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    • 专利摘要:
    The automated well test system 100 according to the present invention measures the volumetric flow rate in a three-phase flow using a two-phase eddy-current separator 104 connected to a pair of Coriolis flow meters 154,156. Measurement is performed in accordance with the process P200 including the iterative convergence method. Measurements are improved by using real-time density and watercut measurements from the water cut meter 172 and the water density meter.
    公开号:KR20020067036A
    申请号:KR1020027005523
    申请日:2000-10-18
    公开日:2002-08-21
    发明作者:로버트 이. 두톤；채드 스틸레
    申请人:마이크로 모우션, 인코포레이티드；
    IPC主号:
    专利说明:

    [0001] MULTIPHASE FLOW MEASUREMENT SYSTEM [0002]
    [2] Material flowing through pipelines often contains multiple states. As used herein, the term " phase " refers to the type of material that may be present in contact with another material. For example, a mixture of oil and water includes individual oil conditions and individual water conditions. Similarly, the mixture of oil, gas and water includes separate gaseous and separate liquid states, the liquid state including oil and water conditions. As used herein, the term " material " refers to a gas and a material comprising a liquid.
    [3] Particular problems arise when using a flow meter in measuring volume or mass flow in a mixed multiphase flow stream. Specifically, the flow meter is configured to provide a direct measurement of the mixed flow stream, but such measurements can not be directly interpreted as individual measurements of each state. This problem is particularly acute in the oil industry, where oil wells and gas wells provide a multiphase flow stream that includes untreated oil, gas and seawater.
    [4] In the oil industry, it is common to install equipment used to segregate oil, gas and water conditions from oil wells and natural gas wells, respectively. Production wells or parts of the field in the field often share production facilities for this purpose, namely the main production segregator, the well test segregator, the pipeline transport access, the desalination well and the safety control device. Appropriate management to produce an oil or gas field requires information on the volume of each of the oil, gas and water produced from the wells in the field and in the field. This information is used to improve production efficiency in this field and is used to assign commercial sales and ownership of the bulk production.
    [5] The installation of a conventional segregation device involved the installation of a large bark vessel type segregation device. These devices have horizontal or vertical elliptical pressure vessels with internal valves and weir assemblies. Industrial jargon is referred to as a " two-phase " separator, which is used to segregate the gas state from a liquid state including oil and water. Since mixed oil and water fractions do not actually arise from a mixed stream of liquid, the use of a two-phase kneader does not allow direct volume measurements to be obtained from segregated oil and water components under actual production conditions. The three-phase kneader is used to segregate the gas state from the liquid state and segregate the liquid state into the oil state and the water state. Compared to a two-phase kneader, the three-phase kneader requires additional valve and ware assemblies, and in each oil, gas and water mixture, a longer residence time of the produced material to gravitational segregation of the product material It has a larger volume that enables time.
    [6] Conventional pressure vessel biasing machines are bulky and have a relatively large surface area. These surface areas are very limited and considerably expensive to provide reliable installation including coastal production platforms and subsea completion templates. Some development efforts have been attempted to provide multiphase measurement capability in small packages for use in locations with limited surface area. These packages typically require the use of nuclear technology.
    [7] The Coriolis flowmeter is a mass flowmeter that operates as a vibrating tube density meter. The density of each phase is used to convert the mass flow rate for a particular state into a volumetric measurement. There are a number of difficulties when using a Coriolis flow meter to verify the percentage mass of each of the oil, gas, and water in the overall flow stream.
    [8] U.S. Patent No. 5,029,482 teaches the use of empirically derived correlations obtained by flowing a mixed gas and liquid flow stream having a known mass percentage of each gas and liquid component passing through a Coriolis flowmeter. The empirically derived correlation is then used to calculate the percentage of gas and the percentage of liquid in the mixed gas and liquid flow stream of unknown gas and liquid percentages based on direct Coriolis measurements of the total mass flow. The composition of the fluid mixture from the well may vary over time based on temperature phenomena such as pressure, volume and pressure within the reservoir, and consequently there is a continuing need to demonstrate the density value.
    [9] U.S. Patent 4,773,257 describes that the wafer fraction of the total oil and water flow stream is calculated by adjusting the measured total mass flow rate for the wafer content, the corresponding mass flow rate of each oil and water state , And the mass flow rate of each phase can be converted into a volume value by dividing by the density of each phase. The density of each phase should be determined from actual laboratory measurements. U.S. Patent No. 4,773,257 relies on separation equipment to separate gas from the total liquid, and it is assumed that this separation is complete.
    [10] U.S. Patent No. 5,654,502 describes a self-calibrating Coriolis flow meter that uses a separator to obtain the density of each oil and water, as opposed to a laboratory density measurement. Oil density measurements are corrected for water content, which is measured by a water cut monitor or probe. U.S. Patent No. 5,654,502 does not describe a mechanism that relies on a separator to remove gas from a fluid passing through a metering device and provides a multiphase flow measurement when the gas is part of a flow stream applied to a Coriolis flowmeter.
    [11] Even three-phase separation equipment does not completely separate the oil phase from the water phase. A water-cut probe is used to measure the water content in the separated oil phase, because visually, the oil component, which is visible to the naked eye, usually has a residual water content of up to about 10%. The term " water cut " is used to describe the water content of a polyphase mixture and refers to the ratio representing the relationship between the volume of oil and the volume of water in a mixture of oil and water, do. According to the most common application of a "water cut", a well production fluid will have a water cut of 95%, with a total of 100 barrels of water and an oil liquid of 95 barrels. The term " water cut " is also used to denote the ratio of the total oil volume produced to the total volume of water produced. The term 'oil cut' refers to the oil volume divided by the total volume of oil and water. As defined herein, the term " water cut " includes any value mathematically equivalent to a value representing water or oil as a percentage of the total liquid mixture including oil and water.
    [12] For multiphase flow measurements when the gas is part of a flow stream, there is a need to provide a small package that does not require the use of nuclear technology to directly measure the fluid. Accordingly, the present invention provides a method and apparatus capable of performing multiphase flow measurement, whether or not these mixtures can be mixed, in a liquid system having a mixture of gas and liquid or a mixture of liquids.
    [1] The present invention relates to the field of flow measurement techniques, including systems used to measure production volumes, including, for example, multiphase mixtures of individual states, such as mixtures comprising oil, gas and water conditions . More particularly, to measuring the production volume of each component or state of a polyphase mixture by using a Coriolis flow meter in conjunction with a two-phase kneader.
    [19] 1 shows a schematic layout of an automatic well test system according to the present invention.
    [20] Figure 2 shows a flow diagram for controlling the operation of the system of Figure 1;
    [21] Figure 3 is a plot of hypothetical data demonstrating the actual effect of gas attenuation in the frequency response of a flow tube of a Coriolis mass flow meter.
    [22] Figure 4 is a plot of hypothetical data showing the relationship between drive gain and time for transient bubbles entering a Coriolis mass flow meter.
    [13] The present invention overcomes the problems described above by providing a fully automated Coriolis-based well test system without the need for manual sampling or laboratory analysis of manufacturing materials to measure the density of the constituent components. Therefore, the test system of the present invention can eliminate the volumetric measurement error caused by discharging the solution gas under reduced pressure.
    [14] The well test system according to the present invention has two modes of operation. The test system operates as a general well test system to measure the volume of each component separated from the wellhead production material, including the mixture, oil, gas and water phase. The well test system also has a special density measurement mode that eliminates the need to obtain a hand sample of the manufacturing fluid for density measurement. An on-site density measurement obtained from a well test system is more accurate than a laboratory measurement because the material is measured in a line condition.
    [15] The well test system also includes a device for separating the combined flow stream comprising the multiphase well head manufacturing fluid into separate components. Valve manifolds are used to selectively fill the vortex separator by fabrication from one well. Gravity separators are used to separate these components from the preparation mixture by gravity, while maintaining a mixture of oil, gas and water from the polyphase well. The dump valve is opened to separate the components and then the liquid components in the manufacturing components are partially discharged from the gravity separator.
    [16] The Coriolis flowmeter can operate in mass flow meter mode and density meter mode. These meters are used to measure the mass flow rate when oil and water components leave each separator. The density measurement is obtained from the separated oil component of the multiphase flow. A water cut monitor is used to read the water cut of the separated oil phase. Fluid density, temperature, mass flow rate and water-cut measurements are all used to measure the volumetric flow on the oil phase and water in the product stream. With this calibration, the volume flow rate of the oil is more accurately measured.
    [17] In a preferred embodiment, the volume test error is also minimized by connecting the pressurized gas source to the test separator. The pressurized gas source is used to maintain the separator pressure almost constant even when the separator dump valve allows liquid to flow from within the test separator.
    [18] Other features, objects and advantages will become apparent to those skilled in the art from the following description with reference to the drawings.
    [23] 1 is a schematic diagram of a small polyphase flow measurement system 100 used in the petroleum industry. The system 100 includes an incoming multiphase flow line 103 connected into a vertical two-phase vortex separator 104. The vortex crystallizer 104 then discharges the gas into the upper gas measurement flow line 106 and drains the liquid into the lower liquid measurement flow line 108. After the flow measurement is performed, the gas specific flow line 106 and the liquid measurement flow line 108 are recombined into the exhaust line 110. Controller 112 includes a central processor with associated circuitry to operate each component of system 100. The system 100 is mounted on a skid structure 114 for portability and the production manifold 116 is connected to the system 100 from a plurality of oil wells or natural gas wells, . Prior to the commercial point of sale, the discharge flow line 110 is connected to a three-phase production kneader 118 for segregation of gas, water and oil.
    [24] The incoming polyphase flow line 102 receives a polyphase fluid including oil, gas, and water along the direction of arrow 120 from the production manifold 116. The venturi section 122 utilizes the well known Bernouli effect to reduce the pressure in the incoming polyphase fluid within the flow line 102 at the venturi throat. The degree of pressure reduction preferably occurs up to a level close to the internal operating pressure in the liquid Coriolis mass flow meter 166. This reduction in pressure causes gas to escape from the polyphase fluid within the flow line 102 or to swish in a flash. The slope / underside section 124 facilitates gravity segregation in the gas and liquid states of the polyphase fluid prior to the eddy-current separator 104. The horizontal discharge member 126 is supplied to the eddy-current separator 104.
    [25] The eddy-current digester 104 is shown in the center of the drawing so that the internal operating components are visible. A horizontal discharge member 126 is operatively positioned for tangential discharge of the vortex solitary 104 into the cylindrical internal segregation section. This evacuation method allows a tornado or cyclone effect to occur within the liquid portion 128 of the polyphase fluid within the eddy-current digester 104.
    [26] Liquid portion 128 is in most liquid state, including individual water, oil, and associated gas states. Centrifugal forces resulting from the cyclone effect further segregate the accompanying gas state from the liquid portion 128, but it is not possible to completely remove the accompanying gas state except at a relatively low flow rate allowing for additional gravity of the associated gas state Do. The liquid portion 128 is discharged from the eddy-current separator 104 to the liquid measurement flow line 108. A water trap 130 is installed under the eddy-current separator 104. Such a trap may be emitted to obtain a periodic water density measurement, or a water density meter (not shown in FIG. 1) may be provided in conjunction with the trap to provide water density information to the controller 112.
    [27] The gas portion 132 of the multiphase fluid within the eddy-current digester is in a mostly gaseous state, including gas, with mist of oil and water. The mist collecting screen 134 is used for partial condensation of the mist, and partial condensation of this mist is dripped into the liquid portion 128 in a condensed form.
    [28] The gas portion 132 is vented into the gas measurement flow line 106. The gas measurement flow line 106 includes a pressure transmitter 135 that transmits an absolute pressure reading of the pressure inside the gas measurement flow line 106 to the controller 112 via path 136. As the pressure transmitter 135, a product such as Model 2088 of Rosemount of Eden, Prairie, Minnesota, USA is commercially available. The gas measurement line 136 is connected by a tube 138 to the bottom of the eddy-current separator 104. This tube 138 is used to deliver pressure information about the hydrostatic head between the point 146 at the bottom of the vortex segregator 104 and the point 144 within the gas measurement flow line 106 And a hydrostatic gauge 140 connected to the pressure transducer 142. The path 148 couples the pressure transmitter 142 to the controller 112 and the controller 112 uses the fixed head data transmitted from the pressure transmitter 142 to ensure proper operation of the vortex solver 104 And opens and closes electrically actuated throttle valves (150, 174) for pressure regulation. That is, it prevents the vortex sludge from overflowing with gas until the gas portion 132 is discharged into the liquid measurement flow line 108 or to the point where the liquid portion 128 is discharged into the gas measurement flow line 106 . Routes 152 and 176 operatively couple the controller 112 with throttle valves 150 and 174 such as those commercially available from Fisher of Marshall Town, Iowa, USA Model V2001066-ASCO valve is available for purchase.
    [29] The Coriolis mass flow meter 154 in the gas measurement flow line 106 provides a mass flow rate and density measurement from the gas portion 132 of the polyphase fluid within the gas measurement flow line 106. The Coriolis mass flow meter 154 is coupled to the flow transmitter 156 to provide signals indicative of these measurements to the controller 112. Coriolis mass flow meter 154 is electrically configured for operations including measurement of mass flow rate, density and temperature of materials passing through gas measurement flow line 106. An exemplary form of the Coriolis mass flow meter 154 includes an ELITE model CMF300356NU and a model CMF300H551NU available from Micro Motion of Boulder, Colorado, USA.
    [30] A path 158 operatively couples the flow transmitter 156 to the controller 112 for the transmission of these signals. The check valve 160 in the gas measurement flow line 106 ensures a positive flow in the direction of the arrow 162 to prevent the ingress of the liquid portion 128 into the gas measurement flow line 106.
    [31] The liquid measurement flow line 108 includes a static mixer 164 that turbulates the liquid portion 128 within the liquid measurement flow line 108 to provide a flow of liquid, Prevents gravity segregation of each state. The Coriolis mass flow meter 166 provides a mass flow and density measurement of the liquid portion 128 within the liquid measurement flow line 108 and transmits signals indicative of these measurements to the controller 112 via path 170 Is connected to the flow flow transmitter (168).
    [32] A liquid measurement flow line 108 is provided with a water cut monitor 172 to measure the water cut of the liquid portion 128 inside the liquid measurement flow line 108. The type of water cut monitor is chosen according to how much water cut is expected in the flow stream. For example, a capacitance meter may be relatively inexpensive, but other types of meters may be required where the water cut may exceed about 30% of the volume. Capacitance or resistance probes have dielectric constants that are significantly different between oil and water. These probes lose sensitivity with increasing water and provide accurate watercut measurements that are acceptable only where the water volume is less than about 20% to 30% of the total flow stream. The upper limit of 30% accuracy limit is well below the level observed from many production wells. For example, the total liquid production volume of the well may be 99% water. Thus, the capacitance or resistivity based on a water cut monitor has been commissioned to determine the water cut in an oil component having a relatively low water content.
    [33] Commercially available devices used to measure water cuts include near-infrared sensors, capacitance / inductance sensors, microwave sensors and radio frequency sensors. This type of device is related to operational limitations. Thus, the water-cut probe measures the volume percentage in the mixed oil and water stream.
    [34] A water cut monitor device including a microwave device can detect water in an amount up to about one hundred percent of the flow mixture, but in an environment involving a three-phase flow, the gas component must be interpreted as oil. This interpretation occurs because the microwave detector operates on the principle that water in the spectrum of interest absorbs more than 60 microwaves more than it does in crude oil. The absorption assumption is that natural gas is absent and natural gas absorbs twice as much microwave radiation as crude oil. The microwave water-cut detection system can calibrate the water-cut reading by correcting the fact that the gas in the mixture did not affect the measurement.
    [35] The water cut monitor 172 is operatively connected to the controller 112 by a path 173. The controller 112 uses an electrically actuated bi-directional valve 174 to control the pressure in the liquid measurement flow line 108 in a manner that cooperates with the valve 150 to ensure proper operation of the eddy- do. That is, the valve 174 is opened and closed to prevent the gas portion 132 from being discharged into the liquid measurement flow line 108 and to prevent the liquid portion 128 from being discharged into the gas measurement flow line 106. This valve 174 is operatively connected to the controller 112 via path 176. The check valve 178 in the liquid measurement flow line 108 ensures a positive flow in the direction of the arrow 180 to prevent the gas portion 132 from penetrating into the liquid measurement flow line 108. The gas measurement flow line 106 encounters a T-shape with the liquid measurement flow line 108 to form a conventional discharge flow line 10 connected to the production kneader 118.
    [36] The controller 112 is an automated system used to control the operation of the system 100. At a base rate, the controller 112 includes a computer 84, which is programmed with data acquisition and programming software along with drive circuitry and interfaces for operation of the remote device.
    [37] The production manifold 116 includes a plurality of electrically actuated three-phase valves, such as valves 182 and 184 which may be connected to a corresponding production source such as a well 186 or a gas well 188 Respectively. A particularly preferred three-phase valve for use in the present application is the Xomox TUFFLINE 037AX WCB / 316 well switching valve with MATRYX MX200 actuator. These valves are preferably configured to respectively receive production fluid from corresponding individual wells, but may also receive production from a group of wells. The controller 112 may optionally be configured to flow polyphase fluid from the well 186 or the assembly of wells (e.g., wells 186, 188) into the rails 192 for delivery of fluid into the incoming polyphase flow line 102. While the other valve is configured to bypass the system 100 by selectively flowing through the bypass flow line 194.
    [38] The production kneader 118 is connected to a pressure transmitter 195 and a path 196 to transmit signals to the controller 112. [ The production kneader 118 is connected to a gas sales line, an oil sales line, and a seawater discharge line (not shown in FIG. 1) in any conventional manner known to those skilled in the art.
    [39] Operation of the system 100
    [40] Figure 2 shows a schematic process diagram of a process P200 that illustrates the control logic used when programming the controller 112. [ These commands reside in electronic memory or electronic storage for access and use by the controller 112. [ The instructions implementing the process P200 may be stored on any machine-readable medium for retrieval, interpretation and execution by the controller 112, or on a similar device coupled to the system 100 in any operable manner. have.
    [41] Process P200 begins at step 202 where the controller 112 determines that it is appropriate to enter the production test mode. 1, the controller 112 selectively configures the valves 182, 184 of the production manifold 116 to selectively route the flow of liquid into the incoming polyphase flow line 102 via the rails 192, 186 < / RTI > of the wells. This determination is typically performed, for example, based on a time delay to test each well one or more times per week. The test mode may be performed in a continuous manner as each valve of the production manifold 116 selectively configured to flow into the system 100 while the other valve is connected to the system 100 via the bypass line 1094. [ . These types of well test measurements are conventionally used to allocate a percentage of the total flow stream that passes through the production seizure 118 and is delivered to a particular production source, such as the sources 186, 188, based on full achievement.
    [42] Manually actuated valves 196,197 may be opened or closed for selective shutoff of the system 100. [ The valves 196,197 may be closed for removal of all the debts mounted on the skid 114. [ Electrically operated valve 199 is normally closed. A second or extra bypass line 198 within the valves 196,197 bypasses the flow when the valve 199 is open and the valves 150,174 are closed.
    [43] The test begins in step P204 where the controller 112 controls the valves 150 and 174 to decrease or increase the total flow rate through the vortex seizure 104 for the purpose of segregating the gas from the liquid phase in the polyphase fluid. Tighten or open. The total flow through the system 100 need not be reduced since the controller 112 opens the valve 199 and allows the flow to pass through the bypass line 198. The exact flow rate will depend on the physical volume of the vortex solver and liquid measurement flow line 108 and will also depend on the amount of fluid that the sources 186,188 can deliver to the system 100. [
    [44] The purpose of reducing the flow rate through the system 100 is to reduce the flow rate of the vortex sludge 104 by the help of gravity segregation when the flow rate is still high enough to prevent substantial gravity segregation of oil from the remaining liquid water. To remove entrainment bubbles from the liquid measurement flow line 108 through use. It is also possible to carry out substantially complete segregation of the gaseous state from the liquid state by increasing the flow rate as a segregation effected by the centrifugal force through the vortex solitator 104. The controller 112 monitors the drive gain or pick-off voltage from the Coriolis mass flow meter 166 for this purpose, as described in connection with FIGS. 3 and 4.
    [45] FIG. 3 is a graph of virtual data demonstrating the actual effects of the gas attenuating the frequency response of the flow tube in the Coriolis mass flow meter 166 (see FIG. 1). The log of the permeability is plotted as a function of the frequency of the alternating voltage applied to the drive coil of the Coriolis mass flow meter 166, e.g., f 0 , f 1 and f 2 . The transmittance ratio (T r ) is equal to the output of the flow meter pick-off coil divided by the drive input. That is, the driving gain is:
    [46] (1) Tr = =
    [47] The first curve 300 corresponds to equation (1) of the non-damping system. That is, no gas exists in the fluid to be measured. The second curve 302 corresponds to an attenuated system in which the gas is present. The two curves 300 and 302 have optimum values 304 and 304 ', respectively, at the natural frequency f n .
    [48] 4 is a plot of virtual data showing the relationship between drive gain and time for a case 400 when a temporary bubble enters a Coriolis mass flow meter 166 as bubbles entrained in a polyphase fluid. These bubbles enter time 402 and go to time 404. The drive gain is plotted as a percentage of time in FIG. 4 and plotted as a function of time at intervals such as t 1 , t 2, and t 3 . The controller 112 (shown in FIG. 1) is programmed to monitor the drive gain or transmittance by comparing the drive gain or transmittance to the threshold 406. Where the drive gain or transmittance of the curve 108 exceeds the threshold 406, the controller 112 recognizes that the density measurement is affected by the presence of transient bubbles. Thus, the Coriolis mass flow meter 166 uses only the density value obtained when the drive gain is less than the threshold value 406 for step P206. The exact level of the threshold value 406 depends on the particular flow meter configuration, along with the intended environment to be used, and is intended to be less than one to two percent by volume in the polyphase fluid.
    [49] When operating the Coriolis mass flowmeter, the pick-off voltage often drops in inverse proportion to the case of the curve 400 shown in Fig. Coriolis mass flow meters are sometimes programmed to sense this drop in amplitude and respond by vibrating the oscillating coil against the amplitude of the maximum configuration requirement until the gas attenuation effect reverses.
    [50] The controller 112 opens and / or closes the valves 150,174 until the drive gain drops below the threshold value 406 in the manner described for step P204, step P206 causes the liquid state And a Coriolis mass flow meter 166 for measuring the density of the fluid. This density measurement is intended to represent the density of the liquid state without gas voids. This density measurement is referred to as rho L in the description below and is used to denote the density of a liquid mixture comprising gas and oil without accompanying gas friction. As an alternative for carrying out the direct measurement for the multiphase fluid in the fluid measuring line 108, the fluid came up empirically derived to obtain a sample of the multiphase fluid for laboratory analysis or to obtain access to the less desirable ρ L than interrelationship It is also possible to estimate the density by use.
    [51] In step P208, a vortex solver 104 (in accordance with the manufacturer's description based on the total flow rate through the Coriolis mass flow meters 154,166, along with the pressure signals received from the pressure transmitter 135 and the differential pressure gauge 140, The controller 112 selectively adjusts the valves 150 and 174 in such a manner as to optimize the segregation results. At this stage, the production manifold 116 is configured to flow for active production well test measurements. The controller 112 adjusts the valves 150,174 in a manner that reduces the drive gain below the threshold 406 shown in Figure 4 so that the vortex sifter 104 is at this stage compared to step P204, Function. In this state, most liquid conditions flowing through the liquid measurement flow line 108 may include accompanying gas bubbles.
    [52] Step P210 includes the most massive total mass flow rate Q TL including the accompanying gas in the liquid measurement flow line 108 and the use of the Coriolis mass flow meter 166 to measure the density of such a majority liquid state . This density measurement is referred to as ρ meas in the following discussion.
    [53] In step P212, the controller 112 determines the dry gas density (ρ gas ) of the gas in the polyphase fluid. Using the well known correlation developed by the American Gas Association based on gas gravity, the gas density may be calculated from the pressure and temperature information, or the actual measurement of the gas produced from the polyphase flow stream ≪ / RTI > may be provided by laboratory analysis. Another alternative technique for determining the gas density is to obtain an actual density measurement from the Coriolis flow meter 154 at the same time as step P204 or in separate step P210, The valves 150 and 174 are selectively adjusted to minimize the intensity. In some situations, it may be assumed that the density of the gas is relatively low compared to the liquid density, so that the gas density remains constant, and this constant gas density assumption results in an acceptable level of error.
    [54] In step P214, the controller 112 calculates the gas porosity X L in the liquid state.
    [55] (2)
    [56] Where XLi is the porosity that represents the gas void in the polyphase fluid flowing through the Coriolis mass flow meter 166, i means continuous repetition, and rmemeasure is the density measurement obtained in step P210 as described above, And ρ calc is a calculated or estimated density value that approximates the density of the polyphase liquid having a porosity of about X Li . Equation (2) will be used for the iterative convergence algorithm. Thus, it may be acceptable to start the calculation with a first guess, such as a stored value for ρcal from a previous cycle of test measurements on a particular production source 186, or any value such as 0.8 g / cc.
    [57] A particularly preferred method for providing a first guess for the value of r calc is to obtain a watercut measurement from the water cut monitor 172. Subsequently, equation (3) can be solved for ρcalc , assuming that no gas is present in the multiphase flow mixture.
    [58] (3)
    [59] Here, WC is the water-cut as shown as a fraction (fraction) containing the amount of water in the liquid composition divided by the total volume of the liquid mixture, ρ w is the density of water in the liquid mixture, and ρ 0 is the oil in the liquid mixture Density. The first generated value for ρ calc is the theoretical value of the liquid mixture without gas porosity. When and if the value of ρ and ρ w o right, X i is greater than 0, the measured density, ρ meas is less than ρ calc. The value of ρ and ρ w o may be obtained from laboratory measurements that are executed on a sample of the most liquid containing oil and water conditions, respectively. For example, the density value of water may be obtained from a hydrometer coupled to the water trap 130. [ These values can be approximated to acceptable levels of accuracy by a well-known empirical relationship published by the American Petroleum Institute.
    [60] In step (P216), the controller 112 is to execute the calculation, and determines whether the final estimate of ρ calc provides a calculation of Li X according to equation (2), X i has converged within the allowable range of error. The next estimate for < RTI ID = 0.0 >
    [61] (4)
    [62] . Here, ρ calci is the next estimate calculated using the value of X Li from equation (2), ρ L is the density of the liquid mixture, and the remaining variables are described above.
    [63] Step P218 is a test for convergence where convergence is true if the following equation is true.
    [64] (5)
    [65] Where D is the absolute value of the delimiter character indicating a negligible error, such as 0.01 g / cc, or the limit of precision available from the Coriolis mass flow meter 166, and ρ calci is the calculated value Is the current value, and ρ calci-1 is the past value from the pre-iteration of equation (2) to produce an X Li value corresponding to ρ calci .
    [66] The controller at step P218 determines that there is no convergence and the new estimate ρ calci is replaced by the past estimate ρ calc at step 220 and steps P214 through P218 are repeated until there is convergence do.
    [67] The water cut can be calculated by the following equation.
    [68] (6)
    [69] Where W C is the water cut, ρ O is mostly the density of the oil in the liquid component, and ρ W is mostly the density of water in the liquid component. Accordingly, the cut meter 172 may have a redundant configuration if there is no gaseous state in the multiphase flow, and may be selectively removed since there is no necessary value for such a repeated convergence method.
    [70] In step P214A, a more precise or non-repetitive solution is available if the measured water cut value supplied by the cut meter 172 is within a range where the instrument functions with acceptable accuracy and precision. This cut gauge reading is a function of the fluid component, which is a simultaneous solution of a system of three equations to provide a solution to three variables. These three equations are as follows.
    [71] (7)
    [72] (8)
    [73] (9)
    [74] Here, the density of water in the ρ W is the flow stream, ρ O is the density of the oil in the flow stream, ρ g is the density of the gas in the flow stream, ρ mix is the density of the combined flow stream, q W is a volume of water fraction flow (i. e., water cut) by a, q O is a fraction ever flow rate by volume of the oil, q g is a fraction ever flow rate of the gas volume, and f (sat) is the total meter reading (M) Lt; RTI ID = 0.0 > flow-cut < / RTI >
    [75] If the water-cut instrument is a microwave instrument, the function f (sat) = M can be approximated as:
    [76] (10)
    [77] Where m w is the instrument reading from pure water, m o is the instrument reading from pure oil, m g is the instrument reading from pure gas, and the remaining terms are described above. Here, in a typical instrument, m w = 60, m o = 1 and m g = 3, and equations (8) through (11) can be calculated for q W as follows.
    [78] (11)
    [79] Here, the terms are as described above. Also,
    [80] (12) , And
    [81] (13)
    [82] Once convergence is achieved in step P218, step P222 is followed by the use of the Coriolis mass flow meter 154 to determine the most gaseous state flowing through the Coriolis mass flow meter 154 under the flow conditions of step 208 The mass flow rate Q TG and the density Mg are measured.
    [83] Step P224 includes the step of solving for the gas gaseous porosity X G of the most gaseous state flowing through the gas measurement flow line 106, according to the following equation:
    [84] (14)
    [85] Where X G is a majority ratio corresponding to the gas volume taken on the total volume of the gaseous phase, ρ mgas is the value obtained in step (P222), ρ gas is a value obtained in step (P212), and ρ L comprises the steps (P206).
    [86] In step P224, the value of the water cut obtained in the water cut monitor 172 is adjusted as necessary to compensate for the presence of gas in a mostly liquid state. For example, if the gas porosity X Li is known, these values can be used to calibrate the water cut for microwave absorption under the assumption that only oil and water are present.
    [87] Step P226 comprises using the data necessary to solve for the flow of each of the three respective states in a mostly liquid state and in most of the gaseous state. The following equations can be used for this purpose.
    [88] (15)
    [89] (16)
    [90] (17)
    [91] (18)
    [92] (19)
    [93] (20)
    [94] (21) And
    [95] (22)
    [96] Where Q L is the total mass flow rate of the liquid phase flowing through system 100 and X i is the gas porosity in most of the liquid state determined from step P214 and causes convergence in step P218. Q TG is the total gas mass flow rate in most of the gaseous states measured in step P222, X G is the porosity in most of the gaseous states determined in step P224, and Q W is the total mass flow rate through system 100 Q O is the total oil mass flow rate through the system 100 and WC is the water cut provided from the water cut monitor 172 by correlation as required in step P224 and V L is the water mass ), the flow total and volume flow, of liquid through ρ L is the liquid density, as determined in step (P206), V O is the total oil volume flow passing through the system (100), ρ O is in flow conditions V G is the total gas volume flow through system 100, p gas is the gas density at flow conditions, V W is the total volume flow through system 100, and ρ W Is the water density at flow conditions.
    [97] In step P228, the controller 12 provides a system output including direct temperature, density, and mass flow measurements, along with calculation results for volume and mass flow rates for each state. These flows can be statistically over time to provide a cumulative production volume for the test interval.
    [98] In step P230, the controller 112 interacts with the system components including the production manifold 116 to optimize field efficiency. For example, in an oil field having drive energy dominated by a gas cap, production efficiency is optimized when the gas cap is depleted after oil is discovered. It is desirable to produce the oil prior to the gas and the gas-oil contact may move downward into the previous oil zone as the oil is depleted. The movement of these gas-oil contacts causes the gas to be produced primarily before the wells, primarily oil being produced. An appropriate response to this significantly increased gas production in the well is to shut down the well or reduce the production rate of the well so as not to exhaust the storage energy of the reservoir and the controller 112 is programmed to take this action. Similar reactions can be programmed to move the oil-water contacts, or to optimize current economic performance from a computational point of view by producing a low cost well ahead of higher costs if all other factors are the same.
    [99] It will be understood by those skilled in the art that the above-described preferred embodiments are susceptible to modification without departing from the scope and spirit of the present invention. Thus, the inventors hereby describe all their intentions on the basis of the doctrine of equivalents in order to protect all their rights in the present invention.
    权利要求:
    Claims (34)
    [1" claim-type="Currently amended] (104) for segregating the incoming multiphase flow in a mostly liquid state with mostly liquid components, including associated gases, and in a mostly gaseous state with mostly gaseous components, and a flow meter (166) A multiphase flow measurement system (100) for use in a flow environment comprising a plurality of flow and gaseous states,
    And a controller (112) configured to measure the flow rate of the substantially liquid state using a calculation for measuring the flow rate of the individual liquid state and the individual gas state in the substantially liquid state.
    [2" claim-type="Currently amended] The system of claim 1, wherein the flow meter (166) comprises a mass flow meter.
    [3" claim-type="Currently amended] 3. The system of claim 2, wherein the mass flow meter (166) is a Coriolis mass flow meter.
    [4" claim-type="Currently amended] The system of claim 1, wherein the calculation of the most liquid state flow rate is an empirically derived relationship, except for an empirically derived relationship used to determine a fluid property selected from the group consisting of density and viscosity.
    [5" claim-type="Currently amended] 5. The method of claim 4, further comprising: a liquid measurement flow line (108) from which the first liquid flows from the zigzag (104) in a manner that does not provide essentially entrained gas bubbles in the first liquid; and
    Further comprising a density meter (166) for determining the density rho L of the first liquid in the liquid flow line (108).
    [6" claim-type="Currently amended] The method of claim 5, wherein the system 100 is a second member for measuring the density of the density ρ meas the most liquid,
    The controller 112 is configured to calculate the porosity XL based on the relationship between the density ρ meas of the most liquid state and the density ρ L of the first liquid, And applying said porosity X L to said total liquid flow Q TL to provide respective flows Q L and Q G.
    [7" claim-type="Currently amended] 7. The system of claim 6, wherein the controller (112) is configured to calculate the porosity X L using an iterative convergence calculation.
    [8" claim-type="Currently amended] 8. The system of claim 7, wherein the controller (112) is configured to converge the iterative convergence calculation method based on a difference between a measured density value and a theoretical density value based on the porosity X L.
    [9" claim-type="Currently amended] 9. The system of claim 8, wherein the transmitter (112) is configured to calculate a porosity X L using non-iterative calculations.
    [10" claim-type="Currently amended] 10. The system of claim 9, wherein the transmitter (112) is configured to calculate the porosity X L , including comparing results from the iterative calculation to results from the non-iterative calculation.
    [11" claim-type="Currently amended] The method of claim 6, wherein the system 100 further comprises a gas densimeter (154) for measuring the gas density ρ of the gas at the temperature and pressure in the multi-phase flow system, and
    Wherein the transmitter (112) is configured to calculate a density (rho calc) based on the gas density (rho gas) , the liquid density (rho L) and the porosity (X L) .
    [12" claim-type="Currently amended] 12. The method of claim 11, the transmitter 112, the On and the porosity of the gas density multiplied by the X L ρ gas, 1 obtained by subtracting the void ratio X L plus the product of the fluid density ρ L value of the density ρ according to the relationship with equal calc system that is configured to calculate the density ρ calc.
    [13" claim-type="Currently amended] The method of claim 12, wherein the transmitter (112) is a continuous value of X L until the ρ calc converged within the range of the allowable error for the value of the density ρ meas is determined by said means for measuring the density ρ meas Lt; RTI ID = 0.0 > ρ calc , < / RTI >
    [14" claim-type="Currently amended] 14. The method of claim 13, the said transmitter (112), the same value in the gas voidage X Li the density ρ calc, obtained by subtracting the value obtained by dividing the density ρ meas to ρ calc and the relationship of gas porosity based on repeated estimate of ρ calc And the value of density < RTI ID = 0.0 > calc < / RTI >
    [15" claim-type="Currently amended] 12. A water cut monitor (172) for measuring a water cut WC in the most liquid state based on the density rho calc when the most liquid state includes an oil state and a water state within an intended use environment Systems Included.
    [16" claim-type="Currently amended] 16. The method of claim 15, wherein the water cut monitor (172) is configured such that the water cut WC is equal to the density Calc , minus the water density divided by the oil density, Wherein the density of the oil in the liquid phase is a function of the density of the water in the liquid phase.
    [17" claim-type="Currently amended] The system of claim 1, wherein the system (100) comprises a density meter (154) for measuring the density of the most gaseous components delivered from the kneader ,
    And a gas flow meter (154) for measuring the flow of said majority gas component.
    [18" claim-type="Currently amended] 18. The method of claim 17 wherein the transmitter system is configured to calculate the void ratio X G in the gas phase, most based on the density using the density ρ mgas.
    [19" claim-type="Currently amended] A method (P200) for performing a multiphase flow measurement in a flow environment comprising a liquid state and a gaseous state,
    (P204) segregating the incoming multiphase flow in a mostly liquid state with mostly liquid components with accompanying gases and in a mostly gaseous state with mostly gaseous components,
    A step (P210) of measuring the flow rate of the most liquid state, and
    (226) to determine a flow rate of the individual liquid state and the individual gaseous state in the substantially liquid state.
    [20" claim-type="Currently amended] 20. The method of claim 19, wherein the calculating step is used to determine fluid properties selected from the group comprising density, viscosity, and non-empirically derived relational expressions. Way.
    [21" claim-type="Currently amended] The step of measuring the flow rate of the most liquid state comprises:
    Flowing the first liquid from the segregation means in a manner that does not essentially provide entrained gas bubbles in the first substantially liquid.
    [22" claim-type="Currently amended] 22. The method of claim 21, wherein measuring the flow rate of the substantially liquid state comprises:
    Measuring (P210) the density, rmeas , in the most liquid state that is likely to include entrained gas bubbles in the liquid state under normal flow conditions;
    Calculating a porosity X L based on the relationship between the density ρ meas and the density ρ L (P214), and
    Applying the porosity X L to the total liquid flow Q TL in order to provide a flow Q L of the liquid component and a flow Q G of the gas component in the bulk liquid state, respectively.
    [23" claim-type="Currently amended] 23. The method of claim 22, wherein calculating the porosity X L (P214) comprises performing an iterative convergence calculation.
    [24" claim-type="Currently amended] 24. The method of claim 23, wherein the iterative convergence calculation is based on a difference between a measured density value and a theoretical density value based on the porosity XL.
    [25" claim-type="Currently amended] 25. The method of claim 24, wherein calculating the porosity X L (P214) comprises performing non-iterative calculations.
    [26" claim-type="Currently amended] 26. The method of claim 25, wherein calculating the porosity X L (P214)
    And comparing the result of the iteration calculation to the result from the non-iterative calculation to obtain the best solution.
    [27" claim-type="Currently amended] The method of claim 22, further comprising measuring the gas density ρ of the gas at the temperature and pressure in the multi-phase flow measurement system and,
    Measuring the liquid density rho L of the most liquid state;
    Calculating a porosity X L based on the relationship between the determined ρ meas and the density ρ L (P214)
    Comprising the step (P216) to the porosity from the porosity determined from the step of calculating the L X X L, the liquid density ρ L, and the gas density ρ gas, calculates the density ρ calc.
    [28" claim-type="Currently amended] 28. The method of claim 27 wherein step (P216) for calculating the density ρ calc the relation:
    P calc = (P gas XL) + (1-X L ) P L ,
    X L is the porosity of the most liquid component.
    [29" claim-type="Currently amended] The method of claim 28 wherein step (P216) for calculating the density ρ calc is
    Repeating the value of ρcal over successive values of X L until ρ calc converges within a range of acceptable errors for the value ρ meas determined from the step of measuring the density ρ meas .
    [30" claim-type="Currently amended] 32. The method of claim 31, further comprising: repeating the values of the relation ρ calc is:
    X Li = (P calc -P meas ) / P calc ,
    Wherein X Li is the gas porosity based on the repetition of Calc .
    [31" claim-type="Currently amended] 31. The method of claim 30 including calculating (P224) the water cut WC in said most liquid state based on density rho calc .
    [32" claim-type="Currently amended] The method according to claim 31, wherein the step (P224) of calculating the water cut WC comprises:
    WC = (P calc -P O ) / (P W -P O )
    Wherein P O is the density of the oil in the most liquid state and P W is the density of water in the most liquid state.
    [33" claim-type="Currently amended] 23. The method of claim 22, further comprising the steps of: (P222) measuring the density < RTI ID = 0.0 > mgasas &
    And measuring (P222) the most gaseous flow rate.
    [34" claim-type="Currently amended] The method of claim 33 wherein using the density ρ mgas determined from the means for measuring the density ρ mgas calculating a void ratio X G in the gas phase, most based on the density.
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    公开号 | 公开日
    JP4890713B2|2012-03-07|
    US6564619B2|2003-05-20|
    EP1224440A2|2002-07-24|
    US6318156B1|2001-11-20|
    CA2389145C|2007-02-13|
    JP2003513234A|2003-04-08|
    RU2270981C2|2006-02-27|
    MXPA02004238A|2003-02-12|
    WO2001031298A2|2001-05-03|
    BR0015083A|2002-10-29|
    CA2389145A1|2001-05-03|
    CN1415070A|2003-04-30|
    AR031833A1|2003-10-08|
    US6810719B2|2004-11-02|
    US20050016292A1|2005-01-27|
    RU2002113739A|2004-02-10|
    WO2001031298A3|2001-12-13|
    US20020033043A1|2002-03-21|
    BRPI0015083B1|2017-02-14|
    US7013715B2|2006-03-21|
    KR100505965B1|2005-08-03|
    CN1187580C|2005-02-02|
    US20030136185A1|2003-07-24|
    HK1053694A1|2005-09-23|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    法律状态:
    1999-10-28|Priority to US09/428,416
    1999-10-28|Priority to US09/428,416
    2000-10-18|Application filed by 마이크로 모우션, 인코포레이티드
    2002-08-21|Publication of KR20020067036A
    2005-08-03|Application granted
    2005-08-03|Publication of KR100505965B1
    优先权:
    申请号 | 申请日 | 专利标题
    US09/428,416|US6318156B1|1999-10-28|1999-10-28|Multiphase flow measurement system|
    US09/428,416|1999-10-28|
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