Multiphase flow rate monitoring means and method

Abstract: A test line (8) includes a chamber (12) inclined downwardly at an angle so that stratification of a petroleum stream into liquid and gas occurs. A sample stream (15) is taken from the chamber, any gas separated therefrom (19), and the water fraction (WC) of the liquid portion is determined (44). Instruments sense and determine the pressure (P), temperature (T), flow rate (FR) and density (D) of the petroleum stream. A computer (50) determines the volumetric flow rates of the gas, oil and water components of the petroelum stream in accordance with the signals (WC, P, T, FR and D).

Description: The present invention relates to petroleum stream analyzers, i.e. to flow rate monitors for monitoring the component flow rates of a composite petroleum stream having a gas component, an oil component and a water component (which may be brine). GB-A-2180352 describes a flow rate monitor for monitoring the component flow rates of a composite petroleum stream having a gas component, an oil component and a water component, comprising: a test line including a chamber inclined downwardly at an angle so that stratification of liquid and gas occurs in the chamber; sampling means for providing a sample stream from the liquid in the chamber; means for separating gas from the sample stream to provide a gas output and a liquid output; means for returning said gas output and said liquid output to the test line; sensor means for sensing predetermined physical variables of said stream and providing signals respectively representative thereof; and means for providing flow rate signals representative of the volumetric flow rates of the gas, oil and water components of the composite petroleum stream in accordance with said signals provided by said sensor means. The sensor means described in that document consists of the combination of: a temperature sensor to sense the liquid output temperature and provide a signal (E1); a pressure sensor to sense the pressure and provide a signal (E2); a gas velocity measuring means to measure the velocity of the gas after stratification and provide a signal (E3); a liquid velocity meter to measure the velocity of the liquid after stratification and provide a signal (E4); a densitometer to sense the density of the fluid and provide a signal (E5); and water fraction means to determine the water fraction of the liquid output and provide a signal (E6). It is also necessary to know the cross-sectional area (A) of the stratification tube. The present invention is characterized by the features as set out in Claim 1 where in particular the sensor means comprises the combination of: water fraction means for determining the water fraction of said liquid output and providing a water fraction signal representative thereof; pressure means for sensing the pressure of the composite petroleum stream and providing a pressure signal representative thereof; temperature means for sensing the temperature of the composite petroleum stream and providing a temperature signal representative thereof; flow rate means for monitoring the volumetric flow rate of the composite petroleum stream and providing a flow rate signal representative thereof; and density means for monitoring the density of the composite petroleum stream and providing a density signal representative thereof. The present invention also provides a monitoring method as set out in Claim 5. An embodiment of the present invention will now be described, by way of example, with reference to the accompanying drawing. The drawing is in part a simplified block diagram and in part schematic showing a flow rate monitor, constructed in accordance with the present invention, for a multiphase petroleum stream. The present invention represents a new apparatus for metering gas, oil and water/brine production rates that will perform at least equal to, or better than conventional apparatus. It should be noted that the word "water" shall be used hereinafter in lieu of "water/brine" and shall cover any water regardless of salinity. Furthermore, apparatus of the present invention is more reliable and can be made more compact and less expensive than commercially available metering systems. The present invention is suitable for measuring the individual flow rates of oil, gas and water components of a multiphase petroleum stream, such as a composite production stream from an oil well. The meter is suitable for installation subsea, at the surface of the sea, on an offshore platform, or onshore. The meter can be sized to accommodate wide ranges of liquid and gas flow rates with water fractions (cuts) from zero to 100 percent. Referring now to the Figure, there is shown a pipeline 5 connected to a test line 8, as indicated by flanges 10. Test line 8 rises vertically and then slopes down at a predetermined angle sufficient to stratify the composite petroleum stream. At the end of the sloping portion of test line 8, the diameter is increased substantially so as to form a chamber 12 before going to a vertical descent. Test line 8 is turned through 90° from the vertical portion to a horizontal direction before reconnection to pipeline 5. The composite petroleum stream, while passing through chamber 12, will tend to stratify by the action of gravity such that liquid flows along the bottom of the sloping pipe with gas flowing along the top. A sample stream of the liquid component of the composite petroleum stream containing some entrained gas is removed by a sampling line 15 and provided to a separator 19. Separator 19 allows the entrained gas in the sample stream to separate from the liquid and be returned to the gas portion of chamber 12 via line 23. The liquid portion of the sample stream in line 15 is returned to the production stream in chamber 12 through a line 26. During the flowing of the petroleum stream through pipeline 5 and test line 8, certain parameters are measured. One parameter is pressure, which is being sensed by a pressure sensor 30 providing a signal P corresponding to the sensed pressure. A temperature sensor 34 senses the temperature of the liquid flowing in test line 8 just prior to entering pipeline 5 again. Temperature sensor 34 provides a signal T corresponding to the sensed temperature. Also in the discharge portion of test line 8, a densitometer 39 provides a signal D corresponding to the density of the fluid exiting pipeline 5. A volumetric flowmeter 42 senses the flow rate of the petroleum stream re-entering pipeline 5 and provides a corresponding signal FR. A net oil or water cut meter 44 provides a signal WC corresponding to the net oil or water cut of the sample stream exiting separator 19. Signals P, T, D, FR and WC, are provided to computer means 50, which provides signals to readout means 55 corresponding to the flow rates of the oil, water and gas. Computer means solves the following equations: (1) X gas = [D comp-[D oil(1-X H20 )+D H20 (X H20 )]]/[D gas -[D oil (1-X H20 ) +D H20 (X H20 )]] where X gas is the volumetric gas fraction of the composite petroleum stream at its actual pressure and temperature X H20 is the volumetric water fraction (water cut) of the oil and water components of the composite petroleum stream at their actual temperature and pressure (measured by monitor 44), D comp is the density of the composite petroleum stream at its actual pressure and temperature (measured by densitometer 39), D gas is the density of the gas component of the composite petroleum stream at its actual temperature and pressure (determined from PVT data for the gas and oil of the composite petroleum stream at its actual pressure and temperature), D oil is the density of the oil component of the composite petroleum stream at its actual pressure and temperature (determined from PVT data for the gas and oil of the composite petroleum stream), and D H20 is the density of the water component of the composite petroleum stream at its actual pressure and temperature. Obviously, from the foregoing, the various PTV density values are stored in computer means 50 memory and computer means 50 uses the stored values as required. (2) Q gas = (X gas) (Q comp), (3) Q H20 = X H20 (Q comp - Q gas), (4) Q oil = (1-X H20 ) (Q comp-Q gas), where Q comp is the volumetric flow rate at its actual pressure and temperature (measured by volumetric flowmeter 42), Q gas is the volumetric flow rate of the gas component of the composite petroleum stream at its actual pressure and temperature, Q oil is the volumetric flow rate of the oil component of the composite petroleum and Q H20 is the volumetric flow rate of the water component at its actual temperature and pressure.

Claims: A flow rate monitor for monitoring the component flow rates of a composite petroleum stream having a gas component, an oil component and a water component, comprising: a test line (8) including a chamber (12) inclined downwardly at an angle so that stratification of liquid and gas occurs in the chamber; sampling means (15) for providing a sample stream from the liquid in the chamber; means (19) for separating gas from the sample stream to provide a gas output and a liquid output; means for returning said gas output and said liquid output to the test line; sensor means (44,30,34,42,39) for sensing predetermined physical variables of said stream and providing signals respectively representative thereof; and means (50) for providing flow rate signals (Q gas, Q oil, Q H20 ) representative of the volumetric flow rates of the gas, oil and water components of the composite petroleum stream in accordance with said signals provided by said sensor means; characterized in that: said sensor means comprises the combination of: water fraction means (44) for determining the water fraction of said liquid output and providing a water fraction signal (WC) representative thereof; pressure means (30) for sensing the pressure of the composite petroleum stream and providing a pressure signal (P) representative thereof; temperature means (34) for sensing the temperature of the composite petroleum stream and providing a temperature signal (T) representative thereof; flow rate means (42) for monitoring the volumetric flow rate of the composite petroleum stream and providing a flow rate signal (FR) representative thereof; and density means (39) for monitoring the density of the composite petroleum stream and providing a density signal (D) representative thereof. A monitor according to Claim 1 characterized in that said means (50) for providing signals includes: means for storing PVT density values corresponding to different pressure (P), volume (V) and temperature (T) values; gas fraction means for deriving the volumetric gas fraction (X gas) in accordance with the water fraction signal (WC), the PVT-related density (D comp) for the composite stream, the PVT-related density (D oil) for the oil component, and the density (D H20 ) of the water component. A monitor according to Claim 2 characterized in that the gas fraction means derives the volumetric gas fraction (X gas) in accordance with the following equation: X gas = [D comp-[D oil(1-X H20 ) +D H20 (X H20 )]]/[D gas -[D oil (1-X H20 ) +D H20 (X H20 ) ]] where: X gas is the volumetric gas fraction of the composite petroleum stream at its actual pressure and temperature; X H20 is the volumetric water fraction of the oil and water components of the composite petroleum stream at their actual temperature and pressure; D comp is the density of the composite petroleum stream at its actual pressure and temperature; D gas is the density of the gas component of the composite petroleum stream at its actual temperature and pressure; D oil is the density of the oil component of the composite petroleum stream at its actual pressure and temperature; and D H20 is the density of the water component of the composite petroleum stream at its actual pressure and temperature. A monitor according to Claim 3 characterized in that the volumetric flow rate Q gas of the gas fraction, the volumetric flow rate Q H20 of the water fraction, and the volumetric flow rate Q oil of the oil fraction are derived in accordance with the following equations: Q gas = (X gas) (Q comp), Q H20 = X H20 (Q comp - Q gas), and Q Oil = (1 - X H20 ) (Q comp - Q gas). A method for monitoring the component flow rates of a composite petroleum stream having a gas component, an oil component and a water component, comprising the steps of: disposing a test line having a chamber at a downwardly inclined angle so that stratification of liquid and gas will occur in the chamber; providing a sample stream from the liquid in the chamber; separating gas from the sample stream to provide a gas output and a liquid output; returning said gas output and said liquid output to the test line; sensing predetermined physical variables of said stream and providing signals respectively representative thereof; and deriving the volumetric flow rates of the gas, oil and water components of the composite petroleum stream in accordance with said signals provided by said sensing step; characterized in that: said sensing step comprises the combination of: determining the water fraction of said liquid output and providing a water fraction signal representative of the determined water fraction; sensing the pressure of the composite petroleum stream and providing a pressure signal representative of the sensed pressure; sensing the temperature of the composite petroleum stream and providing a temperature signal representative of the sensed temperature; monitoring the volumetric flow rate of the composite petroleum stream and providing a flow rate signal representative of the monitored flow rate; and monitoring the density of the composite petroleum stream and providing a density signal representative of the monitored density. A method according to Claim 5 characterized in that the deriving step includes: storing PVT density values corresponding to different pressure (P), volume (V) and temperature (T) values; and deriving the volumetric gas fraction (X gas) in accordance with the water cut signal (WC), the PVT-related density (D comp) for the composite stream, the PVT-related density (D oil) for the oil component, and the density (D H20 ) of the water component. A method according to Claim 6 characterized in that the gas fraction step derives the volumetric gas fraction (X gas) in accordance with the following equation: X gas = [D comp-[D oil(1-X H20 )+D H20 (X H20 )]]/[D gas -[D oil (1-X H20 ) +D H20 (X H20 ) ]] where: X gas if the volumetric gas fraction of the composite petroleum stream at its actual pressure and temperature; X H20 is the volumetric water fraction of the oil and water components of the stream at their actual temperature and pressure; D comp is the density of the composite petroleum stream at its actual pressure and temperature; D gas is the density of the gas component of the composite petroleum stream at its actual temperature and pressure; D oil is the density of the oil component of the composite petroleum stream at its actual pressure and temperature; and D H20 is the density of the water component of the composite petroleum stream at its actual pressure and temperature. A method according to Claim 7 characterized in that the deriving step includes deriving the volumetric flow rate Q gas of the gas fraction, the volumetric flow rate Q H20 of the water fraction, and the volumetric flow rate Q oil of the oil fraction in accordance with the following equations: Q gas = (X gas) (Q comp), Q H20 = X H20 (Q comp - Q gas), and Q Oil = (1 - X H20 ) (Q comp - Q gas).

Inventors: DEAN TIMOTHY LEE, DOWTY EARL LEONARD, STARTUP IAN, DEAN, TIMOTHY LEE, DOWTY, EARL LEONARD, STARTUP, IAN
Applicants: TEXACO DEVELOPMENT CORP, TEXACO DEVELOPMENT CORPORATION
Application year: 1991
Main classification: G01F1
IPC codes: G01F1, G01N1, G01F15, G01N9