Multiphase flow meter using multiple pressure differentials

(54) Title: MULTIPhasic FLOWOMETER, AND METHOD OF MEASURING THE FLOW OF COMPONENTS OF A MULTIPHASE FLUID (73) Holder: BAKER HUGHES INCORPORATED, North American Society. Address: 2929 Allen Parkway, Suite 2100, Houston, TX 77019, UNITED STATES OF AMERICA (US) (72) Inventor: ANDREW RICHARDS

Validity Term: 10 (ten) years from 03/04/2018, observing the legal conditions

Issued on: 03/04/2018

Digitally signed by:

Júlio César Castelo Branco Reis Moreira

Patent Director

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MULTIPHASE FLOWOMETER AND METHOD OF MEASURING THE FLOW OF COMPONENTS OF A MULTIPHASE FLUID.

[001] The present invention relates to apparatus and method for measuring the flow of a multiphase fluid. The invention is particularly suitable, but not exclusively, for measuring the flow of multiphase fluids produced by oil and gas wells.

[002] Multiphase measurement systems are widely used in the oil and gas and petrochemical industries. In the oil and gas industry, it is necessary to measure oil, gas and water flows, all of which are produced from the underground reservoir to the surface, via production wells drilled on the ground.

[003] There are numerous systems available to do this, but few of them are compact enough, or can be built in-line, to allow them to be used inside a drilled well as well as on the surface.

[004] It is known that the measurement of bi-phase hydrocarbon / water flow is obtained by the use of a device for determining the volume fraction in addition to a venturi. The fraction measurement device for hydrocarbon / water normally, but not always, takes advantage of differing electromagnetic properties of the two phases to determine the volumetric phase fractions. Existing water fraction meters inside the borehole allow measurement of two-phase fractions (oil-water or gas-water) over the entire 0 - 1 water fraction range - for example, MF1 Roxar water cut-off meter (Roxar, Norway), Fluenta MPFM 1900 (Fluenta, Norway). It is also known that it is possible to measure the gas fraction, otherwise known as the void fraction, by using radioactive density measurement devices.

[005] By using the two techniques above together with flow measurements derived from the cross correlation of sensor data

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2/13 spatially separated along flow paths, it is possible to build a system that measures three-phase flow.

[006] However, the use of radioactive sources has two main disadvantages. First, the sources require careful and substantial packaging to mitigate the health and safety implications of using such sources, and secondly, the use of such sources currently installed in oil and gas wells is not yet accepted in practice by the entire industry. of oil and gas.

[007] An objective of the present invention is to provide an improved apparatus and method for measuring flow and multiphase fluids, particularly from production wells.

[008] The present invention solves the problems associated with such radioactive sources by eliminating the need for such sources to measure the gas fraction, taking advantage of the high compressibility of the gas phase, as disclosed in US patent 4,168,624.

[009] According to a first aspect of the present invention, a multiphase flow meter is provided to measure the flow of a multiphase fluid flowing through a conduit, said flow meter comprising:

a first pressure measurement means arranged in said conduit at a first location for measuring a first pressure differential at said first location;

a second pressure measurement means arranged in said conduit at a second location spaced along said conduit of said first pressure measurement means for measuring a second pressure differential at said location;

means of creating a pressure drop to create a measurable pressure drop, in use, between the aforementioned first and second locations, and

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3/13 a means of measuring the fraction of water to measure the fraction of water in said multiphase fluid, said fraction meter of water being located upstream of said first location or downstream of said second location. [0010] Preferably, the first and second mentioned means of measurement are venturi flow meters. Alternatively, the aforementioned first and second pressure measurement means are chokes with at least two absolute pressure transducers for measuring the differential pressure in the choke or each having a differential pressure measuring device.

[0011] Preferably, the aforementioned means of creating a pressure drop is a third venturi disposed in said conduit in a third location between said first location and said second location. Preferably, also, the second and third venturis are combined in a double venturi.

[0012] Alternatively, the aforementioned means of creating pressure drop is a choke.

[0013] In an additional alternative arrangement, the means of creating a pressure drop is an extension of the duct providing a frictional pressure drop or, if the duct is inclined in relation to the horizontal, an additional pressure drop due to the height of gravity.

[0014] Preferably, said water fraction measurement means has a capacitance sensor to calculate a water fraction of a continuous oil fluid flowing in said conduit and a conductance sensor to calculate the conductivity of a water fluid flowing in the aforementioned conduit.

[0015] Alternatively, the aforementioned means of measuring the fraction of water includes a microwave generator and detector to detect the fraction of fluid water flowing in said conduit.

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4/13 [0016] Preferably, the first and second venturi, the pressure drop creating means and the water fraction measurement means are arranged on a plurality of tubular members.

[0017] In accordance with a further aspect of the present invention, a method of measuring the flow rate of components of a multiphase fluid flowing in a conduit is provided, said method comprising the steps of:

measuring a first pressure differential in the said conduit at a first location;

measuring a second pressure differential in said conduit at a second location spaced from the first location;

create a pressure drop in the mentioned multiphase fluid, between the mentioned first and second locations and measure the pressure drop;

measure the fraction of water in said multiphase fluid upstream of said first location or downstream of said second location, and process the first and second pressure differences, pressure drop and water fraction measurements to provide a mass flow and a volume flow for each component of said multiphase fluid at temperature and flow pressure.

[0018] Preferably, the method includes the step of measuring the water fraction upstream of the first location.

[0019] These and other aspects of the invention will be apparent from the following description, when considered in combination with the accompanying drawings, in which:

Fig. 1 is a diagrammatic view of a conventional venturi meter for measuring the mass flow rate in a conduit;

Fig. 2 is a diagrammatic view of a multifaceted flowmeter 870170053334, from 27/07/2017, p. 7/22

5/13 physical according to a first embodiment of the present invention;

Fig. 3 is a diagrammatic view of a flow meter according to a second embodiment of the present invention; and Fig. 4 is a diagrammatic view of a multiphase flow meter according to a third embodiment of the present invention.

[0020] Reference will now be made to Fig. 1 of the drawings, which illustrates a conventional venturi meter 10 that measures the mass flow rate in a conduit 12 by measuring the pressure drop ΔΡ caused by the restriction choke 14. When fluid fractions are known, together with fluid densities, in pressure and temperature of fluid flow in situ Pi, T |, then both individual mass and volumetric flow rates can be determined, as is well known in the technique and as revealed in Flow Measurement Engineering Handbook, RW McGraw-Hiil 1996; Venturi Meters in Multiphase Flow, National Engineering Laboratory (UK), Report No. 286/99, 1999.

[0021] Reference is now made to the embodiment shown in Fig. 2 of the drawings, which illustrates a multiphase flow meter according to the first and preferred embodiment of the present invention. It should be noted that the multiphase flow meter, generally indicated by reference number 20, is arranged in a single conduit 22 along which the fluid flows in the direction of arrow A. The end of the conduit 22a is the upstream end and 22b is the downstream end. [0022] The multiphase flowmeter 20 consists of a water fraction meter 23, a first venturi 24 disposed in a first location downstream of the water fraction meter, and a second venturi 26 spaced along the conduit 22 of venturi 24. The second venturi 26 is a double venturi. A first portion of venturi 26a is

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6/13 used to generate a pressure loss and a second portion of the venturi 26b, with a narrower choke, is used to measure a pressure differential for use in multiphase flow calculations, as will be described later. By arranging these components in a single duct 20, a compact flowmeter structure is provided without any moving parts.

[0023] In the flow meter shown in Fig. 2, the diameter of the duct 20 is known and the venturi 24 has a first throat restriction di, so that a pressure differential ΔΡ! be measured in the venturi

24. Similarly, in venturi 26, the pressure differential ΔΡ₂ is measured between venturi D2 throat restriction 26a and d throat₂ venturi 26b. In addition, a pressure differential ΔΡ is measured at venturi 26a, between the diameter Ü! and the diameter D₂ venturi 26a. In addition, the absolute pressure and temperature of the fluid are measured upstream of the venturi 24, at location 27.

[0024] The following fluid parameters are defined for use in the following equations in venturi 24 (location 1) and venturi 26 (location 2):

M1 = Total mass / s in (1)

M_Oi = mass / s oil in (1)

M_G1 = mass / s gas in (1)

M_W1 = mass / s water in (1) p_Oi = density of oil in (1) p_Gi = density of gas in (1) pwi = density of water in (1) V_Oi = volume / s of oil in (1) V_W1 = volume / s of water in (1)

M2 = Total mass / s in (2)

M₀2 = mass / s oil in (2)

M_G2 = mass / s gas in (2)

M_W2 = mass / s water in (2)

Ρ02 = oil density in (2) p_G2 = density of gas in (2) Pw2 = density of water in (2) V₀2 = volume / s of oil in (2) V_W2 = volume / s of water in (2) V_G2 = volume / s of gas in (2)

V_G1 = volume / s of gas in (1)

PiU is the pressure, temperature upstream of the venturi 24. P₂T₂is the pressure, temperature upstream of the venturi 26.

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ΔΡ is the pressure differential between the mounting leads of the venturi 24, 26b.

ΔΡ-ι is the pressure loss in the venturi 24.

ΔΡ₂ is the pressure loss in the venturi 26.

Mass / second at point (1) = Mass / second at point (2) = _C, C_D1d „C, C„, d²

<img file="BRPI0115744B1_D0001.tif" />

For mass conservation: Mi = M₂ (mass / second) ^ç‘^CDld/ 7Ãy = yy ^Çi^ÇD2^dl [0025] Ci is a constant and assuming the gas volume has a relatively small change from point (1) to point (2),

Ci Cdi ⁼ Ci Cd2 and thus:

<img file="BRPI0115744B1_D0002.tif" />

<img file="BRPI0115744B1_D0003.tif" />

Pl ^ P₂

<img file="BRPI0115744B1_D0004.tif" />

<img file="BRPI0115744B1_D0005.tif" />

= δ_χ both are known and are functions of the geometry of the two venturi at locations (1) and (2). So:

διΡιΔΡ · ι = δ₂ρ₂ΔΡ₂

Pl _

Pi (1)

Μ · | ⁼ ΜΟι + MWi + Mgi Μ2 ⁼ Mq2 + Mw2 Mq₂

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Vi - Vqi + Vwi ⁺ VG1 V2 - Vq2 + Vw2 ⁺ VG2 (1a)

Replacing (1a) in (1) produces:

<img file="BRPI0115744B1_D0006.tif" />

[0026] V₂ and Vi are both unknown. However, V₂ can be expressed as a function of V_1; provided that pressure, volume and temperature (PVT) relationships of gas and oil are known. Water is assumed to remain unchanged from location 1 to location 2.

Thus:

V02 = Vqi - [(ξ) ϋΡ * V_Oi] (3) where (ξ) ϋρθ the volumetric shrinkage coefficient of the oil when the oil gas is released from the high pressure point (1) to the low pressure point (2), and

Vq2 ^_ [Vqi * Cq X ΔΡ] + [ARg * Vqi] (4)

THE_LOL is the volume of gas released per unit of oil volume in P-iT-i under pressure ΔΡ, where: V_q1 * Ç_q * ΔΡ is the volume expansion from point 1 to point 2e

AIR_s * V_Oi * Eq is the volume of gas released from the oil when the pressure declines from point (1) to point (2);

thus, replacing (3) and (4) with (2) and expanding, we have:

<img file="BRPI0115744B1_D0007.tif" />

V ^rWl (5) [0027] ΔΡ, ΔΡ₂ and APi are measured by venturi 24, 26 and absolute pressure sensors 28a, 28b. ξ, R_s, Ç_g and is_q are derived from compoPetição 870170053334, of 07/27/2017, p. 11/22

9/13 chemical composition, via state equation calculations, or are measured using representative oil and gas samples.

This leaves unknown quantities -

<img file="BRPI0115744B1_D0008.tif" />

fractions of volume of water at location (1) fractions of volume of gas at location (1) is effectively measured by the water fraction meter 23 placed in line with the double venturi mechanism.

[0028] It should be understood that the calculation of water fraction requires two sensors 30a, 30b. A sensor 30a measures the effective permissiveness when the oil or gas forms a continuous phase, that is, the bulk of the fluid mixture is insulating. A second sensor 20b measures the effective resistivity when the water forms a continuous phase and the mixture is conductive.

[0029] Firstly, considering the use of the multiphase flow meter when receiving a continuous hydrocarbon that is electrically isolated, it should be understood that oil and gas have similar relative permissivities (and_R) that differ greatly from the permissiveness of saline water produced by the well. Typical values ​​are:

and_R gas ~ 1.7 - 2.0 and_R of oil ~ 2.5 and_R of water ~ 100 [0030] The calculations below equation 5 are then made, and in the first interaction, the water volume fraction is calculated from the water fraction meter using the capacitance sensor. Assuming that no gas is present, then, the permittivity of the hydrocarbon is equal to the permittivity of the oil. The volume fraction of gas, for example,

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-2- is then calculated from equation 5 using the first value of the fraction of v

water volume assuming and_R = e_R for the first interaction.

[0031] Fractions of water volume and gas fractions are estimated, y

allowing fractions of oil volume to be calculated.

[0032] Once this is done, the relative relative permissiveness of the hydrocarbon component is recalculated, taking into account that it is not 100% oil and_R hydrocarbon (iteration 2) =

VV,

ò) leo + ^and *and_R gas r, f,

Λ V Λ 1 ^r wi lv J [0033] This new value of e_R of hydrocarbon is inserted in the calculation of water volume fraction, allowing a second set of volume fractions to be calculated. This iteration process is repeated until the result of iteration n is different from the result of iteration n-1 by less than 0.5%.

[0034] In the situation where the multiphase fluid flowing through the conduit is continuous water, that is, it is conductive, there is no need to iterate this y

[0035] Calculation and the value of is obtained from the water fraction meter and can be [0036] directly applied to equation 5 to give the gas volume fraction; thus, the fraction of oil volume can be calculated 870170053334, from 07/27/2017, p. 13/22

11/13.

[0037] Because the three-phase volume fractions at location 1a are known, and the phase densities in the pressure, volume and temperature measurements are known from PVT, then the total density of flowing fluid is known. The following conventional venturi equations are then used to calculate the total mass through the venturi located at location 1, as is well known to someone skilled in the art. This allows the calculation of mass flow rates and volume in the in situ pressure and temperature values ​​Ρ_Ί and T_1;as follows:

in location 1, the fluid density is given by: pfluid,

1 = - * Pw, + ^ p_m + ^ p₀, v_x v_x v_x and the total volume flowing at location 1 is given by:

^Cj Ç_D2 fluid, 1 * AfJ ivi (Total) p fluid, 1 discharge coefficient C_D in the multiphase flow can be derived from the National Engineering Laboratory report mentioned above. Therefore, the volumetric flow rates for water, oil and gas are:

V_w1 = qV-ι (Total) *

V

V_Oi = qV-ι (Total) *

V

V_Gi = qV-ι (Total) *

V [0038] Reference is now made to Fig. 3 of the drawings which illustrates a multiphase flow meter according to an alternative embodiment of the invention. In this embodiment, the flow meter comprises a water fraction meter 40 upstream of a first

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12/13 venturi 42. A second downstream venturi 44 spaced from the first venturi and between the venturi 42, 44 is a pressure drop device or choke 46. The same calculations applied to the first embodiment can similarly be applied here to provide the same results.

[0039] Reference is now made to Fig. 4 of the drawings, which illustrates a further alternative embodiment of the present invention. This embodiment is substantially identical to the embodiment shown in Fig. 2, except that the water fraction meter 23 is arranged downstream of the venturi 26. The same flow calculations apply, but this arrangement is not preferred due to the gas in the multiphase fluid has expanded due to some pressure loss in the system.

[0040] Various modifications can be made to the flow meters described here without departing from the scope of the invention. Although all flow meters are shown as compact structures in a single duct, it should be appreciated by someone skilled in the art that the components could be arranged between widely spaced ducts, for example, the venturi could be arranged in different tubular elements many meters or even hundreds of meters apart. The pressure drop device does not have to be a specific flow restriction component, but it could be based on the distance between the venturi, thus using the friction and gravity pressure drop inside the tube.

[0041] The present invention has the main advantage that radioactive measurement techniques are not used and the system is flexible enough to be installed in a single conduit or as components dispersed throughout a well. An additional advantage is the fact that no moving parts are necessary and the system takes advantage of some of the features and sensors used in the measurement devices 870170053334, from 07/27/2017, p. 15/22

13/13 addition of two phases in wells and extend these, through the knowledge of phase or phase behavior, to three-phase fluid systems that have so far not been achieved.

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