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Abstract The paper describes the challenges and uncertainties associated with the accurate flow measurement of gas, oil and water and also the results of a trial test conducted using four multiphase flow meters in wet gas-condensate producers at a wide range of flowing conditions. The measurement of these three phases is very critical for the reservoir monitoring and production diagnostics and obtaining the accurate three-phase data poses a significant challenge for the majority of conventional multiphase flow meters, because of the high-gas volume fraction (95 % and above) nature of the wells. Multiphase flow meter technology has been successfully used around the world for over 15 years in oil and gas fields with a very low cost comparing with three-phase test separator use. This success encourages all the manufacturers to continue developing meters; to satisfy and meet the production test requirements and the acceptance criteria established by the operator companies. At the end of 2010, Saudi Aramco conducted a second pilot test to evaluate the four wet gas and multiphase flow meters (WGMPFMs) from various leading manufacturers. The objective of this test was to confirm the accuracy and reliability of these meters for measuring gas, condensate and water flow rates in the wet gas stream. A high pressure test separator was the reference measurement and the test was repeated at several selected gas wells. After almost 4 months, the testing concluded that only a particular type of meter performed better than others and met the minimum Saudi Aramco acceptance criteria in measuring the three-phase flow with acceptable accuracy. This paper also describes the Saudi Aramco’s experience of field testing the latest WGMPFM’s meters in real production condition, field test methodology, equipment setup and result analysis.
Multiphase and wet gas flowmeters (MFMs) are becoming drastically cheaper, allowing the capability to be used by most of the oil and gas companies today. If the CAPEX can be reduced, the main question about the reliability and the capability of such equipment to provide accurate data and to perform correctly compared to previous technology (usually a separation-based system) remains. The unrealistic specification of multiphase manufacturers made in the past led to suspicion of such products by oil and gas companies. Additionally, the reluctance of using MFMs could be due to a number of technologies that require significant effort to have a proper understanding of the device.
The buying process very often leads to some form of comparison test made either before delivery (usually tested in a third-party facility), or later in the field regularly or spot check against standard equipment (separators, tanks or any other trending devices). This fair initiative to understand the real performance usually leads to more questions about what/how/where/when to compare and are also incredibly important. Last but not least, what should define the "PASS/FAIL" criteria? It should also be noted that limited test envelopes (flow conditions) may not reflect the entire performance of the meter. Therefore, either additional measurements or statistic elements should be used to establish the actual statement or meter performance.
It is incredible to see, today, in the billions of dollar oil and gas business that most of the systems are reporting flow rates without any information about the measurement uncertainty, this leads to the belief that the production is entirely known. Unfortunately, people working in allocation are the first to face this challenge and to reconcile the data. On the other hand, the top-class MPFMs are providing uncertainty on measurement, which is as good as, if not better than, some of the standard equipment that is used and so the uncertainty of both devices needs to be thoroughly taken into account in these comparisons to make allocation fair and indisputable.
The paper will embrace these comparison tests, the author has repeatedly faced such cases over the years and wishes to bring to light the relevant work that needs to be done before, during, and after the tests to make it conclusive. We expect to provide some practical statements which will progress and help all parties involved in these comparison tests where the presence of a third party (being impartial and independent) can ensure there is no bias in the overall statement.
Abstract Over the last two decades, multiphase flow measurement (MPFM) has become accepted by the Oil & Gas industry worldwide. Nevertheless, the operators are in a pressing need to assess the measurement performances of each MPFM technology. Generally, this is performed through field trials of one or several MPFM technologies against typically a conventional test separator. In this paper, we will describe an accelerated new and cost effective methodology to evaluate the metrological performance of a multiphase flow meter in specialized facilities with live hydrocarbons mimicking the real field conditions. In this methodology, multiphase flow loops are used to reproduce real field conditions with live hydrocarbons fluids where pressure is the key parameter when attempting to mimic real multiphase flow in such controlled environment. Associated with proper test procedure design, these facilities have offered a framework to evaluate multiphase flow meters using live Hydrocarbons under comprehensive conditions in terms of flow regimes, flow rates, phase fractions distributions, salinity, pressure and temperature, ensuring good stability and very high level of accuracy in the reference measurement. The paper guides the reader through the technical considerations required to identify the flow loop test conditions and requirements and set standard procedures from an operator point of view to perform a successful performance evaluation. It also provides case studies where the performance benchmarking obtained in the flow loop has been confirmed and verified in real field conditions. Using a live hydrocarbon multiphase flow loop for evaluating and quantifying metrological performance specifications for multiphase flow meters has shown to be a very powerful and cost effective tool when associated with proper testing procedure design. This new approach also provides results that are translated to an expected and verifiable performance for real field applications with all their associated complexities. This paper provides a new testing methodology for any multiphase flow measurement technology where the conventional ways of testing may fail; it also provides valuable insight to multiphase flow meter performance measurement evaluation and specifications definition from an oil operator point of view.
Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 3-6 November 2008. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Flow metering using conventional separation-based technologies in low-pressure high gas rate environments typical of gaslifted wells is a very difficult operation. Owing to low retention times of the gas, the quality of separation and existing instrumentation is often doubtful leading to an underestimate of liquid rates. An aggravating factor is that such wells are often producing at high water-cuts, thus leading to significant uncertainty on oil rates. A compact dual-energy gamma-ray Venturi multiphase flow meter (MPFM) was selected and placed under field trial to assess whether this technology could reduce the uncertainty on oil production by removing any impact of imperfect separation. Furthermore, the high-frequency high-resolution output of the meter allowed the operator to assess well efficiency and stability and to understand the behavior of the gas lift system. The field test proves that the multiphase metering solution used in this trial can be used successfully and is presenting a reliable alternative or complement to conventional test separators for flow metering in low-pressure high water cut wells under gas lift, providing operational flexibility and additional information of interest to optimize well productivity. At that time, the reserves to be produced were estimated at 194 MMstbo, the field having an expected life span of 15 to 20 years.
Abstract Traditionally, 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 well-specific 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 Introduction Back allocation is a daily must of the upstream and downstream petroleum industry. The need for back allocation rises from the unavailability of permanent "fiscal" quality measurement of oil, gas and water produced and injected or disposed volumes at all entry / exit points in the distribution system. The distribution of the flow according to the various contributors is a challenge, as not only one has to deal with partial information on most of the streams (non continuous / periodic monitoring, lack of data, lost information etc.), but also has to tackle the difficult problem of varying uncertainties for the various measurements. In some cases, no direct measurement of flow is available (this is usually the case for in-well allocation), and one has to rely on reservoir / productivity parameters such as PI (productivity index) and choke performance. The back allocation process can be a contentious because of potential tax implications, custody transfer discussions and poor back allocation results and reserve management practices that have long term financial impact on projects. The main challenge of well measurement process has been the cost of performing "fiscal" type measurement of oil, gas and water flowrates / volumes at or near wellheads. Such challenges are made all the more apparent in the recent unmanned development, both on-shore and offshore. The challenge of finding cost effective solutions for subsea marginal field development, has also bought to light problems related to back allocation. These issues can partially drive deep-sea development strategies. The introduction of new measurement techniques such as multiphase flowmetering was intended initially at replacing the traditional test separator with smaller, more cost effective solution, geared at reaching a uncertainty on flowrates of +/− 10% of gas and liquids (Falcone). There have been many research and engineering efforts to drive the multiphase metering technology towards the "fiscal" type of accuracies (in the order of +/− 0.25% to +/− 0.5% uncertainty for oil, and +/− 0.5 to +/− 1.0% gas and water). Although the present state of the technology does not provide such level of uncertainties, better understanding of the well testing process and production process of wells has allowed significant improvement of back allocation factors in many application. These improvements have been achieved not only through the direct application of multiphase metering technologies but also through the improvement of traditional well testing means.