Measuring and testing – Volume or rate of flow – Of selected fluid mixture component
Reexamination Certificate
2001-10-04
2003-12-02
Williams, Hezron (Department: 2855)
Measuring and testing
Volume or rate of flow
Of selected fluid mixture component
Reexamination Certificate
active
06655221
ABSTRACT:
FIELD OF THE INVENTION
The invention relates to a method and a system for flow measurement of a two-phase liquid/liquid or liquid/gas mixture, or a three-phase liquid/liquid/gas mixture flowing through a production or transport pipe. The method and the system shall be used for measuring the percentage composition of phases in the pipe cross section at any time, as well as the individual phase velocities. Hence, from these measurements, the method and the system provide opportunities for calculating the volumetric flow rate of each respective phase in the two-phase or three-phase mixture. Additionally, knowing the mass densities of the individual phases, it is also possible to calculate the mass flow rates of the phases. The method and the system are in particular directed to applications within oil and gas production industry, where phases in a two-phase mixture may typically be hydrocarbons in liquid form, like crude oil or condensate, and hydrocarbons in gas form—natural gas, or crude oil/condensate and produced or injected water. The phases in a three-phase mixture may typically be crude oil/condensate, water and natural gas.
BACKGROUND OF THE INVENTION
During production of oil and gas, it is desirable to carry out flow measurement, in the form of mass flow rate or volume flow rate, of a pipe flow consisting of a two-phase or three-phase combination of oil/water/gas, so called multiphase measurement, This can be done using permanently installed measurement systems, e.g. on a marine production platform or on a land-based production plant. Such measurement systems are little by little replacing conventional measurement methods comprising bulky test separators complete with single-phase flow meters like turbine meters and measurement orifices measuring individual phases after separation thereof. It is important to measure the quantity produced from a reservoir to be able to control and regulate the production process in an effective manner. This enables optimum total production over the lifetime of a field, it is also desirable to measure the production from single wells individually, since a change in one individual well, for instance a sudden increase in the water production, is difficult to detect by measuring the collective production from several wells. Often, fiscal elements are also involved, wherein it is an important point to allocate the production from individual wells to the rightful owners, where the production from such wells is processed in a common processing plant with a different owner structure than the wells. It would also be desirable to be able to measure produced oil with an accuracy that is sufficient for buying and selling, but so far this is not realistic when using multiphase meters.
Many of the recent oil finds are located in small reservoirs at relatively large water depths, and in such cases it is often not possible to defend conventional development solutions, like for instance today's marine production platforms. In order to extract these marginal resources, large efforts have therefore been made to develop underwater systems. These systems comprise both wellhead control, manifold systems and, gradually, separators, and one can see contours of complete processing plants located on the sea floor. In this connection, a need has also come up for measuring the production flow down at the sea floor, and therefore, multiphase meters are about to be installed for such applications.
It has also become of interest to be able to measure flow rates continuously downhole, and development work is presently going on regarding such instrumentation. Today's well measurements are often carried out on a temporary basis, for instance as production logging where measurement systems are introduced down into the well by means of wireline or coil piping. This is expensive, and provides to a large degree qualitative measurements. Relatively long time may also pass between execution of such measurements, so that there is a risk of regulating the wells in accordance with old data, even if the production may have changed in the meantime. Besides, lately the complexity of the oil wells has increased strongly, due to new and more advanced methods within drilling and completion technology, and production from layered reservoirs, multibranch and horizontal wells have become ordinary practice, Being able to execute continuous downhole multiphase measurement on a permanent basis, will enable effective reservoir control, and in combination with e.g. valves for controlling influx from the reservoir, it is possible to achieve so-called “intelligent wells” that will result in increased oil extraction, reduced water production and eventually reduced intervention frequency. Today permanent well instrumentation consists substantially of pressure and temperature gauges, and to some degree Venturi meters for liquid rate measurements. To a certain degree, flow models are utilized that are based on measurements from pressure and temperature gauges located in different places, conservation laws for mass and moment, thermodynamic relations, physical parameters and reference measurements from logging. However, these methods depend on the “goodness” of the models, i.e. the ability to predict the individual flow rates of phases within the necessary uncertainties, and on correct assumptions regarding the physical and geometrical parameters in the well. They also require a high degree of calibrating in situ to obtain the desired precision.
When oil, water and gas flow simultaneously through a pipe, the distribution of the three phases may form a large number of different regimes or patterns, both axially and radially. Therefore, the influence of the flow on a measuring system will vary correspondingly, which becomes apparent particularly when measurements are carried out continuously over time. Generally, the flow will consist of a continuous and a discontinuous phase. Ordinarily, the liquid is the continuous phase, with free gas as the discontinuous phase. The free gas may be distributed substantially in two ways, like larger pockets, or like myriads of very small bubbles atomized in the liquid phase. In addition, some gas will often be dissolved in the oil phase, particularly under high pressures. As regards the liquid per se, it may be continuous oil with water drops distributed in the oil. This occurs often early in the lifetime of a well, when the oil usually is the dominating phase as to percentage. Moreover, this mixture is electrically insulating. In the opposite case with continuous water flow, oil drops are distributed in the water, which provides an electrically conductive liquid phase. The size of the distributed drops may vary, and the mixing mechanisms may be different, all the way from stable emulsions to more loose mixtures of the two phases. Essentially the liquid will be transported as one phase with one common velocity. Exceptions herefrom are in low flow velocities, where oil and water can be subject to complete or part separation, and when the pipe has an inclination deviating from the horizontal plane. In this case, gravity will make the heaviest component, usually the water, move with lower velocity than the oil. This difference in velocity is often termed “slip”. In a well flow it may also happen that the water has a negative velocity relative to the general flow direction. As the well pressure decreases, more free gas will be produced, and it may happen that the gas becomes the dominating flow phase. Then the liquid will often be distributed as a film flowing relatively slowly along the pipe wall, in combination with a drop phase that to a larger degree accompanies the gas. Since the mass density of the gas is usually substantially lower than the mass density of the liquid phase, there will, as a rule, always exist slip between gas and liquid. The situations described above are often divided into main groups with designations bubble flow, slug flow, chum flow, layered flow and annular flow. A measurement system should therefore be able to make measurements und
Aspelund Audun
Wideröe Tor
Flowsys AS
Thompson Jewel V.
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