Abstract:
Subsea apparatus and a method for sampling and analysing fluid from a subsea fluid flowline proximate a subsea well is provided, wherein the apparatus comprises at least one housing located in close proximity to said subsea fluid flowline; at least one fluid sampling device located in the housing in fluid communication with a said subsea fluid flowline for obtaining a sample of fluid from the subsea fluid flowline; at least one fluid processing apparatus located in the housing in fluid communication with said subsea fluid flowline for receiving and processing a portion of the fluid flowing through said fluid flowline or in fluid communication with the fluid sampling device, for processing the sample of fluid obtained from the subsea fluid flowline for analysis, while keeping the sample of fluid at subsea conditions; a fluid analysis device located in the housing, the fluid analysis device being in fluid communication with the fluid processing device and/or with the fluid sampling device, the fluid analysis device being used for analysing said sample of fluid or the processed sample of fluid to generate data relating to a plurality of properties of said sample of fluid and communicating said data to a surface data processor or to at least one other subsea apparatus; and conveying means included in the housing for conveying the housing means from one subsea fluid flowline to another subsea fluid flowline or for conveying the housing to the surface.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    This invention relates to subsea apparatus for fluid sampling and/or analysis. In particular, the invention relates to a subsea apparatus for fluid sampling and/or analysis used in the oil and gas industry. 
         [0002]    Understanding the properties of fluids in wells in the oil and gas industry is critical for the assessment of oil or gas reservoirs. For example, the fluid properties may be used for the proper management of oil and gas reservoirs including for instance production management and flow assurance. Fluid sampling and/or analysis may be performed during various phases of the exploration, development and production phases of a reservoir. Conventional tools are able to take a fluid sample from the well and bring it to surface where it is processed and analysed. For example, often times the phase behavior of the fluid may be studied using an analysis known in the industry as PVT analysis which measures, inter alia, the bubble point of the fluid as well as its wax, and asphaltene content. Also, compositional analysis of the fluid sample may be performed as well as analysis of its H 2S , CO 2 , Hg, and heavy metal content. Also, well known are tools and methods for measuring the density and viscosity of the fluid its, water content, etc. 
         [0003]    More and more of these measurements are arranged to be performed downhole. This is because, generally, obtaining a correct estimation of fluid phase behavior requires that a sample with a pressure and temperature as close as possible to the conditions present at the wellhead be taken so that wax and asphaltenes do not precipitate out of the fluid. Fluid properties at the surface may differ from those present at the wellhead. Sampling of the fluid at the surface is therefore not a suitable option for the correct estimation of the fluid phase behavior in subsea oil or gas wells. However, the conditions prevalent in a subsea environment make access to a subsea fluid sample rather difficult. 
         [0004]    In a subsea oil or gas well installation, fluid flows from different well heads are often mixed through a series of manifolds. This poses an additional complication in the sampling and analysis of subsea wells. Sampling and analysis of the fluid flowing from each individual well would be preferred as it would provide a valuable understanding of the production capabilities and peculiarities of each well which in turn could be used for proper field management. Also, the properties of the fluid produced by subsea wells may change significantly over a short period of time. Thus, if the analysis of the samples that have been taken is done at a later time at a surface, the value of the data will be diminished. 
         [0005]    Various apparatus, methods and systems for sampling and analyzing well fluids have been identified previously. U.S. Pat. No. 6,435,279 discloses a method and apparatus for sampling fluids from an undersea wellbore utilizing a self-propelled underwater vehicle, and a collection and storage device. The &#39;279 patent describes a method for sampling a fluid produced from a subsea well, the method comprising a remotely operated vehicle (ROV) having a collecting device for collecting a sample of fluid and a storage facility for the collected sample of fluid wherein said collecting device and storage facility are connected to the ROV. The collecting device is used to collect a sample from a subsea location, storing the sample in the ROV and then transferring it to a surface location. 
         [0006]    International patent applications WO 2008/087156, and WO 2006/096659 disclose various systems and methods for subsea sampling. The WO 2008/087156 patent application describes a subsea sampling and data collection device that is coupled to a flowline at a flowline installation. The WO 2008/087156 sampling and data collection device includes a sample collection system having a probe insertable into a flowline to collect a fluid sample. The WO 2008/087156 application is assigned to the same assignee as the present invention and it is hereby incorporated by reference for all purposes allowable under the law to the extent that its disclosure does not contradict with the present invention. 
         [0007]    An article entitled “Improved production sampling using the Framo multiphase flow meter” by Framo Engineering AS in October 1999 discusses a multiphase flow meter used in fluid sampling, including subsea with the aid of remotely operated vehicles (ROV). 
         [0008]    From the description above it is evident that for effective production and flow assurance management in subsea oil and gas reservoirs, there is a real need to obtain a good understanding of produced fluid on a well by well basis and to measure the variation of fluid properties from each of these wells with time. The present invention provides an improved apparatus and associated method that facilitate the sampling and the characterization of the fluids at a subsea environment, and as close as possible to each well head. The present invention and method also enable analysis of sampled fluid to occur on a real time basis and thus obtain accurate real time analysis data for well performance and management. 
       BRIEF SUMMARY OF THE INVENTION 
       [0009]    A first aspect of this invention provides subsea apparatus for sampling and analysing fluid from a subsea fluid flowline proximate a subsea well, comprising:
       at least one housing located in close proximity to said subsea fluid flowline;   at least one fluid sampling device located in the housing in fluid communication with a said subsea fluid flowline for obtaining a sample of fluid from the subsea fluid flowline;   at least one fluid processing apparatus located in the housing in fluid communication with said subsea fluid flowline for receiving and processing a portion of the fluid flowing through said fluid flowline or in fluid communication with the fluid sampling device, for processing the sample of fluid obtained from the subsea fluid flowline for analysis, while keeping the sample of fluid at subsea conditions;   a fluid analysis device located in the housing, the fluid analysis device being in fluid communication with the fluid processing device and/or with the fluid sampling device, the fluid analysis device being used for analysing said sample of fluid or the processed sample of fluid to generate data relating to a plurality of properties of said sample of fluid and communicating said data to a surface data processor or to at least one other subsea apparatus; and   conveying means included in the housing for conveying the housing means from one subsea fluid flowline to another subsea fluid flowline or for conveying the housing to the surface.       
 
         [0015]    The fluid analysis data can be real time data, and this real time data is communicated to at least one electronic device which incorporates at least one software model used to provide information regarding the production of said subsea well. The software model may also used to provide predictions regarding the production of the well. 
         [0016]    In one form of the invention the fluid analysis data is used to control at least one piece of subsea equipment. The fluid processing apparatus separates the sample of fluid into at least a liquid and a gaseous phase, or mixes the sample of fluid with at least one other different fluid, or enriches the sample of fluid. 
         [0017]    In one form of the invention the fluid sampling device is in communication with the well fluid. The fluid sampling device may also be in communication with a fluid processing apparatus, the fluid processing apparatus being in communication with the well fluid. 
         [0018]    Further according to the invention, at least one data processing device may be locatable in the housing and may be in communication with the fluid analysing device. The data processing device processes data received from the fluid analysis device and communicates the data. 
         [0019]    The conveying means may be an attachment for a detachable subsea vehicle such as, for example, a remotely operated vehicle (ROV) or an autonomous underwater vehicle (AUV). 
         [0020]    The subsea apparatus may further comprise a plurality of housings which are connectable to each other in a modular fashion. The fluid analysis device of each housing may be in fluid communication with the fluid analysis device of another connected housing. In the same way, the fluid sampling device of each housing may be in fluid communication with the fluid sampling device of another fluid sampling device of a connected housing, and the data processing device of each housing may be in fluid communication with the data processing device of a connected housing. 
         [0021]    A second aspect of this invention provides a method of sampling and analysing fluid from a subsea well, the method comprising:
       locating at least one housing in close proximity to a subsea flowline proximate said subsea well, said housing comprising at least one fluid analysis device, at least one fluid processing apparatus and at least one fluid sampling device, the fluid sampling device being in fluid communication with said subsea flowline, the fluid processing apparatus being in fluid communication with said subsea flowline and/or with the fluid sampling device, the fluid analysis device being in fluid communication with the fluid processing device and/or with the fluid sampling device;   obtaining a sample of fluid from the subsea flowline, and storing it in the fluid sampling device;   transferring the sample of fluid to the processing device, and processing the sample of fluid with the processing device for analysis by the fluid analysis device, while keeping the sample of fluid at subsea conditions;   transferring the sample of fluid from the processing device to the fluid analysis device;   analysing the properties of the fluid with the fluid analysis device to obtain fluid analysis data subsea;   communicating the fluid analysis data to at least one other subsea apparatus or to a surface data processor; and   conveying the housing from said subsea fluid flowline to another subsea fluid flowline or to the surface.       
 
         [0029]    In one form of the invention the fluid sampling device is in fluid communication with a fluid processing apparatus, the fluid processing apparatus being in fluid communication with the well fluid flowing in the subsea flowline and the sample of fluid is obtained from the well fluid in the subsea flowline via the fluid processing apparatus. The fluid sampling device may also be in communication with a fluid processing apparatus that is in communication with the well fluid. 
         [0030]    Further according to the invention, at least one data processing device may be locatable in the housing and may be in fluid communication with the fluid analysis device, and which further comprises processing fluid analysis data received from the fluid analysis device by means of the data processing device and communicating the processed data to another apparatus or to the surface. The method may further include processing fluid data received from the fluid analysis device and communicating the data. 
         [0031]    The method may also comprise deploying one or more housings of the apparatus by means of a detachable subsea vehicle such as, for example, a remotely operated vehicle (ROV) or an autonomous underwater vehicle (AUV), the housings being connectable to each other. 
         [0032]    In a further form of the invention there may be a plurality of housings, and the method may further comprise connecting the plurality of housings to each other in a modular fashion, and wherein each fluid analysis device of each housing is in fluid communication with each other, and each fluid sampling device of each housing is in fluid communication with each other. 
         [0033]    Further aspects of the invention will be apparent from the following description. 
     
    
     
       BRIEF DESCRIPTION OF SEVERAL VIEWS OF THE DRAWING 
         [0034]      FIG. 1  shows a schematic side view of a subsea apparatus for sampling and/or analysing fluid from a well according to one embodiment of the invention; 
           [0035]      FIGS. 2  shows a schematic side view of a housing of the subsea apparatus for sampling and analysing fluid from a well as shown in  FIG. 1 , attached to a remotely operated vehicle (ROV); 
           [0036]      FIG. 3  shows a schematic side view of the subsea apparatus for sampling and/or analysing fluid attached to a fluid processing device indicating the flow direction through the components of the fluid processing device; 
           [0037]      FIG. 4  shows a diagrammatic view of a hydraulic sampling device of the subsea apparatus for sampling and/or analysing fluid from a well according to one embodiment of the invention; 
           [0038]      FIG. 5   a  shows a diagrammatic view of a passive sampling device of the subsea apparatus for sampling and/or analysing fluid from a well according to another embodiment of the invention; 
           [0039]      FIG. 5   b  shows a diagrammatic view of a passive sampling device of the subsea apparatus for sampling and/or analysing fluid from a well which uses venturi according to another embodiment of the invention; 
           [0040]      FIG. 6  shows a diagrammatic view of an active sampling device of the subsea apparatus for sampling and/or analysing fluid flow which uses a pump according to a further embodiment of the invention; 
           [0041]      FIGS. 7   a ,  7   b  and  7   c  show a series of diagrammatic views of an adjustable inlet of a sampling device according to an embodiment of the invention; 
           [0042]      FIG. 8  shows a schematic layout of a fluid analyser of the subsea apparatus for analysing fluid from a well; 
           [0043]      FIG. 9  shows a schematic side view of a section of an in-line fluid analyser of the subsea apparatus for sampling and analysing fluid from a well according to one embodiment of the invention; 
           [0044]      FIG. 10  shows a schematic side view of a section of an in-line fluid analyser of the subsea apparatus for sampling and analysing fluid from a well which includes a phase behaviour fluid analyser according to another embodiment of the invention; 
           [0045]      FIGS. 11 ,  11   a ,  11   b  and  11   c  show schematic side view of a sampling bottle for low shock sampling with a piston inside the bottle of the subsea apparatus according to one embodiment of the invention; 
           [0046]      FIGS. 12 ,  12   a ,  12   b  and  12   c  show schematic side view of a sampling bottle for low shock sampling without a piston inside the bottle of the subsea apparatus according to one embodiment of the invention; 
           [0047]      FIG. 13  shows schematic view of a self retrievable sampling bottle apparatus of the subsea apparatus according to one embodiment of the invention; and 
           [0048]      FIG. 14  shows a schematic overview of a controller configuration used for the control of a number of subsea apparatuses according to one embodiment of the invention. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0049]    This subsea apparatus for analysing and/or sampling fluid from a well according to the invention is applicable to subsea installations or facilities in the oil and gas industry. In the drawings  FIG. 1  illustrates the basic layout of a subsea apparatus  10  for sampling and/or analysing fluid from a well according to the invention. Subsea apparatus  10  is located in close proximity to the wellhead of a well and includes a subsea fluid processing device  12  for processing fluid samples obtained from the well. The subsea processing device  12  can be a phase separator, a phase accumulator, a boosting pump, a water treatment unit, chemical injector or an injection pump, depending on the application required. 
         [0050]    The subsea processing device  12  includes a fluid sampling device  14 . The fluid sampling device  14  consists of a network of pipes connected to different sampling points in the processing device  12 . The fluid sampling device  14  can also include a distributor that can redirect the sampled fluid to different outlet. 
         [0051]    Subsea apparatus  10  further includes a remote operating device (ROV) docking station  16  which allows the docking and attachment of a remote operating device (ROV)  18  to the subsea processing device  12 . 
         [0052]    As shown in  FIG. 1 , there is a fluid interface  20  in communication with the sampling device  14  which is located below the ROV docking station  16 . The fluid interface  20  allows a hydraulic connection between the ROV  18  and the processing device  12 , and thus fluid at well pressure can travel between them. This hydraulic connection can be initiated when the ROV  18  is docked at the docking station and it can be disconnected when the ROV  18  is removed. 
         [0053]    A frame or skid  22  could also be docked to the docking station with the help of an ROV  18 . As illustrated in  FIG. 2 , the skid  22  is attached to the ROV  18  with several instrumentation modules connected thereto. This will be further described below. Skid  22  can be docked to the docking station  16  as the ROV  18  approaches the installation. The skid  22  can then be detached from the ROV  18  through a specific skid/ROV interface  24  and it can then be left permanently on the installation of apparatus  10 . The skid/ROV interface  24  may be a fluid interface and skid  22  is in communication with the fluid interface  20 . By using a hydraulic connection between skid  22  and fluid interface  20 , the well fluid can be directed to the instrumentation module  26  which is located on the skid  22 . 
         [0054]    Skid  22  is designed so that other skids  22  of a similar type can be connected to it. The design is modular so that the skids  22  can be configured and assembled in different orders, and then used for different purposes. 
         [0055]    Skid  22  can also be deployed using an autonomous under water vehicle AUV. In this case, the skid interface  24  may include instrumentation for the positioning of the AUV during docking. 
         [0056]    An instrumentation module  26  is located inside skid  22  and is connected to a controller/communication module  28 . Instrumentation module  26  contains the fluid analyzer and it is used to perform fluid analysis and/or fluid sampling. It is connected to the fluid interface  20  and it can receive the fluid collected by the fluid sampling device  14 . The type of analysis and the sampling sequence is managed by the controller/communication module  28 . The controller/communication module  28  performs control either through a pre-defined sequence stored in the controller, from the surface with the use of a communication link, or in a completely automated mode with the use of the fluid analysis data obtained by the fluid analyzer in instrumentation module  26 . It is used to enable decisions to be made on how to process the sample of fluid. 
         [0057]    There are various different possible schemes for the sampling which have been described previously in the art and these can easily be implemented in conjunction with this invention. 
         [0058]    The fluid analyzer in instrumentation module  26  consists in a network of pipe connected to pumps, fluid properties sensors, sample chambers, fluid conditioners and injectors. This system is managed through the controller/communication module  28 . 
         [0059]    The fluid analysis data obtained by apparatus  10  is used to control various types of subsea or surface equipment. This fluid analysis data is based on real time sample measurements obtained from the fluid sample that is obtained and also possibly analyzed at wellhead conditions. This real time fluid data may be communicated to an electronic device which incorporates at least one software model and this model may be used to provide information regarding the production of the well and to provide predictions regarding the production of the well. Thus information regarding reservoir assurance, or flow assurance management may be obtained through the processing of this fluid data. 
         [0060]    Details will now be provided of further embodiments of the invention. 
         [0061]      FIG. 3  illustrates an embodiment of the subsea apparatus for sampling and/or analysing fluid from a well according to the invention, which further includes a phase separator  30 . 
         [0062]    The phase separator  30  which may be used is one of the typical examples of phase separators known in the art. Such a typical phase separator consists of a pressure vessel  32  with an internal pipe drilled with radial holes. The pressure vessel  32  includes a fluid inlet  34  and fluid outlet  36 . The direction of fluid flow is shown by arrows A in  FIG. 3 . The phase generator  30  was initially designed in the art as a device for fluid mixing purposes but it can also be used as a fluid separator. In the pressure vessel area, the fluid segregates depending on its density, with gas separating out on top and the liquid (oil and water) separating out at the bottom. As the fluid is forced through the central pipe (with holes), the phases are remixed, leading to a mixed fluid flow leaving at the outlet. 
         [0063]    Phase generator  30  allows liquid can be sampled at the bottom of the vessel while gas can be sampled at the top. 
         [0064]      FIG. 3  further shows a retrievable ROV  18  with a skip  22  including a fluid sampling or analysis module  26  to be used for fluid sampling, as well as a skip  22  including a fluid sampling or analysis module  26  to be used for fluid analysis, and then a multi-phase flow meter  38 . 
         [0065]    The hydraulic sampling device of apparatus  10  is illustrated in  FIGS. 5 and 6 . Fluid sampling can be done either through a passive or an active sampler. In the implementation of the invention shown in  FIGS. 5 and 6 , the fluid sampling or analysis module  26  has internal piping connecting the liquid sampling pipe  44  to the gas sampling pipe  46 . It further includes an inlet pipe  40  to sample the fluid from the separator to the fluid analyzer in module  26  and an outlet pipe  42  to re-inject the fluid to the separator or main fluid flow line after it has been analyzed. The direction of fluid flow is shown in  FIGS. 5   a ,  5   b  and  6  by arrows B. 
         [0066]    Passive sampling devices  26  do not require any pump to sample the fluid as these devices are based on passive mechanisms. Two different possible implementations of passive sampling devices are shown in  FIGS. 5   a  and  5   b . In  FIG. 5   b , the fluid movement inside the sampling tubes is generated using a venturi device  48 . The outlet pipe  42  is connected to venturi device  48  which is located further down the fluid flow line. The venturi device  48  generates a pressure difference that drives the fluid through the piping system and the fluid sampling or analysis module  26  or from the inlet to the outlet. 
         [0067]    In  FIG. 5   a , the fluid in the extraction line is dragged by the main flow in a perforated pipe  50 . 
         [0068]      FIG. 6  describes an active sampler using a pump  52  to generate the fluid flow from the inlet to the outlet. 
         [0069]    In practice several different types of fluid sampling devices can be used. For example, in  FIGS. 5 and 6 , with the use of the proposed separator, it is possible to change the sampled liquid phase by adjusting the position of the inlet inside the phase separation chamber. The liquid phase of the fluid will accumulate at the bottom while the gas phase will accumulate at the top of the vessel. 
         [0070]    One possibility is to have two or more inlet pipes  40 . 1  and  40 . 2  with different heights as is illustrated in  FIG. 7   a . If required, the flow from these sampling pipes could be directed to a manifold before being routed to the fluid sampling or analysis module  26 . 
         [0071]    Another possibility which is described in  FIG. 7   b  is to have a sampling pipe with an adjustable height that is adjustable with the use of mechanical actuators  56 . The height H may then be adjusted according to what is required. With time, the ratio between the different phases of fluid produced by the well changes. With such an adjustable sampling inlet, it is thus possible to adapt the sampling device to the changes in production conditions. 
         [0072]      FIG. 7   c  describes an adjustable fluid sampling or analyzing module  26  which uses a series of controllable valves  57  and  58  connected thereto to change the sampling point position. The valves  57  and  58  can be selectively closed. In the normal operation, all valves  58  are closed except for the valve  57  which is at the level of the sampling point. The fluid flow is illustrated in  FIG. 7  by arrows E. 
         [0073]    In one embodiment of the invention there is a universal skid  22  used for fluid sampling and analysis. This skid  22  includes the fluid interface  20 , power/communication module  28 , skid or ROV interface  24 , a local controller module and a fluid sampling or analysis module  26 . The local controller module controls the working of the sampling or fluid analysis module  26 . 
         [0074]    One feature of apparatus  10  is its modularity. Apparatus  10  may be provided in different kinds of modules. Fluid, communication and skid or ROV interfaces are designed to be fully interoperable so that different kinds of modules of apparatus  10  can be interconnected and configured in many different types of configurations. 
         [0075]    Another feature of apparatus  10  is that modules of apparatus  10  including skids  22  may be installed either on a temporary basis or on a semi-permanent basis. 
         [0076]    Before any fluid sampling or fluid analysis operation starts, the skids  22  are fully engaged in an ROV  18  and connected to the various fluid interfaces. An individual module of apparatus  10  comprising a skid  22  and its attached equipment can be retrieved as required by an ROV  18 . 
         [0077]    The fluid sampling or analyzing device  26  which is mounted in a skid  22  in apparatus  10  is shown in more detail in  FIG. 8 . The device  26  is enclosed in a tool housing  59  and it includes fluid flow lines  60  connected together and guiding the fluid from an inlet to an outlet. The device  26  further includes pumps  62  which can move the fluid there through. Fluid conditioners  64  which are used to process the fluid and change properties such as the ratio between the different fluid phases, or the fluid pressure, volume or temperature are also included in device  26 . Fluid processing devices  12  may further include a separator, a mixer, and a PVT (pressure, volume and temperature) device. 
         [0078]    In device  26  injectors  66  can be used to inject fluids which are different from the fluid which is flowing in a particular flow line  60 . The injected fluid can be used to generate an inhibitory chemical reaction with the sampled fluid or it can change the phase behavior of the fluid. Sample bottles or chambers  68  in device  26  are used to take and store samples of the fluid inside a flow line  60 . Fluid property sensors  70  are also shown located on flow lines  60  in device  26 . 
         [0079]    In the drawings,  FIG. 9  illustrates an embodiment of the fluid sampling or analysis device  26  of apparatus  10  to be used for fluid analysis with one possible configuration of sensors  70 . In this embodiment, device  26  is in-line with the sampling piping. Various types of sensors  70  are shown in the in-line configuration in a fluid flow line  60 . These sensors may be, for example, a lamp  72  and spectrophotometer  74  arrangement, a fluorescence detector  76 , a resistivity sensor  78 , an X-ray or gamma ray density sensor  80 , a pressure and temperature gauge  82 , a density or viscosity sensor  84 , a vibrating wire  86 , an in-line CO2 sensor  88 , or an in-line H2S sensor  90 . In  FIG. 9  the fluid sample is shown to flow in either direction through the flow line  60 . 
         [0080]    The fluorescence detector  76  can be used to, for example, detect traces of oil in water. This information can be useful for the assessment of subsea processing, for example, when water is separated from oil before being re-injected into the formation. 
         [0081]    The fluid resistivity sensor  78  can be used to detect water resistivity, which can be very useful information which can in turn be used to detect injection water breakthrough. Injection water used for reservoir stimulation will usually have a resistivity different from that of formation water. Water resistivity changes, therefore, can be correlated with injection water breakthrough. 
         [0082]    The fluid sampling or analysis device  26  can also include fluid conditioners. One possible fluid conditioner is a phase separator. This can be used for water or oil sampling. The main phase separator will give a liquid or gas separation. The phase separator within the fluid sampling or analysis device  26  can therefore be used to separate the oil from the water if necessary. 
         [0083]    Another sensor which may form part of device  26  is a unit to “flash” the sample. Sample flashing consists of dropping the pressure of sample before injecting it with a specific sensor. This method is well known in the analysis of HP (high pressure) live oil samples by using gas chromatography. 
         [0084]    The embodiment of device  26  which is illustrated in  FIG. 9  is suitable for different types of application. These could include, for example, NMR characterization for composition analysis or viscosity measurement, gas chromatography, mass spectroscopy, inductive coupled plasma chemical (ICP) analysis, electro-chemical sensors, or pH or ion concentration measurement in water phase using colorimetric methods. 
         [0085]    In the drawings,  FIG. 10  illustrates a further embodiment of apparatus  10  of the invention which includes a fluid sampling or analysis device  26  to be used for fluid analysis that has a further possible configuration of sensors  70 . Device  26  in this embodiment can be used for several types of measurement. Device  26  includes two seal valves  92  and  94  that can be opened and closed in order to trap a fluid sample in between them. The volume of fluid in the piping system between the two seal valves  92  and  94  forms a fluid circulation loop. The fluid in the circulation loop can be circulated with the circulation pump  96  and pump unit  103 . Seal valve  98  is used to force the fluid flow through the circulation loop before valves  92  and  94  are closed. 
         [0086]    A piston unit that is used to increase the volume trapped between the seal valves and consequently to reduce sample pressure. There is a pressure sensor connected to the circulation loop to monitor pressure changes as the piston is retracted. The piston is preferably retracted when the circulation pump  96  is operating. The agitation created by the fluid moving helps to prevent a problem posed by fluid supersaturation. It is well-known in the art that estimation of bubble point requires some agitation as the pressure is changed. The circulation loop can include an ultrasonic transducer that will also generate agitation and this helps to prevent supersaturation. 
         [0087]    A scattering detector  100  sensor is used in device  26  in order to detect bubbles or solid particles forming in a fluid flow line  60 . The scattering detector  100  used is known in the art and is used to measure the attenuation of light as it passes through a cell. Formation of solid particles and gas bubbles will lead to an increase in the attenuation of light. This sensor is used to detect the fluid bubble point which indicates at which pressure gas starts to form in the flow line. Such sensors can be used to detect the gas condensate dew point, the fluid bubble point, gas bubble formation or the presence of solid particles. 
         [0088]    A density and viscosity sensor  84  may also be included in device  26 . It is used to measure the evolution of the parameters of density and viscosity against pressure. 
         [0089]    An optical spectrometer (the lamp  72  and spectrometer  74  arrangement) may also be included in device  26  to measure fluid optical absorption at various wavelengths. The optical spectrometer, for example, can be used to estimate fluid composition by NIR spectroscopy. It is of particular interest for hydrocarbon analysis as the hydrocarbons have characteristic absorption peaks around [1600; 1800] nm. Spectral analysis in the visible range can also be used for monitoring asphaltene content of the fluid. 
         [0090]    Device  26  may also include a camera  102  which is used to monitor the condition of the fluid in the flow lines for the presence of bubbles or solid particles. In addition, device  26  may also enclose a US transducer sensor  104 . 
         [0091]    Device  26  may be enclosed in a temperature control unit  106 . The temperature control unit  106  may enable the temperature of the fluid to be changed. In this way by combining pressure and temperature changes, device  26  can provide a comprehensive phase diagram for the fluid trapped in the fluid flow lines  60  of the device. 
         [0092]    Device  26  may be used in various downhole conditions and can be used in various applications such as, for example, the study of fluid phase diagrams (bubble point detection, wax or asphaltene onset, hydrate locus, etc), the study of fluid density and viscosity versus pressure, and the study of fluid composition. 
         [0093]    Another important feature of the invention is the ability to sample fluid.  FIG. 11  gives a possible configuration for a sampling bottle  108 . The sampling bottles  108  of apparatus  10  are configured for low shock sampling. Low shock sampling comprises filling a bottle  108  with the sample with a controlled flow rate. The goal is to avoid fast pressure changes of the sample which could lead to phase transition before the bottle  108  is filled. 
         [0094]    The sampling bottle  108  can be implemented as follows: 
         [0095]    A cylindrical bottle  108  with a piston  110  defining two chamber spaces as it moves along the bottle&#39;s main axis. The sample chamber  112  is located on one side of piston  110  is and the water cushion chamber  114  is located on the other side of piston  110 . 
         [0096]    Bottle  108  is connected to the fluid sampling line as shown in  FIG. 11 . In the initial position before the bottle  108  is opened, shown in  FIG. 11   a , the volume of sample chamber  112  is minimal while the cushion water chamber  114  side is full. For sampling, the solenoid valve  116  and the choke valve  118  are opened. The rate of sampling can be controlled by the choke  120 . The choke  120  controls the fluid flow and therefore the fluid flow rate in the sample chamber  112 . The sampling is completed once the piston  110  reaches its final position on the other side of the bottle  108 . Both the solenoid valve  116  and the choke  120  can be closed. Due to the controlled flow rate, the fluid is sampled with minimum pressure changes. 
         [0097]    It will be noted that low shock sampling can also be done without the piston  110  being in the bottle as shown in  FIG. 12   c . In this case, the sampling bottle  108  must be flashed long enough to remove any of the initial filling water.  FIG. 11   b  illustrates bottle  108  during sampling. 
         [0098]    Low shock sampling is a well known technique for downhole fluid sampling. Other possible variations of fluid sampling have also been described in the prior art. 
         [0099]    The fluid sampling can be controlled either from surface or it can be controlled through a predetermined sequence of actions to be taken on a periodic base. 
         [0100]    The combination of the fact that the fluid sampling or analysis device  26  can be installed on a semi-permanent basis, the configuration of the sampling skid  22  and the possibility that sample can be obtained on a periodic basis, means that it is possible to sample the fluid without mobilizing an ROV  18  with its support vessel. Device  26  can therefore perform time-lapsed sampling during the time it is installed on a subsea apparatus  10 . With the proposed configuration, the sampling can be performed though period of time from a few months to a few years. Sample bottles  108  can be retrieved at the surface by using an ROV  18  to pick up the skid  22  on which the sample bottles  108  are located. 
         [0101]    A sampling bottle  108  may also include a temperature control unit  122 . Temperature control allows the sample temperature to be kept the same as when it was in the fluid flow of the well. It would avoid phase transition due to temperature changes. In practice, the sample will tend to cool when it is sent to the bottle  108 . The temperature control system can consist of a simple electrical heating system wrapped around the bottle. 
         [0102]    Another important feature of the invention is the ability of sampling bottles  108  to be retrieved to the surface before the skid  22  is changed. The bottle  108  may include means for energy storage, a positioning system and a propulsion mechanism. An embodiment of the apparatus  10  according to the invention which illustrates such a configuration of a sample bottle  108  is shown in  FIG. 13 . The bottle  108  in this embodiment is filled with compressed gas. An inflatable structure such as a balloon  124  is connected to the bottle  108  that is filled with compressed gas. The balloon  124  is connected to the compressed gas through a solenoid valve  116 . 
         [0103]    The bottle  108  end fittings use male/female hot stabs  107  that can be released through a command sent from the skid controller. The bottle  108  is fixed to the skid chassis through a mechanical interface that can also be released by a command sent by the skid controller. The bottle  108  also includes a localization system that can communicate with the surface. When the bottle  108  needs to be released a command is sent from the surface and this triggers the inflation of the balloon  124 , as well as the release of the end fitting and mechanical interface. In addition this also activates a localization beacon  126 . The bottle  108  is then buoyed to the surface. Once back at surface, the bottle  108  can be located and retrieved by a surface support vessel  128 . 
         [0104]    In  FIG. 4  of the drawings the fluid sampling section and the skids are shown to be in a modular configuration. The fluid sampling device  26  is configured according to the configuration described in  FIG. 5   a . The device  26  includes two sampling lines located at different heights as is described in  FIG. 7   a . The longer sampling line will sample liquid while the other shorter one will sample gas. An extraction pipe  130  is common to the gas  44  and liquid  46  sampling pipes. They form two primary loops through which production fluid circulates. 
         [0105]    The mechanical and hydraulic fluid interfaces are based on standardized stab plates  134  including electrical and hydraulic connections, as well as hydraulic valves  136  and  138 . The valves  138  are closed when a skid  22  is engaged on top of it. In all other circumstances the valves  136  and  138  are open. The mechanical interfaces of the stab plates  134  and valves  136  and  138  are the same on top of the phase separator as they are on the skids  22 . In this way the skids  22  can be stacked in any configuration on top of the separator  30 . 
         [0106]    The valves  136  and  138  are configured to connect the fluid sampling lines  46  with the extraction line  130 . As the skids  22  are connected one on top of another, the valves  138  from the lower skids are closed while the upper valves  136  are opened. The valves  138  of the lower skid  22  are closed when the upper skid connects to it. This takes place after hydraulic connection is completed. The configuration of the valves  136  and  138  allows the liquid to circulate from the separator  30  to the upper skid  22 . 
         [0107]    Fluid sampling and analysis devices  26  are located between the sampling pipes  44  and the extraction pipes  130 . There may be a pump  132  associated with these devices  26  in order to circulate the fluid from the sampling line  44  to the extraction line  130 . This configuration as shown in  FIG. 4  allows for a fully modular configuration. 
         [0108]    Another important feature of the invention is the use of subsea fluid analysis measurement by apparatus  10  to be used to control subsea equipment. The information from the apparatus  10  can be used, for example to control subsea equipment in a fully automated mode, or to control subsea equipment from the surface using the information obtained from apparatus  10 . Different controllers/communication modules  28  are connected in a network configuration with, for example, an Ethernet architecture, which allows communication and control between the different skids  22 . The information can either be sent to the surface or processed at seabed level for the direct management of the control of other subsea modules. 
         [0109]    In a fully automated mode, the information obtained from the sensors is directly processed at the seabed and a decision is made at subsea apparatus  10 . The information can be used to optimize choke opening for example. Another possible example is the optimization of chemical or water injection and the optimization of phase separator operating conditions. The information can also be sent to the surface for human based interpretation and decision making. 
         [0110]      FIG. 14  shows one embodiment of the subsea apparatus  10  and method according to the invention in which a template of fluid platforms are located on the seabed.  FIG. 14  illustrates the flow of fluids from different wellheads which are mixed through sets of manifolds before being sent to the surface. Fluid platforms are shown placed between a wellhead and a manifold. This configuration enables the production fluid flow of each individual well to be characterized. 
         [0111]    Another important feature of the subsea apparatus  10  and method according to the invention is the ability to combine the measurements obtained from the fluid sensors of devices  26  in apparatus  10  with the measurements obtained from other sensors on the seabed. 
         [0112]    One possibility is to combine fluid analysis results with multiphase flow meter measurement for flow assurance prediction. The measurement results can be fed to simulation software such as OLGA® to predict possible flow assurance problems along the subsea installation. For example, in a case where OLGA® is handling 1D dynamic simulation of fluid phase behavior along the subsea piping installation. It allows simulation from the wellhead to the surface. Critical inputs for this type of software are phase diagrams as well as the respective flow of each phase (water, oil and gas) of the fluid. A phase diagram of each phase can be obtained from a PVT sensor as illustrated in  FIG. 10 . 
         [0113]    Another possibility is the use of composition measurement. A gas chromatograph could be installed on the fluid sampling or analysis device  26  to be used for analysis so as to provide the detailed composition. Combined with equation of state this could provide a phase diagram for each phase. 
         [0114]    The apparatus  10  and method according to this invention in combination with multiphase flow meter data may be used to obtain real-time flow assurance prediction by feeding fluid properties directly into the software models that are used for this purpose. This would allow the control of subsea equipment to optimize production condition. 
         [0115]    Flow assurance problems are likely to happen during installation shut-down, therefore, providing updated information on fluid behavior just before the shut-down would be able to help provide better management of the installation. 
         [0116]    Another possible application of the apparatus and method according to the invention is its use for the optimization of chemical injection. Many chemicals are injected at different points in a subsea installation to manage a flow assurance problem. By sampling the fluid at the injector output after the inhibitor is mixed with the production fluid, it is possible to assess the efficiency of the chemical treatment and optimize the quantity of chemical to be injected. For example, the measurements of a phase behavior analyzer can be used to assess the efficiency of the treatment. By comparing the phase behavior in real time, with the operation safety envelop, it is possible to optimize the volume or the type of chemical injected. 
         [0117]    The measurement from the fluid sampling or analysis device  26  can also be used for a more accurate estimation of the flow rate from each of the different phases from a multiphase flowmeter. An important input parameter of a multiphase flow meter used in the oil and gas industry is the density of each phase. The fluid analysis device of  FIG. 9  could provide an estimation of the density of each phase that could be feedback in real-time to the multiphase flow meter for a more accurate estimation of individual flow rate. 
         [0118]    In the subsea configuration of equipment illustrated in  FIG. 14 , the fluid flow from the different wellheads is mixed through the manifolds before being brought back to the surface. The problem of identifying the contribution of each well is known in the art as allocation. The fluids before mixing can come from different formations and from different pay zones. In addition, operators may sometimes share export lines. In terms of revenue sharing, allocation is extremely important. For allocation, fluid properties as well as flow rate must be considered. Further, in terms of fluid properties, from an allocation standpoint, the important parameters are H2S content, CO2 content as well as hydrocarbon phase composition. Therefore fluid analysis data obtained from the apparatus  10  could be used for real time correction of allocation calculation.