Patent Application
20150003582
The present teachings relate generally to multi-phase mixture flows and to measuring the compositions thereof.
In many industries, techniques for measuring the composition of a multi-phase mixture flow are used. For example, in the gas and oil industry, non-intrusive methods for measuring the multi-phase mixture flow emanating from an oil or gas well are used.
U.S. Pat. No. 6,097,786 describes a method and apparatus for determining the composition of a multi-phase mixture flow based on X-ray radiation. In this method, the multi-phase mixture flow is irradiated with high-energy and low-energy X-ray radiation. The radiation that passes through the flow is measured by a multi-layer detector. Since the attenuation of the radiation depends on the composition of the multi-phase mixture flow, the fractions of the different phases may be determined.
International Patent Document No. WO 2011/005133 A1 describes an apparatus and method for measuring the flow velocity of a multi-phase fluid mixture. In this method, images of the spatial distributions of the photons from X-ray sources are detected at different intervals of time. Based on those distributions, the flow rate of the fluid mixture may be determined.
In conventional analyses of a multi-phase mixture flow, the measurement apparatus is calibrated manually. The different absorption coefficients of the phases in the flow are determined in advance so that the composition of the flow may be calculated based on those absorption coefficients. Manual calibration is time-consuming and involves sampling of the flow at the location of the apparatus by an operator. As a result, manual calibration is not repeated very often and may lead to inaccurate measurements of the composition of the multi-phase mixture flow.
The scope of the present invention is defined solely by the appended claims, and is not affected to any degree by the statements within this summary.
The present embodiments may obviate one or more of the drawbacks or limitations in the related art. For example, in some embodiments, an apparatus and a method for measuring the composition of a multi-phase mixture flow using self-calibration are provided.
An apparatus in accordance with the present teachings measures the composition of a multi-phase mixture flow including at least one liquid phase (e.g., different liquids, such as oil and water) and at least one gaseous phase (e.g., different kinds of gases). In some embodiments, the apparatus is configured for measuring a flow of liquid and gaseous hydrocarbons emanating from a well. The apparatus includes a measurement tube that forms a conduit for a flow of a multi-phase mixture. The term “measurement tube” is to be interpreted broadly and may refer to any measurement section having an arbitrary cross-section (e.g., a rectangular or a circular cross-section). The apparatus further includes a radiation part configured for irradiating the multi-phase mixture in the measurement tube with electromagnetic radiation. A detector is provided for detecting the radiation of the radiation part that passes through the multi-phase mixture in the measurement tube. An analyzer is used for determining the composition of the multi-phase mixture based on the detected radiation and calibration data of the at least one liquid phase and the at least one gaseous phase. The measurement principle used in accordance with the present teachings may be based on conventional methods. For example, the measurement may be based on the method described in U.S. Pat. No. 6,097,786 wherein radiation at different energy levels is detected in order to determine the composition of a multi-phase mixture flow. The entire contents of U.S. Pat. No. 6,097,786 are hereby incorporated by reference.
Apparatuses in accordance with the present teachings implement a self-calibration unit. The unit includes a calibration vessel that is arranged adjacent to the measurement tube. During operation of the apparatus, the radiation part may irradiate the calibration vessel and the detector may detect radiation of the radiation part that passes through the calibration vessel.
The calibration vessel is connectable to the measurement tube, such that the calibration vessel is filled with the multi-phase mixture or respective phases of the multi-phase mixture from the measurement tube. The calibration unit further includes a data acquisition part configured for acquiring calibration data from radiation detected by the detector that passes through the calibration vessel when the calibration vessel is filled with the multi-phase mixture or respective phases of the multi-phase mixture from the measurement tube.
In some embodiments, automatic calibration may be performed by filling a calibration vessel with a multi-phase mixture and automatically acquiring calibration data via the data acquisition part. Thus, manual calibration may be avoided. The automatic calibration may be performed at regular intervals to provide accurate measurements of the composition of a multi-phase mixture flow.
In some embodiments, the radiation from the radiation part includes high-energy electromagnetic radiation with a photon energy of at least 10 KeV. X-ray radiation and/or gamma radiation may be used since the radiation is only partially absorbed by the multi-phase mixture and the radiation may be detected by the detector.
As described above, conventional methods may be used for determining the composition of the multi-phase mixture flow (e.g., the method described in U.S. Pat. No. 6,097,786). In such methods, the radiation part may generate at least two different radiation pulses. The at least two different radiation pulses may include a first pulse having a low energy level and a second pulse having a high energy level. The detector may detect the different radiation pulses. In addition, the analyzer is configured for determining the composition of the multi-phase mixture flow based on the detected different radiation pulses and the calibration data. The calibration data is acquired by the data acquisition part from the different radiation pulses detected by the detector that pass through the calibration vessel when the calibration vessel is filled with the multi-phase mixture or respective phases of the multi-phase mixture from the measurement tube.
In some embodiments, the calibration data includes absorption coefficients for the phases of the multi-phase mixture with respect to the radiation of the radiation part. The absorption coefficients may be used to calculate the different fractions of the phases of the multi-phase mixture flow in the measurement tube.
To facilitate calibration, the measurement conditions for the measurement tube and for the calibration vessel may be similar. In some embodiments, the measurement tube and the calibration vessel are made of the same material and/or have the same cross-section. For example, the measurement tube and/or the calibration vessel may be from materials that are transmissive to electromagnetic radiation (e.g., high-energy electromagnetic radiation). These materials include beryllium bronze and/or carbon fiber and/or glassy carbon.
Furthermore, in some embodiments, the measurement tube and/or the calibration vessel may have an elliptical cross-section or a cross-section in the form of an elongated hole. An elliptical cross-section or a cross-section in the form of an elongated hole provides high resistance with respect to the pressure in the tube and the vessel. An elliptical cross-section or a cross-section in the form of an elongated hole also prevents the paths of the radiation beams through the tube and the vessel from varying too much.
In some embodiments, the measurement tube and the calibration vessel are arranged symmetrically with respect to the radiation part and the detector. The radiation reaching the detector that has passed through the measurement tube and the calibration vessel, respectively, does not change when the positions of the measurement tube and the calibration vessel are reversed. Since the measurement conditions for the tube and the vessel are substantially the same, a straightforward calculation based on the calibration data without any conversions may be performed to determine the composition of a multi-phase mixture flow.
In order to provide similar conditions during calibration and measurement, the temperatures in the calibration vessel and the measurement tube may be the same. In some embodiments, a section of the measurement tube and a section of the calibration vessel are in direct contact with each other to provide a good thermal transfer. Furthermore, the measurement tube and the calibration vessel may be surrounded by a thermal insulation such that the thermal conditions of the tube and the vessel are not affected by the environment.
A detector for use in accordance with the present teachings may be implemented in various ways. For example, the detector may include one or more detection sensors. In some embodiments, the detector includes a matrix detector configured to provide spatial resolution of the detected radiation. The detector may also or alternatively include two detection sensors, wherein a first detection sensor is configured for detecting radiation that passes through the measurement tube and the second detection sensor is configured for detecting radiation that passes through the calibration vessel. By using a matrix detector, different phases in the multi-phase mixture in the calibration vessel may be distinguished after segregation.
In some embodiments, the measurement tube and the calibration vessel extend in the vertical direction during operation of the apparatus, thereby facilitating a gravitational stratification of the different phases in the multi-phase mixture inside the calibration vessel.
In some embodiments, in order to connect the calibration vessel with a measurement tube, a valve system is provided. The valve system includes one or more valves and one or more conduits. The valve system is arranged between the measurement tube and the calibration vessel and is controllable by the data acquisition part. The valve system may be used to fill the calibration vessel with the multi-phase mixture or respective phases of the multi-phase mixture from the measurement tube.
In some embodiments, the valve system includes a sampling probe positioned in the measurement tube and connected with the calibration vessel via a first conduit that includes a first valve. The calibration vessel is filled with the multi-phase mixture from the measurement tube when the first valve is opened.
Furthermore, the valve system may include a second conduit that includes a second valve. The at least one gaseous phase of the multi-phase mixture may be interchanged between the measurement tube and the calibration vessel when the second valve is opened.
The valve system may also include a third conduit that includes a third valve. The multi-phase mixture in the calibration vessel is fed back to the measurement tube when the third valve is opened. The third conduit may be connected to a flow restriction in the measurement tube. A reduction in pressure in the measurement tube due to the flow restriction results in a good return flow to the measurement tube.
In some embodiments, the valve system includes a fourth conduit that includes a fourth valve. The at least one gaseous phase of the multi-phase mixture in the calibration vessel is released from the calibration vessel when the fourth valve is opened. Such embodiments may be used to measure the composition of stable and unstable gas condensates in a gas condensate flow.
In addition to the above-described measurement of the composition of a multi-phase mixture, an apparatus in accordance with the present teachings may also be used for the measurement of flow rate based on images taken by the detector. In some embodiments, the method described in International Patent Publication No. WO 2011/005133 A1 may be used to determine the flow rate. The entire contents of WO 2011/005133 A1 are hereby incorporated by reference.
In addition to the above-described apparatus, the present teachings also provide a method for calibrating the apparatus. The method includes: (i) filling the calibration vessel with the multi-phase mixture of respective phases from the measurement tube; (ii) irradiating the calibration vessel with electromagnetic radiation from the radiation part and detecting the radiation that passes through the calibration vessel by the detector; and (iii) acquiring calibration data by the data acquisition part from the radiation detected by the detector.
In some embodiments, the calibration vessel is successively filled with the at least one gaseous phase and the at least one liquid phase of the multi-phase mixture from the measurement tube. In other embodiments, the calibration vessel is filled in a reverse order. The acts of (ii) irradiating and (iii) acquiring are performed for both the at least one liquid phase and the at least one gaseous phase. The method may be used for a gas condensate flow.
In some embodiments, the calibration vessel is not filled separately with the different phases. Instead, the calibration vessel is filled with the multi-phase mixture from the measurement tube whereupon stratification of the multi-phase mixture takes place. In the stratification, the at least one liquid phase and the at least one gaseous phase are separated in the vessel. The acts of (ii) irradiating and (iii) acquiring are performed after the stratification. The method may be used for a multi-phase mixture flow emanating from an oil well (e.g., that may include oil, water, and gas).
In some embodiments, the at least one liquid phase is separated into different kinds of liquids (e.g., oil and water) during stratification, and calibration data are acquired for each kind of liquid.
In some embodiments, the multi-phase mixture is a gas condensate, wherein the ratio of stable and unstable condensates at atmospheric pressure is determined by the data acquisition part.
An exemplary flow meter that may be used at oil wells or gas wells to determine the composition of a multi-phase mixture flow emanating from the well is described. The flow meter may be installed in oil pipelines or gas pipelines to analyze the flow therein. In addition to determining the composition of the multi-phase flow, the flow meter described below may optionally also be used to determine the flow velocity based on the method described in document WO 2011/005133 A1. However, in some embodiments, the flow meter includes only the function of measuring the composition of the multi-phase mixture flow.
In some embodiments, as shown in
The calculation of the composition of the multi-phase mixture flow uses the absorption coefficients for the gaseous phase and the liquid phase (in some embodiments, separate coefficients for the oil phase, the water phase, and the gas phase or phases). The coefficients are calibration parameters pre-determined in a calibration process. Conventionally, the flow meter is calibrated manually (e.g., a sample is taken from the multi-phase mixture flow and analyzed in a separate process). This manual calibration is time-consuming and involves a person visiting the well or the pipeline to take a sample. By contrast, the flow meter shown in
To perform automatic calibration, the flow meter shown in
To calibrate the flow meter, the calibration vessel 4 is filled via the valve system with multi-phase mixture from the measurement tube 1. Upon filling, gravitational stratification takes place thus separating the different phases and the mixture. In other embodiments, the calibration vessel is separately filled with the liquid phases and gaseous phases from the multi-phase flow as further described below. The calibration vessel is then irradiated by the X-ray source 2 with the two levels of energy. The corresponding intensity of the photons passing through the calibration vessel 4 is measured by the detector 3. As the detector 3 is a matrix detector having a spatial resolution, the different phases may be distinguished due to the different absorption behaviors. Eventually, the absorption coefficients for the different phases are determined. These absorption coefficients are used as calibration data for the measurements of the multi-phase mixture flow in the measurement tube.
As indicated by the arrow P in
The choice of the cross-sectional shape of the measurement tube is based on the criteria that the tube withstands high pressure (e.g., optimally a circular cross-section) and that the path variance for different X-ray beams passing through the measurement tube to the detector be minimal (e.g., optimally a square cross-section). Based on these criteria, an elliptic-like cross-section may be used for the shape of the measurement tube 1. For example, the shape of the measurement tube 1 has the form of an elongated hole that includes two flat sections and two circular sections. As shown in
As described above, both the measurement tube 1 and the calibration vessel 4 may be made of the same or similar material and have identical forms. Furthermore, the temperature of the calibration vessel 4 may be close to the temperature of the measurement tube 1. To fulfill these criteria, a good thermal contact is provided via the contacting flat surfaces of the tube 1 and the vessel 4. Furthermore, to insulate the tube 1 and the vessel 4 from the environment, a thermal insulation 11 (not shown in
In addition to the conduit 10 and the valve 1010, other conduits and valves are shown in
As shown by
In some embodiments, the arrangement of the measurement tube 1 with respect to the X-ray source 2 and the detector 301 corresponds to the arrangement of the calibration vessel 4 with respect to the X-ray source 2 and the detector 302. Furthermore, in some embodiments, the material and the size of the vessel 4 and the tube 1 are the same and the same type of detectors 301 and 302 are used. The multi-phase mixtures in the vessel and the tube are in the same thermal condition. As a result, the absorption coefficients calculated by the data acquisition part 6 may be used directly by the analyzer 5 without any conversion calculations. Hence, facile calibration of the flow meter is achieved, and the calibration data quality is improved.
Two operation modes of the flow meter are now described in reference to
In a first operation mode, a gas condensate flow emanating from a gas well is calibrated. In a gas condensate flow, 90% to 95% by volume of the mixture is gas. To perform calibration of the gaseous phase, the valve 801 of the flow meter is opened, while all of the other valves are closed, such that the calibration vessel is filled with gas mixture. In this condition, the calibration data for the pure gas phase may be acquired using the X-ray source 2 and the detector 3.
The liquid phase of the gas condensate is collected by opening the valves 801 and 701 while all other valves are closed, such that the calibration vessel 4 is filled with the liquid phase. This process may take some time since the fraction of liquid in the gas condensate is rather low by comparison to other multi-phase mixtures. After the collection of the liquid phase, calibration data for this phase are acquired via the X-ray detector 2 and the detector 3.
Optionally, an additional measurement may be performed during calibration. For the optional additional measurement, the valve 6 is opened while all of the other valves are closed, such that atmospheric pressure will settle down in the calibration vessel. As a result, non-stable condensate will evaporate whereas stable fractions will stay in the calibration vessel. The ratio between stable and unstable condensates may be determined via measurement of the liquid level in the calibration vessel (e.g., due to the spatial resolution ability of the matrix detector 302) by comparing the levels in the vessel before and after opening the valve 1010.
Purging of the calibration vessel may be performed. During purging, all valves except the valves 801 and 901 are closed. Since the pressure in the restricted flow area 101 is reduced, the content of the calibration vessel will be blown down into the measurement tube. Thus, the calibration vessel is again filled with the gas fraction of the multi-phase mixture from the measurement tube and the acts described above may be repeated.
In a second operational mode, the calibration procedure is performed for a multi-phase flow emanating from an oil well. Such a multi-phase flow contains water, gas, and oil phases. In this second operational mode, the valve 701 and the valve 901 are opened. As a result, the multi-phase mixture will flow through the calibration vessel. The duration of this act is determined such that the multi-phase mixture in the calibration vessel 4 will be completely exchanged by the mixture from the measurement tube. Since the calibration vessel 4 is being filled from the top and the valve 901 is located at the bottom, the gas content of the mixture will be higher in the calibration vessel as compared to the actual flow in the measurement tube.
Stratification of the mixture in the calibration vessel may be performed. During stratification, only valve 801 is opened. Due to gravitational stratification, segregation of the mixture takes place because of the different densities of oil, water, and gas. The duration of this act may be long enough to allow for complete segregation of the mixture. As a result, the calibration vessel content is distributed such that the vessel contains water at the bottom, oil in the middle, and gas at the top.
Data acquisition takes place with the X-ray source 2 and the detector 3. Since oil, water, and gas have different X-ray absorptions, the different phases may be distinguished by the matrix detector 302. Hence, calibration data in the form of absorption coefficients may be obtained for the oil, water, and gas phases.
While the present invention has been described above by reference to various embodiments, it should be understood that many changes and modifications may be made to the described embodiments. It is therefore intended that the foregoing description be regarded as illustrative rather than limiting, and that it be understood that all equivalents and/or combinations of embodiments are intended to be included in this description.
It is to be understood that the elements and features recited in the appended claims may be combined in different ways to produce new claims that likewise fall within the scope of the present invention. Thus, whereas the dependent claims appended below depend from only a single independent or dependent claim, it is to be understood that these dependent claims may, alternatively, be made to depend in the alternative from any preceding claim—whether independent or dependent—and that such new combinations are to be understood as forming a part of the present specification.
This application is the National Stage of International Application No. PCT/RU2011/000716, filed Sep. 20, 2011, the entire contents of which are hereby incorporated herein by reference.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/RU2011/000716 | 9/20/2011 | WO | 00 | 8/20/2014 |
