Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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PRESSURIZED SYSTEM FOR PROTECTING SIGNAL TRANSFER
CAPABILITY AT A SUBSURFACE LOCATION
FIELD OF THE INVENTION
The present invention relates generally to a system for
prolonging the life of a signal transfer line disposed at a
subsurface location, and particularly to a system for
l0 protecting a signal transfer line, 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.
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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.
Additionally, the signal transfer lines often extend
through the protective tube over substantial distances, e.g.
to substantial depths. If not supported, the weight of the
signal transfer lines creates substantial tension in the
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lines that can result in damaged wires/fibers. Even if the
signal transfer lines can withstand the tension, any cutting
of the wires/fibers results in severe retraction of the
lines into the tube. For example, when a technician cuts
the lines to repair a damaged cable or to cross a tubing
hanger, packer, annulus safety valve, another tool etc., the
retraction occurs.
A common solution is to add a filler in the annulus
l0 between the interior surface of the tube and the wires
and/or fibers. The filler may comprise a foam rubber
designed to expand with temperature to fill the gap between
the signal transfer lines and the interior surface of the
tube. However, such a f-iller does not alleviate the problem
of substantially reduced interior pressure relative to the
exterior pressure that can result in the inflow of
deleterious wellbore fluids.
SZJMMARY OF THE INVENTION
The present invention provides a technique for
preventing damage to signal transmission lines, such as
electric wires and optical fibers, utilized in a high
pressure, subsurface environment. The system utilizes
signal transmission lines deployed in the interior of a
tube, such as a stainless steel tube, extending to a
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subsurface location, such as a downhole location within a
wellbore.
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:
Figure 1 is a front elevational view of a system,
according to a preferred embodiment of the present
invention, utilized in a downhole, wellbore environment;
Figure 2 is an elevational view similar to Figure 1 but
showing a pump to pressurize the system;
Figure 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;
Figure 4 is a cross-sectional view similar to Figure 3
illustrating an alternate embodiment;
Figure 5 is a cross-sectional view similar to Figure 3
illustrating another alternate embodiment;
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Figure 6 is a cross-sectional view taken generally
along the axis of an exemplary protective tube, illustrating
another alternate embodiment;
Figure 6A is a radial cross-sectional view illustrating
another alternate embodiment;
Figure 6B is a cross-sectional view similar to Figure
6A but showing a different transmission line;
Figure 7 is an axial cross-sectional view of an
exemplary connector utilized in connecting a protective
tubing to a downhole tool;
Figure 8 is a cross-sectional view taken generally
along the axis of a penetrator having a hydraulic bypass;
and
Figure 9 is an alternate embodiment of the penetrator
illustrated in Figure 8.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Referring generally to Figure 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
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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.
l0 Depending on the specific production location, the wellhead
22 may be land-based or sea-based on <~n 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 Figure 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
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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'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
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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.
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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'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
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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 Figures 3 through 5, a variety
of exemplary transmission lines 30 are shown disposed within
protective tube 34. In Figure 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 Figure 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
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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
pul l ) .
In the alternate embodiment illustrated in Figure 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 Figures 6 and 6A.
As illustrated in Figure 6, for example, line 30 may be
supported by contact with the interior surface of tube 34.
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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 Figures 6A and
6B, signal transmission line 30 is supported by a support
member 57. Member 57 extends between the inner surface of
l0 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
3 7 .
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.
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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.
4~lings 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 Figure 6) is that these embodiments do not
require selection of fluids 40 or float materials that
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create neutral or near neutral buoyancy of line 30 within
fluid 40.
Referring generally to Figure 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
l0 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
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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 (P2) that is greater than the
external or environmental pressure (P1) 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,
2o 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.
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As illustrated in Figure 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 34A and a
lower portion 34B. Upper portion 34A extends downwardly
into a sealed upper cavity 82 of penetrator 74, while lower
tube section 34B 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 34B 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
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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 Figure 9 and labeled as penetrator 74A. In this
implementation, penetrator 74A 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 74A. 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 34A 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 34A, however, is sealed to a
tubing or cable head 108 which, in turn, is sealably coupled
to penetrator 74A. For example, tube head 108 may include a
threaded region 110 designed for threaded engagement with a
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threaded lower end 112 of penetrator 74A. A seal 114 may be
formed between tube head 108 and penetrator 74A 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
74A, as illustrated.
The penetrator 74A further includes a hydraulic bypass
l0 122 that includes a check valve 124, such as a one-way ball
valve. Thus, fluid 40 may flow from tube 34A downwardly
through fluid bypass 122 and into lower tube 34B. However,
if lower tube 34B is ruptured or damaged, any wellbore fluid
flowing upwardly through lower tube 34B 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;
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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.
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