Abstract:
An optical positioning monitoring system is disclosed. The system has an optical sensing member disposed on a wellbore pipe, such as the tubing or production casing. When a tool comprising an actuating member acts on the optical sensing member, an optical signal is returnable from the optical sensing member indicating the position of the tool. The optical sensing member may include an optical fiber and/or any known optical sensors. The actuating member can be a force applicator or a heat applicator. Alternatively, the optical sensing member can be located on the tool and the actuating member can be located on the tubing or production casing.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
   The present application claims the benefit of U.S. Provisional Patent Application No. 60/660,700 filed on Mar. 12, 2005, the entire contents of which are specifically incorporated herein by reference in its entirety. 

   BACKGROUND 
   Optical Fibers have become the communication medium of choice for long distance communication due to their excellent light transmission characteristics over long distances and the ability to fabricate such fibers in lengths of many kilometers. The transmitted light can also power the sensors, thus obviating the need for lengthy electrical wires. This is particularly important in the petroleum and gas industry, where strings of electronic sensors are used in wells to monitor downhole conditions. 
   As a result, in the petroleum and gas industry, passive fiber optic sensors are used to obtain various downhole measurements, such as, pressure or temperature. A string of optical fibers within a fiber optic system is used to communicate information from wells being drilled, as well as from completed wells. For example, a series of weakly reflecting fiber Bragg gratings (FBGs) may be written into a length of optical fiber, such as by photoetching. As is known in the art, the distribution of light wavelengths reflected from an FBG is influenced by the temperature and strain of the device to which the FBG is attached. An optical signal is sent down the fiber, which is reflected back to a receiver and analyzed to characterize the length of optical fiber. Using this information, downhole measurements may be obtained. 
   Due to the depth of typical oil and gas wells, one or more of the optical sensors are typically spliced into a length of optical transmission fiber that extends from the surface to the desired depths. As such, it is desirable to take measurements at various depths of the well. Additionally, while drilling optical sensors can be added to the monitoring system for adequate coverage of the well. 
   For some applications, it is important to determine the precise location of a tool or the open/closed status of a valve with optical sensors, which heretofore has not been disclosed in the art. 
   SUMMARY OF THE INVENTION 
   The above described and other problems are overcome by the present optical positioning monitoring system, which comprises an optical sensing member disposed on a wellbore pipe, such as the tubing or production casing. When a tool comprising an actuating member acts on the optical sensing member, an optical signal is returnable from the optical sensing member indicating the position of the tool. The optical sensing member may include an optical fiber and/or any known optical sensors. The actuating member can be a strain, pressure, force, temperature, electric and/or magnetic field applicator. 
   Alternatively, the optical sensing member can be located on the tool and the actuating member can be located on the tubing or production casing. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     In the accompanying drawings, which form a part of the specification and are to be read in conjunction therewith and in which like reference numerals are used to indicate like parts in the various views: 
       FIG. 1  is a schematic representation of an exemplary well showing a plurality of optical position sensors with certain details omitted for clarity; 
       FIGS. 2A ,  2 B and  2 C are expanded partial cross-sectional views of different configurations of the optical position sensor; 
       FIGS. 3A ,  3 B and  3 C are cross-sectional view of the different embodiments of the optical sensors; and 
       FIG. 4  is an expanded partial cross-sectional view of another embodiment of the optical position sensor. 
   

   DETAILED DESCRIPTION 
   As illustrated in the accompanying drawings as discussed in detail below, the present disclosure relates to an optical position sensor for measuring the location or position of a downhole tools or oilfield equipment such as packers, fishing tools, perforation gun, logging tools, sliding sleeves, inflatable packers, etc., or whether that a surface or subsurface valve is open or closed. The present optical position sensor can determine the linear location of the tool relative to the wellhead or the ground surface and the angular location within the wellbore. 
   The present optical position sensor may utilize known optical sensors, including but not limited to FBGs, extrinsic Fabry-Perot interferometers (EFPI), intrinsic Fabry-Perot interferometers (IFPI), Mach-Zehnder inferometers, Sagnac interferometers, Michelson type sensors, backscatter, etc., and known sensing techniques including but not limited to optical frequency domain reflectometry (OFDE), optical time domain reflectometry (OTDR), optical coherence domain reflectometry (OCDR) and spectral interrogation. The sensors can be distributed throughout the optical fiber and are distinct or spatially separated from each other, such as distributed discrete sensors (DDxS), which include distributed discrete temperature sensors (DDTS), distributes discrete strain sensors (DDSS) or distributed discrete pressure sensors (DDPS). Alternatively, the sensors can be distributed throughout the optical fiber and are continuous, i.e., not spatially separated from each other, such as distributed temperature sensors (DTS) or distributed strain sensors (DSS). 
   Additionally, the present optical position sensor can also utilize optical fibers without sensors, i.e., using Raleigh backscattering as described in U.S. Pat. No. 6,545,760, or Brillouin back scattering as disclosed in U.S. Pat. No. 5,515,192, to ascertain the location of the tools. The present optical position sensor can also utilize the Raman effect for sensing changes temperature on the optical fiber by measuring the changed wavelength of emitted light as describes in U.S. Pat. No. 5,765,948. These references are incorporated by reference in their entireties. 
   Referring to  FIG. 1  and in accordance to one exemplary embodiment, at least one position sensor  10  is disposed in wellbore  12 . An unlimited number of position sensors  10  can be deployed depending on the particular application or need. Position sensors  10  can be placed inside tubing  14 , outside tubing  14 , on production casing  16  or on any location within wellbore  12 . Position sensors  10  are connected to surface instrumentation unit (SIU)  18  via optical cable(s) (not shown). Optionally, the optical cable is also connected to vent box  20  to relieve potential pressure build up with in the cable. Suitable optical cables include single mode fibers, multimode fibers, polarization maintaining fibers, plastic fibers and coreless fibers. 
   In another exemplary embodiment, position sensor  10  is located at convenient locations in the wellbore, such as proximate to hydrocarbon production zones  22 ,  23 ,  24 , packer  26 , subsurface safety or shutoff valve  28 , inflatable packer  30 , and/or the bottom of the hole. The locations of these elements are important in the management, operation and safety of oil and gas wells, water/gas injection wells for secondary or tertiary recovery, geothermal wells, etc. 
   Referring to  FIG. 2A , position sensor  10  can be a tubular sleeve disposed within a section of pipe, such as tubing 14  or production casing  16 . As tool  32  is lowered into wellbore  12 , one or more arms  34  come into contact with position sensor  10 . Arms  34  can be rigidly affixed to tool  32 , or arms  34  can be flexible or spring loaded. Alternatively, arms  34  can be folded toward the body of tool  32  for easy insertion into the wellbore, and are extended when tool  32  reached the desired location. Arms  34  essentially are forced applicators, and when arms  34  contact sensor  10  they apply a force to sensors  36  that are disposed on sensor  1 - as illustrated in  FIGS. 3A-3C . Sensors  36  are connected to each other by optical fiber  38 . As is known in the art, the applied force stresses sensors  36  and when interrogated by an optical signal, the applied stress alters the signal returned to SIU  18  indicating an accurate position of tool  32 . 
   In an alternative exemplary embodiment, arms  34  generate heat for example by embedded heating elements. When arms  34  comes at least proximate to position sensor  10  the heat changes the interrogating optical signal and SIU  18  can detect this change in the returned signal to obtain an accurate position of tool  32 . One advantage of using a heat applicator is that physical contact between arms  34  and position sensor  10  is unnecessary thereby reducing wear and tear on the sensors. 
   FBGs, EFPI, an IFPI are some of the known optical sensors that react to stress/applied force or changes temperature and, thus, are the preferred sensors. More preferably, FBGs are used due to the ease in manufacturing of these gratings by photoetching. Other sensors such as silicon sensors that are optically sensitive to heat can be used. Any optical sensors that respond to stress/strain or temperature are suitable, including those described above. As illustrated in  FIGS. 3A-3C , sensors  36  are DDxS sensors, e.g., DDTS, DDPS and/or DDSS sensors. However, these sensors can also be DTS or DSS type sensors discusses above. 
   In another exemplary embodiment, sensors  36  are omitted and only optical fibers  38  are present in optical sensor  10 . The signal returnable to SIU  18  are Rayleigh backscattering signals that can be processed to pinpoint the location of tool  32 , as discussed in the &#39;760 patent previously incorporated above. Likewise, Brillouin backscattering and Raman effect can also be used to locate tool  32 . 
   In the exemplary embodiment shown in  FIG. 3A , sensors  36  and fiber  38  are arranged longitudinally relative to the wellbore and longitudinal location of tool  32  can be ascertained. In the exemplary embodiment shown in  FIG. 3B , sensors  36  and fiber  38  are arranged in a serpentine or sinusoidal fashion and the angular position of tool  32  can also be ascertained. Likewise, sensors  36  and fiber  38  can be arranged in a helical fashion to provide both longitudinal and angular locations of tool  32 . 
   Alternatively, as shown in  FIG. 2B  position sensor  10  can be positioned on the outside of the pipe to fix the position of the tools that are lowered into the annulus between tubing  14  and casing  16 . In this case, sensors  36  and fiber  38  are arranged on the outside surface of position sensor  10 . Additionally, sensor  36  and fiber  38  are arranged on both the inside and outside surfaces of position sensor  10 , as illustrated in  FIG. 2C . In one example, one entire section of tubing or casing can be converted into position sensor  10 . The locations of position sensors  10  can be pre-determined by calibration for example by OTDR, Rayleigh scattering or other known techniques and these positions can be stored in SIU  18 &#39;s memory. 
   In another exemplary embodiment illustrated in  FIG. 4 , position sensor  10  is arranged on tool  32  and arms  34  are affixed on either tubing  14  or casing  16 . The fixed positions of arms  34  can be pre-determined by another optical tool or by standard logging tools. When tool  32  / position sensor  10  contact arms  34 , the returned optical signal to SIU  18  would indicate the position of the tool similar to the process described above. Arms  34  can be disposed on the inside or outside of tubing  14  or on casing  16 , depending on the particular application. Sensors  36  and/or fiber  38  can be arranged in a helical fashion as shown to provide longitudinal and angular position of tool  32 , or in a sinusoidal or linear fashion similar to those shown in  FIGS. 3A and 3B . One advantage of this embodiment is that the optical cable-connecting sensor  10  to SIU  18  or a mobile SIU can be lowered along with tool  32 . 
   The precise location of the production zones is vitally important to properly perforating the wellbore for production. As known in oil and gas production, a production zone may comprise a gas stratum on top of an oil stratum and/or a water stratum. Perforating too low can cause water to flood the well and perhaps adversely affect the porosity and permeability of formation rocks. Perforating too close to the interface between the strata can cause water to “cone” or finger into the oil stratum or oil to “cone” or finger into the gas stratum thereby reducing the ultimate hydrocarbon recovery from the well. The perforating tool or gun is typically hung from a long tube or wire. The tube and wire can stretch under their own weight and the weight of the tool, and the thermal expansion caused by heat in the wellbore can also stretch them. The actual position the tool can be accurately recalibrated by presently described position sensor  10 . 
   Additionally, it is very useful to know whether a valve, such as a surface valve or a subsurface safety valve  28 , is open or closed. Subsurface safety valves are designed to provide emergency fail-safe closure to stop the flow from a wellbore if the surface valves or the wellhead are damaged or inoperable. Subsurface safety valves are essential in offshore wells or in wells that produce hazardous gases, such as H 2 S. In normal operation, subsurface safety valves are open to allow flow of produced fluids, but in an emergency automatically closes to stop the flow. Typically, the subsurface safety valve closes when the flow rate exceeds a predetermined value. These valves can be controlled hydraulically from the surface or are designed to operate without human intervention. Typically, the closure mechanism is a rotating ball or a hinged flapper. The ball valve comprises a sphere with a large hole through it. When the hole is aligned with the direction of flow the valve is open, and when the hole is turned 90° the valve is closed. Flapper valve comprises a hinged, biased flapper that is held open (or in the down position) by a movable flow tube. When the tube is moved upward the flapper closes to shut the valve. It is desirable to be able to periodically test these valves to determine whether they are operational. As described above, position sensor  10  of the present invention can detect the angular position of a ball valve or the longitudinal location of the flapper valve. Subsurface safety valves are commercially available from Baker Oils Tools, among other oil services companies. 
   It is also useful to know whether inflatable packer  30  deployed at the correct location. Inflatable packers when deflated are sufficiently small to fit through the tubing and enter the larger casing, as shown in  FIG. 1 . After reaching the casing below the tubing, it can be inflated to isolated one production zone from another to affect selective production. After being inflated, inflatable packer  30  exerts pressure on position sensor  10  to confirm proper deployment. Inflatable packers are fully discussed in “Inflatable Packing Element with Separator Device” by G. McKenzie available at http://os.pennnet.com//Articles/Article_Display.cfm?Section=ARCHI&amp;ARTICLE_ID=159792&amp;VERSION_NUM=1. This reference is incorporated herein by reference in its entirety. 
   As used herein, tool  32  can be any tool or equipment used downhole in wellbore  12  or on the wellhead. Non-limiting examples of tool  32  include, but are not limited to fishing tools, perforating guns, subsurface safety valves, sliding sleeves, packers, inflatable packers, etc. 
   While the present optical position sensor is described in terms of exemplary embodiments, it is appreciated that numerous modifications and other embodiments may be devised by those skilled in the art. Therefore, it will be understood that the appended claims are intended to cover all such modifications and embodiments, which would come within the spirit and scope of the present invention.