Abstract:
An apparatus for varying the gain of a fiber optic sensor that non-intrusively senses the strain response of a pipe is provided. The apparatus includes a circumferential strain attenuator that has an annular land portion that mechanically couples the attenuator to the pipe. An annular web extends coaxially from the land portion and has a reduced cross sectional area relative to the land, and an annular mandrel portion extends coaxially from the web portion and forms a gap between the pipe and the mandrel. The fiber optic sensor is wound on the circumferential strain attenuator. The web and mandrel cooperate to reduce the strain response of the fiber optic sensor relative to the strain response of the pipe.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
   This application is a continuation of U.S. patent application 09/726,061, filed Nov. 29, 2000 now U.S. Pat. No. 6,550,342, to which priority is claimed under 35 U.S.C. § 120, and which is hereby incorporated by reference. 

   BACKGROUND OF THE INVENTION 
   1. Technical Field 
   This invention relates to fluid flow sensing devices that use fiber optics and more particularly to those devices that measure the speed of sound, flow velocity, and other parameters within a pipe using acoustic signals and local short duration pressure variations within the flow. 
   2. Background Information 
   In the petroleum industry, there is considerable value in the ability to monitor the flow of petroleum products in the production pipe of a well in real time. Historically, flow parameters such as the bulk velocity of a fluid have been sensed with venturi type devices directly disposed within the fluid flow. These type devices have several drawbacks including that they provide an undesirable flow impediment, are subject to the hostile environment within the pipe, and typically provide undesirable potential leak paths into or out of the pipe. In addition, these type devices are also only able to provide information relating to the bulk fluid flow and are therefore unable to provide information specific to constituents within a multi-phase flow. 
   Some techniques utilize the speed of sound to determine various parameters of the fluid flow within a pipe. One technique measures the amount of time it takes for sound signals to travel back and forth between ultrasonic acoustic transmitters/receivers (transceivers). This is sometimes referred to as a “sing-around” or “transit time” method. U.S. Pat. Nos. 4,080,837, 4,114,439, 5,115,670 disclose variations of this method. A disadvantage of this type of technique is that gas bubbles and/or particulates in the fluid flow can interfere with the signals traveling back and forth between the transceivers. Another disadvantage of this type of technique is that it considers only the fluid disposed between transceivers during the signal transit time. Fluid flow within a well will very often be non-homogeneous, for example containing localized concentration variations (“slugs”) of water or oil. Localized concentration variations can affect the accuracy of the data collected. 
   Multiphase flow meters can be used to measure the flow rates of individual constituents within a fluid flow (e.g., a mixture of oil, gas, and water) without requiring separation of the constituents. Most of the multiphase flow meters that are currently available, however, are designed for use at the wellhead or platform. A problem with utilizing a flow meter at the wellhead of a multiple source well is that the fluid flow reaching the flow meter is a mixture of the fluids from the various sources disposed at different positions within the well. Thus, although the multiphase meter provides information specific to individual constituents within a fluid flow (which is an improvement over a bulk flow sensors), the information they provide is still limited because there is no way to distinguish sources. 
   Acquiring reliable, accurate fluid flow data downhole at a particular source environment is a technical challenge for at least the following reasons. First, fluid flow within a production pipe is hostile to sensors in direct contact with the fluid flow, and can cause the sensors to erode, corrode, wear, or otherwise compromise their integrity. In addition, the hole or port in the pipe through which the sensor makes direct contact, or through which a cable is run, is a potential leak site, which is highly undesirable. Second, the environment in most wells is harsh, and is characterized by extreme temperatures, pressures, and debris. Extreme temperatures can disable and limit the life of electronic components. Sensors disposed outside of the production pipe may also be subject to environmental constituents such as water (fresh or salt), steam, mud, sand, etc. Third, the well environment makes it difficult and expensive to access most sensors once they have been installed and positioned downhole. 
   What is needed, therefore, is a reliable, accurate, and compact apparatus for sensing fluid flow within a pipe that can sense fluid flow within a pipe in a non-intrusive manner over a broad range of conditions, that is operable in an environment characterized by extreme temperatures and pressures and the presence of debris, that can operate remotely, and that is not likely to need replacement or recalibration once installed. Such are the objects of the present disclosure. 
   SUMMARY OF THE INVENTION 
   An apparatus for varying the gain of a fiber optic sensor that non-intrusively senses the strain response of a pipe is provided. The apparatus includes a circumferential strain attenuator that has an annular land portion that mechanically couples the attenuator to the pipe. An annular web extends coaxially from the land portion and has a reduced cross sectional area relative to the land, and an annular mandrel portion extends coaxially from the web portion and forms a gap between the pipe and the mandrel. The fiber optic sensor is wound on the circumferential strain attenuator. The web and mandrel cooperate to reduce the strain response of the fiber optic sensor relative to the strain response of the pipe. 
   The design of fiber optic flowmeters are constrained by, among other things, the structural compliance of the pipe, optical timing issues for a given length of fiber, and slew rate limitations based on the rate of change of the length of the fiber sensors. It is often desirable to select a fiber length per sensor and sensor spacing that provides an optimum level of gain for the full range of acoustics to be detected, and with regard to the fluid type, fluid consistency, and the anticipated flow rate of the fluid within the pipe. An advantage of the present invention is that it provides the ability to selectively modify, or otherwise attenuate, the gain of a flowmeter while keeping other constraints constant. The present invention results in a flowmeter having a fixed fiber length with the capability to measure a wide range of pressure levels in various acoustic environments. It will be appreciated by those skilled in the art that the environment surrounding a flowmeter may produce too much acoustic energy and thereby overtax the highly sensitive fiber optic sensors. Such environments are those that include pumps, venturis, choke valves, or any other sources that causes noise orders of magnitude above that of normal pipe flow. 
   The present invention also includes a compliant material positioned between the circumferential strain attenuator and the pipe. As a result the relatively high natural frequencies of the device that might otherwise cause a signal-processing problem are dampened out. 
   The foregoing and other objects, features, and advantages of the present invention will become more apparent in light of the following detailed description of exemplary embodiments thereof. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a diagrammatic view of a well having a casing and a pipe, and with flow meters positioned at various locations along the pipe inside the casing. 
       FIG. 2  is a diagrammatic view of an apparatus for non-intrusively measuring fluid flow parameters within a pipe. 
       FIG. 3  is a diagrammatic view of an embodiment of a sensing device. 
       FIG. 4  is a diagrammatic view of an embodiment of a sensing device. 
       FIG. 5  is a diagrammatic view of an embodiment of a sensing device. 
       FIG. 6  is a diagrammatic view of an apparatus for non-intrusively measuring fluid flow parameters incorporating circumferential strain attenuators in accordance with the present invention within a pipe. 
       FIG. 7  is a cross-sectional side view of a circumferential strain attenuator in accordance with the present invention. 
       FIG. 8  is a graphical representation of the attenuation characteristics of an embodiment of the present invention. 
       FIG. 9  is a graphical representation of the attenuation characteristics of an embodiment of the present invention. 
       FIG. 10  is a graphical representation of the attenuation characteristics of an embodiment of the present invention. 
       FIG. 11  is a perspective view in partial section of a circumferential strain attenuator in accordance with the present invention. 
       FIG. 12  is a cross-sectional side view of an alternative embodiment of the circumferential strain attenuator of the present invention. 
   

   DETAILED DESCRIPTION OF THE INVENTION 
   Referring to  FIG. 1 , there is shown an intelligent oil well system  10  containing one or more production pipes  12  that extend downward through a casing  14  to one or more petroleum sources  16 . An annulus  18  is formed between the pipe  12  and the casing  14 . Each production pipe  12  may include one or more lateral sections that branch off to access different petroleum sources  16  or different areas of the same petroleum source  16 . Fluid mixtures, consisting mostly of petroleum products and water, flow from the sources  16  to the platform  20  through the production pipes  12 . The production pipe  12  includes one or more the present invention apparatus  22  for non-intrusively sensing fluid flow within a pipe (also referred to hereinafter as a “flow meter”) to monitor various physical parameters of the fluid mixtures as they flow through the production pipes  12 . 
   Referring to  FIG. 2 , the present invention flow meter  22  includes a first sensing array  24  for sensing acoustic signals traveling at the speed of sound (SOS) through the fluid within the pipe  12  (hereinafter also referred to as the “SOS sensing array”), a second sensing array  26  for sensing short duration local pressure variations traveling with the fluid flow within the pipe  12  (hereinafter also referred to as the “flow velocity sensing array”), and a housing  28  attached to the pipe  12  for enclosing the sensing arrays  24 ,  26 . Each flow meter  22  can be incorporated into an existing section of production pipe  12 , or can be incorporated into a specific pipe section that is inserted in line into the production pipe  12 . The distributed scheme of flow meters  22  shown in  FIG. 1  permits an operator of the intelligent well system  10  to determine the extent and location of breakthrough of water into the petroleum reserve. The availability of this type of information permits the user to monitor and intelligently control the production of the petroleum reserve. 
   The sensing arrays  24 ,  26  receive optical power and produce optical signals via fiber optic cables  30  that extend between the flow meter  22  and instrumentation residing on the platform  20  or at a remote location in communication with the platform  20 . Such instrumentation can include, but is not limited to, that disclosed in U.S. patent application Ser. No. 09/726,059, entitled “Method and Apparatus for Interrogating Fiber Optic Sensors,” filed Nov. 29, 2000, which is hereby incorporated by reference. 
   Optical fiber pressure sensors  32  within each sensing array  24 ,  26  may be connected individually to the platform instrumentation, or may be multiplexed along one or more optical fibers using known techniques including, but not limited to, wavelength division multiplexing (WDM) and time division multiplexing (TDM). In those embodiments where the optical fiber pressure sensors  32  are not connected individually to the instrumentation, the sensors  32  of a sensing array  24 ,  26  may be connected to one another in series or parallel. 
   The optical signals produced by the sensing arrays  24 ,  26  provide information relating to the fluid flow characteristics within the pipe  12  (e.g., local flow disturbances, acoustic wave propagation within the flow, flow pressure magnitude and changes, etc.). Interpretation of the optical signals, which can be accomplished using methods well known in the art, enables the determination of the speed of sound (SOS) of the fluid mixture and the velocity of the fluid flow within the pipe  12 . Once the SOS, the flow velocity, the pressure, and the temperature of the mixture are known, other desirable data such as the phase fraction of the constituents within the mixture can be determined. The optical signals from the sensing arrays  24 ,  26  may also be interpreted using the methods disclosed in the following U.S. Patent applications, but are not limited to being used therewith: U.S. patent application Ser. No. 09/105,534, entitled “Fluid Parameter Measurement in Pipes Using Acoustic Pressures,” filed Jun. 26, 1998; Ser. No. 09/332,070, entitled “Measurement of Propagating Acoustic Waves in Compliant Pipes,” filed 25 Jun. 1999; Ser. No. 09/332,069, entitled “Displacement Based Pressure Sensor Measuring Unsteady Pressure in a Pipe,” filed 25 Jun. 1999; Ser. No. 09/332,094, entitled “Fluid Parameter Measurement in Pipes Using Acoustic Pressures,” filed 25 Jun. 1999; and Ser. No. 09/332,093, entitled “Non-Intrusive. Fiber Optic Pressure Sensor for Measuring Unsteady Pressures Within a Pipe,” filed 25 Jun. 1999, all of which are hereby incorporated by reference. 
     FIG. 2  shows an exemplary embodiment of the present invention wherein the SOS sensing array  24  and the flow velocity sensing array  26  are positioned adjacent one another on a common length of pipe  12 . Further details of this embodiment are provided below.  FIGS. 3-5  diagrammatically illustrate sensing array embodiments and configurations that can be used with either or both sensing arrays  24 ,  26 . 
   To avoid interference from outside sources and to protect from the harsh environment within the well, the sensing arrays  24 ,  26  are enclosed within a housing  28  that is attached to an exterior surface of the pipe section  12 . The housing  28  includes an outer sleeve  34  extending between a pair of bosses  36 . The fiber optic cable(s)  30  that extends between the flow meter  22  and the instrumentation passes through a scalable port  38  in one or both bosses  36  and connects with the sensing arrays  24 ,  26 . Outside the housing  28 , the sensor cable  30  is housed in a protective conduit  40  that is attached to the pipe  12 . In the preferred embodiment, the housing  28  and the pipe  12  together form a pressure vessel. The pressure within the pressure vessel may be greater than or less than the ambient pressure within the annulus  18  between the casing  14  and the pipe  12 . In other embodiments, the housing  28  is sealed to protect the sensing arrays  24 ,  26 , but does not act as a pressure vessel. In all embodiments, the size and structure of the housing  28  are chosen to withstand the pressure gradients present in the well environment, to accommodate the size of the sensing arrays  24 ,  26 , and to allow the sensing arrays  24 ,  26  to be positioned a distance away from the housing  28  such that heat transfer via the pipe  12  and/or the housing  28  is not deleterious for the application at hand. In a preferred embodiment, the housing  28  is filled with a gas such as, but not limited to, air, nitrogen, argon, etc. The gaseous environment within the housing  28  advantageously acts as an acoustic isolator that helps reduce pressure wave interference that might otherwise travel into the housing  28  from the annulus  18  and undesirably influence the sensing arrays  24 ,  26 . The gaseous environment also thermally insulates the sensing arrays  24 ,  26 . 
   In some applications, there is advantage in placing a plurality of bumpers within the housing to help maintain separation between the outer sleeve of the housing and the pipe. U.S. patent application Ser. No. 09/740,757, entitled “Apparatus for Protecting Sensors Within a Well Environment,” filed Nov. 29, 2000, discloses bumpers that can be used in this manner and is hereby incorporated by reference. 
   The pipe section  12  has a compliancy selected to suit the application at hand. The pipe  12  must have sufficient structural integrity to handle the pressure gradient across the pipe  12 , and yet must also be able to deflect (i.e., change in circumference) to a degree that will yield useful information. The amount the pipe  12  will change in circumference for a given pressure distribution is determined by the thickness of the pipe wall  42  and the physical properties of the pipe material (e.g., modulus of elasticity, etc.). Thus, the thickness of the pipe wall  42  and the pipe material can be chosen to help produce a favorable sensor sensitivity for the present apparatus. The characteristics of the pipe section  12  useable with the disclosed sensor arrays may be the same as or different than the characteristics in other sections of the production pipe  12 . 
   The optical pressure sensors  32  used in the SOS and flow velocity sensing arrays  24 ,  26  each include a plurality of optical fiber coils  32 . Each coil  32  is wrapped one or more turns around the circumference of the pipe section  12  in a manner that allows the length of the optical fiber within the coil  32  to change in response to changes in the circumference of the pipe  12 . If, for example, a pipe  12  can be expected to see a maximum circumferential change of “y”, then a one-turn coil will be subject to a maximum potential change in length of “y” (or some known function of “y”). If an optical measurement technique is not sensitive enough to register a change in distance equal to “y”, then the coil  32  can be wrapped to include “n” number of turns. The change in fiber length “y” per turn is therefore multiplied by “n” turns, and a change in fiber length great enough to produce a useful signal (i.e., “n·y”) is provided. In fact, the same technique can be used to not only provide a minimum useful signal, but also to increase the sensitivity of the sensor  32  and therefore increase the range of detectable changes in the circumference of the pipe  12 . In all cases, the length of the optical fiber in each coil  32  is known and is chosen to produce the sensitivity required to sense the disturbance(s) of interest for that particular sensor. The preferred embodiment, as described above, includes coils  32  wrapped around the circumference of the pipe  12 . Alternatively, the optical fiber lengths can be arranged around a portion of the circumference of the pipe  12 . 
   The turns of optical fiber in a sensor  32  are preferably laid next to one another to minimize the axial component of each turn, and thereby keep each turn to a known, constant length. Alternatively, some or all the turns of a coil  32  could be separated from adjacent turns. A coil  32  can consist of a single layer of optical fiber turns, or multiple layers of optical fiber turns depending on the application. The coil  32  of optical fiber in each sensor  32  may be attached to the pipe  12  by a variety of attachment mechanisms including, but not limited to, adhesive, glue, epoxy, or tape. In a preferred embodiment, a tape having an adhesive substance attached to opposite surfaces of a substrate is used. The tape adheres to both the pipe  12  and the fiber and provides a smooth surface on which the fiber can be laid. It is theorized that tape used on a rough surface helps to decrease micro-bend losses within the optical fiber. 
   In most embodiments, the optical pressure sensors  32  used in the SOS and flow velocity sensing arrays  24 ,  26  further include one or more optical reflective devices  46  disposed between coils  32  that are wavelength tunable. In a preferred embodiment, the optical reflective devices  46  are fiber Bragg gratings (FBGs). An FBG, as is known, reflects a predetermined wavelength band of light having a central peak reflection wavelength (λb), and passes the remaining wavelengths of the incident light (within a predetermined wavelength range). Accordingly, input light propagates along the cable  30  to the coils  32  and the FBGs reflect particular wavelengths of light back along the cable  30 . It is believed that in most applications there is advantage in placing an isolation pad between each optical reflective device  46  and the outer surface of the pipe to accommodate pipe growth and/or vibrations. U.S. patent application Ser. No. 09/726,060, entitled “Isolation Pad for Protecting Sensing Devices on the Outside of a conduit,” filed Nov. 29, 2000, discloses such an isolation pad and is hereby incorporated by reference. 
   In the embodiment of the present invention shown in  FIG. 3 , the sensors  32  are connected in series and a single FBG  46  is used between each of the sensor  32 . In this embodiment, each FBG  46  has a common reflection wavelength λ 1 . In the embodiment shown in  FIG. 4 , the sensors  32  are connected in series and pairs of FBGs  46  are located along the fiber at each end of each of the sensors  32 . The FBG pairs  46 , each of which constitute a unique reflection wavelength λ 1-4 , are used to multiplex the sensed signals so that the return signals from each of the sensors  32  can be easily identified. Thus, the pair of FBGs  46  associated with the first sensor  32   a  have a common reflection wavelength λ 1 , and the second pair of FBGs  46  associated with the second sensor  32   b  have a common reflection wavelength λ 2 , which is different from that of the first pair of FBGs  46 . Similarly, the FBGs  46  associated with the third sensor  32   c  have a common reflection wavelength λ 3 , which is different from λ 1 ,λ 2 , and the FBGs  46  associated with the fourth sensor  32   d  have a common reflection wavelength λ 4 , which is different from λ 1 ,λ 2 ,λ 3 . The sensors  32  within either sensing array  24 ,  26  may alternatively be connected to one another in parallel by using optical couplers (not shown) that are positioned upstream of each sensor  32  and coupled to a common fiber. 
   Referring to  FIGS. 2 ,  3 , and  4 , the sensors  32  and accompanying FBGs  46  may be configured in numerous known ways to precisely measure the fiber length or change in fiber length, such as by interferometric, Fabry Perot, time-of-flight, or other known arrangements. An example of a Fabry Perot technique is described in U.S. patent. No. 4,950,883, entitled “Fiber Optic Sensor Arrangement Having Reflective Gratings Responsive to Particular Wavelengths,” to Glenn. Alternatively, a portion or all of the fiber between the optical reflective device  46  may be doped with a rare earth dopant (such as erbium) to create a tunable fiber laser, examples of which can be found in U.S. Pat. Nos. 5,317,576; 5,513,913; and 5,564,832, which are incorporated herein by reference. 
   Referring to  FIG. 5 , in an alternative embodiment, the sensors  32  may also be formed as a purely interferometric sensing array by using sensors  32  without FBGs  46  disposed therebetween. In this embodiment, each sensor  32  is independently connected to the instrumentation at the platform  20  and known interferometric techniques are used to determine the length or change in length of the fiber around the pipe  12  due to pressure variations within the pipe. U.S. Pat. No. 5,218,197, entitled “Method and Apparatus for the Non-invasive Measurement of Pressure Inside Pipes Using a Fiber Optic Interferometer Sensor,” issued to Carroll, discloses such a technique. The interferometric wraps may also be multiplexed in a manner similar to that described in Dandridge et al., “Fiber Optic Sensors for Navy Applications,” IEEE, February 1991, or Dandridge et al., “Multiplexed Interferometric Fiber Sensor Arrays,” SPIE, Vol. 1586, 1991, pp. 176-183. Other techniques to determine the change in fiber length may also be used. In addition, reference optical coils (not shown) may be used for certain interferometric approaches. Such reference coils may also be located on or around the pipe  12 , but may be designed to be insensitive to pressure variations. 
   Adjacent sensors  32 , within either sensing array  24 ,  26 , are spaced apart from each another by a known distance or distances. The sensors  32  in an array are preferably equidistant from one another, but not necessarily. In both sensing arrays  24 ,  26 , the spacing between adjacent sensors  32  and the number of sensors  32  reflect the nature of the signal being sensed. The SOS sensing array  24  detects acoustic signals having relatively long wavelengths, and the flow velocity sensing array  26  detects local pressure variations within the flow having relatively small coherence lengths. In relative terms, the sensors  32  in the SOS sensing array  24  are spaced apart from one another substantially further than are the sensors  32  within the flow velocity sensing array  26  because of the intrinsic differences in the signals being sensed. The exact inter-spacing and number of coils  32  in sensing arrays  24 ,  26  is application dependent and is a function of parameters such as, but not limited to, the spectra of anticipated acoustic signals and local pressure variations, the anticipated SOS of the fluid constituents, the number of sensors  32 , the processing technique used, etc. Examples of signal processing techniques can be found in the following references, which are incorporated herein by reference: H. Krim &amp; M. Viberg, “Two Decades of Array Signal Processing Research-The Parametric Approach,” IEEE Signal Processing Magazine, pp. 67-94; and R. Nielson, “Sonar Signal Processing,” Ch. 2, pp. 51-59. 
     FIG. 2  shows an exemplary embodiment of the present invention flow meter  22  that can be inserted in-line within a production pipe  12  and disposed at an appropriate position within the well. The flow meter  22  includes a SOS sensing array  24  and a flow velocity sensing array  26  mounted on a section of pipe  12  adjacent one another and enclosed within a housing  28 . A fiber optic cable  30  extends through one of the housing bosses  36  and connects to an optical delay line  48 . An optical fiber  50 , in turn, connects the optical delay line  48  to the SOS sensing device  24 . The SOS sensing device  24  includes six (6) sensors  32  located at six predetermined locations (x 1 ,x 2 ,x 3 ,x 4 ,x 5 ,x 6 ) along the pipe  12 , and each sensor  32  is separated from adjacent sensors  32  by an axial length of “Δx”. As noted previously, each sensor  32  is mounted on a tape that includes adhesive on both faces. A FBG  46  is positioned between the optical delay line  48  and the first sensor  32 . One FBG  46  is also positioned between and connected to each pair of adjacent sensors  32 , such that the optical delay line  48 , the FBGs  46 , and the sensors  32  in the SOS sensing array  24  are in series with one another. It is preferred, but not required, to skew each FBG  46  between the adjacent sensors  32  so as to minimize the sharpness of the directional changes of the fibers that comprise the sensors  32  or the fiber associated with the FBGs  46 . 
   An optical fiber  52  extends from the last sensor  32  in the SOS sensing array  24  to a first sensor  32  in the adjacent flow velocity sensing array  26 . A FBG  46  is disposed in-line between the two devices. The flow velocity sensing array  46  includes four (4) sensors  32  located at predetermined locations (x 7 , x 8 , x 9 , x 10 ) along the pipe  12 . Like the SOS sensing array  24 , each sensor  32  in the flow velocity sensing array  26  is mounted on tape and is separated from adjacent sensors  32  by an axial length increment of “Δx”. The axial distance Δx separating the sensors  32  in the flow velocity sensing array  26  is, however, substantially shorter than that used in the SOS sensing array  24  because of the difference in the characteristics of the pressure disturbances sought to be measured. As noted previously, the SOS sensing array  24  senses relatively long wavelength acoustic signals traveling through the fluid flow at the speed of sound, while the flow velocity sensing array  26  senses relatively short coherence length local pressure variations with the fluid flow. One FBG  46  is positioned between and connected to each pair of adjacent sensors  32 , such that the FBGs  46  and the sensors  32  in the flow velocity sensing array  26  are in series with one another. Here again, it is preferred to skew each FBG  46  between the adjacent sensors  32  so as to minimize sharp directional changes. In some applications, it may be useful to connect an additional optical delay line  48  after the last sensor  32  in the flow velocity sensing array  26 . 
   In a version of the exemplary embodiment of the present invention flow meter  22  shown in  FIG. 2 , the optical delay line(s)  48  are formed by wrapping approximately two hundred and ten meters (210 m) of optical fiber around the circumference of a three and one-half inch (3.5″) diameter pipe. Each coil of the SOS sensing array  24  is formed by wrapping one hundred and two meters (102 m) of optical fiber around the circumference of the pipe in a single layer. The optical fiber is wrapped using approximately twenty-five grams (25 g) of tension on the fiber. Each turn of the coil is separated from adjacent coils by a fifteen micron (15 μ) gap. Adjacent coils in the SOS sensing array  24  are spaced approximately eighteen inches (18″) apart, center to center. The velocity sensing array  26  is formed in like manner, except that each coil comprises seven layers rather than a single layer, and adjacent coils are spaced approximately one and eight tenths of an inch (1.8″) apart, center to center. In both sensing devices, the FBGs are spliced in the section of optical fiber that extends in a helical fashion between adjacent coils, or between a coil and a delay line, etc. Each FBG and the splices that tie the FBG into the optical fiber are laid on an isolator pad, as previously noted. 
   The flowmeters as described herein above may be designed to accommodate a variety of pressure levels, slew rates, and pressure variations. For any given design, the practical limitations of the flowmeter will be determined by the ability of the fiber to accurately sense the structural response, or the time varying strain responses, of the pipe to the pressure fluctuations within the pipe. These limitations are determined by, among other things, the structural compliance of the pipe, optical timing issues for a given length of fiber, and slew rate limitations based on the rate of change of the length of the fiber sensors. As described above, it is desirable to select a fiber length per sensor and sensor spacing to provide an optimum level of gain for the full range of acoustics to be detected, and with regard to the fluid type, fluid consistency, and the anticipated flow rate of the fluid within the pipe. The method of interrogating the sensors of a given flowmeter depends on the fiber length and the practical constraints described herein. One such method of interrogation is set forth in U.S. patent application Ser. No. 09/726,059, entitled “Method and Apparatus for Interrogating Fiber Optic Sensors,” filed Nov. 29, 2000, the subject matter of which is incorporated herein by reference in its entirety. 
   The present invention provides the ability to selectively modify, or otherwise attenuate, the gain of a flowmeter while keeping other constraints constant. The present invention results in a flowmeter having a fixed fiber length with the capability to measure a wide range of pressure levels in various acoustic environments. It will be appreciated by those skilled in the art that the environment surrounding a flowmeter may produce too much acoustic energy and thereby overtax the highly sensitive fiber optic sensors. Such environments are those that include pumps, venturis, choke valves, or any other sources that causes noise orders of magnitude above that of normal pipe flow. 
   The flowmeter  22  shown in  FIG. 2  depicts an embodiment wherein sensor wraps  32  are coupled directly, or closely, to the pipe  12 . This configuration provides the highest level of gain or ability to sense the structural response of the pipe  12  to pressure fluctuations from fluids flowing therethrough. An embodiment of attenuators  100  of the present invention is best described with reference to  FIGS. 6 and 7  wherein the various sensors  32  of flowmeter  22  are mounted to the attenuators. Attenuator  100  is an axisymmetrical ring or collar including a land  102  coupled directly to the outside diameter of the pipe  12 . The land may be coupled by providing an interference fit, by welding or by other methods as described herein or by any other known method. Fiber  30  of sensor  32  may variously be positioned on land  102 , mandrel  104 , and web portion  106  as appropriate to obtain the desired level of attenuation. 
   In operation, land  102  has a strain response similar to that of the pipe  12 , but with a slightly stiffer cross-sectional effect. Because the web  106  and mandrel  104  are cantilevered from the pipe  12 , a slight gap  108  is maintained therebetween providing these portions with an attenuated strain response relative to the pipe. The level of attenuation is primarily driven by the geometries selected for attenuator  100  and in the embodiment shown, web  106  is thin compared to the land  102  and the mandrel  104  and provides a low stress transition zone from the land to the mandrel. The mandrel  104  includes a thicker cross section than the web and possesses a higher hoop stiffness than web portion  106  and is able to resist the strain experienced by land  102  in response to pressure fluctuations within pipe  12 . In the embodiment shown, mandrel  104  exhibits a small negative strain response relative to the pipe  12  and land  102  as a result of the relatively low bending stiffness of the web portion  106 . In addition to providing a low stress transition zone from the land to the mandrel, the low bending stiffness of the web portion  106  can be sized to minimize the amount of negative strain imparted to the mandrel portion  104 . 
   The attenuator  100  provides broad band attenuation of the strain response of the pipe without introducing additional dynamics between the strain in the pipe and the average strain in the fiber that would distort the relation between the attenuated strain and the actual strain response of the pipe. The broad band attenuation provided is essentially flat up to frequencies approaching the ring frequency mode of the attenuator (breathing mode) because of its inherent stiffness in all modes that have a circumferentially averaged strain component. The attenuator  100  will have non-axisymmetric modes, such as yaw, that occur at frequencies significantly below the ring frequency. These modes do not influence or otherwise degrade the transfer function because they do not contain a circumferentially averaged strain component and therefore are not observed by the sensor. 
   The level of attenuation provided by attenuator  100  is dependant upon many parameters including material type, coupling methods, the number of layers of fibers  30 , and geometry of the attenuator including its various the lengths and thicknesses. In addition, the position of the sensor  32  along the various portions of the attenuator  100  will change the attenuation level for any given combination of parameters. The extent of attenuation may be determined by integrating the hoop strain over the entire length of the attenuator  100  and may be expressed in terms of the ratio of the strain response of the attenuator with the strain response of the pipe  12 . Optical fibers  30  react to the various strain responses of the attenuator by producing a commensurate length change similar to that described herein above, resulting in a flowmeter  22  which provides attenuated signal responses when compared to a flowmeter having sensors  32  coupled directly to pipe  12 . 
   The present invention will now be described with respect to specific embodiments with reference to  FIGS. 7 and 8 . In a particular embodiment, the attenuator  100  is comprised of a stainless steel material and has a nominal inside diameter  120  of the land portion  102  of 2.375 inches, an outside diameter  122  of 3.225 inches, and a length  124  of approximately 0.25 inches. The length  126  of mandrel portion  104  is nominally 2.0 inches long and includes a sensor  32  comprising a three-layer wrap of fibers  30  occupying a width  128  of approximately 1.664 inches. With reference to  FIG. 8 , the level of attenuation for this particular embodiment is depicted graphically for sensor  32  having a 1.664 inch width mounted to mandrel portion  104  at different positions thereon from a starting position nearest the land  102  to a starting position near the end of the mandrel portion. As can be seen from the figure, the level of attenuation is dependent upon the starting position of the sensor  32  and increases as the sensor starting position moves away from the land  102  portion of the attenuator. The performance of the attenuator depicted in  FIG. 8  is based on a nominal hoop strain response of pipe  12  of 0.096 microinch/in/psi and shows that a sensor  32  starting at a point 0.19 inches along mandrel  104  (point  110 ) has an attenuated strain response of approximately 0.0103 microinch/in/psi or an attenuation of  9 . 29 . Similarly a sensor  32  having starting points at 0.21, 0.23, 0.25 and 0.27 inches along mandrel  104  exhibits attenuation levels of  10 . 09 ,  11 . 03 ,  12 . 16  and  13 . 54  respectively. 
   An alternative embodiment of attenuator  100  is shown with reference to  FIGS. 7 and 9  having different dimensions. This embodiment includes a nominal inside diameter  120  of the land portion  102  of 2.875 inches, an outside diameter  122  of 3.225 inches, and a width  124  of 0.25 inches long. The mandrel portion  104  has a length  126  of nominally 1.8 inches and includes a sensor  32  comprising a three-layer wrap of fibers  30  occupying a width  128  of approximately 1.414 inches. The performance of the attenuator depicted in  FIG. 9  is based on a nominal hoop strain response of pipe  12  of approximately 0.279 microinch/in/psi. Similar to that described herein above in  FIG. 8 , the sensor  32  starts at a point 0.22 inches along mandrel  104  (point  112 ) and has an attenuated strain response of approximately 0.0308 microinch/in/psi or an attenuation of 9.07. Similarly, a sensor  32  having starting points at 0.21, 0.23, 0.25 and 0.26 inches along mandrel  104  exhibits attenuation levels of 9.46, 10.33, and 10.88 respectively. Similarly, although not shown in the figure, a sensor  32  having starting points at 0.30 and 0.35 along mandrel  104  exhibits attenuation levels of  13 . 38  and  18 . 62  respectively. The performance of an attenuator similar to that described above having a mandrel length of 1.5 inches is depicted in  FIG. 10 , and shows a similar relationship between sensor starting point and attenuation level. 
   An alternative embodiment of attenuator  100  is shown with reference to  FIG. 11  wherein the attenuator includes a circumferential groove  130  positioned on the inside diameter of mandrel portion  104 with an O-ring  132  positioned within the groove. O-ring  132  is sized such that it is compressed between attenuator  100  and the outside diameter of pipe  12  to provide a predetermined level of compression. In such a configuration, O-ring  132  provides a predictable level of damping of natural high frequency vibrational modes of the attenuator. In a particular embodiment, O-ring  132  is comprised of a nitrile or neoprene material and together with groove  130  is sized to provide a compression level of about 20%. 
   Yet another alternative embodiment is shown with reference to  FIG. 12  wherein attenuator  100  comprises an axisymmetrical attenuator ring  140  including mandrel  104  and web portion  106  and further comprises a ramp portion  142 . Attenuator  100  further comprises a split ring  144 , comprising two or more partial are sections as is known, having a ramp portion  146  and an externally threaded potion  148 . In operation, the sections of split ring  144  are assembled about pipe  12  and attenuator ring portion  140  is assembled over the split ring with ramp  142  cooperating with ramp  146  to provide a force to wedge the split ring and attenuator ring together. Attenuator  100  further includes nut  150  having internal threads  152  which cooperate with the external threads  148  on split ring  144 . When engaged and tightened, nut  150  forces intimate contact between ramps  142 ,  146  and between split ring  144  and pipe  12 , thus providing a land portion similar to that described herein above. This particular embodiment is particularly advantageous because it facilitates mounting the attenuator on a pipe where other methods are difficult or not possible. 
   Although the invention has been described and illustrated with respect to exemplary embodiments thereof, the foregoing and various other additions and omissions may be made therein and thereto without departing from the spirit and scope of the present invention.