Multiphase flow measurement system

An automatic well test system (100) utilizes a two phase vortex separator 104 connected to a pair of Coriolis flowmeters (154, 166) to measure volumetric flow rates in three phase flow. Measurements are performed according to a process (P200) including an iterative convergence technique. Measurements are enhanced by the use of real time density and water-cut measurements from a water-cut meter (172) and a water density meter.

BACKGROUND OF THE INVENTION
 1. Field of the Invention
 The present invention pertains to the field of flow metering technology
 including systems for use in measuring production volumes including a
 multiphase mixture of discrete phases, e.g., a mixture including oil, gas,
 and water phases. More specifically, the separator system utilizes a
 Coriolis flowmeter in combination with a two phase separator to measure
 production volumes of the respective components or phases of the
 multiphase mixture.
 2. Statement of the Problem
 It is often the case that a fluid flowing through a tubular member contains
 a plurality of phases, i.e., the fluid is a multiphase fluid. As used
 herein, the term "phase" refers to a type of fluid that may exist in
 contact with other fluids, e.g., a mixture of oil and water includes a
 discrete oil phase and a discrete water phase. Similarly, a mixture of
 oil, gas, and water includes a discrete gas phase and a discrete liquid
 phase with the liquid phase including an oil phase and a water phase. The
 term "fluid" is used herein in the context that fluid includes gas and
 liquids.
 Special problems arise when one uses a flowmeter to measure volumetric or
 mass flow rates in the combined multiphase flow stream. Specifically, the
 flowmeter is designed to provide a direct measurement of the combined flow
 stream, but this measurement cannot be directly resolved into individual
 measurements of the respective phases. This problem is particularly acute
 in the petroleum industry where producing oil and gas wells provide a
 multiphase flow stream including unprocessed oil, gas, and saltwater.
 Commercial markets exist only for the hydrocarbon products.
 It is a common practice in the petroleum industry to install equipment that
 is used to separate respective oil, gas, and water phases of flow from oil
 and gas wells. The producing wells in a field or a portion of a field
 often share a production facility for this purpose, including a main
 production separator, a well test separator, pipeline transportation
 access, saltwater disposal wells, and safety control features. Proper
 management of producing oil or gas fields demands knowledge of the
 respective volumes of oil, gas and water that are produced from the fields
 and individual wells in the fields. This knowledge is used to improve the
 producing efficiency of the field, as well as in allocating ownership of
 revenues from commercial sales of bulk production.
 Early installations of separation equipment have included the installation
 of large and bulky vessel-type separation devices. These devices have a
 horizontal or vertical oblong pressure vessel together with internal valve
 and weir assemblies. Industry terminology refers to a `two-phase`
 separator as one that is used to separate a gas phase from a liquid phase
 including oil and water. The use of a two phase separator does not permit
 direct volumetric measurements to be obtained from segregated oil and
 water components under actual producing conditions because the combined
 oil and water fractions are, in practice, not broken out from the combined
 liquid stream. A `three-phase` separator is used to separate the gas from
 the liquid phases and also separates the liquid phase into oil and water
 phases. As compared to two-phase separators, three-phase separators
 require additional valve and weir assemblies, and typically have larger
 volumes to permit longer residence times of produced materials for gravity
 separation of the production materials into their respective oil, gas, and
 water components.
 Older pressure vessel separators are bulky and occupy a relatively large
 surface area. This surface area is very limited and quite expensive to
 provide in certain installations including offshore production platforms
 and subsea completion templates. Some development efforts have attempted
 to provide multiphase measurement capabilities in compact packages for use
 in locations where surface area is limited. These packages typically
 require the use of nuclear technology to obtain multiphase flow
 measurements.
 Coriolis flowmeters are mass flowmeters that can also be operated as
 vibrating tube densitometers. The density of each phase may be used to
 convert the mass flow rate for a particular phase into a volumetric
 measurement. Numerous difficulties exist in using a Coriolis flowmeter to
 identify the respective mass percentages of oil, gas, and water in a total
 combined flow stream.
 U.S. Pat. No. 5,029,482 teaches the use of empirically-derived correlations
 that are obtained by flowing combined gas and liquid flow streams having
 known mass percentages of the respective gas and liquid components through
 a Coriolis meter. The empirically-derived correlations are then used to
 calculate the percentage of gas and the percentage of liquid in a combined
 gas and liquid flow stream of unknown gas and liquid percentages based
 upon a direct Coriolis measurement of the total mass flow rate. The
 composition of the fluid mixture from the well can change with time based
 upon pressure, volume, and temperature phenomena as pressure in the
 reservoir depletes and, consequently, there is a continuing need to
 reverify the density value.
 U.S. Pat. No. 4,773,257 teaches that a water fraction of a total oil and
 water flow stream may be calculated by adjusting the measured total mass
 flow rate for water content, and that the corresponding mass flow rates of
 the respective oil and water phases may be converted into volumetric
 values by dividing the mass flow rate for the respective phases by the
 density of the respective phases. The density of the respective phases
 must be determined from actual laboratory measurements. The '257 patent
 relies upon separation equipment to accomplish separation of gas from the
 total liquids, and this separation is assumed to be complete.
 U.S. Pat. No. 5,654,502 describes a self-calibrating Coriolis flowmeter
 that uses a separator to obtain respective oil and water density
 measurements, as opposed to laboratory density measurements. The oil
 density measurements are corrected for water content, which is measured by
 a water cut monitor or probe. The '502 patent relies upon a separator to
 eliminate gas from the fluids traveling through the meter, and does not
 teach a mechanism for providing multiphase flow measurements when gas is
 part of the flow stream that is applied to the Coriolis flowmeter.
 Even three phase separation equipment does not necessarily provide complete
 separation of the oil phase from the water phase. Water cut probes are
 used to measure water content in the segregated oil phase because a
 residual water content of up to about ten percent typically remains in the
 visibly segregated oil component. The term `water cut` is used to describe
 the water content of a multiphase mixture, and is most often applied to a
 ratio that represents a relationship between a volume of oil and a volume
 of water in an oil and water mixture. According to the most conventional
 usage of the term `water-cut`, well production fluids would have a 95%
 water-cut when water comprises 95 out of a total 100 barrels of oil and
 water liquids. The term `water-cut` is sometimes also used to indicate a
 ratio of the total volume of oil produced to the total volume of water
 produced. A term `oil-cut` could imply the oil volume divided by the
 combined oil and water volume. As defined herein, the term `water-cut`
 encompasses any value that is mathematically equivalent to a value
 representing water or oil as a percentage of a total liquid mixture
 including water and oil.
 There remains a need to provide a compact package for performing multiphase
 flow measurements when gas is part of the flow stream and where the
 package does not require the use of nuclear technology to perform direct
 measurements on the fluid. Accordingly, it is an aspect of the present
 invention to provide method and apparatus that is capable of performing
 multiphase flow measurements in systems having mixtures of gas and liquids
 or in liquid systems having mixtures of liquids, whether these mixtures
 are miscible or immiscible.
 SOLUTION
 The present invention overcomes the problems that are outlined above by
 providing a fully automated Coriolis-based well test system which does not
 require manual sampling or laboratory analysis of the production fluids in
 order to determine the density of the oil and gas components.
 Additionally, the test system eliminates volumetric measurement errors
 that derive from the liberation of solution gas at reduced pressures.
 The well test system of the invention has two modes of operation. The test
 system operates as a normal well test system to measure the volume of
 respective components that are separated from a component mixture, namely,
 a wellhead production material including oil, gas, and water components.
 The well test system also has a special density determination mode that
 avoids the need to obtain hand samples of the production fluids for
 density measurements. The-on-site density measurements obtained from the
 system are more accurate than laboratory measurements because the fluids
 are measured at line conditions.
 The system also includes devices that separate a combined flowstream
 including multiphase wellhead production fluids into separate components.
 A valve manifold is used to selectively fill a vortex separator with the
 production of a single well. A gravity separator is used to retain a
 mixture of oil, gas, and water phases or components from multiple wells
 while the forces of gravity segregate these components from the production
 mixture. A dump valve is opened to at least partially drain the liquid
 components of the production component mixture from the gravity separator
 after separation of the respective components.
 Coriolis flowmeters may be operated in a mass flowmeter mode and
 densitometer mode. These meters are used to measure the mass flow rates of
 the respective oil and water components as they leave the respective
 separators. Density measurements are used obtained from the segregated oil
 components of multiphase flow. A water-cut monitor is used to obtain
 water-cut readings of the segregated oil phase. Altogether, fluid density,
 temperature, mass flow rate, and water-cut measurements are used to
 calculate a volumetric flow rate for the oil and water components in the
 production stream. This correction results in a more accurate calculation
 for the volumetric oil flow rate.
 In preferred embodiments, volumetric test errors are also minimized by
 connecting a pressurized gas source to the test separator. The pressurized
 gas source is used to maintain a substantially constant separator pressure
 even when the separator dump valve is permitting flow of liquids from
 within the test separator.
 Other salient features, objects, and advantages will be apparent to those
 skilled in the art upon a reading of the discussion below in combination
 with the accompanying drawings.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
 FIG. 1 depicts a schematic diagram of a compact multiphase flow measurement
 system 100 for use in the petroleum industry System 100 includes an
 incoming multiphase flow line 102 that discharges into a vertical two
 phase vortex separator 104. In turn, the vortex separator 104 discharges
 gas into an upper gas measurement flow line 106 and discharges liquids
 into a lower liquid measurement flow line 108. The gas measurement flow
 line 106 and the liquid measurement flow line 108 recombine into discharge
 line 110 after flow measurements have been performed. A controller 112
 includes a central processor together with associated circuitry for
 operating the respective components of system 100. The system 100 is
 mounted on skid structure 114 for portability, and a production manifold
 116 supplies multiphase fluids to system 100 from a plurality of oil or
 gas wells. Discharge flow line 110 leads to a three phase production
 separator 118 for separation of gas, water and oil phases prior to a point
 of commercial sale.
 The incoming multiphase flow line 102 receives multiphase fluids including
 oil, gas, and water from production manifold 116 along the direction of
 arrow 120. A venturi section 122 utilizes the well known Bernouli effect
 to reduce pressure in the incoming multiphase fluids within flow line 102
 at the throat of the venturi. It is preferred that the degree of pressure
 reduction occurs to a level which approximates the internal working
 pressure within the liquid Coriolis meter 166. This reduction in pressure
 liberates or flashes gas from the multiphase fluids within flow line 102.
 An incline/decline section 124 facilitates gravity segregation in the gas
 and liquid phases of the multiphase fluids preceding the vortex separator
 104. A horizontal discharge element 126 feeds the vortex separator 104.
 Vortex separator 104 is depicted in midsectional view to reveal interior
 working components. Discharge element 126 is operably positioned for
 tangential discharge into the cylindrical interior separation section of
 vortex separator 104. This manner of discharge causes a tornado or cyclone
 effect to occur in a liquid portion 128 of multiphase fluids within vortex
 separator 104.
 The liquid portion 128 is a majority liquid phase including discrete water,
 oil, and entrained gas phases. Centrifugal forces arising from the cyclone
 effect cause additional separation of the entrained gas phase from the
 liquid portion 128, but it is not possible to completely eliminate the
 entrained gas phase except at relatively low flow rates permitting
 additional gravity segregation of the entrained gas phase. The liquid
 portion 128 discharges from vortex separator 104 into the liquid
 measurement flow line 108. A water trap 130 is installed in the lower
 portion of vortex separator 104. This trap may be bled to obtain periodic
 water density measurements, or a water density meter (not depicted in FIG.
 1) may be installed in combination with the trap 130 to provide water
 density information to controller 112.
 A gas portion 132 of the multiphase fluids within vortex separator is a
 majority gas phase including gas together with mists of oil and water. A
 mist collecting screen 134 is used for partial condensation of the mists,
 which in condensed form drip back into the liquid portion 128.
 Gas portion 132 discharges into the gas measurement flow line 106. Gas
 measurement flow line 106 includes a pressure transmitter 135 that
 transmits an absolute pressure reading of pressure within gas measurement
 flow line 106 to controller 112 on electrical line 136. Pressure
 transmitter 135 may be purchased commercially, for example, as a Model
 2088 pressure transmitter from Rosemount of Eden Prairie, Minn. A tube 138
 connects gas measurement line 136 with the bottom of vortex separator 104.
 Tube 138 contains a hydrostatic gauge 140 coupled with a pressure
 transmitter 142 for use in transmitting pressure information concerning
 the hydrostatic head between point 144 within gas measurement flow line
 106 and point 146 at the bottom of vortex separator 104. Electrical line
 148 connects the pressure transmitter 142 with controller 112, which uses
 the hydrostatic head data from pressure transmitter 142 to open and close
 electrically operable throttling valves 150 and 174 for pressure
 adjustment assuring proper operation of vortex separator 104, i.e., to
 prevent vortex separator from becoming overfull with gas to the point
 where gas portion 132 discharges into liquid measurement flow line 108 or
 to the point where liquid portion 128 discharges into gas measurement flow
 line 106. Electrical lines 152 and 176 operably connect controller 112
 with the throttling valves 150 and 174, which may, for example, be
 purchased as Model V2001066-ASCO valves from Fisher of Marshall Town,
 Iowa.
 A Coriolis mass flowmeter 154 in gas measurement flow line 106 provides
 mass flow rate and density measurements on the gas portion 132 of
 multiphase fluids within gas measurement flow line 106. The Coriolis mass
 flowmeter 154 is coupled with a flow transmitter 156 for providing signals
 representing these measurements to controller 112. Coriolis flowmeter 154
 is electronically configured for operations including measurements of mass
 flow rates, densities, and temperatures of materials passing through gas
 measurement flow line 106. Exemplary forms of Coriolis flowmeter 154
 include the ELITE Models CMF300356NU and Model CMF300H551NU, which are
 available from Micro Motion of Boulder, Colo.
 Electrical line 158 operably couples flow transmitter 156 with controller
 112 for transmission of these signals. A check valve 160 in gas
 measurement flow line 106 assures positive flow in the direction of arrow
 162, thus preventing intrusion of liquid portion 128 into gas measurement
 flow line 106.
 Liquid measurement flow line 108 contains a static mixer 164, which
 turbulates the liquid portion 128 within liquid measurement flow line 108
 to prevent gravity segregation of the respective oil, water, and entrained
 gas phases. A Coriolis flowmeter 166 provides mass flow rate and density
 measurements of liquid portion 128 within liquid measurement flow line
 108, and is connected to flow transmitter 168 for transmission of signals
 representing these measurements on electrical line 170 to controller 112.
 A water cut monitor 172 is installed in liquid measurement flow line 108 to
 measure the water cut in liquid portion 128 within liquid measurement flow
 line 108. The type of water-cut monitor is selected depending upon how
 large the water-cut is expected to be in the flow stream. For example,
 capacitance meters are relatively inexpensive, but other types of meters
 may be required where the water-cut may exceed about 30% by volume.
 Capacitance or resistance probes operate on the principle that oil and
 water have drastically different dielectric constants. These probes lose
 sensitivity with increasing water content, and provide acceptably accurate
 water-cut measurements only where the water volume is less than about 20%
 to 30% of the total flow stream. The upper 30% accuracy limit is far below
 the level that is observed from many producing wells. For example, the
 total liquid production volume of an oil well can be 99% water.
 Capacitance or resistivity based water-cut monitors, therefore, are
 relegated to determining the water-cut in an oil component that has a
 relatively low water content.
 Commercially available devices that are used to measure water-cut include
 near infrared sensors, capacitance/inductance sensors, microwave sensors,
 and radio frequency sensors. Each type of device is associated with
 operational limits. Thus, a water-cut probe can measure the volumetric
 percentage of water in a combined oil and water flow stream.
 Water cut monitoring devices including microwave devices are capable of
 detecting water in an amount up to about one hundred percent of the flow
 mixture, but in environments including three phase flow are subject to
 interpreting gas content as oil. This interpretation occurs because
 microwave detection devices operate on the principle that water in the
 spectrum of interest absorbs sixty times more microwave energy than does
 crude oil. The absorption calculations assume that no natural gas is
 present, but natural gas absorbs twice as much microwave radiation than
 does crude oil. It follows that a microwave water cut detection system
 could correct the water cut reading by compensating for the fact that gas
 in the mixture has affected the measurement.
 Electrical line 173 operably connects water cut monitor 172 with controller
 112. Controller 112 uses an electrically actuated two-way valve 174 to
 control pressure in liquid measurement line 108 in a manner that assures
 proper operation of vortex separator 104 in cooperation with valve 150,
 i.e., valve 174 is opened and closed to prevent gas portion 132 from
 discharging into liquid measurement flow line 108 and to prevent liquid
 portion 128 from discharging into gas measurement flow line 106.
 Electrical line 176 operably connects valve 174 with controller 112. A
 check valve 178 in liquid measurement flow line 108 assures positive flow
 in the direction of arrow 180, thus preventing intrusion of gas portion
 132 into the liquid measurement flow line 108. The gas measurement flow
 line 106 meets in a T with liquid measurement flow line 108 to form a
 common discharge flow line 110 leading to production separator 118.
 Controller 112 is an automation system that is used to govern the operation
 of system 100. On a basic level, controller 100 includes a computer that
 is programmed with data acquisition and programming software together with
 driver circuitry and interfaces for operation of remote devices. A
 preferred form of controller 112 is the Fisher Model ROC364.
 The production manifold 116 contains a plurality of electronically operable
 three way valves, e.g., valves 182 and 184, which each have corresponding
 production sources, such as an oil well 186 or a gas well 188. A
 particularly preferred three-way valve for use in this application is the
 Xomox TUFFLINE 037AX WCB/316 well switching valve with a MATRYX MX200
 actuator. The valves are preferably configured to each receive production
 fluids from a corresponding individual well, but may also receive
 production from a group of wells. Controller 112 selectively configures
 these valves by transmitting signals on electrical line 190. The valves
 are selectively configured to flow multiphase fluids from a well 186 or
 combinations of wells (e.g. wells 186 and 188) into rail 192 for delivery
 of fluids into incoming multiphase flow line 102 while other valves are
 selectively configured to bypass system 100 by flowing through bypass flow
 line 194.
 Production separator 118 is connected to pressure transmitter 195 and an
 electrical line 196 for transmission of signals to controller 112.
 Separator 118 is operably connected with a gas sales line, an oil sales
 line, and a salt water discharge line (not depicted in FIG. 1) in any
 conventional manner known to those skilled in the art.
 Operation of System 100
 FIGS. 2A and 2B depict a schematic process diagram of a process P200
 representing control logic for use in programming controller 112. These
 instructions typically reside in an electronic memory or an electronic
 storage device for access and use by controller 112. Instructions that
 embody the process P200 can be storied on any machine readable medium for
 retrieval, interpretation and execution by controller 112 or similar
 devices that are connected to system 100 in any operable manner.
 Process P200 begins with step P202 in which controller 112 determines that
 it is proper to enter a production test mode. With regard to FIG. 1, this
 means that controller 112 selectively configures the valves 182 and 184 of
 production manifold 116 to flow a well or an operator-selected
 combinations of wells corresponding to production sources 186 and 188
 through rail 192 and into incoming multiphase flow line 102. This
 determination is usually performed on the basis of a time delay, e.g., to
 test each well at least once per week. The test mode may also be performed
 on a continuous basis with the respective valves of production manifold
 116 always being selectively configured to flow into system 100 while
 other valves are configured to bypass system 100 through bypass line 194.
 These types of well test measurements are conventionally used in
 allocating, on a deliverability basis, the percentages of the total flow
 stream that pass through production separator 118 to specific production
 sources, e.g., sources 186 and 188.
 Manually actuated valves 196 and 197 can be opened and closed for selective
 isolation of system 100, i.e., valves 196 and 197 can both be closed for
 the removal of all components that are mounted on skid 114. An
 electrically actuated valve 199 is normally closed. A second or redundant
 bypass line 198 interior to valves 196 and 197 permits flow to bypass
 system 100 when valve 199 is open and valves 150 and 174 are closed.
 Testing begins in step P204 with controller 112 constricting or opening
 valves 150 and 174 to reduce or increase the total flow rate through
 vortex separator 104 for the purpose of separating gas from liquid phases
 in the multiphase fluid. The total flow rate through system 100 need not
 be reduced because controller 112 can open valve 199 to permit flow
 through interior bypass 198. The exact flow rate depends upon the physical
 volume of the vortex separator and liquid measurement flow line 108, as
 well as the amount of fluid that sources 186 and 188 are capable of
 delivering to system 100.
 The object of reducing the flow rate through system 100 is to eliminate
 entrained bubbles from liquid measurement flow line 108 through the use of
 vortex separator 104 with assistance by gravity segregation while the flow
 rate is still high enough to prevent substantial gravity segregation of
 oil from water in the remaining liquid phase. It is also possible to
 accomplish substantially complete separation of the gas phase from the
 liquid phase by increasing the flow rate with separation being
 accomplished by centrifugal forces through vortex separator 104.
 Controller 112 monitors the drive gain or pickoff voltage from Coriolis
 flowmeter 166 for this purpose, as explained with reference to FIGS. 3 and
 4.
 FIG. 3 is a plot of hypothetical data demonstrating the practical effects
 of gas damping on the frequency response of flowtubes in the Coriolis
 flowmeter 166 (see also FIG. 1). The log of transmissivity is plotted as a
 function of the frequency of alternating voltage applied to the drive coil
 of Coriolis flowmeter 166, e.g., at frequencies f.sub.0, f.sub.1, and
 f.sub.2. The transmissivity ratio T.sub.r equals the output of meter
 pickoff coils divided by the drive input, i.e., T.sub.r is the drive gain:
 ##EQU1##
 A first curve 300 corresponds to the undamped system of Equation (1), i.e.,
 no gas is present in the fluid being measured. A second curve 302
 corresponds to a damped system where gas is present. Both curves 300 and
 302 have an optimal value 304 and 304', respectively, at the natural
 frequency f.sub.n.
 FIG. 4 is a plot of hypothetical data showing the relationship between
 drive gain and time for an event 400 where a transient bubble enters the
 Coriolis flowmeter 166 as a bubble entrained in a multiphase fluid. The
 bubble enters at time 402 and exits at time 404. Drive gain is expressed
 as a percentage in FIG. 4, and plotted as a function of time at intervals,
 e.g., t.sub.1, t.sub.2, and t.sub.3. Controller 112 (see also FIG. 1) is
 programmed to monitor drive gain or transmissivity by comparing the same
 against a threshold value 406. Where the drive gain or transmissivity of
 curve 408 exceeds threshold 406, controller 112 recognizes that density
 measurements are affected by the presence of transient bubbles. Thus,
 Coriolis flowmeter 166 uses only density values obtained when drive gain
 is less than threshold 406 for purposes of step P206. The exact level of
 threshold 406 depends upon the specific meter design together with the
 intended environment of use, and is intended to permit less than one to
 two percent gas by volume in the multiphase fluid.
 In operating Coriolis meters, it is often the case that the pickoff voltage
 drops in inverse proportion to the event 400 of the curve 408 shown in
 FIG. 4. The meters are sometimes programmed to sense this drop in
 amplitude, and they respond by vibrating an oscillation coil to an
 amplitude of maximum design specification until the gas damping effect is
 reversed.
 With controller 112 opening and/or closing valves 150 and 174 until the
 drive gain just falls below threshold 406 in the manner described for step
 P204, step P206 includes Coriolis flowmeter 166 measuring density of the
 liquid phase without entrained gas. This density measurement is intended
 to represent density of the liquid phase having no gas voids. This density
 measurement is referred to as .rho..sub.L in the discussion below, and is
 used to describe the density of a liquid mixture including gas and oil
 with no entrained gas fraction. As an alternative to performing direct
 measurements on the multiphase fluid in liquid measurement line 108, it is
 also possible to obtain samples of the multiphase fluid for laboratory
 analysis or to approximate density measurements by the use of empirically
 derived fluid correlations to obtain less preferred approximations of
 .rho..sub.L.
 In step P208, controller 112 selectively adjusts valves 150 and 174 in a
 manner that optimizes separation results in vortex separator 104 according
 to manufacturer's specifications based upon the gross rates of flow
 through Coriolis flowmeters 154 and 166 together with pressure signals
 received from pressure transmitter 135 and differential pressure gauge
 140. In this step, production manifold 116 is configured to flow for
 active producing well test measurements. Vortex separator 104 functions
 differently in this step, as compared to step P204, because controller 112
 does not adjust valves 150 and 174 in a manner that reduces drive gain
 below the threshold 406 shown in FIG. 4. In this circumstance, the
 majority liquid phase flowing through liquid measurement line 108 may
 include entrained gas bubbles.
 Step P210 includes the use of Coriolis flowmeter 166 to measure the total
 mass flow rate Q.sub.TL of the majority liquid phase including entrained
 gas within liquid measurement line 108, as well as the density of the
 majority liquid phase. This density measurement is referred to as
 .rho..sub.meas in the discussion that follows.
 In step P212, controller 112 determines the dry gas density .rho..sub.gas
 of the gas in the multiphase fluid. Gas density may be calculated from
 pressure and temperature information using well known correlations
 developed by the American Gas Association based upon gas gravity, or
 laboratory analysis may provide other empirical correlations for gas
 density determined from actual measurements of produced gas from the
 multiphase flow stream. Another alternative technique for the
 determination of gas density is to obtain an actual density measurement
 from Coriolis flowmeter 154 simultaneously with step P204 or in a separate
 step P210 where controller 112 selectively adjusts valves 150 and 174 to
 minimize the drive gain intensity shown in FIG. 4. In some situations, it
 is also possible to assume that the gas density remains constant because
 the density of gas is relatively low in comparison to the liquid density,
 and the assumption of a constant gas density may result in an acceptable
 level of error.
 In step P214, controller 112 calculates a gas void fraction X.sub.L in the
 liquid phase where
 ##EQU2##
 where X.sub.Li is the void fraction representing gas void in the multiphase
 fluid flowing through Coriolis flowmeter 166, i denotes successive
 iterations, .rho..sub.meas is the density measurement obtained in step
 P210 as described above, and .rho..sub.calc is a calculated or estimated
 density value approximating the density of a multiphase liquid having a
 void fraction of about X.sub.Li. Equation (2) will be used in an iterative
 convergence algorithm. Thus, it is acceptable to begin calculations with a
 first guess, e.g., a stored value for .rho..sub.calc from the preceding
 cycle of test measurements for a particular production source 186 or an
 arbitrary value such as 0.8 g/cc.
 A particularly preferred manner of providing a first guess for the value of
 .rho..sub.calc is to obtain a water cut measurement from water cut monitor
 172. Then, it is possible to assume that no gas is present in the
 multiphase flow mixture and solve Equation (3) for .rho..sub.calc :
EQU .rho..sub.alc =WC(.rho..sub.w -.rho..sub.o)+.rho..sub.o (3)
 where WC is water cut expressed as a fraction comprising the amount of
 water in the liquid mixture divided by the total volume of the liquid
 mixture, .rho..sub.w is the density of water in the liquid mixture, and
 .rho..sub.o is the density of oil in the liquid mixture. The resultant
 first guess for .rho..sub.calc is the theoretical value of a liquid
 mixture having no gas void fraction. The measured density .rho..sub.meas
 will be less than .rho..sub.calc when x.sub.i is greater than zero,
 provided the values .rho..sub.w and .rho..sub.o are correct. The values
 .rho..sub.w and .rho..sub.o may be obtained from laboratory measurements
 that are performed on samples of the majority liquid phase including
 respective oil and water phases. For example, a water density value may be
 obtained from a hydrometer connected to water trap 130. These values may
 also be approximated to acceptable levels of accuracy by well known
 empirical correlations that are published by the American Petroleum
 Institute.
 In step P216, controller 112 performs a calculation to determine whether
 the last guess for .rho..sub.calc has provided a calculation of X.sub.Li
 according to Equation (2) wherein the value of X.sub.i has converged
 within an acceptable range of error. The next guess for .rho..sub.calc is
 calculated as:
EQU .rho..sub.calci =(.rho..sub.gas X.sub.Li)+(1-X.sub.Li).rho..sub.L (4)
 where .rho..sub.calci is the next guess for .rho..sub.calc calculated using
 the value X.sub.Li from Equation (2), .rho..sub.L is the density of the
 liquid mixture, and the remaining variables are defined above.
 Step P218 is a test for convergence wherein convergence exists if the
 expression:
 D&lt;.vertline..rho..sub.calci -.rho..sub.calc.vertline. (5)
 is true where D is the absolute value of a delimiter representing a
 negligible error, e.g., 0.01 g/cc, or approximating the limits of
 precision that is available from Coriolis flowmeter 166, .rho..sub.calci
 is the present value calculated according to Equation (4), and
 .rho..sub.calci-1 is the old value of .rho..sub.calci from the prior
 iteration of Equation (2) that produced the X.sub.Li value corresponding
 to .rho..sub.calci.
 Where controller 112 in step P218 determines that there is no convergence,
 the new guess value .rho..sub.calci is substituted for the old guess value
 .rho..sub.calc in step P220, and steps P214 through P218 are repeated
 until convergence exists.
 Water cut may be calculated as:
 ##EQU3##
 wherein WC is water cut, .rho..sub.o is a density of oil in the majority
 liquid component, and .rho..sub.w is a density of water in said majority
 liquid component. Thus, water cut meter 172 is somewhat redundant if there
 is no gas phase in the multiphase flow, and may then be optionally
 eliminated because it is not a required value for this iterative
 convergence technique.
 In step P214A, a more rigorous or noniterative solution is available,
 provided that the measured water cut value supplied by water cut meter 172
 is within a range where the meter functions with acceptable accuracy and
 precision. The meter reading is a function of the fluid content, and this
 permits the simultaneous solution of a system of three equations to
 provide answers for three variables where the equations are:
EQU .rho..sub.w q.sub.w +.rho..sub.o q.sub.0 +.rho..sub.g q.sub.g
 =.rho..sub.mix, (7)
EQU f(sat)=M (8)
EQU q.sub.w +q.sub.0 +q.sub.g =1 (9)
 where .rho..sub.w is the density of water in the flow stream, .rho..sub.o
 is the density of oil in the flow stream, .rho..sub.g is the density of
 gas in the flow stream, .rho..sub.mix is the density of the combined flow
 stream, q.sub.w is the fractional flow rate of water by volume (i.e., a
 water-cut), q.sub.0 is the fractional flow rate of oil by volume, q.sub.g
 is the fractional flow rate of gas by volume, and f(sat) is a function of
 flow stream content that is unique to a particular type of water-cut meter
 providing a total meter reading M.
 Where the water-cut meter is a microwave meter, the function f(sat)=M may
 be approximated as:
EQU m.sub.w q.sub.w +m.sub.o q.sub.o +m.sub.g q.sub.g =M, (10)
 where m.sub.w is the meter reading in pure water, m.sub.o is the meter
 reading in pure oil, m.sub.g is the meter reading in pure gas, and the
 remaining terms are described above. Where, in a typical meter, m.sub.w
 =60, m.sub.o =1, and mg=2, Equations (8) through (11) can be solved for
 q.sub.w as:
 ##EQU4##
 where the terms are defined above. Also,
EQU q.sub.g =M-1-59q.sub.w, and (12)
EQU q.sub.o =58q.sub.w -M+2. (13)
 Once convergence is achieved in step P218, step P222 entails using Coriolis
 flowmeter 154 to measure the mass flow rate Q.sub.TG and density
 .rho..sub.mgas of the majority gas phase flowing through Coriolis
 flowmeter 154 under the flow conditions of step P208.
 Step P224, as shown in FIG. 2B, includes solving for the gas void fraction
 X.sub.G in the majority gas phase flowing through gas measurement line
 106, according to the equation:
 ##EQU5##
 where XG is a fraction corresponding to a volume of gas taken with respect
 to the total volume of the majority gas phase, .rho..sub.mgas is a value
 obtained in step P222, .rho..sub.gas is a value obtained in step P212, and
 .rho..sub.L is a value obtained in step P206.
 In step P224, the value of water cut obtained from water cut monitor 172 is
 adjusted, as needed, to compensate for the presence of gas in the majority
 liquid phase. For example, where the gas void fraction X.sub.Li is known,
 it is possible to use this value to correct water cut readings for
 microwave absorption based upon the assumption that only oil and water are
 present.
 Step P226 includes using the data thus acquired to solve for the flow rates
 of the three respective phases in each of the majority liquid phase and
 the majority gas phase. These equations are useful for this purpose:
EQU Q.sub.L =Q.sub.TL *(1-X.sub.i)+Q.sub.TG *(1-X.sub.G); (15)
EQU Q.sub.G =Q.sub.TL *X.sub.i *Q.sub.TG *X.sub.G ; (16)
EQU Q.sub.O =Q.sub.L *(1-WC); (17)
EQU Q.sub.W =Q.sub.L *WC; (18)
 ##EQU6##
 wherein Q.sub.L is the total mass flow rate of the liquid phases flowing
 through system 100; Q.sub.TL is the total mass flow rate of the majority
 liquid phase including entrained gas; X.sub.i is the gas void fraction in
 the majority liquid phase determined from step P214 and resulting in
 convergence in step P218; Q.sub.TG is the total gas mass flow rate of the
 majority gas phase measured in step P222; X.sub.G is the gas void fraction
 in the majority gas phase determined in step P224; Q.sub.G is the total
 gas mass flow rate through system 100; .rho..sub.O is the total oil mass
 flow rate through system 100; Q.sub.W is the total water mass flow rate
 through system 100; WC is the water cut provided from water cut monitor
 172 with corrections as needed in step P224; V.sub.L is the total
 volumetric flow rate of the liquid phases flowing through system 100;
 .rho..sub.L is the liquid phase density determined in step P206; V.sub.O
 is the total oil volumetric flow rate through system 100; .rho..sub.O is
 oil density at flow conditions; V.sub.G is the total gas volumetric flow
 rate through system 100; .rho..sub.gas is gas density at flow conditions;
 V.sub.W is the total water volumetric flow rate through system 100; and
 .rho..sub.W is water density at flow conditions.
 Controller 112 in step P228 provides system outputs including direct
 temperature, density, and mass flow rate measurements together with
 calculation results for volumetric and mass flow rates for the respective
 phases. These flow rates may be integrated over time to provide cumulative
 production volumes for the test interval.
 In step P232, controller 112 determines if a new test configuration should
 be executed. If controller 112 determines that a new test configuration
 should be executed, then controller 112 returns to step P204. If
 controller 112 determines that a new test configuration should not be
 executed, then controller 112 exits the production test mode in step P234.
 Controller 112 in step P230 interacts with system components including
 production manifold 116 to optimize field efficiency. For example, in an
 oilfield having drive energy that is predominated by a gas cap, production
 efficiency is optimized when the gas cap is depleted after the oil is
 recovered. It is desirable to produce oil referentially before the gas,
 and the gas-oil contact may move downward into the former oil zone as the
 oil is depleted. This movement of the gas-oil contact can result in wells
 that formerly produced primarily oil changing to produce primarily gas.
 The proper response to this drastically increased gas production in an oil
 well is normally to shut the well in or reduce its production rate so as
 not to deplete the drive energy of the reservoir, and controller 112 can
 be programmed to take this action. Similar responses can be programmed for
 moving oil-water contacts or even to optimize present economic performance
 from an accounting standpoint by producing one low cost well before higher
 cost wells if all other factors are equal.
 Those skilled in the art understand that the preferred embodiments
 described hereinabove may be subjected to apparent modifications without
 departing from the scope and spirit of the invention. Accordingly, the
 inventors hereby state their full intention to rely upon the Doctrine of
 Equivalents in order to protect their full rights in the invention.