Patent Grant
12024955
None.
Not applicable.
Not applicable.
A production string typically comprises tubing that is run into the casing of an oil and gas well and is used to transfer wellbore fluids to and from the surface. Additionally, the production string may have conduits for supplying power, communication, or treatment fluids to downhole tools. The conduits may deliver control fluids for communication to direct downhole tools, hydraulic power to actuate downhole tools, or injection fluids to downhole formations via downhole tools. Further, the production string may have conduits containing conductors (e.g., wires) that communicate electrical signals to and from downhole instrumentation and devices. These conduits can be external to the production string or downhole tools with some portions transitioning to an internal pathway. At other points, the conduits may pass downward through the downhole tools or be connected by fittings to ports, channels or small diameter bores within the well tubulars or tools.
During the lifecycle of the production well, it can be desirable or necessary to break a connection in a production string in order to permit a portion of the production string to be withdrawn from the wellbore while another portion of the string remains installed below the surface. For example, it may be necessary to break a connection in a production string during a workover operation and reconnect the production string after a wellbore servicing operation.
For a more complete understanding of the present disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.
It should be understood at the outset that although illustrative implementations of one or more embodiments are illustrated below, the disclosed systems and methods may be implemented using any number of techniques, whether currently known or not yet in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, but may be modified within the scope of the appended claims along with their full scope of equivalents.
An electrical wet connect tool, also referred to as a disconnect tool, can be part of a production string configured to produce fluids from or inject fluids into a subterranean formation. The production string generally comprises a tubular string extending from the surface to a target location, e.g., a production zone, in a wellbore. The electrical wet connect tool. e.g., disconnect tool, can include a disconnect mandrel, a disconnect receptacle, and at least one electrical connection. The disconnect mandrel can be a generally cylindrical shape with a concentric resilient electrical contact, e.g. a male connector. The disconnect receptacle can be a generally cylindrical shape with a concentric ring connector, e.g., a female connector. The disconnect mandrel can be inserted into the disconnect receptacle such that the disconnect mandrel is concentric with the disconnect receptacle and mate the concentric electrical connection, for example, connect the male connector with the female connector. A wellbore servicing operation may require the disconnect mandrel and the disconnect receptacle to be connected, i.e. mated, and disconnected multiple times, for example, when replacing equipment such as the safety valve or electrical submersible pumps in the upper completion. Wellbore fluids can be trapped within the concentric electrical connection each time the disconnect mandrel is inserted into the disconnect receptacle. These trapped wellbore fluids can reduce the insulation resistance between the electrical contacts and the wellbore environment, promote corrosion, and prevent a reliable transfer of high voltage power to downhole tools located below the disconnect receptacle. A method of improving and preserving the insulation resistance of the electrical connection is desirable.
One solution for improving the insulation resistance of the electrical contacts can include the removal of wellbore fluid from the electrical contacts. In some embodiments, the concentric electrical contacts can form a chamber with connector seals when the disconnect mandrel is inserted into the receptacle. A small volume of wellbore fluids can be trapped within the chamber between the seals. The concentric electrical contacts can include at least one port for the trapped volume of wellbore fluids to exit. In some embodiments, a fluid flow path can be formed from a volume of flushing fluid to the concentric electrical contacts, through the chamber formed by the seals, and out the exit port. The wellbore fluids can be flushed out the concentric electrical connection with a flushing fluid via the fluid flow path. In some embodiments, the flushing fluid can insulate the electrical connection and provide corrosion protection by replacing the potentially conductive and corrosive fluids. In some embodiments, the volume of flushing fluid passed through the fluid flow path can remove particles and debris from the trapped volume.
Another solution for improving the insulation resistance of the electrical contacts can include the ability to disconnect and reconnect multiple times. In some scenarios, the wellbore servicing operations can include disconnecting and reconnecting the electrical connection, for example, to replace equipment in the upper completion, such as the safety valve. In some embodiments, the disconnect mandrel can have more than one volume of flushing fluid to circulate through the fluid flow path. Wellbore fluids can be flushed out of the electrical connection more than one time to allow for multiple connections. In some embodiments, the disconnect tool can include at least one electrical connection and at least one hydraulic connection. The disconnect tool can include multiple electrical connections and multiple hydraulic connections to pass communication, power, and control from one or more tools above the disconnect tool to one or more tools below the disconnect tool. The insertion of the disconnect mandrel into the disconnect receptacle can couple the multiple electrical connections and multiple hydraulic connections. In some embodiments, the disconnect mandrel can be coupled to an upper portion of a production string and the disconnect receptacle can be coupled to a lower portion of the production string. In some embodiments, the disconnect receptacle can be coupled to the upper portion of a production string and the disconnect mandrel can be coupled to the lower portion of the production string.
In an embodiment, the disconnect tool for connecting at least one electrical connection can include a scalable concentric resilient electrical connector, an exit port within the concentric resilient electrical connector, a volume of flushing fluid, and a fluid flow path. The fluid flow path can include the volume of flushing fluid, a pathway through the disconnect mandrel, at least one port into the concentric resilient electrical connector, and a second pathway through the disconnect mandrel or the disconnect receptacle. In addition, a trigger device can be coupled to the volume of flushing fluid to discharge a volume of flushing fluid into the fluid flow path in response to a triggering event.
Turning now to
The wellbore environment 100 may include servicing rig 102 arranged at the Earth's surface 104 and coupled to the wellbore 106. The servicing rig 102 may comprise a drilling rig, a work-over rig, a service rig, a coil tubing rig, or similar wellbore servicing equipment that supports a workstring 130. It is understood that mechanical mechanisms known to those in the arts can control the run-in and withdrawal of the workstring 130 in the wellbore 106, for example, a draw works coupled to a hoisting apparatus, another servicing vehicle, a coiled tubing unit, and/or other lifting apparatus.
Although
In some embodiments, the servicing rig 102 may be a workover rig and the wellhead 116 can include a pressure containment device. The servicing rig 102 and associated servicing equipment may be used to stimulate and otherwise prepare the wellbore 106 and surrounding subterranean formation 108 for the production of hydrocarbons therefrom. The wellhead 116 can comprise a production tree, a surface tree, a subsea tree, a lubricator connector, a blowout preventer, or combinations thereof and may be configured for the production of hydrocarbons from the wellbore 106.
The servicing rig 102 may support or otherwise help manipulate the axial position of a workstring 130 extending into the wellbore 106. In some embodiments, the workstring 130 may include, but not be limited to, one or more types of connected lengths of drill pipe, casing tubular, production tubing, landing string, liners, coiled tubing, or combinations thereof. The workstring 130 can be generally tubular in shape with an inner bore 126, e.g., a flow bore. As illustrated in
The lower completion 112 may comprise one or more downhole devices 138 coupled to the tubular 136. The downhole device 138 can isolate the wellbore environment, provide flow control, measure wellbore properties, or combinations thereof. In some embodiments, the downhole device 138 can form a seal between an outer surface of the tubular 136 and an inner surface of the lateral wellbore 128. For example, the downhole device 138 may comprise a packer. In some embodiments, the downhole device 138 can control the flow of wellbore fluids into an inner passage 142 of the tubular 136 from the subterranean formation 108. For example, the downhole device 138 may comprise a production sleeve configured to open, meter or choke, and/or shut off the flow of fluids. In some embodiments, the downhole device 138 can provide periodic measurements of the wellbore environment with sensors. For example, the downhole device 138 can include sensors to measure pressure, temperature, fluid density, fluid flowrate, position, or combinations thereof. The lower completion 112 may comprise at least two downhole devices 138 spaced axially along the lower completion 112, for example, the downhole devices 138A, 138B, and 138C. In some embodiments, the downhole devices 138 may comprise sensors to measure the wellbore environment (e.g., pressure, temperature, density, flowrate), pumps, packers, gauges, valves, chokes, and other devices used to monitor and control operations performed in the wellbore. Although three downhole devices 138 are shown, it is understood that there may be 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of downhole devices 138.
A control system 144 may control various aspects of the operations performed in the wellbore. The control system 144 can be a computer system configured to control various aspects of the operation of the wellbore environment 100. In some embodiments, the control system 144 can be electrically coupled to downhole devices 138 via conductor conduits and/or hydraulic conduits coupled to the outside of or routed within the tubulars 136. Two or more structures can pass signal communication, electrical power, or both when they are electrically coupled or electrically connected. Although the control system 144 is illustrated as located at the surface 104, it is understood that the control system 144 can be located on the rig 102, on the sea floor, within the wellbore 106, or combinations thereof.
The wellbore environment 100 includes an electric disconnect tool 114. In some embodiments, the electric disconnect tool 114 can be located between an upper completion 110 and a lower completion 112 of the wellbore completion. The electric disconnect tool 114 can comprise an upper portion 146 coupled to the upper completion 110 and a lower portion 148 coupled to the lower completion 112. The electric disconnect tool 114 can have a connected configuration wherein the upper portion 146 is coupled to the lower portion 148 allowing for the production of wellbore fluids, or injection of fluids to stimulate other wells, through an interior bore of the electrical disconnect tool 114 and electrical connections and hydraulic connections can be maintained through the electric disconnect tool 114. The connected configuration of the electric disconnect tool 114 can fluidically connect the inner passage 142 of the lower completion 112 to the inner bore 126 of the upper completion 110. The electric disconnect tool 114 can have a disconnected configuration wherein the upper portion 146 coupled to the upper completion 110 can be separated from the lower portion 148 of the electric disconnect tool 114. For example, a production tool 132 within the upper completion 110 may need to be replaced and/or repaired. In a scenario, the manipulation of the upper completion 110 by the rig 102 can disconnect the upper portion 146 coupled to the upper completion 110 from the lower portion 148 coupled to the lower completion 112. The upper completion 110 can be removed from the wellbore 106 while the lower portion 148 remains in the wellbore 106 coupled to the lower completion 112. The servicing operation can remove the upper completion 110 without damaging the upper portion 146 and lower portion 148 of the electrical disconnect tool 114. As will be further described in detail below, the upper portion 146 of the electrical disconnect tool 114 can be conveyed into the wellbore 106 coupled to the upper completion 110 (the same or a different upper completion) to be inserted (or reinserted) into an lower portion 148 coupled to the lower completion 112 and establish (or reestablish) electrical and/or hydraulic connection between the upper portion 146 and lower portion 148 of the electrical disconnect tool 114.
Turning now to
The locator sub 202 is a generally cylindrical shape with an inner bore also referred to as a flow bore 206. The locator sub 202 comprises a locator ring 214, a resilient connector 216, and at least one seal 218 on the body 212. In some embodiments, the locator ring 214 can position the locator sub 202 within the receptacle sub 204 by contacting a mating surface. The locator ring 214 can be positioned above the resilient connector 216 (e.g., towards the surface 104) of the locator sub 202. The resilient connector 216 can be a ring or band of conductive material surrounded by isolation material located on the body 212 or located in a groove on the body 212. The resilient connector 216 can be electrically coupled to a first conductor housed within an electrical conduit 222 as will be described further herein. The flow bore 206 of the locator sub 202 can be fluidically connect to the inner bore 126 of the workstring 130 as shown in
In some embodiments, the locator sub 202 can include a latch mechanism 220. The latch mechanism 220 can include a set of collet fingers with a latch head 224. In some embodiments, the latch mechanism 220 can be configured with a set of collet fingers with a cantilever collet or a dual collet. In some embodiments, the latch mechanism 220 can be configured with a smooth anchor head or with a threaded latch head 224. In some embodiments, the latch mechanism 220 can be configured with a release feature to maintain the latch mechanism 220 is a locked position. For example, the latch mechanism 220 can remain in the locked position until the release feature is moved to the release position.
In some embodiments, the locator sub 202 can comprise a first hydraulic port 226 located on the body 212 between two seals 218. For example, a first hydraulic port 226 can be located between a first seal 218A and a second seal 218B. The first seal 218A and second seal 218B can be a portion of the seal array. The first hydraulic port 226 can be fluidically connected to a first hydraulic conduit 228 via a drilled passageway as will be described further herein. The hydraulic conduit 228 can be fluidically coupled to a volume of fluid, e.g., hydraulic fluid, at the surface 104. Although one hydraulic port 226 is shown, it is understood that the locator sub 202 can have any number of hydraulic ports 226 and associated hydraulic conduits 228.
Turning now to
In some embodiments, the receptacle sub 204 can comprise a second hydraulic port 252 within a groove 254 in the housing 242. The first hydraulic port 226 in the locator sub 202 can align with the second hydraulic port 252 in the receptacle sub 204 or locate within the groove 254 in the receptacle sub 204 in response to the locator ring 214 contacting the locator shoulder 230. The second hydraulic port 252 can be fluidically connected to a second hydraulic conduit 260 via a fitting. Although the second hydraulic conduit 260 is shown proximate to the outer surface 232 of the receptacle sub 204, it is understood that this location of the second hydraulic conduit 260 is illustrative for clarity and the second hydraulic port 252 may connect with a drilled passageway, the second hydraulic conduit 260 may be placed within a passageway, the hydraulic conduit may be placed with a groove, or combinations thereof. Although one hydraulic port 252 is shown, it is understood that the hydraulic ports 252 of the receptacle sub 204 align with the hydraulic ports 226 of the locator sub 202, thus the receptacle sub 204 can have the same number of ports as the locator sub 202.
In some embodiments, the receptacle sub 204 can include a latch profile 262 within the inner surface of the housing 242. The latch profile 262 can mate with or likewise engage the latch head 224 of the latch mechanism 220 on the locator sub 202. In some embodiments, the latch profile 262 comprises a plurality of grooves and/or a threaded profile to mate with a threaded profile of the latch head 224. The latch profile 262 can be located above the locator shoulder 230 to align with the latch head 224 of the locator sub 202 when the locator ring 214 contacts the locator shoulder 230. In some embodiments, the latch profile 262 can be located below ring connector 234. For example, the latch profile 262 can be located below the bore 210.
During servicing operations conducted on the rig 102 from
Turning now to
A second fluid pathway 314 can be fluidically connected to the resilient connector 216. The second fluid pathway 314 can be formed by a fluid conduit, an axial passageway, a radial passageway 338, or combinations thereof. The second fluid pathway 314 can be fluidically connected to the annulus, the tubing, a hydraulic conduit, or a receiving chamber. In some embodiments, the second fluid pathway 314 can be coupled to a port fluidically coupled to the annulus, e.g., the space located between the workstring 130 and the casing string 118. In some embodiments, the second fluid pathway 314 can be coupled to a port fluidically coupled to the inside of the tubing, e.g., the inner bore 126 of the workstring 130. In some embodiments, the second fluid pathway 314 can be coupled to a hydraulic conduit, e.g., hydraulic conduit 228, fluidically connected to a storage location, e.g., a storage tank, or a volume of fluid, e.g., flushing fluid, at surface 104. In some embodiments, a receiving chamber 344 can be fluidically connected to the resilient connector 216 via the second fluid pathway 314. The receiving chamber 344 can be a generally cylindrical with an outer surface 346 and an inner surface 348. The receiving chamber can include a second volume of flushing fluid labeled V2.
During the wellbore servicing operation, the locator sub 202 can be inserted into the receptacle sub 204 by manipulation of the workstring 130. A volume of flushing fluid, e.g., a first volume V1 or portion thereof, can be released from the fluid source 310 and can travel down the fluid pathway 312 to the resilient connector 216. In some embodiments, the radial passageway 332 is an annular flow path, for example, a groove or a space between an outer surface of a smaller cylinder (e.g., outer surface of the body 212), and an inner surface of the resilient connector 216. In some embodiments, the radial passageway 332 is a port formed during manufacturing, e.g., drilling operation. The first fluid pathway 312 can be sealingly and fluidically coupled to the entrance port 334 on the resilient connector 216. The volume V1 of fluid can exit the resilient connector 216 through the entrance port 334 and into the fluid chamber created by the resilient connector 216 and the ring connector 234 as will be described further herein. The volume V1 of flushing fluid can displace and/or replace trapped wellbore fluids by flowing the wellbore fluids out of the fluid chamber via an exit port 336, a second radial passageway 338, and a second fluid pathway 314. The exit port 336 on the resilient connector 216 can be sealingly and fluidically connected to the second fluid pathway 314. The radial passageway 338 may be a port, a groove, an annular space, a drill hole, or combinations thereof. The volume V1 of flushing fluid can flush or displace the trapped wellbore fluid from the fluid chamber, via the second fluid pathway 314, to the annulus, to the tubing, to the surface, or to the receiving chamber. In some embodiments, the volume V1 of flushing fluid can displace the trapped wellbore fluid to a port coupled to the annulus or the tubing. In some embodiments, the volume V1 of flushing fluid can displace the trapped wellbore fluid to the surface via a hydraulic control line.
In some embodiments, the volume V1 of flushing fluid can displace the trapped wellbore fluid and a volume of flushing fluid into a receiving chamber via the second fluid pathway 314. The receiving chamber can include a second volume V2 and a second balance piston 350 sealingly engaged with the inner surface 348 of the receiving chamber 344. The second balance piston 350 can displace axially along the inner surface 348 as the second volume V2 increases with the displaced wellbore fluid and a portion of the volume V1 of flushing fluid. In some embodiments, the receiving chamber 344 can include a flow control device or be coupled with a flow control device, for example, a check valve, a nozzle or an orifice (e.g., flow restrictor), a flow metering valve, a pressure relief valve, or combinations thereof.
The flushing fluid can be released or delivered from the fluid source 310 by a trigger mechanism 316. In some embodiments, the trigger mechanism 316 can include a fluid control device, a motive device, a communication device, or combinations thereof. For example, the trigger mechanism 316 can comprise a check valve (e.g., fluid control device), a fluid pump (e.g., motive device), and a transceiver (e.g., communication device). The servicing operation can activate the trigger mechanism 316 by communicating a signal from surface. For example, the service personnel can transmit power and commands via the electrical conduit 222 of
In an embodiment, the trigger mechanism 316 can comprise a controller with a hydraulic pump electrically coupled to the electric conduit 222. A signal comprising communication and power can be transmitted from surface 104 to the trigger mechanism 316. A fluid expansion device such as a balance piston, a bladder, a set of bellows, or combinations thereof can replace the motive device 318 to change the volume V1 of the fluid source 310 as the flushing fluid is pumped into the fluid pathway 312 by the fluid pump. The controller can direct the hydraulic pump within the trigger mechanism 316 to transfer flushing fluid into the fluid pathway 312. In some embodiments, the trigger mechanism can comprise a battery, a controller, an acoustic communication device, and a hydraulic pump. The controller can receive communication from an acoustic signal transmitted from surface to the acoustic communication device communicatively coupled to the controller.
In an embodiment, the trigger mechanism 316 can comprise a manifold and a motive device 318 supplying a volume of gas. For example, the motive device 318 can include a pressurized gas source, such as a compressed volume of gas (e.g., nitrogen) or a gas generator. The gas generator can be configured to produce gas from a chemical reaction (e.g., iron sulphate and hydrogen peroxide) or from combusting a fuel source (e.g., ignition of a pyrotechnic charge). A communication device communicatively coupled to a controller can receive a signal from the surface via acoustic signal or conductor within electric conduit 222 to open a valve on a manifold and/or initiate the gas generation. A volume of compressed gas can displace the volume V1 for flushing fluid from fluid source 310 into the fluid pathway 312.
In an embodiment, the motive device 318 can comprise a hydrostatic piston retained by a lock-out feature, e.g., a trigger mechanism 316. The hydrostatic piston can comprise a piston with a trapped volume of gas at atmospheric pressure, i.e., 1 bar. The hydrostatic piston can include a first piston area (i.e., cross-sectional area) exposed to wellbore pressures and a second piston area exposed to the atmospheric gas pressure. In some embodiments, the trapped volume of gas can be lower than atmospheric pressure by applying a vacuum to the trapped volume of gas. The lock-out feature. e.g., the trigger mechanism 316, can comprise a shear device, a locking mechanism, a balance chamber, or combinations thereof. The shear device of the lock-out feature can be a set of shear pins configured to shear at a predetermined value. For example, the shear device can break (e.g., shear) when the wellbore pressure reaches a pre-determined value. In some embodiments, the shear device can break when pressure is applied to the hydrostatic pressure inside the tubing pressure, e.g., inside the workstring 130, above a predetermined value. In some embodiments, the shear device can break when pressure is applied to the annulus, e.g., between the workstring 130 and the casing string 118, above a predetermined value. In some embodiments, a locking mechanism can be unlocked by a signal communicated from the surface to a controller via a communication device to actuate a valve or rupture a disk to expose the hydrostatic piston to wellbore fluid.
In some embodiments, the motive device 318 can be a balance piston, a locking mechanism, and a fluid pathway to the annulus or tubing. The balance piston can be exposed to the wellbore pressure of the annulus or inside the tubing via the fluid pathway. The locking mechanism can be a set of shear pins or rupture disk configured to break at a predetermined pressure value. In some embodiments, pressure applied to the tubing, e.g., inside the workstring 130 can break the locking mechanism and release the balance piston. In some embodiments, pressure applied to the annulus can break the locking mechanism and release the balance piston. The applied fluid pressure to the annulus or tubing can displace the balance piston and reduce the volume V1 of fluid as the flushing fluid transfers to the fluid pathway 312.
Although one fluid source 310 is illustrated, it is understood that the fluid flowpath 300 can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of fluid sources 310 fluidically coupled with at least one fluid pathway 312. Although one fluid pathway 312 is illustrated, it is understood that the fluid flowpath 300 can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of one fluid pathway 312 fluidically coupled with at least one resilient connector 216. Although one resilient connector 216 is illustrated, it is understood that the locator sub 202 can comprise any number of resilient connectors 216. Although one fluid flowpath 300 is illustrated, it is understood that the locator sub 202 can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of fluid flowpath 300 fluidically coupled with at least one fluid source 310. Although one resilient connector 216 with one fluid flowpath 300 is illustrated, it is understood that the locator sub 202 can have two or more resilient connector 216 fluidically connected to a corresponding fluid flowpath 300.
Turning now to
The fluid flowpath 360 can operate with a similar method of operation as the previously described fluid flowpath 300. A volume of flushing fluid, e.g., a first volume V1, can be released from the fluid source 310 by a trigger mechanism 316. The volume V1 can travel down the fluid pathway 362 to the ring connector 234. The volume V1 of fluid can exit the ring connector 234 through the entrance port 366 and into the fluid chamber created by the resilient connector 216 and the ring connector 234 as will be described further herein. As described, the fluid source 310 can be fluidically connected to the entrance port 366. The volume V1 of flushing fluid can displace and/or replace trapped wellbore fluids by flowing the wellbore fluids out of the fluid chamber via an exit port 370 and a second fluid pathway 374. The exit port 370 can be fluidically connected to the second fluid pathway 374. The volume V1 of flushing fluid can flush or displace the trapped wellbore fluid from the fluid chamber via the second fluid pathway 314. In some embodiments, the volume V1 of flushing fluid can displace the trapped wellbore fluid and a volume of flushing fluid into a receiving chamber 344 via the second fluid pathway 374.
In some embodiments, the locator sub 202 can include a first seal 218A, a hydraulic port 226, a second seal 218B, and a seal array 208 comprising a series of seals 218. The hydraulic port 226, fluidically connected to an electrical conduit 222, can form individual hydraulic passages between the first seal 218A and second seal 218B when the locator sub 202 is inserted into receptacle sub 204. Receptacle sub 204 may include at least one hydraulic port 252 that is positioned to align with hydraulic port 226 of the locator sub 202 when the locator sub 202 is fully inserted into the receptacle sub 204. The hydraulic passages and hydraulic ports 252 may be configured to form one or more fluidic connections between the locator sub 202 and the receptacle sub 204 when the locator sub 202 is fully inserted into the receptacle sub 204.
Although one fluid source 310 is illustrated, it is understood that the fluid flowpath 360 can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of fluid sources 310 fluidically coupled to at least one radial passageway 364. Although one radial passageway 364 is illustrated, it is understood that the fluid flowpath 360 can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of fluid pathway 312 fluidically coupled with at least one ring connector 234. Although one ring connector 234 is illustrated, it is understood that the receptacle sub 204 can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of ring connectors 234. Although one ring connector 234 with one fluid flowpath 360 is illustrated, it is understood that the receptacle can have two or more ring connectors 234 fluidically connected to at least one fluid flowpath 360. Although one fluid flowpath 360 is illustrated, it is understood that the receptacle sub 204 can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of fluid flowpath 360 fluidically coupled with at least one fluid source 310. Although one ring connector 234 with one fluid flowpath 360 is illustrated, it is understood that the receptacle sub 204 can have two or more ring connector 234 fluidically connected to a corresponding fluid flowpath 360.
In some embodiments, the locator sub 202 with a fluid source 310 and fluid flowpath 300 can be installed into a receptacle sub 204 with a fluid source 310 and fluid flowpath 360. For example, the locator sub 202 can include two or more resilient connectors 216 fluidically connected to at least one fluid source 310 via a fluid flowpath 300. In this example, the locator sub 202 can be installed into a receptacle sub 204 that includes two or more ring connectors 234 fluidically connected to at least one fluid source via a fluid flowpath 360. In some embodiments, the fluid flowpath 300 on the locator sub 202 can be connected to at least one resilient connector 216 and the fluid flowpath 360 on the receptacle sub 204 can be connected to a different ring connector 234 such that the fluid flowpath 300 flushes at least one electrical connection and the fluid flowpath 360 flushes at least one different electrical connection. In some embodiments, the fluid flowpath 300 on the locator sub 202 can be fluidically connected to at least one resilient connector 216 and the fluid flowpath 360 on the 22) receptacle sub 204 can be fluidically connected to a corresponding ring connector 234 such that the fluid flowpath 360 and fluid flowpath 300 can flush the same electrical connection.
As previously described, an electrical connection can be configured when the locator sub 202 is installed into the receptacle sub 204. The electrical connection can be formed when the resilient connector 216 on the locator sub 202 is sealingly and electrically coupled with the ring connector 234 of the receptacle sub 204. A set of seals on the resilient connector 216 can sealingly engage and form a fluid chamber with the outer surface of the ring connector 234. Turning now to
The ring connector 234 can include an outer surface 420, an inner surface 422, an end surface 468, a set of seals 424 within mating grooves, and a ring contact 428. The ring contact 428 can be electrically coupled to a conductor cable within a passage bore 432 by a threaded post 434 and cable termination 436. The cable termination 436 can be connected to the conductor cable 430 and include a threaded port. The conductor cable can be an embodiment of the conductor cable within the electric conduit 250. The threaded post 434 can electrically couple to the ring contact 428 and pass through a port 438 to threadingly couple to the cable termination 436. The set of seals 424 can sealingly engage an inner surface 446 of the groove 240 to isolate the passage bore 432 and port 438 from wellbore fluids.
The resilient connector 216 can be a generally cylinder shape with an outer surface 410, an inner surface 412, and an end surface 466. The resilient connector 216 can include a first isolation seal 414, a second isolation seal 416, and a resilient contact 418. A set of seals 440 within seal grooves 442 on the body 212 can sealingly engage the inner surface 412 of the resilient connector 216. A first set of passage seals 444 can sealingly engage the inner surface 412 to isolate the first radial passageway 332 from wellbore environment. A second set of passage seals 448 can sealingly engage the inner surface 412 to isolate the second radial passageway 338 from wellbore environment. The resilient connector 216 can be retained within the groove 330 by a locking ring 452 installed within a locking groove 454 on the body 212. Although the resilient contact 418 is not shown electrically coupled to a conductor cable, e.g., conductor cable within electrical conduit 222, it is understood that the resilient contact 418 can be electrically coupled with a similar set of connectors including a threaded post passing through a port to a cable termination electrically connected to a conductor cable within an electrical conduit. The connection of the conductor cable via a threaded post to the resilient contact 418 is not shown for clarity of the description of the fluid flow-path passing through the electrical connection in the mated configuration.
In some embodiments, a fluid chamber 402 can be formed when the resilient connector 216 on the locator sub 202 is mated with the ring connector 234 on the receptacle. The first isolation seal 414 and second isolation seal 416 can sealingly engage the inner surface 422 of the ring connector 234. The fluid chamber 402 can be formed by the first isolation seal 414, the inner surface 422 of the ring connector 234, the second isolation seal 416, and the outer surface 410 of the resilient connector 216. The resilient contact 418 can electrically connect to the ring contact 428 of the ring connector 234 to pass electrical power, signal communication, or both. The resilient contact 418 can be formed of a single cantilever arms or double cantilever arms of electrically conductive materials, e.g., a copper alloy. In some embodiments, the resilient contact 418 can be formed of a conductive wire wound in a helical shape, e.g., spring shape. The cantilevers arms can be formed with spaces or gaps between each cantilever arm for deflection of the cantilevers arms resulting in a spring stress state to provide a normal force against the mating connector. e.g., the ring contact 428. These spaces or gaps between each cantilever arm provides a flow path for the flushing fluid to pass through the fluid chamber 402.
As previously described, a volume of flushing fluid, e.g., a first volume V1, can be released from the fluid source 310 by a trigger mechanism 316 to travel down the fluid pathway 312 to the first radial passageway 332 of the resilient connector 216. The first radial passageway 332 can be sealingly and fluidically coupled by the passage seals 444 to the entrance port 334 on the resilient connector 216. The volume V1 of fluid can exit the resilient connector 216 through the entrance port 334 and into the fluid chamber 402 to displace and/or replace trapped wellbore fluids by flowing the wellbore fluids out of the fluid chamber 402 via an exit port 336, a second radial passageway 338, and a second fluid pathway 314. The exit port 336 on the resilient connector 216 can be sealingly and fluidically coupled with a passage seal 448 to the second radial passageway 338. In some embodiments, the volume V1 of flushing fluid can displace the trapped wellbore fluid and a volume of flushing fluid into a receiving chamber via the second fluid pathway 314. In some embodiments, a first flow control device 460, e.g., a check valve, can be coupled to the fluid pathway 312. In some embodiments, a second flow control device 462. e.g., a check valve, can be coupled to the second fluid pathway 314. Although
Although the entrance port 334 and exit port 336 are described as single port, it is understood that the resilient connector 216 can have 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, or any number of ports. For example, the resilient connector 216 can have 12 ports. e.g., entrance ports 334, equally distributed radially about the central axis. The resilient connector 216 can have the same number of entrance ports 334 and exit ports 336. In some embodiments, the resilient connector 216 has fewer exit ports 336 than entrance ports 334. In some embodiments, the total area of exit ports 336 is greater than the total area of entrance ports 334. For example, the exit ports 336 may be larger size than an equal number of entrance ports 334.
The fluid source 310 in
In some embodiments, the fluid source 500 can comprise a motive device 518 with a locking device 520. The motive device 518 can be a hydrostatic piston comprising knocker piston 526 and an activation chamber 514. The knocker piston 526 can be a generally cylinder shape with an outer surface 564, an inner surface 566, a front end surface 570, and a back end surface 572. The knocker piston 526 can include an outer seal 560 sealingly engaging an inner surface 558 of the housing 512. An inner seal 562 on the housing 512 can sealingly engage the outer surface 564 of the knocker piston 526. The activation chamber 514 can be bounded by the outer seal 560, the inner surface 558, the inner seal 562, and the outer surface 564. The activation chamber 514 can contain a volume of gas (e.g., air) above atmospheric pressure, at or near atmospheric pressure, or below atmospheric pressure. In some embodiments, the volume of gas may be pressurized above atmospheric pressure. For example, a trigger mechanism that activates with a predetermined hydrostatic pressure within the wellbore may require the activation chamber 514 to be pressurized to a designated value. In some embodiments, the activation chamber may be an atmospheric chamber with air at or near atmospheric pressure, i.e., 1 bar. In some embodiments, a vacuum port 574 can be utilized to lower the gas pressure below atmospheric pressure. The vacuum port 574 can be sealed with a suitable plug or flow control device.
In some embodiments, the locking device 520 can comprise a shearable device, for example, a shear pin. The locking device 520, e.g., shear pin, can be installed through a pin port 584 on the housing 512 and into a shear port 586 on the knocker piston 526. The shear port 586 can be a port, a groove, or any similar feature capable of receiving the shearable device. The locking device 520 can retain the knocker piston 526 in a first position, e.g., the run-in position. The locking device 520 can shear or break at a predetermined value.
The locator sub 202 of
The fluid source 500 can be activated with pressure applied to the annulus, e.g., the space between the casing string 118 and the upper completion 110, or with pressure applied down the bore of the tubing, e.g., workstring 130. In some embodiments, the fluid source 500 can be activated with pressure applied down the annulus by including a plug 582 sealing coupled with a port 580 on the mandrel 510 and a port 554 without a plug on the housing 512. In some embodiments, the fluid source 500 can be activated with pressure applied down the bore of the tubing, e.g., workstring 130, by including port 580 without a plug on the mandrel 510 and an sealingly coupling the plug 582 to the port 554 on the housing 512.
A triggering mechanism to retain the flushing fluid within a fluid source until activated can be located on another device or away from the fluid source. For example, the fluid source 500 was described with a triggering device within the fluid source 500. A triggering device can be located away from the fluid source. Turning now to
A fluid chamber 640 can be formed between the inner surface 638 and end surface 642 of the housing 612, the outer surface 622 of the mandrel 610 and a front end surface 670 of the knocker piston 616. The fluid chamber 640 can include a volume V1 of flushing fluid. The housing 612 can include a first port 652 to allow wellbore fluids into chamber formed between the seal 634 and the inner seal 662. The knocker piston 616 can have a back end surface 672 in contact with wellbore fluids via a second port 654 in the housing 612. The knocker piston 616 can apply wellbore pressure against an resultant force from the atmospheric chamber, to the volume V1 of flushing fluid in the fluid chamber 640. The conduit port 632 can fluidically connect the fluid chamber 540 to the fluid pathway 312 of
Turning now to
The operation of the locator with the fluid source 600 can now be described. The locator sub 202 with the triggering mechanism 390 of
The following are non-limiting, specific embodiments in accordance with the present disclosure.
A first embodiment, which is a downhole tool, comprising: an electrical disconnect tool 200 comprising a locator sub 202 and a receptacle sub 204, wherein the locator sub and receptacle sub engage to provide an electrical connection; a fluid source 310 in fluid communication via a fluid flowpath 300 with the electrical connection via the locator sub 202, the receptacle sub 204, or both; and a trigger mechanism 316 coupled to the fluid source 310, wherein upon activation of the trigger mechanism 316 a volume of flushing fluid is provided from the fluid source 310 to the locator sub 202, the receptacle sub 204, or both.
A second embodiment, which is the downhole tool of the first embodiment, wherein the locator sub and receptacle sub engage to provide a hydraulic connection.
A third embodiment, which is the downhole tool of the first or the second embodiment, wherein the locator sub and receptacle sub engage to provide a flow pathway for production fluids.
A fourth embodiment, which is the downhole tool of any of the first through the third embodiments, wherein the locator sub 202 comprises: a body 212 with a generally cylindrical shape and a flow bore; a conductor within an electrical conduit 222 electrically coupled to a control system 144; and a resilient connector 216 electrically coupled to the conductor.
A fifth embodiment, which is the downhole tool of the fourth embodiment, wherein the locator sub 202 further comprises: at least one seal 218 coupled to the body 212; and a hydraulic port 226 fluidically coupled to a hydraulic conduit 228.
A sixth embodiment, which is the downhole tool of any of the first through the fifth embodiments, wherein the receptacle sub 204 comprises: a housing 242 with a generally cylindrical shape with a bore 210; a conductor within an electrical conduit 250 electrically coupled to at least one downhole tool 138; and a ring connector 234 electrically coupled to the conductor.
A seventh embodiment, which is the downhole tool of the sixth embodiment wherein the receptacle sub 204 further comprises: a hydraulic port 252 fluidically connected to a hydraulic conduit 260.
An eighth embodiment, which is the downhole tool of any of the first through the seventh embodiments, wherein the fluid source 310 includes a volume of flushing fluid within a chamber 308.
A ninth embodiment, which is the downhole tool of any of the first through the eighth embodiments, wherein the trigger mechanism 316 comprises a motive device 318, a communication device, a fluid control device, or combinations thereof; wherein the motive device 318 comprises one selected from a group comprising i) spring, ii) a hydraulic pump, iii) a compressed volume of gas, iv) a hydrostatic piston, v) a motor driven extension piston, vi) a gas generator, vii) a balance piston with an annular port, or viii) a balance piston with a tubing port; wherein the fluid control device comprises i) a manifold, ii) a check valve, iii) an orifice, iv) a flow restrictor, v) a flow metering valve, vi) a pressure relief valve, or vii) combinations thereof; wherein the communication device comprises a controller, a signal transceiver, and a power source; and wherein the signal transceiver comprises a pressure transducer, an acoustic transceiver, a network communication card, or combinations thereof.
A tenth embodiment, which is the downhole tool of any of the first through the ninth embodiments, wherein the fluid flowpath 300 comprises a first fluid pathway 312, at least one entrance port 334, a flow chamber 402, at least one exit port 336, and wherein the flow chamber 402 is formed by the electrical connection in a mated configuration.
An eleventh embodiment, which is the downhole tool of any of the first through the tenth embodiments, wherein: the fluid source 500 comprises a fluid chamber 540 with the volume of flushing fluid; wherein the fluid chamber 540 is formed with a balance piston 516 movably and sealingly engaged with a housing 512; and wherein wellbore hydrostatic pressure is transferred to the volume of flushing fluid via a back end surface 548 of the balance piston 516.
A twelfth embodiment, which is the downhole tool of any of the first through the eleventh embodiments, wherein the trigger mechanism 518 comprises: a motive device 518 comprising an activation chamber 514 formed with a knocker piston 526 movably and sealingly engaged with a housing 512; and a locking device 520 comprising a shearable pin; wherein the knocker piston 526 produces an activation force in response to a pressure differential between wellbore hydrostatic pressure and a volume of gas within the activation chamber 514; wherein the locking device 520 is coupled to a pin port 584 in the housing 512 and a shear port 586 in the knocker piston 526; wherein the locking device 520 is configured to release the motive device 518 in response to the activation force exceeding a shear value of the locking device 520; and wherein the motive device 518 is configured to activate in response to release of the locking device 520.
A thirteenth embodiment, which is the downhole tool of any of the first through the twelfth embodiments, wherein the fluid source 600 comprises: a fluid chamber 640 with the volume of flushing fluid; and a motive device 618 comprising an activation chamber 614 formed with a knocker piston 616 movably and sealingly engaged with a housing 612; wherein the fluid chamber 640 is formed with the knocker piston 616 movably and sealingly engaged with a housing 612; wherein the motive device 618 produces an activation force in response to a pressure differential between wellbore hydrostatic pressure and a volume of gas below atmospheric pressure, at atmospheric pressure, or above atmospheric pressure within the activation chamber 614; and wherein the volume of flushing fluid is pressurized by the knocker piston 616 via the activation force.
A fourteenth embodiment, which is the downhole tool of any of the first through the thirteenth embodiments, wherein the trigger mechanism 390 comprises: an isolation sleeve 380 with a generally cylinder shape with an inner surface 384 movingly and sealingly engaged with a second isolation seal 416 and first isolation seal 414 on a connector 216; and a retaining spring 382 configured to bias the isolation sleeve 380 into a first configuration; wherein the first configuration retains the volume of flushing fluid within a fluid source 640; wherein a second configuration releases the volume of flushing fluid from the fluid source 640 into the fluid pathway 312; and wherein connection of the electrical connection via workstring manipulation displaces the isolation sleeve 380 from the first configuration to a second configuration.
A fifteenth embodiment, which is the downhole tool of any of the first through the fourteenth embodiments, wherein the flushing fluid comprises transformer oil, perfluoroalkanes, mineral oil, castor oil, silicone oil, hexane, or purified water.
A sixteenth embodiment, which is a method of connecting a downhole tool assembly, comprising: conveying a locator sub with at least one resilient connector into a wellbore coupled to a workstring, wherein the at least one resilient connector is electrically coupled to a control system; installing the locator sub into a receptacle sub with at least one ring connector 234 electrically coupled to a downhole device 138 and wherein the receptacle sub and at least one downhole device 138 are coupled to a tubular 136; connecting at least one electrical connection comprising the at least one resilient connector and the at least one ring connector; activating a triggering mechanism with a communication signal; and flushing the at least one electrical connection with a flushing fluid from a fluid source via a fluid flowpath in response to the triggering mechanism being activated.
A seventeenth embodiment, which is the method of the sixteenth embodiment, wherein: the resilient connector is electrically coupled to a conductor; wherein the conductor is electrically coupled to the control system; wherein the ring connector is electrically coupled to a conductor; wherein the conductor is electrically coupled to the at least one downhole device; and wherein the at least one electrical connection electrically couples the control system to the at least one downhole device.
An eighteenth embodiment, which is the method of the sixteenth or the seventeenth embodiment, wherein the communication signal is a pressure signal, an acoustic signal, an electronic signal, a positional signal, or combinations thereof.
A nineteenth embodiment, which is the method of any of the sixteenth through the eighteenth embodiments, further comprising: sealingly engaging a bore on the receptacle sub with two seals on the locator sub; fluidically coupling a first hydraulic port between the two seals on the locator sub and a second hydraulic port on the receptacle sub; and wherein a first hydraulic conduit coupled to the locator sub is fluidically coupled to a second hydraulic conduit coupled to the receptacle sub in response to the fluidic coupling of the first hydraulic port on the locator sub to the second hydraulic port on the receptacle sub.
A twentieth embodiment, which is a method of coupling an electrical connection in a wellbore, comprising: aligning a resilient connector with a ring connector; forming a flushing chamber by sealingly engaging an inner surface of the ring connector with a first isolation seal and a second isolation seal of the resilient connector; contacting a plate contact with a resilient contact, wherein the resilient connector is electrically connected to the ring connector by the plate contact; and flushing the flushing chamber with a volume of flushing fluid in response to a communication signal.
A twenty-first embodiment, which is the method of the twentieth embodiment, further comprising: activating a trigger mechanism with the communication signal; and releasing the volume of flushing fluid from a fluid source in response to activation of a trigger mechanism.
A twenty-second embodiment, which is the method of the twentieth or the twenty-first embodiment, further comprising: displacing a volume of trapped fluid within the flushing chamber with the volume of flushing fluid via a fluid flowpath.
While several embodiments have been provided in the present disclosure, it should be understood that the disclosed systems and methods may be embodied in many other specific forms without departing from the spirit or scope of the present disclosure. The present examples are to be considered as illustrative and not restrictive, and the intention is not to be limited to the details given herein. For example, the various elements or components may be combined or integrated in another system or certain features may be omitted or not implemented.
Also, techniques, systems, subsystems, and methods described and illustrated in the various embodiments as discrete or separate may be combined or integrated with other systems, modules, techniques, or methods without departing from the scope of the present disclosure. Other items shown or discussed as directly coupled or communicating with each other may be indirectly coupled or communicating through some interface, device, or intermediate component, whether electrically, mechanically, or otherwise. Other examples of changes, substitutions, and alterations are ascertainable by one skilled in the art and could be made without departing from the spirit and scope disclosed herein.
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