Patent Application
20110112773
This disclosure relates in general to multiphase flow measurement for oil-gas wells and, but not by way of limitation, to accurate measurement of various phases.
Most oil wells ultimately produce both oil and gas from the formation, and often produce water. Consequently, multiphase flow is common in oil wells. Surface monitoring of oil and gas producing wells is tending towards metering multiphase flows with a wide range of gas volume flow fraction (GVF).
There are existing approaches to metering multiphase flows which include separation and mixing approaches. The separation approach provides for splitting the flow into an almost liquid flow plus an almost gas flow flowing in separate conduits and then separately metering the separated flows using single-phase flow meters. The mixing approach attempts to minimize the slip between the different phases so that the velocity and holdup measurements can be simplified.
There are flow meters that measure flow rates in pipes that are intrusive into the flow. By intruding into the flow, the flow can be impeded and sensors can be fouled. Retrofitting pipes with a flow meter is problematic after it is operational. On occasion, the production of hydrocarbons is interrupted in this process.
Methods that are used to measure flow rate in a liquid phase of the multiphase flow make certain presumptions in analyzing the data to arrive at a flow rate. For example, a height of the gas-liquid interface or the speed of sound in the liquid phase might be estimated such that calculations can proceed. By not having accurate information on various parameters a certain amount of error is introduced to these flow rate determinations.
Embodiments of the present invention provide for measuring flow properties of multiphase mixtures within a pipe carrying hydrocarbons. Embodiments of the present invention use differential pressure measurements of multiphase mixtures flowing in phase-separated flow regimes to analyze characteristics of a liquid phase of the multiphase mixture. The phase-separated flow regimes may be provided by flowing the multiphase mixture in a substantially horizontal pipeline or swirling the multiphase mixture. The combination of differential measurements with measurements from other sensors, such as ultrasonic sensors, microwave sensors, densitometers and/or the like may provide for multiphase flow measurements, such as flow rates of the different phases or determination of the speed of sound.
In one embodiment, the present disclosure provides a method for measuring flow properties of a multiphase mixture flowing in a pipe of stratified flow. The method includes flowing the multiphase mixture through the pipe in a phase separated flow regime, wherein the phase separated flow regime separates a liquid phase of the multiphase mixture and a gas phase of the multiphase mixture; measuring a differential pressure across a diameter of the pipe; and using a density of the gas phase, a density of the liquid phase and the measured differential pressure to determine a liquid layer thickness of the liquid phase of the multiphase mixture flowing in the pipe.
In another embodiment, the present disclosure provides a system for measuring flow properties of a multiphase mixture flowing in a pipe of stratified flow. The system includes an ultrasonic transducer, a differential pressure sensor and a processor. The ultrasonic transducer is configure to operatively engage the pipe without intruding into the stratified flow and measure velocity in the pipe. The differential pressure sensor is configured to operatively engage with the pipe at two points and measure flow a difference in pressure between the two points. The processor is configured to determine a height of a gas-liquid interface within the pipe using the differential pressure and calculate liquid flow within the pipe using the velocity and the height.
In yet another embodiment, the present disclosure provides a method for measuring flow properties of a multiphase mixture including hydrocarbons flowing in a pipe of stratified flow is disclosed. In one step, a differential pressure between two points of the pipe is sampled. A height of a gas-liquid interface within the pipe is determined using the differential pressure. A gas velocity and/or a liquid velocity of the stratified flow is measured without intruding into the stratified flow. A liquid flow within the pipe is calculated using the gas velocity and/or the liquid velocity and the height.
Further areas of applicability of the present disclosure will become apparent from the detailed description provided hereinafter. It should be understood that the detailed description and specific examples, while indicating various embodiments, are intended for purposes of illustration only and are not intended to necessarily limit the scope of the disclosure.
The present disclosure is described in conjunction with the appended figures:
In the appended figures, similar components and/or features may have the same reference label. Further, various components of the same type may be distinguished by following the reference label by a dash and a second label that distinguishes among the similar components. If only the first reference label is used in the specification, the description is applicable to any one of the similar components having the same first reference label irrespective of the second reference label.
The ensuing description provides preferred exemplary embodiment(s) only, and is not intended to limit the scope, applicability or configuration of the disclosure. Rather, the ensuing description of the preferred exemplary embodiment(s) will provide those skilled in the art with an enabling description for implementing a preferred exemplary embodiment. It being understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope as set forth in the appended claims.
Multi-phase flow is commonly produced during hydrocarbon production. The liquid phase can include hydrocarbons, water and/or various contaminants. Some methods rely on one or more ultrasonic transducers that transmit pulses into the liquid phase to determine a height of a gas-liquid interface based upon time-of-flight measurements. Doppler can be used be used to determine the direction and velocity of flow. These measurements use a value for the speed of sound, but some methods estimate a typical value for the speed of sound even though it varies with the make-up of the liquid phase.
In one aspect, pressure sensing is used to find a difference in pressure within the pipeline. The pressure is affected by the make-up of the multiphase flow. The difference in pressure between the bottom and top of the pipeline is used in determining a height of the gas-liquid interface. Essentially, the pressure differential allows weighing the multi-phase flow. Presuming or measuring densities for the gas and liquid flows allows for estimation of the height of the gas-liquid interface.
As described in this application, measurement of flow properties of multiphase mixtures has been of significant importance, especially in the hydrocarbon industries for many years. In this time, many methods and systems have been developed for and considerable time and expense has been put into to development of measuring the flow properties of the phases of a multiphase mixture. In this application, methods and systems are described in which the flow regime of the multiphase mixture flow is controlled, by developing a horizontal stratified flow or developing a swirling stratified flow in a pipe and using a differential pressure sensor to interrogate the flow and, among other things, determine flow properties of the liquid phase, such as liquid phase thickness. This surprising development may lead to the manufacture of lower cost and/or more accurate multiphase flow meters.
In one embodiment of the present invention, the ultrasonic pulsed Doppler transducers are arranged in a Doppler array around the circumference of the pipeline to measure the gas-liquid flow. Additionally, the Doppler array can be used to estimate the water/liquid hydrocarbon ratio (WLR) measurement in some embodiments.
The slip velocity between the liquid and gas phases for a horizontal flow is very different from that for a vertical flow with the same gas volume flow fraction (GVF) value. Normally, the slip in the horizontal case is much larger. This means that even with the same GVF, the liquid holdup in the horizontal case is normally much larger than that in the vertical case. As a result, the flow regime map for horizontal flows is very different from that for vertical flows.
Applicants have determined that liquid holdup is typically 15 times of liquid cut for GVF>0.95 and the liquid flow rate<3 m3/hr. This means that if the liquid flow rate is 1% of the total flow rate, then the liquid holdup is 15%. Therefore, the gravity separation helps to create a liquid-rich region towards the lower part of a horizontal pipe, and a gas-rich region above it. Knowing the phase distribution in such flows, Applicants submit that various velocity and holdup measurements may be optimized for the different phase regions.
Gas velocity may be measured by using a gas flowmeter, e.g. an ultrasonic gas flowmeter, which may be installed around the appropriate height of the pipe bore to ensure measurement of the gas-only/gas-rich zone. The liquid flow velocity and liquid holdup may be measured by an array of ultrasonic Doppler transducers mounted around the circumference of the pipe. The WLR in the liquid-phase may be further characterized using at least one pair of electromagnetic microwave transmitter and receiver, whose transmission path is mostly covered by the liquid-rich region towards the bottom of the pipe. The flowmeter may be built around a section of straight pipeline and may use non-intrusive sensors, and, therefore, provide no disturbance to the flow.
In one embodiment of the present invention, an ultrasonic clamp-on transit-time gas flowmeter and a range-gated ultrasonic Doppler transducer may be used for the measurement of gas and liquid flow velocities of stratified gas-liquid flow in a horizontal or near horizontal production pipeline. The ultrasonic Doppler transducer may be installed at the pipe underside to measure the flow velocity and thickness (hence volume fraction) of the dominant liquid layer. The liquid-layer thickness may be estimated from a time delay measurement where the range-gated Doppler energy is at a maximum. The gas and liquid flow rates may then be determined from the above gas-liquid velocities and liquid fraction measurements, without intruding into the production flows within the pipeline.
In certain aspects, transit-time (gas) and Doppler (liquid) flow velocity and holdup measurements may also be used to derive the prevalent flow-regime information (from flow-regime maps), hence facilitating the use of a more flow-regime specific correlation of gas-liquid velocity slip for an alternative determination of gas-liquid flow rates. An estimation of the speed of sound in the liquid phase allows the ultrasonic measurements to be more accurate.
In stratified flow regimes, a clamp-on ultrasonic gas flow meter may be used with a pulsed Doppler sensor(s) and/or a microwave EM sensor(s) to measure flow characteristics of a multiphase (gas-liquid) mixture flowing in a pipeline. For such measurements to be accurate and robust, it may be desirable to measure a thickness of the liquid portion of the stratified flow of the gas-liquid as accurately as possible. As such, embodiments of the present invention provide for an independent measure of the liquid layer thickness using a differential pressure measurement that can be used in combination with other ultrasonic measurements. Embodiments of the present invention may be used for flow regimes that are either stratified, such as may be found in near horizontal flows and/or a flow regime comprising a liquid annulus and gas core, such as may be created by inducing a swirling-type of flow in the gas-liquid.
Ultrasonic measurements of flowing liquid layers with velocity, v and thickness h, give for an ultrasonic beam perpendicular to the flow direction:
where t=measured delay time, cliquid=liquid sound velocity
Doppler: v(depth=T*cliquid)∝ Doppler frequency shift*Cliquid where T=gate time
Time of flight: v=v(cliquid,h,t)
Combinations of ultrasonic measurements can give the liquid film velocity, liquid sound velocity and liquid layer thickness. However the interdependency of these parameters makes accurate measurements difficult when presumptions are used as input to the above equations; for example, the speed of sound in the liquid layer. This invention describes an independent measure of the liquid layer thickness using a differential pressure measurement that can be used in combination with various ultrasonic measures. The flow regime is either stratified or a liquid annulus and gas core created by swirling the fluid.
The concept comprises measuring the differential pressure across the diameter of a horizontal pipe in which there is stratified gas-liquid flow or a liquid annulus and gas core induced by swirling the flow. A priori measurements or estimations of the gas and liquid densities allows determination of the liquid layer thickness. Some embodiments could measure the density of the gas and liquid phases with a sensor or make periodic measurements.
An advantage of measuring the differential pressure perpendicular to the flow velocity, as provided in some embodiments of the present invention, is that there is little or no frictional pressure drop to be taken into account in this embodiment.
The differential pressure, ΔP, measured across the diameter, D, of a horizontal pipe is:
ΔP=g(h(ρliquid−ρgas)+Dρgas)
ΔP=g(2h(ρliquid−ρgas)+Dρgas)
The diameter can be measured or may be known for standard pipe sizes. Some embodiments could use the ultrasonic transducer(s) to automatically determine the diameter.
Given the liquid and gas densities, the liquid layer thickness can be determined from the above equations. Merely by way of example, densities of the gas and liquid phases may be automatically determined from radiation count measurements, Venturi type measurements, microwave measurements and/or the like in various embodiments.
If the water-liquid ratio is not known, then an estimate of the liquid density may be provided when WLR=0.5. Other embodiments could use a determined value for the WLR using EM microwave devices, for example.
The uncertainty in the thickness measurement for an uncertainty in the differential pressure measurement is:
At 10 mbar span the Honeywell STD110 differential pressure sensor has an accuracy of ±0.01 mbar; this results in an accuracy of ˜0.07 mm for h if used for these types of measurements. Other embodiments could use other differential pressure sensors.
Referring first to
The ultrasonic pulsed Doppler transducer 120 is range-gated in this embodiment. The Doppler transducer 120 could operate at 1 MHz, for example, to measure flow velocity of the dominant liquid layer. This embodiment clamps the ultrasonic pulsed Doppler transducer 120 on the pipe underside to measure the flow velocity of the dominant liquid layer flowing at the pipe bottom. Additionally, the liquid level or height of the liquid-gas interface can also be determined by the ultrasonic pulsed Doppler transducer 120. The internal cross-sectional area of the pipe can be measured from an ultrasonic pipe-wall thickness gauge, or estimated with readings from the ultrasonic pulsed Doppler transducer 120. The internal cross-sectional area is used with the flow rate measurement to determine the volume of liquid, hydrocarbon and/or gas passing through the pipeline.
The differential pressure sensor 116 attaches to the pipe at two points to measure the difference in pressure between those two points. In this embodiment, one end of the pressure sensor is coupled to the bottom of the horizontally configured pipeline and the other sensor is coupled to the top of the pipeline. The difference in pressure generally corresponds to the weight of the contents within the pipeline. Presuming or measuring densities of the phases, the height of the liquid-gas interface can be determined. Other embodiments could use several pairs of pressure measurements differentially to gather more data points for pressure difference in the pipeline.
A processor 110 is configured with a state machine and/or software to automatically determine certain parameters from the gathered information. Additionally, the various sensors and transducers are driven and read with the processor 110. Gas, liquid and hydrocarbon flow and volume can be determined by the processor 110. Any input or output of the multiphase flow measurement system 100 passes through an interface port 114. Some embodiments could include a display that shows the determined results and measurements, but this embodiment just relays that information out the interface port 114 to a data logging device.
With reference to
When there is only a film of liquid within the pipe adjacent to a Doppler transducer 120 the reflection is considerably different from the circumstance were the Doppler transducer 120 is adjacent to the liquid phase. The returned Doppler energy level is higher when the Doppler transducer 120 is adjacent to the liquid phase. By noting which Doppler transducers 120 appear to be adjacent to a film rather than the liquid phase, the liquid-gas interface can be further estimated in this embodiment. Further, other ultrasonic transducer readings can be improved by using the Doppler array 122.
With reference to
Referring next to
With reference to
A top chamber 308-1 and a bottom chamber 308-2 are each pressure coupled to the interior of the pipeline 204. The chambers 308 are aligned on a vertical diameter to engage the pipeline 204 near the top and bottom. By attaching a tube to each chamber 308 the pressure can be coupled to the differential pressure sensor 116. Each chamber 308 is separated from the contents of the pipeline with a diaphragm 304 suitable as a barrier to keep contamination out of the chamber 308. The chamber and accompanying tube may be filled with an inert gas or a isolation fluid.
Although not shown, some embodiments can increase or decrease an inner diameter of the pipeline 204. Decreasing the inner diameter increases the flow rate, and increasing the inner diameter decreases the flow rate. Various embodiments can add a section with an increased or decreased diameter near the chambers 308.
Referring next to
With reference to
Referring next to
With reference to
Referring next to
With reference to
The ultrasonic pulsed Doppler transducer(s) 120 can optionally measure the flow of the liquid phase 240 in block 512. Additionally, the ultrasonic pulsed Doppler transducer(s) 120 can optionally measure the height of the gas-liquid interface 230 using reflections, the estimated speed of sound and/or by noticing which transducers 120 in a Doppler array 122 appear to not be submerged. Additionally, the WLR can be optionally determined by an analysis of readings from the ultrasonic pulsed Doppler transducer(s) 120.
The Doppler transducer(s) 120 allow confirmation of stratified flow in block 516. Where a separated flow regime cannot be confirmed, processing goes to block 518 where the error is noted and reported. Other measurements may be taken where there is not a separated flow regime. Where separated flows are determined in block 516, processing goes to block 520.
EM microwave elements could be optionally used in block 520 for an estimate of WLR. In block 524, a gas flowmeter can optionally measure the velocity of the gas phase 250. In step 528, the differential pressure between the chambers 308 is measured by the differential pressure sensor 116. The density of the gas and/or liquid phases can be measured with dosimeters in block 532. Other embodiments could use experimentation, prior knowledge and modeling to find densities of the gas and liquid phases.
The processor 110 in block 536 determines the height of the gas-liquid interface 230 using the differential pressure, the density of the gas layer, and/or the density of the liquid layer. In block 540, the flow rate, speed of sound in the liquid phase and other parameters can be further determined. Determined information may be relayed to other systems through the interface port 114 and/or displayed.
A number of variations and modifications of the disclosed embodiments can also be used. For example, the various flowmeters, arrays, transducers, sensors, transmitters, and receivers can be combined in various ways for a given multiphase flow measurement system. Additionally, the number of sensors, probes and transducers can be different in various embodiments. For example, several differential pressure sensors could be used to more accurately weigh the flow. Above embodiments are discussed in the context of hydrocarbon transport, but the invention need not be limited to hydrocarbons.
While the principles of the disclosure have been described above in connection with specific apparatuses and methods, it is to be clearly understood that this description is made only by way of example and not as limitation on the scope of the disclosure.
This application claims the benefit of and is a non-provisional of co-pending U.S. Provisional Application Ser. No. 60/973,373 filed on Sep. 18, 2007, which is hereby expressly incorporated by reference in its entirety for all purposes. This application is related to U.S. application Ser. No. ______, filed on a date even herewith, entitled “MULTIPHASE FLOW MEASUREMENT” (temporarily referenced by Attorney Docket No. 57.0754 US NP), the disclosure of which is incorporated herein by reference for all purposes. This application expressly incorporates by reference U.S. Pat. No. 6,758,100, filed on Jun. 4, 2001 and U.S. patent application Ser. No. 12/048,831, filed on Mar. 14, 2008; in their entirety for all purposes.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/GB2008/003138 | 9/17/2008 | WO | 00 | 1/19/2011 |
| Number | Date | Country | |
|---|---|---|---|
| 60973373 | Sep 2007 | US |
