You are an expert at summarizing long articles. Proceed to summarize the following text:

You are an expert at summarizing long articles. Proceed to summarize the following text: 
BACKGROUND OF THE INVENTION  
       [0001]     1. Field of the Invention  
         [0002]     The present invention relates to an apparatus and method for sensing hydrostatic pressure, in a distributed fashion, in hydrocarbon pipelines and wells. The invention is particularly concerned with the detection and localization of flow restrictions and blockages in hydrocarbon flowlines for flow assurance purposes.  
         [0003]     2. Background of the Invention  
         [0004]     As part of the overall process of oil extraction and processing, it becomes necessary to transport the fluids containing liquid hydrocarbons from their reservoirs to remote plants for chemical processing. This transport process is usually conducted and pipelines that can be anywhere from several hundred meters to various kilometers in length. Ensuring the safe, reliable and continuous transport of hydrocarbons through the pipelines is of vital importance to oil companies and hydrocarbon refineries. It is also equally important to properly measure the pressure, flow and composition of the produced fluid. However, the transport of liquid hydrocarbons is faced with serious problems such as the buildup of wax and scale in the pipe walls, internal pipe erosion and corrosion, formation of hydrates and asphaltenes, and several others.  
         [0005]     It is well understood that fluid containing heavy hydrocarbons tend to precipitate and form waxy crude oils as they flow through pipelines. These paraffin precipitates deposit on the inner walls of pipes accumulating over time and forming a solid layer that narrows the passage of any liquid flow. In addition, other chemicals present such as sulfates, calcium carbonate, drilling fluids, and other scale precipitates, start depositing solid debris layers that further obstruct the fluid flow. Obviously, if one were to know the mechanisms of wax formation, it would be possible to predict the time at which a dramatic flow reduction would occur. This is in practice possible, but in order to make the analytical models accurate and effective, it is necessary to have accurate measurements of deposited wax thickness. This is not an easy task to perform on operational flowlines and most methods available are based on invasive or destructive techniques to arrive at the sought wax thickness value.  
         [0006]     Ensuring pipeline safety and reliability, and the flow assurance of hydrocarbons are the main drivers for the development of new, on-line, monitoring techniques for the detection and localization of wax and hydrate build-ups and blockages in oil pipelines. Pipeline blockages have dramatic operational and economic consequences. For example, consider an oilfield with 8 wells, each producing 10,000 barrels of oil per day (B/d). The importance of operating at peak efficiency of transport within a pipeline is demonstrated by considering that a 5% increase in efficiency—for a pipeline transporting 80,000 B/d of crude—would result in an increase of 4,000 B/d in transported oil. This would translate to an annual revenue increase of $36 million, assuming $25/barrel. Furthermore, as oil production practices move to regions with deeper reservoirs and cold waters, these problems become more serious, and thus it becomes increasingly important to develop monitoring systems that alert operators when the conditions are critical for wax and paraffin formation to occur.  
         [0007]     In general, there are two popular approaches to dealing with this problem: chemical injection and pigging. In the case of injection, chemical inhibitors are injected inside the pipeline to prevent the formation of, or dissolve any wax or hydrate build-up. Pigging consists in the mechanical removal of deposited wax and build-ups inside pipelines via a mechanical swab element commonly known as a “pig”. The pig is commonly inserted inside the flowline through an access port, and pushed forward by fluid pressure or some other mobile mechanism. As the pig moves, it scrapes the inner surfaces of the conduit, removing any wax or scale build-up present. For instance, in U.S. Pat. No. 6,615,848, Coats illustrates the use of an electronically controlled pig element that is buoyant and able to travel inside pipelines. The pig has provisions for the measurement and removal of build-up and avoids damage to the interior pipe walls by the use of a selectively expandable body. However, both the above-mentioned approaches are expensive and cumbersome, and they also require periodic maintenance and calculated guessing on the part of the operators to determine an appropriate time to conduct the chemical injection or pigging operations. Chemical injection also carries the risk of contaminating produced water, restricting its release to the sea.  
         [0008]     In an effort to reduce the costs associated with ensuring the flow of produced fluids from the wellhead to the primary processing facility based on the above techniques, the oil industry has shown increasing interest in reducing wax build-up and in on-line monitoring instrumentation. One approach is to use electrical heating and insulation of long and deep flowlines, to prevent hydrate or wax formation. This technique may be augmented by the use of a distributed fiber optic temperature sensor to help obtain temperature profiles of the flowline and detect the onset and location of possible blockages, as well as cold temperature zones along the flowline. However, for this approach to become practical, it becomes necessary to have access to the pipeline prior to its deployment in order to install the necessary electrical heating conductors and associated monitoring optical fibers and thermal insulation.  
         [0009]     Other on-line monitoring systems rely on the non-intrusive detection of blockages via acoustic or strain measurements taken from the outside of the flowline. U.S. Pat. No. 6,513,385 describes an acoustic sensor based on a piezoelectric transducer that emits an acoustic pulse signal. The pulse traverses the pipeline walls as well as the various deposited layers until it impinges on the opposite side wall, where the pulse is reflected back to the transmitter. Wax build-up layers are detected by measuring the time delays between incoming and returning pulses arriving at the acoustic transmitter. As before, one problem here is the fact that sensor heads need to be installed and secured around the flowlines. This presents difficulties for retrofitting into existing subsea installations. In addition, the technique might not be effective until a certain wax layer thickness is developed and, often times, it becomes necessary to calibrate and couple the system to a particular pipe and build-up combination.  
         [0010]     Berthold et al., in U.S. Pat. No. 5,845,033, describe a fiber optic blockage detection system based on an array of fiber Bragg grating strain sensors disposed along a continuous fiber length. The sensor arrayed is mounted or spirally strapped around the exterior of a pipeline so that there is good mechanical transfer of the pipe stresses to the fiber. Any internal pressure change resulting from a flow restriction or blockage will result in a hoop strain that can be detected by the fiber Bragg grating strain sensors. As before, this approach assumes that the fiber installation can be accomplished prior to the pipeline installation itself. In addition, proper mechanical bonding and strain transfer between the pipeline and optical fiber control the efficacy of the technique. Any unwanted stress in the pipe which is not directly the result of an internal hydrostatic pressure change, can give rise to an erroneous reading or false blockage detection.  
       SUMMARY OF THE INVENTION  
       [0011]     An assembly for sensing fluid pressure variations along a length of a flowline may be installed in an existing flowline. The assembly includes a fiber optic cable disposed axially within the passage of the flowline. The fiber optic cable experiences a mechanical strain responsive to variations in the fluid pressure of the fluid communicating through the passageway of the flowline along the length of the flowline. The assembly also includes an enhancing layer surrounding the fiber optic cable. The enhancing layer is more responsive to the fluid pressure of the fluid communicating through the passageway of the cable than the fiber optic cable. The enhancing layer enhances the responsiveness of the fiber optic cable to the pressure by magnifying the mechanical strain associated with the fiber optic cable within a particular region of varying fluid pressure.  
         [0012]     The present invention allows for the on-line and real-time detection and localization of flow restrictions and blockages in oil pipelines and wells. The assembly measures the internal hydrostatic pressure along a region of interest in hydrocarbon producing systems, in a distributed fashion, using an optical interrogation technique based on the measurement of the back-reflected Brillouin scattering of the light traveling inside said coated fiber.  
         [0013]     The present invention detects the presence of blockages in hydrocarbon production systems—such as flowlines, well tubing, injection lines, pipelines, umbilicals, and any other fluid-transporting conduit—caused by asphaltenes and paraffin deposits by measuring changes in the internal hydrostatic pressure induced by the flow constriction caused by the deposits build-up, without the sensing optical fiber obstructing or impeding the hydrocarbon flow. Any and all regions along the coated fiber under the influence of an external hydrostatic pressure will induce an internal strain in the fiber, which will produce localized changes in the amount of Brillouin backscattering of the light traveling inside the fiber.  
         [0014]     The present invention can also locate the physical location of a blockage or obstruction along the total length of a hydrocarbon pipeline or well by measuring the time of flight of the back reflected Brillouin scattered light traveling inside the optical fiber exposed to the region of interest.  
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0015]      FIG. 1  is a perspective view illustrating a vessel receiving well fluid from a subsea collection manifold that is receiving well fluid from a plurality of subsea wells through a plurality of flowlines, constructed in accordance with the present invention.  
         [0016]      FIG. 2  is a sectional view of a flowline of  FIG. 1 , when viewed along line  2 - 2  of  FIG. 1 .  
         [0017]      FIG. 3  is a sectional view of one of the flowlines of  FIG. 1  with a fiber optic line extending through it flowline in accordance with the present invention.  
         [0018]      FIG. 4  is a sectional view of the fiber optic line of  FIG. 3 , when viewed along line  4 - 4  of  FIG. 3 .  
         [0019]      FIG. 5  is a schematic isometric view of the fiber optical line of  FIG. 3 .  
         [0020]      FIG. 6  illustrates a typical Brillouin light signal spectrum.  
         [0021]      FIG. 7  is a schematic view of the fiber optic measurement instrumentation of  FIG. 3  and built in accordance with the present invention.  
         [0022]      FIG. 8  is schematic representation of the distributed pressure sensing capability of the fiber optic line and fiber optic measurement instrument of  FIG. 3 .  
         [0023]      FIG. 9  is a graphical representation plotting pressure against distance for a fiber optic line built in accordance with the present invention with a portion exposed at atmospheric pressure, and another at high pressure.  
         [0024]      FIG. 10  is a schematic sectional view of an assembly constructed in accordance with the present invention that is used to install the fiber optic line of  FIG. 4  into one of the flowlines of  FIG. 1 .  
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0025]     Referring to  FIG. 1 , a vessel  11  collects well fluids from subsea wells  13  situated in a cluster on a sea floor  12 . Preferably, each subsea well  13  includes a subsea wellhead  15  protruding above the sea floor  12 . A production line  17  extends from each wellhead  15  to a collection manifold  19  situated on the subsea floor  12 . A riser  23  extends from the collection manifold  19  to the vessel  11  for transferring well fluids from the subsea floor  12  to the vessel  11 . As will be readily appreciated by those skilled in the art, the riser  23  can preferably include a plurality of individual risers  23  or a bundle of individual tubular structures for supplying segregated streams of well fluid from the collection manifold  19  to the vessel  11 . In some situations, it is desirous to connect production line  17  to vessel  11  via a riser  21  rather than to collection manifold  19  and through common riser  23 . While vessel  11  is shown as a floating platform in  FIG. 1 , vessel  11  is merely representative and those readily skilled in the art will appreciate that vessel  11  can be numerous surface vessels including platforms, both that float or are secured to the sea, and tankers.  
         [0026]     Referring to  FIG. 2 , a deposit  25  is formed on the interior surface of production line  17 . Deposit  25  reduces the diameter of flowline  17  for fluids to pass. Over their service life, hydrocarbon producing flowlines suffer from wax, scale and hydrate build-ups that deposit on the inner walls of the transporting pipes, constricting the oil flow and, in some instance, clogging them completely. Any diameter reduction or obstruction caused by build-ups on the inside of the pipe will result in a flow change, which, by Bernoulli&#39;s principle, will result in a pressure change. Deposit  25  can also form in risers  21 ,  23 . For the ease of description, deposit  25  is only shown in flowlines  17 , however, it should be readily appreciated by those skilled in the art that the present invention is also applicable for use in risers  21 ,  23 . Accordingly, for the present invention, risers  21 ,  23  within this description should be understood to also be flowlines.  
         [0027]     Referring to  FIG. 3 , a fiber optic line  27  is shown disposed axially within an interior passage defined by flowline  17 . Fiber optic line  27  extends a desired length though a portion of flowline  17 . Fiber optic line  27  is preferably run through or installed in an existing flowline  17  with the assistance of a pump through pig ( FIG. 10 ). Depending on the length of flowlines  17 , fiber optic line  27  can extend for hundreds of meters, and even several kilometers. Fiber optic line  27  is not physically attached to the walls of flowline  17 , rather it loosely lays inside. A fiber optic measurement instrumentation  29  is attached to an end of fiber optic cable  27  at a convenient location, such as on vessel  11  ( FIG. 1 ). Fiber optic line  27  is in fluid communication with the fluid passing through flowline  17 . The fluid within flowline  17  has a hydrostatic pressure P 1 , P 2 , P 3 , . . . , P n  along the length of flowline  17 . The hydrostatic pressure acts on the entire length of fiber optic line  27  within flowline  17 . The hydrostatic pressure is dependant upon the inner diameter of flowline  17  through which the fluid passes. Therefore, in regions having deposits  25 , the hydrostatic pressure P 2  is greater than the hydrostatic pressure P 1  upstream of deposit  25 . Thus, deposit  25  creates a pressure differential that is communicated to the outer surface of fiber optic line  27 . Such a pressure differential creates a strain on fiber optic line  27  that is detected by fiber optic measurement instrumentation  29 .  
         [0028]     Referring to  FIGS. 4 and 5 , a preferred embodiment of fiber optic line  27  is shown in a manner illustrating various rings or segments. Fiber optic line  27  includes a core  31  and a cladding  33  surrounding core  31 . Light waves travel through core  31 . Cladding  33  can comprise an acrylic material surrounding core  31  such that the diameter of the combination of core  31  and cladding  33  is about 180 microns. An inner coating  35 , which can be another acrylic material, preferably surrounds cladding  33 . Inner coating  35  may be a polyhemite hemetic coating, which helps protect the glass matrix of core  31  from harsh chemicals that may be present in the fluid. The addition of inner coating  35  preferably increases the diameter to about 250 microns. An intermediate coating  37  preferably surrounds inner coating  37 . Intermediate coating  37  is preferably a layer of silicone that increases the diameter to about 400 microns. An outer coating  39  surrounds inner coating  37 . Outer coating  39  is typically the final coating, and is preferably nylon. The diameter increases to about 1200 microns with the addition of outer coating  39 . By increasing the size of the diameter of fiber optic line  27 , the effects of strain due to pressure differentials created by the presence of deposits  25  is enhanced or magnified. Therefore, the presence of at least outer coating  39  increases the sensitivity of fiber optic line  27  to pressure differences within flowline  17 .  
         [0029]     A fiber with suitable coatings deployed inside a subsea flowline would then be able to convert the hydrostatic pressure acting along its length from the liquid hydrocarbons, into a strain, which can be detected and processed by the proposed Brillouin scattering interrogation technique outlined before in U.S. Pat. No. 6,555,807, issued to Clayton et al.  
         [0030]     Referring to  FIG. 10 , fiber optic line  27  is typically installed within flowline  21  with the assistance of a deploying device  51 . In the preferred embodiment, deploying device is a pig. Deploying device  51  typically enters flowline  21  through a Y-shaped converger  53  of flowline  21 . An upstream main valve  55  is located in flowline  21 , and converging valve  57  is located within the portion of converger  53  feeding into flowline  21 . Deploying device  51  typically exits flowline  21  through Y-shaped diverter  59 . Diverter  59  preferably includes a downstream main valve  61  located in flowline  21  and a diverting valve  63  located in the portion of diverter  59  extending away from flowline  21 . A pump  65  preferably feeds into the converging portion of coverger  53  upstream of converging valve  57 , and a lubricator  67  is preferably located upstream of pump  65 . Lubricator  67  preferably acts as a seal allowing fiber optic line  27  extend to extend into flowline  21 .  
         [0031]     Deploying device  51  is inserted into the converging portion of converger  53 . An end of fiber optic line  27  is connected to a tail end of deploying device  51 . The other end of fiber optic line  27  is preferably wound around a line spool  69 . Lubricator  67  is installed upstream of deploying device  51  with fiber optic line  27  extending through lubricator  67 . Main valves  55 , 61  are shut and converging and diverging valves  57 , 63  are opened. Pump  65  pumps a fluid into the converging portion of converger  53  behind or upstream of deploying device  51  which pushes deploying device  51  into and through flowline  17 . Fiber optic line  27  is continuously fed into flowline  21  by spool  69  as deploying device travels through flowline  21 . Deploying device  51  travels through the diverting portion of diverter  59  because diverting valve  63  is open and main valve  61  is closed.  
         [0032]     Fiber optic line  27  is cut upstream of diverting valve  63  after removal of deploying device  51  so that diverting valve  63  can be closed. Fiber optic line  27  is cut prior to spool  69 , and spool  69  is replaced with fiber optic measurement instrumentation  29 . Main valves  55 , 61  are then opened which allows production fluid to flow through flowline  17 , thereby creating pressures to be sensed by fiber optic line  27 . An alternative method of deploying fiber optic line  27  can be that described in U.S. Pat. No. 6,561,488, which locates the spool on the pig and has the end of the cable fixed upstream of the pig. Fiber optic line  27  remains in flowline  17  during operations while fluid is pumped through flowline  17 . Monitoring pressures along the length of flowline  17  over time allows the operator to more easily recognize and identify build-ups of deposit  25 . Preferably, fiber optic line  27  remains in flowline  17  while a pig design for cleaning of pipelines is run through flowline  17 , or during chemical cleaning of flowline  17 . Alternatively, flowline  17  can be removed and replaced with another flowline  27  after cleaning in harsh conditions or in the event fiber optic line  27  is damaged during cleaning.  
         [0033]     In operation, the present invention converts hydrostatic pressure acting along a fiber optic line  27 , into a distributed mechanical strain. Measurements of distributed pressure can be thus inferred by converting the applied hydrostatic pressure P 1 , P 2 , P 3 , . . . , P n  into distributed mechanical strain acting on fiber  27 , and measuring the strain changes by the Brillouin scattering frequency shifts they experience.  
         [0034]     Amplification of the effective pressure acting on fiber line  27  by the plurality of coatings  33 ,  35 ,  37 ,  39  applied to core  31  allows for a more effective pressure-to-strain conversion. The hydrostatic pressure P 1 , P 2 , P 3 , . . . , P n  acting on the outer coating  39  produce radial and axial forces on fiber line  27 . These forces compress or relax the glass structure of core  31  in fiber line  37 , depending on their magnitude and direction, inducing compressive or tensile stresses in the fiber line  27 . The stresses produce axial and radial strains that change the refractive index of the core  31  through a photo-elastic effect. The induced strains are distributed along core  31  and proportional to the external pressure acting on the outer surface of outer coating  39  of fiber line  27  at any given point along its length. These strains are measured and spatially located along fiber line  27  by means of an interrogation system based on an optical time domain Brillouin scattering reflectometer ( FIG. 5 ).  
         [0035]     Based on past studies conducted to investigate the pressure response of fiber optic acoustic and hydrophone sensors, it is known that at low frequency (&lt;1 KHz), both the axial and radials strains contribute to the fiber&#39;s sensitivity to hydrostatic pressure. The fiber&#39;s sensitivity to external hydrostatic pressure is dictated by the bulk and Young&#39;s moduli of the coating material. The bulk modulus determines the maximum dimensional changes of the coating in response to an external pressure, while the Young&#39;s modulus controls the amount of strain transferred from the coating to the fiber itself. Therefore, high-pressure sensitivities can be obtained using coatings with a low bulk modulus, but a high Young&#39;s moduli as described by Lagakos et al. see “Phase-Modulated Fiber Optic Acoustic Sensors”, ISA Trans., Vol. 28, No. 2, pp 1-6, 1989.  
         [0036]     The thickness of the coating is, by itself, another design parameter. Hence, for thick fiber coatings, high sensitivity is generally obtained with Teflon TFE and Teflon FEP due to their low bulk modulus. Conversely, for thin coatings, Noryl is a good choice material due to its intermediate bulk modulus and high Young&#39;s coefficient.  
         [0037]     Budiansky et al., see “Pressure Sensitivity of a Clad Optical Fiber”, Appl. Opt.,Vol. 18, No. 24, pp 4085-4088, 1979, have developed a simple mathematical model to relate the axial strain developed in a glass fiber under hydrostatic pressure, as a function of the coating&#39;s thickness and Young&#39;s modulus. Using their expressions, for the case of an un-coated fiber, a pressure sensitivity of 0.06 mstrain/psi is obtained. However, when the fiber is coated with a material having a thickness of several hundred microns and large Young&#39;s modulus, but a low bulk modulus such as Teflon, it is possible to get a strain amplification of up to 30 times. This translates into pressure sensitivity in the fiber of approximately 1.8 mstrain/psi, which results in a minimum detectable pressure of approximately 5 psi. Such pressure resolution is within the desirable pressure resolution of +/−1 psi for a 1000 psi full pressure range flowline.  
         [0038]     For applications involving oil flowlines, it is necessary to design coatings  33 ,  35 ,  37 ,  39  of fiber line  27  so that for the desired range of pressure to measure, the resultant induced strain falls within the mechanical strain limits of an optical fiber, which is of the order of 1-3%. In addition to the compliant mechanical layers, it also becomes necessary to have additional coating layers to provide both mechanical and chemical protection to the fiber against the corrosive and harsh environment downhole.  
         [0039]     Referring to  FIG. 6 , when a high intensity light pulse of a very narrow linewidth (single optical frequency) is coupled into an optical fiber or fiber optic line  27 , a number of different back reflected signals are generated at each point along fiber optic line  27 . As discussed in U.S. Pat. No. 6,555,807 to Clayton et al.,  FIG. 6  depicts a typical scattered light spectrum for fiber optic line  27 . The spectrum is composed of Raleigh back-scattered light of a frequency identical to that of the original source but with a much reduced amplitude. Added to this is the so-called Raman back-scattered light, are Brillouin scattering signals that also have up- and down-shifted frequency components. It can clearly be seen that the frequency shift in the case of the Brillouin scatter is much smaller than the Raman one being in the order of GHz, while the Raman is in the THz range. The other main difference is that the Brillouin scatter is at lest two orders of magnitude stronger in magnitude compared to Raman.  
         [0040]     Raleigh scattering is related to inhomogeneities due to the material structure of fiber optic line  27 . Small refractive index fluctuations scatter light in all directions without changing the frequency of the scattered light. Raman scattering occurs when light is absorbed by molecules in the medium and re-emitted at different frequencies. Brillouin scattering of light occurs as a result of the interaction between a highly coherent incident light source and an acoustic wave generated by the incident light within the guiding material, i.e. fiber optic line  27 . The scattered light experiences a Doppler frequency shift, because the pressure variations of the acoustic wave are periodic and traveling in the material. This frequency shift is known as Brillouin frequency shift and is dependent on the material and its acoustic wave velocity. Typical Brillouin shifts are of the order of +/−13 GHz for incident light at 1.33 um, and of +/−11 GHz for incident light at 1.55 um.  
         [0041]      FIG. 7  shows the basic architecture of the interrogation system employed to transmit light through fiber optic line  27 , and to detect the back-reflected Brillouin scattered signals. A Distributed Feedback Laser (DFB) laser  41  is used as a light and reference source. The center frequency of this source is at v o . The light is split into two signals, one acting as the reference signal in the coherent detector  43 . The other is fed into a plurality of light modulators A 01 , A 02  and a frequency shifter  45 . The light modulators A 01 , A 02  are preferably acousto-optic modulators, which modulate the incoming continuous source light into light pulses. The light pulse, at frequency v o +v s , is injected into fiber optic line  27 . The back-reflected light returning to the same fiber end will be the sum of the Rayleigh and Brillouin scattered light. The returned signal is then mixed with the local reference light signal and fed into a coherent detector and thus to an analyzer.  
         [0042]     The frequency shift in Brillouin scattering is strain dependent, with a coefficient of 433 MHz/% of strain @ 1.55 um of incident light. Therefore, any mechanical strain acting on fiber optic line  27  or resulting from and induced pressure effect, as in the present invention, will result in a frequency shift of the Brillouin scattering back-reflected signal. The greater the magnitude of the applied strain, the greater the spectral shift.  
         [0043]     However, it should be noted that the Brillouin frequency shift is both strain and temperature dependent, which means that the net spectral shift will be the result of both temperature and strain (pressure) external effects acting on the fiber. In the preferred embodiment, one of coatings  35 ,  37 ,  39  of fiber optic line  27  acts as an insulator to reduce the effects of temperature while isolating the pressure or strain effects acting on fiber optic line  27 . Typically, this insulation is accomplished by outer coating  39 . Alternatively, a non-insulated fiber optic line  27 , and a fiber optic line  27  that is pressure or strain isolated can be used in conjunction. First, non-insulated fiber optic line  27  receives signals dependent upon both pressure and temperature, and the signals from second fiber optic line  27  helps to distill or filter the effects of background temperature. Another alternative is the use of a different Brillouin scattering interrogation approach. As discussed by Parker et al. (see “A Fully Distributed Simultaneous Strain and Temperature Sensor using Spontaneous Brillouin Backscatter”, Photonics. Tech. Lett., Vol. 9, No. 7, pp. 979-981, July 1997), the strain and temperature effects are separated by measuring both the peak amplitude and frequency shifts in back-reflected Brillouin scattering light signals.  
         [0044]     Under the influence of a hydrostatic pressure, a standard, communications-grade, optical fiber would not experience a significant strain. This is because the primary and secondary coatings found in this type of fiber are designed to cushion and absorb external forces, thus providing the fiber with mechanical isolation. Therefore, the sensitivity of the fiber to convert a given magnitude of external pressure into a fiber strain will be determined by the fiber&#39;s coating material. Numerous studies have been conducted in the past to analyze these effects in more detail during the development of fiber optic acoustic sensors and hydrophones. The use of fiber optic line  27  with a plurality of coating layers having the appropriate thickness, combination and material properties, enhances the strains induced on the fiber by any externally acting hydrostatic pressure.  
         [0045]     Referring to  FIG. 8 , a fiber with suitable coatings, such as fiber optic line  27 , deployed inside a flowline  17  is able to convert the hydrostatic pressure acting along its length from the liquid hydrocarbons, into a strain, which is detected and processed by the proposed Brillouin scattering interrogation technique outlined above with fiber optic measurement instrumentation  29 . Fiber optic measurement instrumentation  29  sends a light pulse into fiber optic line  27  and receives back-reflected light from fiber optic line  27  due to external pressure. The three-dimensional profile illustrates a typical profile having a shift in the Brillouin frequency in the back-reflected light. As discussed above, the shift is a function of pressure, accordingly, at the length where the Brilluoin frequency shifts, the pressure profile also has an incremental increase between P 1  and P 2  on the pressure versus distance profile.  FIG. 8  illustrates that the proposed invention obtains a profile of the variation of the hydrostatic pressure distribution acting along a fiber optic line  27 , as a function of distance. By comparing pressure profiles over time, it is possible to determine the overall state of flow in flowline  17 , as well as to identify and locate regions where formations of deposits  25  or clogging are occurring.  
         [0046]      FIG. 9  shows a trace on the screen of the Brillouin analyzer of fiber optic measurement instrumentation  29 . The horizontal axis denotes the fiber length in kilometers. The vertical axis shows relative pressure magnitude (inferred from the induced fiber strain). This plot corresponds to the three dimensional Brillouin frequency envelope depicted in  FIG. 8 . The illustration of  FIG. 9  is for fiber segment length of 40 meters long. The first 20 meters are exposed to atmospheric pressure, while the remaining 20 meters are under 5,000 psi of pressure. Note how the pressure profile clearly differentiates the pressure levels between the two regions. The pressure spikes observed at the beginning and at the transition of the two regions, are the result of strains introduced by hermetic penetrators and connectors used as part of the experimental test.  
         [0047]     While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited but is susceptible to various changes without departing from the scope of the invention. For example, while the discussion above has focused on flowlines  17 , the system can easily be used with risers  21 ,  23  that have already been defined as being flowlines for the sake of this invention.

Summary:
An assembly senses fluid pressure variations within a passageway along a length of a flowline. A fiber optic cable is disposed axially within the passageway of the flowline. The fiber optic cable experiences a mechanical strain responsive to variations in the fluid pressure of the fluid communicating through the passageway of the flowline along the length of the flowline. The assembly also includes an enhancing layer surrounding the fiber optic cable. The enhancing layer is more responsive to the fluid pressure of the fluid communicating through the passageway of the cable than the fiber optic cable, which enhances the responsiveness of the fiber optic cable to the pressure by magnifying the mechanical strain associated with the fiber optic cable within a particular region of varying fluid pressure. Strain associated with the cable is communicated through back-reflected light.