CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit to U.S. Provisional Application No. 63/335,217, filed on April 26, 2022; and this application hereby incorporates herein U.S. Provisional Application No. 63/335,217 as if set forth herein in its entirety.

BACKGROUND

1. Field of Inventions

[0002] The field of this application and any resulting patent is systems and methods for event detection during electric submersible pump assembly deployment.

2. Description of Related Art

[0003] Various systems and methods for event detection during electric submersible pump assembly deployment have been proposed that include event detection assemblies. However, those systems and methods lack the combination of steps and/or features of the systems and methods claimed herein Furthermore, it is contemplated that the systems and/or structures methods herein, including those claimed, solve certain problems that prior art systems and methods have failed to solve. Also, the system and/or methods claimed herein may have benefits that would be surprising and unexpected to a hypothetical person of ordinary skill with knowledge of the prior art existing as of the filing date of this application.

SUMMARY

[0004] Disclosed herein are systems for event detection during electric submersible pump assembly deployment that may each include: an event detection assembly for electric submersible pump assembly deployment downhole that may include: a reel; an electric cable that may be coupled to the reel and may be capable of being electrically coupled to an electric submersible pump assembly; one or more sensors, which may be: configured to detect a first location on the electric cable and to detect a second location on the electric cable; and configured to detect an event on the cable occurring any time from detection of the first location to detection of the second location; and an alarm configured to actuate in response to detection of an event.

[0005] Additionally, disclosed herein are systems for event detection during electric submersible pump assembly deployment that may each include: an event detection assembly for electric submersible pump assembly deployment downhole that may include: a reel; an electric cable that may be coupled to the reel and may be capable of being electrically coupled to an electric submersible pump assembly; one or more sensors configured to: identify a portion of the electric cable; and detect an event on the cable occurring during identification of the portion of the electric cable; and an alarm configured to actuate in response to detection of an event.

[0006] Also, disclosed herein are systems for event detection during electric submersible pump assembly deployment that may each include: one or more sensors configured to detect a first location on an electric cable and to detect a second location on the electric cable, wherein the electric cable is capable of being coupled to a reel, and of being electrically coupled to an electric submersible pump; and one or more sensors configured to detect an event on the cable that occurs between detection of the first location and detection of the second location.

[0007] In addition, disclosed herein are methods for event detection during electric submersible pump assembly deployment for electric submersible pump assembly deployments that may each include: providing an event detection assembly that may include: a reel; an electric cable coupled to the reel and to the electric submersible pump assembly; one or more sensors; a controller; and an alarm; detecting, using any of the one of more sensors, a first location on the electric cable and a second location on the electric cable; detecting, using any of the one or more sensors, an event on the electric cable occurring any time from detection of the first location to detection of the second location; and actuating the alarm in response to detection of the event.

[0008] Further, disclosed herein are methods for event detection during electric submersible pump assembly deployment for electric submersible pump assembly deployments that may each include: providing an event detection assembly that may include: a reel; an electric cable coupled to the reel and to the electric submersible pump assembly; one or more sensors; a controller; and an alarm; detecting, with the one or more sensors, a portion of the electric cable; detecting, with the one or more sensors, an event on the electric cable occurring any time during detection of the cable portion; and actuating the alarm in response to detection of the event.

BRIEF DESCRIPTION OF THE DRAWINGS

[0009] FIG. 1 is a schematic drawing that illustrates an example of a downhole wellbore system that includes an event detection assembly for detecting events during electric submersible pump assembly deployment.

[0010] FIG. 2 illustrates a cross-sectional perspective view of a reel and a perspective view of an event detection assembly coupled to the reel.

[0011] FIG. 3 illustrates an exploded perspective view of components of an event detection assembly.

[0012] FIG. 4 illustrates a perspective view of a cable disposed between a sensor and a sheave.

[0013] FIG. 5 is a schematic illustration of a cable having 3-phase wires coupled to two relays.

[0014] FIG. 6 is a schematic drawing that illustrates an example of event detection assembly for electric submersible pump assembly deployment including both surface sensors and downhole sensors.

DETAILED DESCRIPTION

1. Introduction

[0015] A detailed description will now be provided. The purpose of this detailed description, which includes the drawings, is to satisfy the statutory requirements of 35 U.S.C. § 112. For example, the detailed description includes a description of inventions defined by the claims and sufficient information that would enable a person having ordinary skill in the art to make and use the inventions. In the figures, like elements are generally indicated by like reference numerals regardless of the view or figure in which the elements appear. The figures are intended to assist with the description and to provide a visual representation of certain aspects of the subject matter described herein. The figures are not all necessarily drawn to scale, nor do they show all the structural details, nor do they limit the scope of the claims. [0016] Each of the appended claims defines a separate invention which, for infringement purposes, is recognized as including equivalents of the various elements or limitations specified in the claims. Depending on the context, all references below to the “invention” may in some cases refer to certain specific embodiments only. In other cases, it will be recognized that references to the “invention” will refer to the subject matter recited in one or more, but not necessarily all, of the claims. Each of the inventions will now be described in greater detail below, including specific embodiments, versions, and examples, but the inventions are not limited to these specific embodiments, versions, or examples, which are included to enable a person having ordinary skill in the art to make and use the inventions when the information in this patent is combined with available information and technology. Various terms as used herein are defined below, and the definitions should be adopted when construing the claims that include those terms, except to the extent a different meaning is given within the specification or in express representations to the Patent and Trademark Office (PTO). To the extent a term used in a claim is not defined below or in representations to the PTO, it should be given the broadest definition persons having skill in the art have given that term as reflected in at least one printed publication, dictionary, or issued patent.

2. Selected Definitions

[0017] Certain claims include one or more of the following terms which, as used herein, are expressly defined below.

[0018] The term adjacent as used herein means next to and includes physical contact but does not require physical contact.

[0019] The term aperture as used herein is defined as any opening in a solid object or structure. For example, an aperture may be an opening that begins on one side of the solid object and ends on the other side of the object. An aperture may alternatively be an opening that does not pass entirely through the object, but only partially passes through, e.g., a groove. An aperture can be an opening in an object that is completely circumscribed, defined, or delimited by the object itself. Alternatively, an aperture can be an opening in the object formed when the object is combined with one or more other objects or structures. One or more apertures may be disposed and pass entirely through a casing, a conduit, and/or a pump. An aperture may receive another object and permit ingress and/or egress of the object through the aperture.

[0020] The term “assembly” as used herein is defined as any set of components that have been fully or partially assembled together. A group of assemblies may be coupled to form a body having an inner surface and an outer surface.

[0021] The terms “cable” as used herein is defined as any sheathed electrically conductive structure shaped, sized, and configured for transmission of electricity and electrical signals thereupon.

[0022] The term “coupled’’ as used herein is defined as directly or indirectly connected, attached, or integral with, e.g., part of. A first object may be coupled to a second object such that the first object is positioned at a specific location and orientation with respect to the second obj ect. For example, controller may be coupled to a reel. Two objects may be “permanently coupled’ to each other via adhesive, or welding, or they may be mechanically pressed together; or they may be removably coupled via collets, screws, or nuts and bolts. Thus, a controller may be removably coupled to a reel such that the controller may then be uncoupled and removed from the reel. Two objects may be “electrically coupled,” e.g., where electricity in a first object may be conducted to second object. For example, a terminal of a cable may be electrically coupled to a pothead of an electrical submersible motor such that, in some cases, electricity flows from the cable to the electrical submersible motor. Two conductive objects may be electrically coupled to each other via physical contact. Two conductive objects may be electrically coupled to each other via a conductive wire. Two conductive objects may be electrically coupled to each other wirelessly, e.g., via electromagnetic waves.

[0023] The term “deploy” as used herein is defined as move a structure or assembly in reference to another structure or assembly. Running an electric submersible pump assembly (ESP assembly) into a wellbore may be considered deploying the ESP assembly. Pulling an ESP assembly out of a wellbore may also be considered deploying the ESP assembly. [0024] The term “disposed in as used herein means having been put, placed, positioned, inserted, or oriented in a particular location. For example, when a controller occupies a position within a housing, the controller is disposed within the housing.

[0025] The term “electric submersible pump assembly' as used herein means an assembly configured for artificial lift of downhole fluid to surface. An electric submersible pump assembly may include a motor, a seal, and a pump. Motors, pumps, and other components of electric submersible pump assemblies may each include one or more sensors capable of detecting various properties related to the individual components and surrounding environments, including but not limited to resistance, insulation, amperage, voltage, pressure, temperature, and fluid flow.

[0026] The term “event” as used herein is defined as a set of one or more detectable occurrences. An event, in the context of electric submersible pump assembly deployment, may include but is not limited to, downhole kick, power surge, power lost, broken cable, blowout, unresponsive equipment, ESP system dielectric (insulation) abnormal reduction, phase to phase conductor resistance imbalance, and downhole power generation with permanent magnet motors. A chain of related events may indicate a trend or a regular pattern of constancy or change, e.g., in pressure, temperature, vibration, or flow, over time.

[0027] The terms “first, “second ” and “third” when used to refer to certain things, e g., structures, are terms that differentiate those things from one another and do not mean or imply anything in terms of importance, sequence, etc.

[0028] The term “horizontal wellbore” as used herein is defined as a wellbore that has been drilled using some type of directional drilling technique and includes at least a portion that is more than 45 degrees from vertical. However, at least a portion of any horizontal wellbore is vertical or at least substantially vertical, as the term “vertical” is used in the oil and gas industry, i.e., pointed toward the center of the earth. For example, the upper portion of the wellbore closest to the surface is typically vertical, or substantially vertical, and the lower portion is less vertical and closer to perfectly horizontal relative to the earth's surface above that portion of the wellbore. For example, a horizontal wellbore may include a wellbore that is formed as a kick-out wellbore from an originally drilled vertical wellbore. Any horizontal wellbore mentioned herein is defined to include a “heel,” which is the part, point, or section of the wellbore where the portion of the wellbore changes from being vertical to being horizontal, and the “toe” which refers to the end of the wellbore. In any discussion of wellbores herein, there is no restriction in length unless stated specifically otherwise, a central part of any elongated space, such as a conduit.

[0029] The term “pressure” as used herein means force(s), including but not limited to the forces exerted in every direction an enclosed space, e.g., forces applied against the inside surfaces of any structure defining the enclosed space. Pressure may be, for example, exerted against a surface of an object, e.g., rotor, piston head, seat, and/or dart, from the flow of fluid across the surface.

[0030] The term “protrusion ” as used herein is defined as a structure extending from a surface of an object. A protrusion may be a knob. For example, a knob may protrude from a surface of a cable. A protrusion may be a step extending above a surface. For example, a strip of armor wrapped around electric cables may have a second portion overlapping a first portion such that the second forms a step on the first portion.

[0031] The term “providing” as used herein is defined as making available, furnishing, supplying, equipping, or causing to be placed in position.

[0032] The term “relay” as used as noun herein is defined as any device configured for opening or closing electrical coupling between two conductive objects or structures. A relay may be an electrically operated switch.

[0033] The term “sensor” as used herein is defined as any device configured for detection of one or more properties of an object or structure. Properties of an object or structure may include, but is not limited to, length, diameter, resistance, insulation, amperage, voltage, pressure, temperature, fluid flow, cable damage, and cable defect. A sensor may be an optical device. A sensor may be a laser device. A sensor may detect markings, e.g., paint, ink, protrusions, notches, scratches, on a surface of an electric cable. A sensor may detect structures, e.g., ridges, protrusions, or indentations, on a surface of an electric cable. A sensor may detect structures, e.g., RFID tags, magnets, or ferrous material, coupled to an electric cable. [0034] The term “unitary” as used herein means having the nature, properties, or characteristics of a single unit. For example, a shaft and a rotor may be unitary where they are connected, directly or indirectly, and fulfdl the intended purpose of being rotated. Also, a shaft and an impeller may be unitary where they are connected, directly or indirectly, and fulfdl the intended purpose of being rotated to move fluid, e.g., water, hydrocarbon, or lubricant.

[0035] The terms “upper” and “lower” as used herein are relative terms describing the position of one object, thing, or point positioned in its intended useful position, relative to some other object, thing, or point also positioned in its intended useful position, when the objects, things, or points are compared to distance from the center of the earth. For example, the term “upper” identifies any object or part of a particular object that is farther away from the center of the earth than some other object or part of that particular object, when the objects are positioned in their intended useful positions.

[0036] The term “wellbore” as used herein is defined as the drilled elongated cylindrical borehole extending through the formation from the surface, where the drilling was initiated, to the endpoint where the drilling was terminated. Depending on the context, the term may also include any downhole components placed within the borehole, e.g., casing, cement, tubing, packers, etc.

3 Certain Specific Embodiments

[0037] Disclosed herein are systems for event detection during electric submersible pump assembly deployment that may each include: an event detection assembly for electric submersible pump assembly deployment downhole that may include: a reel; an electric cable coupled to the reel and capable of being electrically coupled to an electric submersible pump assembly; a first sensor configured to detect a first location on the electric cable and to detect a second location on the electric cable; a second sensor configured to detect an event on the cable that occurred any time from detection of the first location to detection of the second location; and an alarm configured to actuate when an event has been detected.

[0038] Additionally, disclosed herein are systems for event detection during electric submersible pump assembly deployment that may each include: an event detection assembly for electric submersible pump assembly deployment downhole that may include: a reel; an electric cable coupled to the reel and capable of being electrically coupled to an electric submersible pump assembly; a first sensor configured to identify a cable portion of the electric cable; a second sensor configured to detect an event on the cable that occurred any time during identification of the cable portion; and an alarm configured to actuate when an event has been detected.

[0039] Also, disclosed herein are systems for event detection during electric submersible pump assembly deployment that may each include: one or more sensors configured to detect a first location on an electric cable and to detect a second location on the electric cable, wherein the electric cable is capable of being coupled to a reel, and of being electrically coupled to an electric submersible pump; and one or more sensors configured to detect an event on the cable that occurs between detection of the first location and detection of the second location.

[0040] In addition, disclosed herein are methods for event detection during electric submersible pump assembly deployment for electric submersible pump assembly deployments that may each include: providing an event detection assembly that may include: a reel; an electric cable coupled to the reel and to the electric submersible pump assembly; a first sensor; a second sensor; a controller; and an alarm; detecting, with the first sensor, a first location on the electric cable and a second location on the electric cable; detecting, with the second sensor, an event on the electric cable that occurred any time from detection of the first location to detection of the second location; and actuating the alarm after detection of the event.

[0041] Further, disclosed herein are methods for event detection during electric submersible pump assembly deployment for electric submersible pump assembly deployments that may each include: providing an event detection assembly that may include: a reel; an electric cable coupled to the reel and to the electric submersible pump assembly; a first sensor; a second sensor; a controller; and an alarm; detecting, with the first sensor, a cable portion of the electric cable; detecting, with the second sensor, an event on the electric cable that occurred any time during detection of the cable portion; and actuating the alarm after detection of the event.

[0042] Any one of the systems disclosed herein may further include a controller configured for identifying when an event occurred any time from detection of the first location to detection of the second location. [0043] Any one of the systems disclosed herein may further include a controller configured for identifying when an event occurs any time during detection of an event.

[0044] Any one of the systems disclosed herein may further include a power pack coupled to the controller.

[0045] In any one of the systems disclosed herein, the controller may further include a power pack.

[0046] In any one of the systems disclosed herein may further include: a first relay coupled to a first wire of the electric cable and a second wire of the electric cable; a second relay coupled to a third wire of the electric cable and a second wire of the electric cable.

[0047] In any one of the systems disclosed herein, the controller may be capable of simultaneously receiving from the one or more sensors data associated with the first location and data associated with the second location and receiving from the one or more sensors data associated with the event.

[0048] In any one of the systems disclosed herein, a portion of the electric cable may extend between the first sensor and a sheave.

[0049] In any one of the systems disclosed herein, the first location on the cable may include a first protrusion and the second location on the cable may include a second protrusion.

[0050] In any one of the systems disclosed herein, the first location on the cable may include a first mark and the second location on the cable may include a second mark.

[0051] In any one of the systems disclosed herein, the first location on the cable may be a first notch and the second location on the cable may be a second notch.

[0052] Any one of the methods disclosed herein may further include inhibiting, with a first relay, flow of electricity in a first wire of the electric cable and a second wire of the electric cable. [0053] Any one of the methods disclosed herein may further include actuating, with the controller, a first relay to inhibit flow of electricity in a first wire that may be a part of the electric cable and to inhibit flow of electricity in a second wire that may be a part of the electric cable.

[0054] Any one of the methods disclosed herein may further include comprising inhibiting, with a second relay, flow of electricity in a third wire of the electric cable and a second wire of the electric cable.

[0055] Any one of the methods disclosed herein may further include actuating, with the controller, a second relay to inhibit flow of electricity in a third wire that may be part of the electric cable and to inhibit flow of electricity in a second wire that may be part of the electric cable.

[0056] Any one of the methods disclosed herein may further include using a first relay to inhibit flow of electricity in a first wire that may be part of the electric cable and to inhibit flow of electricity in a second wire that may be part of the electric cable.

[0057] In any one of the systems disclosed herein, the controller may be coupled to the reel.

[0058] In any one of the systems disclosed herein, the one or more sensors may include a first sensor configured to detect the first location and the second location; and a second sensor configured to detect the event on the cable.

4. Specific Embodiments in the Drawings

[0059] The drawings presented herein are for illustrative purposes only and do not limit the scope of the disclosure or claims. Rather, the drawings are intended to help enable one having ordinary skill in the art to make and use the systems and assemblies and practice the methods disclosed herein.

[0060] This section addresses specific versions of event detection assemblies shown in the drawings, which relate to assemblies, elements and parts that can be part of a downhole wellbore system. Although this section focuses on the drawings herein, and the specific embodiments found in those drawings, parts of this section may also have applicability to other embodiments not shown in the drawings. The limitations referenced in this section should not be used to limit the scope of the claims themselves, which have broader applicability than the structures disclosed in the drawings.

[0061] FIG. 1 is a schematic drawing that illustrates an example of a downhole wellbore system that includes an event detection assembly 100 for detecting events during electric submersible pump assembly deployment. That wellbore system includes a wellbore 102 lined with a casing 104. The wellbore 102 is depicted as a vertical wellbore in FIG. 1, but it should be understood that any wellbore disclosed herein may also include or be a horizontal wellbore. The wellbore 102 extends downward and underground, preferably across multiple zones of rock formations. One or more perforations 106 in the casing 104 is capable of providing fluid communication between a reservoir 108, e.g., a hydrocarbon reservoir, adjacent the perforations 106 and an annular space inside the casing that is adjacent the perforations 106. The downhole wellbore system also includes an electric submersible pump assembly 110 (ESP assembly) disposed in the wellbore 102. The ESP 110 is run from surface into the wellbore 102 for drawing fluid, e.g., hydrocarbon, to surface that had exited the reservoir 108 through the perforations 106 into the wellbore 102.

[0062] The ESP assembly 110 may include a motor section, a seal section, a pump section, and a sensor section. The lower end of the motor section may be coupled to the upper end of the sensor section. The upper end of the motor section may be coupled to the lower end of the seal section. The upper end of the seal section may be coupled to the lower end of the pump section.

[0063] Various components of the ESP assembly 110 require electric power to operate downhole. Thus, a cable 112 is used to transfer electric power from surface down the wellbore 102 to the ESP assembly 110. A terminal of the cable 112 is coupled to a pothead connector on the ESP assembly 110.

[0064] The length of the cable 112 may extend tens of thousands of feet long (with several cable segments spliced together). Accordingly, segments of the cable 112 are transported to the worksite of the wellbore 102 wound around large reels 114. In some cases, a reel 114 may be delivered to a worksite as part of an event detection assembly 100. In other cases, a reel 114 may be delivered separately from an event detection assembly 100 that is then later installed on the reel 114

[0065] During deployment of the ESP assembly 110 downhole, the cable 112 is strapped alongside one or more portions of the ESP assembly 110 as it is run into the wellbore 102. As the ESP assembly 110 advances downhole, the cable 112 advances, likewise, progressively unwinding from a reel 114.

[0066] As the cable 112 advances downhole, various downhole conditions may act on one or more portions of the cable 112 that could affect or damage the one or more portions. For example, a portion of the cable 112 may scratch or rub against the casing 104, tearing armor and/or insulation around the inner conductive wires (see FIG. 4). In another example, fluid pressurized within the wellbore enter the advancing ESP assembly 110 and cause a motor in the ESP assembly 110 to turn, which may generate a surge of electricity. The surge may travel from the ESP assembly 110 up the cable 112 to surface, unbeknownst to operators handling exposed conductive portions of the cable 112. The surge could damage equipment and/or injure or kill an operator.

[0067] Thus, the downhole wellbore system includes an event detection assembly 100 1) to detect one or more events occurring in the wellbore 102, in the ESP assembly 110, and on the cable 112 that could lead to equipment damage or injury to operators, 2) warning the operators, and 3) to record data associated with those events for later analysis.

[0068] FIG. 2 illustrates a cross-sectional perspective view of a reel 114 and a perspective view of an event detection assembly 100 coupled to the reel 114. FIG. 3 illustrates an exploded perspective view of components of an event detection assembly 100.

[0069] Referring to FIG. 2 and FIG. 3, an event detection assembly 100 includes a controller 202, a power pack 204, a first sensor 206a (see FIG. 1), one or more second sensors 206b, and an alarm 302. The controller 202 is disposed in a housing. In some versions, the power pack 204 and/or the one or more second sensors 206b may be disposed in the housing with controller 202. The controller 202, the power pack 204, the one or more second sensors 206b are coupled to a cable reel 114. [0070] The power pack 204 is electrically coupled , e.g., via adapter cables 208a-c, to terminals of a cable 112 that is wound around the cable reel 114. Electricity from the power pack 204 may be transmitted to the cable 112. A second sensor 206b is coupled the cable 112. The second sensor 206b is configured to detect one or more properties on the cable 112. The second sensor 206b is capable of transmitting to the controller 202 data representing the one or more properties on the cable 112. The controller 202 is electrically coupled to the alarm 302.

[0071] The controller 202 is a specialized computer system having hardware and software configured to communicate with and/or actuate devices electrically coupled , e.g., wirelessly or over wire, to the controller 202. For example, the controller 202 may actuate the one or more sensors 206a to perform one or more operations to gather data concerning one or more properties, e.g., resistance or insulation, related to the cable 112. The controller 202 is capable of receiving data from the one or more sensors 206a. Additionally, the controller 202 is capable of storing the received data onto local memory or hard drive. Also, the controller 202 is capable of transmitting, e.g., wirelessly or over wire, the received or stored data to a remote central database (not shown).

[0072] Furthermore, the controller 202 may actuate the alarm 302 after receiving and processing data indicating occurrence of an event that poses hazard to equipment and/or personnel.

[0073] FIG. 4 is a perspective view of a cable 112 disposed between a sensor 206a and a sheave 402. When deployed together with an ESP assembly 110, the cable 112 would run across the sheave 402 to ease entry of the cable 112 downhole (see FIG. 1). The sheave 402 may be supported on a stand. However, in some cases, the sheave 402 may be a pulley supported on an overhanging structure, e.g., derrick or stand (not shown).

[0074] Conductive wires 404a-c of the cable 112 are wrapped by an outer armor 406. The out armor is a strip of non-conductive material or conductive material, e.g., galvanized, stainless steel, or monel. The outer armor 406 wrapping has uniform spaced windings around the conductive wires 404a-c such that the sensor 206a can detect one revolution of winding of the strip of the outer armor 406 as the cable 112 is run across the sheave 402. Accordingly, a controller 202 (see FIG. 1) electrically coupled , e.g., wirelessly or over wire, to the sensor 206a may receive from the sensor 206a data indicating each revolution. Thus, the controller can record the number revolutions that have passed the sensor 206a. Because the spacing of the outer armor windings are uniform, the controller 202 is capable of calculating a length of the cable 112 that has passed across the sensor 206a.

[0075] Additionally, with the use of a clock (not shown), a first time can be identified with detection of a first location on cable 112 and a second time can be identified detection of a first location of on cable 112. For example, when a first location on the cable 112 is identified and recorded, a first time and date 13:04:00 on April 26, 2022, may also be recorded for the first location, and when a second location on the cable 112 is identified and recorded, a second time and date 13:04:05 on April 26, 2022, may also be recorded for the second location. The difference between the first time and the second time can be calculated, e.g., by the controller 202, to show that 5 seconds had elapsed from detection of the first location to detection of the second location. Hence, the velocity of travel of the cable 112 relative to the sensor 206a can also be calculated, e.g., by the controller 202.

[0076] FIG. 5 is a schematic illustration of a cable having 3-phase wires 404a-c coupled to a first relay 502a and a second relay 502b. Each relay 502 has two terminals 504, 504’. The wire 404a is coupled to a terminal 504a of the first relay 502a. The wire 404c is coupled to a terminal 504b of the second relay 502b. The wire 404b has a Y-connection to terminal 504a’ of the first relay 502a and terminal 504b’ of the second relay 502b.

[0077] For an ESP assembly 110 (see FIG. 1) to operate via electricity received from the cable 112, the ESP assembly 110 must receive electricity from each of the 3-phase wires 404a-c of the able 112. Disruption of electricity flow from any one wire 404 would prevent the ESP assembly 110 from operating. Accordingly, for purposes of maintenance and/or safety, an operator may actuate (via a controller 202) the first relay 502a to disable electricity flow on wires 404a, 404b and/or the second relay 502b to disable electricity flow on wires 404b, 404c.

[0078] FIG. 6 is a schematic drawing that illustrates an example of event detection assembly 100 for electric submersible pump assembly deployment including both surface sensors 206a, 206b and downhole sensors 206c-f. The first downhole sensor 206c is coupled to an inner surface of a casing 104 downhole. Sensor 206c may detect pressure in a wellbore 102. The second downhole sensor 206d is disposed inside a pump of the ESP assembly 110. The second downhole sensor 206d may detect fluid volume flowing through the pump. The third downhole sensor 206d is disposed inside a pump of the ESP assembly 110. The third downhole sensor 206d may detect vibration, temperature, and/or pressure in the motor. The fourth downhole sensor 206f is disposed inside a sensor section of the ESP assembly 110. The third downhole sensor 206f may detect vibration, temperature, and/or pressure on the sensor section.

[0079] A controller 202 may actuate the one or more sensors 206a-e to perform one or more operations to gather data concerning one or more downhole wellbore system properties, e.g., cable length in the wellbore 102, resistance and/or insulation related to the cable 112, conditions in the wellbore 102, and/or conditions in the ESP assembly 110. The controller 202 is capable of receiving data from the one or more sensors 206a-e. Additionally, the controller 202 is capable of storing the received data onto local memory or hard drive. Also, the controller 202 is capable of transmitting, e.g., wirelessly or over wire, the received or stored data to a remote central database.

[0080] Referring to FIGS. 1-6, an event detection assembly 100 may be used to detect events occurring during deployment of an ESP assembly 110 down a wellbore 102. First, an operator may couple terminals of a cable 112 to the ESP assembly 110. Next, the operator may advance the ESP assembly 110 downhole by coupling additional pipes to the ESP assembly 110 at surface and lowering the ESP assembly 110 downhole.

[0081] As the ESP assembly 110 is advanced downhole, the cable 112 is unwound from a reel 114. The unwound cable 112 is run across a first sensor 206a that detects a portion of the cable 112. The portion may include a mark, e.g., paint, protrusion, indentation, regular surface pattern, stepped surface, or tag, to indicate that a certain length of the cable 112 has passed the first sensor 206a. Preferably, the distance between any two marks is uniform so that a length of the cable 112 can be calculated based on the number of marks detected. A controller 202 may receive data from the first sensor 206a representing all marks that have crossed the first sensor 206a. Data representing the marks may be used to calculate a length of the cable 112 and/or speed of advancement of the cable 112 into the wellbore 102. [0082] Additionally, one or more second sensors 206b may detect one or more properties, e.g., resistance and insulation, related to the cable 112. Also, one or more third sensors 206c may detect one or more properties, e.g., pressure, related to downhole conditions in the wellbore 102. Furthermore, one or more fourth sensors 206d may detect one or more properties, e.g., temperature, related to a motor of the ESP assembly 110. Moreover, one or more fifth sensors 206e may detect one or more properties, e.g., flow, related to a pump of the ESP assembly 110. The controller 202 may receive simultaneously data from all the sensors 206a-e representing the one or more properties over time. The controller 202 may receive data from the one or more sensors 206a-e representing the one or more properties over regular time intervals. Moreover, the received data may be processed by the controller 202 or by a remote server. Thus, the controller 202 is capable of continuously receiving and processing data as the ESP assembly 110 is deployed in real time. Continuous, real time receiving and processing of data, without having to stop deployment of the ESP assembly 110 to take measurements and readings, reduces or eliminates downtime and delays in deployment.

[0083] If an event occurs during deployment of the ESP assembly 110, the controller 202 may actuate an alarm 302 to alert the operator of the event. Additionally, the controller 202 may actuate relays 502a, 502b to inhibit electricity flow on one or more portions of the cable 112. Furthermore, the operator may then view, e.g., on a screen coupled to the controller 202, data related to the event on the controller 202. Alternatively, the data may be processed by a remote server and then transmitted to the controller 202.

[0084] The processed data may contain information representing the event, a time the event occurred, a length a portion of the cable 112 that has been run downhole, the velocity (e.g., instantaneous and average) at which the cable 112 was advancing downhole, a pressure in the wellbore 102, resistance in the cable 112, and/or insulation of the cable 112. The operator may use the information to quickly act to mitigate risks and hazards resulting from the event.

[0085] Although any event detection system 100 herein may be described as executing or performing steps or functions, those skilled in the art should understand that an individual or person is responsible for the action of the event detection system 100. For instance, a programmer may implement software which may instruct the event detection system 100 to automatically perform one or more steps or functions based on some input, e.g., from a person, another system, or a clock.