Abstract:
A method and system for producing fluid from a subsea wellbore. An amount of fluid is sampled from fluid being produced and retained for a period of time until constituents in the fluid stratify. A fluid characteristic is sensed at spaced apart vertical locations in the sampled fluid. A water fraction as well as gas content can be ascertained from sensing the sampled fluid. The fluid characteristic is used for calibrating a multi-phase flowmeter that measures flow of the fluid being produced from the wellbore.

Description:
BACKGROUND 
       [0001]    1. Field of Invention 
         [0002]    The invention relates generally to a system and method for sampling a connate fluid subsea. More specifically, the present invention relates generally to a method and device for automatically sampling fluid at a subsea wellhead. 
         [0003]    2. Description of Prior Art 
         [0004]    Subsea wellbores are formed from the seafloor into subterranean formations lying underneath. Systems for producing oil and gas from subsea wellbores typically include a subsea wellhead assembly set over an opening to the wellbore. Subsea wellheads usually include a high pressure wellhead housing supported in a lower pressure wellhead housing and secured to conductor casing that extends downward past the wellbore opening. Wells are generally lined with one or more casing strings coaxially inserted through, and significantly deeper than, the conductor casing. The casing strings are typically suspended from casing hangers landed in the wellhead housing. One or more tubing strings are usually provided within the innermost casing string; that among other things are used for conveying well fluid produced from the underlying formations. The produced well fluid is typically controlled by a production tree mounted on the upper end of the wellhead housing. The production tree is typically a large, heavy assembly, having a number of valves and controls mounted thereon 
         [0005]    Well fluids can be produced from a subsea well after the wellhead assembly is fully installed and the well completed. Produced well fluid is generally routed from the subsea tree to a manifold subsea, where the fluid is combined with fluid from other subsea wells. The combined fluid is then usually transmitted via a main production flow line to above the sea surface for transport to a processing facility. Often, a pump is required for delivering the combined produced fluid from the sea floor to the sea surface. Thus knowledge of the well fluid flow and constituency is desired so the pump and flow line can be adequately designed. While the fluid is often analyzed at sea surface, fluid conditions, e.g. temperature, pressure, are generally different subsea. Moreover, the respective ratios of fluid components, as well as the components themselves, often change over time. As such, a time lag of knowledge of the fluid in the flow lines may occur. 
       SUMMARY OF THE INVENTION 
       [0006]    Disclosed herein is a method of and system for producing fluid from a subsea wellbore. In one example the method includes obtaining an amount of fluid produced from the wellbore, where the fluid obtained is referred to as sampled fluid. The sampled fluid is isolated in a container that is adjacent the wellbore. The sample fluid is sensed at locations that are vertically spaced apart, where the sensing takes place over a period of time after the sampled fluid is obtained. Using the information obtained by sensing, a constituent of the sampled fluid is identified. The method can further include identifying stratification of the sampled fluid into phases based on the step of sensing. The container can be mechanically coupled to a production tree mounted over the subsea wellbore. In an example, the fluid produced from the wellbore flows through a flowmeter; in this example the method further involves adjusting a value of a measurement obtained using the flowmeter based on the step of identifying a constituent of the sampled fluid. In one example embodiment, an amount of water in the sampled fluid and the flowmeter is a multi-phase flowmeter is identified. The method may optionally further include estimating a percentage an identified constituent makes up of the total sampled fluid. In one alternate embodiment, the steps of obtaining and retaining the sampled fluid include flowing the amount of fluid into a sample flow line having valves and closing the valves to isolate the sampled fluid between the valves in the sample flow line. Optionally, the step of sensing includes measuring a property of a discrete portion of the sampled fluid with a sensor disposed at each of the vertically spaced locations. The method may further include releasing the amount of sampled fluid from the container and into a production flow line that transmits fluid produced from the wellbore. 
         [0007]    Also disclosed herein is a subsea wellhead assembly, that in one example embodiment is made up of a wellhead housing mounted over a subsea wellbore, a production tree coupled to the wellhead housing, a production flow line in fluid communication with the production tree, and a sample circuit. The sample circuit includes a container selectively in fluid communication with the production flow line and a sensor system. The sensor system has fluid sensors that are in communication with vertically spaced points along an inside of the container. Optionally, the sample circuit further includes an inlet in fluid communication with the production flow line, an outlet in fluid communication with the production flow line, an inlet valve in fluid communication with the inlet, and an outlet valve in fluid communication with the outlet, and wherein the container is defined between the inlet and outlet valves. In one alternate embodiment, a value characterizing flow through the production flow line is measured with a flowmeter and the value is adjusted based on an output of the sensor system. Optionally, the sensor system is in communication with the flowmeter through a control module provided on the production tree. 
         [0008]    A method of producing fluid from a subsea well is disclosed that involves retaining an amount of fluid produced from the well in a sealed environment that is subsea and proximate the subsea well and sensing a characteristic of the fluid at discrete vertically spaced apart locations in the sealed environment. A rate of flow of fluid produced from the well is measured and adjusting the measured rate of flow based on a result of the sensing. Optionally, a multi-phase flowmeter is used to measure a rate of flow of fluid and wherein the step of adjusting includes calibrating the flowmeter. In one alternate embodiment, the step of sensing takes place over a period of time ranging up to at least about  10  hours. Alternately, sensing is repeated until water and hydrocarbon liquid in the fluid being retained has substantially stratified. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0009]    Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which: 
           [0010]      FIG. 1  is a side sectional view of an example embodiment of a wellhead assembly with a sampling system in accordance with the present invention. 
           [0011]      FIGS. 2A-2C  are side sectional views of an example details of an embodiment of the sampling system of  FIG. 1 . 
       
    
    
       [0012]    While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims. 
       DETAILED DESCRIPTION OF INVENTION 
       [0013]    The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. 
         [0014]    It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation. Accordingly, the improvements herein described are therefore to be limited only by the scope of the appended claims. 
         [0015]    An example embodiment of a wellhead assembly  20  is shown in a side sectional view in  FIG. 1 . In the example of  FIG. 1 , the wellhead assembly  20  includes a production tree  22  coupled on a wellhead housing  24 ; where the wellhead housing  24  is shown mounted over a wellbore  26 . An amount of annular production tubing  28  extends downward from within the wellhead housing  24  and into the wellbore  26 . A main bore  30  is shown extending axially within the wellhead housing  24  further upward into the production tree  22 . A main valve  32  is set within the main bore  30  and in the portion circumscribed by the production tree  22 . Selective opening, or closing, of the main valve  32  communicates, or isolates, fluid in the production tubing  28  and a production line  34  laterally projects through the production tree  22  above the main valve  32 . A swab valve  36 , shown above the main valve  32  and in the main bore  30 , isolates an upper end of the main bore  30  from outside of the wellhead assembly  20 . A wing valve  38  is shown set within the production line  34  for isolating various portions of the production line  34  from one another. Also shown within the production line  34  is a choke  40  for regulating and/or controlling flow of fluid through the production line  34 . Further downstream from the choke  40  is an isolation valve  42  for providing additional isolation of fluid communication through the production line  34 . 
         [0016]    Further shown in the example embodiment of  FIG. 1  is a sampling circuit  44  having an inlet  45  in fluid communication with the production flow line  34  and an inlet valve  46  set just downstream of the inlet  45  and within the sample circuit  44 . Similarly, an outlet  47  of the sampling circuit  44  defines where an end of the sample circuit  44  intersects with the production line  34 . A sample valve  48  is provided in the sample circuit  44  and upstream of the outlet  47 . In the example embodiment of  FIG. 1 , the sample circuit  44  is made up of an annular passage defined in the space between the inlet and outlet valves  46 ,  48 . 
         [0017]    In one example of operation of the sample circuit  44 , inlet valve  46  is moved from a closed to an opened position, thereby providing for fluid communication between the production line  34  and inside of the sample circuit  44 . Outlet valve  48  may also be opened thereby fully filling the sample circuit  44  with fluid produced from inside of the wellbore  26  and to flush out any other fluids, such as air, or residual fluid from a previous sampling, thereby ensuring a true and accurate sample. To regulate the amount of flow passing into the sample circuit  44 , the choke  40  may be urged into a restricted or closed position thereby forcing more flow of fluid through the sample circuit  44 . When it is determined that fluid fully fills the sample circuit  44 , inlet and outlet valves  46 ,  48  can be closed thereby retaining and isolating the sampled fluid from the wellbore  26  within the sample circuit  44 . 
         [0018]      FIGS. 2A through 2C  show in one example embodiment sensing of the fluid retained within the sample circuit  44 . Specifically referring to  FIG. 2A , sampled fluid  50  fills the space defined by the valves  46 ,  48  and walls of a container  51  making up the sample circuit  44 . In the example of  FIG. 2A , the container  51  is a tubular member. In an alternate embodiment the portion of the sample circuit  44  between the valves  46 ,  48  includes a passage (not shown) formed through a substantially solid member, such as the production tree  22 . In an example embodiment depicted in  FIG. 2A , constituents of the fluid  50  include liquid  52  and gas  54 . The walls of the container  51  having the fluid  50  define a vessel. Sensors  56   1  . . .  56   n  are shown in the wall of the container  51  and in communication with the fluid  50  within the sample circuit  44 . In one example embodiment, the sensors  56   1  . . .  56   n  measure various fluid properties, such as density, viscosity, temperature, pressure, and the like, and may use resistance, capacitance, or other means for measuring these properties. Further, the sensing of the fluid properties can characterize the fluid adjacent each of the sensors  56   1  . . .  56   n . The sensors  56   1  . . .  56   n  are shown having an end coupled to a signal line  60   1  . . .  60   n , wherein the distal end of these lines  60   1  . . .  60   n  coupled to a controller  58 . In an example embodiment, the controller  58  sends and/or receives data signals, can process the data signals, and can run executable code in response to receiving/sending a data signals. In one example, the controller  58  includes an information handling system. 
         [0019]    Referring now to  FIGS. 2B and 2C , in  FIG. 2B  the sample fluid  50  is shown after a period of time when the gas  54  has stratified and separated from the liquid  52 . As such, position of sensors  56   1 ,  56   2  are positioned at discreet vertical locations along the wall of the container  51  and provide information about the gas constituent of the fluid  50 . Moreover, when compared to what is sensed by sensors  56   3  . . .  56   n , the gas content of the fluid  50  may be estimated. In  FIG. 2C , the fluid  50  is shown further stratified such that the liquid  52 A has separated into a water fraction  62  shown residing adjacent the outlet valve  48  and a hydrocarbon fraction  64  that extends in the liquid column  52 A on the upper end of the water fraction  62  to a lower end of the gas fraction  54 . Further, the strategically disposed sensors  56   1  . . .  56   n , being set substantially along the entire length of the container  51 , can be used to detect where in the container  51  are interfaces between the different types of fluids making up the produced fluid so that a mass percent of produced fluid may be estimated. It is believed it is within the capabilities of those skilled in the art to ascertain fluid composition based on output from the sensors  56   1  . . .  56   n . 
         [0020]    Further illustrated in  FIG. 2C  is a signal line  66  that provides communication between the controller  58  and a service control module  68  ( FIG. 1 ). Referring back to  FIG. 1 , the service control module  68  is further illustrated in signal communication via a signal control line  70  with a flow indicator  72 . The flow indicator  72  is associated with a flowmeter  74  that is disposed in the production flow line downstream of the isolation valve  42 . The flowmeter  74  which in one example embodiment is a multiphase flowmeter, can be upstream of a manifold (not shown) where production lines from other subsea wells are combined into a single flow line. 
         [0021]    As is known, the accuracy of multiphase flow meters can be significantly improved by a rough estimation of the different fluid phases within the total flow, such as the total water cut in the flow. Thus, in one example of operation, the information about the sampled fluid  50  can be integrated with a measured flow rate through the flow meter  74  to further calibrate the flowmeter  74  and thereby arrive at a more precise and accurate actual flow through the flowmeter  74 . 
         [0022]    One of the advantages of the method and device disclosed herein is that automatic fluid sampling may be achieved without need for remote intervention such as that from a remotely operated vehicle. Optionally, the time at which the sampled fluid  50  is obtained and allowed to stratify can range up to a few hours and in excess of a few days, as well as up to a hundred hours. 
         [0023]    The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.