POLIKHOV, Stepan Alexandrovich (Mira str. 2, appt 61Ramenskoe, 5, 14010, RU)
MALININ, Vitaly Vladimirovich (Marshal Konev str, 16 appt. 5, Moscow 0, 12306, RU)
POLIKHOV, Stepan Alexandrovich (Mira str. 2, appt 61Ramenskoe, 5, 14010, RU)
| PATENT CLAIMS 1. A system (100) for determination of material deposition on an inner surface (5) of a pipe (3) carrying a multi-phase fluid medium (1) therethrough, said system (100) comprising: - an acoustic sensor (10) disposed on an outer surface (6) of said pipe (3) for capturing acoustic signals (8) in a frequency range transmitted through said pipe (3) from said fluid medium (1), to resultantly provide an intensity spectrum of said captured acoustic signals (8) across said frequency range, and - analysis means (9) adapted for determining a layer (2) of material deposition on said inner surface (5) of said pipe (3) on the basis of said intensity spectrum of said acoustic signals obtained from said acoustic sensor (10). 2. The system (100) according to claim 1 , wherein said acoustic signals (8) transmitted through said pipe (3) to said acoustic sensor (10) are produced by turbulent flow pulsations in said fluid medium (1). 3. The system (100) according to any of the preceding claims, wherein said frequency range lies between 10 kHz to 1 MHz. 4. The system (100) according to claim 1 , wherein said analysis means (9) is adapted to detect the formation of said layer (2) of material deposition based on a measured change in the intensity spectrum of the acoustic signals obtained from said acoustic sensor (10) at successive intervals of time. 5. The system (100) according to any of the preceding claims, wherein said analysis means (9) is adapted for determining a relative transmission coefficient from the obtained intensity spectrum and therefrom determining a thickness of said layer (2) of material deposition, wherein said relative transmission coefficient is determined as a ratio of an energy transmission coefficient of acoustic signals transmitted to said pipe (3) having said layer (2) of material deposition on said inner surface (5) thereof and an energy transmission coefficient of acoustic signals transmitted through a clean pipe without any material deposition, said relative transmission coefficient being a function of at least the thickness of said layer (2) of material deposition, thickness of said pipe (3), a frequency of the acoustic signals and one or more material properties of said multi-phase fluid medium and said pipe. 6. The system (100) according to claim 5, wherein said analysis means (9) is adapted for determining said thickness of said layer (2) of material deposition from the determined relative transmission coefficient using a pre-stored database representing dependence of relative transmission coefficient on material deposition layer (2) thickness and pipe (3) thickness for different acoustic frequencies and for different material properties of said multi-phase fluid medium and said pipe. 7. The system (100) according to claim 1, comprising an acoustic signal transmitter for producing said acoustic signals in said fluid medium (1). 8. A method for determination of material deposition on an inner surface (5) of a pipe (3) carrying a multi-phase fluid medium (1) therethrough, said method comprising: - disposing an acoustic sensor (10) on an outer surface (6) of said pipe for capturing acoustic signals (8) in a frequency range transmitted through said pipe (3) from said fluid medium (1), - obtaining an intensity spectrum of said captured acoustic signals across said frequency range, and - determining a layer (2) of material deposition on said inner surface (5) of said pipe (3) on the basis of the obtained intensity spectrum of said acoustic signals. 9. The method according to claim 8, wherein said acoustic signals transmitted through said pipe (3) to said acoustic sensor (10) are produced by turbulent flow pulsations in said fluid medium (1). 10. The method according to any of claims 8 and 9, wherein said frequency range lies between 10 kHz to 1 MHz. 1 1. The method according to claim 8, comprising detecting the formation of said layer (2) of material deposition by measuring a change in the intensity spectrum of the acoustic signals obtained from said acoustic sensor (10) at successive intervals of time. 12. The method according to any of claims 8 to 1 1 , further comprising: - determining a relative transmission coefficient from the obtained intensity spectrum, and - determining a thickness of said layer (2) of material deposition based on the determined relative transmission coefficient, wherein said relative transmission coefficient is determined as a ratio of an energy transmission coefficient of acoustic signals transmitted to said pipe (3) having said layer (2) of material deposition on said inner surface (5) thereof and an energy transmission coefficient of acoustic signals transmitted through a clean pipe without any material deposition, said relative transmission coefficient being a function of at least the thickness of said layer (2) of material deposition, thickness of said pipe (3), a frequency of the acoustic signals and one or more material properties of said multiphase fluid medium and said pipe. 13. The method according to claim 12, further comprising determining said thickness of said layer (2) of material deposition from said determined relative transmission coefficient using a pre-stored database representing dependence of relative transmission coefficient on material deposition layer (2) thickness and pipe (3) thickness for different acoustic frequencies and for different material properties of said multi-phase fluid medium and said pipe.. 14. The method according to claim 8, comprising providing an acoustic signal transmitter for producing said acoustic signals in said fluid medium (1). |
MULTI-PHASE FLUID FLOW
The present invention relates to the field of detecting a deposit or a solid phase liable to form in a pipe for transporting a multi-phase fluid.
It is known that multi-phase fluids, such as petroleum fluids, can lead to the formation of a solid phase such as hydrates, paraffins, asphaltenes, or other mineral deposits. The solid phase may be deposited at one or more locations in the pipeline, thereby reducing flow rate to such an extent as to disturb the fluid transport completely, causing clogging or further destruction of the pipeline. The problem of deposits formation is especially critical in technological processes which include pressurized hydrocarbons passing through the ducts, such as in oil & gas and chemical industry. For example, hydrate formation is favored by higher pressures and lower temperatures during producing hydrocarbons from deep-sea reservoirs. Similar situation occurs in long-distance pipelines in regions with cold climate or sub-sea pipelines.
Currently, to solve the problem of detecting deposits (particularly, hydrate) formation, efforts are focused on the development of various types of multiphase fluid flow models which can predict fluid flow behavior and fluid parameters at any point of a pipeline or manifold. The document US6028992-A discloses a method for modeling multi-phase flow in a pipe using hydro- and thermo-dynamics, in particular, conservation of mass and of momentum and energy transfer in the mixture to define properties. The document US5550761-A discloses a method for modeling steady state and transients in multi-phase flows, e.g. hydrocarbon mixture, in pipeline and determimng any current flow regime when solving set of closure relations by comparing current values of liquid fraction in slugs to liquid fraction in dispersed region of flow. The document US6871118-B2 discloses a method for continuously detecting and controlling thermodynamic conditions for formation of hydrates at all points in pipe containing polyphasic mixture of fluids.
The above described approach, based on the solution of corresponding conservation equations for mass, momentum and energy, allows monitoring and localization of deposits (hydrates) formation conditions. However, in this approach, for correct prediction of hydrate formation conditions, the supplied software demands an additional sensors network that provides boundary conditions for fluid flow models. Most of these sensors are intrusive. Moreover, the accuracy of such a system strongly depends on the number of sensors and their quality.
There have also been other approaches to the problem that are based on direct detection of deposits formation. For example, the document EP1216380-B1 discloses a method for detection of hydrate deposition in multi-phase hydrocarbon flow that comprises applying thermal gradient across a zone of the pipe and comparing thermal flux with threshold value. The document WO2000043762-A1 discloses a method for detecting the formation of a deposit of material contained in a fluid on a heat flow detector by measuring the heat flow between the faces of the detector. The document JP000142229 discloses a pipe arrangement monitoring method used in an LPG plant that comprises judging the generation of pH rate of formation phenomenon in control valve when difference between theoretical measured temperatures of petroleum gas exceeds threshold value. Disadvantageously, all these methods are either intrusive or demand external source of energy.
The object of the present invention is to provide a system and method for direct, accurate and non-intrusive determination of material deposition in a multi-phase fluid flow.
The above object is achieved by the system according to claim 1 and the method according to claim 8.
The underlying idea of the present invention is to determine material deposition on an inner surface of a pipe carrying a multi-phase fluid medium by capturing acoustic signals in a frequency range transmitted through the pipe from the fluid medium. These acoustic signals are captured by an acoustic sensor disposed on an outer surface of the pipe, i.e., external to the pipe. From the captured acoustic signals, an intensity spectrum is obtained for that frequency range, on the basis of which a layer of material deposition is determined. The technique proposed is thus direct and non-intrusive, and hence obviates many of the disadvantages of the above-mentioned state of the art.
In one embodiment, said acoustic signals transmitted through said pipe to said acoustic sensor are produced by turbulent flow pulsations in said fluid medium. This embodiment thus eliminates the use of an acoustic transmitter and instead uses acoustic signals from inherent flow pulsations associated with turbulent flow of the multi-phase fluid medium. However, in an alternate embodiment, the proposed system may comprise an acoustic transmitter for producing said acoustic signals in said fluid medium.
In a preferred embodiment, said frequency range lies between 10 kHz to 1 MHz. Advantageously, for such high frequency turbulent pulsations, the intensity spectrum is independent of the pipe geometry, allowing such a system for any system geometry and operating condition. Further, this range of frequency provides increased measurement sensitivity as illustrated in the description below. However, it should be understood that the proposed invention works for any acoustic frequency.
In one embodiment, said analysis means is adapted to detect the formation of said layer of material deposition based on a measured change in the intensity spectrum of the acoustic signals obtained from said acoustic sensor at successive intervals of time. The above is a simple and inexpensive implementation of the present invention that simply detects the formation of a deposit based on a change in acoustic signals.
In a further embodiment, for real time determination of thickness of the deposit, said analysis means is adapted for determining a relative transmission coefficient from the obtained intensity spectrum and therefrom determining a thickness of said layer of material deposition, wherein said relative transmission coefficient is determined as a ratio of an energy transmission coefficient of acoustic signals transmitted to said pipe having said layer of material deposition on said inner surface thereof and an energy transmission coefficient of acoustic signals transmitted through a clean pipe without any material deposition, said relative transmission coefficient being a function of at least the thickness of said layer of material deposition, thickness of said pipe, a frequency of the acoustic signals and one or more material properties of said multiphase fluid medium and said pipe.
In a further embodiment, said analysis means is adapted to determine said thickness of said layer of material deposition from the determined relative transmission coefficient using a pre-stored database representing dependence of relative transmission coefficient on material deposition layer thickness and pipe thickness for different acoustic frequencies and for different material properties of said multi-phase fluid medium and said pipe.
The present invention is further described hereinafter with reference to illustrated embodiments shown in the accompanying drawings, in which: FIG 1 illustrates a system for determination of deposits in a multi-phase fluid flow medium according one embodiment of the present invention,
FIG 2 is an exemplary graphical representation illustrating dependence of relative transmission coefficient on sound frequency in a "low" frequency domain for various pipe thicknesses and deposit layer thickness, and
FIG 3 is an exemplary graphical representation illustrating dependence of relative transmission coefficient on sound frequency in a "high" frequency domain for various pipe thicknesses and deposit layer thickness,
Referring now to FIG 1 is illustrated a system 100 for determination of deposits in multi-phase fluid flow in accordance with one embodiment of the present invention. The system 100 includes a pipe 3 carrying a multi-phase fluid medium 1 , including, for example, petroleum. The wall of the pipe 3 has an inner surface 5 in contact with the multi-phase fluid medium 1. The surrounding medium is designated by the numeral 4. The flow of the multi-phase fluid 1 through the pipe 3 leads to the formation of a solid- phase organic or mineral deposit layer 2 at one or more locations on the inner surface 5 of the pipe 3. In the illustrated example, the deposit mainly includes hydrates. However, the despot may also include paraffins, asphaltenes, or other organic or mineral deposits. The presence and/or thickness of a deposit layer 2 at any point on the pipe 3 inner surface 5 is determined based upon analysis of acoustic signals in a frequency range transmitted through the pipe 3 from the fluid medium 1. The acoustic signals transmitted through the pipe 3 are captured by an acoustic sensor 10 disposed at one or more locations on an outer surface 6 of the pipe 3.
In the illustrated embodiment, the acoustic signals are produced by inherent turbulent pulsations in the fluid medium 1. It is known that any type of fluid flow, due to its inherent instabilities, is accompanied by sound emission at different frequencies. For any given fluid flow system, the lowest possible sound frequency v 0 is proportional to fluid medium sound speed c„ divided by the system character length scale L (v 0 = c n /L). For example, in case of pipe flow, the length scale L may include the diameter of the pipe. Most of the emitted sound energy is contained in the range from v0 to 10v 0 . These frequencies diapason is influenced by the surrounding medium which results in strong non-uniformity and anisotropy of sound spectrum. In case of laminar flow the "high" frequency part (i.e. frequencies higher than lOvo) of sound spectrum is practically absent due to the absence of high frequency sources of influence. At the same time high frequency pulsations are an inherent property of any turbulent flow, i.e. for flows with Reynolds number (Re) greater than some specific value depending on given flow parameters and geometry. It has been found that in case of high frequency turbulent pulsations (i.e. frequencies higher than 10v 0 ), the energy or intensity spectrum is independent on the system (i.e., pipe) geometry. Thus, advantageously, high frequency turbulent pulsations can be considered as an isotropic source of acoustic energy suitable for any system geometry conditions. At the same time it should be taken into account that pulsations intensity decreases with frequency. In view of the above mentioned advantages, a preferable frequency range of the acoustic signals to be captured by the acoustic sensor 10 has been seen to be 10 kHz to 1 MHz. However, in principle, the proposed approach works for any acoustic frequency.
Referring back to FIG 1 , an acoustic signal 7 produced by turbulent pulsations in the fluid medium 1 propagates through the deposit layer 2 and the wall of the pipe 3 and the transmitted signal 8 is captured by the acoustic sensor 10. The acoustic sensor 10 provides an acoustic intensity spectrum across the frequency range of the captured acoustic signals 8 to an analysis means 9. The analysis means 9 comprises, for example, a computing device, such as a computer or a processor having suitable hardware for signal processing. The formation of a deposit layer 2 on the pipe 3 inner surface 5 may be determined by the analysis means 9 in real time in response any change in the acoustic intensity spectrum obtained from the acoustic sensor 10 at successive intervals of time. In a further embodiment, on the basis of the obtained acoustic intensity spectrum, the analysis means 9 may further determine the thickness of the deposit layer 2 as explained in detail below. The theoretical background for the proposed approach of thickness determination will be discussed first.
For the system 100, the energy transmission coefficient, i.e. ratio of transmitted acoustic signal intensity to the incident acoustic signal intensity, is dependent on the thickness of the pipe (Δ), thickness of the deposit layer (δ) and frequency (co) of the acoustic signal. The energy transmission coefficient for "low" frequency domain (i.e. for frequencies less than 10 v 0 ) may be defined by the relationship in Eq.1 below: wherein
Re refers to Reynolds number,
p„ and c„ being η Λ medium density and sound speed respectively (n= 1, 2, 3 and 4 for fluid medium, deposit, wall of pipe and surrounding medium respectively)
Θ is the incident wave angle,
where E refers to Young modulus of the pipe, and
σ refers to Poisson ratio of the pipe.
The energy transmission coefficient for "high" frequency domain (i.e. for frequencies greater than 10 v 0 ) may be defined by the relationship in Eq.5 below:
wherein
where k„ - wave number of sound wave propagating in η Λ medium (n= 1, 2, 3 and 4 for fluid medium, deposit, wall of pipe and surrounding medium respectively), k n = iycos„(#)/c„ ; and
the dimensionless functions Fi (Θ) to F 4 (0) are as defined below:
The thickness of the deposit layer 2 may be determined by the analysis means 9 by first determining a relative transmission coefficient ξ, i.e. ratio of the energy transmission coefficient of the acoustic signals transmitted through the deposit layer 2 and the pipe 3 wall to the energy transmission coefficient for clean pipe 3 wall (without deposit). In an exemplary embodiment, the analysis means 9 may have a pre-stored database representing the dependence of relative transmission coefficient on deposit layer thickness and pipe thickness for different acoustic frequencies and different values of material properties of the pipe and fluid medium. Thus, once a relative transmission coefficient is determined by the analysis means 9 from the acoustic intensity spectrum obtained from the acoustic sensor 10, this database may be referred to arrive at the thickness of the deposit layer.
An example of the relative transmission coefficient dependence on pipe thickness and deposit layer thickness for different acoustic frequencies is illustrated below. For this example, the following parameters are assumed: natural gas with p t =60kg/m3, c 1 =430m/s; gas hydrate deposit with p 2 =940kg/m3, c 2 =3778m/s; steel pipe wall with p3=7800kg/m3, c 3 =7500m/s, E 3 =l.85-101 lPa, 03=0.27 and surrounding medium with p 4 =1000kg/m3, c 4 =1000m/scase. Based on the above assumptions and the relationships defined in Eq. (1) to Eq. (10), the dependence of relative transmission coefficient on pipe thickness and deposit layer thickness for the "low" frequency domain may be represented by the graph 20 shown in FIG 2, while the dependence of relative transmission coefficient on pipe thickness and deposit layer thickness for the "high" frequency domain may be represented by the graph 30 shown in FIG 3.
Referring to FIG 2, the axis 21 represents scaled frequency (i.e., lg(v)) while the axis 22 represents relative transmission coefficient ξ. Herein, the curve 23 with dotted line corresponds to pipe wall thickness A=0.005m and deposit layer thickness 6=0.00 lm; the curve 24 with crosses corresponds to A=0.005m and 6=0.025m; the curve 25 having solid line corresponds to A=0.025m and 5=0.00 lm; and the curve 26 with circles corresponds to A=0.025m and 6=0.025m. Referring to FIG 3, the axis 31 represents scaled frequency (i.e., lg(v)) while the axis 32 represents scaled relative transmission coefficient (lg½)). Herein the curve 33 with dotted line corresponds to pipe wall thickness A=0.005m and deposit layer thickness 6=0.00 lm; the curve 34 with crosses correspond to A=0.005m and 6=0.025m; the curve 35 having solid line corresponds to A=0.025m and 5=0.00 lm; and the curve 36 with circles correspond to A=0.025m and 6=0.025m.
It is clearly seen from FIG 2 that in the "low" frequency domain, the sensitivity decreases with the increase of pipe wall thickness. Moreover the absolute values of ξ are of order of 1. At the same time, as can be seen from FI 3, in the of the "high" frequency domain, the absolute values of ξ vary in the range from 0.1 to 10000, such that the presence of the deposit layer on the wall is easily detectable. The preferred frequency range of 10 kHz to 1 MHz lies in this high frequency domain and hence has the advantage of providing increased sensitivity of deposit layer thickness measurement.
Embodiments of the present invention offer several advantages. The proposed method allows detection of deposits of any origin with the only limitation since acoustical properties of the deposit should be noticeably different from the main portion of the flow. Moreover, there is no need for precise, expensive or highly sensitive equipment since the operating principle is based on the detection of acoustic intensity change. In the preferred embodiment, the use of high frequencies (in the range from 10 kHz to 1 MHz) provides sufficient sensitivity for the reliable detection of fluid contained materials deposition and further eliminates dependencies on pipe geometry and operating conditions.
A further advantage is that, in the illustrated embodiment, there is no need in additional signal sources, since the monitoring system uses acoustic energy generated by inherent fluid flow pulsations. However, in an alternate embodiment an acoustic signal transmitter may be used for producing said acoustic signals in said fluid medium. In a further embodiment for deposit detection, an array of active sensors may be used which emit and receive sound waves of predefined frequency. Sound wave intensity decay caused by deposit layer presence can thus be detected.
While this invention has been described in detail with reference to certain preferred embodiments, it should be appreciated that the present invention is not limited to those precise embodiments. Rather, in view of the present disclosure which describes the current best mode for practicing the invention, many modifications and variations would present themselves, to those of skill in the art without departing from the scope and spirit of this invention. The scope of the invention is, therefore, indicated by the following claims rather than by the foregoing description. All changes, modifications, and variations coming within the meaning and range of equivalency of the claims are to be considered within their scope.
List of reference signs
1 multi-phase fluid medium
2 deposit
3 pipe/pipe wall
4 surrounding medium
5 inner surface of pipe wall
6 outer surface of pipe wall
7 incident acoustic signal
8 captured acoustic signal
9 analysis means
10 acoustic sensor
20 graphical representation illustrating dependence of relative transmission coefficient on sound frequency in a "low" frequency domain for various pipe thicknesses and deposit thickness
21 axis representing log of frequency
22 axis representing relative transmission coefficient
23 curve corresponding to pipe wall thickness A=0.005m and deposit thickness 6=0.00 lm
24 curve corresponding to A=0.005m and 6=0.025m
25 curve corresponding to A=0.025m and 6=0.00 lm
26 curve corresponding to A=0.025m and 6=0.025m
30 graphical representation illustrating dependence of relative transmission coefficient on sound frequency in a "high" frequency domain for various pipe thicknesses and deposit thickness
31 axis representing log of frequency
32 axis representing log of relative transmission coefficient
33 curve corresponding to A=0.005m and 6=0.001m
34 curve corresponding to A=0.005m and 6=0.025m
35 curve corresponding to A=0.025m and 6=0.00 lm 36 curve corresponding to m
100 System for determination of deposits in multi-phase fluid flow.
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