Patent Publication Number: US-6341652-B1

Title: Backflow prevention device

Description:
FIELD OF THE INVENTION 
     The present invention relates generally to a system for preventing backflow of fluid along a tube, and particularly to a system for preventing backflow of liquid in a tube used to protect signal transfer lines, such as those containing electric cable and/or optic fiber, in a downhole, wellbore environment. 
     BACKGROUND OF THE INVENTION 
     A variety of tools are used at subsurface locations from which or to which a variety of output signals or control signals are sent. For example, many subterranean wells are equipped with tools or instruments that utilize electric and/or optical signals, e.g. pressure and temperature gauges, flow meters, flow control valves, and other tools. (In general, tools are any device or devices deployed downhole which utilize electric or optical signals.) Some tools, for example, may be controlled from the surface by an electric cable or optical fiber. Similarly, some of the devices are designed to output a signal that is transmitted to the surface via the electric cable or optical fiber. 
     The signal transmission line, e.g. electric cable or optical fiber, is encased in a tube, such as a one quarter inch stainless steel tube. The connection between the signal transmission line and the tool is accomplished in an atmospheric chamber via a connector. Typically, a metal seal is used to prevent the flow of wellbore fluid into the tube at the connector. This seal is obtained by compressing, for example, a stainless steel ferrule over the tube to form a conventional metal seal. 
     However, the hostile conditions of the wellbore environment render the connection prone to leakage. Because the inside of the connector and tube may stay at atmospheric pressure while the outside pressure can reach 15,000 PSI at high temperature, any leak results in the flow of wellbore fluid into the tube. The inflow of fluid invades the internal connector chamber and interior of the tube, resulting in a failure due to short circuiting of the electric wires or poor light transmission through the optic fibers. This, of course, effectively terminates the usefulness of the downhole tool. 
     It would be advantageous to have a system for preventing the backflow of wellbore fluids along the protective tube (or other types of tubes) from one wellbore zone to another. 
     SUMMARY OF THE INVENTION 
     The present invention provides a technique for preventing backflow of fluid, such as wellbore fluid, along a tube. The technique further allows for the use of signal transmission lines deployed in the interior of a tube, such as a stainless steel tube, extending to a subsurface location, e.g. a downhole location within a wellbore. Thus, signals can be transmitted from one zone to another while being protected by the outer tube. However, wellbore fluids are prevented from crossing from one zone to another in the event such fluid enters the tube. The technique includes the use of a penetrator combined with a zone separation device, such as a feed-through packer, a tubing hanger or an annulus safety valve. The system, however, should not be limited to any particular zone separation devices or tubes. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and: 
     FIG. 1 is a front elevational view of a system, according to a preferred embodiment of the present invention, utilized in a downhole, wellbore environment; 
     FIG. 2 is an elevational view similar to FIG. 1 but showing a pump to pressurize the system; 
     FIG. 3 is a cross-sectional view of an exemplary combination of a signal transmission line extending through the interior of a protective tube, according to a preferred embodiment of the present invention; 
     FIG. 4 is a cross-sectional view similar to FIG. 3 illustrating an alternate embodiment; 
     FIG. 5 is a cross-sectional view similar to FIG. 3 illustrating another alternate embodiment; 
     FIG. 6 is a cross-sectional view taken generally along the axis of an exemplary protective tube, illustrating another alternate embodiment; 
     FIG. 6A is a radial cross-sectional view illustrating another alternate embodiment; 
     FIG. 6B is a cross-sectional view similar to FIG. 6A but showing a different transmission line; 
     FIG. 7 is an axial cross-sectional view of an exemplary connector utilized in connecting a protective tubing to a downhole tool; 
     FIG. 8 is a cross-sectional view taken generally along the axis of a penetrator having a hydraulic bypass; and 
     FIG. 9 is an alternate embodiment of the penetrator illustrated in FIG.  8 . 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     Referring generally to FIG. 1, a system  10  is illustrated according to a preferred embodiment of the present invention. One exemplary environment in which system  10  is utilized is a well  12  within a geological formation  14  containing desirable production fluids, such as petroleum. In the application illustrated, a wellbore  16  is drilled and lined with a wellbore casing  18 . 
     In many systems, the production fluid is produced through a tubing  20 , e.g. production tubing, by, for example, a pump (not shown) or natural well pressure. The production fluid is forced upwardly to a wellhead  22  that may be positioned proximate the surface of the earth  24 . Depending on the specific production location, the wellhead  22  may be land-based or sea-based on an offshore production platform. From wellhead  22 , the production fluid is directed to any of a variety of collection points, as known to those of ordinary skill in the art. 
     A variety of downhole tools are used in conjunction with the production of a given wellbore fluid. In FIG. 1, a tool  26  is illustrated as disposed at a specific downhole location  28 . Downhole location  28  is often at the center of very hostile conditions that may include high temperatures, high pressures (e.g., 15,000 PSI) and deleterious fluids. Accordingly, overall system  10  and tool  26  must be designed to operate under such conditions. 
     For example, tool  26  may constitute a pressure temperature gauge that outputs signals indicative of downhole conditions that are important to the production operation; tool  26  also may be a flow meter that outputs a signal indicative of flow conditions; and tool  26  may be a flow control valve that receives signals from surface  24  to control produced fluid flow. Many other types of tools  26  also may be utilized in such high temperature and high pressure conditions for either controlling the operation of or outputting data related to the operation of, for example, well  12 . 
     The transmission of a signal to or from tool  26  is carried by a signal transmission line  30  that extends, for example, upward along tubing  20  from tool  26  to a controller or meter system  32  disposed proximate the earth&#39;s surface  24 . Exemplary signal transmission lines  30  include electrical cable that may include one or more electric wires for carrying an electric signal or an optic fiber for carrying optical signals. Signal transmission line  30  also may comprise a mixture of signal carriers, such as a mixture of electric conductors and optical fibers. 
     The signal transmission line  30  is surrounded by a protective tube  34 . Tube  34  also extends upwardly through wellbore  16  and includes an interior  36  through which signal transmission line  30  extends. A fluid communication path  37  also extends along interior  36  to permit the flow of fluid therethrough. 
     Typically, protective tube  34  is a rigid tube, such as a stainless steel tube, that protects signal transmission  30  from the subsurface environment. The size and cross-sectional configuration of the tube can vary according to application. However, an exemplary tube has a generally circular cross-section and an outside diameter of one quarter inch or greater. It should be noted that tube  34  may be made out of other rigid, semi-rigid or even flexible materials in a variety of cross-sectional configurations. Also, protective tube  34  may include or may be connected to a variety of bypasses that allow the tube to be routed through tools, such as packers, disposed above the tool actually communicating via signal transmission line  30 . 
     Protective tube  34  is connected to tool  26  by a connector  38 . Connector  38  is designed to prevent leakage of the high pressure wellbore fluids into protective tube  34  and/or tool  26 , where such fluids can detrimentally affect transmission of signals along signal transmission line  30 . However, most connectors are susceptible to deterioration and eventual leakage. 
     To prevent the inflow of wellbore fluids, even in the event of leakage at connector  38 , fluid communication path  37  and connector  38  are filled with a fluid  40 . An exemplary fluid  40  is a liquid, e.g., a dielectric liquid used with electric lines to help avoid disruption of the transmission of electric signals along transmission line  30 . 
     Fluid  40  is pressurized by, for example, a pump  42  that may be a standard low pressure pump coupled to a fluid supply tank. Pump  42  may be located proximate the earth&#39;s surface  24 , as illustrated, but it also can be placed in a variety of other locations where it is able to maintain fluid  40  under a pressure greater than the pressure external to connector  38  and protective tube  34 . Due to its propensity to leak, it is desirable to at least maintain the pressure of fluid within connector  38  higher than the external pressure at that downhole location. However, if pump  42  is located at surface  24 , the internal pressure at any given location within protective tube  34  and connector  38  typically is maintained at a higher level than the outside pressure at that location. Alternatively, the pressure in tube  34  may be provided by a high density fluid disposed within the interior of the tube. 
     In the event connector  38  or even tube  34  begins to leak, the higher internal pressure causes fluid  40  to flow outwardly into wellbore  16 , rather than allowing wellbore fluids to flow inwardly into connector  38  and/or tube  34 . Furthermore, if a leak occurs, pump  42  preferably continues to supply fluid  40  to connector  38  via protective tube  34 , thereby maintaining the outflow of fluid and the protection of signal transmission line  30 . This allows the continued operation of tool  26  where otherwise the operation would have been impaired. 
     In fact, pump  42  and fluid communication path  37  can be utilized for hydraulic control. The ability to move a liquid through tube  34  may also allow for control of certain hydraulically actuated tools coupled to tube  34 . 
     Referring generally to FIGS. 3 through 5, a variety of exemplary transmission lines  30  are shown disposed within protective tube  34 . In FIG. 3, signal transmission line  30  includes a single electric wire or optic fiber  44 . The single wire or optic fiber  44  is surrounded by an insulative layer  46  that may comprise a plastic material, such as non-elastomeric plastic. Fluid  40  surrounds the signal transmission line  30  within the interior  36  of tube  34 . 
     In FIG. 4, the wire or optic fiber  44  is surrounded by a thicker insulation layer  48 , such as an elastomeric layer. The radial thickness of insulation  48  is selected according to the specific gravity or density of fluid  40  to provide a support for signal transmission line  30 . For example, if fluid  40  is a dielectric liquid, insulation layer  48  is selected such that signal transmission line  30  is supported within fluid  40  by its buoyancy. Preferably, the average density of insulation layer  48  and wire or fiber  44  is selected such that the signal transmission line  30  floats neutrally within fluid  40 . In other words, there is minimal tension in line  30 , because it is not affected by a greater density relative to the liquid (resulting in a downward pull) or a lesser density (resulting in an upward pull). 
     In the alternate embodiment illustrated in FIG. 5, a plurality of wires, optic fibers, or a mixture thereof, is illustrated as forming signal transmission line  30 . Each wire or fiber  50  is surrounded by a relatively thin insulation layer  52  and connected to a float  54 . Float  54  preferably is designed to provide signal transmission line  30  with neutral buoyancy when disposed in fluid  40 , e.g. a dielectric liquid. 
     Other embodiments for supporting signal transmission line  30  within tube  34  are illustrated in FIGS. 6 and 6A. As illustrated in FIG. 6, for example, line  30  may be supported by contact with the interior surface of tube  34 . With this type of physical support, it may be desirable to wrap any conductive wires or optical fibers in an outer wrap  56  that has sufficient stiffness to permit frictional contact between outer wrap  56  and the interior surface of tube  34  at multiple locations along tube  34 . 
     In another embodiment, illustrated in FIGS. 6A and 6B, signal transmission line  30  is supported by a support member  57 . Member  57  extends between the inner surface of tube  34  and signal transmission line  30  to provide support. An exemplary support member  57  includes a hub  58  disposed in contact with line  30  and a plurality of wings  59 , e.g. four wings, that extend outwardly to tube  34 . Wings  59  permit uninterrupted flow of fluid along fluid communication path  37 . 
     In an exemplary application, tube  34  is drawn over support member  57  to provide an interference fit. Preferably, an interference fit is provided between signal transmission line  30  and hub  58  as well as between the radially outer ends of wings  59  and the inner surface of tube  34 . It also should be noted that if tube  34  is formed of a polymer rather than a metal, the polymer tube can be extruded on the winged profile of support member  57 . 
     Additionally, the winged support members can be used to draw a second tube, such as a stainless steel tube, over an inner steel tube, such as tube  34  or other types of tubes able to carry signal and/or power transmission lines. Effectively, any number of concentric tubes, e.g. steel or polymer tubes, with varying internal diameters, can be supported by each other via concentrically deployed support member  57 . 
     Wings  59  may have a variety of shapes, including hourglass, triangular, rectangular, square, trapezoidal, etc., depending on application and design parameters. Also, the number of wings utilized can vary depending on the configuration of the signal and/or power transmission lines. Exemplary materials for support member  57  include thermoplastic, elastomer or thermoplastic elastomeric materials. Many of these materials permit the winged profile of support member  57  to be extruded onto the signal and/or power transmission lines by a single extrusion. Additionally, separate winged members can be formed, and communication between the independent wings can be accomplished by cutting slots into the wings at regular intervals. One advantage of utilizing support member or members  57  (or the frictional engagement described with respect to FIG. 6) is that these embodiments do not require selection of fluids  40  or float materials that create neutral or near neutral buoyancy of line  30  within fluid  40 . 
     Referring generally to FIG. 7, an exemplary connector  38  is illustrated. Connector  38  includes a tool connection portion  60  designed for connection to tool  26 . The specific design of tool connection portion  60  varies according to the type or style of tool to which it is connected. Typically, the signal transfer line  30  is electrically, optically or otherwise connected to tool  26  by an appropriate signal transmission line connector  62 . Connector  38  also includes a connection chamber  64  that may be pressurized with fluid  40  to ensure an outflow of fluid  40  in the event a leak occurs around connector  38 . Connection chamber  64  may be separated from tool connection portion  60 , at least in part, by an internal wall  66 . 
     Tube  34 , and particularly interior  36  of tube  34 , extends into fluid communication with connection chamber  64  via an opening  68  formed through a connector wall  70  that defines chamber  64 . With this configuration, signal transmission line  30  extends through interior  36  and connection chamber  64  to an appropriate signal transmission line connector  62  coupled to tool  26 . The actual sealing of tube  34  to connector  38  may be accomplished in a variety of ways, including welding, threaded engagement, or the use of a metal seal, such as by compressing a stainless steel ferrule over the connecting end of tube  34 , as done in conventional systems and as known to those of ordinary skill in the art. Regardless of the method of attachment, fluid  40  is directed through interior  36  to connection chamber  64  and maintained at a pressure (P 2 ) that is greater than the external or environmental pressure (P 1 ) acting on the exterior of connector  38  and tube  34  at a given location. 
     In certain applications, it is desirable to ensure against backflow of wellbore fluids through tube  34 , at least across certain zones. For example, tube  34  may extend across devices, such as a tubing hanger disposed at the top of a completion, an annulus safety valve, and a variety of packers disposed in wellbore  16  at a location dividing the wellbore into separate zones above and below the packer. If tube  34  is broken or damaged, it may be undesirable to allow wellbore fluid to flow from a lower zone to an upper zone across one or more of these exemplary devices. Accordingly, it is desirable to utilize a barrier, sometimes referred to as a penetrator, to prevent fluid flow across zones. Existing penetrators, however, do not allow fluid circulation, so they cannot be used with a pressurized connector system of the type described herein. 
     As illustrated in FIG. 8, an improved penetrator  74  is illustrated as deployed in a zone separation device  76 , such as a packer (e.g. a feed-through packer), a tubing hanger or an annulus safety valve. Device  76  separates the wellbore into an upper annulus region  78  and a lower annulus region  80 . 
     Tube  34  is separated into an upper portion  34 A and a lower portion  34 B. Upper portion  34 A extends downwardly into a sealed upper cavity  82  of penetrator  74 , while lower tube section  34 B extends upwardly into a sealed lower cavity  84  of penetrator  74 . Sealed upper cavity  82  is connected to sealed lower cavity  84  by a fluid bypass  86  that includes a one way check valve  88 . Check valve  88  permits the flow of fluid  40  downwardly through penetrator  74 , but it prevents the backflow of fluid in an upward direction through penetrator  74 . Thus, if lower tube  34 B is broken or damaged, any backflow of wellbore fluid is terminated at check valve  88 . 
     The signal transmission line  30  passes through a solid wall  90  separating sealed upper cavity  82  from sealed lower cavity  84 . Preferably, line  30  has an upper connection  92  and a lower connection  94  that are coupled together via one or more high pressure feed-throughs  96  that extend through wall  90 . It should be noted that the signal transmission line  30  can be connected to a tool at and/or below penetrator  74  to provide communication and/or power to the tool. Also, fluid  40 , e.g. a liquid, can be utilized not only in the actuation of tools below zone separation device  76  but also device  76  itself. For example, if device  76  comprises a hydraulically actuated packer, the fluid  40  can be selected and used for hydraulic actuation. 
     An alternate embodiment of penetrator  74  is illustrated in FIG.  9  and labeled as penetrator  74 A. In this implementation, penetrator  74 A is designed as an independent sub to be secured, for example, to the lower face of or inside device  76 , such as to the lower face or inside of a packer body. 
     In the embodiment illustrated, the packer body includes a threaded bore  98  for receiving a threaded top end  100  of penetrator  74 A. A metal-to-metal seal  102  is formed between a chamfered penetrator edge  104  and a chamfered surface  106  disposed on the body of device  76 . Additionally, the upper tube  34 A is sealed to the body of device  76  by any of a variety of conventional methods known to those of ordinary skill in the art. Lower tube  34 A, however, is sealed to a tubing or cable head  108  which, in turn, is sealably coupled to penetrator  74 A. For example, tube head  108  may include a threaded region  110  designed for threaded engagement with a threaded lower end  112  of penetrator  74 A. A seal  114  may be formed between tube head  108  and penetrator  74 A when threaded regions  110  and  112  are securely engaged. Signal transmission line  30  includes an upper connector  116  and a lower connector  118  that are coupled across an electric feed-through  120  that is threadably engaged with penetrator  74 A, as illustrated. 
     The penetrator  74 A further includes a hydraulic bypass  122  that includes a check valve  124 , such as a one-way ball valve. Thus, fluid  40  may flow from tube  34 A downwardly through fluid bypass  122  and into lower tube  34 B. However, if lower tube  34 B is ruptured or damaged, any wellbore fluid flowing upwardly through lower tube  34 B is prevented from flowing past device  76  by check valve  124 . Accordingly, no wellbore fluids flow from a lower zone beneath the device  76  to an upper wellbore zone above device  76 . 
     It will be understood that the foregoing description is of preferred exemplary embodiments of this invention, and that the invention is not limited to the specific forms shown. For example, the pressurized fluid system may be used in a variety of subsurface environments, either land-based or sea-based; the system may be utilized in wellbores for the production of desired fluids or in a variety of other high pressure and/or high temperature environments; and the specific configuration of the tubing, pressurized fluid, tool, signal transmission line, and penetrator may be adjusted according to a specific application or desired design parameters. These and other modifications may be made in the design and arrangement of the elements without departing from the scope of the invention as expressed in the appended claims.