Wet gas metering covers a variety of measurements in production streams with high to very high gas volume fractions. There is a need for direct measurement of gas under these conditions in such applications as gas condensate and high GOR fields as well as many production operations where gas from separation systems may contain liquid. More gas will be produced in the future from remote and subsea fields where production, capital investment, and operating costs must be optimized. For example, real time measurement of gas and liquid flow rate are critical in a subsea production system which will improve well allocation, optimize reservoir production, and enhance flow assurance. A number of wet gas metering strategies and systems have been developed to address these needs. This paper reviews the principle of operations of commercially available systems, and evaluates their strength and limitations in various applications. Available data from test loops, pilot and field installations are used to assess the performance and accuracy of these wet gas systems. The field installations are used to identify the types of applications as well as the application trends that have utilized these systems. The paper also assesses the potential benefits from the deployment of a wet gas metering system. The technologies employed in the current systems impose performance and accuracy as well as operational limitations. These limitations are outlined and evaluated in terms of operator expectations and requirements. The analysis is used to outline a list of issues that an operator has to consider in selecting and justifying a system for wet gas measurements in an asset development. New developments that are ongoing or must be undertaken to address the limitations of the current wet gas metering systems are also reviewed. The implications of these developments to extend the future applications of wet gas metering systems are discussed. Introduction More gas will be produced in the future from remote and subsea fields where production, capital investment, and operating costs must be optimized. As an example, gas production from deep waters in the GOM (1) has increased in the last 5 years as shown in Fig. 1. Real time measurement of gas and liquid flow rate are critical in a subsea production system to improve well allocation, optimize reservoir production, and enhance flow assurance. In many of the deepwater reservoirs, the economics developments dictate that several fields be commingled together and processed at a central facility. In such cases, it is critical to be able to measure the produced gas at the wellhead in order to be able to allocate the oil and gas assets to partners in each reservoir (2). These trends have provided much support to the development of more robust and accurate wet metering systems. Wet gas metering covers a wide range of measurements, which is necessitated by the specific applications and the definition of "wet gas". The definition of wet gas can vary depending on whether one is looking at the fluids from the perspectives of reservoir engineering, measurement systems, or commercial sales of the products (3). The lack of a common definition is partly to be blamed for some confusion and misunderstanding when facility engineers, operators and vendors have to communicate across these perspectives. In the following section an attempt is made to establish an acceptable definition, which could be used through the rest of this paper to facilitate our discussion of the wet gas metering systems.
In many mature fields production well testing is limited by the availability of test separator. Prior industry attempts to utilize the new technology of multiphase metering to fill this gap has been hampered by the cost of multiphase meters. This paper describes the development and field tests of a low cost portable multiphase meter. The meter utilizes the Coriolis flow meter technology combined with a microwave based water cut meter that can measure WC in the 0-100% range. The combination of these techniques provides a light weight metering package that can be mounted on trailer for portable well testing. This multiphase meter can measure oil, water and gas without separation of the production stream at low GOR. These applications can be found in mature fields with low GOR and in heavy oil fields.The multiphase meter was subjected to field qualification tests prior to deployment in a West Texas field. The paper describes the results from the qualification tests and the performance history during the 18 months of deployment in the field. Well test data from the multiphase meter is compared to conventional test separator and grab samples. Comparison between the test separator and the multiphase meter shows average liquid flow deviation of about ±7%. The water cut was measured within 1-2 points of the water cut from the test separator.
The application of Multiphase Meters (MPM) over the past decade or so has, in the main, been in deployment of meters in small quantities (i.e. ones and twos) and there are few applications where MPM's have been deployed in bulk. Petrozuata in Venezuela is such an operation where 37 MPM's were deployed and have been in use for over 5 years. This paper describes the facility and the operations where MPM's have been selected, tested and implemented. The paper also describes the difficulties experienced and the operational results from the extensive use of such measurement techniques. Introduction Petrozuata is a joint venture Strategic Association owned by ConocoPhillips (50.1 percent) and Petróleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela (49.9 percent). The project is a fully integrated crude oil processing and petroleum business, located in the state of Anzoátegui, Venezuela. It began commercial operations on April 12, 2001, however Extra Heavy Crude Oil (EHCO) began flowing in mid 1998. Petrozuata's primary function is to produce EHCO from the Zuata region of the Orinoco Oil Belt; transport it to the Jose industrial complex on the north coast of Venezuela; upgrade it into 19 to 26.5 degree API synthetic crude; and market it along with 14 degree API gas oil and associated by products e.g. LPG, sulfur and petroleum coke. The Petrozuata "project" is now an operational oil producing business with over 5 years production experience. The Strategic Association has a 35-year operating life and will require the drilling of more than 750 wells with an estimated recovery of approximately 1.6 billion barrels of Extra Heavy Crude Oil (EHCO) during this period. This facility uses the ConocoPhillips' proprietary coking technology to upgrade heavy crude oil into lighter synthetic crude and has a nameplate capacity of 120,000 barrels per day (BOPD). At present, Petrozuata produces more than 125,000 BOPD of EHCO. The synthetic crude oil produced by Petrozuata is used as a feedstock for ConocoPhillips' Lake Charles, Louisiana, refinery and the Cardón refinery in Venezuela, operated by PDVSA. Since 1997, Petrozuata has drilled more than 260 wells (at present there are 195 active producers) in an area of 56,000 acres of the Zuata region with the expectancy of drilling a further 490 wells over the next 30 years in order to drain the reservoir. Wells are clustered around 37 production pads as shown in Figure 1. Conceptual engineering for the Petrozuata project was carried out in the early 1990's, and a substantial body of engineering was put forward for the use of multiphase technology for both pumping and measurement. Initial engineering required steam flood of the reservoir; however, this was later changed such that production is now based on the use of cold horizontal wells in unconsolidated sands with the extensive use of single and multi-laterals (1). Production is moved around the field via 11 off 2000 hp multi-phase pumps (MPP), with the EHCO diluted with naphtha. Within the field, the production is metered and allocated using 37 multi-phase meters (MPM), one located at each production pad as shown in Figure 2. The diluted crude is processed (degassed and dewatered) at a central processing facility, after which, it is fiscally metered and pumped to the upgrader via a 125 mile 36 inch pipeline.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractTraditionally, well allocation and fiscal allocation have been performed on the basis of test separator information. The technology breakthrough of multiphase flowmeters brings new solutions to allocation solutions. These new flow rate measurements have demonstrated some unexpected well behavior. These dynamic effects (instability, slugs) have shed light on the origin of some back-allocation factor issues experienced in some fields. The paper discusses actual causes for large back-allocation discrepancies and provides examples of challenges to standard test separator. This paper also presents the decision strategies related to the implementation of multiphase flowmeters to determine allocation issues. The paper discusses the impact of uncertainties of multiphase flowmeters on the overall fiscal allocation and provides recommendations on installation methodologies and screening processes to make best use of the dynamics of these new measurements.The understanding of the different needs for well test information and allocations is illustrated and the impact to the allocation factors is shown. The distinction between wellspecific tests and diagnostic information from pad/manifold fiscal allocation is important to the hardware selection process and to the back-allocation issues. The impact of the frequency of the measurement is also quantified. The paper concludes with a series of recommendations to improve back-allocation factors on existing installations
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAccurate well testing is required for making intelligent decisions on oil and gas production wells. This paper reports on an effort to assess the application of multiphase metering technology to high water-cut (75+% water) and high volume production wells, as found in many North American Mid-Continent brown fields. A portable multiphase oil, water and gas production well tester was designed and field tested for these wells. Key components of the trailer mounted and battery operated tester are: a compact gas-liquid cylindrical cyclonic (GLCC) separator with control valves, GLCC bypass valving, coriolis liquid meter, infrared water-cut meter, vortex shedding gas meter and a data acquisition unit. One key finding is that separation is not needed in many such applications, thereby significantly reducing the size, weight and cost of future testers. This is due to the inherent downhole well separation and annulus venting used in most such well configurations along with specific coriolis/water-cut meter combinations allowing accurate measurements with gas content up to 10 to 20% GVF.
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