1. Field of the Invention
Embodiments of the present invention generally relate to remote operation of a cementing head.
2. Description of the Related Art
A wellbore is formed to access hydrocarbon bearing formations, e.g., crude oil and/or natural gas, by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a tubular string, such as a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
It is common to employ more than one string of casing in a wellbore. In this respect, the well is drilled to a first designated depth with a drill bit on a drill string. The drill string is removed. A first string of casing is then run into the wellbore and set in the drilled out portion of the wellbore, and cement is circulated into the annulus behind the casing string. Next, the well is drilled to a second designated depth, and a second string of casing or liner, is run into the drilled out portion of the wellbore. If the second string is a liner string, the liner is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The liner string may then be fixed, or “hung” off of the existing casing by the use of slips that utilize slip members and cones to frictionally affix the new string of liner in the wellbore. The second casing or liner string is then cemented. This process is typically repeated with additional casing or liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing/liner of an ever-decreasing diameter.
Cementing operations have involved the use of plugs as a way of correctly positioning the cement when setting the casing. Some mechanisms have employed the use of pressure or vacuum to initiate plug movement downhole for proper displacement of the cement to its appropriate location for securing the casing properly. In addition, confirmation of the plug movement was by line-of sight (e.g., flag at the cementing head indicating ball drop). The early designs were manual operations so that when it was time to release a plug for the cementing operation, a lever was manually operated to accomplish the dropping of the plug. This created several problems because the plug-dropping head would not always be within easy access of the rig floor. Frequently, depending upon the configuration of the particular well being drilled, the dropping head could be as much as 100 feet or more in the derrick (i.e., 100 feet from the rig floor). In order to properly actuate the plug to drop, rig personnel would have to go up on some lift mechanism to reach the manual handle. This process would have to be repeated if the plug-dropping head had facilities for dropping more than one plug. In those instances, each time another plug was to be dropped, the operator of the handle would have to be hoisted to the proper elevation for the operation. In situations involving foul weather, such as high winds or low visibility, the manual operation had numerous safety risks.
Hydraulic systems involving a stationary control panel mounted on the rig floor, with the ability to remotely operate valves in conjunction with cementing plugs, have also been used in the past. Some of the drawbacks of such systems are that for unusual applications where the plug-dropping head turned out to be a substantial distance from the rig floor, the hoses provided with the hydraulic system would not be long enough to reach the control panel meant to be mounted on the rig floor. Instead, in order to make the hoses deal with these unusual placement situations, the actual control panel itself had to be hoisted off the rig floor. This, of course, defeated the whole purpose of remote operation. Additionally, the portions of the dropping head to which the hydraulic lines were connected would necessarily have to remain stationary. This proved somewhat undesirable to operators who wanted the flexibility to continue rotation as well as up or down movements during the cementing operation.
Accordingly, what is needed are techniques and apparatus for remotely operating the cementing head.
One embodiment of the present invention provides a method. The method generally includes exchanging signals between a first device and a second device via a medium in connection with the cementing head, wherein the second device is adjacent to the cementing head, and performing cementing head operations corresponding to the exchanged signals.
Another embodiment of the present invention is a system. The system generally includes a first device located at a rig floor of the wellbore, a second device located adjacent to the cementing head, and a control unit for remotely operating the cementing head. The control unit is typically configured to exchange signals between the first device and the second device via a medium in connection with the cementing head and perform cementing head operations corresponding to the exchanged signals.
So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
After a first section of a wellbore 116 has been drilled, an outer casing string 119o may be installed in the wellbore 116 and cemented 111o in place. The outer casing string 119o may isolate a fluid bearing formation, such as aquifer 130a, from further drilling and later production. Alternatively, fluid bearing formation 130a may instead be hydrocarbon bearing and may have been previously produced to depletion or ignored due to lack of adequate capacity. After a second section of the wellbore 116 has been drilled, an inner casing string 119i may be installed in the wellbore 116 and cemented 111i in place. The inner casing string 119i may be perforated and hydrocarbon bearing formation 130b may be produced, such as by installation of production tubing (not shown) and a production packer.
The casing string 119o may be run into the wellbore 116 with a guide shoe 212. A float collar 210 may be located one to four joints above the guide shoe 212, wherein the float collar 210 may function as a back flow valve that may prevent the heavier cement slurry 204 from flowing back into the casing string 119o after the slurry has been placed into the annulus between the outside of the casing string 119o and the borehole wall. Centralizers 208 may be placed along the length of the casing string 119o, wherein the centralizers 208 may ensure that the casing string 119o is nearly centered in the borehole, thus allowing a more uniform distribution of cement slurry flow around the casing string 119o. This nearly uniform flow around the casing may be necessary to remove drilling mud in the annulus and provide an effective seal.
The casing string 119o may be lowered into the drilling mud in the wellbore 116 using the rig drawworks 124 and elevators. The displaced drilling mud may flow to the mud tanks 120 and be stored there for later use. Once the entire casing string 119o is in place in the wellbore 116, the casing string 119o may be left hanging in the elevators through the cementing operation. This may allow the casing string 119o to be reciprocated (i.e., moved up and down) and possibly rotated as the cement is placed in the annulus. This movement may assist the removal of the drilling mud. While the casing string 119o is hanging in the elevators, a cementing head 202 may be placed along an upper end of the workstring 102.
The cementing head 202 may be connected with flow lines that come from, for example, a pump truck 214. A blender 216 may mix dry cement and additives with water. A cement pump on the pump truck 214 may pump cement slurry 204 to the cementing head 202, which will eventually form the cementing 111o. For some embodiments, a preflush or spacer may initially be pumped ahead of the cement slurry 204, wherein the spacer may be preceded by a bottom wiper plug 206. The spacer may be used to assist in removing the drilling mud from the annular space between the outside of the casing string 119o and the borehole wall.
Cementing operations have involved the use of plugs as a way of correctly positioning the cement when setting the casing. Some mechanisms have employed the use of pressure or vacuum to initiate plug movement downhole for proper displacement of the cement to its appropriate location for securing the casing properly. Traditionally, when it was time to release a plug for the cementing operation, manual operations and hydraulic systems have been involved in operating valves in conjunction with the cementing plugs. However, manual operations and operations involving hydraulic systems, as described above, may become infeasible when the cementing head could be over 100 feet above the rig floor. This may prove somewhat undesirable to operators who want the flexibility to continue rotation as well as up or down movements (e.g., of the top drive 142) during the cementing operation. Accordingly, what is needed are techniques and apparatus for remotely operating the cementing head while continuing rotation as well as up or down movements.
For some embodiments, the system 300 may be a single-wire line transmission system, wherein the cementing head 202 may be used as the conductor, while both ends of the system 300 use a common path for the return current (e.g., earth return). For example, the cementing head 202 may be connected on the upper side to ground through the top drive (or grounded to the derricks ground). In addition, the lower side of the system 300, for example, below the lower device 304, may be connected to ground through slips, which make electrical contact with the mechanical rig structure, ensuring another path to earth's ground.
The signals received by the upper device 302 may be processed by the local control unit 3082 (dedicated microcontroller) and actuate operations of the cementing head 202 (e.g., dropping plugs, darts, tool activation, and/or confirmation devices—such as balls, RFID tags, etc.—into the wellbore). The signals may be acoustic or electromagnetic (EM) signals. For some embodiments, when the signals transmitted by the lower device 304 are acoustic signals (e.g., transmitted by a piezoelectric stack or a solenoid), the upper device 302 may include piezoelectric sensors (e.g., accelerometer) for detecting acoustic vibrations generated along an acoustic throughpipe (e.g., workstring 102). For acoustic signals, the devices 302, 304 may be in physical contact with the medium (e.g., rigid contact with workstring 102). However, for EM signals, the devices 302, 304 may not be in physical contact with the workstring 102, allowing the workstring to rotate as well during a cementing job. Although
When the signals exchanged between the devices 302, 304 are EM signals, the devices 302, 304 may include toroidal coils, as will be discussed further herein. Various parameters of the toroidal coils may be adjusted, such as the coil size, magnetic core permeability, wire size, and the number of windings. More specifically, each device 302, 304 may include two toroidal coils: one for transmitting and another for receiving. A transmission between the devices 302, 304 may be achieved by energizing the winding of a transmission coil (e.g., the transmitting toroidal coil of the lower device 304). As described above, the transmission may be initiated by the handheld device. The current that flows through the winding may produce a magnetic flux in the core, which than induces a current in a conductor positioned in the center of the toroid (e.g., workstring 102), which can represent various signals. The current generated has to be high enough to overcome potential noise, yet low enough to conserve power. If a string of voltage pulses is applied to the coil, a corresponding string of current pulses may be induced in the workstring 102.
The transmission may be received at the upper device 302 (e.g., by the receiving toroidal coil of the upper device 302) by converting the current pulses flowing through the workstring 102 into voltage pulses. Confirmation of the operation may be indicated by a signal transmitted from the upper device 302 to the lower device 304. The handheld device may receive an indication of the confirmation. For some embodiments, multiple confirmations may be received. For example, acknowledgment of receipt of the command transmitted from the lower device 304 may be received. As another example, successful execution of the command or an error may be indicated on the handheld device, which can lead to the ability to troubleshoot the issue.
For some embodiments, each device 302, 304 may include a single toroidal coil with a first winding for transmitting signals, and a second winding for receiving signals, wherein the windings may have different configurations. Examples of configurations that may differ between the windings generally include a different number of windings and a different diameter of wiring for the winding. The receiver may require increased sensitivity to compensate for noise that may be received (signal-to-noise ratio (SNR)).
The toroidal coils 610, 612 may be formed by latching the partial toroidal coil sections 614, 616 that are mounted on the frame by a latching mechanism 606. The hinged frame 602 may have to be along a certain diameter of the tubular member (e.g., workstring 102) to properly latch. For some embodiments, the hinged frame 602 may comprise stands 618 for moving the frame along the workstring 102 until an outer diameter of the workstring 102 causes the partial toroidal coil sections 614, 616 to properly latch and form the toroidal coils 610, 612. The hinged frame 602 may further comprise centering guides (e.g., rollers) for centralizing the frame around the workstring 102. For example, in order to ensure concentricity of the toroidal coils 610, 612 around the workstring 102, a set of four equally spaced rollers 608 may be utilized in order to maintain a preset gap between the coils 610, 612 and the workstring 102, as illustrated in
As described above, activation of the retainer valve for the bottom wiper plug 702 may be initiated by transmitting a signal via a lower toroidal coil 706 located on the rig floor (or at the cement pump or a convenient location) through a medium (e.g., workstring 102) in connection with the cementing head 202. Control electronics associated with the upper toroidal coil 708, located adjacent to the cementing head 202, may receive and decode the signal, then activate the retainer valve for releasing the bottom wiper plug 702. For some embodiments, activating the retainer valve may involve utilizing compressed gas (e.g., air, nitrogen, etc.) to control the retainer valve.
Upon transmitting the signal via the lower toroidal coil 706, an operator (e.g., located on the rig floor and/or at the pump truck) may receive several confirmations. For example, the operator may receive a first confirmation indicating that the upper toroidal coil 708 has received and decoded the signal transmitted by the lower toroidal coil 706. Further, the operator may receive a second confirmation indicating that the retainer valve for the bottom wiper plug 702 has been activated. Moreover, the operator may receive a third confirmation indicating that the bottom wiper plug 702 has actually been released after the retainer valve has been activated. For example, a proximity sensor 710 may be used for indicating that the bottom wiper plug 702 has been released (as indicated by the downward arrow in
When a predetermined volume of cement slurry has passed through the cementing head 202, the retainer valve for the top wiper plug 704 may be activated, releasing the top wiper plug 704 into the flow to the well (not illustrate). Activation of the retainer valve for the top wiper plug 704 and the confirmations may be performed as described above. For some embodiments, parameters of the signal transmitted by the lower toroidal coil 706 (e.g., frequency) may be modified in accordance with the fluid traveling through the medium (e.g., workstring 102).
Remote Operation of Cementing Head for Subsea Operations
Referring to
The cementing head 820 may have an upper set of toroidal coils 832 located adjacent to the cementing head 820. The upper set of toroidal coils 832 may receive signals from a lower set of toroidal coils 830 located on the deck 826 of the vessel 824, wherein the lower set of toroidal coils 830 may transmit the signals through a medium in connection with the cementing head 820. The signals received by the upper set of toroidal coils 832 may actuate operations of the cementing head 820 (e.g., dropping darts). For some embodiments, the lower set of toroidal coils 830 may be attached to or wrapped around a metal pipe (e.g., drill pipe 802) and may transmit signals through the metal pipe (i.e., a metal pipe in connection with the upper set of toroidal coils 832 attached to the cementing head 820). The signals may be acoustic or electromagnetic signals, as described above.
When spacer fluid and cement slurry are ready to be pumped to the inside of the drill pipe 802 through the cementing head 202 (and eventually into the well casing 819), a retainer valve for a bottom wiper dart may be activated. This bottom wiper dart may keep drilling fluid from contaminating the spacer fluid and the cement slurry while they pass through the inside of the drill pipe 802.
Activation of the retainer valve for the bottom wiper dart may be initiated by transmitting a signal via the lower set of toroidal coils 830 located on the deck 826 through the drill pipe 802 in connection with the cementing head 820. The upper set of toroidal coils 832, located adjacent to the cementing head 820, may receive and decode the signal, then activate the retainer valve for releasing the bottom wiper dart. For some embodiments, activating the retainer valve may involve utilizing compressed gas to control the retainer valve. After the bottom wiper dart has been released, confirmation of the release may be indicated to an operator on the deck 826. For some embodiments, one or more proximity sensors that detect when the bottom wiper dart has been released may trigger on a light to notify the operator that the bottom wiper dart has been released. In addition, the operator may be notified in other ways, as described above.
When a predetermined volume of cement slurry has passed through the cementing head 820, a retainer valve for a top wiper dart may be activated, releasing the top wiper dart into the flow to the well 836. Activation of the retainer valve for the top wiper dart and confirmation of the release may be performed as described above. For some embodiments, parameters of the signal transmitted by the lower set of toroidal coils 830 (e.g., frequency) may be modified in accordance with the fluid traveling through the medium (e.g., drill pipe 802).
After a dart has been dropped into the well 836, and seated into a corresponding plug, confirmation of the location of the dart and plug in the well 836 may be useful in determining successful operation of the cementing head 820 using any of the above-described methods. For example, it may be useful to determine whether the bottom wiper dart and corresponding plug has reached a pre-defined location, such a float collar (e.g., by a pressure sensor or load cell). For some embodiments, a first signal may be transmitted through the well casing 819 up to the floor 816 of the sea. A device 806 may receive the first signal and transmit a second signal 808 up to the surface 822 of the sea using sonar or an acoustic modem.
Due to transmitting between multiple mediums (e.g., seawater and within the wellbore), coupling of the first signal with the second signal may be required for successfully determining whether the bottom wiper dart and plug have reached the pre-defined location. For some embodiments, the second signal may be transmitted by a remotely operated vehicle (ROV) that is plugged in at a convenient location (e.g., at the blowout preventer or wellhead 804). For some embodiments, a buoy 810 may receive the second signal 808 transmitted through the sea 818 and transmit a signal via a transmission line 812 to a receiver located on the deck 826. The receiver located on the deck 826 may process the signal to confirm the location of the dart and corresponding plug. For some embodiments, the direction of signal transmission between the buoy 810 and the device 806 may be downwards when a signal is transmitted from the vessel 824 to the well 836.
While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
This application claims benefit of U.S. Provisional Patent Application Ser. No. 61/413,233, filed Nov. 12, 2010, and Ser. No. 61/491,755, filed May 31, 2011, which are herein incorporated by reference.
Filing Document | Filing Date | Country | Kind | 371c Date |
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PCT/US11/60460 | 11/11/2011 | WO | 00 | 7/22/2013 |
Number | Date | Country | |
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61413233 | Nov 2010 | US | |
61491755 | May 2011 | US |