Source: http://www.google.com/patents/US6655221?ie=ISO-8859-1&dq=7,117,286
Timestamp: 2014-08-30 17:45:20
Document Index: 295908441

Matched Legal Cases: ['application no. 971791', 'application no. 971791', 'application no. 971791', 'application no. 971791', 'application no. 971791', 'application no. 971791', 'art 3']

Patent US6655221 - Measuring multiphase flow in a pipe - Google PatentsSearch Images Maps Play YouTube News Gmail Drive More »Sign in<nobr>Advanced Patent Search</nobr>PatentsThe method and the measuring system in accordance with the invention utilizes a measurement of electrical fields to determine the electrical characteristics of phases in a multi-phase mixture constituting a fluid flow through a conduit. This is used as part of the determination of the phase fractions....http://www.google.com/patents/US6655221?utm_source=gb-gplus-sharePatent US6655221 - Measuring multiphase flow in a pipeAdvanced Patent SearchPublication numberUS6655221 B1Publication typeGrantApplication numberUS 09/869,994PCT numberPCT/NO2000/000005Publication dateDec 2, 2003Filing dateJan 10, 2000Priority dateJan 11, 1999Fee statusPaidAlso published asCA2360256A1, CA2360256C, EP1173734A1, WO2000045133A1Publication number09869994, 869994, PCT/2000/5, PCT/NO/0/000005, PCT/NO/0/00005, PCT/NO/2000/000005, PCT/NO/2000/00005, PCT/NO0/000005, PCT/NO0/00005, PCT/NO0000005, PCT/NO000005, PCT/NO2000/000005, PCT/NO2000/00005, PCT/NO2000000005, PCT/NO200000005, US 6655221 B1, US 6655221B1, US-B1-6655221, US6655221 B1, US6655221B1InventorsAudun Aspelund, Tor Wider�eOriginal AssigneeFlowsys AsExport CitationBiBTeX, EndNote, RefManPatent Citations (12), Referenced by (45), Classifications (16), Legal Events (4) External Links: USPTO, USPTO Assignment, EspacenetMeasuring multiphase flow in a pipeUS 6655221 B1Abstract The method and the measuring system in accordance with the invention utilizes a measurement of electrical fields to determine the electrical characteristics of phases in a multi-phase mixture constituting a fluid flow through a conduit. This is used as part of the determination of the phase fractions. Further, one uses time-varying signals from at least one pair of detectors for the electrical characteristics of the fluid, combined with the use of a cross-correlation for determining one or several velocities in the flowing fluid. Additionally, one or several pressure drops are measured across, or adjacent to, a narrow passage. By combining measurements of the electrical characteristics, with measurements of pressure drop, the fractions of all phases in the flow are determined. Combined with measurements of the velocities, the volume flow rates are calculated for the phases and by further combining this with the mass densities of the phases, the mass flow rates of the phases are determined.
FIELD OF THE INVENTION The invention relates to a method and a system for flow measurement of a two-phase liquid/liquid or liquid/gas mixture, or a three-phase liquid/liquid/gas mixture flowing through a production or transport pipe. The method and the system shall be used for measuring the percentage composition of phases in the pipe cross section at any time, as well as the individual phase velocities. Hence, from these measurements, the method and the system provide opportunities for calculating the volumetric flow rate of each respective phase in the two-phase or three-phase mixture. Additionally, knowing the mass densities of the individual phases, it is also possible to calculate the mass flow rates of the phases. The method and the system are in particular directed to applications within oil and gas production industry, where phases in a two-phase mixture may typically be hydrocarbons in liquid form, like crude oil or condensate, and hydrocarbons in gas form�natural gas, or crude oil/condensate and produced or injected water. The phases in a three-phase mixture may typically be crude oil/condensate, water and natural gas.
BACKGROUND OF THE INVENTION During production of oil and gas, it is desirable to carry out flow measurement, in the form of mass flow rate or volume flow rate, of a pipe flow consisting of a two-phase or three-phase combination of oil/water/gas, so called multiphase measurement, This can be done using permanently installed measurement systems, e.g. on a marine production platform or on a land-based production plant. Such measurement systems are little by little replacing conventional measurement methods comprising bulky test separators complete with single-phase flow meters like turbine meters and measurement orifices measuring individual phases after separation thereof. It is important to measure the quantity produced from a reservoir to be able to control and regulate the production process in an effective manner. This enables optimum total production over the lifetime of a field, it is also desirable to measure the production from single wells individually, since a change in one individual well, for instance a sudden increase in the water production, is difficult to detect by measuring the collective production from several wells. Often, fiscal elements are also involved, wherein it is an important point to allocate the production from individual wells to the rightful owners, where the production from such wells is processed in a common processing plant with a different owner structure than the wells. It would also be desirable to be able to measure produced oil with an accuracy that is sufficient for buying and selling, but so far this is not realistic when using multiphase meters.
It has also become of interest to be able to measure flow rates continuously downhole, and development work is presently going on regarding such instrumentation. Today's well measurements are often carried out on a temporary basis, for instance as production logging where measurement systems are introduced down into the well by means of wireline or coil piping. This is expensive, and provides to a large degree qualitative measurements. Relatively long time may also pass between execution of such measurements, so that there is a risk of regulating the wells in accordance with old data, even if the production may have changed in the meantime. Besides, lately the complexity of the oil wells has increased strongly, due to new and more advanced methods within drilling and completion technology, and production from layered reservoirs, multibranch and horizontal wells have become ordinary practice, Being able to execute continuous downhole multiphase measurement on a permanent basis, will enable effective reservoir control, and in combination with e.g. valves for controlling influx from the reservoir, it is possible to achieve so-called �intelligent wells� that will result in increased oil extraction, reduced water production and eventually reduced intervention frequency. Today permanent well instrumentation consists substantially of pressure and temperature gauges, and to some degree Venturi meters for liquid rate measurements. To a certain degree, flow models are utilized that are based on measurements from pressure and temperature gauges located in different places, conservation laws for mass and moment, thermodynamic relations, physical parameters and reference measurements from logging. However, these methods depend on the �goodness� of the models, i.e. the ability to predict the individual flow rates of phases within the necessary uncertainties, and on correct assumptions regarding the physical and geometrical parameters in the well. They also require a high degree of calibrating in situ to obtain the desired precision.
When oil, water and gas flow simultaneously through a pipe, the distribution of the three phases may form a large number of different regimes or patterns, both axially and radially. Therefore, the influence of the flow on a measuring system will vary correspondingly, which becomes apparent particularly when measurements are carried out continuously over time. Generally, the flow will consist of a continuous and a discontinuous phase. Ordinarily, the liquid is the continuous phase, with free gas as the discontinuous phase. The free gas may be distributed substantially in two ways, like larger pockets, or like myriads of very small bubbles atomized in the liquid phase. In addition, some gas will often be dissolved in the oil phase, particularly under high pressures. As regards the liquid per se, it may be continuous oil with water drops distributed in the oil. This occurs often early in the lifetime of a well, when the oil usually is the dominating phase as to percentage. Moreover, this mixture is electrically insulating. In the opposite case with continuous water flow, oil drops are distributed in the water, which provides an electrically conductive liquid phase. The size of the distributed drops may vary, and the mixing mechanisms may be different, all the way from stable emulsions to more loose mixtures of the two phases. Essentially the liquid will be transported as one phase with one common velocity. Exceptions herefrom are in low flow velocities, where oil and water can be subject to complete or part separation, and when the pipe has an inclination deviating from the horizontal plane. In this case, gravity will make the heaviest component, usually the water, move with lower velocity than the oil. This difference in velocity is often termed �slip�. In a well flow it may also happen that the water has a negative velocity relative to the general flow direction. As the well pressure decreases, more free gas will be produced, and it may happen that the gas becomes the dominating flow phase. Then the liquid will often be distributed as a film flowing relatively slowly along the pipe wall, in combination with a drop phase that to a larger degree accompanies the gas. Since the mass density of the gas is usually substantially lower than the mass density of the liquid phase, there will, as a rule, always exist slip between gas and liquid. The situations described above are often divided into main groups with designations bubble flow, slug flow, chum flow, layered flow and annular flow. A measurement system should therefore be able to make measurements under all of the above described flow situations, including cases with velocity slip between phases, and in particular between liquid and gas
SUMMARY OF THE INVENTION In the following, the present invention is described in the form of a system for measuring characteristic parameters of a multiphase flow of crude oil or condensate, produced and/or injected water, and natural gas in a transport pipe, as well as a method that uses the measured parameters for determining the individual flow rates for crude oil/condensate, water and natural gas. The system comprises a compact sensor body having a substantially circular cross section, which sensor body is located centrally inside a transport pipe having a relatively constant inner diameter and having a circular cross section. The sensor body will in a first variant form a coaxial sensor wherein the flow is transported in an annular space between the body exterior and the inner pipe surface. In another variant, the sensor insert will be designed as a sensor insert shaped in principle inverted in relation to the first one, with a diameter choke having a transition from a diameter equal to the inner diameter of the transport pipe, through a reduction of the diameter to a cylindrical part and thereafter an increase of the diameter again to an inner diameter equal to the transport pipe inner diameter.
DESCRIPTION OF THE PRIOR ART It is previously known from Norwegian patent application no. 971791 (Japan National Oil Corp., Yokogawa Electric Corp., NKK Corp., Japan Petroleum Exploration Co. Ltd., Teikoku Oil Co. Ltd.) a device that utilizes principles that may to some degree exhibit similarity with the present invention. The common features are that both inventions measure velocity and phase fractions in a multiphase mixture, and both utilize one or several coaxial sensors measuring the electrical characteristics in the three-phase mixture flowing between an outer electrode shaped as a cylinder and an inner, cylindrical electrode, placed concentrically inside the pipe. Further, cross-correlation is made between two sensors placed a fixed distance apart along the pipe axis, in order to determine one or several velocities. Finally, the electrical measurement principle can be combined with a pressure drop gauge to determine one of the fractions by combining the pressure drop equation with the equation for the electrical characteristics. However, the two inventions exhibit substantial difference in that the instrument described in patent application no. 971791 measures the dielectric constant between two outer, separate excitation electrodes respectively, which electrodes are excited by a sweep of frequencies through the microwave range, and a concentrically placed, inner common electrode, possibly two separate such electrodes, lying constantly on the electrical ground potential. The inner electrode is hollow, ie. tubular, so that the flow passes both on the inside and the outside thereof. In the present invention, the electrical field is measured between several electrodes on the outside of a massive, substantially cylindrical, inner body placed concentrically inside the pipe, and associated counter electrodes. In patent application no. 971791, measurements are made by varying the frequency through a relatively large range, and thereafter two frequencies are selected in order to measure one individual phase fraction in the liquid. First, the water fraction is measured by measuring the permittivity difference at the two frequencies, based on the dielectric loss of the water, or dispersion, in this range. Thereafter, the oil fraction is measured in a similar manner, at two other frequencies, provided that the oil has a dielectric loss in the swept frequency range. If the oil is without loss, one uses a measurement from a flow meter of the differential pressure type with the momentum equation valid therefor, combined with one of the impedance measurements, for determining the oil fraction. The differential pressure gauge is placed upstream of the impedance sensors, and separate therefrom. The gas fraction is always calculated by subtracting the two other phase fractions from the sum of fractions that is equal to 1. The embodiment of the present invention that reminds of the flow meter described in patent application no. 971791, differs therefrom in that it first measures the velocity of the complete liquid phase by cross-correlation between two measurements of the electrical characteristics. At the same time, a pressure drop is measured between a position e.g. upstream in relation to the inner body and a position in the narrowing along said body. The general momentum equation for pressure drop gauges, in which the liquid velocity is included, is then combined with the equation for the electrical characteristics, in order to determine the gas fraction as well as the water-in-liquid fraction at the same time. Another important difference is that in the present invention, one and the same body is utilized both for generating a pressure drop and for measuring the electrical characteristics, so that both measurements are made in approximately one and the same position. In addition, the gas velocity is measured by means of a second cross-correlation between a second pair of electrodes on the inner body. In patent application no. 971791 there is no description regarding a separate measurement of the gas velocity, only of water and oil. In the case where the instrument described in patent application no. 971791 uses the momentum equation to determine the oil fraction, it is presumed that there is no velocity difference between phases after having these phases mixed in a static mixer upstream of the gauges.
OBJECTS OF THE INVENTION The method and the system in accordance with the invention are defined precisely in the appended patent claims.
BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 shows a first embodiment of the invention, with the transport pipe, the sensor body with electrodes, as well as a differential pressure gauge in the upstream end of the sensor body.
This sensor design results in a coaxial sensor that is characterized by two particular advantages; it is one of the most sensitive types of sensor for measuring electrical characteristics, and it provides a symmetrical geometry in the measuring area 10 in the annular space between the measuring section 3 and the pipe 11, rendering the electrical field a symmetrical field. The electrodes 7 a-d may have different length, and the distance between them may vary, depending on what they are intended to measure. Substantially there will be two pairs of measurement electrodes 7 a and 7 b as well as 7 c and 7 d, where one pair 7 a and 7 b consists of equally large, but relatively short electrodes with a relatively short distance therebetween. The second pair 7 c and 7 d consists of equally large, but somewhat longer electrodes with a relatively large distance therebetween. In addition, the measuring section 3 can be provided with further electrodes as required, so called �guard electrodes�, to ensure that the electrical field in the measuring area 10 is as homogenous as possible. The guard electrodes will in such cases be driven on the same electrical potential as the measurement electrodes 7 a-d, and geometrically they will be placed closely adjacent the measurement electrodes 7 a-d The method consists in continuously measuring the electrical field between electrodes 7 a-d and the wall of pipe 11 in the measuring area 10 so as to determine the electrical characteristics of the, fluid 14 flowing at any moment in the annular space 10 between measuring section 3 and the inside of flow pipe 11. This can be done in two ways. One way is to excite the electrodes 7 a-d on the sensor body 1 with an electrical voltage, and measure the magnitude of the electrical field between these electrodes 7 a-d and the wall of pipe 11, which is held on electrical ground potential. In this case is will be particularly important to use guard electrodes. The second way is illustrated in FIG. 2, and is executed by placing a large cylindrical electrode 12 out next to the wall of pipe 11 in such a manner that it is placed concentrically with pipe 11, but insulated therefrom by means of an electrically insulating material 13. Such an electrode will have a length that is at least the size of the distance from the upstream end of the first electrode 7 a, to the downstream end of the last electrode 7 d on sensor body 1. Using this principle, the above mentioned cylindrical electrode 12 is excited with an electrical voltage, and one measures the magnitude of the electrical field between this electrode 12 and the individual electrodes 7 a-d on sensor body 1 which in this case electrically may be on a virtual ground potential. The electrical characteristics of the flowing medium 14 depend on the fraction ratio (e.g. a percentage) between oil, water and gas in the fluid flow 14, and, again referring to FIG. 1, output signals representing this fraction ratio are obtained from the electronic circuits 9 a-d. Several physical models exist regarding the interrelation between fraction ratios and electrical characteristics for a mixture of fluids 14. As an example, it can be referred to the Boyle model for parallel-oriented spheroids of a phase 15 distributed in a continuum of another phase 16. In this model, the electrical characteristics are expressed through the permittivities (the dielectric constants) of the individual phases in a mixture, as well as the permittivity of the mixture 14 itself, as a function of the fraction of the discontinuous phase 15 in the mixture 14. For a two-phase liquid/liquid mixture 14 wherein the discontinuous phase 15 is water drops distributed in a continuum 16 of oil, the following exemplary model may be usable: ɛ watt - ɛ liq ɛ watt - ɛ oil � ( ɛ oil ɛ liq ) A 2 =  1 - φ wat / ( φ wat + φ oil ) =  1 - φ wat Equation   1. with only oil and water present, because φwat+φoil =1, and wherein εwat, εoil and εliq are the permittivities of water, oil and liquid mixture respectively, fast is the water fraction in the liquid phase, and Aa is a form factor depending on the shape of the spheroids. For perfect small balls, this form factor is typically ⅓. The relative sum of the water fraction and the oil fraction is in this case equal to 1, which gives the second necessary equation for this system. It is then possible to calculate the fractions of the two phases 15 and 16 directly, since the permittivities of the individual phases are presumed to be known, while the permittivity of the liquid mixture is a result of the measured quantity.
φgas+φwat+φoil=1 Equation 3. Thereby, one has two equations, but one further equation is needed to find the fractions for all three phases. This problem will be reverted to, after first having looked at further use of the measurements of the electrical characteristics. As far as it goes, Equation 1 and Equation 2 may be substituted by other models regarding the relation between the same parameters, or by models regarding the relation between e.g. the conductivities of the individual phases and the fraction ratios. Thus, in the last mentioned case, the conductivity will represent the measured electrical characteristics.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS In the calculations referred to above, one further equation is necessary to determine the fractions, and in this invention a differential pressure measurement is used to solve this problem. The sensor body 1 will namely cause a pressure drop, ΔP, when the flow passes through the narrowed area 10 in the annular space between the sensor body 1 and the pipe wall 11. This differential pressure is measured by means of a suitable differential pressure gauge 18, between a position 19 upstream in relation to the sensor body 1, and a position 20 along the cylindrical part 3 of the sensor body 1, in the measuring section. Of course, this differential pressure can be measured in a similar manner also between a position at the cylindrical part of the sensor body 1, and a position downstream from the same sensor body 1. By means of per se known, physical relations, one can use the differential pressure for determining the total mass flow rate, Q, in the pipe. Such a general physical relation is given in Equation 5 below:
Q=εEC D A 2 M{square root over (2�ρ�ΔP)} Equation 5 wherein: E = 1 1 - β 4 ɛ = f  ( Δ   P P , γ , β ) β = 1 - d 2 D 2 A 2 M = π 4  ( D 2 - d 2 ) CD is the �discharge coefficient�
γ is �specific heat ratio�
It has been shown (eg. in Hammer, E. A., Nordtvedt, J. E.: �Scientific/Technical Report No. 239: MULTIPHASE FLOW MEASUREMENT USING A VENTURIMETER�, University of Bergen, November 1990) that in connection with a liquid/gas flow, one may use the following expression for the volume flow rate of the liquid phase, assuming low pressure so that gas mass density can be disregarded: q liq = ɛ   EC D  A 2 M  2  ( 1 - φ gas )  Δ   P ρ liq Equation   6. By utilizing the obvious relation in Equation 7:
q liq=νliqφliqÅ=νliq(1−φgas)Å Equation 7. and combine this with Equation 6 hereabove, the result is: 1 - φ gas = 2  ( ɛ   EC D  A 2 M ) 2  Δ   P ρ liq  v liq 2  A 2 Equation   8. From Equation 8 one can see that the gas fraction, φgas, is directly dependent upon the mass density of the mixture, pliq, the liquid velocity, vliq, and the pipe cross section area, A, as well as the measured differential pressure, ΔP. There exists also a known relation for the mass density of the fluid, where the mass densities of the individual phases are presumed known:
ρmix=φgasρgas+φoilρoil+φwatρwat≈φoilρoil+φwatρwat=ρliq�(1−φgas), Equation 9. while in general the following holds true: ρ liq = φ wat φ wat + φ oil � ρ wat + φ oil φ wat + φ oil � ρ oil For relatively low pressures, the gas density will be negligible in relation to the densities of the liquids, and the density of the mixture will be approximately the same as the liquid density, as appears from Equation 9 hereabove. At higher pressures, this is not necessarily the case, and then this must be taken into consideration, and the equations must be amended correspondingly.
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G01F1/712Cooperative ClassificationG01F1/363, G01F1/74, G01F1/712, G01N33/2823European ClassificationG01N33/28E, G01F1/712, G01F1/36A, G01F1/74Legal EventsDateCodeEventDescriptionMay 12, 2011FPAYFee paymentYear of fee payment: 8May 31, 2007FPAYFee paymentYear of fee payment: 4Dec 15, 2005ASAssignmentOwner name: SHELL TECHNOLOGY VENTURES BV, NETHERLANDSFree format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:FLOWSYS AS;REEL/FRAME:016891/0956Effective date: 20051110Oct 9, 2001ASAssignmentOwner name: FLOWSYS AS, NORWAYFree format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:ASPELUND, AUDUN;WIDEROE, TOR;REEL/FRAME:012247/0090;SIGNING DATES FROM 20010920 TO 20010923Owner name: FLOWSYS AS SANDSLIMARKA 251BERGEN, (1)N-586 /AEFree format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:ASPELUND, AUDUN /AR;REEL/FRAME:012247/0090;SIGNING DATESFROM 20010920 TO 20010923RotateOriginal ImageGoogle Home - Sitemap - USPTO Bulk Downloads - Privacy Policy - Terms of Service - About Google Patents 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