Detection system for a wellsite and method of using same

A detection system and method for a well site is provided. The well site has a surface rig and a surface unit. The surface rig is positioned about a formation and a surface unit. The detection system includes a well site component deployable from the surface rig via a conveyance, well site equipment positioned about the well site and having a bore to receive the well site component therethrough; and base units. The base units include scanners positioned radially about the bore of the well site equipment. The scanners detect an outer surface of the well site component and generate combinable images of the well site component whereby the well site equipment is imaged.

BACKGROUND

The present disclosure relates generally to techniques for performing well site operations. More specifically, the present disclosure relates to techniques for detecting well site equipment.

Oilfield operations may be performed to locate and gather valuable subsurface fluids. Oil rigs are positioned at well sites, and downhole tools, such as drilling tools, are deployed into the ground to reach subsurface reservoirs. Once the drilling tools form a wellbore to reach a desired reservoir, casings may be cemented into place within the wellbore, and the wellbore completed to initiate production of fluids from the reservoir.

Tubular devices, such as pipes, certain downhole tools, casings, drill pipe, drill collars, tool joints, liner, coiled tubing, production tubing, wireline, slickline, and/or other tubular members and/or tools (referred to as ‘tubulars’ or ‘tubular strings’) may be deployed from the surface to enable the passage of subsurface fluids to the surface. Various deployable tools, such as logging tools, wireline tools, drill stem testers, and the like (referred to as “subsurface tools”), may also be deployed from the surface to perform various downhole operations, such as performing tests and/or measuring well site parameters. Tubulars may be measured for use in well site operations. Examples of tubulars and related techniques are provided in U.S. Patent/Application Nos. 2012/0160309 and/or 62/064,966, the entire contents of which are hereby incorporated by reference herein.

Well site equipment, such as blow out preventers (BOPs), may be positioned about the wellbore to form a seal about a tubular therein to prevent leakage of fluid as it is brought to the surface. BOPs may be annular or ram BOPs with a mechanism, such as rams or fingers, with seals to seal a tubular in a wellbore. Examples of BOPs are provided in U.S. Patent/Application Nos. 2012/0227987; 2011/0226475; 2011/0000670; 2010/0243926; U.S. Pat. Nos. 7,814,979; 7,367,396; 6,012,744; 4,674,171; and PCT Application No. 2005/001795, the entire contents of which are hereby incorporated by reference herein.

SUMMARY

In at least one aspect, the disclosure relates to a detection system for a wellsite. The wellsite has a surface rig and a surface unit. The surface rig is positioned about a formation and a surface unit. The detection system includes a wellsite component deployable from the surface rig via a conveyance, well site equipment positioned about the wellsite and having a bore to receive the wellsite component therethrough, and base units. The base units include scanners positioned radially about the bore of the wellsite equipment. The scanners detect an outer surface of the wellsite component and generate combinable images of the wellsite component whereby the wellsite equipment is imaged.

The scanners may include magnetic resonance and/or acoustic sensors. The base units may be positioned in a circular or an irregular pattern about the bore in the wellsite equipment. The detection system may also include equipment units positionable about the wellsite component.

The equipment units are coupled to the surface unit by a communication link. Each of the equipment units include an identifier disposed about the wellsite component. The scanners may include ID sensors capable of detecting the identifiers. The identifiers may include RFIDs. The equipment units may also include a sensor package to detect wellsite parameters. Each of the base units also include a communicator. The communicator may be in communication with the equipment units and/or the surface unit. Each of the equipment units and each of the base units may also include a power supply, a processor, and a memory.

The wellsite component may be a drill collar, drill pipe, casing, tool joint, liner, coiled tubing, production tubing, wireline, slickline, logging tool, wireline tool, and/or drill stem tester. The wellsite equipment may be a blowout preventer, a low marine riser package, and/or a remote operated vehicle. The wellsite component may include a deployable tool and the wellsite equipment comprises a blowout preventer. The deployable tool may be detectable by the scanners to determine a position for severing by the blowout preventer. The wellsite component may have a narrowed portion. The wellsite component may be positionable about the narrowed portion of the wellsite equipment.

In another aspect, the disclosure relates to a method of detecting a wellsite component at a wellsite. The wellsite may have a surface rig and a surface unit. The surface rig may be positioned about a formation and a surface unit. The method involves providing well site equipment with base units. Each of the base units may include a scanner positioned about a bore in the wellsite equipment. The method may also involve deploying the wellsite component through the bore in the wellsite equipment, detecting an outer surface of the wellsite component with the scanners, generating images of the wellsite component from each of the scanners, and imaging the wellsite component by combining the images from the scanners.

The method may also involve providing the wellsite component with equipment units. Each of the equipment units may include an identifier. The method may also involve detecting the identifiers with the scanners and/or engaging the wellsite equipment with the wellsite component. The engaging may involve sealing about the deployable tool. The wellsite component may include a deployable tool and the wellsite equipment comprises a blowout preventer, and the engaging may involve severing the deployable tool based on the imaging. The method may also involve adjusting a position of the wellsite component based on the imaging. The adjusting may involve positioning a narrowed portion of the wellsite component about the wellsite equipment and the engaging may involve engaging the narrowed portion of the wellsite component with the wellsite equipment.

In another aspect, the disclosure relates to a detection system for a wellsite. The wellsite has a surface rig positioned about a formation. The detection system includes a surface unit, a wellsite component deployable into from the surface rig via a conveyance, wellsite equipment positioned about the wellsite, equipment units, and at least one base unit. The equipment units are positionable about the wellsite component, and are coupled to the surface unit by a communication link. Each of the equipment units includes an identifier disposed about the wellsite component. The base unit(s) are positionable about the wellsite equipment, and include a scanner to detect the identifiers of the equipment units as it comes within proximity thereto whereby the wellsite equipment may be selectively activated to engage a desired portion of the wellsite component.

The identifiers include radio frequency identifiers. The equipment units may also include a sensor package to detect wellsite parameters. The equipment units may include a communicator. Each of the base units may include a sensor package to detect wellsite parameters. Each of the base units may include a communicator. The communicator may be in communication with the equipment units and/or the surface unit. Each of the equipment units and each of the base units may include a power supply, a processor, and a memory. The wellsite component may include a drill collar, drill pipe, casing, tool joint, liner, coiled tubing, production tubing, wireline, slickline, logging tool, wireline tool, and/or drill stem tester. The wellsite equipment may be a blowout preventer, a low marine riser package, and/or a remote operated vehicle.

The equipment units may be positionable in a recess extending into an outer surface of the wellsite component. The equipment units may have a shield disposed thereabout. The equipment units may have a connector engageable with the wellsite equipment. The equipment units may be raised about and recessed within the wellsite component. The equipment units may be disposed radially about the wellsite component. The equipment units may be disposed vertically about the wellsite component. The base units may be disposed radially about the well site equipment. The base units may be disposed vertically about the wellsite equipment.

The wellsite component may include a deployable tool and the wellsite equipment may include a blowout preventer. The identifiers may be detectable by the scanners to determine a position for severing by the blowout preventer. The wellsite component may have a narrowed portion, and the wellsite component may be positionable about the narrowed portion of the well site equipment. The base units may be positioned in a circular or an irregular pattern about a passage in the wellsite equipment, and the wellsite component may be deployable through the passage.

In another aspect, the disclosure relates to a method of detecting a wellsite component. The method involves providing the wellsite component with equipment units and providing well site equipment with at least one base units. Each of the equipment units includes an identifier and each of the base units includes a scanner. The method further involves deploying the wellsite component about the wellsite equipment via a conveyance, detecting the identifiers of the equipment units with the scanner as it comes within proximity thereto, determining a position of the wellsite component based on the detecting, and engaging the wellsite component with the wellsite equipment based on the determining.

The method may also involve adjusting a position of the wellsite equipment based on the determining. The adjusting may involve positioning a narrowed portion of the wellsite component about the wellsite equipment and wherein the engaging comprises engaging the narrowed portion of the wellsite component with the wellsite equipment. The wellsite component may include a deployable tool and the wellsite equipment may include a blowout preventer. The engaging may involve severing the deployable tool based on the determining.

Finally, in another aspect, the disclosure relates to a method of detecting a wellsite component. The method involves deploying the wellsite component about the wellsite and providing a detection system comprising equipment units and base units. The equipment units may be positionable about the wellsite component. Each of the equipment units may include an identifier. The base units may be positionable about the wellsite location. The base units may include a scanner. The method may involve determining a position of the wellsite component relative to a wellsite location by detecting the equipment units with the base units, positioning the wellsite component in a desired position relative to the wellsite location based on the determining, and activating the wellsite component based on the positioning.

The method may also involve adjusting the positioning based on the determining. The adjusting may involve comprises positioning a narrowed portion of the wellsite component about the wellsite equipment and the activating may involve severing the narrowed portion of the wellsite component with the wellsite equipment. The wellsite component may include a deployable tool and the wellsite equipment may include a blowout preventer. The activating may include severing the deployable tool based on the determining.

DETAILED DESCRIPTION OF THE INVENTION

The description that follows includes exemplary apparatus, methods, techniques, and/or instruction sequences that embody techniques of the present subject matter. However, it is understood that the described embodiments may be practiced without these specific details.

A wellsite detection system may be provided about a wellsite for detecting (e.g., sensing, locating, identifying, measuring, etc.) various wellsite components. The detection system may include an equipment unit and a base unit. The equipment unit may be positioned about the wellsite components, such as deployable tools including tubulars and/or other equipment. The base unit may be positioned about the wellsite (e.g., in wellsite equipment) to detect the equipment units as they pass thereby.

The equipment and/or base units may collect and/or pass stored and/or real time information about the equipment. Such information may be used, for example, to sense, identity, locate, and/or measure the wellsite component, to collect wellsite data, and/or to provide information about operating conditions. The equipment and/or the base units may be, for example, in communication with communication units positioned about downhole tools, subsea, subsurface, surface, downhole, offsite and/or other locations. Power, communication, and/or command signals may be passed about portions of the well site and/or offsite locations via the detection system.

FIG. 1depicts an offshore wellsite100including a surface system102and a subsurface system104. The surface system102may include a rig106, a platform108(or vessel), and a surface unit110. The surface unit110may include one or more units, tools, controllers, processors, databases, etc., located at the platform108, on a separate vessel, and/or near to or remote from the wellsite100. While an offshore wellsite is depicted, the wellsite may be land based.

The subsurface system104includes a conduit112extending from the platform108to a sea floor114. The subsurface system104further includes a wellhead116with a tubular118extending into a wellbore120, a low marine riser package (LMRP)121with a BOP122, and a subsea unit124. The BOP122has a BOP assembly125with sealing devices126for shearing and/or sealing the wellbore120.

A wellsite component127is deployed through the conduit112and to the BOP122. In the example shown, the wellsite component127is a deployable tool including a series of tubulars118threaded together to form a drill string. A detection system130is provided for detecting the wellsite component127. The detection system130includes equipment units131positioned about the wellsite component127and base units133positioned about the wellsite100.

In the example shown, the equipment units131are provided at various locations about the wellsite component127. The base units133are provided at various locations about the rig106, the surface unit110, BOP122, and tubulars118. As also shown, the base unit133may be carried by other devices, such as a remote operated vehicle (ROV)135deployed from the platform108. The various base units133may form a wired or wireless connection with one or more of the equipment units131.

The surface system102and subsurface system104may be provided with one or more communication units, such as the surface unit110and/or the subsea unit124, located at various locations to work with the surface system102and/or the subsurface systems104. Communication links128may be provided for communication of power, control, and/or data signals between the equipment and base units and various wellsite locations100and/or offsite locations138. The communication links128may be wired or wireless connections capable of passing communications between the various units. As shown, communications may also be conveyed by a satellite134or other means.

While an example configuration is depicted, it will be appreciated that one or more equipment units, base units, wellsite components, communication units, communication links, and/or other options may be provided for detecting the well site equipment about various parts of the well site.

FIG. 2depicts an example of use of the detection system130. In this example, the equipment units131are positioned in the tubular118and the base units133are positioned in the BOP122. As shown, the BOP122includes a housing225with multiple sealing means, including fingers (or annulars)226aof an annular BOP, rams226bof a ram BOP, and a blade226cof a guillotine BOP. The various sealing means may have seals, blades, and/or sealing devices capable of sealing the BOP122.

The sealing means226a-care activated by actuators234, which may be one or more hydraulic, electrical or other actuators capable of selectively activating the sealing means to sever and/or seal about the tubular118. One or more sealing means, actuators and/or other devices may be provided about the BOP. Examples of sealing means that may be present are provided in US Patent Nos. 2012/0227987; 2011/0226475; 2011/0000670; 2010/0243926; U.S. Pat. Nos. 7,814,979; and 7,367,396, previously incorporated by reference herein.

The tubular118extends through a passage236in the housing225. The sealing means226a,bare positionable in the passage236of the housing225and selectively movable into engagement with the tubular118for sealing and/or severing the tubular118. The actuators234may be selectively activated by units (e.g.,110,124ofFIG. 1). The sealing means226a-cmay extend for engagement within the BOP122with or without contact with the tubular118to form a seal about the passage236. The sealing means226a-cmay include, for example, fingers, blades, seals, or other devices for sealing about tubular118and/or passage236.

The tubular118may have one or more of the equipment units131thereabout. The BOP122may have one or more base units133positionable thereabout. The equipment units131are detectable by the base units133. Individual base units133may detect the equipment units131and communicate therewith as the equipment units131pass thereby. The equipment and base units131,133may pass data, power, communication, and/or other signals therebetween.

The equipment and base units131,133may exchange information, such as equipment information, measurement data, and/or other information. The base units133may collect, store, and/or process the information received from the equipment units131. The base units133may also contain and/or collect information about the wellsite, wellsite operations, equipment, and/or other information.

WhileFIG. 2shows the equipment and base units131,133positioned in the tubular118and the BOP housing225, the equipment units131may be in any wellsite component movable about a base unit133, and the base unit133may be positioned about any location about the wellsite. The wellsite location of the base unit133may be a fixed member, such as portions of the LMRP121and/or a movable member, such as the ROV135ofFIG. 1.

FIGS. 3A-3Cshow schematic views of various examples of the wellsite components318a-cwith the equipment units131disposed thereabout.FIGS. 3A and 3Bshow drill strings318a,bwith tubulars340a,b, respectively.FIG. 3Cshows a downhole tool318c. As shown by these examples, the equipment units131may be positioned in various locations about a variety of deployable tools, such as downhole drilling tools, usable as the wellsite components.

FIG. 3Ashows the drill string318aincluding a series of drill pipe340a. Each drill pipe340aincludes a pin end342a, a box end342b, with a tubular344atherebetween and a passage345therethrough. The pin end342aof a drill pipe340ais threadedly connectable to a box end342bof another drill pipe340ato form the drill string318a. The drill pipe340amay be any drill pipe, tool joint, or other tubular deployable from the surface. Examples of tubulars are provided in US Patent/Application Nos. 6012744, 4674171, and PCT Application No. 2005/001795 previously incorporated by reference herein.

FIG. 3Bshows another version of the drill string318bwith a series of drill pipe340b. The drill pipe340bis the same as the drill pipe340a, except that it is provide with a raised portion346along the tubular344b. The raised portion346of the tubular344bhas a larger diameter than the tubular344a. In at least some cases, it may be desirable to identify dimensions of the tubular344b, such as which portions of the tubular344bare larger. This may be used, for example, to identify where to seal about the tubular344bas is described herein.

As shown inFIGS. 3A-3B, the equipment units131may be positionable along various portions of the drill string318a,b, such as the pin and box ends342a,b, the tubular344a,b, and/or the raised portion346of the drill pipe340a,b, and/or various portions of the downhole tool318c.

The downhole tool318cis depicted as a wireline tool having a housing348deployable from the surface by a wireline350. The downhole tool318cmay be any deployable device provided with various downhole components, such as resistivity, telemetry, logging, surveying, sampling, testing, measurements while drilling, and/or other components, for performing downhole operations. The wireline350may be provided with smart capabilities for passing signals between the downhole tool318cand the surface (e.g.,110ofFIG. 1).

As demonstrated by the examples shown inFIGS. 3A-3C, the equipment units131may be positioned about a surface and/or subsurface portion of the well site components. One or more equipment units131may be provided in various forms and/or positions. One or more of the equipment units131may be unitary and/or in multiple portions. The equipment units131may be installed into a surface of the well site components318a-c, and/or embedded within.

FIGS. 4A and 4Bshow schematic views of various configurations of placement of equipment units131in the wellsite component.FIG. 4Ashows a portion4A ofFIG. 3Awith an equipment unit131in a recessed position.FIG. 4Bshows another version of the equipment unit131′ in a raised position.

In the recessed position ofFIG. 4A, the equipment unit131is recessed into a pocket450extending into an outer surface of the wellsite component318a. The equipment unit131may be recessed for protection from harsh conditions. The equipment unit131is recessed into the pocket450a distance from an outer surface of the wellsite component318a. The equipment unit131is provided with a connection451in the form of a thread matable with a thread in the pocket450.

A shield452is disposed over the equipment unit131about an opening of the pocket450. The shield452may enclose the equipment unit131in the wellsite component318a. The shield452may be, for example, an epoxy and/or other material to protect the equipment unit131while allowing communication therethrough.

In the raised position ofFIG. 4B, the equipment unit131′ is partially recessed into a pocket450′ extending into an outer surface of the wellsite component318a. The equipment unit131′ may be raised and/or extend a distance from an outer surface of the wellsite component318ato facilitate communication with base units133located about the wellsite. A tip portion of the equipment unit131′ extends from the pocket450′ a distance from an outer surface of the wellsite component318a.

A shield452′ is disposed over the wellsite component318a. The shield452′ may be the same as the shield452, except that it is shaped to permit the equipment unit131′ to extend beyond the outer surface of the wellsite component. The equipment unit131′ may be press fit in place and secured with the shield452′.

As shown byFIGS. 4A and 4B, the equipment unit131may have any shape and be positioned in a correspondingly shaped pocket450with the shield452thereon. The equipment units131may also be secured in place using a variety of techniques, such as the connection451ofFIG. 4A, the press fit ofFIG. 4B, and/or other means. It will be appreciated that other geometries and/or materials may be provided.

FIG. 5is a schematic diagram depicting an electrical configuration of the detection system130. As shown in this view, the equipment unit131includes an identifier454, a sensor package456, a power supply458, a communicator460, a processor462, and a memory464. The base unit133includes a power supply458, a communicator460, a processor462, a memory464, and a scanner466.

One or more of the communication links128may be provided between one or more of the equipment units131, the base units133, surface units110, and/or an offsite locations138. One or two way communication may be provided by the communication links128. The communicators460may be antennas, transceivers or other devices capable of communication via the communication links128in wellsite conditions. The communicators460may communicate with the surface unit110directly or via subsurface equipment, such as electrical cabling (e.g., mux cables along the riser) extending to the surface.

The equipment and base units131,133may be provided with identifiers454, such as radio frequency identifiers (RFIDs), capable of storing information. For example, as shown, the RFID454may be used to store information about the wellsite component, the wellsite, the well site operation, the client, and/or other information as desired. The RFID454may be readable by the scanner466via the communication link128.

The equipment unit131and/or the base unit133may be provided with sensing capabilities for measuring wellsite parameters about the wellsite. The sensor package456may include one or more sensors (e.g., magnetometer, accelerometer, gyroscope, etc.), gauges (e.g., temperature, pressure, etc.), or other measurement devices. Data collected from the sensor package456and/or scanner466may be stored in memory464in the equipment and/or base units131,133.

The power supply458may be a battery, storage unit, or other power means capable of powering the equipment and/or base units131,133. In some cases, the power458may be passed via the communication links128between the equipment and base units131,133. The power may be carried internally within the equipment and/or base unit(s)131,133and/or be external thereto. For example, the base unit133of the ROV135ofFIG. 1may be attached to one or more of the equipment and/or base units131,133and provide power (and/or other signals) thereto via the communication link128.

While specific electrical components are depicted, the equipment unit131and the base unit133may have various combinations of one or more electrical components to provide power, communication, data storage, data collection, processing, and/or other capabilities. The detection system130may be provided with other devices, such as switches, timers, connectors, and/or other features to facilitate communication. The processors and/or controllers may be provided to selectively activate the well site component and/or the well site equipment herein.

FIGS. 6A-6Cdepict an example operation sequence for detecting the equipment units131a-ccarried by a wellsite component618using a base unit133a-clocated about a wellsite location622. As shown, the wellsite component618may be tubulars (e.g.,318a-cofFIGS. 3A-3C) carrying equipment units131a-c, and the wellsite location622may be a BOP, LMRP or other wellsite component618with the base units133a-cthereon. The wellsite location622may be provided with activation means626, such as blade seals, fingers, or other devices (see, e.g.,226a-cofFIG. 2) of a BOP, engageable with the wellsite component618. The well site component618has the equipment units131a-cextending from an uphole end to a downhole end thereof.

In this example, the equipment units131a-care used to locate and position the wellsite component618. As shown by these figures, the equipment units131a-care detectable by the communication units133a-cas they move thereby. The equipment units131a-cmay be detectable by the base units133a-c, for example, by sending a signal readable by the base units133a-c. The equipment units131a-cmay be provided with a range of detection capabilities such that they are detectable when positioned adjacent a base unit133a-cand/or a distance therefrom.

In the sequence shown,FIG. 6Ashows the wellsite component618with the equipment units131a-cin a misaligned position uphole from the base units133a-c. In this position one or more of the base units133a-cmay be able to communicate with the equipment units131a-cand determine that they are not in an aligned position relative thereto. For example, the base units133a-cmay be able to detect a distance between the equipment units131a-cand the base units133a-c, as well as a direction, location or other positioning information. The base units133a-cmay also gather information from the equipment units131a-c, such as the type of equipment and its specifications.

FIG. 6Bshows the wellsite component618with the equipment units131a-cin a misaligned position downhole from the base units133a-c. The wellsite component618may be moved until at least one of the base units133a-cindicates alignment with one or more of the equipment units131a-c. In the position ofFIG. 6B, the wellsite component618has advanced downhole such that equipment unit131cis aligned with base unit133cthereby identifying a location of a downhole end of the well site component618relative to the wellsite location622.

FIG. 6Cshows the wellsite component618advanced uphole until another of the base units, namely uphole base unit133a, indicates alignment with one or more of the equipment units, namely equipment unit131a. In the position ofFIG. 6C, the wellsite component618has advanced uphole such that equipment unit131ais aligned with base unit133athereby identifying a location of an uphole end of the wellsite component618relative to the wellsite location622.

The information gathered by detection using the base units133a-cinFIGS. 6A-6Dmay be used to determine information about the wellsite component618and its position about the wellsite location622. Detection of the uphole equipment unit131aby the base unit133aand the downhole equipment unit131cby the base unit133c(and/or other information gathered from the equipment units131a-c) may be used to provide a mapping of the wellsite component618and/or a location of the wellsite component618relative to the well site location622.

Information from the equipment units131aand/or about the wellsite component618may be used, for example, to place the wellsite component618in a desired position about the wellsite location622. For example, in a case where the wellsite component is a tubular (e.g.,318a,bofFIGS. 3A, 3B), placement of the tubular about a BOP (e.g.,122ofFIGS. 1 and 2) may be useful to place a thinner portion of the tubular relative to blades626of the BOP. Thinner portions of the tubular may be easier to cut than thicker portions of the BOP thereby facilitating severing and/or sealing the wellbore during a blowout and/or other incident.

As shown inFIG. 6D, the wellsite component618may be moved up or down to a desired activation position. Based on the information provided by detection of the wellsite component618, the equipment units131a-cmay be placed in an aligned position about the base units133a-c. As shown, the wellsite components618are positioned relative to blades626. Once in a desired activation position, such as with a narrowest portion of the tubular618adjacent the blades626as shown, the blades626may be engaged as indicated by the arrows.

The blades626and/or other equipment and/or components may be selectively activated by one or more controllers and/or processors of the surface unit, wellsite component, and/or well site equipment. While blades626are depicted for severing along a narrowed portion of the well site component618, any portion of the wellsite component618may be positioned at a desired location about wellsite location622.

FIGS. 7A-7D show additional configurations of the detection system730disposable about a wellsite component718and a wellsite location (e.g., BOP)722.FIG. 7Ashows a longitudinal view of the BOP722with the wellsite component718passing therethrough.FIG. 7Bshows a radial cross-sectional view of the BOP722ofFIG. 7Ataken along line7B-7B.FIGS. 7C and 7Dshow additional schematic views of the BOP722.

As shown inFIGS. 7A and7B, the wellsite component718is a tubular deployable through a passage736of a BOP722. Wellsite component718may have one or more equipment units131disposed thereabout. The BOP722has base units133a-ddisposed radially thereabout to detect the wellsite component718.

As demonstrated by this configuration, the base units133a-dmay act as distance sensors to determine a distance of the wellsite component718therefrom. Each base unit133a-dmay detect a distance d1-d4to determine a radial position of the wellsite component718in the passage736. One or more equipment and base units131,133a-dcan be added as desired (e.g., to detect smaller diameter objects in the BOP).

The base units133a-dmay be provided with sensors or sensor packages (see, e.g.,456ofFIG. 4) with measurement (e.g., magnetic resonance and/or acoustic) capabilities to detect distance and/or to determine a diameter D of the wellsite component718. For example, if the base units133a-dare at a position 10 feet (3.048 m) above rams729in the BOP722, when a portion of the tubular718detected by the base units133a-dmoves 10 feet (3.048 m) downward, the tubular718may be in the path of the ram729. The base units133a-dmay also be used to detect a tool joint or other item on the tubular718that may affect (e.g., interfere) with operation of the rams729. Upon detection of a portion of the tubular718, such as a tool joint, the wellsite component718may be selectively moved relative to the ram729to avoid engagement with portions of the wellsite component718that may be more difficult to sever.

FIGS. 7A-7Dshow one or more of the base units133a-emay be positioned at one or more depths. As shown inFIGS. 7A and7B, base units133a-dare positioned in discrete locations about the BOP722in a radial pattern at 0, 90, 180, and 360 degrees at a given depth along the BOP722. The base units133a-dmay line the inner surface of the passage of the BOP722. Additional base units133eare also shown at different depths.

As schematically shown inFIG. 7C, a continuous set of the base units133may be positioned about an inner surface of the BOP722and form a circular array740aof the base units133about passage736. As schematically shown inFIG. 7D, the base units133may be positioned in any shape, such as the continuous circular array740adefining a circular pattern along passage736, or the irregular array740balong passage736.

One or more of the base units133,133a-emay be provided with scanning capabilities such that, as the wellsite component718moves through the passage736, a picture (e.g., 3D image) may be generated by mapping the wellsite component718as it passes the base units133,133a-e. For example, the base units133may include the scanners466in the form of, for example, an array of magnetic resonance sensors mounted radially about the bore as shown inFIGS. 7C and 7Dto detect the tubular as it passes therethrough. The scanners466of the base units133,133a-emay be used alone or in conjunction with the equipment units131.

Each of the magnetic resonance sensors466can detect the outer surface of the tubular and combine to generate an image based on data received from each individual sensor466. The scanners466may collect and process the images using the memory and storage of the base unit133and images may be communicated to the surface unit110via communicator460(FIG. 5). This image can identify the shape and location of the tubular as it passes through the wellbore. A 3D image may be generated of the tubular. These scans may be combined with information gathered from one or more sensors, RFIDs, memory, and/or other information. These scans may be compared and/or validated with known information about the tubulars, such as other scans and/or measurements performed using other equipment. Examples of scanners usable to image equipment are commercially available from SALUNDA at www.salunda.com.

The base units133,133a-emay also be used to measure parameters of the wellsite component718, such as diameter, distance, dimension, and/or other parameters. Examples of other scans and/or measurements that may be performed are available in US 2012/0160309 and/or 62/064,966, previously incorporated by reference herein.

One or more techniques may be used to detect a position of a wellsite component718about a wellsite, such as those described herein. Other techniques may also be used. For example, one or more of the equipment unit131of the wellsite component718may be an RFID tag that provides last inspection data to know the exact dimensions. Dimensions may be measured and/or stored for access during operations.

With known dimensions, a position of any wellsite component718that is deployed downhole may be estimated by counting the number of wellsite components618and calculating the overall length of the tool string. In another example, the BOP (e.g., annular226aofFIG. 2) can be engaged to ‘feel for’ a tool joint and/or raised portion along the tool string.

One or more of the techniques used to detect and/or locate the wellsite component may be compared to confirm a position. This information may be fed back to the operator to confirm/revise estimates, to validate, and/or to otherwise analyze well site operations. These various outputs may be visible to the operator by feedback to a display on or offsite.

The data gather from the base units133,133a-eand/or other data sources may be processed (e.g., by the processor462ofFIG. 5) to generate various outputs, such as a dimensions and/or position of the wellsite component. This information may be used along with the measurement of the length of the string, top drive position, a position of collars and/or tools along the tubular718. These outputs may be analyzed, processed, communicated, and/or displayed to the user.

FIG. 8depicts a method800of detecting a wellsite component. The method800involves860—deploying a wellsite component about a wellsite location and providing a wellsite detection system. The detection system comprises equipment units positionable about the well site component and base units positionable about the wellsite location. The method800also involves862determining a position (e.g., radial and/or longitudinal) of the wellsite component relative to the wellsite location by detecting the equipment units with base units, and864positioning the wellsite component in a desired position relative to the wellsite location based on the determining.

In another example, the method may involve positioning a tubular relative to sealing means of a BOP and engaging (e.g., severing and/or sealing) a narrow portion of the tubular with the sealing means. The method may also involve other activity, such as866activating the well site component based on the positioning, scanning the well site component with the equipment units, and/or collecting information from the equipment units. Activating may involve, for example, engaging a desired portion of the well site component based on the positioning. Various combinations of the methods may also be provided. The methods may be performed in any order, or repeated as desired.

Example

In an example, the detection system is used to image a deployable tool and determine, for example, its position relative to a BOP. The deployable tool includes a drilling tool deployed from a surface location via a drill string comprising a series of metal drill pipe (see, e.g.,FIGS. 3A-3B). The BOP has a bore to receive the deployable tool therethrough (see, e.g.,FIG. 2).

The BOP has base units postioned about the bore (see, e.g.,FIGS. 2, 6A-6D, 7A7D). The base units include conventional nuclear magnetic resonance scanners, such as those commercially available from SALUNDA™, capable of detecting the outer surface of the deployable tool and generating an image thereof. A first set of base units are positioned radially about the bore of the BOP at 0, 90, 180 and 270 degrees around the passage at a first depth and a second set are positioned at a different depth in the bore (see, e.g.,FIGS. 7A and7B).

Each scanners generates images of the downhole tool from its individual perspective. The combined output from these scanners is stored in memory and communicated view communicator to the surface unit (see, e.g.,FIG. 5). One or more are collected as the deployable tool passes by the scanner(s). The combined scans are processed via processor and used to generate a 3D image of the deployable tool.

The scanners also detect a distance to the downhole tool (see, e.g.,FIG. 7B). The distance is also used to determine the shape and location of the drill pipe as it passes through the BOP. These distances are processed to detect a narrowed portion along the deployable tool (see, e.g.,FIGS. 6A-6D).

The scanned data is fed back to the surface unit and the position of the deployable tool is adjusted to locate the narrowed portion adjacent a sealing component of the BOP. The BOP is then activated to engage (sever and seal) around this narrowed portion of the drill pipe.

It will be appreciated by those skilled in the art that the techniques disclosed herein can be implemented for automated/autonomous applications via software configured with algorithms to perform the desired functions. These aspects can be implemented by programming one or more suitable general-purpose computers having appropriate hardware. The programming may be accomplished through the use of one or more program storage devices readable by the processor(s) and encoding one or more programs of instructions executable by the computer for performing the operations described herein. The program storage device may take the form of, e.g., one or more floppy disks; a CD ROM or other optical disk; a read-only memory chip (ROM); and other forms of the kind well known in the art or subsequently developed. The program of instructions may be “object code,” i.e., in binary form that is executable more-or-less directly by the computer; in “source code” that requires compilation or interpretation before execution; or in some intermediate form such as partially compiled code. The precise forms of the program storage device and of the encoding of instructions are immaterial here. Aspects of the invention may also be configured to perform the described functions (via appropriate hardware/software) solely on site and/or remotely controlled via an extended communication (e.g., wireless, internet, satellite, etc.) network.

While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. For example, various combinations of one or more well site components, well site locations, equipment units, base units and/or other features may be used for storing, collecting, measuring, and/or communication data.

Insofar as the description above and the accompanying drawings disclose any additional subject matter that is not within the scope of the claim(s) herein, the inventions are not dedicated to the public and the right to file one or more applications to claim such additional invention is reserved. Although a very narrow claim may be presented herein, it should be recognized the scope of this invention is much broader than presented by the claim(s). Broader claims may be submitted in an application that claims the benefit of priority from this application.