TELEMETRY CABLE BYPASS

Abstract

Tubing encapsulated cable is generally difficult to place in the interior of a well. Currently the tubing encapsulated cable must pass through the various valves used isolate the well as it passes into the interior of the wellbore. In a current embodiment of the tubing encapsulated cable is secured, usually by compression fitting, to the lower end of the tubing hanger where the tubing hanger is situated beneath the lowest valve used to isolate the well. The conductors within the tubing encapsulated cable are routed into the tubing hanger to a position where a penetrator passes laterally through the side of the tubing hanger. The penetrator is configured such that there are insulated and conducting portions of the penetrator tip that correspond to the insulated and conducting portions of the conductors within the tubing encapsulated cable. The penetrator is then inserted into the tubing hanger to the point where the insulating and conducting portions of both the penetrator at the conductors within the tubing encapsulate cable are aligned. The penetrator in cooperation with the tubing hanger allows access from the exterior of the well to the interior of the wellbore.

Description

BACKGROUND

In present oil and gas drilling operations, there presently exists a need to monitor pressure, temperature and other wellbore conditions during lifetime of the well. In addition, it may be beneficial to have information about the subsurface formations that are penetrated by a wellbore. For example, certain formation evaluation schemes include measurement and analysis of the formation pressure and permeability. These measurements may be useful in predicting the production capacity and production lifetime of the subsurface formation. Evaluating and/or measuring properties of encountered formations, formation fluids, and/or formation gases may also be beneficial. An example property is the phase-change pressure of a formation fluid, which may be a bubble point pressure, a dew point pressure and/or an asphaltene onset pressure depending on the type of fluid.

Recently the cost of sensors and cabling capable of being placed in a well has been reduced to the point where it is now cost-effective to place telemetry within a well. In order to facilitate the placement of telemetry, which may be a pressure, temperature, or other sensor, within the well it is necessary to run the associated cables from the surface to a location where the sensor is desired. The desired location may be 8000, 9000, or more feet below the surface. Additionally the natural pressure within the well may be several thousand psi. Therefore it is necessary to support the weight of several thousand feet of sensor cable such as a tubing encapsulated cable, also known as a TEC line, as well as the various sensors from the wellhead. At the same time the pressurized wellbore fluid must be prevented from escaping at any undesired location. TEC line consists essentially of a metal armor shell, typically stainless steel, at least one inner insulator, and a conductor within the insulator or insulators.

In the past the cabling, the TEC line and the included electrical conductors or fiber optic cables for such sensors has been run through the various valves that make up the christmas tree and blowout preventer. However in many instances the valves may be closed without first removing the TEC line and included cabling. When the valves close the TEC line and included cabling is severed allowing the remaining Tec line and cable to fall into the well.

SUMMARY

In an embodiment of the present invention a tubing encapsulated cable, TEC, enters the lower end of the tubing hanger for the tubing hanger is located within a blowout preventer or christmas tree below the valves utilized for isolating the well. The tubing hanger, which typically sits below the various valves within the christmas tree is utilized to both retain the TEC line within the well bore and to provide access to the conductors and/or data fibers within the TEC line.

Generally the TEC has an outer armor shell usually made of stainless steel and within the outer armor shell has a fiber-optic cable and/or at least one insulated conductor. In some instances the insulated conductors may be coaxial with the other conductors or fiber-optic cable. The tubing hanger has a port at the lower end for the TEC to enter the tubing hanger. In a current embodiment the TEC is secured to the lower end of the tubing hanger by compression fitting. With the TEC's outer armor shell secured to the tubing hanger the interior insulated conductors pass further through the bore and the lower end of the tubing hanger to a position where the insulated conductors may be intersected from the side of the tubing hanger by a conducting penetrator. It is anticipated that the conducting penetrator will access the tubing hanger in place of a lockdown pin. The conducting penetrator is configured such that the tip of the penetrator will pierce the layers of the insulated conductor allowing the various conducting layers of the penetrator to contact the appropriate layers of the insulated conductor to provide connectivity from the wellbore through the conducting penetrator to the exterior of the wellbore.

Is generally envisioned that the tubing hanger will prevent wellbore fluids from inadvertently being lost to the exterior by having seals at least between the wellbore and the penetrator access. In addition is envisioned that the TEC will be sealed to the tubing hanger where the TEC intersects the tubing hanger generally by a compression fitting. Additionally penetrator will incorporate seals.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a typical wellbore surface set up.

FIG. 2 depicts a close-up of a portion of a christmas tree showing the location of the tubing hanger within the tubing head adapter and below the lower master valve.

FIG. 3 depicts an embodiment of the invention where a tubing hanger has been adapted to hang a TEC line into a well.

FIG. 4 depicts a lockdown pin configured to provide a conductive pathway to an insulated cable within a tubing hanger.

FIG. 5 depicts an alternative embodiment of a penetrator tip.

DETAILED DESCRIPTION

The description that follows includes exemplary apparatus, methods, techniques, or instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.

FIG. 1 is a typical wellbore set up. The particular setup depicted is a wellhead known as a christmas tree 10. The christmas tree 10 is typically utilized on a newly producing well 8, where for the first 8 to 12 months the well is produced without a production tubing hanging in the well. Generally an operator will not place production tubing in the well until the natural pressure within the wellbore is reduced to a preset limit. The christmas tree shown in FIG. 1 includes a series of master valves such as the crown valve 12, the upper master valve 14, and the lower master valve 16. Below the master valves is generally a tubing head adapter 18. The tubing head adapter includes a number of lockdown pins 19, at least one test port 21 and a no-go 23.

One of the problems with running telemetry within a well 8 is that typically the telemetry cable has to pass through the master valves, such as the lower master 16, the upper master 14, and the crown valve 12. With the telemetry cable running through the master valves, any time that any of the master valves have to be closed either the telemetry must be pulled from the well 8 before a master valve is closed or the master valve will sever the telemetry cable as the master valve closes. The telemetry cable will then fall into the well 8 requiring that the severed telemetry cable be fished out and replaced once the master valve can be reopened.

There have been many instances where a master valve is closed due to some problem with the well 8 in which case there's no time available to remove the telemetry cable. In other cases the master valve may be closed simply due to human error where the valve is closed without the operator realizing that the telemetry cable passes through. Fishing out and replacing telemetry cable is both time-consuming and expensive. Consequently, even though the cost of telemetry gauges and cabling has declined to the point where using telemetry within a well is cost-effective, operators are hesitant to allow telemetry cable to run up through the christmas tree through the master valves and out of the well to the pack off at the top of the Christmas tree.

It is desirable to place telemetry, such as landing a pressure gauge on a TEC line, at some point within the well, where the well has no production tubing, and then terminating the telemetry cable at the base of the production christmas tree. In other words, operators desire to safely bring the data cable out of the christmas tree but below the master valves, so that the operators have full use of the master valves at all times.

FIG. 2 is a close-up of a portion of the Christmas tree 10 showing the location of the tubing hanger 30 within the tubing head adapter 18 and below the lower master valve 16. Generally the tubing hanger 30 is lowered into the tubing head adapter 18. The tubing hanger 30 forces the tubing into the no-go which prevents the tubing from being lowered further into the well thereby suspending the tubing from the tubing head adapter 18. The tubing hanger 30 incorporates O-ring seals on its OD. The test port 34 is utilized to verify that the O-ring seals are pressure tight. Circumferentially spaced lockdown pins 19 penetrate the tubing head adapter 18 from the exterior of the tubing head adapter 18 to engage the tubing hanger 30. Generally the tubing hanger 30 has recesses 32 formed into the outer surface of the tubing hanger 30 to allow the circumferentially spaced lockdown pins 19 a defined surface to grip the tubing hanger 30. With the tubing head adapter lockdown pins 19 engaged with the tubing hanger recesses 32 the tubing is prevented from pistoning out of the well 8 due to hydraulic forces within the well which tend to force the tubing upwards while the no-go 23 prevents the tubing from descending further into the well 8. In other words the tubing hanger 30 in conjunction with the tubing head adapter 18 locks the tubing in place within the well 8.

FIG. 3 depicts an embodiment of the invention where a tubing hanger 100, similar to tubing hanger 30 in FIG. 2, has been adapted to hang a TEC line 102 into the well. The tubing hanger 100 has an outer surface 104, inner bore 106, and at least one port 108. The port 108 is adapted to allow the TEC line 102 to be attached to tubing hanger 100, generally by compression fitting 110, although any known means of attachment would suffice. Grooves such as grooves 118 are provided both above and below circumferential recess 114 so that when tubing hanger 100 is placed within the tubing head adapter, O-rings within the O-ring grooves 118 of tubing hanger 100 will prevent pressurized fluid from entering the circumferential recess 114 and potentially leaking to the exterior of the christmas tree 10 through the ports provided for the lockdown pins 19.

TEC line 102 has an outer wall 103, typically stainless steel, although other material may be used. Generally the TEC line 102 protects and provides support for the insulated cable 112 within the TEC line 102. In the present embodiment the insulated cable 112 includes from the outer layer inwards, an outer insulator 119, a conductive layer 115, an inner insulator 117, and an inner core conductor 113. The TEC line 102 and the included insulated cable 112 penetrates into tubing hanger 100 via port 108 so that a portion of the insulated cable 112 is adjacent to circumferential recess 114. In the present embodiment the insulated cable 112 penetrates an insulated pad 107 that provides support for the insulated cable 112 as the penetrator pierces the insulated cable 112 generally through port 105. In other embodiments the support for the insulated cable 112 may be provided by the tubing hanger 100 in lieu of the insulated pad 107. In certain embodiments tubing hanger 100 may not include circumferential recess 114 and may incorporate ports for the individual TEC lines that penetrate the tubing hanger 100. While FIG. 3 depicts only a single TEC line 102 it is envisioned that multiple TEC lines may penetrate the tubing hanger.

FIG. 4 depicts a lockdown pin 200 configured to provide an electrically conductive pathway through the lockdown pin 200 to insulated cable 112 within port 108. The lockdown pin 200 has an outer housing 202 which in certain instances may be an insulating material such as a fiber composite. In those instances where outer housing 202 is not constructed of an insulating material the conductor 204 that penetrates outer housing 202 via interior pathway 206 generally includes an outer insulating layer 208 between the inner conductor 204 and the outer housing 202. Housing 202 generally includes interior pathway 206 to allow conductor 204 and its insulation layer 208 to be in communication with penetrator tip 212. The interior pathway 206 may provide a fluid leak path from tubing hanger 100 to the exterior of the tubing head adapter 18 therefore compression fitting 210 is provided to seal the conductor 204 and the outer insulating layer 208 to outer housing 202 of lockdown pin 200. Generally the lockdown pin 200 includes a penetrator tip 212 where the penetrator tip 212 is a conducting material and is attached to conductor 204.

In certain instances the lockdown pin 200 may be an insulating material which allows the conductor 204, insulator 208, and interior pathway 206 to be replaced with a solid conducting core within lock pin 200. With a solid conducting core the penetrator tip 212 is incorporated into the solid conducting core and potential fluid pathways through lock pin 200 are prevented.

FIG. 5 depicts an alternative embodiment of the penetrator tip 301. In this embodiment, the insulated cable 300, used in place of the insulated cable 112 shown in FIG. 3, may include alternating, generally coaxial, conducting and insulating layers, such as conductive layer 303, insulating layer 302, conductive layer 304, and insulating layer 306. In such an event the penetrator tip 301 is arranged to have alternating conducting an insulating layers, such as conducting portion 308, insulating portion 309, and conducting portion 310 spaced from the point of the tip 314 linearly along the tip to coincide with the distance of the insulating and conducting layers within the insulated cable 300. The conducting portions 308 and 310 of the penetrator tip 301 may include a further conductive path to the exterior of the penetrator such as by insulated wires 312 and 315. As the point of the tip 314 reaches the desired point within the insulating cable 300 the various conducting layers provided on the penetrator tip 301 will coincide with the conducting layers in the insulated cable 300 to provide multiple conductive pathways within a single cable from the TEC line 102 to the exterior of the tubing head adapter 18.

Referring now to FIGS. 2, 3, and 4, and operation tubing hanger 100 is placed within the tubing head adapter 18 and TEC line 102 is placed within tubing hanger 100. The lockdown pin 200 is inserted into the tubing head adapter in place of a standard lockdown pin adjacent to port 108 within the tubing hanger 100. As the lockdown pin 200 is inserted through the tubing head adapter 18 the penetrator tip 212 intersects insulated cable 112. The lockdown pin 200 is further inserted through the tubing head adapter 18 until penetrator tip 212 is in contact with the conducting material within insulated cable 112 thereby providing a conductive pathway from the insulating cable 112 within TEC line 102 through the tubing head adapter and to the exterior of the tubing head adapter 18 so that downhole sensors may be connected to surface instrumentation.

While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.

Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.

Claims

1. A device to allow access to a conductor comprising, a tubing encapsulated cable having at least one insulated conductor,a tubing hanger having at least one port in a lower end of the tubing hanger,wherein the insulated conductor is within the port,at least a second lateral bore through a side of the tubing hanger,wherein the second lateral bore intersects the port and the insulated conductor,a penetrator within the second lateral bore.

2. The device of claim 1 wherein, the penetrator has an insulated portion and a conductive portion

3. The device of claim 2 wherein, the penetrator insulated portion and conductive portion intersect the insulated conductor at corresponding insulated and conducting portions.

4. The device of claim 1 wherein, the penetrator and the insulated conductor provide a conductive pathway between a sensor and a surface display.

5. The device of claim 1 wherein, the penetrator prevents fluid flow thorough the second lateral bore.

6. The device of claim 1 wherein, the tubing hanger has a seal between the lower end of the tubing hanger and the second lateral bore.

7. The device of claim 1 wherein, the tubing encapsulated cable is sealed to the tubing hanger.

8. A method of providing electrical access to a wellbore, comprising, attaching a tubing encapsulated cable to a tubing hanger, wherein the tubing encapsulated cable has at least one insulated conductor,placing the insulated conductor within a port in the tubing hanger,intersecting the port and the insulated conductor with a lateral bore,inserting a penetrator within the lateral bore.

9. The method of claim 8 wherein, the penetrator has an insulated portion and a conductive portion

10. The method of claim 9 wherein, the penetrator insulated portion and conductive portion intersect the insulated conductor at corresponding insulated and conducting portions.

11. The method of claim 8 wherein, the penetrator and the insulated conductor provide a conductive pathway between a sensor and a surface display.

12. The method of claim 8 wherein, the penetrator prevents fluid flow thorough the second lateral bore.

13. The method of claim 8 wherein, the tubing hanger has a seal between the lower end of the tubing hanger and the second lateral bore.

14. The method of claim 8 wherein, the tubing encapsulated cable is sealed to the tubing hanger.