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WO2016168335A1 - Ligne d'instrument multi-segment pour instrument d'un train de tiges - Google Patents

Ligne d'instrument multi-segment pour instrument d'un train de tiges Download PDF

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Publication number
WO2016168335A1
WO2016168335A1 PCT/US2016/027340 US2016027340W WO2016168335A1 WO 2016168335 A1 WO2016168335 A1 WO 2016168335A1 US 2016027340 W US2016027340 W US 2016027340W WO 2016168335 A1 WO2016168335 A1 WO 2016168335A1
Authority
WO
WIPO (PCT)
Prior art keywords
line
instrument
drill string
active
interconnected
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2016/027340
Other languages
English (en)
Inventor
Jacques Orban
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Technology Corp
Original Assignee
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Technology Corp
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schlumberger Canada Ltd, Services Petroliers Schlumberger SA, Schlumberger Technology BV, Schlumberger Technology Corp filed Critical Schlumberger Canada Ltd
Publication of WO2016168335A1 publication Critical patent/WO2016168335A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/02—Couplings; joints
    • E21B17/023—Arrangements for connecting cables or wirelines to downhole devices
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/08—Introducing or running tools by fluid pressure, e.g. through-the-flow-line tool systems
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
    • E21B33/072—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells for cable-operated tools
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/01—Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like

Definitions

  • information is sometimes transmitted to the surface from instruments within the wellbore, and/or from the surface to downhole instruments.
  • signals may be transmitted to or from measurement-while-drilling (MWD) equipment, logging-while-drilling (LWD) equipment, steering equipment, or other equipment.
  • MWD measurement-while-drilling
  • LWD logging-while-drilling
  • Such information may assist operators in the task of efficiently drilling a wellbore by providing information related to tool- face orientation and/or formation composition, and allowing commands and configuration of the downhole instruments, among other possible uses.
  • wireline logging processes may be employed to collect information related to drill-string characteristics, including tool-face orientation, e.g., using a gyroscope. Additionally, "free-point indication" may be determined, facilitating locating a stuck point along the drill string. Wireline logging processes may be performed with the wireline logging tool installed inside the bore of the drill string.
  • the drill string may extend thousands of feet, and transmitting data from MWD equipment over this distance, below the surface, may present challenges.
  • One way such transmission has been effected is through the use of mud-pulse telemetry; however, in mud-pulse telemetry, the signal-to-noise ratio and the transmission rates are generally low.
  • Electromagnetic (“e-mag”) signal transmission has also been employed. However, the effectiveness of this type of signal transmission depends partially on the formation properties. If, for example, the wellbore penetrates a salt layer, the electromagnetic transmissions may be unable to reach the surface.
  • Wired drill pipe for example, has been proposed, and has the potential to obviate the challenges experienced with wireless signal transmission.
  • each pipe includes a wire connector that is prone to failure, if one connector in one pipe among the potentially thousands of pipes fails, the entire assembly can be rendered inoperative.
  • inductive coupling may be used in the pipe connectors; however, this may lead to signal attenuation at each connector pair.
  • data repeaters are sometimes employed in the drill pipe.
  • the combination of a large number of connectors and repeaters along the drill string increases cost and complexity of the drill string, while reducing reliability.
  • it may be difficult to locate due to the number of failure- prone components available, and the drill string is typically removed to locate the failure, resulting in costly lost time.
  • Embodiments of the disclosure may provide a method for deploying an instrument in a drill string in a wellbore.
  • the method includes receiving an active instrument line through a drilling device and into the drill string, the active instrument line being connected to the instrument via a shallow connection, the instrument and the shallow connection being in the drill string.
  • the method also includes lowering the active instrument line until a lower connection thereof reaches a predetermined depth, disconnecting the active instrument line from the shallow connection at the predetermined depth, and removing the active instrument line from the drill string, while the instrument remains in the drill string.
  • the method further includes connecting a first interconnected line to the shallow connection in the drill string and to the active instrument line, and lowering the active instrument line, the first interconnected line, and the instrument in the drill string.
  • Embodiments of the disclosure may also provide a drilling system including a drilling device, a drill string coupled to the drilling device and extending into a wellbore, an instrument located in the drill string, the instrument being configured to generate one or more signals, and an active instrument line configured to extend into the drill string.
  • the active instrument line is configured to transmit the one or more signals.
  • the system may further include an interconnected line configured to be positioned in the drill string.
  • the interconnected line includes an upper connector and a lower connector.
  • the upper and lower connectors are each configured to form a junction with another connector in the drill string. The junction is disconnectable within the drill string, and the one or more interconnected lines are configured to transmit the one or more signals.
  • Figure 1 illustrates a simplified, schematic view of a drilling rig system, according to an embodiment.
  • Figures 2A and 2B illustrate a flowchart of a method for deploying an instrument in a drill string, according to an embodiment.
  • Figures 3, 4, 5, 6, and 7 illustrate a side, schematic view of a drilling system at various stages during the method, according to an embodiment.
  • Figure 8 illustrates a conceptual, side, schematic view of a junction module, according to an embodiment.
  • Figures 9A and 9B illustrate conceptual, side, schematic views of a connection between the junction module and instrument lines, according to an embodiment.
  • Figures 10A and 10B illustrate conceptual, side, schematic views of a passive connection between junction modules and instrument lines, according to an embodiment.
  • Figures 11A and 11B illustrate a partial cross-sectional view of another example of a junction module, according to an embodiment.
  • Figure 12 illustrates a schematic view of a computing system, according to an embodiment.
  • first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. For example, a first object could be termed a second object or step, and, similarly, a second object could be termed a first object or step, without departing from the scope of the present disclosure.
  • FIG. 1 illustrates a schematic view of a drilling rig system 100, according to an embodiment.
  • the drilling rig system 100 includes a drilling apparatus 102 and a drill string 104 coupled thereto.
  • the drilling apparatus 102 may include any type of drilling device, such as a top drive or any other device configured to support, lower, and rotate the drill string 104, which may be deployed into a wellbore.
  • the drilling apparatus 102 may also include a travelling block 105, which may include of one or more rotating sheaves.
  • the drilling rig system 100 may also include a rig floor 108, from which a support structure (e.g., including a mast) 110 may extend.
  • a slips assembly 109 may be disposed at the rig floor 108, and may be configured to engage the drill string 104 so as to enable a new stand of tubulars to be added to the drill string 104 via the drilling apparatus 102.
  • a crown block 112 may be coupled to the support structure 110.
  • a drawworks 114 may be coupled to the rig floor 108.
  • a drill line 116 may extend between the drawworks 114 and the crown block 112, and may be received through the sheaves of the travelling block 105. Accordingly, the position of the drilling apparatus 102 may be changed (e.g., raised or lowered) by spooling or unspooling the drilling line 116 from the drawworks 114, e.g., by rotation of the drawworks 114.
  • the drilling rig system 100 may also include an active instrument line 120, which may be received through the drilling apparatus 102 and into the drill string 104.
  • the active instrument line 120 may be spooled on an instrument line spool or "primary" winch 122, and may be received at least partially around a line sheave 124, between the primary winch 122 and the drilling apparatus 102.
  • the primary winch 122 may be coupled to the rig floor 108 as shown, but in other embodiments, may be positioned anywhere on the drilling rig system 100 or in proximity thereto.
  • the line sheave 124 is installed above the sheaves of the crown block 112.
  • the active instrument line 120 passes between the sheaves of the crown block 112 as the crown block 112 may be split in a similar fashion of the split travelling block 105.
  • the line sheave 124 may be installed on the side or even slightly at lower elevation of the sheaves of the crown -block 112.
  • the instrument line 120 may not leave the line sheave 124 in a fully aligned position versus the entry port 146 of the drilling apparatus 102.
  • the drilling apparatus 102 may include an instrument line guide to align the instrument line 120 with the bore of the entry port 146.
  • the active instrument line 120 may be connected to a downhole instrument, which may be deployed into the interior of the drill string 104, as will be described in greater detail below.
  • the instrument may generate signals, e.g., related to measurements taken by sensors thereof, which may be communicated to surface equipment (e.g., a controller 128) via the active instrument line 120, and, in some embodiments, without including wires formed as part of the drill string 104 itself.
  • the position of the downhole instrument may be changed (e.g., raised or lowered) by spooling or unspooling the active instrument line 120 from the primary winch 122.
  • the downhole instrument may be any type of instrument, such as a logging device, geophone, acoustic receiver, torque sensor, and/or the like.
  • the drilling apparatus 102 may further include a drilling device 138, e.g., a top drive.
  • the drilling device 138 may include a housing 139 and a shaft 140, which may be coupled to and extend out of the housing 139.
  • the shaft 140 may be rotatably coupled to the housing 139 via a thrust bearing 163 .
  • the shaft 140 may be driven to rotate by a motor 150, which may be coupled to and/or disposed within the housing 139.
  • the shaft 140 may be connected to the drill string 104, such that rotation of the shaft 140 may cause the drill string 104 to rotate.
  • the housing 139 which transmits the weight to the rig floor 108 via the crown block 112 and the support structure 110, as well as the drawworks 114.
  • the drilling device 138 may also include one or more rollers 144 (four are shown) or slide guides, which may transmit reactionary torque loads to the support structure 110.
  • the housing 139 may further include an entry port 146, through which the active instrument line 120 and the instrument 300 may be received.
  • the drilling apparatus 102 may include a sealing device 152, through which the active instrument line 120 and the instrument may be received into the entry port 146.
  • the sealing device 152 may be coupled to the housing 139 of the drilling device 138, and may be movable therewith.
  • the sealing device 152 may have (e.g., be able to be operated in) at least three configurations. In an open configuration, the sealing device 152 may be configured to receive the instrument therethrough. In a first sealed configuration (illustrated in Figure 2), the sealing device 152 may be configured to receive and seal with the active instrument line 120.
  • the active instrument line 120 may be able to slide relative to the sealing device 152 when the sealing device 152 is in the first sealed configuration, but fluid may be prevented from proceeding through the entry port 146 by the sealing device 152.
  • the sealing device 152 may completely seal the entry port 146, e.g., when the active instrument line 120 is not received therethrough.
  • the sealing device 152 may function similarly to how a blowout preventer does for the drill string 104, serving to control access into and seal the entry port 146.
  • the different configurations may be reached based on a position of an annular "preventer" or seal 180 of the sealing device 152.
  • the sealing device 152 may also include one or more rams (two shown: 181, 182).
  • the annular seal 180 may be movable in response to a command, e.g., radially inwards and outwards. Accordingly, the annular seal 180 may be moved outwards to receive the active instrument line 120 and inwards to seal the entry port 146.
  • the ram 181 may be a pipe ram, and the ram 182 may be a blind ram.
  • a line- pusher 165 may include two or more tracks or "wheels" 184, 185, which may be moved to move the active instrument line 120 through the entry port 146.
  • the entry port 146 may communicate with an interior 160 of the shaft 140, e.g., via a conduit 161 within the housing 139.
  • the shaft 140 may be rotatably coupled to the conduit 161 via swivel 164, as shown. Accordingly, the active instrument line 120, when received through the entry port 146, may proceed through the conduit 161 and into the shaft 140, and then into the drill string 104.
  • the drilling device 138 may also receive a flow of drilling mud via a mud conduit 162.
  • the mud conduit 162 may communicate with the conduit 161 within the housing 139, and thus the mud conduit 162 may be in fluid communication with the entry port 146, as well as the interior 160 of the shaft 140 and the drill string 104.
  • the sealing device 152 may serve to prevent mud flow up through the entry port 146 in either or both of the first and second configurations thereof.
  • the drilling apparatus 102 may further include a line -pusher 165.
  • the line -pusher 165 may be configured to apply a downwardly-directed force on the active instrument line 120, which may cause the active instrument line 120 to be directed downward, through the sealing device 152, the entry port 146, the conduit 162, the interior 160 of the shaft 140, and through at least a portion of the drill string 104, so as to deploy the instrument (see, e.g., Figure 3) therein.
  • the line-pusher 165 may be coupled to the housing 139 of the drilling device 138 and may be movable therewith.
  • the line -pusher 165 may be directly attached to the sealing device 152, e.g., such that the sealing device 152 is positioned between the housing 136 and the line-pusher 165.
  • the line-pusher 165 may be configured to push the instrument line 120 through the entry port 146 via the sealing device 152.
  • the line-pusher 165 may be employed to overcome initial fluid resistance provided by the drilling mud coursing through the mud conduit 162, as well as the friction between the instrument linel20, the interconnected line 202 and the instrument 300 with the internal bore of the drill string 104 when these components are moved axially inside the bore of the drill string 104 . Further, the line-pusher 165 may provide for rapid deployment of the active instrument line 120 through the drill string 104, e.g., at a similar rate, or even faster than, the velocity of the drilling mud therein, and thus the line-pusher 165 may overcome drag forces of the instrument and the drilling line 116 in contact with the mud.
  • the line-pusher 165 may also be used to retract the active instrument line 120 and the instrument out of the drill string 104, e.g., by reversing direction and pushing the active instrument line 120 upwards, away from the entry port 146.
  • the retracted active instrument line 120 may thus be spooled on winch 122, e.g., with minimum pull force by the winch 122.
  • the line-pusher 165 may include two or more tracks or "caterpillars" as shown, which may engage and move the active instrument line 120 into and/or out of the entry port 146.
  • the tracks may include links, rollers, or any other structure capable of engaging the active instrument line 120 and, e.g., through the friction created by such an engagement, force the active instrument line 120 downwards into the entry port 146, or to push the instrument line 120 upwards, out of the entry port 146.
  • the drilling apparatus 102 may also include a pivotable guide 170, through which the active instrument line 120 may be received.
  • the pivotable guide 170 may be positioned, as proceeding along the line 120, between the line sheave 124 and the line -pusher 165.
  • the pivotable guide 170 may be movable across a range of positions, for example, between a first position, shown with solid lines, and a second position, shown with dashed lines. In the first position, the pivotable guide 170 may direct the active instrument line 120 toward the entry port 146 to avoid the sheaves of the crown block 112 and between the sheaves of the travelling block 105 and. In the second position, the pivotable guide 170 may direct the active instrument line 120 away from the entry port 146.
  • the second position may be employed when the active instrument line 120 is directed towards the rig floor 108 so that the operator can manipulate the instrument line 120 and/or the instrument connected thereto, e.g., to connect the instrument on the instrument line 120. Then the instrument can be raised above the travelling block 105, guided by the pivotable guide 170 in the second position. Similar usage of the pivotable guide 170 may be considered for the removal of the instrument from the active instrument line 120.
  • the shaft 140 is connected to a gear 190, which meshes with a gear 192 that is connected to a motor shaft 194.
  • the motor shaft 194 is rotated by the motor 150, and such rotation is transmitted to the shaft 140 via the meshing gears 190, 192.
  • the motor 150 is coupled to the housing 139 using motor mounts 196.
  • the gear 192 and motor shaft 194 are guided via the mounts 196 supporting bearings.
  • the drilling rig system 100 may include one or more secondary winches (one shown: 200), which may spool and unspool an interconnected line 202.
  • the interconnected line 202 may include an upper connection 204, and may, although it is not visible in this view, also include a lower junction.
  • the upper connection 204 may include a fishing head and the lower junction may include a fishing tool as described below with reference to Figures 10A and 10B.
  • the upper connection 204 of the interconnected line 202 may include a junction module as described below, with reference to Figure 8.
  • the interconnected line 202 may be received through or over a guide 206, which may direct the interconnected line 202, lower junction first, into the drill string 104.
  • the guide 206 may be a rotatable sheave.
  • the interconnected line 202 may be deployed when the drilling device 138 is disconnected from the drill string 104, e.g., when adding a new stand of one or more drill pipes, as will be described in greater detail below.
  • the active instrument line 120 Prior to disconnecting the drilling device 138 from the drill string 104, the active instrument line 120 may be removed from the drill string 104 by the primary winch 122; the lower extremity of the active instrument line may be kept inside shaft 140 of the drilling apparatus 102.
  • the drill string 104 may be supported by the slips assembly 109 at the rig floor 108, or elsewhere, so as to allow the drilling device 138 to be disconnected therefrom and allow entry into the drill string 104.
  • the active instrument line 120 and/or the interconnected line 202 may be or include a metallic line with one or more internal wires therein (e.g., electrical or fiber optic wires) for communication and/or transmission of power.
  • the lines 120, 202 may have a diameter from approximately 1/16 inch (1.5 mm) to approximately 1 inch (2.5 cm) or from approximately 1/8 inch (3.0 mm) to approximately 1/2 inch (1.3 cm).
  • the lines 120, 202 may transmit signals to and from one or more instruments or other devices coupled thereto.
  • the lines 120, 202 may transmit power to and from one or more instruments or other devices coupled thereto.
  • the Euler buckling length of the lines 120, 202 may be more than 10 feet (3.1 m) at the bottom of the lines 120, 202.
  • the lines 120, 202 may thus not pack within the bore of the drill string when released from connection with the surface.
  • the line 120,202 may not pack within the bore of the drill string 104, thereby facilitating re-connection or fishing in the drill string 104.
  • the lines 120, 202 may have a resistance to torque, to constrain the twist angle when torque is applied over its length.
  • the lines 120, 202 may also have a smooth outer surface or approximately smooth outer surface, thus reducing friction in the rotating drill string 104 and/or in the sealing device 152.
  • the lines 120, 202 may be configured to transmit measurement data (e.g. signals) generated by an instrument.
  • lines 120, 202 may transmit logged data to the rig.
  • One or more downhole instruments, delivered by the lines 120, 202 may be any type of instrument, such as a wireline logging tool or a connecting system which may ensure a connection to a logging-while-drilling ("LWD") tool, a measurement-while-drilling (“MWD”) tool, including a geophone, an acoustic receiver, an electrical electrode, a navigation sensor package, a torque sensor, and/or the like.
  • LWD logging-while-drilling
  • MWD measurement-while-drilling
  • the downhole instrument may be configured to obtain measurements in the wellbore 106, and the measurements may be or include current measurements, voltage differential measurements, rotational measurements (e.g., local instantaneous RPM of the drill string 104), radial and axial shocks, local elastic deformation measurements (e.g., axial and torsion), steel acoustic transmission measurements (e.g., "CBL- type"), navigation data based either on gravity accelerometers, magnetometers or gyroscope and the like.
  • the downhole instrument 300 may include two set of anchoring systems.
  • the instrument 300 may serve as a "wireline free-point indicator" or may perform measurements of current or voltage difference along the drill-string, as well as vibration monitoring of the drill string 104.
  • the active instrument line 120 may be used to recover mud pulse telemetry data or electromagnetic telemetry data from a measurement-while-drilling tool.
  • the lines 120, 220 may be used to transmit data, information or commands or settings form the surface to the downhole tool or an MWD and LWD tool. Further, in some embodiments, the lines 120, 202 may have approximately equal lengths, e.g., from about 750 feet (about 230 m) to about 6000 feet (about 1830 m), e.g., about 1330 feet (about 405 m).
  • Figures 2A, 2B, and 2C illustrate a method 250 for deploying an instrument in the drill string 104, according to an embodiment. The method 250 is described with reference to the drilling rig system 100 shown in Figure 1 as a matter of convenience, but embodiments of the method 250 may also be executed using other structures.
  • Figures 3, 4, 5, 6, and 7 illustrate a sequence of execution of the method 250, in which an instrument 300 is lowered into a wellbore, according to an embodiment.
  • an instrument 300 is lowered into a wellbore, according to an embodiment.
  • two secondary winches 200-1 and 200-2 are shown, and will be described in greater detail below.
  • the method 250 may begin by receiving the active instrument line 120 through the entry port 146 formed in the drilling apparatus 102, as at 251.
  • the active instrument line 120 may be lowered through the entry port 146, through the drilling apparatus 102, and into the drill string 104.
  • the active instrument line 120 may be connected to an instrument 300 ( Figure 3), e.g., using a junction, as at 252.
  • the upper extremity of the instrument 300 may be equipped with a fishing head, which may be directly connected to (e.g., form a part of) the instrument line 120. Furthermore, a swivel and an anchor may be installed above the instrument 300, e.g., as part of a junction module. An embodiment of such a junction module is described below, with reference to Figure 8. This junction module may be plugged directly onto the upper fishing head of the instrument 300.
  • the instrument 300 may include or be connected to an anchor, swivel, and/or fishing head, as described below with reference to Figures 9 A and 9B.
  • the connection of the instrument 300 to the active instrument line 120 may be performed by coupling of the fishing tool of the active instrument line 120 onto the fishing head of the instrument 300.
  • the active instrument line 120 and the instrument 300 may then be received into the drill string 104. Thereafter, the method 250 may also include lowering the active instrument line 120 and the instrument 300 until the lower extent of the active instrument line 120 reaches a predetermined depth Dl , as at 254.
  • the depth Dl may be chosen according to a variety of factors. One such factor may include the time available to insert or retrieve the active instrument line 120 through the entry port 146 before the addition and the removal of stand of drill pipe. This may be compared with the time to drill the corresponding length of the stand of drill pipe, as well as the time to perform the addition or removal of drill pipe form the drill sting 104.
  • the drilling apparatus 102 When a new stand of drill pipe is to be added, the drilling apparatus 102 is disconnected from the drill string 104, in order to receive the new stand therebetween. Before, during, or after initially disconnecting the drilling apparatus 102, the active instrument line 120 may be removed from the drill string 104 and into the drilling apparatus 102, such that the new stand may be added without being impeded by the presence of the active instrument line 120. The active instrument line 120 may then be lowered back through the drill string 104, through the new stand first.
  • the operator and/or system may anticipate the spooling process in relation to the drilling process, so as to limit the waiting period to finish the spooling of the active instrument line 120 onto the winch 122 when ready to add a new stand. This anticipated time is minimized by increasing the speed for retrieving the active instrument line 120 out of the drill string 104.
  • the retrieval of the active instrument line 120 may overlap with some operations used to prepare the addition the new stand of drill pipe, for example, such operations may include setting the drill string in slips, breaking the torque between the drill string 104 and shaft 140 of the drilling apparatus 102, unscrewing the threads on the shaft 140 from the drill string 104, etc.
  • the active instrument line 120 may then be lowered in the drill sting 104 to allow connection to and operation of the instrument 300 at its predetermined depth.
  • the lowering of the active instrument line 120 may start when some operations related to the addition of the new stand of drill-pipe are still in progress (e.g., engaging the threads and applying the make-up torque over the new tubular connection).
  • the time during which the instrument 300 is out of position or when not connected to the controller 128 may be "blind" time, during which the instrument 300 may not provide meaningful information.
  • the length of the active instrument line 120 may be constrained, such that the active instrument line 120 extends to the depth Dl, which may be a portion of the depth to which the instrument 300 may eventually be positioned.
  • the length of the active instrument line 120 may thus be a function of the speed of the primary winch 122 and the time it takes to perform some tasks for the addition of a new stand to the drill string.
  • the depth Dl may be a depth between about 750 feet (230 m) and about 4000 feet (1220 m), e.g., about 1330 feet (405 m). In some embodiments, the depth Dl may be about 6000 feet (1830 m) or more.
  • the active instrument line 120 may be partitioned into multiple segments 120A, 120B, 120C, which may be connected together using connectors 299A, 299B, and one or more interconnected instrument line(s) 306 may be provided, as will be described below.
  • the active instrument line 120 may be spooled on the winch 122 and may pass through the drilling device 138 via the entry port 146 to a line connection in the drill string 104. Initially, this connection may be between the active instrument line 120 and the instrument 300. Later in the drilling process, the connection may be the connection of the active instrument line 120 with an interconnected line 202.
  • the active instrument line 120 and the instrument 300 are lowered in the well so that a shallow connection (formed by connectors 302, 304) reaches the depth Dl, as at 254.
  • the method 250 may include activating or setting the anchor of the junction module of the shallower connection, as at 256. Then data acquisition and transmission (e.g., to the surface) by the instrument 300 may then be started, as at 258.
  • the drilling process can be started and/or continued, as at 260.
  • another drill pipe or stand of drill pipes
  • the status anchor of the shallow connection e.g., part of the upper connector 302
  • the anchor of the shallow connection may then be activated (if not activated yet), as at 264, to support the weight of the anchor some equipment below the anchor such as potentially the instrument 300 hanging and the instrument line 120 or even later an interconnected line 202.
  • the anchor of the connection/connector may be activated in response to a signal from the drilling rig system 100, prior to disconnecting the upper and lower connectors 302, 304. At least some (e.g., each) of the connectors for the various lines discussed herein may, in various embodiments, include such anchors.
  • One example of an anchor will be described below.
  • the equipment below the anchor such as the instrument 300 hanging and the instrument line 120 and/or an interconnected line 202 may generally remain in place in the drill string 104 after such disconnection (as shown in Figure 4).
  • the method 250 may then proceed to removing the active instrument line 120 from the drill string 104, as at 266.
  • the lower connector 304 may be raised to a position inside of the drilling apparatus 102, as shown in Figure 4.
  • the method 250 may include disconnecting the drilling device 138 from the drill string 104, as at 268.
  • the drill string 104 may be supported by the slips assembly 109 or another device, such that the drilling device 138 may be moved away from the drill string 104 to allow for a new stand of one or more drill pipes to be positioned between the drill string 104 and the drilling apparatus 102.
  • the new stand (e.g., new stand 500 shown in Figure 7) may then be added by connecting the new stand 500 to the drill string 104 and the drilling device 138, as at 269.
  • the method 250 may then include determining whether the active instrument line 120 is long enough to reconnect to the upper connector 302 in the drill string 104, so as to re-form the shallow connection therewith, as at 270.
  • the instrument 300 may be installed deep in the drill string 104, e.g., beyond the reach of the active instrument line 120 after the addition of the new stand of drill pipe. Accordingly, one or more "interconnected" lines 306, as shown in Figure 5, with corresponding connectors 308, 310 (e.g., including a junction module with anchor, as explained below) may be deployed to form the communication line between the instrument 300 and the surface, allowing transmission of measurements and control information.
  • the interconnected line 306 may be supported by its upper connector 310, which may be selectively anchored in the drill string 104. To add or remove a stand of drill pipe, the active instrument line 120, and possibly the upper-most interconnected line 306, may be removed from the drill string 104. This may reduce the amount of line inserted and removed when adding or removing a stand of drill pipe to/from the drill string 104.
  • the length of the interconnected line 306 may be between about 1330 feet (about 407 m) and about 6000 feet (about 1830 m), e.g., about 4000 ft.
  • the active instrument line 120 may be slightly longer than the interconnected line 306.
  • the active instrument line 120 may be formed from several, e.g., three instrument line segments 120A, 120B, 120C (approximately slightly more than 1330 feet), connected end-to-end at connectors 299A, 299B ( Figure 3), so that the combined length is slightly longer than the length of the interconnected line 306.
  • Each line segment 120A-C may include an upper connector having a junction module with anchor and swivel, as describe below.
  • One of these instrument line segments 120A-C may be stored on the winch 200-1, with the winch 200-2 supporting an interconnected line (such as line 306). In other embodiments, the secondary winch 200-2 may also support the interconnected line 306.
  • the length of the inserted part of the active instrument line 120 may increase with every addition of a stand of drill pipe to the drill string 104. This may allow operation with the shortest-available active instrument line 120, with a line 120 of one segment 120A being employed, until its full length is inserted in the drill string 104. Then a second segment 120B of the active instrument line 120 is added in the drill string 104, then 120C, etc. Accordingly, two (or more) short instrument lines may be added from the winch 200-1. When the winch 200 (or 200-1 or 200-2) has transferred its line into the drill string 104, the winch 122 may be reloaded with one or more additional short active instrument line(s).
  • the lower connector 304 may reach the upper connector 302 after the addition of the new stand of drill pipe.
  • An additional stand of drill pipe may then be inserted between the top of the drill string 104 (maintained in the slips assembly 109) and the drilling device 138, as at 272.
  • the lower connector 304 of the active instrument line 120 may be lowered through the drill string 104 and reconnected onto the upper connector 302, as at 274.
  • the method 250 may then return to acquiring/transmitting data using the instrument 300.
  • the drill string 104 may be opened for access thereto by lifting the drilling device 138, which was disconnected at block 268, away from the drill string 104, e.g., while the drill string 104 is supported at the rig floor 108 using the slips assembly 109.
  • the method 250 may then proceed to deploying a first interconnected line 306 into the drill string 104, as at 280, e.g., through the new stand 500. This may be accomplished using the secondary winch 200-1, which may lower the first interconnected line 306 though the open end of the drill string 104 supported in the slips assembly 109.
  • the first interconnected line 306 may include a lower connector 308 and upper connector 310.
  • the first interconnected line 306 is unspooled until the upper connector 310 reaches the top of the drill string as 282.
  • the upper connector 310 is locked onto the drill pipe 104 using a locking device 316. Then, the upper connector 310 may be disconnected from a connector 312 of an installation line 314 attached on the winch 200-1, thereby releasing the interconnected line 306 from the winch 200-1.
  • the active instrument line 120 may then be unspooled to allow the connection of its lower connector 304 onto the upper connector 310 of the first interconnected line 306, as at 284. This is shown in Figure 6.
  • the winch 122 applies a tension on the active instrument line 120 and the first interconnected line 306, as at 286, allowing the removal of the lock device 316.
  • the drilling device 138 may be reconnected to the drill string 104, as at 288.
  • the method 250 in this embodiment, may include lowering (unspooling) the active instrument line 120 and the interconnected line 306 connected thereto, until the lower connector of the interconnected line 306 connects with the upper connector (in this case, the upper connector of the instrument 300).
  • the upper connector 310 of the first interconnected line 306, once the first interconnected line 304 is connected to the instrument connector 302, may thus serve as the shallow connection. Accordingly, the method 250 may return to block 258, such that the use and lowering of the instrument 300 via the short active instrument line 120 may repeat. When the shallow connection again reaches the predetermined depth Dl, a third interconnected line may be connected therewith, with the process repeating with additional interconnected lines, for as far as the instrument 300 is to be deployed. In some embodiments, the method 250 may facilitate maintaining the instrument 300 at a predefined distance from the drill bit 700; however, other logic for instrument positioning may be considered.
  • the active instrument line 120 may be moved by the winch 122 and the line -pusher 165 through the entry port 146. As this line is short, the spooling time is also relatively short, reducing blind time and non-productive time (NPT).
  • the instrument 300, the active instrument line 120, and any interconnected line(s) may be un-anchored from the drill string 104, by sending a signal to the appropriate junction modules (connectors).
  • the instrument 300, active instrument line 120, and any interconnected lines 306 may then be removed from the drill string 104 as a single unit.
  • This assembly of components may also be re-anchored at a new axial position in the drill string 104, e.g., in response to commands sent to the appropriate junction module(s) (connectors).
  • an upper part of the system may be retrieved from the drill string 104, while a lower part remains therein. This may be effected by un-anchoring the upper part of the system, which allows the upper part of the system to be removed from the drill string 104 while leaving the drill sting 104 within the well. Accordingly, a malfunctioning or failing component may be removed from the drill string 104 without calling for removal of the full assembly. Once the inoperative component is located and repaired or replaced, the removed, upper part of the system may be lowered back into the drill string 104 and into connection with the lower part of the system.
  • FIG. 8 illustrates a conceptual, side, schematic view of a junction module 800 as a network node, according to an embodiment.
  • the junction module 800 may include an upper section 802.
  • the upper section 802 may include an inductive coupler 804 (male part), fishing neck 806, and an un-coupler 808.
  • the inductive coupler 804 can be configured to inductively transfer signal and/or power to and from the junction module 800.
  • the fishing neck 806 can be configured to provide connection point for the upper end of the junction module 800.
  • the fishing neck 806 may provide a connection point for fishing tools, instrument lines, junction modules, and the like.
  • the un- coupler 808 can be configured to uncouple devices from the fishing neck 806, as discussed further below.
  • the junction module 800 may include a swivel 810 coupled to a lower portion of the upper section 802.
  • the swivel 810 may be positioned between the upper section 802 and the electronics section 812.
  • the swivel 810 may allow the junction module 800 to rotate while sections of the instrument line, connected to the junction module, do not rotate. This may allow the junction module 800 to rotate with the drill string 104.
  • the swivel 810 may also support the axial load generated by the junction module 800 or sections of the instrument line.
  • the swivel 810 may include thrust bearing 814.
  • the swivel 810 may also include lubrication 816 (e.g. oil) within a cavity of the swivel 810 and surround the thrust bearing 814.
  • the swivel 810 may also include rotary connection 818.
  • the rotary connection 818 may allow for transmission of signal and/or power transmission for each wire in the instrument line and for grounding the tubing.
  • the rotary connection 818 may be rotary contact or a rotary split transformer.
  • the electronics section 812 may include any electronics or electrical components requirement during the operations.
  • the electronics section 812 may be sealed against the down- hole pressure to allow the operations of the electronics or electrical components, for example, approximately atmospheric pressure.
  • the electronics section 812 may include logging tools, MWD telemetry tools (described above), control modules, communication devices, and the like.
  • the electronics section 812 may also include a network node.
  • the network node may be used to decode and re-encode in one or two directions, for example, data transmitted downhole from the surface and/or data received from instruments in the wellbore 106 and transmitted to the surface. Data collected from LWD/MWD type measurements within the electronics section may also be added to the data transmitted by the network node.
  • the electronics section 812 may also include a power source 820.
  • the power source 820 may be any type of power source such as a battery, a rechargeable battery, and the like.
  • the power may be supplied through the instrument line to charge the power source and provide power to the electronics section 812 and other components in the wellbore 106, for example, the BHA.
  • the power source may provide power if the junction module 800 is disconnected from the surface.
  • the junction module 800 may include an anchor section 822.
  • the anchor section 822 may be configured to anchor the junction module 800 (and any attached sections of instrument line) to an interior of the drill string 104.
  • the anchor section 822 may include one or more articulated anchors 824, one or more solenoids 826, and one or more biasing members 828.
  • the articulated anchors 824 may be configured to expand radially-outward and engage with the interior surface of the drill string 104.
  • the solenoids 826 may be configured to cause the articulated anchors 824 to expand or contract by moving the instrument axially in the bore of the drill-sting 104, and lock the articulated anchors 824 in a position.
  • the biasing member 828 may provide force radially-outward on the articulated anchors 824.
  • the articulate anchor has such bidirectional design so that when the junction module 800 moves axially in the bore of the drill string, the anchor (when not set and not locked by the solenoid) may retract when the extremity of the anchor enters in contact with a change of dimeter in the drill-sting (such as shoulder or change of bore in the drill-pipe tool-joint).
  • the junction module 800 may include a lower section 830.
  • the lower section 830 can include an inductive coupler 832 (female part) and one or more grabbing fingers 834.
  • the inductive coupler 832 can be configured to inductively transfer signal and/or power to and from the junction module 800.
  • the grabbing fingers 834 can be configured to provide connection point for the lower end of the junction module 800.
  • the fishing neck 806 may provide a connection point for fishing tools, instrument lines, junction modules, and the like.
  • junction module 800 While described above as having a “male” connection in the upper end of the junction module 800 and a “female” connection as the lower end of the junction module 800, the junction module 800 may have “female” connection in the upper end of the junction module 800 and a “male” connection as the lower end of the junction module 800.
  • the junction module 800 may be decoupled from the instrument line 120. This may be done via network control or slick-line mechanical techniques. Once decoupled, the instrument line 120 may be retrieved at the pipe connection.
  • Figures 9A and 9B illustrate conceptual, side, schematic views of a connection between the junction module 800 and instrument lines, according to an embodiment. More particularly, Figure 9A shows the lower end of one section of the instrument line 120 decoupled from the upper end of the junction module 800, and the lower end of the junction module 800 decoupled from the upper end of another section of the instrument line 120. The lower end of one section of the instrument line 120 having a female fishing tool 904 coupled thereto and the upper end of another section of the communication cable having a male fishing neck 902 coupled thereto. As illustrated Figure 9B shows the lower end of one section of the instrument line 120 coupled to the upper end of the junction module 800, and the lower end of the junction module 800 coupled to the upper end of another section of the instrument line 120.
  • the instrument line 120 may have a fishing tool coupled thereto.
  • the fishing tool at the "active inserted line" may be decoupled in the wellbore 106.
  • the communication line and the junction module may form or include a network with a repeater. This may be a similar configuration as the multiple sections of the communication line discussed above. There may be a continuous data-latch to measuring-while-drilling and logging- while-drilling. This may enable the detection of faults in the network.
  • Figures 10A and 10B illustrate conceptual, side, schematic views of a passive connection between junction modules and instrument lines, according to an embodiment. More particularly, Figure 10A shows the lower end of one section of the instrument line 120 having a female fishing tool 1002 coupled thereto and the upper end of another section of the communication cable having a male fishing neck 1004 coupled thereto. As illustrated in Figure 10B, the female fishing tool 1002 may couple to the male fishing neck 1002. The female fishing tool 1002 may couple to the male fishing neck 1002 may include inductive couplers to inductively transfer signal and/or power between the instrument lines 120. The embodiment shown in Figures 10A and 10B may provide more attenuation.
  • Figures 11A and 11B illustrate partial cross-sectional views of examples of a locating module, according to an embodiment.
  • Figure 11A illustrates a partial cross- sectional view of examples of a locating module 1100, according to an embodiment.
  • the locating module 1100 may include landing groove 1110.
  • a latching dog may be installed on the of the junction module 800 (as illustrated in Figure 8) and replace the anchor 822 (as illustrated in Figure 8) and may allow locking of the latching dog in a landing groove 1110 on the locating module 1100.
  • the latching dog may be released when desired by an operator at the surface: the latching dog is then radially pushed against the bore of the drill-sting 104 to possibly enter into the landing groove 1110 of the locating module 1100 when the junction module 800 passes across the locating module 1100. With locating module 1100, the latching dog may be released when the junction module 800 is still above the locating module 1100. The latching dogs will stop against an axial stop 1120 of the locating module 1100.
  • the release mechanism may be triggered via telemetry (e.g., from the surface). This may include a one time activation, and it may be reset manually.
  • the latching dog may be chamfered so that the junction module 800 may be pulled upwards in the drill string without catching upon an obstruction in the bore of the drill-sting 104.
  • FIG 11B illustrates a partial cross-sectional view of examples of a locating module 1130, according to an embodiment.
  • the locating module 1130 may include landing groove 1140.
  • a latching dog may be installed on the of the junction module 800 (as illustrated in Figure 8) and replace the anchor 822 (as illustrated in Figure 8) and may allow locking of the latching dog in a landing groove 1140 on the locating module 1130.
  • the latching dog may be released when desired by an operator at the surface: the latching dog is then radially pushed against the bore of the drill-sting 104 to possibly enter into the landing groove 1140 of the locating module 1130 when the junction module 800 passes across the locating module 1130.
  • the latching dog may be released when the junction module 800 is still above the locating module 1130.
  • the latching dogs will stop against an axial stop 1120 of the locating module 1130.
  • the release mechanism may be triggered via telemetry (e.g., from the surface). This may include a one time activation, and it may be reset manually.
  • the latching dog may be chamfered so that the junction module 800 may be pulled upwards in the drill string without catching upon an obstruction in the bore of the drill-sting 104.
  • the release may be triggered when the latching dog of the junction module 800 has passed below the locating module 1130.
  • the release mechanism may be triggered via telemetry (e.g., from the surface). This may include a one time activation, and it may be reset manually.
  • the latching dog may be chamfered so that the junction module 800 may be pulled upwards in the drill string without catching upon an obstruction in the bore of the drill-sting 104.
  • the locating module 1100 or 1130 may be designed as part of the drill string 104.
  • the junction module 800 may be configured to latch or couple into the locating module.
  • a different section of the instrument line may "hang" from the bottom of the network module.
  • a "coiled pig tail” may be positioned at the lower end of each section of the instrument line.
  • the pig tail may be a coil and/or spring that account for the mismatch in length between the instrument line and the distance between successive locating modules of the drill string.
  • the bore of the locating module may be larger than the bore of the drill sting 104. This provides more annular space between the junction module 800 and the bore of the locating module 1100 or 1130 so that the mud flow does not have too high velocity and flor erosion is limited.
  • the methods of the present disclosure may be executed by a computing system.
  • Figure 12 illustrates an example of such a computing system 1200, in accordance with some embodiments.
  • the computing system 1200 may include a computer or computer system 1201A, which may be an individual computer system 1201A or an arrangement of distributed computer systems.
  • the computer system 1201A includes one or more analysis modules 1202 that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these various tasks, the analysis module 1202 executes independently, or in coordination with, one or more processors 1204, which is (or are) connected to one or more storage media 1206.
  • the processor(s) 1204 is (or are) also connected to a network interface 1207 to allow the computer system 1201 A to communicate over a data network 1209 with one or more additional computer systems and/or computing systems, such as 1201B, 1201C, and/or 1201D (note that computer systems 1201B, 1201C and/or 1201D may or may not share the same architecture as computer system 1201A, and may be located in different physical locations, e.g., computer systems 1201A and 1201B may be located in a processing facility, while in communication with one or more computer systems such as 1201C and/or 1201D that are located in one or more data centers, and/or located in varying countries on different continents).
  • 1201B, 1201C, and/or 1201D may or may not share the same architecture as computer system 1201A, and may be located in different physical locations, e.g., computer systems 1201A and 1201B may be located in a processing facility, while in communication with one or more computer systems such as 1201C
  • a processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.
  • the storage media 1206 may be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of Figure 12 storage media 1206 is depicted as within computer system 1201A, in some embodiments, storage media 1206 may be distributed within and/or across multiple internal and/or external enclosures of computing system 1201A and/or additional computing systems.
  • Storage media 1206 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLU-RAY ® disks, or other types of optical storage, or other types of storage devices.
  • semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories
  • magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape
  • optical media such as compact disks (CDs) or digital video disks (DVDs), BLU-RAY ® disk
  • the instructions discussed above may be provided on one computer-readable or machine -readable storage medium, or alternatively, may be provided on multiple computer- readable or machine-readable storage media distributed in a large system having possibly plural nodes.
  • Such computer-readable or machine -readable storage medium or media is (are) considered to be part of an article (or article of manufacture).
  • An article or article of manufacture may refer to any manufactured single component or multiple components.
  • the storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.
  • the computing system 1200 contains one or more telemetry module(s) 1208.
  • computer system 1201A includes the telemetry module 1208.
  • a single telemetry module may be used to perform some or all aspects of one or more embodiments of the methods disclosed herein.
  • a plurality of telemetry modules may be used to perform some or all aspects of methods herein.
  • the computing system 1200 is one example of a computing system; in other examples, the computing system 1200 may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of Figure 12, and/or the computing system 1200 may have a different configuration or arrangement of the components depicted in Figure 12.
  • the various components shown in Figure 12 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.
  • the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices.
  • information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices.

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Abstract

La présente invention concerne un système de forage et un procédé de déploiement d'un instrument dans un train de tiges dans un puits de forage. Le procédé comprend la réception d'une ligne d'instrument actif à travers un dispositif de forage et dans le train de tiges, la ligne d'instrument actif étant reliée à l'instrument par l'intermédiaire d'un raccordement peu profond, l'instrument et le raccordement peu profond se trouvant dans le train de tiges. Le procédé consiste également à abaisser la ligne d'instrument actif jusqu'à ce qu'un raccordement inférieur correspondant atteigne une profondeur prédéterminée, à déconnecter la ligne d'instrument actif du raccordement peu profond à la profondeur prédéterminée, et à retirer la ligne d'instrument actif du train de tiges, tandis que l'instrument reste dans le train de tiges. Le procédé consiste en outre à raccorder une première ligne interconnectée au raccordement peu profond dans le train de tiges et à la ligne d'instrument actif, et à abaisser la ligne d'instrument actif, la première ligne interconnectée, et l'instrument dans le train de tiges.
PCT/US2016/027340 2015-04-13 2016-04-13 Ligne d'instrument multi-segment pour instrument d'un train de tiges Ceased WO2016168335A1 (fr)

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