WO2011119479A1

WO2011119479A1 - Mass flow meter

Info

Publication number: WO2011119479A1
Application number: PCT/US2011/029184
Authority: WO
Inventors: Charles Edward Higham Tyrrell
Original assignee: Shell Oil Company; Shell Internationale Research Maatschappij B.V.
Priority date: 2010-03-23
Filing date: 2011-03-21
Publication date: 2011-09-29

Abstract

A system comprising a subsea well drilled into a subsurface formation located beneath a body of water; a wellhead located at a top end of the subsea well and located on a sea floor; a manifold located on the sea floor; and a flowline connecting the wellhead and the manifold, the flowline comprising one or more sensors adapted to measure a mass flow rate through the flowline.

Description

MASS FLOW METER

BACKGROUND OF INVENTION

[0001] United States Patent Application Publication US 2008/0034890 discloses a coriolis flowmeter configured to determine a first property of a multi-phase fluid. A flow model is configured to determine a second property of the multi-phase fluid. A determination system is configured to determine a third property of the multi-phase fluid based, at least in part, on the first property and the second property. United States Patent Application Publication US 2008/0034890 is herein incorporated by reference in its entirety.

[0002] United States Patent Application Publication US 2005/0081643 discloses a flowmeter. The flowmeter includes a vibratable flowtube, and a driver connected to the flowtube that is operable to impart motion to the flowtube. A sensor is connected to the flowtube and is operable to sense the motion of the flowtube and generate a sensor signal. A controller is connected to receive the sensor signal. The controller is operable to determine a first flow rate of a first phase within a two-phase flow through the flowtube and determine a second flow rate of a second phase within the two-phase flow. United States Patent Application Publication US 2005/0081643 is herein incorporated by reference in its entirety.

[0003] United States Patent 4,689,989 discloses a portable instrument for testing at the wellhead continuously, or a stationary instrument for use at a production battery, the outflow of crude hydrocarbons from the well or wells. The instrument utilizes a simple relationship of density and thermal coefficients of expansion of the oil and the water, together with improved instrumentation to measure mass flow rate of the crude mixture, to produce accurate continuous readings of oil and water contents in the crude. The instrument depends upon state of the art technology both as to the crude handling and the electronics portions of its apparatus. United States Patent 4,689,989 is herein incorporated by reference in its entirety.

[0004] There is a need in the art for improved systems and methods for determining flow rates from a subsea well. There is a need in the art for improved systems and methods for determining flow rates from a group of subsea wells. SUMMARY OF INVENTION

[0005] One aspect of the invention provides a system comprising a subsea well drilled into a subsurface formation located beneath a body of water; a wellhead located at a top end of the subsea well and located on a sea floor; a manifold located on the sea floor; and a flowline connecting the wellhead and the manifold, the flowline comprising one or more sensors adapted to measure a mass flow rate through the flowline.

BRIEF DESCRIPTION OF DRAWINGS

[0006] Figure 1 shows a perspective view of a subsea production system in accordance with embodiments of the present disclosure.

[0007] Figure 2 shows a side view of components of a subsea production system, with a mass flow meter coupled therebetween, in accordance with embodiments of the present disclosure.

[0008] Figure 3 shows a perspective view of a subsea production system including a mass flow meter in accordance with embodiments of the present disclosure.

[0009] Figure 4 shows a simplified schematic diagram of a mass flow meter in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

[0010] In one aspect, embodiments disclosed herein relate generally to a mass flow meter and systems for using the same. Other embodiments disclosed herein relate to a mass flow meter configured to vibrate at low natural frequencies, such that the mass flow meter may detect various properties associated with fluid flow. Specific embodiments relate to a Coriolis mass flow meter that may be coupled between oilfield components disposed in a subsea environment. In other aspects, embodiments disclosed herein may provide a method of operating a mass flow meter coupled between oilfield components disposed in a subsea production system.

[0011] It is to be understood that the various embodiments described herein may be used in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various environments, such as subsea or underground, without departing from the scope of the present disclosure. The embodiments are described merely as examples of useful applications, which are not limited to any specific details of the embodiments herein. Further, in the following detailed description, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter.

However, it will be apparent to one of ordinary skill in the art that the embodiments described may be practiced without these specific details. In other instances, well- known features have not been described in detail to avoid unnecessarily complicating the description. Embodiments of the present disclosure will now be described in detail with reference to the accompanying figures. Like elements in the various figures may be denoted by like reference numerals for consistency.

[0012] Figure 1:

[0013] Referring to Figure 1, a subsea production system according to embodiments of the present disclosure is shown. A subsea production system 100 may include various components used in the production of hydrocarbons from a wellbore 14 drilled into a subsea formation, as would be known to a person having ordinary skill in the art. For example, system 100 may include a well production hub or manifold 16 that may provide fluid communication and/or mechanical intervention between at least one subsea wellbore 14 and a production facility 20. As known in the art of subsea hydrocarbon production, the manifold 16 may be an arrangement of piping, valves, etc., designed to control, distribute or monitor fluid flow within the system 100.

After the wellbore 14 is drilled and cased, a wellhead 18 may be installed on the wellbore 14 to control fluid flow into and out of the wellbore 14. A jumper line 10 may be coupled between the wellhead 18 and the manifold 16, and as shown in Figure 1, system 100 may have a plurality of jumper lines 10 to connect any number of wellbores 14 to the manifold 16. It should also be appreciated that there may be more than one manifold 16 in fluid communication with other manifolds (not shown) to facilitate the connection of multiple well fields (not shown).

Production fluids may flow from the wellbore 14 to the manifold 16, and then through at least one transfer line 12 to the production facility 20. Although the production facility 20 is shown as a stationary facility above the surface of the water, the location of the production facility 20 may reside elsewhere, such as below the surface of the water or onshore. Although not shown, the subsea production system 100 may be provided with applicable utilities that support the operation of the system 100, such as hydraulic pressure and electrical power. Other variants of a subsea production system 100 may be tailored to suit seabed or formation conditions, as may be applicable, but are not further described here. Suitable production facilities 20 may include a semi submersible, an FPSO, a tension leg platform, a spar, or other facilities as are known in the art.

Figure 2:

Referring to Figure 2, components of a subsea production system, with a mass flow meter coupled therebetween, in accordance with embodiments disclosed herein, are shown. A mass flow meter 1, which may include a flow line 32, may be installed between components prior to being lowered to the seabed floor (S, Figure 3), such as on a fabricated sled or skid. In the embodiment illustrated in Figure 2, the mass flow meter 1 may be installed and coupled between the wellhead 18 and the manifold 16 before the wellhead 18, manifold 16, and mass flow meter 1 are lowered to the seabed floor (S, Figure 3). However, the installation of the mass flow meter 1 is not meant to be limited, and the mass flow meter 1 may be installed in any fashion, such as in situ between other submerged oilfield components already connected within system 100. Other embodiments may include the placement of the mass flow meter 1 between submerged components through the use of a remotely operated vehicle (ROV) (not shown) or a diver or submarine, or any other suitable means or method that provides subsea coupling.

The mass flow meter 1 may have substantially linear portions, bent portions, or combinations thereof. A substantially linear portion would be understood to a person having ordinary skill in the art as being "straight," whereas a bent portion may be, for example, "turned," "twisted," or "curved," but is not meant to be limited by the description other than a shape that is non-linear. A combined linear portion and bent portion may resemble, for example, a general "U," "S," or "W-shape." The flow line 32 of the mass flow meter 1 may be constructed of any material commonly used in the art, such as steel, aluminum, or other rigid metals; however, the materials of construction are also not meant to be limited and may include other materials, such as fiberglass, plastics, rubber, or composite materials, etc. For example, the flow line 32 may be constructed of flexible flowline to provide durability and flexibility.

The mass flow meter 1, in accordance with the present application, may measure and/or calculate various properties associated with fluid flow, such as the mass flow rate, based on the resultant Coriolis forces acting on the meter 1. When measuring Coriolis forces, the length of a vibrated tube in a mass flow meter may be an important parameter, because the flow meter sensitivity (i.e., accuracy) increases proportionally as the total length of the tube increases. A longer tube length for a mass flow meter also has an inverse relationship to the natural frequency of the tube, such that the lower the natural frequency required for vibration to produce Coriolis forces, the higher the accuracy of the meter. Therefore, the longer the length of tube, the greater the accuracy of the mass flow meter.

Accordingly, the length of the flow line 32 of mass flow meter 1 may be selected to provide vibration at a selected natural frequency. In other words, the length of the flow line 32 of mass flow line 1 coupled between existing subsea pipes and/or components of subsea system 100 may be selected to provide a predetermined accuracy of the measurement of the mass of the fluid flow therethrough. In an exemplary embodiment, the mass flow meter 1 may include a significantly long, unconstrained flow line 32 coupled between subsea oilfield components, such that the flow line may be in the range from about 1 to about 100 meters, for example from about 5 to about 50, or from about 10 to about 25 meters.

The mass flow meter 1 may include one or more support elements 22 and 23 disposed on either end of the flow line 32. The supports 22 and 23 may provide support for the mass flow meter 1 when it is coupled between other components. For example, the supports 22 and 23 may be flange-type connectors that may couple with corresponding flanges 64 and 65 of the wellhead 18 and the manifold 16, respectively. In one embodiment, the length, L, of the flow line 32 between the support elements 22 and 23 may determine the natural frequency at which the flow line 32 vibrates, as discussed above. Support for the mass flow meter 1 may also be provided by a surface, such as the sea floor (S, Figure 3), one or more cables, a truss structure, or a sled resting on the sea floor.

Although embodiments described herein may be for a subsea production system 100, the mass flow meter 1 may be operable with other sizes and shapes of pipes and/or components, and in other environments, such as, for example, other oilfield components disposed offshore or onshore.

Figure 3:

Referring now to Figure 3, a subsea production system 100 that includes a mass flow meter 1, in accordance with embodiments disclosed herein, is shown. As previously mentioned, the mass flow meter 1 may be coupled between various subsea components, such as the wellhead 18 and the manifold 16. In accordance with embodiments disclosed herein, the flow line 32 of the mass flow meter 1 may be vibrated by a driver 24. As fluid flows through the vibrated flow line 32, the resultant Coriolis forces may cause a subsequent motion (e.g. , twisting, bending, etc.) of the flow line 32. These forces may be, for example, forces that are perpendicular to both the velocity of the mass moving through the flow line 32 and the angular velocity vector of the vibration of the flow line 32. Any motion of the flow line 32 as a result of the forces imparted on the flow line 32 may be measured at various points along the flow line 32 by various sensors (e.g. , position sensors, velocity sensors, etc.) (not shown).

In order to vibrate the flow line 32 at a particular frequency, the mass flow meter 1 may include the driver 24 that operates over a wide range of frequencies, and is attached thereto. In one embodiment, the driver 24 may vibrate the flow line 32 at a low natural frequency of the flow line 32. For example, the natural frequency of the flow line 32 may be in the range of 100 to 100,000 Hz, and the driver 24 may be configured to vibrate the flow line 32 within the frequency range from about 80 to about 1000 hertz. In an exemplary embodiment, the driver 24 may be configured to vibrate the flow line 32 at a very low natural frequency. For example, the flow line 32 may have a very low natural frequency.

Although Figure 3 illustrates the driver 24 of the mass flow meter 1 coupled to the outside surface of the flow line 32, the manner and configuration of the driver 24 of the mass flow meter 1 is not meant to be limited. For example, the driver 24 may be disposed within the flow line 32, and coupled to the inner surface (not shown) of the flow line 32. The driver 24 may be coupled in any manner as would be known to a person having ordinary skill in the art, such as fastened, welded, clamped, etc. Although shown as a single driver 24, there may be additional drivers coupled to the mass flow meter 1 as needed. For example, there may be a second driver (not shown) coupled to the flow line 32 for redundancy purposes.

In accordance with embodiments disclosed herein, the driver 24 may be any type of device that may vibrate the flow line 32 at a selected frequency. For example, the driver 24 may be a magneto strictive driver that vibrates the flow line 32 at the natural frequency of the flow line 32. In such an example, the driver 24 may include a magnet and coil configuration that may be coupled directly to the flow line 32 so that the magnet and coil sufficiently vibrate the flow line 32. To generate the vibration, an alternating current may be passed through the coil, such that vibration of the flow line 32 provided by the driver 24 may be sinusoidal. In this manner, the coil may move through the magnetic field of the magnet, and the voltage generated from the coil movement may create a sine wave signal that is proportional to the amount of fluid flow through the flow line 32. Although described as a magnet and coil, the exact configuration of the driver 24 is not meant to be limited, and the driver selection may be based on many variables, such as the power, force, frequency, motion required, etc. for operation of the mass flow meter 1. In other embodiments, the driver 24 may be part of a feedback circuit (not shown), which may maintain a constant desired frequency and amplitude of vibration for the flow line 32.

Because motion may occur in the flow line 32 as a result of vibration at a certain frequency, the phase of the motion at various points along the flow line 32 may no longer be equal. For example, the flow line 32 may have a portion that moves with a phase lag, and another portion of flow line 32 that moves and may lead in phase. The phase difference or time lag between the moving portions (i.e., sinusoidal motion) may also be representative of, or proportional to, the mass flow through the flow line 32.

Figure 4:

Referring to Figure 4, a simplified schematic diagram of a mass flow meter 1 according to embodiments of the present disclosure is shown. The mass flow meter 1 may include the flow line 32 operably connected with at least one sensor, or a plurality of sensors 27 and 29, disposed thereon; however, the position and/or connectivity of any sensors with the mass flow meter 1 is not meant to be limited, and the sensors may be disposed in any fashion along or within the mass flow meter 1 as may be suitable. In addition, while the flow line 32 may have the sensors directly disposed thereon, the flow line 32 may optionally be connected with other sensors contained within a sensor unit (not shown).

[0031] As previously mentioned, the Coriolis forces that result from fluid flow through the vibrated flow line 32 may cause movement of the flow line 32. Accordingly, the sensors 27 and 29 may sense information, such as position, velocity, acceleration, or any other useful signal that may be used in the measurement of the motion of the flow line 32. However, the type of sensors is not meant to be limited, and the sensors may be any sensor known to a person having ordinary skill in the art for sensing motion. The choice of sensor used may be based upon any number of considerations, such as, for example, economics, effectiveness, ease of construction, availability and stability of appropriate circuitry, or combinations thereof.

[0032] The sensors operably connected with the flow line 32 may provide a signal output that may be converted and processed into a signal that is indicative of the mass flow through the flow line 32. For example, the signal output of sensors 27 and 29 may be processed by an electronic controller 26. The operable connection between the sensors and the flow line 32 may be by any means known in the art, such as an electrical connection and associated circuitry. As shown, the sensors 27 and 29 and/or the mass flow meter 1 may communicate with the electronic controller 26 via a communication link. In addition, the mass flow meter 1 may communicate directly to operators in a production facility (20, Figure 1) via a user interface (not shown), and the mass flow meter 1 may also be configured with other peripheral devices such as a transmitter, or other monitoring and/or control elements (not shown).

[0033] As mentioned, the sensors 27 and 29 may be any kind of sensor useful in sensing motion of the flow line 32, such as accelerometers that may measure the acceleration or motion at various points along the flow line 32. In one embodiment, the accelerometer may be a three-axis accelerometer in order to provide sensor information for tri-axial motion of the flow line 32. Motion of the flow line 32 may also be sensed by optical fiber sensors. For example, an optical fiber sensor may include at least one loop of optical fiber (not shown) that may be flexed by the motion of the flow line 32. The flexing of the fiber may cause a corresponding change in the optical conductivity, and a corresponding change in the intensity of the light transmitted through the fiber from a light signal source to the controller (not shown). Accordingly, the light signal received by the controller 26 may be converted to an electrical signal that is representative of the mass flow rate through the flow line 32. Alternatively, one or more Bragg gratings may be provided and connected to an exterior surface of the flow line 32, such that motion of the flow line 32 causes a corresponding motion in the Bragg grating which would be transmitted to a processor by a fiber optic cable.

Because flow line 32 may be vibrated at a low natural frequency, the mass flow meter 1 may provide an accurate, dependable measurement that is less susceptible to extraneous noise and vibrations. However, in some situations, the mass flow meter 1 may be used in environments that may affect the accuracy of the mass flow meter 1. For example, if the mass flow meter 1 is coupled in areas of high wind or water current, or is emplaced with a limited amount of rigid support, the wind or other elements may adversely affect the accuracy of the mass flow meter 1. As another example, the mass flow meter 1 may be used in subsea applications, and may be affected by extraneous motions, such as vortex induced vibrations, caused by strong currents. Thus, embodiments of the present application may also include the use of a correction device or circuitry to account for inadvertent movement and other background noise of the mass flow meter 1. In one embodiment, there may be a correction circuit configured to account for the effects of subsea currents through the use of localized measurement devices.

Embodiments disclosed herein may provide for a method of operating a mass flow meter 1 coupled between oilfield components in a subsea production system. For example, the method may include positioning a first subsea component and a second subsea component on a seabed floor. The method may further include connecting the mass flow meter 1 of the present application between the first and the second subsea components. The mass flow meter 1 may include, for example, at least one flow line, at least one sensor, and at least one driver, wherein the at least one sensor and driver are operably connected with the flow line.

The method may also include the steps of flowing a fluid through the flow line, activating the driver to vibrate the flow line, and generating Coriolis forces. In addition, the method may include other steps, such as measuring a parameter associated with the Coriolis forces, and indicating the mass flow rate of the fluid flowing through the at least one flow line.

Embodiments disclosed herein may include one or more of the following advantages. A mass flow meter of the present disclosure may help maximize and optimize hydrocarbon production, such that the ability to accurately measure the flow rate may be advantageous over other prior art flow meters. In certain embodiments, the present disclosure may provide a Coriolis mass flow meter configured to provide mass flow measurement of hydrocarbons produced from a subsea production well. Advantageously, the placement of the mass flow meter between subsea oilfield components may eliminate the need for additional flow meters on each wellhead.

[0038] The length of the mass flow meter may be substantial and unconstrained, and may also include vibration of the flow line at a very low natural frequency, to provide a highly accurate measurement. The selected length of the mass flow meter may allow the meter to be much less sensitive to entrained gases. In some embodiments, the present disclosure may provide a highly accurate mass flow meter that is unaffected by extraneous noises or vibrations.

[0039] While the present disclosure has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the disclosure as described herein. Accordingly, the scope of the disclosure should be limited only by the attached claims.

Claims

C L A I M S

1. A system comprising: a subsea well drilled into a subsurface formation located beneath a body of water; a wellhead located at a top end of the subsea well and located on a sea floor; a manifold located on the sea floor; and a flowline connecting the wellhead and the manifold, the flowline comprising one or more sensors adapted to measure a mass flow rate through the flowline.

2. The system of claim 1, further comprising: a second subsea well drilled into a subsurface formation; a second wellhead located at a top end of the second subsea well and located on the sea floor; and a second flowline connecting the second wellhead and the manifold, the second flowline comprising one or more sensors adapted to measure a mass flow rate through the second flowline.

3. The system of one or more of claims 1-2, further comprising: an export line connected to the manifold at a first end and

connected to a production facility at a second end.

4. The system of one or more of claims 1-3, further comprising: a driver connected to the flowline, the driver adapted to vibrate the flowline at a desired frequency.

5. The system of claim 4, wherein the desired frequency is in the range from 100 to 500 Hertz.

6. The system of one or more of claims 1-5, wherein the flowline comprises one or more straight portions and one or more curved portions.

7. The system of one or more of claims 1-6, wherein the system is located at a water depth of at least about 1000 meters.

8. The system of one or more of claims 1-7, wherein the flowline comprises a plurality of drivers.