Patent Grant
8251147
Subsurface valves are typically installed in strings of tubing deployed to subterranean wellbores to prevent the escape of fluid, from one production zone to another and/or to the surface. Possible applications of the embodiments of the present disclosure relate to all types of valves. For purposes of illustration this application discloses, as an example, safety valves used to shut in a well in the absence of continued hydraulic pressure from the surface. This example should not be used to limit the scope of the disclosure for non safety valve applications which may be readily apparent from the disclosure made herein to a person having ordinary skill in this art.
Without a safety valve, a sudden increase in downhole pressure can lead to catastrophic blowouts of production and other fluids into the atmosphere. For this reason, drilling and production regulations throughout the world require placement of safety valves within strings of production tubing before certain operations can be performed.
Various obstructions exist within strings of production tubing in subterranean wellbores. Valves, whipstocks, packers, plugs, sliding side doors, flow control devices, landing nipples, and dual completion components can obstruct the deployment of capillary tubing strings to subterranean production zones. Particularly, in circumstances where stimulation operations are to be performed on non-producing hydrocarbon wells, the obstructions stand in the way of operations that are capable of obtaining continued production out of a well long considered “depleted.” Most depleted wells are not lacking in hydrocarbon reserves, rather the natural pressure of the hydrocarbon-producing zone is insufficient to overcome the hydrostatic pressure or head of the production column. Often, secondary recovery and artificial lift operations will be performed to retrieve the remaining resources, but such operations are often too complex and costly to be performed on a well. Fortunately, many new systems enable continued hydrocarbon production without costly secondary recovery and artificial lift mechanisms. Many of these systems utilize the periodic injection of various chemical substances into the wellbore to stimulate the production zone thereby increasing the production of marketable quantities of oil and gas. However, obstructions in a producing well often stand in the way to deploying an injection conduit to the production zone so that the stimulation chemicals can be injected. While many of these obstructions are removable, they are typically components required to maintain production of the well and permanent removal is not feasible. Therefore, a mechanism to work around them would be highly desirable.
One of the most common of these obstructions found in production tubing strings are subsurface safety valves. Subsurface safety valves are typically installed in strings of tubing deployed to subterranean wellbores to prevent the escape of fluids from one zone to another. Frequently, subsurface safety valves are installed to prevent production fluids from blowing out of a lower production zone either to an upper zone or to the surface. Absent safety valves, sudden increases in downhole pressure can lead to disastrous blowouts of fluids into the atmosphere or other wellbore zones. Therefore, numerous drilling and production regulations throughout the world require safety valves within strings of production tubing before many operations are allowed to proceed.
Safety valves allow communication between zones under regular conditions and are typically designed to close when undesirable downhole conditions exist. One popular type of safety valve is commonly referred to as a flapper valve. Flapper valves typically include a closure member generally in the form of a circular or curved disc that engages a corresponding valve seat to isolate zones located above and below the flapper in the subsurface well. A flapper disc is preferably constructed such that the flow through the flapper valve seat is as unrestricted as possible. Flapper-type safety valves are typically located within the production tubing and isolate production zones from upper portions of the production tubing. Optimally, flapper valves function as high-clearance check valves, in that they allow substantially unrestricted flow therethrough when opened and completely seal off flow in at least one direction when closed. Particularly, production tubing safety valves prevent fluids from production zones from flowing up the production tubing when closed but still allow for the flow of fluids (and movement of tools) into the production zone from above.
Flapper valve disks are often energized with a biasing member (spring, hydraulic cylinder, etc.) such that in a condition with zero flow and with no actuating force applied, the valve remains closed. In this closed position, any build-up of pressure from the production zone below will thrust the flapper disc against the valve seat and act to strengthen any seal therebetween. During use, flapper valves are opened by various methods to allow the free flow and travel of production fluids and tools therethrough. Flapper valves may be kept open through hydraulic, electrical, or mechanical energy during the production process.
Non-limiting examples of subsurface safety valves can be found in U.S. Provisional Patent Application Ser. No. 60/593,216 filed Dec. 22, 2004 by Tom Hill, Jeffrey Bolding, and David Smith entitled “Method and Apparatus of Fluid Bypass of a Well Tool”; U.S. Provisional Patent Application Ser. No. 60/593,217 filed Dec. 22, 2004 by Tom Hill, Jeffrey Bolding, and David Smith entitled “Method and Apparatus to Hydraulically Bypass a Well Tool”; U.S. Provisional Patent Application Ser. No. 60/522,360 filed Sep. 20, 2004 by Jeffrey Bolding entitled “Downhole Safety Apparatus and Method”; U.S. Provisional Patent Application Ser. No. 60/522,500 filed Oct. 6, 2004 by David R. Smith and Jeffrey Bolding entitled “Downhole Safety Valve Apparatus and Method”; and U.S. Provisional Patent Application Ser. No. 60/522,499 filed Oct. 7, 2004 by David R. Smith and Jeffrey Bolding entitled “Downhole Safety Valve Interface Apparatus and Method”. Each of the above references is hereby incorporated by reference in its entirety.
One popular means to counteract the closing force of the biasing member and any production flow therethrough involves the use of capillary tubing to operate the safety valve flapper through hydraulic pressure. Traditionally, production tubing having a subsurface safety valve mounted thereto is disposed in a wellbore to a depth of investigation. In this circumstance, the capillary tubing used to open and shut the subsurface safety valve is deployed in the annulus formed between the outer surface of the production tubing and the inner wall of the borehole or casing. A fitting outside of the subsurface safety valve connects to the capillary tubing and allows pressure in the capillary to operate the flapper of the safety valve. Furthermore, because former systems were run with the production tubing, installations after the installation of production tubing in the wellbore are evasive. To accomplish this, the production tubing must be retrieved, the safety valve installed, the capillary tubing attached, and the production tubing, safety valve, and capillary tubing assembly run back into the hole. This expense and time consumed are such that it can only be performed on wells having a long-term production capability to justify the expense.
The present disclosure generally relates to hydrocarbon producing wells where production of the well can benefit from continuous injection of a fluid. More specifically, injection of a fluid from the surface through a small diameter, or capillary, tubing. Exemplary, non-limiting applications of fluid injection are: injection of surfactants and/or foaming agents to aid in water removal from a gas well; injection of de-emulsifiers for production viscosity control; injection of scale inhibitors; injection of inhibitors for asphaltine and/or diamondoid precipitates; injection of inhibitors for paraffin deposition; injection of salt precipitation inhibitors; injection of chemicals for corrosion control; injection of lift gas; injection of water; injection of hydraulic oil, such as through a stinger, to operate a wireline valve (as will be described in greater detail with respect to
Many wells throughout the world have surface controlled subsurface safety valves (“SCSSV”) installed in the production tubing, and such valves are well known by those of ordinary skill in the art of completion engineering and operation of oil and gas wells. SCSSVs fall into two generic types: tubing retrievable (“TR”) valves and wireline retrievable (“WR”) valves.
TR valves are attached to the production tubing and are deployed and removed from the well by deploying or removing the production tubing from the well. Removing the production tubing is typically cost prohibitive because a drilling rig must be mobilized, which can cost the operator of the well millions of dollars.
In sharp contrast, WR valves are deployed by wireline or slickline. Deploying WR valves via wireline or slickline is typically significantly less expensive to deploy and retrieve than TR valves. WR valves can also be referred to as “insert valves” because they can be adapted to be inserted inside either a TR valve or a hydraulic nipple in situ. Additionally, WR valves can be removed without removal of the production tubing. The actual method of deployment for WR valves is not critical to the claimed invention. Deployment methods utilizing slickline, wireline, coiled tubing, capillary tubing, or work string can be used in conjunction with the claimed invention. For the purposes of this patent, WR shall be used to describe any valve that is not a TR valve.
Because SCSSVs are a critical safety device used in virtually all modern wells, the manufacture and design of SCSSVs is controlled by the American Petroleum Institute (“API”). The current controlling specification published by API for SCSSVs is API-14a. While API-14a provides design and manufacture guidance for current SCSSVs, embodiments of the present disclosure can be adapted to incorporate new features or specifications required by future specifications that control the design and manufacture of SCSSVs.
API-14a currently requires certification testing, typically performed by a third party. In addition to the testing required by API-14a, valve manufacturers generally require a rigorous series of testing of new valve designs which can entail weeks or even months of in-house testing. The significant testing requirements imposed by API-14a and by manufacturers can result in newly designed SCSSVs taking months or even years to develop and perfect and can often cost manufacturers hundreds of thousands of dollars.
A new apparatus and method of use has been developed that solves the problems inherent with the prior art. The bypass passageway apparatus described herein has been adapted to work in concert with the invention described in U.S. Provisional Application Ser. No. 60/595,137, filed Jun. 8, 2005 by Jeffrey Bolding and Thomas Hill entitled “Wellhead Bypass Method and Apparatus”, a copy of which is hereby incorporated by reference as if set out fully herein. Although the bypass passageway apparatus described herein is compatible with the above invention, the bypass passageway apparatus of the present application can be used without the benefit of the Wellhead Bypass Method and Apparatus.
The bypass passageway apparatus enables a production-stimulating fluid to be injected into a wellbore using capillary tubing while maintaining the operation of a safety valve. As the demand for the bypass passageway apparatus is expected to be extremely high, there is a need for a means to convert existing certified designs to the bypass passageway apparatuses of the present application. For simplification, a WRSCSSV that has been converted to a bypass passageway apparatus shall be referred to as an “enhanced WRSCSSV”.
The present application discloses a conversion kit that enables a WRSCSSV to be converted to a bypass passageway apparatus. In addition, the present application discloses an enhanced WRSCSSV adapted to hang tubing. The present application also discloses a method for performing artificial lift using a bypass passageway apparatus. Finally, the present application discloses a method of injecting a production-enhancing fluid into a well while maintaining safety valve operation using a bypass passageway apparatus.
An embodiment of the present disclosure is directed to a wellbore injection system. The wellbore injection system comprises a capillary fluid flow path positioned in a subsurface wellbore so as to allow fluid communication through the wellbore, the wellbore having a wellbore pressure. A receptacle is in fluid communication with a second fluid flow path that is positioned below the capillary fluid flow path in the wellbore. An injector is attached to a distal end of the capillary fluid flow path, the injector comprising an injector flow path. The injector is capable of being removably attached to the receptacle to provide fluid communication between the capillary fluid flow path and the second fluid flow path through the injector flow path. An isolation mechanism is capable of isolating the capillary fluid flow path from the wellbore pressure when the injector is not attached to the receptacle.
Another embodiment of the present disclosure is directed to an injector isolation system for use in a wellbore. The wellbore comprises a capillary fluid flow path providing fluid communication through the wellbore. A receptacle is in fluid communication with a second fluid flow path that is positioned below the capillary fluid flow path in the wellbore. The injector isolation system comprises an injector capable of being attached to a distal end of the capillary fluid flow path. The injector comprises an injector flow path through which fluid can pass into and out of the injector. The injector is capable of being removably attached to the receptacle to provide fluid communication between the capillary fluid flow path and the second fluid flow path through the injector flow path. An isolation mechanism is capable of isolating the capillary fluid flow path from the wellbore pressure when the injector is not attached to the receptacle.
Another embodiment of the present disclosure is directed to a kit for enhancing a wireline retrievable surface controlled subsurface safety valve (“enhanced WRSCSSV”) to inject a fluid while maintaining safety valve operation. The components can include a locking mandrel, an upper adapter, a lower adapter, and/or an injection bypass passageway. The kit can further include a WRSCSSV, a spacer tube, a tubing string hanger attached to the lower adapter for hanging a tubing string, and/or one or more packings to seal the enhanced WRSCSSV to the side of the wellbore. The spacer tube, locking mandrel, and/or the upper adapter can include a receptacle removably receiving an injector for injecting fluid into the bypass passageway. In any embodiment, the kit can include the necessary upper and/or lower capillary tube(s) depending on customer requirements.
A kit for enhancing a wireline retrievable surface controlled subsurface safety valve to inject a production-enhancing fluid while maintaining operability of the wireline retrievable surface controlled subsurface safety valve can include an upper adapter connected to a locking mandrel and adapted to connect to a proximal end of the wireline retrievable surface controlled subsurface safety valve, a lower adapter adapted to connect to a distal end of the wireline retrievable surface controlled subsurface safety valve, and a bypass passageway extending between the upper and the lower adapters allowing fluid communication around the wireline retrievable surface controlled subsurface safety valve. The kit can include a tubing string hanger. Bypass passageway can be external the wireline retrievable surface controlled subsurface safety valve. The kit can include a spacer tube, which can be disposed between the upper adapter and the locking mandrel. At least one of the upper adapter, locking mandrel, and lower adapter can include a packing to seal said at least one of the upper adapter, locking mandrel, and lower adapter to a wellbore. A bypass passageway can include a check valve.
An upper capillary tube can be connected to the upper adapter, the upper capillary tube in communication with the bypass passageway. A receptacle of the upper adapter can removably receive an injector disposed on a distal end of an upper capillary tube, the receptacle in communication with the bypass passageway. A lower capillary tube can be connected to the lower adapter, the lower capillary tube in communication with the bypass passageway. The lower capillary tube can include or be connected to a gas lift valve. A bypass passageway can include a capillary tube. The kit can include the wireline retrievable surface controlled subsurface safety valve.
In another embodiment, a method of enhancing a wireline retrievable surface controlled subsurface safety valve includes connecting an upper adapter to a proximal end of the wireline retrievable surface controlled subsurface safety valve, connecting a lower adapter to a distal end of the wireline retrievable surface controlled subsurface safety valve, and providing a bypass passageway extending between the upper and lower adapters. The bypass passageway can be external the wireline retrievable surface controlled subsurface safety valve. The method can include connecting a locking mandrel to the upper adapter and/or disposing a spacer tube between the locking mandrel and the upper adapter. The spacer tube can include a receptacle removably receiving an injector disposed on a distal end of an upper capillary tube, the receptacle in communication with the bypass passageway. Bypass passageway can be a capillary tube. Bypass passageway can include a check valve.
A method of enhancing a wireline retrievable surface controlled subsurface safety valve can include connecting an upper capillary tube to the upper adapter, the upper capillary tube in communication with the bypass passageway. A method of enhancing a wireline retrievable surface controlled subsurface safety valve can include connecting a lower capillary tube to the lower adapter, the lower capillary tube in communication with the bypass passageway. A method can include connecting a tubing hanger to the lower adapter.
In yet another embodiment, a method of injecting a production-enhancing fluid into a well while maintaining operation of an enhanced wireline retrievable surface controlled subsurface safety valve includes connecting an upper adapter to a proximal end of a wireline retrievable surface controlled subsurface safety valve, connecting a lower adapter to a distal end of the wireline retrievable surface controlled subsurface safety valve, providing a bypass passageway extending between the lower and upper adapters and external to the wireline retrievable surface controlled subsurface safety valve to form the enhanced wireline retrievable surface controlled subsurface safety valve, connecting an upper capillary tube to the upper adapter, the upper capillary tube in communication with the bypass passageway, inserting the enhanced wireline retrievable surface controlled subsurface safety valve into a wellbore, sealing the enhanced wireline retrievable surface controlled subsurface to the wellbore with a packing, and injecting the production-enhancing fluid into the wellbore below the safety valve through the upper capillary tube and the bypass passageway. The production-enhancing fluid can be a surfactant, a foaming agent, a de-emulsifier, a diamondoid precipitate inhibitor, an asphaltine inhibitor, a paraffin deposition inhibitor, a salt precipitation inhibitor, a corrosion control chemical, and/or an artificial lift gas.
A method of injecting a production-enhancing fluid into a well while maintaining operation of an enhanced wireline retrievable surface controlled subsurface safety valve can include connecting a lower capillary tube to the lower adapter, the lower capillary tube in communication with the bypass passageway, and injecting the production-enhancing fluid into the wellbore below the enhanced wireline retrievable surface controlled subsurface safety valve through the upper capillary tube, the bypass passageway, and the lower capillary tube. The method can further include connecting a gas lift valve to the lower capillary tube, suspending a tubing string from a tubing hanger connected to the lower adapter, and/or disposing a locking mandrel connected to the upper adapter into a nipple profile of the wellbore. The tubing string can be a velocity tubing string.
A method of injecting a production-enhancing fluid into a well while maintaining operation of an enhanced wireline retrievable surface controlled subsurface safety valve can include flowing a produced fluid through an annulus formed between the velocity tubing string and the wellbore. A method can include flowing a produced fluid through the velocity tubing string. A method can include connecting a lower capillary tube to the lower adapter, the lower capillary tube extending within the velocity tubing string and in communication with the bypass passageway, and injecting the production-enhancing fluid into the wellbore below a distal end of the velocity tubing string through the upper capillary tube, the bypass passageway, and the lower capillary tube. A method can include connecting a gas lift valve to a distal end of the lower capillary tube, and injecting the production-enhancing fluid into the wellbore below the enhanced wireline retrievable surface controlled subsurface safety valve through the upper capillary tube, the bypass passageway, the lower capillary tube, and the gas lift valve.
The present application further discloses a method of enhancing a certified WRSCSSV by connecting an upper capillary tube to a locking mandrel, connecting the locking mandrel to an upper adapter, connecting the upper adapter to a WRSCSSV and a bypass passageway, connecting the WRSCSSV to a lower adapter, and connecting the bypass passageway or pathway to the lower adapter. In addition, a spacer tube containing an injector and receptacle can be inserted between the locking mandrel and upper adapter. The spacer tube can also include a bypass passageway, which can simply be a capillary tube. A check valve can be installed on the lower adapter to prevent flow from the wellbore into the injection tubing. A capillary tube can also be installed on the check valve to provide deeper injections.
In another embodiment, a method for injecting production-enhancing fluids into a well while maintaining safety valve operation is disclosed. The method includes inserting an enhanced WRSCSSV into a wellbore with an upper capillary tube, forming a seal between the safety valve and the wellbore, and injecting production-enhancing fluid into the wellbore below the safety valve using the upper capillary tube and a bypass passageway. Production-enhancing fluids can include surfactants, foaming agents, de-emulsifiers, diamondoid precipitate inhibitors, asphaltine precipitate inhibitors, paraffin deposition inhibitors, salt precipitation inhibitors, corrosion control chemicals, artificial lift gas, water, and the like. The method enables inserting a single fluid or combinations of fluid that can provide production enhancement.
In another embodiment, a kit for converting a certified WRSCSSV into an enhanced WRSCSSV to act as a hanger while maintaining well safety is disclosed. This embodiment can include a locking mandrel, an upper adapter, and a lower adapter including a hanger. In addition, the kit may include a pre-certified WRSCSSV. The kit may also include a spacer tube and packing to seal the enhanced WRSCSSV to the side of the wellbore. The kit can also be provided with a lower capillary tube which may act as a velocity tube string.
Another embodiment discloses a method for enhancing a standard WRSCSSV to incorporate bypass passageway to hang tubing while maintaining well safety valve operation. This method includes connecting a locking mandrel to an upper adapter, connecting the upper adapter to a WRSCSSV and a bypass passageway, connecting the WRSCSSV to a lower adapter, connecting the bypass passageway to the lower adapter, and connecting a tubing string to the lower adapter. The tubing string can be any type of tubing string commonly used in the oilfield industry including a velocity string, for example. The velocity string can be used such that produced fluid flows up the well within the velocity string or in the external annulus created between the velocity string and the production tubing.
Another embodiment of the present application includes a method of hanging a tubing string in a well while maintaining safety valve operation comprising: affixing a tubing string to the lower adapter of an enhanced WRSCSSV, inserting the tubing string and enhanced WRSCSSV into a wellbore, and sealing the WRSCSSV to the wellbore. The tubing string can be any type of tubing string known to one of ordinary skill in the art such as, for example, a velocity string.
An additional embodiment describes a kit for enhancing a WRSCSSV to use bypass passageway to perform artificial lift while maintaining well safety. This kit comprises a locking mandrel, an upper adapter, a bypass passageway, a lower adapter, a tubing string, a lower capillary tube, and a gas lift valve. The gas lift valve can be any standard valve used in the oilfield industry to control the rate of flow of artificial lift gases into a well. The kit can optionally include a WRSCSSV, a spacer tube, a hanger, a packing seal, and/or a check valve on the lower adapter. In addition, the upper adapter can include an injector and receptacle. In some cases the upper capillary tube can be included. Optionally, the bypass passageway can be a capillary tube.
Another embodiment describes a method of enhancing a WRSCSSV to utilize bypass passageway to perform artificial lift operations while maintaining safety valve operation. This method can include connecting an upper capillary tube to a locking mandrel, connecting the locking mandrel to an upper adapter, connecting the upper adapter to a WRSCSSV and a bypass passageway, connecting the WRSCSSV to a lower adapter, connecting the bypass passageway to the lower adapter, connecting a tubing string to the lower adapter, connecting a gas lift valve to a lower capillary tube, and connecting the lower capillary tube to the lower adapter.
An additional embodiment describes a method for performing artificial lift operations on a well while maintaining safety valve operation. This method includes connecting an upper capillary tube to the locking mandrel of an enhanced WRSCSSV, connecting a tubing string to the lower adapter of an enhanced wireline retrievable surface controlled subsurface safety valve, connecting a gas lift valve to a lower capillary tube, connecting the lower capillary tube to the lower adapter of the enhanced wireline retrievable surface controlled subsurface safety valve, inserting the tubing string, capillary tubes, and enhanced wireline retrievable surface controlled subsurface safety valve into a wellbore, sealing the safety valve to the wellbore, and injecting artificial lift gas into the wellbore below the safety valve via the enhanced wireline retrievable surface controlled subsurface safety valve and a bypass passageway.
Still another embodiment of the present disclosure is directed to a kit for enhancing a wireline retrievable surface controlled subsurface safety valve to inject a production-enhancing fluid while maintaining operability of the wireline retrievable surface controlled subsurface safety valve. The kit comprises an upper adapter connected to a locking mandrel and adapted to connect to a proximal end of the wireline retrievable surface controlled subsurface safety valve. A lower adapter is adapted to connect to a distal end of the wireline retrievable surface controlled subsurface safety valve. A bypass passageway extending between the upper and the lower adapters allowing fluid communication around the wireline retrievable surface controlled subsurface safety valve. A receptacle of the upper adapter is capable of removably receiving an injector disposed on a distal end of an upper capillary tube, the receptacle being in communication with the bypass passageway. An isolation mechanism is capable of isolating the capillary tube from a wellbore pressure when the injector is not received by the receptacle.
10A and 10B illustrate a male receptacle and female injector arrangement, according to an embodiment of the present disclosure.
Referring initially to
An upper capillary tube 105 can be connected to any portion of the enhanced WRSCSSV assembly 100. Upper capillary tube 105 can connect directly to the upper adapter 160 and be in communication with bypass passageway 150 if desired. A connection can be of any type known in the art including flange, quick-connect, threaded, or the like. In addition, a hydraulic control line 115 can be connected to a tubing retrievable surface controlled subsurface safety valve (“TRSCSSV”) 125 separately from the upper production tubing 110. Enhanced WRSCSSV assembly 100 is not limited to installation within a TRSCSSV 125 as shown and can be mounted in any wellbore and/or production tubing if desired. The enhanced WRSCSSV assembly 100 can further include a locking mandrel 120 for engagement within a nipple profile 145 for securing to the TRSCSSV 125, or any type of anchor for securing a downhole component within a tubing string. Locking mandrel 120 can be disposed at any portion of enhanced WRSCSSV assembly 100 and is not limited to connection to the proximal end of spacer tube 140 as shown. Enhanced WRSCSSV assembly 100 can be sealed within the wellbore, here the bore of TRSCSSV 125, by a packing (130, 155). Upper packing 130 is shown disposed between optional locking mandrel 120 and optional spacer tube 140. Spacer tube 140 connects the upstream end of the locking mandrel 120 to the downstream end of upper adapter 160. Spacer tube 140 can ensure the WRSCSSV is installed in the lower production tubing 165, preferably below the closure member of TRSCSSV 125 so said closure member does not interfere with the injection of production-enhancing fluids. For example, if distal end of lower adapter 175 of enhanced WRSCSSV assembly 100 is downstream of closure member of TRSCSSV 125, lower capillary tube 190 would extend through the bore of the TRSCSSV 125 and activation of the closure member of TRSCSSV 125 could sever lower capillary tube 190. As a closure member of a TRSCSSV 125 is typically biased to a closed position and nipple profile 145 is typically a fixed distance from the closure member, utilizing a spacer tube 140 of a desired length allows an enhanced WRSCSSV assembly 100 to extend through the bore of the TRSCSSV 125 adjacent the closure member to prevent the severing of lower capillary tube 190 and can further serve to retain the closure member of TRSCSSV 125 in an open position.
Lower packing 155 is shown disposed between upper adapter 160 and spacer tube 140 to provide a seal within the TRSCSSV 125. Upper adapter 160 can connect spacer tube 140 to a WRSCSSV 170, although the use of a spacer tube 140 is optional. The WRSCSSV 170 can be disposed within the lower production tubing 165 and attached to the lower adapter 175. Lower adapter 175 connects the WRSCSSV 170 and connects to the optional check valve 185 and lower capillary tubing 190.
An injected fluid can pass from upper capillary tube 105, for example, from a surface location, through an upper portion of bypass passageway 150 contained in locking mandrel 120. Optionally, an injector and injector receptacle 135 can be utilized if desired. As the receptacle is in communication with upper portion of bypass passageway 150, an injector disposed on the distal end of upper capillary tube 105 can be removably received within the receptacle to facilitate communication between the upper capillary tube 105 and the bypass passageway 150. Fluid can further travel through optional spacer tube 140 via an intermediate portion of bypass passageway 150. A lower portion of bypass passageway 150 extends through the upper adapter 160 and connects to portion 180 of bypass passageway 150. Portion 180 of bypass passageway 150 extends from upper adapter 160 and through the lower adapter 175 to allow bypass passageway 150 to connect to lower capillary tube 190. Lower adapter 175 can serve as a tubing string hanger to support the lower capillary tubing 190 and/or any tubing string.
In the embodiment shown, the portion of bypass passageway 150 that is coterminous with WRSCSSV 170 is routed external to the bore of WRSCSSV 170 so as not to impede the actuation of any closure member of WRSCSSV 170. A further benefit of such a configuration is that a standard WRSCSSV 170 can be used as no modification to the WRSCSSV 170 itself is required. A control line (not shown) to actuate WRSCSSV 170 can be any type or configuration known in the art.
Bypass passageway (150, 180) can be any conduit suitable for the flow of fluids including passageways or pathways machined into the tools, capillary tubing, piping, metallic tubing, non-metallic tubing, or the like. Upper capillary tubing 105, lower capillary tubing 190, and bypass passageway (150, 180) can be a single conduit if so desired.
The embodiment of
While the present application is especially suited for a bypass passageway 280 external to the WRSCSSV, one of ordinary skill in the art would recognize that a WRSCSSV containing an integral bypass passageway can be used. External bypass passageway 280 extends between upper adapter 260 to lower adapter 275 to allow fluid communication therebetween in at least one direction.
Referring now to
Distal end of upper capillary tube 305 is attached to an injector 335, which can be a stinger. Injector 335 is removably received by a receptacle 337 located within a proximal end of the upper adapter 360. Receptacle portion of upper adapter 360 is shown as a separate piece in
Upper adapter 360 can further be sealed to the walls of the polished bore of the TRSCSSV 325 with lower packing 355. Upper 330 and lower 355 packing can be positioned between the bore of the TRSCSSV 325 and the exterior of the enhanced WRSCSSV as shown to fluidicly isolate a zone including closure member 327 of the TRSCSSV 325, for example, if control mechanism of TRSCSSV 325 has failed so as to create a leak of production fluid external the TRSCSSV 325.
Upper adapter 360 connects to a WRSCSSV 370. The portion of bypass passageway 350 within upper adapter 360 connects to an external portion 380 of bypass passageway, shown as a capillary tube with a ferrule fitting 373 on a proximal end thereof. Fluid 348 flows through bypass passageway 350 to bypass passageway 380. Fluid 348 in bypass passageway 380 shall be referred to as fluid 382 (see
Closure mechanism or flapper 374 of WRSCSSV 370 can be actuated by any means to impede or stop production flow 352 if desired, for example, if the well becomes over pressurized or otherwise unsafe. In the illustrated embodiment, WRSCSSV 370 and bypass passageway tubing 380 are connected to lower adapter 375. Lower adapter 375 can provide protection, for example, protection from crushing contact with the bore of the TRSCSSV 325, and/or provide support to lower capillary tube 386. Lower adapter 375 further includes a tubing retainer or hanger 384 and a flow nozzle 395. Tubing retainer 384 can function to hang a lower capillary tube 386 below the flow nozzle 395. Distal end of lower capillary tube 386 can extend to any desired depth to allow dispersal of the injected fluid 382 below the WRSCSSV 370, or more specifically, the zone upstream of the closure member 374 of the WRSCSSV 370. Optional flow nozzle 395 can aid the flow of production flow 352 into the bore extending through the enhanced WRSCSSV of
Starting at the top,
The master valve 440 is connected to production tubing 410. Production tubing 410 extends below the surface of the water 458 and is disposed within a casing string 430. Below the mudline 460, an enhanced valve 400 can be installed in the production tubing 410 at a nipple profile of the production tubing 410 and/or TRSCSSV 425. Lower capillary tubing 405 and velocity tubing string 407 are thus suspended from the enhanced WRSCSSV 400, which is typically anchored into nipple profile of production tubing or the nipple profile of TRSCSSV 425 as shown here.
Hydrocarbon producing formation 472 and perforations 480 allow produced fluid 477 to flow from the formation 472. The flow of hydrocarbons (e.g., produced fluid 477) can be induced by artificial gas lift injected through the lower capillary tube 405. Although not shown, distal end of lower capillary tube 405 can merely extend within the production tubing 410, typically to a depth adjacent to the perforations 480. In the illustrated embodiment, the distal end of lower capillary tube 405 connects to a gas lift valve 475 attached to velocity tubing string 407. So configured, the injected gas flows through velocity tubing string 407 and aids the lifting of produced fluids 477 through the velocity tubing string 407 and through the enhanced WRSCSSV 400 to the bore of production tubing 410. Although ports are illustrated on the distal end of the enhanced WRSCSSV 400, in this embodiment they are not required and can be closed so that the produced fluids 477 flow through velocity tubing string 407 into the enhanced WRSCSSV 400, out the ports on the proximal end of enhanced WRSCSSV 400, through the production tubing 410 and out production flow line 450.
Gas lift valve 475 controls the flow of the injected gas through the lower capillary tube 405. As the bypass passageway (not shown) allows the operation of the closure member (e.g., flapper disc) of an enhanced WRSCSSV 400 to be maintained, an operator can inject gas independent of the position of the closure member to aid in the lifting of produced fluids 477 through the velocity string 407 via the bypass passageway (not shown) of the enhanced WRSCSSV 400. While gas lift is depicted in
Although
An alternate embodiment is depicted in the inset
Starting at the top,
The hydrocarbon producing formation 572 and perforations 580 allow produced fluid 577 to flow from the formation 572. The flow can be lifted by standard techniques known in the art such as gas lift through the through the velocity tubing string 507 and up through the enhanced valve 500 to the production tubing 510. Pump 512 and hydraulic control line 515 connect to the closure member of the enhanced WRSCSSV 500 to allow actuation thereof.
Although
Wellbore injection system 602 includes a capillary tube 605 positioned in a subsurface wellbore so as to allow fluid communication through the wellbore. An injector 635 comprises an injector flow path 635a and an injector flow path opening 635b. Injector 635 is attached, either directly or indirectly, to capillary tube 605 so as to provide fluid communication from the capillary tube 605 through the injector flow path 635a and injector flow path opening 635b.
A receptacle 637 capable of receiving injector 635 is also positioned in the wellbore. Receptacle 637 is in fluid communication with bypass passageway 650, which can be similar to other bypass passageways described herein in that it can allow injection of a fluid around a WRSCSSV. Injector 635 is capable of being removably attached to receptacle 637 to provide fluid communication between the capillary tube 605 and the bypass passageway 650 through injector flow path 635a.
As more clearly shown in
As shown in
One or more wings 639 can be attached to the tubular member 638a. In an embodiment, two, three, four or more wings 639 can be employed. A gap 639a can be positioned in the wing 639 so as to form a flexible wing member 639b. A wing retaining profile 639c can be formed as part of the flexible wing member 639b. A corresponding tube profile 641 can be formed in the spacer tube 640. Spacer tube profile 641 can include, for example, a protrusion 641 a and a groove 641b. The flexible wing member 639b and wing retaining profile 639c can function as a retaining mechanism 642 (shown in
For example, as shown in the embodiment of
The retaining mechanism 642 allows the injector 635 to move relative to the isolation mechanism 638, so that while wing 639 is held in place, injector 635 can continue in a down-hole direction to engage receptacle 637, as illustrated in
A second retaining mechanism 646 can be employed for holding the injector 635 substantially in place relative to the receptacle 637. In an embodiment, the second retaining mechanism 646 comprises a shoulder profile 647 in the injector 635 that is capable of engaging one or more collet fingers 649 attached to the receptacle 637.
Wellbore injection system 602 further comprises a biasing mechanism 644 proximate the isolation mechanism 638. Any suitable biasing mechanism can be employed, such as, for example, a spring. The biasing mechanism 644 can act on the isolation mechanism 638 to force it into a desired position so as to block injector flow path 635a, thereby automatically isolating the capillary tube 605 from the wellbore pressure when the injector 635 is not attached to the receptacle 637. Thus, for example, biasing mechanism 644 can apply a force to the tubular member 638A that tends to move the tubular member 638A into the first position, as illustrated in
In addition to biasing mechanism 644, retaining mechanism 642 can also act as a mechanical means for forcing isolation mechanism 638 into the first position when removing injector 635 from receptacle 637. This is because the less gradual angle positioned on the up-hole side of wing member profile 639b can make it relatively difficult for wing 639 to move in an up-hole direction. Thus, the wing 639 is held in place as the injector 635 is removed from the receptacle 637, thereby forcing isolation mechanism 638 from the second position, as shown in
As the injector 635 is moved into the first position, it is forced up against a shoulder 651, which is fixed relative to the isolation mechanism 638. The up-hole force on the injector 635 is then transferred directly to the isolation mechanism 638, which in turn provides sufficient force to move wing member profile 639b up past the spacer tube profile 641. In this manner, the retaining mechanism 642 helps to insure that the isolation mechanism 638 is positioned to isolate the injector flow path 635a from wellbore conditions as the injector 635 is removed from the wellbore.
A second set of wings 652 can be included as part of the wellbore injection system 602, as illustrated in the embodiment of
Referring to
Valve 970 can be any suitable WR valve that can be controllable by hydraulic fluid, such as the wireline safety valves described herein. The injection system 902 and the WR valve can be deployed, for example, in the event a tubing valve control line fails. The system 902 can be placed inside the tubing valve or other nipple. Any suitable method for deploying the injection system can be used, including any of the methods discussed herein for deploying WR valves.
After injection system 902 is deployed, the injector 935 can be inserted into the receptacle 937. Subsequently, hydraulic fluid, which is shown by the dashed line in hydraulic passageway 950, can be pumped through the injector flow path 935a. Hydraulic fluid is injected into the hydraulic fluid passageway 950 from injector flow path 935a. The hydraulic fluid can be used to hydraulically control valve closure member 974. For example, hydraulic fluid can be used to force a mandrel 976 down to open valve closure member 974; and or force mandrel 976 up to allow valve closure member 974 to close.
While each of the illustrated embodiments of
Female injector 1035 can include an injector flow path 1035a and an injector flow path opening 1035b. An isolation mechanism 1038 can be employed for blocking the injector flow path opening 1035b. Isolation mechanism 1038 can be held in position by a biasing mechanism 1044, which can be, for example, a spring. Seals 1036 can aid in reducing leakage of fluids when either isolation mechanism 1038 is positioned to block injector flow path opening 1035b, or when male receptacle 1037 engages female injector 1035.
The male receptacle 1037 can be attached to the tubular housing of the wireline valve (not shown). In an embodiment, the male receptacle 1037 can be made to be removable from the tubular housing to provide for ease of manufacturing. Receptacle 1037 can include a bypass passageway 1050 that provides fluid communication with the wellbore downhole of the wireline valve, similar to the embodiment of
In operation, the capillary tube having the female injector 1035 attached thereto is passed down the wellbore and inserted onto the male receptacle. The downward motion of the female injector 1035 causes the male receptacle to force the isolation mechanism 1038 upward until the bypass passageway or hydraulic fluid passageway 1050 aligns with the injector flow path opening 1035b. In this manner, fluid communication is established between the capillary attached to injector 1035 and the bypass passageway or hydraulic fluid passageway 1050.
Isolation mechanism 678 is chosen and positioned to reduce the likelihood of undesired flow of wellbore fluids up through the capillary tube to the surface, while still allowing fluid to pass through the valve from the surface down to the receptacle 637 (See
Capillary tube 605 can be attached to the injector 635 by any suitable manner, such as by screwing or latching the injector 635 onto the capillary tube 605. In another embodiment, as illustrated in
Isolation mechanism 1592 can be a shuttle valve that effectively allows manipulation of the injector flow path 635a to open or close the valve. For example, the isolation mechanism 1592 can comprise an injector dart 1588 that slideably engages an injector body 1586, as illustrated in
When the injector 1535 is being run in, the injector dart 1588 can be slideably positioned relative to the injector body 1586 so that that first section of the injector flow path 1535a is not aligned with the second section of the injector flow path 1535c, so as to provide a barrier to fluid flow through the injector flow path, as illustrated in
Similarly as described above for the embodiment of
Numerous embodiments and alternatives thereof have been disclosed. While the above disclosure includes the best mode belief in carrying out the embodiments of the present application as contemplated by the inventors, not all possible alternatives have been disclosed. For that reason, the scope and limitation of the present invention is not to be restricted to the above disclosure, but is instead to be defined and construed by the appended claims.
The present application is a continuation-in-part of copending U.S. patent application Ser. No. 11/916,966, having a 371 (c)(1) date of Dec. 7, 2007, to Thomas G. Hill, et al., which is a 371 application of PCT International Application No. PCT/US2006/022264, filed Jun. 8, 2006, which claims benefit of U.S. Provisional Application No. 60/595,138, filed Jun. 8, 2005, the disclosures of each of which applications are hereby incorporated by reference in their entirety.
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| Number | Date | Country | |
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| 20090277643 A1 | Nov 2009 | US |
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| Number | Date | Country | |
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| Parent | 11916966 | US | |
| Child | 12500688 | US |
