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    • 专利摘要:
    MULTIPHASE METER TO PROVIDE DATA FOR PRODUCTION MANAGEMENT. The present invention relates to a method and apparatus for determining a one-phase volume of a multiphase fluid flowing in a production tube. A magnetic field is given over the fluid to align the nuclei of the multiphase fluid along a direction of the magnetic field. A radio frequency signal is transmitted to the multiphase fluid to excite the nuclei, and a signal is detected from the nuclei responsive to the transmitted radio frequency signal. An amplitude of the detected signal is determined and the volume of the phase flowing in the production tube is determined using the determined amplitude and an amplitude of a calibration signal.
    公开号:BR112013020868B1
    申请号:R112013020868-6
    申请日:2012-01-18
    公开日:2021-03-02
    发明作者:Joo Tim Ong；Songhua Chen；Terry R. Bussear
    申请人:Baker Hughes Incorporated；
    IPC主号:
    专利说明:

    CROSS REFERENCE OF RELATED ORDERS
    [001] This application claims the benefit of U.S. Patent No. 13/028553, filed on February 16, 2011, which is incorporated here by reference in its entirety. BACKGROUND OF THE DESCRIPTION 1. Description field
    [002] The present description generally refers to a measuring device and methods for estimating downhole fluid characteristics. 2. Description of the Related Art
    [003] In the oil and gas industry, it is becoming increasingly important to obtain measurements of the flow rate and phase ratio of multiphase fluids such as those produced by drilling operations and downhole fluid compositions.
    [004] To measure the flow rate and ratio properties of these multiphase fluids precisely to satisfy the requirements of the operator, it is currently known to use techniques such as Nuclear Magnetic Measurement (NMR) and Electronic Spin Resonance (ESR) analyzes. However, the systems currently available to measure these properties using these techniques require a number of separate components that employ a variety of operational and analytical techniques and generally involve a number of distinct devices adapted to measure a particular fluid flow property. For example, a device for detecting the fraction of a phase can be provided together with a device for detecting the fraction of another phase and another device for measuring the total flow rate. Also, these techniques are generally not used for compositional analyzes of hydrocarbons in downhole fluids. DESCRIPTION SUMMARY
    [005] In one aspect, the present description provides a method for determining a phase volume of a multiphase fluid flowing in a tube, including: imparting a magnetic field over the fluid to align the nuclei of the multiphase fluid over a magnetic field direction; transmitting a radio frequency signal to the multiphase fluid to excite the nuclei; detecting a signal from the cores responsive to the transmitted radio frequency signal; determine an amplitude of the detected signal; and determining the volume of the phase flowing in the tube using the determined amplitude and an amplitude of a calibration signal.
    [006] In another aspect, the present description provides an apparatus for determining a phase volume of a multiphase fluid flowing in a tube, the apparatus includes a source configured to impart a primary magnetic field in the fluid to align the nuclei of the multiphase fluid along a direction of the primary magnetic field; a source configured to transmit a radio frequency signal in the multiphase fluid to excite the cores; a detector for detecting a signal from the cores responsive to the transmitted radio frequency signal; and a processor configured to determine an amplitude of the detected signal and the volume of the phase flowing in the tube using the determined amplitude of the detected signals and an amplitude of a calibration signal.
    [007] In yet another aspect, the present description provides a method of determining the stability of an emulsion flowing in a production column, the method including providing a primary magnetic field in the emulsion to align the emulsion cores along a direction of the primary magnetic field; transmit a radio frequency signal in the emulsion flowing in the production column; detecting a signal from the emulsion cores responsive to the transmitted radio frequency signal; determine an amplitude of the detected signal; determining a fraction of water in the emulsion using the obtained amplitude; determining a relaxation rate of a signal obtained from nuclei of the emulsion excited in response to the transmitted radio frequency signal; obtain an emulsion viscosity from the determined relaxation time; and determining the stability of the emulsion from the determined emulsion viscosity and the water fraction of the emulsion.
    [008] Examples of the most important characteristics of the methods and devices for analyzing the composition of a hydrocarbon have been summarized so that the detailed description below can be better understood and so that the contributions they represent to the technique can be evaluated. Of course, there are additional features of the methods and apparatus that are described below and that will form the subject of any claims that may be in accordance with that description. BRIEF DESCRIPTION OF THE DRAWINGS
    [009] For a detailed understanding of the apparatus and methods for compositional analysis of hydrocarbons in a downhole fluid, reference should be made to the following detailed description, carried out in conjunction with the attached drawings, in which similar elements are generally designated by similar numerical references, and where:
    [0010] FIG. 1 is a cross-sectional side view of an embodiment of the apparatus according to the present description;
    [0011] FIG. 1a is a cross-sectional side view of the apparatus of FIG. 1 showing magnetic gradient coils that act in the direction of the geometric axis z with respect to the reference axes indicated in FIG. 1;
    [0012] FIG. 2 is a cross-sectional side view of the apparatus of FIG. 1 showing the magnetic gradient coils acting in the direction of the y-axis in relation to the reference axes indicated in FIG. 1;
    [0013] FIG. 3 is a cross-sectional view of the apparatus of FIG. 1 showing the components of the magnetic gradient coils acting in the x, y and z directions with respect to the reference axes indicated in FIG. 1;
    [0014] FIG. 4 is a schematic view of the component of the gradient nozzles acting in the direction of the geometric axis z with respect to the reference axes of FIG. 1, arranged around the combined transmission and reception coils according to a particular embodiment of the description;
    [0015] FIG. 5 is a schematic view of the gradient coils acting in the direction of the y-axis in relation to the reference axes of FIG. 1, arranged around the combined transmission and reception coils according to an embodiment of the present description;
    [0016] FIG. 6 is an illustration of a magnetic field orientation for producing the homogeneous magnet used in accordance with the present description;
    [0017] FIG. 7a is a schematic circuit diagram showing the interaction between the various components of the reception circuit of the combined transmission and reception coils;
    [0018] FIG. 7b is a schematic circuit diagram showing the interaction between the various components of the transmission circuit of the combined transmission and reception coils;
    [0019] FIG. 8 is a schematic cross-sectional diagram of the primary magnet composition used in accordance with the present description;
    [0020] FIG. 9 is a cross-sectional side view of another embodiment of the apparatus according to the present invention without the gradient and transmission coils shown;
    [0021] FIG. 10 is a schematic perspective view of the magnet configuration used in the apparatus of FIG. 9;
    [0022] FIG. 11 is a cross-sectional side view of the apparatus of FIG. 9 showing the gradient and transmission coils;
    [0023] FIG. 12 is a schematic view of the component of the gradient nozzles of FIG. 10 acting in the direction of the geometric axis z;
    [0024] FIG. 13 is a schematic view of the component of the gradient nozzles of FIG. 10 that act in the directions of geometric axis x and y;
    [0025] FIG. 14 is a functional diagram of a circuit for performing the compositional analysis of hydrocarbons according to one embodiment of the description;
    [0026] FIG. 15 is a visual representation of the relationship between some types of hydrocarbon and the frequency deviation (also referred to as chemical deviation) between a radio frequency signal conferred in a fluid and a radio frequency signal detected from the fluid; and
    [0027] FIG. 16 is a frequency shift spectrum for some types of hydrocarbons. DETAILED DESCRIPTION OF THE REVELATION
    [0028] With reference to FIG. 1, the apparatus 10 according to the first embodiment of the present invention comprises an external housing 12 which surrounds a section of a fluid flow tube 14, as a production pipe, by locking through a suitable locking mechanism. Inside the housing 12 is located a permanent permanent magnet 16 in an outer recess 18 and a secondary electromagnet housing 20 located in a more internal recess 22. The electromagnet housing 20 has an electromagnet 21 located inside it that comprises coils of electromagnet Gx, Gy and (as shown in FIG. 1a) Gz. The combined transmission and reception coils 24 are also supplied within the inner diameter of the electromagnet housing 20.
    [0029] The outer housing 12 provides magnetic shielding that substantially minimizes the leakage of magnetic field outside the apparatus 10, and provides safe tool manipulation. This also improves the signal transmission and reception performance of the coils 24 by minimizing interference from surrounding radio signals such as FM radio signals. The housing 12, in this modality, comprises low permeability iron (typically μr <1.00) that supplies the main external body of the device. The material is typically about 10 mm thick around the middle portion of the apparatus 10 and thicker towards the ends of the apparatus 10, typically to a thickness of about 60 mm. The skilled reader will find that a different thickness and material can be used in housing 12 to adapt to the particular application.
    [0030] With particular reference to FIGS. 6 and 8, the primary permanent magnet 16 comprises numerous concentric arranged magnetic cells 26 which are stacked. Each magnetic cell 26 comprises numerous outer segments 28 (FIG. 8) arranged adjacent to numerous inner segments 30 so that a circumferential band of inner segments 30 is disposed within a circumferential band of outer segments 28. Flat plates 32 are positioned between the circumferential strip of outer segments 28 and the circumferential strip of inner segments 30 so that a circumferential strip of plates 32 is located between outer segments 28 and inner segments 30. The plates 32 are typically formed of an iron-based material that has a permeability greater than 1000.
    [0031] Aperture 34 is provided in the center of each cell 26 to allow fluid to flow through it as will be discussed subsequently. When cells 28 are stacked, they form a through hole 36 (as shown in FIG. 6) along the length of the magnet 16. The iron plates 32 ensure that the resulting magnetic field produced by inner segments 30 and outer segments 28 is concentrated towards the center of the opening 34 of each cell and then along the through hole 36 of the apparatus 10.
    [0032] The versed reader will understand that the term, permanent magnet, in this context is defined as a magnet that provides a constant magnetic field without requiring, for example, an electric current to create the magnetic field. In an alternative embodiment, the permanent magnet can be an electromagnet that provides a continuous and substantially homogeneous magnetic field.
    [0033] The direction of the magnetic field vectors (indicated by MF in FIG. 6) of each outer segment 28 and inner segment 30 is carefully arranged during manufacture to create a resulting magnetic field for magnet 16 that is as close as possible to be homogeneous throughout the through hole of the magnet 16. This ensures that the magnetic field present within the through hole 36 of the magnet 16 remains compatible with the through hole 36 regardless of the location within the through hole 36 that the magnetic field is experienced. Typically, the required homogeneity is about 1.0 ppm. This ensures that accurate measurements are possible using the apparatus 10 in conjunction with the NMR techniques as will be subsequently discussed.
    [0034] The secondary electromagnet housing 20 is provided with a combined transmission and reception coil 24 that is capable of transmitting a radio frequency pulse and detecting the radio frequency emitted by the cores excited by that radio frequency pulse. In the embodiment shown in FIGS., Coil 24 comprises a pair of circular circuits 24a at the top and bottom of coil 24 connected by circumferentially spaced connecting coils 24b to form a "cage" configuration. This provides the apparatus 10 with the ability to transmit a radio frequency pulse equally across the through hole 36 and competently detect the radio frequency signal emitted by the cores anywhere within the through hole 36 of the apparatus 10. Instead of a "cage" configuration, the coils can alternatively be arranged to provide a "saddle coil" configuration depending on the application.
    [0035] With reference to FIG. 7a, the receiving circuit 40 of the combined transmit and receive coils 24 comprises a reference input signal generator 42 and a 90 ° phase switch 44 connected to a standard amplification and filtering system 46 to provide an output signal real and imaginary as a result of the signal received from the coil 24. With reference to FIG. 7b, the transmitting circuit 48 of the combined transmit and receive coils 24 comprises a signal generator input module 50 and an oscillator 52 which are connected to an amplifier 54 and a pulse programmer 56 to transmit the required radio frequency through coil 24. Although separately illustrated in FIGS. 7a and 7b, it will be understood that these circuits can be combined or integrated to provide the required transmission and reception capacity of combined transmission and reception coils 24.
    [0036] The secondary electromagnet housing 20 provides the magnetic gradient using the coils Gx, Gy, and Gz which selectively (depending on whether the electromagnet is on or off) provide a graduated magnetic field inside the through hole 36 of the device in the directions x, y, and z respectively indicated by the reference axes R in FIG. 1. This arrangement provides the graduated magnetic field required by the flow rate calculation process described below.
    [0037] The profile of the primary permanent magnet 16 and the secondary electromagnet 20 is arranged in the present modality, so that they can be housed inside the outermost recess 18 and the innermost recess 22 respectively to maintain a consistent diameter of through hole 36 through the apparatus 10 so that disturbance of the fluid flowing from the tube 14 through the apparatus 10 is minimized.
    [0038] A second embodiment of the present invention that has numerous modifications will now be described. Many components of the second modality are the same as those described in relation to the first modality. These components will no longer be described. In addition, numerous components in the second modality correspond to similar components previously described in relation to the first modality, and where applicable, similar numerical references will be used.
    [0039] With reference to FIGS. 9 to 13, the apparatus 100 according to the second embodiment of the present invention comprises an outer housing 120 surrounding a primary magnet 160. Primary magnet 160 has an inner ring 160A and an outer ring 160B. A secondary electromagnet is provided in housing 215 as subsequently discussed. The transmission / receiving coil housing 205 is provided in the inner hole of the apparatus 100. The housing 205 can be made of a material such as Poly-Ether-Ether-Ketone (PEEK) or a nickel alloy such as Inconel®. The required pressure rating using (PEEK) is generally performed using a housing 205 that has a very thick wall (about 20 mm). This wall generally degrades the resistance of the magnetic field in the center of the flow path as the magnet resistance decreases with the radial distance of the magnet. The thickness required using Inconel.RTM. is much smaller (more or less 7 mm). In addition, the use of Inconel® (which has permeability comparable to free space (μr = 1)), concentrates the magnetic field in the flow path, thus increasing the homogeneity of magnetic resistance.
    [0040] Housing 205 in this mode is provided with recessed tracks (not shown) that are machined on the outer surface of housing 205 during manufacture. Additional shapes can also be machined on the outer surface to accommodate components such as the transmit and receive coil capacitors used in the transmit and receive circuit. Electrical insulation (not shown) as an adhesive insulation is also provided between the transmission / reception coil and housing 205.
    [0041] In addition, in contrast, with the first modality, the apparatus 100 has coils of gradient Gx, Gy, Gz mounted on the pipe 215 between the portions of primary magnet 160A and 160B. This separates the magnets 160A and 160B from each other increasing the combined efficiency of the magnets to produce a homogeneous, high strength magnetic field in the flow path. Piping 215 also provides mechanical support to retain the primary magnet and provide support against pressure exerted from the flow. In the present embodiment, pipe 215 is made of high-permeability iron and is dodecagonal in shape (as shown in FIG. 10). A pair of 215A axial end elements is also provided to provide a magnetically permeable trajectory for the magnetic field.
    [0042] As seen in FIG. 12, piping 215 houses the axial gradient coil along the flow path (Gz) on the inner surface and the orthogonal gradients (Gx and Gy) on the outer surface (see FIG. 13). Again, these coils are supplied on the lowered tracks in the pipe 215 and are isolated from the pipe itself using adhesive insulation. Gradient coils are capable of imparting a variable magnetic field as subsequently discussed and, in this respect, can be considered as an electromagnet.
    [0043] Piping 215 is provided with a tubular inner diameter to provide minimal friction losses to the fluid passing through it, and a dodecagonal outer surface that allows the tubing to fit within the magnet rings.
    [0044] In use, each modality of apparatus 10 operates in an identical manner using Nuclear Magnetic Resonance (NMR) techniques to determine the volume fraction of multiphase flow produced from a well bore. In addition to determining the fraction of each phase present in the flow, the invention can also be used to determine the rate of fluid flowing from the well bore. The described modalities determine the phase fraction of fluid that contains oily, gaseous and aqueous phases; however, it will be understood by the converse reader that additional and / or different phases can be determined using the apparatus and method described.
    [0045] For clarity purposes, the phase fraction analysis process will be first described followed by a description of the flow measurement process; however, both processes can be effectively performed simultaneously when configuring the control system of the device 10 to quickly switch between the fraction analysis mode and the flow measurement mode. This switching between modes is typically performed at a rate of approximately one second for each mode, that is, the control system will allow the fraction analysis mode to operate for one second and then allow the flow measurement mode operate for one second before switching back to fraction analysis mode and so on as required. The versed reader will notice that this time can be changed to adapt to the specific situation.
    [0046] The method of using the first modality of the device will be described in the following description; however, the versed reader will realize that each modality can be used.
    [0047] In the modality shown, the apparatus 10 is installed in line with a fluid flow tube 14. As the produced fluids flow into the apparatus 10, these enter the substantially homogeneous primary magnetic field generated by the primary magnet 16. The atomic nuclei that have a non-zero magnetic moment that are present in the fluids that flow through the apparatus 10 align with the geometric axis of the primary magnetic field. Fluids that have a nonzero magnetic moment include 1H, 13C, 31P and 15N. In this modality (and in many NMR applications in general) 1H is the most commonly measured among these, since it is naturally present in hydrocarbons such as those produced from well bores. The flow cores within the bore 36 of the apparatus 10 including water, oil and gas are now aligned with the direction of the primary magnetic field.
    [0048] A radio frequency (RF) pulse signal is now transmitted to the through hole 36 using the transmission circuit 48 of the combined transmission and reception coils 24. The frequency of the RF pulse will be transmitted at a frequency that is known to excite the 1H atomic nucleus (typically in the range 40-45 MHz) to a 1 Tesla static magnetic field so that it resonates at its natural resonant frequency (this is known as the Larmour frequency). This ensures that any nucleus 1H present in the fluid flowing through the through hole 26 will resonate in response to the RF pulse signal. The frequency (v) required to resonate the nuclei can be determined using the following equation:

    [0049] where .gama. is the gyromagnetic ratio of the nucleus and B is the magnetic field.
    [0050] Although resonant, the nucleus emits a radio signal at a frequency corresponding to its resonant frequency.
    [0051] The frequency at which the nuclei present in the flow of flow from the resonate after being excited by the RF pulse signal is detected by the receiving circuit 40 of the combined transmitter and receiver coils 24. In a mixture of phases as in the present modality, the resonance described provides molecular information such as the type of bond and the environment surrounding the nuclei. From this, the ratio of the signal that is received from the resonant cores to the base frequency of the RF pulse can be calculated. The knowledgeable reader will understand that this value is known as Chemical Deviation and is measured in parts per million ("ppm").
    [0052] The chemical deviation (δ) recorded by the device can now be used to determine the ratio of oil and gas (combined) to water using the following equation:

    [0053] In this respect, the separation between the phases is increased by ensuring that a satisfactory magnetic field homogeneity is provided by the primary permanent magnet 16 to produce a peak relaxation time graph with a small bandwidth.
    [0054] However, as previously presented, it is desired to measure the oil to gas ratio also to determine the oil, gas and water ratios in the multiphase fluid, without assuming the presence of other phases. In general, the chemical drift between the oil and gas cores is too small to measure precisely using the chemical drift method. Therefore, the present invention determines the oil-to-gas ratio by comparing the relaxation times T1 (subsequently described) for each hydrocarbon. This is possible since the relaxation times T1 of gaseous hydrocarbons are longer compared to the relaxation times T1 of liquid hydrocarbons.
    [0055] In addition to causing the nuclei of each phase to resonate, the energy provided by the RF pulse signal of the combined transmission and reception coil 24 causes the nuclei of each phase to be removed from their previous alignment with the primary magnetic field . After the RF signal is pulsed, the spins (nuclei that have been subjected to a magnetic field) will tend to relax again to their equilibrium state in which they are realigned along the primary magnetic field. The time it takes for the spins to relax again to their steady state after the RF signal is pulsed is known as the T1 relaxation time of the nuclei.
    [0056] It is possible to measure the relaxation times T1 of the oil and gas using the device 10 by monitoring the angle through which the nucleus of each phase of the flow is inclined in relation to the primary magnetic field at any given time (which must be shorter) relaxation time) after the RF signal is pulsed. This is done by measuring the time taken for the magnitude of the radio frequency received from the cores to reach a maximum value in the direction of the primary magnetic field and the time spent for a minimum value in the direction orthogonal to the direction of the primary magnetic field, which can be performed using the combined transmission and reception coils 24. This results in two distinct T1 relaxation times that are detectable; one for the oil phase and one for the gas phase. The proton density (PD) of each hydrocarbon phase is now calculated by integrating the area under each peak of the accumulated T1 relaxation time density. The graph is derived by applying an inverse algorithm to the measured relaxation time T1 extracted using an inversion recovery sequence. Using the proton density measurement, the volume fraction is now calculated using the following equation:

    [0057] where MWs is the molecular weight, ps is the sample density, Av is the number of Avogadro, PD is the proton density, α is the natural abundance of 1H and R1H is the number of 1H for 1 molecule of phase.
    [0058] The sequence applied here is such that the required measurement time is less than the transit time (T) of the flow. The method of determining the proton density is performed using a one-dimensional hydrogen nucleus sequence (1D-1H) in combination with an inversion recovery sequence for the T1 measurement and the Carr-Purcell-Meiboom-Gill (CPMG) sequence for T2 measurement.
    [0059] However, the one above simply returns the volume values of the relative phases and, as previously mentioned, not the phase fraction. To calculate the phase fraction, the following equation can be used:

    [0060] where n is the number of phases present in the sample.
    [0061] It should be noted that in a sample containing ape in both phases (a and b), the equation can be simplified to:

    [0062] Therefore, each fraction of oil, gas, and water was calculated using the device 10 without (as in some previous systems) the requirement to assume that once the ratios of two phases in the flow were calculated, the third constitutes the rest of the fluid.
    [0063] The method and apparatus for determining the fluid flow rate will now be described.
    [0064] Now that the ratio of each phase has been calculated, the relaxation time T1 for each phase is known. The modality shown is capable of employing two alternative methods to calculate the flow rate of each phase through the apparatus 10. The first method is based on the Flight Time (TOF) of the spins along the apparatus 10. In this method, a signal of pulse is applied in a 'portion' at a first location along the through hole 36 of the apparatus 10 to tilt the cores at that location. A detection area is then monitored downstream from where the pulse signal was applied. The resulting NMR signal received by the receiving circuit 40 of the combined transmission and detection coils 24 will now be increased by each fully tilted spin entering the detection area and will be reduced with each completely tilted spin exiting the detection area. Therefore, the total net signal can again be related to the phase flow through the device. This allows the flow velocity (v) to be calculated using the transit time (T) and the distance from the detection area (d) using the following equation:

    [0065] The second alternative method to measure the flow through the device 10 uses the graduated magnetic field provided by the secondary electromagnet 20. A gradient echo sequence is given over the flow so that the flow cores rotate around its axes. In a steady stream, this does not result in the accumulation of phase signals as the nuclei experience the same time-balanced gradient. However, in a dynamic flow, the magnetic field experienced by the cores will change as the cores flow along the through hole 36 of the device 10 due to the magnetic field gradient provided by the electromagnet 20. This variation of the magnetic field, dependent on the movement of the flow along the through hole 36 of the apparatus 10, results in an accumulation of phase signal. This is dependent on the speed of the flow through the device 10 and the resistance and duration of the magnetic field gradient provided by the electromagnet 20. The accumulation in phase (Φ) that can be directly correlated to the speed of the flow is determined by:

    [0066] where B0 is the magnetic field provided by the primary magnet, n represents the position of the spins within the through hole on each x, y, or z axis (as shown in FIG. 1) and Gn is the magnitude of the field gradient magnetic that is applied by the electromagnet 20 in the direction of geometric axis n.
    [0067] The previously described method allows the flow rate and proportion of each phase to be calculated using a single device 10. Furthermore, the described system and device do not require that the device users protect themselves against different operational risk levels than those normally expected in oil and gas exploration operations. Specifically, the apparatus and method described do not require the user to be protected against, for example, radiation and biological risks.
    [0068] In other aspects, the compositional analysis of hydrocarbons produced from the well bores can be provided using the radio frequency signals checked and detected. FIG. 14 shows a modality of an apparatus that can be used to estimate the types of hydrocarbon in downhole fluids. The apparatus of FIG. 14, in one aspect, may include a processor, such as a microprocessor or a computer 1410 and a data storage device 1420, which may be any suitable device, including, but not limited to, solid state memory, compact disk, hard drive, and tape. One or more programs, models and other data (collectively referred to as "programs" and designated by numeric reference 1430) can be stored on the data storage device 1420 or another suitable device accessible to the 1410 processor to execute the instructions contained in those programs . A display device 1440 can be provided for the 1410 processor to display information regarding compositional analysis, as described in more detail below.
    [0069] In one aspect, processor 1410 can compute the frequency difference or frequency deviation 1460 between the original checked or disturbing signal 1402 and the detected signal 1401. This phenomenon is also known as chemical deviation. In one aspect, the 1410 processor can estimate or determine the composition (types of hydrocarbons produced) using frequency or chemical deviation.
    [0070] FIG. 15 shows a 1500 ratio of the frequency or chemical shift and various types of a hydrocarbon. For example, a chemical shift between -2 to -1.0 parts per million (ppm) indicates the presence of alkane, a chemical shift between -7 to -5.5 ppm indicates the presence of Alkene, and a chemical shift between - 8.0 and -7.0 ppm indicates the presence of aromatic compounds. Aromatic compounds are compounds that have a benzene ring structure, such as toluene, benzene and zylene. The data shown in FIG. 15 can be stored on the data storage device 1420 for use by the processor 1410.
    [0071] FIG. 16 shows a chemical deviation curve or spectrum 1600 referring to the various types of a hydrocarbon produced from the well bores. In another aspect, processor 1410 can estimate a number of types in the 1600 spectrum. In one aspect, an area under the chemical shift curve 1600 can be integrated to estimate the number of hydrocarbon types. Therefore, the area under curve section 1610 will provide the amount or fraction of alkane in the fluid sample, while the area under section 1620 will provide the amount or fraction of aromatics in the fluid sample. The composition of the types can therefore be estimated as a relative value or as an absolute value.
    [0072] In another aspect, the 1430 programs may include instructions for the processor to determine the relaxation times and provide a detailed analysis of the types from them, such as a division of the types of alkanes. The relaxation time, as previously described, is the time it takes for the signal emitted by the nuclei to decay. There is a direct relationship between the density of the alkane (which is linked to the length of the carbon chain) and the relaxation time. The higher the alkane density, the longer the relaxation time.
    [0073] In another aspect, the compositional hydrocarbon analysis described here can be used to provide information for a PVT analysis of the hydrocarbon. From the estimated hydrocarbon composition, as described above, the total PVT properties of the hydrocarbon can be determined.
    [0074] In prior art, PVT hydrocarbon analysis is typically performed employing a sample of the well-bottom fluid at a known pressure and temperature and several tests are performed to determine the properties of the fluid, such as the boiling point and density and viscosity at varying temperatures and pressures. The division of the hydrocarbon into its core components is then carried out. The PVT properties of the core components are well known and can be reconstituted to provide a total hydrocarbon PVT property. A known reconstitution technique is used. For example, for gas hydrocarbons, gas chromatography can be performed to divide the gas into its individual components and based on this composition, a total gas property can be recalculated.
    [0075] The compositional analysis technique described here is contorted using a fluid sample and rigorous tests typically performed to determine the PVT properties of the hydrocarbon. In addition, in the present method, measurements are performed in real time (in-situ) as opposed to ‘sampling’ of the hydrocarbon.
    [0076] The dimensions of the device can be changed using the manufacturing stage depending on the conditions of downhole or particular submarines in which they will be used. In this respect, the space requirements of the components can be balanced based on the desired measurement accuracy, which may be relevant for the primary magnet 16 or the electromagnet 20. Additionally, the apparatus described above can be used in a borehole or aligned with any portion of the production piping. Alternatively, the device can be used off-site as an external measurement and analysis tool.
    [0077] In another aspect, the present description provides a method for determining volumes of liquid and gaseous phases of a multiphase fluid. The phase volume is determined for a multiphase fluid in a constant measurement volume, as in a volume of the NMR apparatus of FIG. 17. FIG. 17 shows an exemplary 1700 Nuclear Magnetic Resonance (NMR) flow meter device for estimating a volume of a fluid phase using the exemplary methods of the present description. In one embodiment, the fluid is a multiphase fluid. In another embodiment, the fluid is a fluid that flows in a production system or a tube for the transportation of hydrocarbons. The exemplary NMR flow meter 1700 includes a section 1710 for delivering NMR excitation pulses to the fluid and obtaining NMR signals in response to the fluid's NMR excitation pulses, and a 1726 test unit for receiving NMR response signals detection section 1710 and perform calculations on the NMR response signals received to obtain a phase volume.
    [0078] The device 1700 includes a magnet 1714 that can be outside the detection tube section 1712 to provide a static magnetic field in a volume of the detection tube section 1712, and a 1716 radio frequency (RF) coil. As the fluid passes through the 1714 magnet's static magnetic field, nuclear spins of atoms and molecules within the fluid align the direction of the static magnetic field. The RF 1716 coil confines a volume within the detection tube section and is arranged to supply one or more NMR excitation pulses to the fluid in the device and to detect one or more NMR response signals from the fluid. The test unit 1726 includes several sets of circuits to obtain one or more NMR response signals from the fluid and estimate a parameter of interest of the fluid from the obtained NMR response signals. In one embodiment, the exemplary test unit 1726 is coupled to the RF coil 1716 via the preamplifier 1720. The exemplary test unit 1726 includes a transmitter 1724 to provide an NMR excitation pulse to the RF coil 1716 through the pre -amplifier 1720. In one embodiment, transmitter 1724 provides multiple NMR excitation pulse sequences, each NMR excitation pulse sequence has been adjusted to a selected nuclear resonance frequency. The exemplary test unit 1726 also includes a receiver 1722 for receiving NMR response signals detected on the RF coil 1716 through the 1720 preamplifier. The test unit 1726 also includes a 1728 NMR control unit for estimating one or more parameters of the fluid from the NMR response signals received using exemplary methods of the present description. In one embodiment, the 1728 control unit may include a 1730 processor, one or more 1732 computer programs that are accessible by the 1730 processor to execute instructions contained in those programs to obtain one or more fluid-related parameters such as a fluid phase volume , viscosity, water fraction, and an emulsion stability parameter, for example, and a 1734 storage device, such as a solid state memory, tape, or hard disk to store one or more parameters obtained from the 1730 processor.
    [0079] NMR signal amplitude measurements on a constant volume measurement device can be used to determine a fraction of fluid volume in liquid vs. phase. volume fraction in gas phase. As shown with reference to FIG. 17, fluids flow into the apparatus 1700 where they enter the substantially homogeneous primary magnetic field generated by the primary magnet 1714. The nuclei of the produced fluids thus polarize along the direction of the primary magnetic field. A radio frequency pulse (RF) signal is transmitted to the through hole 1712 using the transmitter 1724 of the combined transmission and reception coils 1716. A signal amplitude of the nuclei present in the fluid flow after being excited by the RF pulse is detected by the 1722 receiver of the 1716 combined transmitter and receiver coils.
    [0080] The resistance of one phase NMR signal is a function of phase volume and hydrogen index of the phase. The hydrogen index is proportional to the proton density in the sensitive volume of the measuring device. The hydrogen content of methane CH4, for example, is proportional to the gas density: HI g = Apg Eq. (9)
    [0081] with A = 2.25. Gas density, in turn, is dependent on temperature and pressure and can be determined by correlations of state equation (EOS) such as those described by Londono et al (SPE paper # 75721 (2002)) and by Drumdruk et al "Calculation of z-factors for natural gases using equations of states" in J. of Canadian Petro., V.14, pp.24-26 (1975).
    [0082] To determine the volumes in liquid and gaseous phase, a calibration signal is first obtained. The calibration signal is used to represent the NMR signal resistance or scaled signal amplitude. In one aspect, the calibration signal resistance M is determined for a calibration signal using 100% water, such as distilled water (HI = 1) flowing in the production tube. A calibration constant can be obtained using c = M / V, where V is the sensitive volume and M is the resistance of the calibration signal at a given temperature. The value of the calibration constant can be temperature dependent and, therefore, can be determined using a theoretical prediction or obtaining values for the calibration constants at a plurality of temperatures and interpolating the values when necessary.
    [0083] In a multiphase fluid that has liquid and gaseous phases, the NMR signal amplitude m is described by

    [0084] where c (T) is the temperature dependent calibration constant, Vgas is the volume of a gas phase, Vliquid is the volume of a liquid phase, HIgas is the hydrogen index of the gas phase and HIliquid is the hydrogen content of the liquid phase. Most forming water has a hydrogen index that is close to the unit. Water salinity can affect the hydrogen index, and the hydrogen index can be determined when the salinity is known or estimated. The hydrogen index of liquid hydrocarbon is also substantially close to one.
    [0085] When HIliquid is 1 and HIgas is known, for example, from Eq. (9), then Eq. (10) can be solved for the volume of gas to obtain:

    [0086] An equation similar to Eq. (11) can be derived when HIliquid is a known value not equal to 1. This equation may be adequate to obtain Vgas in subsea or rock bottom locations.
    [0087] In several respects, the phase volume can be obtained at a surface location, where the pressure is substantially close to 1 atm. At this (low) pressure, HIgas is substantially close to zero and, thus, 1-HIgas is substantially close to 1. For a more adequate equation for the volume phase estimate, Eq. (10) can be obtained for high pressure environments. low pressure, observing that Vgas • Higas << Viiquid • Hiiiquid. If Viiquid is substantially nonzero, then m * c (T> V ^ uid-Hiliqmd) and the resulting NMR signal mainly represents the liquid phase (s):
    Vgas = V - Eq. Vliquid (14)
    [0088] Alternatively, Vliquid and Vgas can be estimated using a first order Taylor expansion from Eq. (10):
    and VuqUld = V - Vgas Eq. (16)
    [0089] Thus, the volume of liquid phase and the volume of gas phase can be determined for a multiphase fluid flowing in a production pipe. In addition, the volumetric flow rates for each phase can be obtained from the phase volumes and flow rates obtained.
    [0090] In another aspect, the present description provides a method for determining the stability of an emulsion (i.e., multiphase fluid) flowing in a production pipe. Emulsion stability can vary from very strict emulsions characterized by small, closely distributed droplets to very free emulsions characterized by large, widely distributed droplets. Emulsion stability can be characterized by an emulsion stability parameter, the value of which indicates the type of emulsion. For example, an emulsion stability parameter of about 7.0 indicates a very strict emulsion and an emulsion stability parameter of about 3.0 indicates a very free emulsion.
    [0091] As discussed below, the emulsion stability parameter is related to the viscosity and water fraction of the emulsion. Viscosity measurements can be determined from the relaxation times of NMR signals obtained from the emulsion. The relaxation times of the emulsion, i.e., T1 (longitudinal relaxation constant (spin-lattice)) and T2 (transversal relaxation constant (spin-spin)), for example, can be measured using the exemplary apparatus of FIG. 17. An exemplary relationship between T1, T2 and the viscosity of a fluid is determined below:

    [0092] where ε0 is the magnetic permeability of free space, h is the Planck constant divided by 2π, Y is the gyromagnetic ratio of a proton H, r is a distance between the closest portions in a molecule, μ is the fluid viscosity, k is the Boltzmann constant, and T is the absolute temperature.
    [0093] FIG. 18 shows an exemplary relationship between the emulsion viscosity and water fraction (WC) or fraction of water volume in the emulsion. The water fraction can be determined using the exemplary methods described herein or any other methods known in the art as infrared measurements. In various emulsions, the viscosity of the emulsion is typically greater than the viscosity of oil or water at a given temperature. For example, FIG. 18 shows various viscosity curves vs. fraction of water at different temperatures (75 ° F (1801), 100 ° F (1803), 125 ° F (1805), 150 ° F (1807)) for a water-in-oil emulsion. In a fraction of water of 0%, the emulsion is 100% oil and the emulsion has the oil viscosity (μ0). In a 100% water fraction, the emulsion is 100% water and the emulsion has the water viscosity (μw). As the water fraction of the emulsion increases from 0%, the viscosity of the emulsion increases to a point of inversion of the water fraction. In this range between 0% water fraction and the inversion point, the emulsion is a water-in-oil emulsion. In the range between the inversion point and 100% water fraction, the emulsion is an oil-in-water emulsion. The inversion point in FIG. 17 exemplary occurs in approximately 80% water fraction of water.
    [0094] The viscosity of an emulsion depends on several factors: the viscosities of oil in water, the volume fraction of water (water fraction), droplet size distribution, temperature, shear rate, amount of solids present, for example example. The viscosity of the emulsion can be substantially greater than the viscosity of oil or water at a given temperature. The viscosity of an emulsion is related to the viscosity of crude oil at the same temperature by the following equation for WC <WCinv:

    [0095] where α is the emulsification stability, μ0 is the oil viscoside, μW is water viscosity, WC is the water fraction and WCinv is the water fraction inversion point. In addition, the following relationship is considered WC> WCinv:

    [0096] Eq. (19) can be used to determine the emulsion stability parameter α of an emulsion flowing in a production pipe. The method includes obtaining a relaxation time of an emulsion NMR signal, determining an emulsion viscosity from the relaxation time obtained, and determining the emulsion stability using the determined viscosity and a water fraction value of the emulsion.
    [0097] In a number of ways, fluid emulsification information helps production engineers in shaping piping by providing information about the drag exerted by the fluid. The present invention further provides an ability to represent a flow pattern in the pipeline. This provides data to diagnose plug formations within the pipeline, thereby improving production pipeline and well bore models. The known fluid composition also allows fluid analysis to obtain fluid PVT properties.
    [0098] The NMR measuring device provides real-time measurement data that can be continuously updated. Updated compositional information can be fed back into a production model to improve flow analysis. Many technologies such as, but not limited to, infrared (IR) measurement can be used with magnetic resonance measurements.
    [0099] Therefore, in one aspect, the present description provides a method of determining a one-phase volume of a multiphase fluid that flows into a tube, which includes: imparting a magnetic field over the fluid to align the nuclei of the multiphase fluid to the along a direction of the magnetic field; transmitting a radio frequency signal within the multiphase fluid to excite the nuclei; detecting a signal from the cores responsive to the transmitted radio frequency signal; determine an amplitude of the detected signal; and determining the volume of the phase flowing in the tube using the determined amplitude and an amplitude of a calibration signal. When the phase is a liquid phase, the method also includes determining a relaxation time of the detected signal; and determining the viscosity of the multiphase fluid using the determined relaxation time. In one embodiment, the method includes determining a fraction of water in the liquid phase; and determining an emulsification stability parameter of the liquid phase from the determined viscosity and the determined water fraction. The water fraction determined from the liquid phase may include determining a proton density of the liquid phase from an accumulated relaxation time density. Also, the calibration signal can be obtained from a stream of water. Determination of the volume of the phase may include determining a hydrogen index of a phase of the multiphase fluid. The method may further include determining a phase flow rate; and determining the flow rate of the phase using the determined volume of the phase and the determined flow rate of the phase. In several embodiments, the amplitude of the calibration signal is a temperature-corrected amplitude.
    [00100] In another aspect, the present description provides an apparatus for determining a phase volume of a multi-phase fluid flowing in a tube, the apparatus including a source configured to impart a primary magnetic field over the fluid to aligning the nuclei of the multiphase fluid along a direction of the primary magnetic field; a source configured to transmit a radio frequency signal within the multiphase fluid to excite the cores; a detector for detecting a signal from the cores responsive to the transmitted radio frequency signal; and a processor configured to determine an amplitude of the detected signal and the volume of the phase flowing in the tube using the determined amplitude of the detected signals and an amplitude of a calibration signal. The processor can be configured to determine a relaxation time for the detected signal; and determining a viscosity of the multiphase fluid using the determined relaxation time. In one embodiment, the processor is configured to determine a fraction of water in the liquid phase; and determining an emulsification stability parameter of the liquid phase from the determined viscosity and the determined water fraction. The processor can be further configured to determine the water fraction of the liquid phase by determining the proton density of the liquid phase from an accumulated relaxation time density. The calibration signal can be obtained from a flow of water. The processor can be configured to determine the volume of the phase by determining a hydrogen content of a phase of the multiphase fluid. In various embodiments, the processor is configured to determine a phase flow rate and determine a phase flow rate using the determined phase volume and the determined phase flow rate. The span of the calibration signal is typically a temperature-corrected span.
    [00101] In another aspect, the present description provides a method of determining the stability of an emulsion flowing in a production column, the method including conferring a primary magnetic field on the emulsion to align the emulsion cores along a direction of the primary magnetic field; transmitting a radio frequency signal within the emulsion flowing in the production column; detecting a signal from the emulsion cores responsible for the transmitted radio frequency signal; determine an amplitude of the detected signal; determining a fraction of water in the emulsion using the obtained amplitude; determining a relaxation rate of a signal obtained from nuclei of the excited emulsion in response to the transmitted radio frequency signal; obtain an emulsion viscosity from the determined relaxation time; and determining the stability of the emulsion from the determined emulsion viscosity and the water fraction of the emulsion.
    [00102] Although the previous description is aimed at certain modalities, several modifications will become apparent to the elements versed in the technique. It is intended that all such changes are included within the scope and spirit of that description and any claims that are or may be made.
    权利要求:
    Claims (12)
    [0001]
    1. Method for determining an emulsion stability parameter of a multiphase fluid flowing in a tube in order to determine a fluid flow rate, which comprises: imparting a magnetic field over the multiphase fluid to align the fluid nuclei multiphase along a direction of the magnetic field; transmitting a radio frequency signal in the multiphase fluid to excite the cores; detecting a signal from the cores responsive to the transmitted radio frequency signal; determine the amplitude of the detected signal; estimate a fraction of water in the multiphase fluid from the determined amplitude; determine a relaxation time of the detected signal; and determining a viscosity of the multiphase fluid from the determined relaxation time of the detected signal; determining a volume of the phase flowing in the tube using the determined amplitude and an amplitude of a calibration signal; and determining the fluid flow rate using one or more of the parameters determined above; the method characterized by the fact that: determining the emulsion stability parameter of the multiphase fluid from the determined viscosity, the estimated water fraction and a curve that relates the viscosity, the water fraction and the emulsion stability parameter; model the multiphase fluid with an emulsion defined by the emulsion stability parameter; and represent a flow pattern of the multiphase fluid in the tube using the emulsion model.
    [0002]
    2. Method according to claim 1, characterized in that it further comprises determining the water fraction of a liquid phase by determining a proton density of the liquid phase from an accumulated relaxation time density.
    [0003]
    Method according to claim 1, characterized by the fact that it further comprises determining a volume of a phase of the multiphase fluid using an integrated signal from the calibration signal obtained from a flow of water and the amplitude of the signal detected.
    [0004]
    4. Method according to claim 3, characterized by the fact that determining the volume of the phase additionally comprises determining a hydrogen index of a phase of the multi-phase fluid.
    [0005]
    Method according to claim 3, characterized by the fact that it further comprises: determining a flow rate of the phase; and determining a phase flow rate using the determined phase volume and the determined flow rate of the phase.
    [0006]
    6. Method according to claim 1, characterized by the fact that the amplitude of the calibration signal is a temperature-corrected amplitude.
    [0007]
    7. Apparatus for determining a parameter of emulsification stability of a multiphase fluid flowing in a tube in order to determine a fluid flow rate, which comprises: a magnetic source (16) configured to impart a magnetic field in the multiphase fluid to aligning the nuclei of the multiphase fluid along a direction of the magnetic field; a source (48) configured to transmit a radio frequency signal in the multiphase fluid to excite the cores; a detector (40) for detecting a signal from the cores corresponding to the transmitted radio frequency signal; and a processor (1410) configured to: determine an amplitude of the detected signal; estimate a fraction of water in the multiphase fluid from the determined amplitude; determine a relaxation time of the detected signal; determine a viscosity of the multiphase fluid from the determined relaxation time; determining a phase volume flowing in the tube using the determined amplitude of the detected signals and an amplitude of a calibration signal; and determining the fluid flow rate using one or more of the parameters determined above; the device characterized by the fact that the processor (1410) is configured to: determine the emulsification stability parameter of the multiphase fluid from the determined viscosity, the water fraction and a curve that relates the viscosity, the water fraction and the emulsion stability parameter; model the multiphase fluid with an emulsion defined by the emulsion stability parameter; and represent a flow pattern of the multiphase fluid in the tube using an emulsion model.
    [0008]
    8. Apparatus according to claim 7, characterized by the fact that the processor (1410) is additionally configured to determine the water fraction of a liquid phase of the multi-phase fluid when determining a proton density of the liquid phase from of an accumulated relaxation time density.
    [0009]
    9. Apparatus according to claim 7, characterized by the fact that the processor (1410) is additionally configured to determine a phase volume of the multiphase fluid using the calibration signal obtained from a water flow and amplitude the detected signal.
    [0010]
    Apparatus according to claim 7, characterized in that the processor (1410) is additionally configured to determine the volume of the phase by determining a hydrogen index of a liquid phase of the multiphase fluid.
    [0011]
    Apparatus according to claim 7, characterized by the fact that the processor (1410) is additionally configured to: determine a phase flow rate; and determining a phase flow rate using the determined phase volume and the determined flow rate of the phase.
    [0012]
    12. Apparatus according to claim 7, characterized by the fact that the amplitude of the calibration signal is an amplitude corrected by temperature.
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    同族专利:
    公开号 | 公开日
    BR112013020868A2|2016-09-27|
    WO2012112254A2|2012-08-23|
    GB2501858B|2018-02-07|
    GB201315380D0|2013-10-16|
    US20120209541A1|2012-08-16|
    GB2501858A|2013-11-06|
    AU2012218102B2|2015-11-26|
    US9335195B2|2016-05-10|
    NO20131032A1|2013-08-30|
    NO343398B1|2019-02-18|
    WO2012112254A3|2012-10-26|
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    法律状态:
    2018-12-18| B06F| Objections, documents and/or translations needed after an examination request according art. 34 industrial property law|
    2019-12-10| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|
    2021-01-12| B09A| Decision: intention to grant|
    2021-03-02| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 18/01/2012, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US13/028,553|US9335195B2|2011-02-16|2011-02-16|Multiphase meter to provide data for production management|
    US13/028,553|2011-02-16|
    PCT/US2012/021716|WO2012112254A2|2011-02-16|2012-01-18|Multiphase meter to provide data for production management|
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