SUBSEA FLUID SAMPLING AND ANALYSIS

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

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.

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, CO₂, 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.

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.

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.

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 '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.

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.

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).

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

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.

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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.

Further aspects of the invention will be apparent from the following description.

BRIEF DESCRIPTION OF SEVERAL VIEWS OF THE DRAWING

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;

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);

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;

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;

FIG. 5a 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;

FIG. 5b 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;

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;

FIGS. 7a, 7b and 7c show a series of diagrammatic views of an adjustable inlet of a sampling device according to an embodiment of the invention;

FIG. 8 shows a schematic layout of a fluid analyser of the subsea apparatus for analysing fluid from a well;

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;

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;

FIGS. 11, 11a, 11b and 11c 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;

FIGS. 12, 12a, 12b and 12c 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;

FIG. 13 shows schematic view of a self retrievable sampling bottle apparatus of the subsea apparatus according to one embodiment of the invention; and

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Details will now be provided of further embodiments of the invention.

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.

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.

Phase generator 30 allows liquid can be sampled at the bottom of the vessel while gas can be sampled at the top.

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.

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. 5a, 5b and 6 by arrows B.

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. 5a and 5b. In FIG. 5b, 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.

In FIG. 5a, the fluid in the extraction line is dragged by the main flow in a perforated pipe 50.

FIG. 6 describes an active sampler using a pump 52 to generate the fluid flow from the inlet to the outlet.

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.

One possibility is to have two or more inlet pipes 40.1 and 40.2 with different heights as is illustrated in FIG. 7a. 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.

Another possibility which is described in FIG. 7b 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.

FIG. 7c 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

The sampling bottle 108 can be implemented as follows:

A cylindrical bottle 108 with a piston 110 defining two chamber spaces as it moves along the bottle'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.

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. 11a, 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.

It will be noted that low shock sampling can also be done without the piston 110 being in the bottle as shown in FIG. 12c. In this case, the sampling bottle 108 must be flashed long enough to remove any of the initial filling water. FIG. 11b illustrates bottle 108 during sampling.

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.

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.

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.

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.

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.

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.

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. 5a. The device 26 includes two sampling lines located at different heights as is described in FIG. 7a. 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Claims

1. 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.

2. Subsea apparatus as in claim 1, further comprising at least one electronic device which

incorporates at least one software model used to provide information regarding the production of said subsea well.

3. Subsea apparatus as in claim 1, wherein the fluid analysis data is used to control at least one subsea piece of equipment.

4. Subsea apparatus as in claim I, wherein 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.

5. Subsea apparatus as in claim 1, wherein at least one data processing device is located in the housing and is in communication with the fluid analysis device.

6. Subsea apparatus as in claim 1, wherein the conveying means is an attachment for a detachable subsea vehicle.

7. Subsea apparatus as in claim 6, wherein the conveying means is an attachment for a remotely operated vehicle (ROV) and/or an autonomous underwater vehicle (AUV).

8. Subsea apparatus as in claim 1, which comprises a plurality of fluid analysis devices which are connected to each other.

9. Subsea apparatus as in claim 1, which comprises a plurality of housings connected to each other in a modular fashion located in close proximity to said subsea fluid flowline, 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.

10. 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.

11. The method as in claim 10, wherein 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.

12. The method as in claim 10, wherein at least one data processing device is locatable in the housing and is 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.

13. The method as in claim 10, wherein the conveying means is an attachment for a detachable subsea vehicle.

14. The method as in claim 10, wherein there are a plurality of housings, and which further comprises 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.