US20140124197A1

US20140124197A1 - Systems and methods for maneuvering downhole tools in a subsea well

Info

Publication number: US20140124197A1
Application number: US13/668,685
Authority: US
Inventors: Daniel Marco Veeningen
Original assignee: Intelliserv LLC
Current assignee: Intelliserv LLC
Priority date: 2012-11-05
Filing date: 2012-11-05
Publication date: 2014-05-08

Abstract

A method for maneuvering a downhole tool in a well system includes: displacing a tool through a riser; detecting electromagnetic radiation from a source in real time using a detector coupled to the tool; and altering the velocity of the tool in response to detecting the electromagnetic radiation.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Disclosure
The disclosure relates generally to systems and methods for operating or testing offshore wellbore service equipment. More particularly, the disclosure relates to systems and methods for transporting equipment to a wellhead or wellbore in an offshore well system.
2. Background of the Technology
In drilling for oil and gas from a hydrocarbon producing well, a well or well system is provided that includes a drilling rig with a riser section and a drill string used to convey drilling fluid down the drill string and through a wellhead at the sea floor to a drill bit disposed within a wellbore that extends into a subterranean formation. At certain points during the operation of the well system, it may become necessary or advantageous to install or land equipment (e.g., a casing plug, back pressure valve, casing hangers, casing lock-down assemblies, jet-subs, packers, whipstocks etc.) within the well system far below the water at or below the wellhead. In some instances, such equipment may be landed or seated on associated equipment at the wellhead in order to form a seal engagement between the landed equipment and its associated equipment at the wellhead. For instance, in certain jurisdictions it is required to pressure test specific pressure containing equipment of the well system (e.g., blowout preventer, choke line, kill line, etc.) at regulated intervals. As part of the procedure for pressure testing such components, it may be necessary to install a testing plug, or other equipment downhole, proximal to the wellhead in order to accommodate the pressure testing of downhole systems and equipment.
As an example, in order to pressure test individual sealing elements (i.e. rams) of a blowout preventer (BOP) after it has been installed at the wellhead, it is necessary to isolate the wellbore extending below the wellhead from the BOP such that the internal cavity of the BOP may be pressurized to a fluid test pressure to ensure that individual rams of the BOP will seal against such fluid pressures. In order to fluidically isolate the wellbore from the BOP, a BOP test plug is often coupled to a work or drill string and displaced downward with the drill string through the marine riser of the well system to land on a component of the wellhead (e.g., wellhead spool, tubing head, casing head body, etc.).
The BOP test plug is typically configured to engage the wellhead by landing a lower annular surface of the plug against an upper annular surface of a wellhead spool located at the wellhead. However, while a drilling operator may have a rough estimate of the distance between the rig and the wellhead and the total length of drill string between the BOP test plug and the rig, the operator is often without means for precisely and accurately determining when the BOP test plug has come into close proximity with the wellhead. Thus, at times, the BOP test plug may collide with the wellhead spool at a velocity that may result in damaging the BOP test plug, wellhead, or other associated equipment of the well system. Specifically, as the velocity of the drill string and its associated equipment is increased, the amount of impulse or change in momentum of the string resulting from an impact correspondingly increases, making it more likely that the string or its associated equipment may become damaged from such a collision. Thus, without reducing the mass of the drill string and its associated equipment, the velocity of the string must be reduce to minimize the impulse imparted to the string in a potential impact. Further, following a collision between the BOP test plug and the wellhead spool, continued downward displacement of the drill string into the marine riser may lead to buckling of the drill string within the riser. In this case, a drilling operator may not become aware of such a collision in time to slow and stop the displacement of drill string into the riser before buckling of the drill string has already commenced.
During the course of drilling and completing a well for the production of hydrocarbons, it may also become necessary to install well components downhole, below the wellhead and extending into the formation. For instance, in wells that feature a lined or cemented wellbore, liner may be displaced from the rig, through the riser, BOP and wellhead, into the borehole where it will be affixed to the wall of the wellbore. Further, in some drilling and completion operations it may become necessary to displace a bottomhole assembly into the wellbore, such as instruments for directional drilling. As the bottomhole assembly or other equipment passes through the BOP stack and wellhead, it is possible for such equipment to “snag” or “hang” on the BOP or wellhead. This is often caused by relative movement between the wellhead and the rig at the surface, such as when water currents or other forces cause the rig to pitch or yaw. However, the likelihood of snagging or other complications as equipment is displaced downwardly through the BOP and wellhead may be reduced by decreasing the rate of downward displacement or velocity of the drill string into the wellbore.
Accordingly, there remains a need in the art for systems and methods that allow for the safe and reliable installation of equipment below the water line of an offshore well system. It would be particularly advantageous if such systems and methods would provide accurate and precise indication of the proximity between the equipment to be installed below the water line and the corresponding equipment to be seated or landed against. Further, it would also be particularly advantageous if such systems and methods would provide an indication of or warning against the buckling of the drill or work string during the process of landing such equipment.

BRIEF SUMMARY OF THE DISCLOSURE

In an embodiment, a method for maneuvering a downhole tool in a well system comprises displacing at a first velocity a tool through a riser, detecting electromagnetic radiation from a source in real time using a detector coupled to the tool and altering the velocity of the tool from the first velocity to a second velocity in response to detecting the electromagnetic radiation. In an embodiment, the electromagnetic radiation comprises gamma rays. In an embodiment, the source comprises radioactive material. In an embodiment, the electromagnetic radiation comprises radio waves. In an embodiment, the source comprises a radio-frequency identification tag. In an embodiment, the electromagnetic radiation comprises long wave magnetic signals. In an embodiment, the source comprises an acoustic source. In an embodiment, the second velocity is of a lesser magnitude than the first velocity. In an embodiment, the method for maneuvering a downhole tool further comprises physically engaging the tool with a component of the well system. In an embodiment, the method for maneuvering a downhole tool further comprises forming a closeable chamber by actuating a ram of a blowout preventer of the well system. In an embodiment, altering the velocity of the tool from a first velocity to a second velocity comprises altering the velocity of the tool at a vertical distance from a spool of the well system. In an embodiment, physically engaging the tool with the component of the well system comprises physically engaging the blowout preventer tool against the component of the well system at the second velocity. In an embodiment, altering the velocity of the tool between the first velocity and the second velocity comprises decelerating the tool at a substantially constant rate. In another embodiment, altering the velocity of the tool between the first velocity and the second velocity comprises decelerating the tool at a substantially constant rate, reducing the rate of deceleration of the tool, accelerating the tool at a substantially constant rate and reducing the rate of acceleration of the tool.
An embodiment of a method for maneuvering a downhole tool in a well system comprises displacing a tool through a riser at a first velocity, physically engaging the tool with a component of the well system, detecting in real time a compressive strain of a tubular coupled to the tool using a strain gauge and altering the velocity of the tool from the first velocity to a second velocity in response to detecting the compressive strain. In another embodiment, altering the velocity of the tool comprises reducing the velocity of the tool from the first velocity to zero relative to the component of the well system. In another embodiment the component of the well system comprises a wellhead spool. In another embodiment, a method for maneuvering a downhole tool may further comprise transmitting the detected compressive strain to a computer of the well system. In another embodiment physically engaging the tool with a component of the well system comprises forming a seal within a tubular member of the well system. In another embodiment altering the velocity of the tool comprises reducing the detected compressive strain of the tubular coupled to the tool. In another embodiment, a method for maneuvering a downhole tool may further comprise actuating a ram of a blowout preventer of the well system to form a closeable chamber within the tubular member. In another embodiment, the strain gauge is disposed on the surface of a node coupled to the tool. In another embodiment, detecting a compressive strain of a tubular coupled to the tool comprises deforming the strain gauge. In another embodiment, a method for maneuvering a downhole tool may further comprise calculating a stress of the tubular coupled to the tool using the detected compressive strain.
Embodiments described herein comprise a combination of features and characteristics intended to address various shortcomings associated with certain prior devices, systems, and methods. The various features and characteristics described above, as well as others, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the exemplary embodiments of the invention disclosed herein, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic view of an embodiment of a well system in accordance with principles described herein;

FIGS. 2A-2D are perspective views, some in cross-section, showing components of the downhole electromagnetic network shown in FIG. 1;

FIG. 3 is an enlarged schematic view of an embodiment of a well system including an embodiment of a subsea tool landing system in accordance with principles described herein;

FIG. 4 is a chart illustrating a velocity profile of components of the well system of FIG. 3;

FIG. 5 is an enlarged schematic view of an embodiment of a well system including an embodiment of a subsea tool landing system in accordance with principles described herein;

FIG. 6 is a schematic view of an embodiment of a downhole maneuvering and installation system in accordance with principles described herein;

FIGS. 7A and 7B are schematic views of another embodiment of a downhole maneuvering and installation system in accordance with principles described herein; and

FIG. 8 is a chart illustrating a velocity profile of components of a downhole maneuvering and installation system.

DETAILED DESCRIPTION

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a given axis (e.g., given axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the given axis. For instance, an axial distance refers to a distance measured along or parallel to the given axis, and a radial distance means a distance measured perpendicular to the given axis. Still further, as used herein, the phrase “communication coupler” refers to a device or structure that communicates a signal across the respective ends of two adjacent tubular members, such as the threaded box/pin ends of adjacent pipe joints; and the phrase “wired drill pipe” or “WDP” refers to one or more tubular members, including drill pipe, drill collars, casing, tubing, subs, and other conduits, that are configured for use in a drill string and include a wired link. As used herein, the phrase “wired link” refers to a pathway that is at least partially wired along or through a WDP joint for conducting signals, and “communication link” refers to a plurality of communicatively-connected tubular members, such as interconnected WDP joints for conducting signals over a distance.
A system and method for landing subsea equipment in an offshore well system is disclosed herein. Embodiments described herein may be employed in various well drilling and production applications; however, it has particular application as a system for installing subsea tools in anticipation of performing a pressure test of pressure containing components of the well system. For instance, embodiments described herein may be employed in maneuvering downhole tools (e.g., BOP test plugs, casing hangers, packers, whipstocks, seal assemblies, etc.) in a well system. Further, it has particular application with regard to subsea well drilling and production systems.
Referring now to FIG. 1, an offshore well drilling system 10 generally includes an offshore semi-submersible drilling rig 20 disposed at the water line 12 with a deck 22 having a derrick 24 disposed thereon. System 10 further includes a fluid containment system (40), a riser 30 that extends between the rig 20 and a wellhead 60 and BOP 41 disposed at the sea floor 14, a drill string 50 disposed within a marine riser 30 and having a central axis 55. Well system 10 further includes casing 70 disposed about a wellbore 62 and extends downward from a wellhead spool 61 of wellhead 60 and is secured in place via cement 72.
A mud pit 25, a cement unit 27 and a fluid conduit 28 are disposed on floor 22 and are configured to provide a supply of drilling or testing fluid to the drill string 50. Conduit 28 provides a fluid flowpath for the passage of drilling fluid from mud pit 25 to drill string 50 while cement unit 27 is configured to pressurize and pump the fluid along the flowpath. In the embodiment illustrated in FIG. 1, cement unit 27 comprises a high pressure, reciprocating triplex pump. However, in other embodiments cement unit 27 may comprise other components configured to pressurize a fluid. Testing fluid 29 comprises a high density and weight fluid (e.g., drilling fluid, SOBM, completion fluid, etc.) relative to the ambient water 13 disposed below water line 12.
An annulus 35 is formed between drill string 50 and riser 30 and allows for the recirculation of drilling fluid between rig 20 and wellbore 62 that extends into subterranean formation 16 from the sea floor 14. FCS 40 generally includes components configured to retain and manage fluid pressure within well system 10 (e.g., drill string 50, FCS 40 and annulus 35). In the embodiment of well system 10, FCS 40 includes, among other components, BOP 41, choke line 44, kill line 46 and an internal blowout preventer (IBOP) 48. Rams 42 of BOP 41 are configured to provide an annular seal (not shown) about drill string 50 upon actuation, dividing annulus 35 into a first or upper section extending between rig 20 and the seal and a second or middle section extending from the annular seal downward to a FCS testing plug 49 coupled to drill string 50. Tool 49 and the annular seal provided by the BOP 41 may be used to form a closeable chamber within well system 10.
Well system 10 further includes a choke line 44 and a kill line 46, where lines 44 and 46 each provide an individual conduit between rig 20 and the BOP 41. During a formation kick, high pressure fluid from the formation may be circulated upward through choke line 44 to the rig 20, in an effort to regulate or meter the flow of formation fluid into annulus 35 such that fluid pressure within FCS 40 may stabilize. Choke line 44 generally includes a lower valve 44 a, a manifold 44 b and an upper valve 44 c. Fluid flow through choke line 44 may be restricted by closing lower valve 44 a or upper valve 44 c. Further, choke manifold 44 b includes a plurality of valves, chokes and other equipment, and as such is configured to manage and regulate flow through choke line 44. Because successful control of a formation kick may depend on the effective operation of choke line 44 and its components, valves 44 a, 44 c and manifold 44 b are individually pressure tested during the pressure testing of FCS 40.
Kill line 46 is also used to manage a formation kick by allowing for circulation between annulus 35 and rig 20. For instance, kill line 46 is used as a route of fluid communication to pump high density drilling mud or other fluid downward from rig 20 to the annulus 35 to forcibly maintain the fluid from the formation kick within the wellbore 62. Thus, a kill line such as kill line 46 may be used to “kill” the well by reversing, stopping or at least substantially restricting the flow of fluid from the formation into the wellbore 62 by pumping heavy fluid into annulus 35 from the rig 20. Kill line 46 comprises a lower valve 46 a, a kill manifold 46 b and an upper valve 46 c. As with choke line 44, flow through kill line 46 may be substantially restricted or controlled via valves 46 a, 46 c and manifold 46 b. Thus, during pressure testing of FCS 40, valves 46 a, 46 c and manifold 46 b are pressure tested as well.
Well system 10 also includes IBOP 48, which is disposed at an upper end 50 a of drill string 50 at the rig 20 and is configured to manage fluid pressure within drill string 50. For instance, during a formation kick, high pressure formation fluid may begin flowing upward through string 50 via an opening or port of the string 50 disposed within wellbore 62 (e.g., at the drill bit). For instance, IBOP 48 includes a valve that allows for the passage of fluid into string 50 but prevents or at least substantially restricts fluid from flowing out of string 50 through IBOP 48 in the event of an uncontrolled influx of fluid from the formation into well system 10. Thus, because IBOP 48 may be used in effectively controlling a formation kick, IBOP 48 is pressure tested during the pressure testing of FCS 40.
Referring now to FIGS. 1 and 2A-2D, drill string 50 comprises a plurality of nodes 51 coupled between a plurality of tubular joints 52. Wired or networked drill pipe incorporating distributed sensors can transmit data from anywhere along the drill string 50 to the rig 20 for analysis. Nodes 51 are provided at desired intervals along the drill string 50. Network nodes 51 essentially function as signal repeaters to regenerate and/or boost data signals and mitigate signal attenuation as data is transmitted up and down the drill string. The nodes 51 may also include measurement assemblies. The nodes 51 may be integrated into an existing section of drill string or a downhole tool along the drill string 50. For purposes of this disclosure, the term “sensors” is understood to comprise sources (to emit/transmit energy/signals), receivers (to receive/detect energy/signals), and transducers (to operate as either source/receiver). Tubular joints 52 include a first pipe end 53 having, for example, a first induction coil 53 a and a second pipe end 54 having, for example, a second induction coil 54 a.
Nodes 51 comprise a portion of a wired pipe communication network 56 that provides an electromagnetic signal path that is used to transmit information along the drill string 50. The communication network 56, or broadband network telemetry, may thus include multiple nodes 51 based along the drill string 50. Communication links or wired conductors 52 a may be used to connect the nodes 51 to one another, and may comprise cables or other transmission media integrated directly into sections of the drill string 50. The cable may be routed through the central borehole of the drill string 50, or routed externally to the drill string 50, or mounted within a groove, slot or passageway in the drill string 50. Signals from the plurality of sensors of nodes 51 along the drill string 50 are transmitted to rig 20 through wire conductors 52 a along the drill string 50. Communication links 52 a between the nodes 51 may also use wireless connections. A plurality of packets may be used to transmit information along the nodes 51. Further detail with respect to suitable nodes, a network, and data packets are disclosed in U.S. Pat. No. 7,207,396 (Hall et al., 2007), hereby incorporated in its entirety by reference. Various types of sensors 57 may be employed along the drill string 50 in various embodiments, including without limitation, axially spaced pressure sensors, temperature sensors, electromagnetic radiation sensors, and others. The sensors 57 may be disposed on the nodes 51 positioned along the drill string, disposed on tools incorporated into the drill string, or a combination thereof. Thus, sensors 57 of nodes 51 may measure temperature, pressure, etc., of fluid within string 50 or annulus 35 of well system 10.
Network nodes 51 are disposed along the drill string 50 between joints 52. In some embodiments, the booster assemblies are spaced at 1,500 ft. (500 m) intervals to boost the data signal as it travels the length of the drill string 50 to prevent signal degradation. Network nodes 51 are also located at these intervals to allow measurements to be taken along the length of the drill string 50. The distributed network nodes 51 provide measurements that give the driller additional insight into what is happening along the potentially miles-long stretch of the drill string 50.
Rig 20 includes a well site computer 58 that may display information for the drilling operator. The communication network 56 transmits information from each of a plurality of sensors 57 to a surface computer 58. Information may also be transmitted from computer 58 to another computer 59, located at a site remote from the well, with this computer 59 allowing an individual in the office remote from the well to review the data output by the sensors 57. Although only a few sensors 57 are shown in the figures, those skilled in the art will understand that a larger number of sensors may be disposed along a drill string (e.g., drill string 50) when drilling, and that all sensors associated with any particular node may be housed within or annexed to the node 51, so that a variety of sensors rather than a single sensor will be associated with that particular node.
Due to the risk of losing control of well system 10 (i.e., the uncontrolled flow of formation fluid into well system 10) caused by an uncontrolled wellbore influx of fluid from the formation, it is important to detect the influx as soon as possible. In some circumstances, a BOP (e.g., BOP 41) of the FCS (e.g., FCS 40) is actuated to close off the well above the wellbore influx. In some cases, for example in deepwater wells, the wellbore influx may migrate above the BOP before a ram of the BOP fully closes to seal off the wellbore. In the embodiments disclosed herein, the communication network 56 allows wellsite personnel to identify potential remedial actions for the migrated wellbore influx. In some embodiments, the measurements used are independent from surface measurements.
Referring now to FIG. 3, a well system 300, similar to well system 10 (like components numbered alike), includes a downhole positioning or maneuvering system 301 and downhole BOP testing tool or plug 49, which is disposed within riser 30 and coupled to drill string 50. A lower portion 50 b of string 50 extends from plug 49 into wellbore 62 while an upper portion 50 c extends between tool 49 and end 50 a. However, in other embodiments tool 49 may be another type of downhole tool, such as casing liners, packers, whipstocks and the like. Tool 49 is installed within string 50 of the well system 300 via lowering the tool 49 from the rig 20 axially downward through riser 30 and landing a lower annular surface 49 a of tool 49 against an upper annular surface 61 a of wellhead spool 61. Tool 49 and drill string 50 are displaced through riser 30 at a predetermined velocity (e.g., 30 feet/minute until annular surface 49 a of tool 49 has reached a vertical proximal distance 49 b from the annular surface 61 a of wellhead spool 61. In the embodiment shown in FIG. 3, the proximal distance 49 b is 10 feet. However, in other embodiments the proximal distance 49 b may vary according to the needs of the present application. For instance, the proximal distance may vary depending on rig heave, the accuracy of the positional measurements, the delicacy of the equipment being displaced downhole and the importance of minimizing the risk of damage to the displaced equipment (e.g., the cost of replacing the equipment if damaged, will damaging the equipment jeopardize the integrity of the well system, etc.). The velocity at which tool 49 and string 50 are displaced axially downward through riser 30 toward wellhead spool 61 may lead to a collision between tool 49 and spool 61, and thus the velocity of the downward displacement of tool 49 and string 50 may be substantially reduced upon reaching proximal distance 49 b.
Riser 30 may extend over thousands of feet between wellhead 60 and the rig 20, making it difficult for a drilling operator to precisely determine when surface 49 a of tool 49 has reached the proximal distance 49 b from surface 61 a of wellhead spool 61. For instance, a drilling rig may have a strain gauge attached to an uppermost joint of the drill string, where the gauge measures a tensile load applied to the gauge from the weight of the drill string. Once the BOP testing tool has landed on the spool, the amount of tensile load measured by the strain gauge decreases substantially, indicating that the BOP tool has landed on the wellhead spool and thus the downward axial displacement of the drill string may be ceased. However, this method may lack precision and thus may lead to damaging components of the well system due to a collision between the BOP testing tool and the wellhead spool and/or buckling of the drill string prior to the cessation of downward axial displacement. Thus, the possibility of a drilling operator inaccurately estimating the position of tool 49 downhole within riser 30 is heightened, increasing the risk of a collision between tool 49 and spool 61. Further, other types of downhole tools (e.g., casing liners, bushings, whipstocks, etc.) may also be beneficial to slow the rate of downward displacement of the downhole tool as it passes through the BOP and/or wellhead in order to avoid damaging any of the subsea equipment.
Referring now to FIGS. 1 and 3, in an embodiment, well systems 10 and 300 further includes maneuvering system 301, which is configured to allow for accurate estimation of the position of BOP testing tool 49 within riser 30 as annular surface 49 a reaches the proximal distance 49 b from annular surface 61 a of wellhead spool 61. Maneuvering system 301 generally includes a source 305 coupled to the BOP 41 and a node 51 a coupled to the upper portion 50 c of drill string 50. Alternatively, source 305 may be coupled to riser 30 or other components of well system 300. Source 305 is configured to emit a substantially continuous stream of electromagnetic radiation 315.
In the embodiment of FIG. 3, source 305 is configured to emit a stream of gamma rays via a radioactive material contained within source 305. In this embodiment, source 305 at least partially comprises Caesium-137. However, other embodiments of source 305 may comprise other materials suited for the production of gamma rays. Also, in other embodiments source 305 may be configured to emit a form of electromagnetic radiation other than gamma rays. For instance, in an embodiment, source 305 may comprise a radio-frequency identification (RFID) tag configured to emit a stream of radio-frequency electromagnetic radiation (i.e., radio waves). In an embodiment, source 305 may comprise a RuBee wireless tag configured to emit long wave (LW) magnetic signals. In yet another embodiment, source 305 may comprise an acoustic transmitter such as an underwater beacon configured to emit an ultrasonic pulse.
Referring still to FIG. 3, node 51 a includes a gamma ray detector 320 configured to receive the substantially continuous stream of electromagnetic radiation 315 emitted from source 305. Detector 320 of node 51 a includes a scintillation counter having a sodium iodide crystal that illuminates or flashes in response to being struck by a gamma ray. Each flash of the crystal is converted to an electrical pulse that is counted, with more counts per second (cps) corresponding to a higher intensity of gamma ray radiation being received by node 51 a.
Detector 320 has a vertical resolution of approximately 12 inches at a logging speed (i.e., speed of the drill pipe as it is displaced downhole) of 1,800 feet/hour (ft/hr). In the embodiment shown in FIG. 3, detector 320 comprises the Platform Express Integrated Wireline Logging Tool provided by Schlumberger Oilfield Services, 1325 S Dairy Ashford St. Houston, Tex., 77077. However, in other embodiments detector 320 may comprise other detectors having vertical resolutions that vary from 10 inches at a logging speed of 1,800 ft/hr (e.g., less than or greater than 12 inches). Thus, the cps measured by detector 320 will remain substantially constant when the vertical distance between detector 320 and source 35 is approximately at least 10 inches. However, the cps measurement of detector 320 rapidly increases and reaches a zenith once detector 320 and source 315 are disposed within a vertical distance of approximately 36 inches of each other. Further, the vertical resolution of detector 320 may vary with respect to logging speed, with a greater logging speed resulting in a correspondingly less precise vertical resolution.
Having received the radiation 315, an electromagnetic signal corresponding to the received radiation 315 is transmitted from detector 320 to the rig 20 along drill string 50 via communication network 56. However, in another embodiment, an electromagnetic signal corresponding to the received radiation 315 may be transmitted to the rig 20 wirelessly via low frequency electromagnetic waves propagated from node 51 a and transmitted through the formation 16 to the rig 20. In this embodiment, node 51 a may comprise the Blackstar™ Electromagnetic-Measurement while Drilling tool provided by National Oilwell Varco, 7909 Parkwood Circle Dr. Houston, Tex. 77036.
As tool 49 and drill string 50 that includes 51 a are displaced downward through riser 30, tool 49 approaches spool 61 and node 51 a approaches source 305. The cps reading (i.e., gamma ray intensity) from node 51 a remains substantially stable until the vertical distance between source 305 and detector 320 of node 51 a decreases to a distance equal to or less than 36 inches, the vertical resolution of detector 320. Once the cps measured by detector 320 has substantially increased, the velocity at which tool 49 and string 50 is displaced axially downward within riser 30 may be decreased, as surface 49 a of tool 49 is within proximal distance 49 b plus or minus 36 inches (i.e., the vertical resolution of detector 320). The velocity of tool 49 and string 50 is decreased to a velocity suitable for landing surface 49 a of tool 49 against surface 61 a of spool 61 without substantially risking the damage of components of the landing system 301 or the well system 300. In the embodiment of FIG. 3, the velocity of the downward axial displacement of tool 49 and drill string 50 is gradually decreased to zero.
For instance, now referring now to FIGS. 3 and 4, chart 350 displays the downward vertical velocity of testing tool 49 versus distance (i.e., distance to wellhead 60). Prior to decelerating, testing tool 49 is displaced downward from rig 20, it moves at a relatively constant velocity 351. Once detector 320 receives radiation 315 from source 305, and a corresponding signal is communicated to rig 20 via network 56, drill string 50 and tool 49 begin to decelerate at point 352 with regard to the downward vertical direction (i.e., in the direction of wellhead 60). The rate of deceleration of tool 49 continues to increase at 354 until stabilizing at point 355. The rate of deceleration is stabilized at point 355 once the velocity of tool 49 reaches 80% of its velocity at 351 (1,800 ft/hr). However, this point may be varied (e.g., between 50%-90%) depending upon the fragility of tool 49 and conditions at rig 20 (e.g., amount of heave at the rig, etc.). At 356 the velocity of string 50 and tool 49 decreases linearly until the velocity has decreased to 20% of the velocity at 351, shown at point 357 on chart 350. As with point 355, the point at which the rate of deceleration begins to decrease at 357 may be varied (e.g., between 10%-40%), depending upon the application. At 358 the downward velocity of tool 49 continues to decline until finally reaching zero at the wellhead. In this manner, the velocity, and thus the momentum of drill string 50 and tool 49, may be gradually decreased in a manner to minimize the amount of impulse or impact transmitted to string 50 as tool 49 is landed onto wellhead spool 61. Further, because deceleration is gradually increased at 354 and then gradually decreased at 358, the transition between 100% velocity at 351 and 0 at the wellhead will minimize any jarring due to acceleration/deceleration or other forces on string 50 and its associated components. Also, while the tripping speed in the embodiment of FIG. 8 is 1,800 ft/hr, this rate may vary dramatically between different applications.
Referring now to FIG. 5, a well system 400, similar to well system 10 (similar components numbered alike) includes anti-buckling system 401 configured to prevent or substantially reduce the likelihood of the buckling of drill string 50 during landing or installation of the BOP testing tool 49 against the wellhead spool 61. Anti-buckling system 401 comprises a node 405 (similar to nodes 51) coupled to the upper portion 50 c of the drill string 50. Node 405 includes a strain gauge 410 configured to continuously measure tensile and compressive loads applied to node 405. As BOP testing tool 49 lands on wellhead spool 61, weight of the drill string 50 is applied to wellhead spool 61. Specifically, the weight of drill string 50 as BOP tool 49 engages spool 61 results in a compressive load applied against both upper annular surface 61 a of wellhead spool 61 and lower annular surface 49 a of BOP testing tool 49. Drill string 50 may extend axially for thousands of feet, and thus drill string 50 may weigh multiple tons. The compressive load applied against surface 49 a of tool 49 is transferred axially upward in the direction of arrow 415 through the drill string, passing through joints 52 and node 410. A substantial compressive load applied to drill string 50 may result in the buckling of string 50, where portions of drill string 50 may be damaged due to excessive strain and deformation resulting from the compressive load applied to drill string 50 by spool 61. The amount of stress is reduced as it is transferred axially upward through drill string 50 by the straining and flexing of joints 52 and other components of string 50 that are subjected to the compressive stress. Thus, because upper portion 50 c of string 50 extends approximately between 500-1,000 feet between rig 20 and spool 61, strain gauge measurements taken at the rig 20 only indicate a decreasing tension load, and not the intensity of the compressive stress imparted to the portion of the drill string 50 proximal to BOP tool 49. Node 405, including strain gauge 410, is disposed a proximal vertical distance 420 from BOP testing tool 49. In this embodiment, the vertical distance 420 is 30 feet. Strain gauge 410, disposed proximately to tool 49, is configured to receive a compressive stress substantially approximate to the maximum compressive stress imparted to upper portion 50 c of drill string 50 due to physical engagement between tool 49 and spool 61.
Strain gauge 410 is coupled to a surface of node 405 and generally comprises an insulating flexible backing that supports a metallic foil pattern or circuit having a resistance that is configured to proportionally fluctuate in response to deformation of the circuit. The pattern of the circuit of gauge 410 forms a zigzag pattern that is oriented to be parallel with central axis 55 of drill string 50, thus sensitizing the circuit of gauge 410 to axial stress imparted to the drill string 50 at node 405. The change of resistance of the circuit of gauge 410 is measured using a Wheatstone bridge. An electrical signal transmitted from strain gauge 410 may be communicated to the rig 20 via node 405 and other components of the communication network 56. Node 405 also contains electrical components configured to condition the electrical signal (e.g., amplifiers, etc.) from strain gauge 410 prior to transmitting the signal to the rig 20. Alternatively, strain gauge 410 may be other forms of strain gauges known in the art. Thus, strain gauge 410 and communication network 56 are configured to allow for the continuous measurement and real time observation of axial stresses imparted to drill string 50 at the node 405 that is a vertical distance 420 (30 feet) from BOP testing tool 49. The proximity between strain gauge 410 of node 405 and BOP testing tool 49 allows for the measurement of an axial stress that is substantially near the maximum amount of axial stress imparted to a portion or component of the drill string 50. A compressive stress within node 405 may be calculated using the measured strain from gauge 410 and the Young's modulus of the material forming node 405.
As BOP testing tool 49 and drill string 50 are lowered downward within riser 30 as part of installing tool 49, measurements from strain gauge 410 may be continuously observed at the rig 20. Once lower annular surface 49 a of tool 49 and upper annular surface 61 a of wellhead spool 61 have physically contacted, a compressive strain will be imparted to upper portion 50 c of drill string 50 and strain gauge 410. The velocity of the downward displacement of tool 49 and string 50 may be reduced to zero by a drilling operator at the rig 20 in response to the observation of an increase in axial strain measured by strain gauge 410 at node 405. Thus, in this manner, the risk of applying an axial stress to drill string 50 capable of damaging and/or inducing buckling in drill string 50 is reduced via an early warning of strain within a portion of drill string 50 proximal to tool 49.
Referring now to FIGS. 3 and 5, the anti-buckling system 401 of FIG. 5 may be used in conjunction with the maneuvering system 301 of FIG. 3 in the same well system (e.g., well system 10 of FIG. 1). In this embodiment, maneuvering system 301 may be used to reduce the velocity of BOP testing tool 49 and drill string 50 prior to the point where tool 49 engages wellhead spool 61 (e.g., when tool 49 is at a proximal distance 49 b from spool 61). At some point after the velocity of tool 49 has been reduced, tool 49 physically engages spool 61. The engagement between tool 49 and spool 61 may be monitored at rig 20 (FIG. 1) via strain measurements taken by gauge 410 and transmitted to rig 20 and computers 58, 59, via network 56. Once an increase in measured strain by gauge 410 is observed, downward axial displacement of tool 49 and string 50 is ceased, preventing or at least substantially reducing the risk of damaging drill string 50 due to an overwhelming compressive stress applied to string 50.
Referring now to FIG. 6, a well system 500, similar to well system 10 (like components numbered alike), includes positioning or maneuvering system 501, an upper source 305 a, a lower source 305 b, detector 320 coupled to the drill string 50 and a bottomhole assembly 502 disposed at a terminal end 50 d of string 50. While this embodiment of system 500 is described as having a bottom hole assembly 502, other embodiments of maneuvering and installation systems may include a variety of components that are displaced from an offshore rig into a wellbore. For instance, in other embodiments the maneuvering system may allow for the maneuvering or installation of liners, lower completions, whipstocks or other downhole tools. Also, while system 501 includes two sources, 305 a and 305 b, other embodiments of maneuvering and installation systems may use varying numbers of sources 305, depending on the needs of the particular application (e.g., fragility of the tools being displaced downhole, relative movement between the wellhead and the rig, etc.).
In this embodiment, lower source 305 b is disposed at a vertical distance of 501 a from upper source 305 b. Distance 501 a is greater than the vertical length 501 b of the wellhead 60 and BOP 41 between the sea floor 14 and upper end 41 a of BOP 41. Also, distance 501 a is similar or substantially the same as the distance 501 c between end 50 d of string 50 and the detector 320 of node 51 a. Thus, in this configuration, as assembly 502 is displaced downwardly through annulus 35 towards wellhead 60, the detector 320 approaches and passes upper source 305 a, at which point it detects radiation 315. Having detected radiation 315, detector 320 transmits a first signal to the rig 20 via communication network 56, signaling the position of assembly 502 within riser 30. Once rig 20 has received the first signal from detector 320, the rate of downward displacement or velocity of string 50 may be gradually decreased, in order to reduce the velocity of assembly 502 as it travels through BOP 41 and wellhead 60 to minimize the risk of snagging or colliding with BOP 41 or wellhead 60.
String 50 and assembly 502 are continually displaced downwardly towards wellbore 62 at a reduced velocity until detector passes by lower source 305 b, receives radiation 315 and transmits a second signal to rig 20 via network 56. At this point, the rate of displacement into wellbore 62 may be increased to the original velocity as bottomhole assembly will have travelled below wellhead 60 and into wellbore 62. This is true because the vertical length of distances 501 a and 501 c are substantially the same and both are greater in length than the total vertical length of the combination of wellhead 60 and BOP 41.
Referring now to FIGS. 7A and 7B, a well system 600, similar to well system 10 (like components numbered alike) includes a positioning or maneuvering system 601, source 305 configured to emit electromagnetic radiation, bottom hole assembly 502 a, a first or lower detector 320 a of node 51 a and a second or upper detector 320 b of a node 51 b (FIG. 7B). Lower detector 320 a is disposed proximal to assembly 502 a on string 50 while upper detector 502 b is disposed at a vertical distance 601 a (FIG. 7B) from lower detector 502 a. Vertical distance 601 a is at least equal to or greater than the sum of length 501 b (total length of wellhead 60 and BOP 41) and the length of assembly 502. Thus, as configured, when upper detector 502 b is at a similar vertical depth as source 305 (as shown in FIG. 7B), the entire length of assembly 502 will be disposed below wellhead 60 and BOP 41.
In operation, as assembly 502 is displaced downwardly towards wellbore 62, lower detector 320 a passes by source 305 (FIG. 7A) and receives radiation 315, causing detector 320 a to transmit a first signal to the rig 20 via network 56. Upon receipt of the first signal, the rate of downward displacement or velocity of string 50 and assembly 502 towards wellbore 62 is gradually reduced as assembly 502 enters BOP 41, reducing the likelihood of assembly 502 colliding with BOP 41 or wellhead 60. Assembly 502 is then displaced at a new reduced velocity through BOP 41 and wellhead 60 as it enters wellbore 62. Once assembly 502 has exited wellhead 60 and completely entered wellbore 62, upper detector 320 b passes by source 305 and receives radiation 315. At this point, detector 320 b transmits a second signal to the rig 20, indicating that assembly 502 has entirely passed vertically through both BOP 41 and wellhead 60, and thus the rate of downward displacement of string 50 may be gradually increased without incurring a risk of colliding assembly 502 with BOP 41 or wellhead 60.
Referring now to FIG. 8, chart 150 illustrates a velocity profile of assembly 502 as it descends from rig 20 through BOP 41 and wellhead 60 and into wellbore 62. The bottom hole assembly 502 descends through the riser 30 at 100% velocity (1,800 ft/hour) at 151, but upon receiving the first signal from a detector coupled to string 50 at point 152, the velocity of assembly 502 begins to gradually decrease along 153 until bottoming at point 154, with the velocity of assembly 502 at 20% of its velocity at 151 (i.e., prior to deceleration Upon reaching the minimum velocity point 154, the velocity is linearly increased (i.e., assembly 502 is accelerated) along 155 until reassuming substantially 100% velocity at point 156, corresponding to the point where the entire length of assembly 502 has been displaced below BOP 41 and wellhead 60. At this point, the velocity may remain constant at 157 as assembly 502 is displaced farther into wellhead 62. Also, while the tripping speed in the embodiment of FIG. 8 is 1,800 ft/hr, this rate may vary dramatically between different applications.
While in this embodiment, the deceleration of assembly 502 is ceased at reaching 20%, this value may vary (e.g., between 10%-50%) depending on the application. For instance, in well systems with high amounts of relative movement between the wellhead and the rig due to water currents and other forces, or in situations where the tools being displaced into the wellbore are highly sensitive or fragile, it may be beneficial to reduce the velocity below 20%. However, in applications where there is less relative movement or the assembly is less fragile, it may be beneficial to follow the velocity profile of chart 160, which includes a greater bottom velocity (40% of prior velocity) and a lesser deceleration/acceleration along 163 and 165, as compared with the amount of deceleration along 153 and acceleration along 155.
While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

Claims

What is claimed is:

1. A method for maneuvering a downhole tool in a well system comprising:

displacing at a first velocity a tool through a riser;

detecting electromagnetic radiation from a source in real time using a detector coupled to the tool; and

altering the velocity of the tool from the first velocity to a second velocity in response to detecting the electromagnetic radiation.

2. The method of claim 1, wherein the electromagnetic radiation comprises gamma rays.

3. The method of claim 2, wherein the source comprises radioactive material.

4. The method of claim 1, wherein the electromagnetic radiation comprises radio waves.

5. The method of claim 4, wherein the source comprises a radio-frequency identification tag.

6. The method of claim 1, wherein the electromagnetic radiation comprises long wave magnetic signals.

7. The method of claim 6, wherein the source comprises an acoustic source

8. The method of claim 1, wherein the second velocity is of a lesser magnitude than the first velocity.

9. The method of claim 1, further comprising physically engaging the tool with a component of the well system.

10. The method of claim 9, further comprising forming a closeable chamber by actuating a ram of a blowout preventer of the well system.

11. The method of claim 1, wherein altering the velocity of the tool from a first velocity to a second velocity comprises altering the velocity of the tool at a vertical distance from a spool of the well system.

12. The method of claim 9, wherein physically engaging the tool with the component of the well system comprises physically engaging the blowout preventer tool against the component of the well system at the second velocity.

13. The method of claim 1, wherein altering the velocity of the tool between the first velocity and the second velocity comprises decelerating the tool at a substantially constant rate.

14. The method of claim 1, wherein altering the velocity of the tool between the first velocity and the second velocity comprises:

decelerating the tool at a substantially constant rate;

reducing the rate of deceleration of the tool;

accelerating the tool at a substantially constant rate; and

reducing the rate of acceleration of the tool.

15. A method for maneuvering a downhole tool in a well system comprising:

displacing a tool through a riser at a first velocity;

physically engaging the tool with a component of the well system;

detecting in real time a compressive strain of a tubular coupled to the tool using a strain gauge; and

altering the velocity of the tool from the first velocity to a second velocity in response to detecting the compressive strain.

16. The method of claim 13, wherein altering the velocity of the tool comprises reducing the velocity of the tool from the first velocity to zero relative to the component of the well system.

17. The method of claim 15, wherein the component of the well system comprises a wellhead spool.

18. The method of claim 15, further comprising transmitting the detected compressive strain to a computer of the well system.

19. The method of claim 16, wherein physically engaging the tool with a component of the well system comprises forming a seal within a tubular member of the well system.

20. The method of claim 17, wherein altering the velocity of the tool comprises reducing the detected compressive strain of the tubular coupled to the tool.

21. The method of claim 19, further comprising actuating a ram of a blowout preventer of the well system to form a closeable chamber within the tubular member.

22. The method of claim 15, wherein the strain gauge is disposed on the surface of a node coupled to the tool.

23. The method of claim 15, wherein detecting a compressive strain of a tubular coupled to the tool comprises deforming the strain gauge.

24. The method of claim 15, further comprising calculating a stress of the tubular coupled to the tool using the detected compressive strain.