Downhole Event Detection

Abstract

A method for downhole event detection includes measuring a parameter of a wellbore using a first sensor of a drill string, and measuring the parameter of the wellbore using a second sensor of the drill string. The method also includes detecting, by surface equipment, an event in the wellbore based on a first set of measurements provided by the first sensor, and detecting, by the surface equipment, the event in the wellbore based on a second set of measurements provided by the second sensor. The method further includes assigning, by the surface equipment, a probability value to the event based on the event as detected in the first set of measurement values and the event as detected in the second set of measurement values.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional Patent Application No. 63/580,220, filed Sep. 1, 2023, entitled “Downhole Event Detection,” which is hereby incorporated herein by reference in its entirety.

BACKGROUND

In drilling a borehole into an earthen formation, such as for the recovery of hydrocarbons or minerals from a subsurface formation, a drill string is formed from a plurality of pipe joints connected end-to-end with a drill bit at the lower end. The drill bit is rotated, by rotation of the drill string or operation of a motor, so that the drill bit progresses downward into the earth to create a borehole along a predetermined trajectory. The drill string may include sensors that gather information about downhole conditions. For example, the drill string may include pressure sensors that can be used to measure the annular pressure surrounding the drill string within the wellbore. These pressure measurements may be used to estimate the density of the drilling fluid surrounding the drill string and may help to capture information relating to changing conditions in the wellbore. Knowledge of these changing conditions can be helpful, for example, to allow a drilling system to control kicks (e.g., influx of fluid into the wellbore from a formation) and/or loss of fluid from the wellbore.

SUMMARY

In one example, a drilling system includes a drill string and surface equipment coupled to the drill string. The drill string includes a sensor array having first and second sensors distributed along a length of the drill string. The first and second sensors are configured to measure a parameter of a wellbore, and transmit measurement values representative of the parameter to the surface equipment. The surface equipment is configured to detect an event in the wellbore based on a first set of measurement values received from the first sensor, and detect the event in the wellbore based on a second set of measurement values received from the second sensor. The surface equipment is also configured to assign a probability value to the event based on the event as detected in the first set of measurement values and the event as detected in the second set of measurement values.

In another example, a method for downhole event detection includes measuring a parameter of a wellbore using a first sensor of a drill string, and measuring the parameter of the wellbore using a second sensor of the drill string. The method also includes detecting, by surface equipment, an event in the wellbore based on a first set of measurements provided by the first sensor, and detecting, by the surface equipment, the event in the wellbore based on a second set of measurements provided by the second sensor. The method further includes assigning, by the surface equipment, a probability value to the event based on the event as detected in the first set of measurement values and the event as detected in the second set of measurement values.

In a further example, a non-transitory computer-readable medium is encoded with instructions that when executed cause a processor to receive a first set measurement values representative of a parameter of a wellbore measured by a first sensor of a drill string, receive a second set of measurement values representative of the parameter of the wellbore measured by a second sensor of the drill string, and receive a third set of measurement values representative of the parameter of the wellbore measured by a third sensor of the drill string. The instructions also cause the processor to detect an event in the wellbore based on the first set of measurement values received from the first sensor, detect the event in the wellbore based on the second set of measurement values received from the second sensor, and detect the event in the wellbore based on the third set of measurement values received from the second sensor. The instructions further cause the processor to assign a probability value to the event based on the event as detected in the first set of measurement values and the event as detected in the second set of measurement values, and update the probability value assigned to the event based on the event as detected in the third set of measurement values.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of various examples, reference will now be made to the accompanying drawings in which:

FIG. 1 shows an example drilling system that includes downhole event detection in accordance with the present disclosure.

FIG. 2 is a view of a portion of the drill string of FIG. 1, showing multiple sensors in accordance with the present disclosure.

FIG. 3 is a side view of a downhole tool of the drill string of FIG. 1, the downhole tool having a pressure sensor array in accordance with the present disclosure.

FIG. 4 is a flow diagram for an example method of downhole event detection implemented by the drilling system of FIG. 1.

FIG. 5 is a graph of example density data showing identification of possible events in the downhole event detection method of FIG. 4.

FIG. 6 is a graph of example density data from two sensors illustrating determination of event probability values in the downhole event detection method of FIG. 4.

FIG. 7 is a graph of example density data from three sensors illustrating the updating of event probability values in the downhole event detection method of FIG. 4.

FIG. 8 shows an example drilling system with downhole event detection that includes influx location and influx arrival time determination;

FIG. 9 is a block diagram of a rig computing system suitable for implementing the event detection method of FIG. 4 in the drilling system of FIG. 1, and the influx location and influx arrival time determination in the drilling system of FIG. 8.

DETAILED DESCRIPTION

FIG. 1 shows an example drilling system 100 that includes downhole event detection in accordance with the present disclosure. In the drilling system 100, a drilling platform 102 supports a derrick 104 having a draw works 136 for raising and lowering a drill string 108. In various embodiments, a top drive (not shown) or a rotary table 112 may be used to rotate the drill string 108. A drill bit 114 is positioned at the downhole end of the tool string 126, and is driven by rotation of the drill string 108 or by a downhole motor (not shown) positioned in the tool string 126 up hole of the drill bit 114. The drill string 108 includes a plurality of lengths (or joints) of drill pipe 118 that are coupled end-to-end. As the drill bit 114 rotates, it removes material from the various formations and creates the borehole 116 (also referred to as a wellbore). A pump 120 circulates drilling fluid through a feed pipe 122 and downhole through the interior of drill string 108, through orifices in drill bit 114, back to the surface via the annulus 140 around the drill string 108, and into a retention pit 124. The drilling fluid transports cuttings from the borehole 116 into the retention pit 124 and aids in maintaining the integrity of the borehole 116.

The drill string 108 includes sensors 110 distributed along the length thereof. The sensors 110 may measure various parameters including those related to the drill string 108, the borehole 116, and the formation, and transmit measurement values to the surface. The sensors 110 acquire information concerning various aspects of drilling operation (e.g., information about the formation being drilled, information about fluid in the borehole 116, information about the drill string 108). For example, sensors 110 may include pressure sensors and resistivity sensors. The pressure sensors may measure pressure in the borehole 116. Resistivity sensors may be used to transmit, and then receive, high frequency signals (e.g., electromagnetic waves) that travel through the formation surrounding the sensors 110. By comparing the transmitted and received signals, information can be determined concerning the nature of the formation through which the signal traveled, such as whether it contains water or hydrocarbons. Other sensors provided in sensors 110 may be used in conjunction with magnetic resonance imaging (MRI). Still other sensors provided in the sensors 110 may include gamma scintillators, which are used to determine the natural radioactivity of the formation, and nuclear detectors, which are used to determine the porosity and density of the formation.

The sensors 110 may also provide information concerning the direction of the drilling. This information can be used, for example, to control the direction in which the drill bit 114 advances while drilling. Such sensors may include a set of magnetometers and accelerometers to sense azimuth, inclination, and tool face direction.

FIG. 2 is a view of a portion of the drill string 108, showing multiple instances of the sensors 110 longitudinally spaced along the drill string 108. In one or more examples of the drill string 108, an instance of the sensors 110 may be positioned relatively close to the drill bit 114 so as to capture bottom hole pressures. Other instances of the sensors 110 may be spaced along the drill string 108 at equal spacings or unequal (e.g., asymmetric) spacings.

The information collected by the sensors 110 may be transmitted to the surface equipment (e.g., a rig computing system 132) for analysis. The rig computing system 132 may be local to the drilling platform 102 or remote from the drilling platform 102 (e.g, coupled to the drilling platform 102 via a network, such as the Internet). In some implementations of the drilling system 100, the drill pipe 118 of the drill string 108 is wired drill pipe that includes conductors for transmitting measurements in real-time from the sensors 110 to the surface equipment. Transmission of measurements to the surface via wired drill pipe allows the surface equipment to monitor downhole conditions and respond in real-time. For example, on detection of a downhole event, such as fluid influx, the surface equipment may halt drilling (e.g., halt rotation of the drill bit 114 and/or flow of the drilling fluid) or change drilling parameters.

FIG. 3 is a side view of an example of a downhole tool including the example sensors 110, wherein the sensors 110 include three sensor locations 312 and a pair of sensors 310 at each of the sensor locations 312. As shown, a first pair of sensors 310 may be provided at or near a first end of the sensors 110. The first pair of sensors 310 may include a first sensor 310 with a second sensor 310 spaced a short distance longitudinally and/or circumferentially away from the first sensor 310. A second pair of sensors 310 may be provided along the length of the sensors 110 and spaced from the first pair of sensors 310. The second pair of sensors 310 may include a third sensor 310 with a fourth sensor 310 spaced a short distance longitudinally and/or circumferentially away from the third sensor 310. A third pair of sensors 310 may be provided spaced from the second pair of sensors and at or near a second end of the sensors 110 opposite the first end. The third pair of sensors 310 may include a fifth sensor 310 with a sixth sensor 310 spaced a short distance longitudinally and/or circumferentially away from the fifth sensor 310. The second pair of sensors 310 may be arranged between the first and third pairs of sensors 310. As shown, the second pair of sensors 310 may be located so as to be spaced a first distance 314 from the first pair of sensors 310 and a second distance 316 from the third pair of sensors 310. While this first and second distance 314/316 may be equal, FIG. 3 shows these distances 314/316 being unequal. This unequal spacing may provide additional measurement advantages.

The sensors 310 in each pair may be spaced from one another by a short distance. The short distance may range from approximately 0.5 inches to approximately 18 inches, or from approximately 3 inches to approximately 12 inches or a short distance of approximately 6 inches may be provided. In contrast, the spacing of the pairs of sensors relative to adjacent pairs of sensors may range from approximately 24 inches to approximately 300 inches, or from approximately 36 inches to approximately 120 inches, or from approximately 48 inches to approximately 96 inches, or from approximately 60 inches to approximately 72 inches, for example.

In one or more implementations, the sensors 310 in the sensor array 304 may be pressure sensors. For example, mechanical pressure transducers or capacitance pressure transducers may be provided. Additionally, or alternatively, strain pressure transducers or quartz pressure transducers may be provided. In any case, the sensors may be adapted to emit a signal based on the pressure it is experiencing at any given time. The sensors may emit a signal continually, periodically, or when prompted, for example. In one or more examples, the sensors 310 may be in wired or wireless communication with a downhole or surface controller or other receiver for analyzing the sensor data and/or applying the sensor data to control the drilling system 100.

The sensors 310 in the sensor array 304 may be powered by and/or in signal communication with the telemetry system including the wired drill pipe and/or with one another. That is, for example, where differential sensor measurements within the tool are desired, one or more sensors or sensor pairs may be hardwired to another so as to emit a differential pressure signal to the telemetry system.

FIG. 4 is a flow diagram for an example method 400 of downhole event detection that may be implemented by the drilling system 100. Though depicted sequentially as a matter of convenience, at least some of the actions shown can be performed in a different order and/or performed in parallel. Additionally, some implementations may perform only some of the actions shown. Operations of the method 400 may be performed in the drill string 108 and the rig computing system 132.

In block 402, the drill string 108 and/or the drill bit 114 are rotating to drill and extend the borehole 116. Drilling fluid is circulating in the borehole 116. The sensors 110 may acquire downhole pressure measurements and/or other measurements of parameters of the borehole environment. (e.g., drill bit rotation speed (revolutions per minute), gamma ray measurements, vibration measurements, temperature measurements, resistivity measurements, etc.). The measurements acquired by the sensors 110 may be transmitted to the surface equipment (e.g., the rig computer system 132) via wired drill pipe telemetry.

The measurement values transmitted by the sensors 110 may include a first set of measurements transmitted by a first instance of the sensors 110, a second set of measurements transmitted by a second instance of the sensors 110, and a third set of measurements transmitted by a third instance of the sensors 110. As described above, the sensors 110 may include pressure sensors, and the measurements provided by the sensors 110 may be measurements of pressure in the borehole 116.

In examples of the method 400 using measurements of pressure in the borehole 116, the surface equipment may estimate density of the fluid in the borehole 116 based on the pressure measurements received from the sensors 110. Operations of the method 400 are described with reference to density data derived from downhole pressure measurements. However, while the method 400 is described with reference to pressure measurements received from the sensors 110, and density data derived therefrom, the method 400 may be applied to measurements of other wellbore parameters.

In block 404, the surface equipment applies smoothing to the measurement data received from the sensors 110 (or data derived therefrom). The smoothing may include subdividing or partitioning the measurements into time segments (windowing of the measurements) of a selected duration or number of measurement values. For example, the measurement data may be subdivided into segments that are 500 samples in length, in which case the time window applied to the measurement data is 500 sample intervals. Other examples may apply a different window length depending on the event duration and the noise level of measurements. For each segment, the surface equipment may fit a line with linear regression to the data of the segment and determine a slope of the line. The window applied to the measurement data may be shifted in time to produce overlapping or non-overlapping segments of the measurement data. The surface equipment may plot the slope values determined for each time window to produce smoothed measurements with clear peaks and valleys.

In block 406, the surface equipment compares the smoothed measurements generated in block 404 to threshold values, and assigns symbol values to the threshold crossings. For example, the surface equipment may compare the smoothed measurements to a peak threshold value, a valley threshold value, and a zero-crossing threshold value to identify peaks, valleys, and zero-crossings in the smoothed measurement data. A peak may be defined as a local maximum where the slope is greater than a peak threshold. A valley may be defined as a local minimum where the slope is less than a valley threshold. A zero-crossing may be defined as a sign change (e.g., “+” to “−” or “−” to “+”). In an example of the method 400, a symbol value of “1” may be assigned to an identified peak, a symbol value of “−1” may be assigned to an identified valley, and a symbol value of “0” may be assigned to an identified zero-crossing.

In block 408, the surface equipment selects one or more event codes (also referred to as an “event definition”) to be compared to the symbols assigned to the measurement data in block 406. For example, a symbol sequence [0, 1, 0, −1, 0] may define an event code for an influx (e.g., a flow of fluid from the formation into the borehole 116). This event code implies that an influx is marked by an increasing trend in the slope followed by decreasing values and change of sign. Other event codes may be selected to define various other downhole events.

In block 410, the surface equipment identifies possible downhole events by comparing the event codes selected in block 408 to the symbols assigned to the smoothed measurement data in block 406. FIG. 5 is a graph of example pressure density data derived from pressure measurements showing identification of possible events. FIG. 5 shows density data, smoothed density data, and nine possible fluid influx events identified by comparing the influx event code to the symbol sequence assigned to the smoothed density data. In FIG. 5, an oval has been placed around the peak included in each symbol sequence that may indicate an influx event. A shaded area around the peak defines the extent of the possible influx event based on the influx event code. It should be noted that the last event code ‘0’ in the symbol sequence [0, 1, 0, −1, 0] is only used to confirm that the original density data returns to the non-event level after a peak, and is therefore not included in calculating the time duration of an influx event.

Returning to FIG. 4, in block 412, the surface equipment quantifies the uncertainty of the time difference between the downhole events detected by each of two adjacent sensors 110. In other words, the surface equipment assigns a probability value to the event, where the probability value estimates the likelihood that the event is real. First, the surface equipment may estimate the uncertainty in time (relative to the location of a possible downhole event) between peaks at two adjacent instances of the sensors 110. The uncertainty may be estimated based on the distance between the two instances of the sensors 110 in the drill string 108 (the spacing of the two adjacent instances of the sensors 110) and flow rate of the drilling fluid in the borehole 116. Second, the surface equipment determines a probability value for each possible downhole event being real by comparing the location of a peak of a possible event detected in a first set of measurements to a location of peak of in a second set of measurements. Finally, an overall probability of the downhole event being real may be determined as a weighted sum of probabilities determined for all available locations of the sensors 110.

FIG. 6 is a graph of example density data derived from two instances of the sensors 110 illustrating determination of event probability values in the method 400. The data in FIG. 6 is similar to that of FIG. 5. In FIG. 6, the graph 602 represents density data and possible influx events derived from a first set of measurements received from a first sensor of the sensors 110. The graph 604 represents density data and possible influx events derived from a second set of measurements received from a second sensor of the sensors 110. The interval 606 represents the expected time from a peak of a possible event 610 identified in the graph 602 to a peak of a possible event identified in the graph 604. The interval 608 represents the expected time from a peak of a possible event 612 identified in the graph 602 to a peak of a possible event identified in the graph 604. The curves 615 and 618 represent the probability distribution for the timing of the peak of a downhole event in the graph 604 relative to the peak of an event in the graph 602.

Comparing the graphs 602 and 604, the peak of the curve 614 of the graph 604 is relatively distant (outside of the curve 615) in time from the optimal time represented as the apex of the curve 615. Accordingly, a low value (e.g., approximately zero) may be assigned to the probability that the downhole event 610 is real. The peak of the possible downhole event 616 of the graph 604 is relatively near (within of the curve 618) in time from optimal time represented as the apex of the curve 618. Accordingly, a high value (e.g., approximately one) may be assigned to the probability that the downhole event 612 is real.

Returning to FIG. 4, in block 414, the surface equipment updates event probability value based on additional sensor measurements. For example, the surface equipment receives measurement data from a third instance of the sensors 110, processes the measurement data according to blocks 408-412, and updates the probability values as per block 412. The surface equipment may update the probability values for each possible downhole event for any number of instances of the sensors 110. FIG. 7 is a graph of example density data from three sensors illustrating the updating of event probability values in the downhole event detection method 400. In the graphs 702, 704, and 706, each sub-graph represents measurement data received from a different instance of the sensors 110. In the graph 702, an event has been detected in one set of measurement data (as shown in the shaded area of graph 702), so event probability is uncertain (e.g., 0.50). In the graph 704, the event has been detected in two sets of measurement data (as shown in the shaded areas of graph 704), so event probability is updated to a higher value (e.g., 0.75). In the graph 706, the event has been detected in three sets of measurement data (as shown in the shaded areas of graph 706), so event probability is updated to a yet higher value (e.g., 0.90).

Returning again to FIG. 4, in block 416, the surface equipment distinguishes true (real) downhole events from false events based on the probability value determined for each possible downhole event. For example, if the event probability value exceeds a predetermined threshold value (e.g., 90%), the downhole event may be deemed real.

In block 418, the surface equipment initiates mitigation of the downhole event deemed to be real in block 416. For example, the surface equipment may halt drilling, halt rotation of the drill bit 114, halt extension of the borehole 116, increase drilling fluid density, apply backpressure using managed pressure drilling, space out and shut in the wellbore using annular or pipe rams, initiate autonomous well control, shear the drill pipe, modify the height of drilling fluid using controlled mud level, etc.).

FIG. 8 shows another example of the drilling system 100. The drilling system 100 includes the drill string 108, and the drill string 108 includes N distributed sensors 810₁-810_N (collectively sensors 810). The sensors 810 are examples of the sensors 110. Sensors 810₁, 810₂, 810₃, 810₄, 810_N-2, 810_N-1, and 810_N are shown in FIG. 8. The drilling system 100 includes event detection as described herein, and includes influx location determination and influx arrival time determination. Influx location determination estimates the location of a fluid influx in the borehole 116. Influx arrival time determination estimates the time at which the fluid influx will reach a target location. FIG. 8 shows target location 812. In practice, the target location 812 may be at the surface, at the ocean bottom, in the borehole 116, or any other location where a fluid influx flows in the drilling system 100.

In FIG. 8, A₁-A_K define the annulus areas of the borehole 116 at K sections. The annulus area can be calculated as the area of the outer casing (varying at different sections) minus the area of internal tubing (fixed based on the diameter of the tubing). The annulus areas A₁, A₂, A_K-1, and A_K are shown in FIG. 8. AC₁-AC_K-1 define the K−1 locations where the annulus area of the borehole 116 changes significantly.

Using flow rates that are derived from the pump rates, FR_i, where i=1-N, the current location of a fluid influx can be calculated as:

$\begin{array}{cc}{D}^{\mathrm{cur}}=\left(D^{\mathrm{cr}}-D_n\right)+{\mathrm{FR}}_n{t}^n/A_k& \left(1\right)\end{array}$

• • where:
  • n is the index of the sensor 810 at which the fluid influx was last detected, n is updated as the fluid influx moves towards the target location 812 in the borehole 116;
  • D^cr is the depth of the target location;
  • Dⁿ is the depth of the sensor 810 at which the fluid influx was last detected;
  • k is the index of the section A_k that is between sensors 810n and 810n+1;
  • FR_n is the stable flow rate (e.g., standard deviation of FR<5) measured at the sensor 810 at which the fluid influx was last detected; and
  • tⁿ is the time duration (e.g., minutes) since the fluid influx was detected at sensor location n.

The term FR_ntⁿ/A_k can be expanded if multiple area sections lie between sensor locations n and n+1.

Time remaining until the fluid influx arrives at the target location 812, termed remaining useful life (RUL), can be calculated as:

$\begin{array}{cc}\mathrm{RUL}=\left(D^{n+1}-D^{\mathrm{curr}}\right)A_k^n/{\mathrm{FR}}_n+{\sum }_{i=n+1}^{N-1}\left(D^{i+1}-D^i\right)A_k^i/{\mathrm{FR}}_i+\left(D^{\mathrm{cr}}-D^N\right)A_k^N/{\mathrm{FR}}_N& \left(2\right)\end{array}$

• • where:
  • (Dⁿ⁺¹−D^cur)A_kⁿ/FR_n is the expected time duration for fluid influx to flow from the current sensor location (n) to the next sensor location (n+1);
  • Σ_i=n+1^N-1 (Dⁱ⁺¹−Dⁱ)A_kⁱ/FR_i is the time for the fluid influx to flow from the location of the sensor n+1 to the location of the sensor N; and
  • (D^cr−D^N)A_k^N/FR_N is the time for the fluid influx to flow from the location of sensor N to the target location 812.

Influx location determination and influx arrival time determination as described herein may be implemented by the rig computing system 132 (e.g., as part of the method 400). The rig computing system 132 may apply the results of influx location determination and/or influx arrival time determination to initiate mitigation or to select a mitigation action to be performed as described in block 418 of the method 400.

FIG. 9 is a block diagram of a rig computing system 900 suitable for implementing the event detection method of FIG. 4 in the drilling system 100. The rig computing system 900 is an example of the rig computing system 132. The rig computing system 900 may be coupled to drilling components 914, which may include the pump 120, the draw works 136, the sensors 110, and other rig and downhole components. The rig computing system 900 may be coupled to one or more network devices 912 across a network 910. A network device 912 may include any kind of device accessible across network 910 with which the rig computing system 900 may communicate. For example, network device 912 may be an additional rig computing system, a server, or a remote computer. Network 910 may include many different types of computer networks available today, such as the Internet, a corporate network, a LAN, or a personal network such as those over a Bluetooth connection. Each of these networks can contain wired or wireless programmable devices and operate using any number of network protocols (e.g., TCP/IP). Network 910 may be connected to gateways and routers, servers, and end user computers.

The rig computing system 900 may include, for example, a processor 902 and storage 904. The processor 902 may include a single processor or multiple processors. Further, the processor 902 may include different kinds of processors, such as a CPU and a GPU. The storage 904 may include a number of software or firmware modules executable by processor 902. Storage 904 is a non-transitory computer-readable medium and may include a single memory device or multiple memory devices, including semiconductor memory, magnetic memory, optical memory, etc. As depicted, storage 904 may include measurements 906, downhole event detection 908, and influx location and arrival time determination 916. The measurements 906 include measurement values received from the sensors 110. The downhole event detection 908 includes instructions executable by the processor 902 to provide the downhole event detection of the method 400. The 916 includes instructions executable by the processor 902 to determine the location of an influx in the borehole 116, and the time of arrival of the influx at a target location as described herein. The storage 904 may also include one or more drilling applications. The drilling applications may import well plans that describe, for example, the desired drilling directions, and execute the well plans to drill the borehole 116. Although components are depicted within a single computing device, the components and functionalities described with respect to the rig computing system 900 may instead be reconfigured in a different combination or may be distributed among multiple computing devices.

The rig computing system 900 may transmit drilling data, downhole event indications, or other information from the rig computing system 900 to the network device 912. For example, rig computing system 900 may transmit data related to one or more of the drilling applications or a detected downhole event to a network device 912 associated with an entity that manages the drilling system 100 or a particular drilling application. Further, the network device 912 may include end user computers or servers utilized in conjunction with rig computing system 900.

The rig computing system 900 may also include user interface devices, such as keyboards, monitors, etc.) that allow a user to interact with the drilling system 100. For example, the rig computing system 900 may provide information related to a downhole event detected using the method 400 on a display device, such as a computer monitor, to inform a user of the downhole event. The rig computing system 900 may automatically, or responsive to a control prompt received via a user interface device, initiate mitigation actions responsive to the downhole event.

Certain terms have been used throughout this description and claims to refer to particular system components. As one skilled in the art will appreciate, different parties may refer to a component by different names. This document does not intend to distinguish between components that differ in name but not function. In this disclosure and claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection or through an indirect connection via other devices and connections. The recitation “based on” is intended to mean “based at least in part on.” Therefore, if X is based on Y, X may be a function of Y and any number of other factors.

A device that is “configured to” perform a task or function may be configured (e.g., programmed and/or hardwired) at a time of manufacturing by a manufacturer to perform the function and/or may be configurable (or reconfigurable) by a user after manufacturing to perform the function and/or other additional or alternative functions. The configuring may be through firmware and/or software programming of the device, through a construction and/or layout of hardware components and interconnections of the device, or a combination thereof.

A circuit or device that is described herein as including certain components may instead be adapted to be coupled to those components to form the described circuitry or device. For example, a structure described as including one or more elements may instead include only some of the elements within a single physical device and may be adapted to be coupled to at least some of the elements to form the described structure either at a time of manufacture or after a time of manufacture, for example, by an end-user and/or a third-party.

In this description, unless otherwise stated, “about,” “approximately” or “substantially” preceding a parameter means being within +/−10 percent of that parameter or, if the parameter is zero, a reasonable range of values around zero.

The above discussion is meant to be illustrative of the principles and various embodiments of the present invention. Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such variations and modifications.

Claims

1. A drilling system comprising:

a drill string and surface equipment coupled to the drill string, in which:

the drill string includes: a sensor array having first and second sensors distributed along a length of the drill string, the first and second sensors configured to: measure a parameter of a wellbore; and transmit measurement values representative of the parameter to the surface equipment; and

the surface equipment is configured to: detect an event in the wellbore based on a first set of measurement values received from the first sensor; detect the event in the wellbore based on a second set of measurement values received from the second sensor; and assign a probability value to the event based on the event as detected in the first set of measurement values and the event as detected in the second set of measurement values.

2. The drilling system of claim 1 wherein:

the drill string includes a third sensor configured to: measure the parameter of the wellbore; and transmit a third set of measurement values representative of the parameter to the surface equipment;

the surface equipment is configured to: detect the event in the wellbore based on the third set of measurement values received from the third sensor; and update the probability value assigned to the event based on the event as detected in the third set of measurement values.

3. The drilling system of claim 1, wherein the surface equipment is configured to generate smoothed measurement values by partitioning the measurement values into overlapping or non-overlapping segments and assigning a slope value to each of the segments, the slope value representing the slope of a line fit to the measurement values of a segment.

4. The drilling system of claim 3, wherein the surface equipment is configured to:

identify peaks, valleys, and zero-crossings in the smoothed measurement values, and

assign symbol values to the peaks, valleys, and zero-crossing including: assignment of a first symbol to each peak, assignment of a second symbol to each valley, and assignment of a third symbol to each zero-crossing.

5. The drilling system of claim 4 wherein the surface equipment is configured to detect the event by comparing a symbol set that includes multiple sequential ones of the symbol values to an event definition that identifies the event based on the symbol values.

6. The drilling system of claim 4, wherein the surface equipment is configured to assign the probability value to the event based on a time difference between a peak of the event in the first set of measurement values and a peak of the event in the second set of measurement values.

7. The drilling system of claim 1, wherein the surface equipment is configured to identify the event as being real based on the probability value exceeding a threshold.

8. The drilling system of claim 7, wherein the surface equipment is configured to halt drilling based on the event being identified as real.

9. The drilling system of claim 7, wherein the surface equipment is configured to, based on the event being identified as real:

determine a location of a fluid influx in the wellbore; and

determine a time at which the fluid influx will reach a target location.

10. A method for downhole event detection comprising:

measuring a parameter of a wellbore using a first sensor of a drill string;

measuring the parameter of the wellbore using a second sensor of the drill string;

detecting, by surface equipment, an event in the wellbore based on a first set of measurements provided by the first sensor;

detecting, by surface equipment, the event in the wellbore based on a second set of measurements provided by the second sensor; and

assigning, by surface equipment, a probability value to the event based on the event as detected in the first set of measurement values and the event as detected in the second set of measurement values.

11. The method of claim 10, further comprising:

measuring the parameter of the wellbore using a third sensor of the drill string;

detecting, by surface equipment, the event in the wellbore based on a third set of measurements provided by the third sensor; and

updating, by surface equipment, the probability value assigned to the event based on the event as detected in the third set of measurement values.

12. The method of claim 10, further comprising generating, by the surface equipment, smoothed measurement values by partitioning the measurement values into segments and assigning a slope value to each of the segments, the slope value representing the slope of a line fit to the measurement values of the segment.

13. The method of claim 12, further comprising:

identifying, by the surface equipment, peaks, valleys, and zero-crossings in the smoothed measurement values, and

assign, by the surface equipment, symbol values to the peaks, valleys, and zero-crossing including: assignment of a first symbol to each peak, assignment of a second symbol to each valley, and assignment of a third symbol to each zero-crossing.

14. The method of claim 13, further comprising detecting the event by comparing a symbol set that includes multiple sequential ones of the symbol values to an event definition that identifies the event based on the symbol values.

15. The method of claim 13, further comprising assigning the probability value to the event based on a time difference between a peak of the event in the first set of measurement values and a peak of the event in the second set of measurement values.

16. The method of claim 10, further comprising identifying, by the surface equipment, the event as being real based on the probability value exceeding a threshold.

17. The method of claim 16, further comprising halting drilling responsive to the event being identified as real.

18. The method of claim 16, further comprising:

based on the event being identified as real: determining a location of a fluid influx in the wellbore; and determining a time at which the fluid influx will reach a target location.

19. A non-transitory computer-readable medium encoded with instructions that when executed cause a processor to:

receive a first set measurement values representative of a parameter of a wellbore measured by a first sensor of a drill string;

receive a second set of measurement values representative of the parameter of the wellbore measured by a second sensor of the drill string;

receive a third set of measurement values representative of the parameter of the wellbore measured by a third sensor of the drill string;

detect an event in the wellbore based on the first set of measurement values received from the first sensor;

detect the event in the wellbore based on the second set of measurement values received from the second sensor;

detect the event in the wellbore based on the third set of measurement values received from the second sensor;

assign a probability value to the event based on the event as detected in the first set of measurement values and the event as detected in the second set of measurement values; and

update the probability value assigned to the event based on the event as detected in the third set of measurement values.

20. The non-transitory computer-readable medium of claim 19, wherein the instructions when executed cause the processor to generate smoothed measurement values by partitioning the measurement values into segments and assigning a slope value to each of the segments, the slope value representing the slope of a line fit to the measurement values of a segment.

21. The non-transitory computer-readable medium of claim 20, wherein the instructions when executed cause the processor to:

identify peaks, valleys, and zero-crossings in the smoothed measurement values, and

assign symbol values to the peaks, valleys, and zero-crossing including: assignment of a first symbol to each peak, assignment of a second symbol to each valley, and assignment of a third symbol to each zero-crossing.

22. The non-transitory computer-readable medium of claim 19, wherein the instructions when executed cause the processor to:

assign the probability value to the event based on a time difference between a peak of the event in the first set of measurement values and a peak of the event in the second set of measurement values; and

identify the event as being real based on the probability value exceeding a threshold.

23. The non-transitory computer-readable medium of claim 22, wherein the instructions when executed cause the processor to halt drilling based on the event being identified as real.

24. The non-transitory computer-readable medium of claim 22, wherein the instructions when executed cause the processor to, based on the event being identified as real:

determine a location of a fluid influx in the wellbore; and

determine a time at which the fluid influx will reach a target location.