Abstract:
An apparatus for installing two sensing instruments and cables inside of a single tubing string in a wellbore for monitoring well conditions at two different locations includes an upper sensor attached to an inner sleeve seated at a first location in a ported outer sleeve in the tubing string. The upper sensor is allowed to be in pressure communication with the exterior of the tubing string at the first location. A second lower sensor is deployed on a pump down cup (PDC) assembly to a lower depth in the outer sleeve to allow fluid pressures to be monitored at a second location in the wellbore.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority from U.S. provisional patent application No. 61/880,071, filed Sep. 19, 2013, the entire disclosure of which is incorporated herein by reference. 
    
    
     FIELD OF THE INVENTION 
     The invention relates to a method and apparatus for installing two or more instrumentation sensors and cables inside of a single tubing string in a wellbore for monitoring well conditions at two or more locations in the wellbore. 
     BACKGROUND OF THE INVENTION 
     In many oil and/or gas producing wells, it is essential to measure parameters such as pressure and temperature at different points in the wellbore for safety, efficiency and production reasons. Typically, as shown in  FIG. 1 , in the past and in particular within various deviated wells that may have both vertical and horizontal sections, this has been achieved in a well casing  1  by installing a lower sensor  2  deployed at the end of a cable  3  to a depth near the toe  4  of the wellbore inside a tubing string  5 . In the past, in a typical scenario, an upper sensor  6  and cable  7  are clamped or banded onto the outside of a production tubing string  8  near the heel  9  of the wellbore. 
     During well servicing and other interventions that may be necessary throughout the life of a well, the production tubing string is often pulled out and re-installed at various times, which requires the upper sensor  6  and cable  7  that have been clamped to the outside of the production tubing string to be handled. Handling the sensor and cable adds to the complexity of each intervention and increases the time, costs, and the number of services involved in the intervention. Furthermore there is also a risk of damaging the sensor and cable during deployment and pulling of the production tubing string each time it is handled. 
     Moreover, by having the sensor and cable attached to the production tubing string, vibrations in the production tubing string created by pumps and other equipment can damage the sensor, resulting in inaccurate readings and/or the need to repair or replace the sensor. 
     A review of the prior art reveals several systems for measuring pressure in a wellbore. For example, U.S. Pat. No. 8,230,917 teaches a system and method for determining fluid invasion in reservoir zones using a sensor in coiled tubing. US 2004/0031319 teaches a system that displaces a predetermined fluid in order to measure pressure in a highly deviated or horizontal wellbore. US 2011/0229071 teaches a sensor system for taking measurements at a variety of locations in a wellbore using an optical fiber having a plurality of pressure sensors spaced apart on the optical fiber. US 2013/0048380 teaches a method for estimating one or more interval densities in a wellbore by acquiring first and second axially spaced pressure measurements in the wellbore using a tool string containing a number of spaced apart pressure sensors. U.S. Pat. No. 6,116,085 teaches a tubing string housing a plurality of pressure sensor assemblies connected to ports along the tubing string and a plurality of thermocouples operative to measure temperature at points along the tubing string in a wellbore. 
     In view of the foregoing, there is a need for an apparatus and method for deploying and installing instrumentation into a wellbore wherein subsequent handling of the instrumentation is minimized. There is also a need for an apparatus and method for deploying instrumentation to reduce vibrations on the instrumentation caused by pumps. There is a further need for an apparatus and method for deploying two or more instruments inside of a single tubing string, separate from the production tubing string, wherein measurements can be taken simultaneously at more than one location in the wellbore. There is also a need for such an apparatus and method to enable the monitoring of well conditions at more than one location in the wellbore that is simple to install. 
     SUMMARY OF THE INVENTION 
     In accordance with the invention, there is provided an apparatus for deploying at least two sensing instruments at different locations in a tubing string within a wellbore having an outer sleeve for operative connection to the tubing string; an inner sleeve connected to a first sensing instrument, the inner sleeve for engagement with the outer sleeve at a first location; and a pump down assembly connected to a second sensing instrument, the pump down assembly disengageably connected to the inner sleeve and moveable through the tubing string with the inner sleeve to the first location; wherein applying fluid pressure in the tubing string disengages the pump down assembly from the inner sleeve at the first location, and applying further fluid pressure in the tubing string moves the pump down assembly and the second sensing instrument through the tubing string to a second location. 
     In one embodiment, the first and second sensing instruments are pressure sensors and are in pressure communication at the first and second locations, respectively, with the exterior of the tubing string. 
     In one embodiment, the outer sleeve includes at least one outer sleeve port for enabling pressure communication between the first, sensing instrument and the exterior of the tubing string. 
     In another embodiment, the inner sleeve includes an inner sleeve port positioned adjacent the first sensing instrument and in pressure communication with the at least one outer sleeve port for enabling pressure communication between the first sensing instrument and the exterior of the outer sleeve. 
     In yet another embodiment, the inner sleeve further comprises an orifice located between the inner sleeve port and the first sensing instrument for enabling pressure communication between the first sensing instrument and the inner sleeve port. 
     In another embodiment, the system further comprises at least one seal located between the inner sleeve and the outer sleeve for sealing the first sensing instrument from the inside of the inner sleeve. 
     In a further embodiment, the interior of the outer sleeve further comprises a circumferential groove within which the at least one outer sleeve port is located, and wherein the groove defines a recess between the at least one outer sleeve port and the inner sleeve port for allowing fluid communication between the at least one outer sleeve port and the inner sleeve port regardless of the orientation of the inner sleeve port within the recess. 
     In yet another embodiment, the system further comprises a plurality of outer sleeve ports located in the circumferential groove, and the recess enables the plurality of outer sleeve ports to be in fluid communication with each other and with the inner sleeve port. 
     In one embodiment, the first and second sensing instruments are sensors for measuring fluid pressure and/or temperature. 
     In another embodiment, the pump down assembly is disengageably connected to the inner sleeve by a shear sub, and applying fluid pressure into the tubing string causes the shear sub to shear, disengaging the pump down assembly from the inner sleeve at the first location. 
     In a further embodiment, the pump down assembly includes a pump down cup for pumping the pump down assembly from the first location to the second location using fluid pressure. 
     In yet a still further embodiment, the pump down cup includes a heat dissolvable material. The heat dissolvable material may be urethane that melts at temperatures of around 100° C. 
     In another embodiment, the pump down cup includes a plurality of outwardly extending cups for engagement with the interior of the tubing string for enabling the pump down assembly to be pumped from the first location to the second location. 
     In a further embodiment, the pump down assembly further comprises a bullnose for guiding the pump down assembly through the tubing string. In one embodiment, the pump down assembly has an outer surface containing at least one groove for creating turbulence in a pumping fluid. In another embodiment, there are a plurality of longitudinal grooves in the pump down assembly outer surface. 
     In one embodiment, the first and second sensing instruments are attached to a first and second cable, respectively, that extend from the sensing instruments to a well surface. 
     In yet another embodiment, the outer sleeve further comprises a restriction at the second location for landing the pump down assembly at the second location in the tubing string. 
     In one embodiment, the system includes at least one perforation in the tubing string adjacent the second sensing instrument at the second location for enabling fluid communication between the second sensing instrument and the exterior of the tubing string. 
     In another aspect, the invention provides a method for deploying two sensing instruments at different locations in a tubing string within a wellbore comprising the steps of: a) operatively connecting an outer sleeve to a tubing string and running the outer sleeve and tubing string into the wellbore; b) running an inner sleeve and a pump down assembly down the tubing string, the inner sleeve connected to a first sensing instrument and the pump down assembly connected to a second sensing instrument, wherein the pump down assembly is disengageably connected to the inner sleeve; c) seating the inner sleeve and first sensing instrument in the outer sleeve at a first location in the tubing string; d) applying fluid pressure into the tubing string to disengage the pump down assembly from the inner sleeve at the first location; and e) applying further fluid pressure into the tubing string to pump the pump down assembly and second sensing instrument through the tubing string from the first location to a second location; wherein the first and second sensing instruments are in pressure communication with the exterior of the tubing string at the first and second locations, respectively. 
     In another embodiment, in step d), the pump down assembly is disengaged from the inner sleeve by shearing. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The invention is described with reference to the accompanying figures in which: 
         FIG. 1  is a schematic of a horizontal wellbore illustrating a typical dual sensor installation in accordance with the prior art. 
         FIG. 2  is a schematic of a horizontal wellbore illustrating a dual sensor installation scenario in accordance with one embodiment of the invention. 
         FIG. 3  is a cross-sectional side view of a dual instrumentation apparatus with an inner sleeve seated in an outer sleeve, and a pump down cup assembly (PDC) in the run-in position wherein the pump down cup assembly is attached to the inner sleeve at a first location in the tubing string in accordance with one embodiment of the invention. 
         FIG. 4  is a cross-sectional side view of a dual instrumentation apparatus with the inner sleeve seated in the outer sleeve, and the pump down cup assembly in the set position wherein it has been released from the inner sleeve and pumped to a second location in the tubing string in accordance with one embodiment of the invention. 
         FIG. 5  is a side view of the outer sleeve at the first location in the tubing string with the internal profile illustrated in accordance with one embodiment of the invention. 
         FIG. 6A  is a top view of the inner sleeve showing the orifice and the upper sensor at the first location in the tubing string in accordance with one embodiment of the invention. 
         FIG. 6B  is a cross-sectional side view of the inner sleeve at  6 B- 6 B of  FIG. 6A  in accordance with one embodiment of the invention. 
         FIG. 7A  is a side view of a shear sub with an internal profile illustrated in accordance with one embodiment of the invention. 
         FIG. 7B  is a bottom view of the shear sub with the internal profile illustrated in accordance with one embodiment of the invention. 
         FIG. 8  is a side view of the pump down cup (PDC) mandrel in accordance with one embodiment of the invention. 
         FIG. 9  is a side view of the pump down cup (PDC) with the internal profile illustrated in accordance with one embodiment of the invention. 
         FIG. 10A  is a side view of a retainer nut with the internal profile illustrated in accordance with one embodiment of the invention. 
         FIG. 10B  is a bottom view of the retainer nut with the internal profile illustrated in accordance with one embodiment of the invention. 
         FIG. 11  is a cross-sectional side view of the PDC assembly in the set position at the second location in the tubing string, showing the flow of pump down fluid from the interior to the exterior of the outer sleeve in accordance with one embodiment of the invention. 
         FIG. 12  is a cross-sectional side view of the PDC assembly in the set position at the second location in the tubing string after the PDC has dissolved in accordance with one embodiment of the invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     With reference to the figures, a dual instrumentation apparatus  10  and method of deploying the apparatus in a wellbore are described. 
       FIG. 2  is a schematic of a horizontal wellbore  1  showing one embodiment of the dual instrumentation apparatus  10 . The apparatus  10 , contained within a well casing  1 , comprises a tubing string  5  containing two cables  3 ,  7  containing wires that extend from instrumentation at the surface of the well to a lower sensor  2  and an upper sensor  6  in the apparatus. In  FIG. 2 , the upper sensor  6  is located near the heel  9  of the wellbore at a first location, and the lower sensor  2  is positioned further downhole at a second location near the toe  4  of the wellbore. In alternate embodiments, the upper and lower sensors may be positioned at other locations in the wellbore. For example, the lower sensor may be located further uphole instead of at the end of the tubing string. Alternatively, the lower sensor may be positioned out the end of the tubing string. 
       FIG. 2  illustrates the dual instrumentation apparatus installed in a horizontal wellbore, however the apparatus can also be installed in other types of wellbores such as vertical and deviated wellbores. 
     Referring to  FIG. 3 , the apparatus comprises an inner sleeve  12  seated inside an outer sleeve, which is integral with the utility tubing, and a pump down cup (PDC) assembly  16  attached to the inner sleeve. The entire PDC assembly is moveable between a run-in position, shown in  FIG. 3 , and a set position, shown in  FIGS. 4 and 11 . The upper sensor  6  is attached to the inner sleeve, and the lower sensor is retained on the PDC assembly. 
     Outer Sleeve 
     Referring to  FIG. 5 , outer sleeve includes an outer surface  14   g,  an inner surface  14   a  defining a cavity  14   d,  a plurality of ports  14   b,  an inner shoulder  14   e,  and a groove  14   f.    
     The outer sleeve inner shoulder  14   e  is located on the inner surface  14   a  of the cavity  14   d  to provide a landing point for the inner sleeve  12 . The ports  14   b  extend through the outer sleeve around the outer sleeve circumference in the groove  14   f . When the inner sleeve is landed in the outer sleeve, the groove  14   f  creates a recess  14   i  (shown in  FIGS. 3 and 4 ) between the inner and outer sleeves to allow all the ports  14   b  to be in pressure communication with each other and with a port  12   b  on the inner sleeve. The groove and recess allow the inner sleeve port to be orientated in any manner within the recess and be in fluid communication with all the outer sleeve ports. The multiple ports also ensure fluid communication between the upper sensor and the exterior of the outer sleeve is maintained in the event that one or more of the ports  14   b  becomes plugged. 
     Inner Sleeve 
     Referring to  FIGS. 6A and 6B , the inner sleeve  12  includes an outer surface  12   g,  an inner surface  12   c  defining a cavity  12   d,  an upper end  12   i,  a lower end  12   j,  an orifice  12   a,  a port  12   b,  an inner shoulder  12   e,  an outer shoulder  12   k,  seal recesses  12   f , retainer holes  12   h,  and a protrusion  12   m.    
     The orifice  12   a  extends longitudinally from the inner sleeve upper end between the outer surface and the inner surface. The upper sensor  6  is connected to an upper end  12   m  of the orifice and is in sealing engagement with the orifice. In one embodiment, shown in  FIG. 6B , the orifice extends beyond the upper end of the inner sleeve for ease of connection of the upper sensor. That is, the extension of the orifice upper end allows the upper sensor and cable to be threaded (for example) onto the extension using a wrench or similar device. 
     The port  12   b  extends from the orifice to the outer surface of the inner sleeve to allow the upper sensor to be in pressure communication with the exterior of the outer sleeve. The seal recesses  12   f  are located in the outer surface of the inner sleeve and contain sealing elements  28 , such as O-rings, to seal the port and upper sensor from the inside of the inner and outer sleeves. The outer shoulder  12   k,  located on the outer surface of the inner sleeve, abuts with the outer sleeve inner shoulder  14   e  for landing the inner sleeve  12  within the outer sleeve  14  at the first location. The inner shoulder, located on the inner surface of the inner sleeve, allows for a shear sub  22  (described below) to be positioned in the inner sleeve cavity. The shear sub is affixed within the cavity using shear pins or screws that are installed through the inner sleeve retainer holes  12   h  and corresponding shear sub retainer holes. 
     Pump Down Cup (PDC) Assembly 
     Referring to  FIGS. 3 and 4 , the PDC assembly  16  includes a PDC mandrel  18 , a PDC  20 , a shear sub  22 , and a retainer nut  26 . 
     Referring to  FIG. 8 , the PDC mandrel  18  is the core of the PDC assembly  16  and includes an upper end  18   a,  a central region  18   b  a lower end  18   c , an upper hole  18   d  and a lower hole  18   e.  Preferably, the lower sensor  2  is threaded onto the upper end of the mandrel. The shear sub  22  is retained on the central region  18   b,  near the upper end  18   a,  and held in place using pins or screws inserted through the upper hole  18   d . The PDC  20  is also retained on the central region, below the shear sub  22 . The retainer nut  26  is connected to the lower end  18   c  of the PDC mandrel and held in place using pins or screws inserted through the lower hole  18   e.    
     Referring to  FIGS. 7A and 7B , the shear sub  22  of the PDC assembly includes a sleeve  22   c  having an outer surface  22   d,  an internal bore  22   e,  an upper end  22   b,  a lower end  22   f,  longitudinal grooves  22   g,  shear pins  22   a  retained within shear pin holes  22   h,  a retainer hole  22   i,  and a shear sub seal groove  22   j.  At least a portion of the shear sub is retained within the inner sleeve  12  when the PDC assembly is in the run-in position at the first location in the outer sleeve, and the shear pins  22   a  extend into the inner sleeve retainer holes  12   h.  When pressure is applied to the shear sub upper end  22   b,  the shear pins  22   a  shear, releasing the shear sub from the inner sleeve and allowing the entire PDC assembly and lower sensor  2  to be pumped downhole into the set position at the second location. The longitudinal grooves  22   g  on the shear sub outer surface  22   d  create turbulence in the pump fluid to aid in pumping the PDC assembly downhole. The PDC mandrel  18  is inserted into the shear sub internal bore  22   e  and secured in place using pins or screws extending through the shear sub retainer hole  22   i . The shear sub seal groove  22   j  is located upstream of the shear pins  22   a  and contains a shear sub seal (not shown) for preventing fluid leakage around the shear sub outer surface when the PDC assembly is in the run-in position. 
     Referring to  FIG. 9 , the PDC  20  includes a sleeve  20   a  having an inner bore  20   b  and a plurality of cups  20   c  each having an upper surface  20   d  and an outer surface  20   c . The PDC is used to pump the PDC assembly downhole after the shear sub has sheared by applying fluid pressure onto the upper surface  20   d  of the cups  20   c , pushing the PDC assembly downhole. The outer surface of each cup is in engagement with the outer sleeve inner surface  14   a  during run-in of the dual instrumentation apparatus, and then in engagement with the internal diameter of the tubing string after the PDC assembly has been sheared from the inner mandrel with pump pressure and is being pumped downhole. Other shapes and configurations for the PDC may be used as would be known to one skilled in the art. In one embodiment, a portion of the PDC is made from a material that melts or dissolves at high temperatures to enable subsequent fluid flow around the PDC if desired. In this embodiment, a portion of the PDC comprises a dissolvable material such as urethane may be incorporated, which melts at a temperature of 108° C. 
     Referring to  FIGS. 10A and 10B , the PDC retainer nut  26  includes a body  26   a  having an outer surface  26   b,  a bore  26   d,  an upper end  26   c,  a bull nose  26   g,  a retainer hole  26   e,  and a plurality of grooves  26   f.  The PDC mandrel  18  is inserted into the bore  26   d  and attached via a pin or screw inserted through a hole  26   e  in the retainer nut body that lines up with the PDC mandrel lower hole  18   e.  The bull nose  26   g  guides the PDC assembly down the tubing string and provides protection for the rest of the PDC assembly and lower sensor. Similar to the shear sub  22 , the PDC retainer nut grooves  26   f  create turbulence in the pump-down fluid to aid in the pumping down process in order to move the PDC assembly from the run-in position to the set position, and from the first location to the second location in the tubing string. 
     Setting the Pump Down Cup (PDC) Assembly 
       FIGS. 11 and 12  illustrate a lower section  14   k  of the tubing string wherein the PDC assembly and the lower sensor are set at the second location. The lower section  14   k  of the tubing string is a specialized section or sleeve that includes a restriction in the tubing string that prevents the PDC assembly from going past the desired location and that includes perforations to permit fluid flow through the lower section  14   k.  In one embodiment, the restriction is an internal diameter restriction in the tubing string. In another embodiment, there is a bar (not shown), such as a tag bar, extending across the internal cavity of the tubing string to act as a restriction. Other suitable mechanisms for setting the PDC assembly and lower sensor at the desired location are known to one skilled in the art. 
     As noted above, the lower section  14   k  of the tubing string also includes perforations  14   h  for allowing the lower sensor to be in fluid and pressure communication with the exterior of the tubing string. 
     Method 
     In operation, the tubing string is prepared by connecting the lower section  14   k  to the end of the tubing string as well as connecting the outer sleeve  14  to the tubing string at a desired position. The tubing string is run into a wellbore, typically such that the lower section  14   k  is adjacent the toe and the outer sleeve  14  is adjacent the heel of the wellbore thereby defining the first and second positions. At the well surface. the upper sensor cable  7  and upper sensor  6  are attached in the inner sleeve orifice  12   a,  and the lower sensor  2  and lower sensor cable  3  are attached to the PDC mandrel  18 . The PDC assembly is connected to the inner sleeve, and the inner sleeve and PDC assembly are pumped into the tubing string until they land at the first location in the outer sleeve, 
     Upon seating of the inner sleeve in the outer sleeve, pumping fluid pressure is increased, shearing the shear sub  22  and releasing the PDC assembly from the inner sleeve. Pumping is continued, causing the PDC assembly and attached lower sensor  2  and cable  3  to move downhole to the second location where the restriction  32  prevents the PDC assembly from moving beyond the desired depth/location. Upon seating the PDC assembly in the outer sleeve at the second location, pumping is stopped and the PDC is now in the set position at the second location. The pump down fluid flows out of the outer sleeve cavity  14   d  through the perforations  14   h  where it is pumped back to the surface for recovery. 
     In one embodiment, after the PDC assembly has reached the desired depth/location and is in the set position, high temperature fluid or steam is injected into the tubing string to cause the PDC to melt or dissolve.  FIG. 12  illustrates the PDC assembly in the set position after the PDC has melted/dissolved. 
     Alternative Uses for the Dual Instrumentation Apparatus 
     While the dual instrumentation apparatus has been described as deploying an upper and lower sensor for measuring pressure and temperature of wellbore fluid, the apparatus may be used for other purposes. For example, the apparatus can be used to inject substances into the well at different depths. Instead of cables containing wires attached to sensors there are hollow cables into which chemicals or other substances are injected that would then be introduced to different depths in the wellbore. In another embodiment, instead of measuring pressure at a first and second location using sensors and cables, “bubble tubes” are used to monitor downhole pressure at the first and second location. Bubble tubes, as known to one skilled in the art, are hollow cables that allow pressure access from one end of the tube to the other end of the tube. 
     In a further embodiment, the apparatus can be used for taking fluid samples from different depths in the well. Again, in this embodiment the system would not include sensors but rather just hollow cables. 
     Although the present invention has been described and illustrated with respect to preferred embodiments and preferred uses thereof, it is not to be so limited since modifications and changes can be made therein which are within the full, intended scope of the invention as understood by those skilled in the art.