks. For instance, based on the downhole data, the ROP manager may determine a baseline ROP as well as a localized average ROP that the drill break system may monitor against the baseline ROP to identify when a downhole tool encounters a transition from one formation to another based on a dynamic threshold change in the ROP. The ROP manager may provide one or more of these metrics in order to facilitate the drill break system identifying drill breaks.

As just mentioned, the ROP manager may determine a baseline ROP. The baseline ROP may represent an average, expected, recent, and/or reference ROP for the downhole tool. For instance, the baseline ROP may be based on previous ROP measurements taken uphole of the current MD, or may be based on previous ROP measurements from a previous downhole operation in the same or different wellbore. The baseline ROP may be determined based on (e.g., calculations from) formation evaluation logs, or formation models.

In some embodiments, the baseline ROP may be an average of the ROP data over a baseline distance. For example, the baseline distance may be a set (e.g., constant) distance or interval over which the baseline ROP is calculated. The baseline ROP may be calculated over a set baseline distance at time t=1. At time t=2, the downhole tool has progressed somewhat through the formation, and the baseline ROP may be calculated based on the same set baseline distance (e.g., same length), but advanced according to the advancement of the downhole tool at time t=2. In this way, while the baseline distance may be a set or constant distance, it may be a rolling interval such that the baseline ROP is a rolling average that progresses as the MD of the downhole tool increases. The baseline distance may be 1 meter, 2 meters, 3 meters, 4 meters, 5 meters, 10 meters, or any other distance. In this way, the baseline ROP may provide a reference ROP for a somewhat recent distance through which the downhole tool has progressed.

In some embodiments, the baseline distance may not be a set distance or interval, but may be an increasing interval based on a specific MD or a specific position in the wellbore. A baseline ROP may be calculated at a time t=1 as an average over a baseline distance that extends back to an MD of interest. At time t=2, the downhole tool has progressed somewhat through the formation, and the baseline ROP 140-2 may be calculated as an average over a (e.g., larger) baseline distance that extends back to the same MD of interest 150. In this way, as the downhole tool progresses through the formation, the baseline distance over which the baseline ROP is calculated and updated may accordingly increase. In this way, the baseline ROP may represent a reference ROP for the downhole tool from some point of interest in the wellbore.

In some embodiments, the MD of interest (e.g., the point back to which the baseline ROP is calculated) may correspond to an identified threshold between formations. For example, the drill break system may identify that the downhole tool transitions from one formation to another, and may set the MD of interest at a point associated with the transition between formations. In this way, the baseline ROP may represent an average, expected, or reference ROP for how the downhole tool is or has behaved in that formation.

In some embodiments, the MD of interest may correspond to a point at which the drill break system identifies that the downhole system is operating in a drilling state. For example, the MD of interest may correspond to a point at which one or more drilling parameters of the downhole data have been identified as being substantially constant or uniform. In this way, the baseline ROP may be representative of an average, expected, of reference ROP for the downhole tool under the constant and/or uniform conditions indicated by the (e.g., constant) drilling parameters such that any identified threshold change in the ROP may be more confidently attributed to a change in the formation, or drill break (e.g., rather than a change in parameters). The MD of interest may be at any other position in the wellbore and/or may be based on any other identified condition or event. For example, in some embodiments, the MD of interest may be at the surface such that the baseline ROP is an average ROP of the downhole tool calculated over an entirety of the length of the wellbore.

As described herein, the drill break system may monitor the ROP data against the baseline ROP in order to identify changes in the ROP data of a threshold amount. In some embodiments, the ROP data (e.g., an instantaneous ROP) may exhibit one or more measurement errors, stochastic spikes, outliers, noise, etc. As mentioned above, the ROP manager may determine a localized average ROP in order to smooth or average out some of the data artifacts in the ROP data that may not necessarily characterize an actual behavior of the downhole tool.

The localized average ROP may be an average of the ROP data calculated over a localized distance. The localized distance may be any distance such as a distance of greater than 1 meter. The localized distance may be 1.1 meters, 1.5 meters, 2 meters, 3 meters, 4 meters, 5 meters, 10 meters, or any other distance. For example, localized average ROP may be an average of the ROP data calculated over a set interval or distance from a (e.g., current) MD of the downhole tool. The localized distance may be a rolling interval of a constant length that progresses in accordance with the progression of the downhole tool, similar to that discussed above in connection with the baseline ROP. In some embodiments, the localized average ROP may be calculated over a non-set, increasing interval extending back to a measurement depth of interest, similar to that discussed above in connection with the baseline ROP. In this way, the ROP data may be monitored via the localized average ROP in order to more accurately characterize the current ROP behavior of the bit based on how the bit has behaved as it progressed through a recent distance of the formation.

In some embodiments, the baseline ROP may be calculated over a baseline distance that overlaps at least somewhat with the localized distance over which the localized average ROP is determined. For example, both the baseline ROP and the localized average ROP may be calculated over intervals that extend from a current MD of the downhole tool. The baseline distance may be greater than the localized distance and in this way the baseline ROP may characterize an average or expected behavior for the ROP of the downhole tool, and the localized average ROP may represent a more current or active ROP behavior of the downhole tool. One or both of the localized distance and the baseline distance may be static, set intervals that roll with the progression of the downhole tool as described herein, or one or both may be non-set, increasing intervals that increase with the progression of the downhole tool as described herein.

In some embodiments, the baseline ROP may be calculated over a baseline distance that does not overlap with the localized distance over which the localized average ROP is determined. For example, the localized average ROP may be calculated over an interval that extends from a MD of the downhole tool. The baseline ROP may be calculated over an interval that prior to, uphole of, or before the localized distance. For instance, the baseline distance may be an interval immediately prior to or adjacent the localized distance. In another example, there may be a gap between the baseline distance and the localized distance. In some embodiments, the localized distance and the baseline distance may be the same sized interval or length. In some embodiments, the localized distance and the baseline distances may have different lengths. One or both of the localized distance and the baseline distance may be static, set intervals that roll with the progression of the downhole tool as described herein, or one or both may be non-set, increasing intervals that increase with the progression of the downhole tool as described herein.

The ROP manager may determine a localized average ROP and a baseline ROP through various techniques in order to facilitate identifying changes in the ROP data. For example, the ROP manager may determine the localized average ROP and baseline ROP in real time as the data manager receives the downhole data in real time.

As mentioned above, the drill break system includes a threshold manager. The threshold manager may monitor the ROP data in order to identify drill breaks based on identifying corresponding changes in the ROP data. For example, the threshold manager may compare the ROP data against the baseline ROP in order to identify a change or difference between the ROP data and the baseline ROP that indicates a drill break. In some embodiments, the threshold manager may identify drill break based on changes in the instantaneous ROP against the baseline ROP. In some embodiments, the threshold manager may identify drill break based on changes in the localized average ROP against the baseline ROP.

In some embodiments, the threshold manager may determine, identify, or define one or more thresholds for identifying drill break based on changes in the ROP data. For example, the threshold may be a difference or change of ROP (e.g., instantaneous ROP or localized average ROP) of a certain value, as compared to the baseline ROP, such as a change in ROP of 5 m/hr (meters/hour), 10 m/hr, 25 m/hr, 50 m/hr, or any other value. In some embodiments, the threshold may be a proportionate difference or change in ratio of the ROP as compared to the baseline ROP, such as an ROP that is 1.5 times, 2 times, 2.5 times, 2.7 time, 3 times, 5 times, or 10 times the baseline ROP, or any other proportion or ratio. In this way, based on identifying that the localized average ROP (or instantaneous ROP) surpasses a corresponding threshold, the threshold manager may determine a drill break of the downhole tool, and that the downhole tool is transitioning from one formation to another.

In some embodiments, the threshold manager may determine a dynamic threshold. For example, the dynamic threshold may not be constant or static for all situations, circumstances, or baseline ROP values (or ranges). For instance, the dynamic threshold may define a threshold change in ROP for a certain value (or range) of baseline ROP, and may define a different threshold change in ROP for one or more other values (or ranges of baseline ROP). As an illustrative example, the dynamic threshold may define a first threshold for baseline ROPs that are relatively low, and a second threshold for a baseline ROPs that are relatively high (and/or any number of thresholds for any number of relative levels of baseline ROP). The multiple thresholds of the dynamic threshold may be changes of a certain value, changes of a certain ratio with respect to the baseline ROP, or combinations of both. In some embodiments, the dynamic threshold may be inversely related to the baseline ROP such that at lower baseline ROPs, the threshold may require a more substantial change to the ROP to indicate drill break than at higher baseline ROPs. For instance, at a baseline ROP of 1 m/hr, the dynamic threshold may define that a localized average ROP of 10 m/hr or more indicates drill break, while at a baseline ROP of 75 m/hr, the dynamic threshold may define that a localized average ROP of 78 m/hr or more indicates drill break. In this way, the dynamic threshold may define several thresholds for applying to different downhole situations exhibiting different baseline ROPs. The dynamic threshold may incorporate any number of thresholds for any number of baseline ROP values. Additionally, the dynamic threshold may define one or more threshold based on any metric, circumstance, or behavior of the downhole tool, for example, in addition or as an alternative to thresholds based on the baseline ROP.

In some embodiments, the dynamic threshold may include many discrete thresholds for segmenting the (e.g., potential) baseline ROPs into several, discrete ranges, with each range having a corresponding threshold. In some embodiments, the dynamic threshold may include a progressive or continuous scale such that an associated threshold may be determined or calculated for any baseline ROP. For example, the thresholds may be determined based on a linear relationship or function of the baseline ROP, such as by multiplying the baseline ROP by a coefficient. The thresholds may be based on any other relationship or function of the baseline ROP such as based on a quadratic, exponential, logarithmic, piecewise, trigonometric, or differential relationship, or based on any other relationship or function. In this way, the dynamic threshold may be tailored to apply to different downhole situations (e.g., exhibiting different baseline ROPs) in order to accurately identify changes in the formation based on changes in the localized average ROP.

Based on the monitoring the ROP data (e.g., the instantaneous and/or localized average ROP) against the baseline ROP, and based on identifying that the ROP data exceeds one or more associated thresholds with respect to the baseline ROP, the threshold manager may accordingly determine that the downhole system is experiencing drill break. For instance, based on identifying an increase to the ROP passed a given threshold, the threshold manager may identify a positive drill break, which may correspond with the downhole tool transitioning into a softer formation. In another example, based on identifying a decrease to the ROP passed a given threshold, the threshold manager may identify a negative drill break, which may correspond with the downhole tool transitioning into a harder formation.

In some embodiments, the threshold manager may confirm that the threshold change in the ROP data may be confidently associated to the downhole tool transitioning between formations. For example, the threshold manager may verify that some or all of the downhole data is constant, indicating that the change in ROP is not falsely attributed to drill break when in fact it may be a result of changes to one or more drilling parameters.

In some embodiments, the threshold manager 126 may determine drill break based on comparing the localized average ROP to one or more metrics as an alternative to or in addition to baseline ROP. For example, the threshold manager 126 may compare the localized average ROP to a minimum or maximum ROP as determined over an interval prior to or uphole from the downhole tool and/or from an interval over which the localized average ROP is determined. For example, the localized average ROP may be an ROP over the most recent 5 meters, and the threshold manager 126 may determine drill break based on identifying a change in the localized average ROP over a minimum or maximum ROP from a previous interval. For instance, the previous interval (e.g., over which the minimum ROP is determined) may be an interval, such as 2 meters, before the 5-meter interval of the localized average ROP. In some embodiments, the threshold manager 126 may determine drill break based on the localized average ROP changing by a threshold amount over an average ROP of the previous stand of drill pipe. For instance, the threshold manager 126 may determine drill break based on a change of a factor of 2, a factor of 2.7 or some other factor.

In some embodiments, the threshold manager may determine drill break based on formation strength. For example, as described above, the data manager may calculate and record formation strength based on the WOB, rotational speed, and ROP data that it receives. The threshold manager may determine drill break based on monitoring the formation strength to identify one or more threshold changes in the formation strength. For example, the threshold manager may implement any of the techniques described herein with respect to the ROP (e.g., the baseline ROP, localized average ROP, etc.) and may determine similar metrics for the formation strength. Based on identifying changes in the formation strength of a threshold degree, the threshold manager may determine that that observed change in formation strength is associated with a change in the formation and may accordingly determine that the downhole tool has experienced a drill break.

In some embodiments, the threshold manager may generate an indication of a detected drill break. For example, the threshold manager may generate an alert, alarm, flag, data object, or otherwise may indicate that drill break has occurred. The indication may identify at what time or location the drill break occurred. The threshold manager may alert drilling personnel to the drill break, such as by presenting the indication via a graphical user interface. In some embodiments, the threshold manager may generate an indication in the downhole data of where and/or when drill break has been detected.

In some embodiments, the threshold manager may facilitate adjusting one or more drilling parameters in response to detecting drill break. For example, based on detecting (positive or negative) drill break, the threshold manager may suggest or indicate for one or more changes to be implemented to one or more drilling parameters, for example, to more efficiently drill through the new formation. In another example, the threshold manager may indicate to perform one or more steering maneuvers, such as to remain within a producing formation. In some embodiments, the threshold manager may automatically adjust one or more of these (or other) parameters, such as without user input.

In some embodiments, the threshold manager may cause one or more (e.g., additional) measurements to be taken based on detecting drill break. For example, the threshold manager may cause an LWD, MWD, a tool sub, or other downhole measurement tool to begin (or continue) taking measurements with respect to the new formation. For example, the threshold manager may cause resistivity measurements, gamma ray measurements, EM measurements, porosity measurements, or other formation evaluation measurements to be taken. In some embodiments, the threshold manager may indicate for cuttings and/or gas to be analyzed (e.g., at the surface) corresponding to the location where drill break was detected.

In this way, the drill break system may monitor the downhole data in order to determine drill breaks corresponding to a transition of the downhole tool between formations. This may be advantageous for identifying a formation in which an underground target is located. For example, it may be known that a current formation in which the downhole tool is located is adjacent or above a formation of interest, such as above a formation containing an underground reservoir. By identifying when a transition out of the current formation and into the next formation occurs, the downhole system may be operated to access the target reservoir. In another example, the hardness of a formation may influence how and/or with what parameters the downhole system is operated. By identifying a transition from one formation to another with different properties (e.g., hardness), the drill break system may facilitate drilling more efficiently and/or optimally. In another example, certain (e.g., softer) formations may be associated with more pressure fluctuations, fluid influx, and/or well control issues. By identifying when a downhole tool encounters a softer formation, the drill break system may facilitate taking appropriate and timely corrective or remedial action in order to mitigate or avoid downtime, damage to one or more downhole tools, catastrophic failures, and even injury to personnel.

In some embodiments, example downhole data is described herein in association with the drill break system identifying a drill break, according to at least one embodiment of the present disclosure. The downhole data may include various measurements associated with the operation of a downhole tool. For example, the downhole data may indicate a flow rate, torque, WOB, ROP (e.g., instantaneous), block position, and depth associated with the downhole tool. The downhole data may be collected with respect to time. As described herein, the drill break system may convert or transform some or all of the downhole data to a depth domain. The drill break system may convert the data to be represented with respect to depth, and/or may otherwise consider the downhole data with respect to depth when performing the calculations, determinations, and features described herein for determining drill breaks.

At a measurement depth MD1, the drill break system may identify that the downhole system is operating in a drilling state. For example, the drill break system may identify that the flow rate, the torque, and the WOB are each substantially uniform. Additionally, the torque data may indicate that the downhole system is generating torque and the WOB data may indicate that downward force is being applied to a bit. Thus, the drill break system may determine that the downhole system is in a drilling state.

As described herein, the drill break system may determine and/or calculate a baseline ROP for comparing against an active ROP to identify drill break. For instance, the baseline ROP may be determined based on a predefined baseline distance that may be a rolling interval with the progression of the downhole tool. In other examples, the baseline ROP may be determined over an increasing baseline distance, such as an interval extending back to MD1 and increasing with the progression of the downhole tool, or an interval extending back to any other MD.

Similarly, the drill break system may determine and/or calculate a localized average ROP for comparing to the baseline ROP. The drill break system may continually update the baseline ROP and/or localized average ROP to identify if and/or when the localized average ROP reaches a level that surpasses a dynamic threshold in order to determine that a drill break has occurred.

For example, at measurement depth MD2, the drill break system may determine that a baseline ROP is around 4 m/hr. Additionally, the drill break system may determine that the localized average ROP is also around 4 m/hr. Thus, the drill break system may determine that, given the constant nature of other drilling parameters of the downhole data, and given that the localized average ROP is substantially the same as the baseline ROP, that no drill break has occurred, and accordingly that the downhole tool has not transitioned to a different formation.

At a measurement depth of MD3, the drill break system may determine an updated baseline ROP that is still around 4 m/hr. However, at MD3 the drill break system may determine an updated localized average ROP with an increased value, such as 40 or more m/hr (e.g., corresponding with the observed increase to the instantaneous ROP increasing to about 40 m/hr for several meters). Thus, the drill break system may identify, at MD3, that a drill break has occurred, that the downhole tool has transitioned to a different formation, and in this case, that the new formation is a softer formation. The drill break system may confirm this identification of drill brake by confirming that one or more other parameters of the downhole data have remained constant such that the change in ROP may not be attributed to a change in drilling parameters.

The drill break system may provide an indication of the identified drill break. For example, the drill break system may generate a flag or other data object in the downhole data indicating the drill break. The drill break system may generate an alarm or alert for presenting to a user. In some embodiments, the drill break system may adjust or may indicate to adjust one or more drilling, steering, or other parameters based on identifying the drill break at MD3.

In some embodiments, certain components that may be included within a computer system are described herein. One or more computer systems may be used to implement the various devices, components, and systems described herein.

The computer system includes a processor. The processor 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 701 may be referred to as a central processing unit (CPU). Although just a single processor 701 is described in the computer system, in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.

The computer system also includes memory in electronic communication with the processor. The memory may include computer-readable storage media and may be any available media that may 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 may 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 may be used to store program code in the form of computer-executable instructions or data structures and which may 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 and data may be stored in the memory. The instructions may be executable by the processor to implement some or all of the functionality disclosed herein. Executing the instructions may involve the use of the data that is stored in the memory. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions stored in memory and executed by the processor. Any of the various examples of data described herein may be among the data that is stored in memory and used during execution of the instructions by the processor.

A computer system may also include one or more communication interfaces for communicating with other electronic devices. The communication interface(s) may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 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 may connect the computer system 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, or other electronic devices, or combinations thereof. 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 may include a communication network and/or data links, carrier waves, wireless signals, and the like, which may be used to carry desired program or template code means or instructions in the form of computer-executable instruction or data structures and which may be accessed by a general purpose or special purpose computer.

A computer system may also include one or more input devices and one or more output devices. Some examples of input devices include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices include a speaker and a printer. One specific type of output device that is typically included in a computer system is a display device. Display devices 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 may also be provided, for converting data stored in the memory into one or more of text, graphics, or moving images (as appropriate) shown on the display device.

The various components of the computer system may be coupled together by one or more buses, which may include one or more of a power bus, a control signal bus, a status signal bus, a data bus, other similar components, or combinations thereof.

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 may 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 may 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 may be included in computer system components that also (or even primarily) utilize transmission media.

The following description from ¶¶ [0160]-[0180] includes various embodiments that, where feasible, may be combined in any permutation. For example, the embodiment of ¶ [0161] may be combined with any or all embodiments of the following paragraphs. Embodiments that describe acts of a method may be combined with embodiments that describe, for example, systems and/or devices. Any permutation of the following paragraphs is considered to be hereby disclosed for the purposes of providing “unambiguously derivable support” for any claim amendment based on the following paragraphs. Furthermore, the following paragraphs provide support such that any combination of the following paragraphs would not create an “intermediate generalization.”

In some embodiments, a method of determining drill break of a downhole system, includes receiving downhole data associated with a downhole tool implemented in a wellbore, the downhole data including rate of penetration (ROP) data of the downhole tool; based on the downhole data, determining a baseline ROP; identifying a threshold change of the ROP data from the baseline ROP, wherein the threshold change is a based on a dynamic threshold; and generating an indication of the threshold change.

In some embodiments, identifying the threshold change of the ROP data includes determining a localized average ROP and identifying a change in the localized average ROP from the baseline ROP, wherein the localized average ROP is an average of the ROP data over a localized distance from a measurement depth of the downhole tool.

In some embodiments, the localized distance is greater than 1 meter.

In some embodiments, the localized distance is 5 meters.

In some embodiments, the baseline ROP is an average of the ROP data over a baseline distance.

In some embodiments, the baseline distance and the localized distance have the same length.

In some embodiments, the baseline distance is based on an identified formation in which the downhole tool is located.

In some embodiments, the baseline distance is based on identifying that the downhole system is operating in a drilling state.

In some embodiments, the threshold change is a change in a ratio of the localized average ROP to the baseline ROP.

In some embodiments, the dynamic threshold is based on the baseline ROP.

In some embodiments, the dynamic threshold is inversely related to the baseline ROP.

In some embodiments, identifying the threshold change includes identifying an increase in the ROP data from the baseline ROP indicating a softer formation.

In some embodiments the downhole data is time-series data, the method further comprising generating depth-dependent downhole data by normalizing the downhole data based on the ROP data, and wherein determining the baseline ROP and identifying the threshold change are based on the depth-dependent downhole data.

In some embodiments, identifying the threshold change is based on determining that the downhole system is operating in a drilling state based on based on identifying that at least some of the downhole data is substantially constant.

In some embodiments, the downhole data includes one or more of torque data, hookload data, flow rate data, or weight on bit data.

In some embodiments, the method further includes automatically adjusting one or more drilling parameters based on the indication.

In some embodiments, the method further includes causing one or more additional measurements to be taken based on the indication, including one or more of resistivity measurements, porosity measurements, gamma ray measurements, cuttings analysis, gas analysis.

In some embodiments, the threshold change is identified, and the indication is generated without using formation information.

In some embodiments, a system includes at least one processor, memory in electronic communication with the at least one processor, and instructions stored in memory, the instructions being executable by the at least one processor to: receive downhole data associated with a downhole tool implemented in a wellbore, the downhole data including rate of penetration (ROP) data of the downhole tool; based on the downhole data, determine a baseline ROP; identify a threshold change of the ROP data from the baseline ROP, wherein the threshold change is a based on a dynamic threshold; and generate an indication of the threshold change.

In some embodiments, a computer-readable storage medium includes instructions that, when executed by at least one processor, cause the processor to: receive downhole data associated with a downhole tool implemented in a wellbore, the downhole data including rate of penetration (ROP) data of the downhole tool; based on the downhole data, determine a baseline ROP; identify a threshold change of the ROP data from the baseline ROP, wherein the threshold change is a based on a dynamic threshold; and generate an indication of the threshold change.

The embodiments of the drill break system have been primarily described with reference to wellbore drilling operations; the drill break system described herein may be used in applications other than the drilling of a wellbore. In other embodiments, the drill break 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 drill break 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. Additionally, as used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items.

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.