Abstract:
An apparatus is utilized for obtaining flow measurements from an individual oil and gas well. The apparatus utilizes pipe segments rather than vessels to separate the fluid components into a gas phase, a water phase, and an oil phase. Separation of the flow stream into the different phases allows the measurement of a particular phase. Because the oil stream may continue to contain a small amount of water, a water cut meter may be employed to determine the water content in the oil stream. The apparatus may be configured as a skid package to facilitate transportation and installation of the unit.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
       [0001]    U.S. Provisional Application No. 60/778,698 for this invention was filed on Mar. 2, 2006 for which these inventors claim domestic priority. 
     
    
     BACKGROUND OF THE INVENTION 
       [0002]    The present invention generally relates to devices and methods for flow measurement. In particular, a method for continuous multiphase flow measurement is disclosed, as well as the apparatus utilized in the method. In this invention, phase separation and measurement are accomplished utilizing a compact piping arrangement as compared to the measurement vessels utilized in conventional measurement systems. 
         [0003]    Industry utilizes or has proposed several methods to measure the production of individual oil wells. The conventional approach is to use a three-phase or two-phase separator to separate the multi-phase fluid mixture into distinctive phases. In the case where a three-phase separator is employed, three separate outgoing streams are produced. These streams comprise gas, water, and oil (which may include water or comprise an oil/water emulsion). Separate flow meters measure the respective flow rates of the outgoing streams of oil, water, and gas. An on-line “cut” meter may be utilized to determine the water content of the oil stream. The two-phase separator operates similarly to the three-phase separator except that the free water stream is omitted. 
         [0004]    These test separators are relatively large in physical size, expensive to construct, and require an abundance of ancillary pressure control and flow regulating equipment. Accordingly, it is rarely practical to utilize this approach for production testing an individual oil well. Instead, the practice is to utilize a single test separator to production test a group of wells. Each individual well is production tested for a relatively short period of time, and its production is determined. After the well is removed from test, it is assumed that the production from the well does not vary substantially until the well is again placed on test. Depending upon the number of wells serviced by the test separator, individual wells may be tested for a relatively short duration on a limited basis. This characteristic of multiple-well test systems may result in questionable well test results, and delay the detection of a problem with a particular well. 
         [0005]    U.S. Pat. No. 5,390,547 (Liu) teaches a multiphase flow measurement method and apparatus using a piping arrangement which may be utilized for testing an individual well. Liu describes a technique for measuring flow rates for a multiphase fluid flow for continuously and respectively measuring the quantities of one gas and one or two liquid components flowing concurrently in a common pipeline. In Liu, the mixture delivered by a feed pipeline is separated into two separate streams of gas and liquid by a piping configuration, as opposed to conventional separators. The system then measures the flow rate in each stream individually. If there are multiple liquid components in the liquid phase, an on-line liquid fraction meter determines the proportion of each liquid component. The piping system then combines the two flow streams to a common discharge pipeline. Thus, Liu provides a technique to determine respective flow rates in a multiphase fluid flow system that is continuous and accurate using an apparatus, which is compact, low cost, reliable, and requires little maintenance. This technique has been effective in the measurement of oil and gas from individual wells. 
         [0006]    The invention disclosed by Liu utilizes a two phase measurement technique, in that the incoming multiphase flow stream (i.e., natural gas, crude oil, and produced water) are separated into two separate streams, namely a gas phase and a liquid phase. The gas phase predominantly comprises natural gas. The liquid phase predominantly comprises a mixture of crude oil and produced water, but no further separation of the liquid phase occurs. Instead, a “water cut meter” is used to determine the water content in the liquid stream. The respective volumes of net oil and produced water are ascertained by applying the water cut measurement to the total liquid flow rate. 
         [0007]    However, as the water cut in the liquid stream increases, the net oil measurement loses accuracy because the net oil measurement resolution sharply decreases when the water cut of the production stream increases. An increase in water cut is common for mature, depleting water drive hydrocarbon reservoirs. 
       SUMMARY OF THE INVENTION 
       [0008]    The presently disclosed apparatus provides an apparatus for separating and measuring the components of a multiple component fluid stream, specifically where the fluid stream comprises oil, gas, water, and related constituents. For purposes of this specification, and the claims to follow, the terms “oil phase” and “oil stream” are collectively defined to include the following compositions: (1) oil containing a small percentage of water (generally ten percent or less); and/or (2) oil/water emulsions. 
         [0009]    The disclosed compact apparatus separates the liquid stream into a water stream and an oil stream, such that the flow rates of the water stream and oil stream may be measured separately. Because the oil stream may continue to contain a small amount of water, a conventional water cut meter may be employed to determine the water content in the oil stream. 
         [0010]    The disclosed apparatus does not require the vessels or tanks generally utilized for separation of the fluid components as generally utilized. Instead, the separation of the fluid components occurs in piping segments. These piping segments, referred to herein as “separators” because of the component separation which occurs therein, are fabricated from pipe. A first piping segment is configured into a vertical separator for separating the free gas phase from the liquid phase. The free gas flows into a gas line at the upper portion of the vertical separator. The gas phase is thereafter measured and subsequently discharged back into the production flow line. 
         [0011]    The liquid phase is discharged from the lower portion of the vertical separator into a liquid line, which comprises a plurality of piping segments, including a generally horizontal section, a first generally vertical chamber, and a second generally vertical chamber respectively arranged in series. The first vertical chamber, referred to as the water chamber, primarily collects and discharges a water phase through a first actuated control valve into a discharge line. The second vertical chamber, referred to as the oil chamber, primarily collects and discharges an oil phase through a second actuated control valve into the discharge line. A weir plate divides the water chamber and the oil chamber. An interface detection device is disposed adjacent to the water chamber, upstream of the weir plate. The oil chamber comprises a high liquid level switch and a low liquid level switch. The discharge line comprises flow measurement means. 
         [0012]    The first actuated control valve is normally open. When the level of the oil phase reaches the high liquid level switch, the first actuated control valve on the water chamber closes and the second actuated control valve on the oil chamber opens. When the level of the oil phase reaches the low liquid level switch, the second actuated control valve on the oil chamber closes and the first actuated control valve opens. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0013]      FIG. 1  shows a perspective front view of an embodiment of the disclosed apparatus. 
           [0014]      FIG. 2  shows a perspective rear view of the embodiment of the apparatus shown in  FIG. 1 . 
           [0015]      FIG. 3  is a simplified diagram of an embodiment of the disclosed apparatus. 
       
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
       [0016]    Referring now specifically to the drawings,  FIG. 1  shows an embodiment  10  of the disclosed multiphase measurement apparatus which has been configured into a skid package. The skid configuration facilitates transporting and installing the apparatus for production testing an individual well. 
         [0017]    This embodiment  10  generally includes a plurality of “separators” which have been fabricated from segments of commercial grade pipe and fittings suitable for oil and gas service, including suitability for corrosive service if required by the particular application. These separators comprise a vertical separator  12  and a liquid line  14  which comprises a generally horizontal section  16 , a first generally vertical chamber, referred to hereafter as the water chamber  18 , and a second generally vertical chamber, referred to hereafter as the oil chamber  20 . While various pipe sizes might be employed for fabrication of the different components of the invention, it has been found that vertical separator  12  is preferably fabricated from pipe having a diameter ranging from six inches to thirty-six inches, but may be sized as large as forty-eight inches. The components of liquid line  14  are similarly fabricated from pipe. Horizontal section  16  is preferably fabricated from pipe having a diameter of six inches to thirty-six inches, but may be sized as large as forty-eight inches. Water chamber  18  and oil chamber  20  may be fabricated from pipe having a diameter of six inches to forty-eight inches, but will preferably have the same diameters as horizontal section  16 . It is to be appreciated that the diameters of the various components of vertical separator  12  and liquid line  14  may comprise a variety of combinations, which will depend on the desired flow rates and the chemical and physical properties of the various fluid phases. 
         [0018]    The production line from the well to be tested is connected to inlet pipe  22  of vertical separator  12 . As described in greater detail in U.S. Pat. No. 5,526,684, inlet pipe  22  may be mounted downwardly and tangentially connected between the top end and bottom end of vertical separator  12  to initiate a vortex separation mechanism of the fluid entering the vertical separator. Free gas in the vertical separator  12  flows into a gas line  24  at the upper portion of the vertical separator. Backpressure on vertical separator  12  may be maintained by actuated control valve  26 , which may be actuated by pneumatic, electrical, or hydraulic means known in the art. Controlling the actuation of the actuated control valve  26  may be implemented by processing means, such as a programmable controller, computer, or work station. The gas phase may be measured by gas flow meter  102  and subsequently commingled with liquids discharged from the water chamber  18  and the oil chamber  20  into the outlet piping  28  of the apparatus  10 . Gas flow meter  102  may be an orifice meter, turbine meter, vortex shedding meter, ultrasonic meter or other comparable device, depending upon the specific service requirements. A differential pressure transmitter  105  may provide a signal to the processing means. 
         [0019]    The liquid phase of the vertical separator  12 , comprising an oil phase and a water phase, is discharged from the lower portion of the separator into liquid line  14 . As discussed above, the term “oil phase” is defined to include oil containing a small percentage of water or an oil/water emulsion. Liquid line  14  comprises a plurality of piping segments, which include, in respective serial placement, a generally horizontal section  16 , the water chamber  18  and the oil chamber  20 . Liquid line  14  further comprises a vent line  25  which allows the flow of gas from the liquid line to the gas line  24 . 
         [0020]    Depending upon the fluid properties, flow rate and the diameter of generally horizontal section  16 , gravity separation of the oil phase and water phase will take place to some degree within the generally horizontal section  16 , such that upon reaching water chamber  18 , there will some degree of phase separation between the oil phase and water phase. Because the oil phase will typically have a lower density than the water phase, the oil phase will normally rise to the upper portion of the horizontal section  16  and the water phase will flow to the lower portion of the horizontal section. However, it is to be appreciated that some crude oils have densities higher than that of water, in which case the relative elevational positions of the oil phase and water phase as described herein would be reversed. A level indicating device, such as level gauge  107  may be utilized to provide the fluid level within horizontal section  16 . 
         [0021]    Water chamber  18  discharges the water phase through an actuated control valve  30 . The water phase may be measured by a liquid flow meter  104 . Acceptable liquid flow meters include coriolis, turbine meter, or positive displacement meters. The water phase is routed to the outlet piping  28  of the apparatus  10 , where the water phase is commingled with the gas phase from vertical separator  12  and discharged from the apparatus. 
         [0022]    As shown in  FIG. 3 , a weir plate  32  is installed in the liquid line  14  between the water chamber  18  and the oil chamber  20 . An interface detection device  106  has a probe installed in the piping above or adjacent to water chamber  18 , upstream of weir plate  32 . The interface detection device  106  typically uses relative capacitance measurements or guided wave radar to detect the level of the interface between the heavier liquid component, typically the water phase, and the lighter liquid component, typically the oil phase. The interface detection device  106  includes a transmitter which transmits a signal to processing means, such as a programmable controller. The oil chamber  20  collects the oil phase which flows over weir plate  32 . Oil chamber  18  discharges the oil phase through an actuated control valve  34 . The oil phase may be measured by liquid flow meter  104 . Because the oil phase will likely include a small percentage of water, the apparatus may comprise means for ascertaining the amount of water in the oil phase, such as a water cut meter  108 . Suitable water cut meters may be of the capacitance-type, such as those manufactured by Hydril, Drexelbrook, Halliburton, MSIP, Robertshaw, etc. Alternatively, microwave-type water cut meters may be utilized, such as those manufactured by Phase Dynamics, Agar, Roxar, etc. Other types of water cut meter  108  may also be employed, such as those which are based upon radio frequency energy absorption and density differential principles. 
         [0023]    As shown in  FIG. 3 , oil chamber  20  comprises a low fluid level detection device  110  and a high fluid level detection device  112  which are disposed in a vertically stacked arrangement The low level detection device  110  and high fluid level detection device  112 , typically configured as switches, transmit a signal which causes the actuation of actuated control valve  30  (referred to herein as the “first actuated control valve”) and actuated control valve  34  (the “second actuated control valve”). The first actuated control valve  30  is normally open. When the level of the oil phase reaches the high fluid level detection device  112 , the first actuated control valve  30  on the water chamber closes and the second actuated control valve  34  opens. When the level of the oil phase reaches the low level detection device, the second actuated control valve  34  closes and the first actuated control valve  30  opens. The first actuated control valve  30  and the second actuated control valve  34  may be operated by processing means based upon input provided by, among other possible devices, the interface detection device  106 , the low level detection device  110  and the high fluid level detection device  112 . The interaction of these devices may be utilized to maintain the oil phase/water phase interface at some distance below the top of the weir plate  32 , but above the bottom of the generally horizontal section  16 , allowing the oil phase to spill over the weir plate and accumulate in the oil chamber  20 . 
         [0024]    As shown in the figures, the apparatus may include a variety of additional piping, fittings and valves, as well as having additional instrumentation and controls. 
         [0025]    As shown in  FIG. 1  and  FIG. 2 , the apparatus may be assembled as a self-contained skid unit to facilitate transportation and installation of the invention. As indicated in the figures, the skid may be configured with various structural steel members, including longitudinal beams  40 , vertical beams  42 , and transverse beams  44  to provide sufficient strength for the skid to be placed by crane lifting, which is facilitated by eye plates  46 . As also shown in the figures, the beam members provide convenient anchors for the various piping components. The self-contained skid may also include all controls and displays required by the unit, including a display panel  48  and programmable controller  50 . The flanged fittings are provided within the self-contained skid to facilitate connecting the unit between an oil well and the existing production facilities. 
         [0026]    While the above is a description of various embodiments of the present invention, further modifications may be employed without departing from the spirit and scope of the present invention. For example, the size, shape, and/or material of the various components may be changed as desired. Thus the scope of the invention should not be limited by the specific structures disclosed. Instead the true scope of the invention should be determined by the following claims.