Abstract:
A fiber optic sensor assembly for use on a sub-sea pipeline. The fiber optic sensor assembly is coupled to remotely located equipment by fiber optic cable(s) which extend outside of the pipeline. The fiber optic sensor assembly is affixed to a mounting point on the pipeline. The mounting point is a pipe section having an internal conduit and at least one layer that surrounds the internal conduit for protection and insulation of the internal conduit. A segment of the pipe section has a portion of such layer(s) removed or omitted to define an annular recess. When installed, the assembly has two semi-cylindrical halves that are positioned with the annular recess and coupled together to thereby surround and embrace the segment of the pipe section. The assembly houses a length of optical fiber that is coupled to at least one externally accessible fiber optic connector.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates to sub-sea pipelines carrying petroleum gas or an oil-gas mixture. More particularly, the invention relates to fiber optic sensors for use on sub-sea pipelines as well as methods for deploying the sensors. 
     2. Description of Related Art 
     It has been known for many years that fiber optic waveguides can be used to measure temperature.  FIG. 1  schematically illustrates a system that employs a fiber optic waveguide to measure temperature. A pulsed-mode high power laser source  1  launches a pulse of light through a directional coupler  3  and along a fiber optic waveguide  2 . The fiber optic waveguide  2  forms the temperature sensing element of the system and is deployed where the temperature is to be measured. As the pulse propagates along the fiber optic waveguide  2  its light is scattered through several mechanisms including density and composition fluctuations (Rayleigh scattering) as well as molecular and bulk vibrations (Raman and Brillouin scattering, respectively). Some of this scattered light is retained within the core of the fiber optic waveguide and is guided back towards the source  1 . This returning signal is split off by the directional coupler  3  and sent to a receiver  4 . In a uniform fiber, the intensity of the returned light shows an exponential decay with time (and reveals the distance the light traveled down the fiber optic waveguide based on the speed of light in the fiber optic waveguide). Variations in such factors as composition and temperature along the length of the fiber optic waveguide  2  show up in deviations from the “perfect” exponential decay of intensity with distance. The receiver  4  typically employs optical filtering  5  that extracts backscatter components from the returning signals. The backscatter components are detected by a detector  6 . The detected signals are processed by the signal processing circuitry  7  which typically amplifies the detected signals and then converts (e.g. by a high speed analog-to-digital converter) the resultant signals into digital form. The digital signals may then be analyzed to generate a temperature profile along the length of the fiber optic waveguide  2 . This type of temperature sensing is called distributed temperature sensing (DTS) because it measures a temperature profile along the length of a fiber optic waveguide. 
     Another type of fiber optic sensing is called point sensing. In point sensing, a Bragg grating is etched into a fiber optic waveguide at a desired location. The Bragg grating is designed to reflect light at a particular wavelength. Measurements of wavelength shift of the reflected light can be used to measure temperature or pressure or strain. Multipoint sensors have multiple spaced apart Bragg gratings, which are typically etched to reflect different wavelengths. Analysis of the wavelength shifts of the reflected light can sense conditions at multiple discrete locations along the fiber optic waveguide. Such “point sensing” functionality is described in detail in U.S. Pat. No. 6,097,487, herein incorporated by reference in its entirety. 
     A typical sub-sea pipeline is composed of a pipe surrounded by one or more layers of protective/insulating material, for example a steel pipe covered with a polymer sheath and then encased in concrete. For fiber optic sensing applications, optical fiber is placed between the pipe and the first layer of protective/insulating material. The sub-sea pipeline is assembled on a barge at sea from sections that are bolted and/or welded together. As sections of pipe are joined together, the ends of the optical fiber for the adjacent pipe sections must be joined to each other. Although such a sub-sea pipeline provides for fiber optic sensing, it suffers from several shortcomings, which include: (i) increased costs and difficulties in integrating the optical fiber as part of the pipeline sections; and ii) increased deployment times and costs as well as maintenance times and costs associated with ensuring the integrity and operation of the fiber optic couplings between section joints of the pipeline. 
     BRIEF SUMMARY OF THE INVENTION 
     It is therefore an object of the invention to provide a fiber optic sensor for a sub-sea pipeline. 
     It is another object of the invention to provide such a fiber optic sensor which can be used for temperature sensing as well as other sensing applications for a sub-sea pipeline. 
     It is also an object of the invention to provide such a fiber optic sensor which can be effectively and efficiently deployed and maintained in conjunction with deployment and maintenance of a sub-sea pipeline. 
     It is also an object of the invention to provide a fiber optic sensor which has an operational lifespan comparable to a sub-sea pipeline. 
     In accord with these objects, which will be discussed in detail below, the present invention provides a fiber optic sensor assembly (referred to below as a “sensor pad”) that is mounted to a sub-sea pipeline. The sensor pad has two parts which are clamped together to form a generally annular structure which embraces a portion of the sub-sea pipeline. One of the two parts supports a housing that contains a length of a fiber optic waveguide encapsulated in a resin and terminating in at least one externally-accessible optical connector. 
     According to an illustrated embodiment, the sub-sea pipeline is made of sections that are joined together. The sections include an internal pipe (preferably made of steel) that is wrapped in one or more layers of protective/insulating material (e.g., an intermediate polypropylene layer and an outer layer of concrete). A portion of the protective/insulating material is removed or omitted for one or more predetermined pipeline sections to form an annular recess in such pipeline section(s). The annular recess provides an exposed area that is adapted to receive a sensor pad that is attached thereto. The housing of the sensor pad is operably disposed adjacent the exposed area such that the fiber optic waveguide disposed therein is in thermal contact with the internal pipe of the pipeline section. 
     Prior to attaching the sensor pad, two shrouds can be affixed (preferably by adhesive or by mechanical fixation such as an interference fit) to the opposed edges of the annular recess in the pipe section. The shrouds provide an environmental seal for the portions of the pipeline section exposed at the edges of the annular recess as well as an environmental seal between the exposed area of pipeline section and the contact area of the sensor pad. A first set of toroidal sealing rings are installed between the respective shrouds and the exposed outer diameter surface that defines the recess. A second set of toroidal sealing rings are installed between the shrouds and the contact surfaces of the sensor pad. For alternate embodiments where the shrouds are not used, the first set of sealing rings can be omitted and the second set of sealing rings can be installed between the contact surfaces of the sensor pad and the exposed outer diameter surface that defines the recess. 
     The sensor pads are coupled to remotely-located equipment by sub-sea certified fiber optic cables which run outside of and along the sub-sea pipeline. Some of the sensor pads can be coupled to one another in an in-line configuration by sub-sea certified fiber optic cables which run outside of and along the sub-sea pipeline. The sensor pads are provided with either wet-mate or dry-mate optical connectors and the cables are provided with a corresponding connector. Preferably, the sensor pads are attached to the pipeline at predetermined locations as the pipeline is being deployed from the construction barge. If dry-mate connectors are used, the cable is connected to the sensor pad prior to deploying it underwater. If wet-mate connectors are used, the cables are coupled to the sensor pads by divers or an ROV (remotely operated vehicle) after the pipeline is deployed. Above-water fiber connections can be made using standard fiber optic connectors. 
     The remote equipment preferably provides for distributed fiber optic temperature sensing measurements ( FIG. 1 ) that provide an indication of the temperature in the vicinity of the sensor pads as well as at various locations along the fiber optic cable(s) extending between the sensor pad and remote equipment (and/or along fiber optic cable(s) extending between sensor pads). Because such fiber optic cable(s) extend along the exterior of the sub-sea pipeline, the temperature measurements for the locations along the fiber optic cable(s) provide for measurements of the ambient sea temperature along the fiber optic cable(s). Alternatively, the remote equipment can provide for fiber optic “point sensing” measurements that provide an indication of the temperature or pressure or strain in the vicinity of the sensor pads. The measurements of the remote equipment can be communicated to other systems for use in monitoring the sub-sea pipeline. The measurements can also be used to predict the formation of gas hydrates which can clog the pipeline. Alternatively, or in addition to such measurements, the remote equipment may be configured to detect pipeline leaks through the detection of vibrations or bubbles using known fiber optic noise detection techniques. Noise detection may also be used to detect the formation of hydrates. 
     Additional objects and advantages of the invention will become apparent to those skilled in the art upon reference to the detailed description taken in conjunction with the provided figures. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic diagram of a prior art system for measuring temperature along a fiber optic waveguide. 
         FIG. 2  is a schematic illustration of an exemplary fiber optic sensing apparatus according to the invention, which includes an assembly that is mounted to a sub-sea pipeline and that is coupled by a sub-sea fiber optic cable to remotely-located equipment (e.g., a system for fiber optic distributed temperature sensing). 
         FIG. 2A  is an enlarged, partially exploded, view of the fiber optic sensor assembly of  FIG. 2 ; 
         FIG. 3  is an exploded and partially cut away schematic view of the fiber optic sensor assembly and pipe section of  FIGS. 2 and 2A  in accordance with the present invention; 
         FIG. 3A  is an enlarged, partially exploded, view of a portion of the fiber optic sensor assembly of  FIG. 3 ; 
         FIG. 4  is a side elevation view, in partial section, of the fiber optic sensor assembly of  FIGS. 2 and 3  in accordance with the present invention; 
         FIG. 5  is a schematic diagram illustrating one arrangement utilizing a plurality of fiber optic sensor assemblies in accordance with the present invention; 
         FIG. 6  is a schematic illustration of an alternate arrangement utilizing a plurality of fiber optic sensor assemblies in accordance with the present invention; and 
         FIGS. 7A-7D  are schematic diagrams illustrating exemplary configurations for the optical fiber housed in the sensor apparatus of the present invention;  FIG. 7A  is suitable for spot temperature sensing as part of a fiber optic distributed sensing system;  FIG. 7B  is suitable for “point sensing” as part of a fiber optic point sensing system;  FIG. 7C  is suitable for in-line spot temperature sensing as part of a fiber optic distributed sensing system; and  FIG. 7D  is suitable for “multi-point sensing” as part of a fiber optic multiple-point sensing system. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     Turning now to  FIGS. 2 and 2A , a fiber optic sensing system  10  for use in a sub-sea pipeline  12  includes at least one fiber optic sensor assembly  14  (“sensor pad”) coupled to the pipeline  12 . The sensor pad  14  is coupled to remote equipment  16  by a sub-sea certified fiber optic cable  18  which runs outside of the pipeline  12 . On-shore or above water, the cable  18  is coupled via splice box  20  to standard fiber optic cable  22  which is then coupled to the remote equipment  16 . The remote equipment  16  may be configured to measure the temperature in the vicinity of the sensor pad  14  as well as the ambient sea temperature in the vicinity of the cable  18  connecting the equipment to the sensor pad. The temperature measurements can be transmitted to other systems to monitor the pipeline  12 , to predict hydrate formation within the pipeline  12 , to detect leaks in the pipeline  12 , or other useful applications. Alternatively, or in addition to such temperature measurements, the remote equipment  16  may be configured to detect pressure or strain or vibrations or sound, and process such signals to detect leaks in the pipeline  12 , and/or to detect the formation of hydrates within the pipeline  12 , and/or other useful applications. 
     Turning now to  FIGS. 3 and 3A , the sensor pad  14  has two main parts  24 ,  26 . The part  24  includes an upper clamp portion  34 , a housing  36 , and a cover  42 . The upper clamp portion  34  is a semi-cylinder with oppositely arranged radial flanges  27 . The part  26  is a semi-cylinder with oppositely arranged radial flanges  27 A. The flanges  27  and  27 A have a plurality of bolt holes which receive bolts so that the upper clamp portion  34  and the part  26  are clamped together about the pipeline  12  ( FIG. 2A ). The upper clamp portion  34  and part  26  are preferably made of glass reinforced nylon or a material with similar mechanical and thermal properties. Preferably a neoprene seal (not shown) is placed between the flanges  27 ,  27 A before they are bolted together. 
     The pipeline  12  is made up of sections, each composed of an internal pipe  28  (which is preferably made of steel) that is wrapped in one or more layers of protective/insulating material. In the illustrative embodiment shown, the protective/insulating material includes an intermediate polypropylene layer  30  and an outer layer  32  of concrete. One or more sections  12 ′ of the pipeline have a portion of the protective/insulating material removed or omitted to form an annular recess  31  in such pipeline section(s) as best shown in  FIG. 3 . The annular recess  31  provides an exposed area that is adapted to receive a sensor pad  14  that is attached thereto. In the illustrative embodiment shown, the annular recess  31  is formed by removing or omitting the outer layer  32  of concrete over a lengthwise segment of the pipeline section  12 ′ and thus leaving the intermediate polypropylene layer  30  exposed over this lengthwise segment. 
     The upper clamp portion  34  of the sensor pad  14  supports the housing  36 . The housing  36  is bolted to the upper clamp portion  34  before the sensor pad  14  is installed on the pipe. The housing  36  supports at least one externally-accessible connector  38  ( FIG. 3A ) which is optically coupled to a length of optical fiber  15  ( FIGS. 7A-7D ) disposed within the housing  36 . The optical fiber  15  (or portions thereof) is preferably encapsulated in thermally conductive thermoset resin on the lower surface  37  of the housing  36 . The lower surface  37  fits within a central cutout  35  in the upper clamp portion  34  such that when installed the lower surface  37  is positioned in close proximity to the exposed area of the pipeline section  12 ′. This configuration allows the optical fiber  15  (which is disposed in resin on or adjacent to this lower surface  37 ) to be positioned in close thermal contact with the exposed area of the pipeline section  12 ′. The thermoset resin should offer a very low coefficient of thermal expansion to prevent damage to the optical fiber due to seasonal variations in temperature and should also provide maximum thermal conductivity. 
     The connector  38  may be wet-mate or dry-mate. In either case, the fiber optic cable  18  is provided with the same kind of mating connector  40 . Once the connectors  38  and  40  are connected, a protective cover  42  is mounted over them. The housing  36  and the bulkhead of the connector  38  are preferably made of identical metal to eliminate the risk of galvanic corrosion. A sealing ring (not shown) is preferably provided between the bulkhead of the connector  38  and the housing  36 . 
     During installation, the housing  36  is bolted to the upper clamp portion  34  with a sealing ring (not shown) between them. The main part  24  (less the protective cover  42 ) and the main part  26  are positioned in the annular recess  31  of a selected pipeline section  12 ′ and then clamped around the exposed area of the selected pipeline section  12 ′. Preferably, such operations are performed as the pipeline  12  is being deployed from a construction barge. If dry-mate connectors are used, the connector  40  is connected to the connector  38  and the protective cover  42  is installed prior to deploying the pipeline underwater from the barge. If wet-mate connectors are used, the connectors  38  and  40  are coupled and the protective cover  42  is installed by divers or an ROV after the pipeline is deployed. 
     Turning now to  FIG. 4 , prior to attaching the sensor pad  14  to the pipeline section  12 ′, two shrouds  44 ,  46  are preferably installed on the pipeline section  12 ′. The shrouds  44 ,  46  cover the opposed edges of the annular recess  31  of the pipeline section  12 ′. The shrouds  44 ,  46  can be affixed to the opposed ends of the pipeline section  12 ′ by adhesive or by mechanical fixation, such as an interference fit. The shrouds  44 ,  46  provide an environmental seal for the portions of the pipeline section  12 ′ exposed at the edges of the annular recess  31 , as well as an environmental seal between the exposed area of pipeline section  12 ′ and the contact area of the sensor pad  14  as shown. A first set of toroidal sealing rings  48 ,  50  are installed between the respective shrouds and the exposed outer diameter surface that defines the recess  31 . A second set of toroidal sealing rings  52 ,  54  are installed between the shrouds  44 ,  46  and the contact surfaces of the sensor pad  14 . When assembled, the shrouds  44 ,  46  each present a cylinder having stepped inner and outer diameters. As illustrated, the shrouds  44 ,  46  each have an outer section and two inner sections. The outer section has an inner diameter that fits over the outer concrete layer  32  of the pipeline section  12 ′. One of the inner sections fits over the outer diameter surface of the recess  31  outside the contact area of the sensor pad  14 . The other of the inner sections fits over the outer diameter surface of the recess  31  and under the contact area of the sensor pad  14 . For alternate embodiments where the shrouds  44 ,  46  are not used, the first set of sealing rings  48 ,  50  can be omitted and the second set of sealing rings  52 ,  54  can be installed between the contact surfaces of the sensor pad  14  and the exposed outer diameter surface of the recess  31 . 
     Preferably, the inside surfaces of the upper clamp portion  34  and the part  26  of the sensor pad  14  are lined with a thermal interface material, e.g. silicone pads used in the electronics industry for rapid conduction of heat away from sensitive devices. The use of such thermal interface material provides a thermal bridge between the sensor pad  14  and the exposed area of the pipeline section  12 ′ and ensures even surface area contact in the event that there are surface imperfections in the exposed area of the pipeline section  12 ′. The thermal interface material preferably has a thickness in a range from 0.015 to 0.200 inches (0.38 to 5.08 mm). The thermal interface material can also aid in preventing seawater from contacting the portion of the pipeline section  12 ′ that is covered by the clamp portion  34  and the part  26 . 
     As described above, the sensor pad(s)  14  mounted on the section(s)  12 ′ of the sub-sea pipeline  12  are coupled by fiber optic cables  18  to remote equipment  16 . The remote equipment  16  can be located on-shore ( FIG. 2 ) or on a platform. The remote equipment  16  preferably provides for distributed fiber optic temperature sensing measurements ( FIG. 1 ) that provide an indication of the temperature in the vicinity of the sensor pad(s)  14  as well as at various locations along the fiber optic cable(s)  18  extending between the sensor pad(s)  14  and remote equipment  16  (and/or along fiber optic cables extending between sensor pads  14 ). Because such fiber optic cable(s) extend along the exterior of the sub-sea pipeline  12 , the temperature measurements for the locations along the fiber optic cable(s)  18  provide for measurements of the ambient sea temperature along the fiber optic cable(s)  18 . Alternatively, the remote equipment  16  can provide for fiber optic “point sensing” measurements that provide an indication of the temperature or pressure or strain in the vicinity of the sensor pad(s)  14 . The measurements of the remote equipment  16  can be communicated to other systems for use in monitoring the sub-sea pipeline  12 . Existing remote equipment, such as that sold by Schlumberger under the Sensa® name, can be used. Details of the operations of such remote equipment are described in U.S. Pat. No. 5,696,863, the complete disclosure of which is hereby incorporated by reference herein. 
     The temperature measurements of the remote equipment  16  can also be used to predict the formation of gas hydrates which can clog the pipeline  12 . In organic chemistry, a hydrate is a compound formed by the addition of water. In the petroleum industry, a gas hydrate is a water lattice (ice) in which hydrocarbon molecules are embedded. A gas hydrate can be formed when a stream of gas is cooled to below a dew point temperature in the presence of water. If a gas hydrate should form in the pipeline  12 , it will likely agglomerate, stick to the interior wall of the pipe, and block the flow of petroleum. The process of clearing a hydrate plugged pipeline is expensive and time consuming. It will also be noted that until the pipeline is cleared, petroleum is not being transported. Since the locations in the pipeline  12  where gas hydrates are likely to form are known, the present invention proposes placing sensor pads  14  at each of these locations. In the preferred embodiment, the sensor pads  14  employ a long length of optical fiber  15  (for example, on the order of 10 meters in length or more) within the housing  36 . The long length of optical fiber provides for a “spot” temperature measurement when used in conjunction with fiber optic distributed temperature sensing equipment. Such temperature measurements can be used to predict the formation of gas hydrates in the pipeline as is known in the art. For example, see U.S. Patent Application Publication 2005/0283276 and U.S. Patent Publication 2005/0139138, herein incorporated by reference in their entireties. Alternatively, or in addition to such measurements, the remote equipment  16  may be configured to detect pipeline leaks through the detection of vibrations or bubbles using known fiber optic noise detection techniques. 
       FIGS. 5 and 6  illustrate schematically two different arrangements that use a plurality of sensor pads  14  as described herein. In the arrangement of  FIG. 5 , each sensor pad  14  is coupled by its own cable  18  to the remote equipment  16 . In the in-line arrangement of  FIG. 6 , two of the sensor pads  14  are provided with two connectors  38 A,  38 B (one at each end of the optical fiber disposed within its housing) and the sensor pads  14  are coupled in series with each other using cables  18 . 
       FIGS. 7A-7D  are schematic diagrams illustrating exemplary configurations for the length of optical fiber  15  housed in the sensor pad  14  of the present invention. 
     In  FIG. 7A , the optical fiber  15 ′ is a long length of optical fiber which is preferably wrapped around itself in a coiled manner. The optical fiber  15 ′ is preferably at least 10 meters in length and can be up to 1000 meters in length. The configuration of  FIG. 7A  is suitable for a “spot” temperature measurement when used in conjunction with fiber optic distributed temperature sensing equipment. The configuration of  FIG. 7A  can be used for hydrate formation prediction as described above. 
     In  FIG. 7B , the optical fiber  15 ″ includes a Bragg grating etched therein. The configuration of  FIG. 7B  is suitable for “point sensing” as part of a fiber optic point sensing system. 
     In  FIG. 7C , the optical fiber  15 ″′ is a long length of optical fiber which is preferably wrapped around itself in a coiled manner. The ends of the long length of optical fiber  15 ″′ are terminated at connectors  38 A,  38 B supported by the housing  36 . The optical fiber  15 ″′ is preferably at least 10 meters in length and can be up to 1000 meters in length. The configuration of  FIG. 7C  is suitable for in-line “spot” temperature sensing as part of a fiber optic distributed temperature sensing system. 
     In  FIG. 7D , the optical fiber  15 ″″ includes a Bragg grating etched therein. The ends of the optical fiber  15 ″″ are terminated at connectors  38 A,  38 B supported by the housing  36 . The configuration of  FIG. 7D  is suitable for “multi-point sensing” as part of a fiber optic multi-point sensing system. 
     There have been described and illustrated herein a fiber optic sensing apparatus for use on sub-sea pipelines, methods for deploying the apparatus, and methods for using same. While particular embodiments of the invention have been described, it is not intended that the invention be limited thereto, as it is intended that the invention be as broad in scope as the art will allow and that the specification be read likewise. Thus, while a particular shape and configuration has been disclosed for the housing of the sensor pad, it will be appreciated that other shapes and configurations can be used as well. For example, and not by way of limitation, the housing can be integrally formed as part of the upper clamping member of the sensor pad. In another alternative embodiment, the lower clamping member can be replaced by a clamping member that supports a second sensor housing in a manner similar to the upper clamping member. In this configuration, two sensing fibers can be housed on opposite sides of the given pipeline section. In yet another alternative embodiment, a layer of insulation material can be applied between the exterior surface of the pipeline section and the contact area of the sensor pad. The addition of such insulation material can permit the fiber optic temperature sensing system to measure both the temperature of the pipeline and the effects of degradation in efficiency of insulation along the pipeline. It will therefore be appreciated by those skilled in the art that yet other modifications could be made to the provided invention without deviating from its scope as claimed.