For over 20 years, sonic logging has implied compressional velocity logging using first break detection from two-receiver tools. Today, sonic logging techniques can utilize more of the information contained in the acoustic waveform to provide shear- and Stoneley-wave velocity and attenuation measurements. This requires signal-processing techniques for full-waveform analysis. These techniques generally need more spatial samples of the wavefield than are provided by standard two-receiver tools. To fulfill this need, a new multireceiver sonic tool has been designed. In this paper, we describe a new sonic array tool which has an array of eight receivers spaced 6 in. apart, located 8 ft from the nearer of two transmitters. In addition to array capabilities, standard short- and long-spaced sonic logs are available. A special section has been incorporated to give a mud-velocity measurement. The downhole electronics provide digitized waveform acquisitions with an effective resolution capability of 11 bits. To extract the additional answers from the full waveform, slowness-time coherence (STC) processing has been developed. Based on semblance processing has been developed. Based on semblance techniques, STC identifies coherent arrivals across the array. Examples of waveforms and processed logs from both open and cased wells are presented to illustrate the tool's capabilities. Introduction After more than 20 years of compressional-wave logging, the field of acoustic well logging is moving toward a more complete analysis of the full sonic waveform. This trend is being driven by the use of other wave components to probe rock properties and mechanical characteristics. Shear-wave logging, for example, can be effectively used in lithology and fluid identification, porosity determination, rock elastic and inelastic properties measurement, and in shear seismics. Stoneley waves can be used to determine shear-wave propagation characteristics in soft, unconsolidated propagation characteristics in soft, unconsolidated formations where converted shear waves are often absent from the borehole. Achieving this requires both digitizing the full acoustic waveform and applying modern signal-processing techniques. This paper describes a tool and processing technique that addresses both requirements. Digitizing capabilities are placed downhole so that more than one received wave form can be simultaneously digitized free of cable-induced distortion. Instead of the standard two receivers, a linear array of several receivers is used to provide more spatial samples of the propagating provide more spatial samples of the propagating wavefield. This allows a much better picture of the composite wave and its propagation characteristics. These additional data make possible the use of more sophisticated array-processing techniques that give unambiguous, more highly resolved estimates of the various wave component slownesses. In the sections that follow, the tool hardware and logging capabilities are described along with the signal processing. Examples of logs made in open and cased wells illustrate the tool's utility.

Multiphase flow meters (MPFM) are finding increasing acceptance offshore, where operators are achieving some level of comfort after several years of familiarization with the technology. Meters are being applied in well testing, well management, and allocation of production. Since first deliveries of the Framo meter in 1993, significant experience has been gained in both topside and subsea application of the devices. For topside applications, the principal advantage of the meter remains the elimination of the test separator and all its associated hardware and maintenance. For subsea applications, the advantage is even greater, viz, the elimination of the platform. Combining the Framo fluid mixer and Venturi with a multiple-energy gamma ray absorption composition measurement provides the optimum in precise estimation of gas, oil, and water flow rates, while at the same time solving many of the operational problems which plague alternative methods. Operational experience with Framo multiphase meters installed around the World, both topside and subsea, will be reviewed. Special attention will be paid to the difficult issues peculiar to subsea meters, such as their remote installation, retrieval, calibration, and maintenance. Finally, future trends in multiphase metering will be explored. One of the most significant of these will be the migration of this methodology into areas of application where today it is not economically feasible. What must be done to apply multiphase metering in more routine applications, such as in onshore fields? The answer, as with any other standard oilfield measurement, lies in the evolution of the technology from an experimental domain on one of routine usage. This and other future directions in this discipline will be addressed. Purpose of Multiphase Flow Measurement Before considering in detail the descriptions and experiences of multiphase meters, it is useful to list the reasons why a producer might want to use them. Elimination of Test Separator, Manifold and/or Flow Line. This is ordinarily the single most important reason for choosing to use a multiphase meter (Fig. 1). Not only are test separators and their associated metering equipment expensive, but their bulk requires additional platform space in offshore topside installations. In the case of satellite fields, running a test line back to a test separator on a platform is also a non-negligible expense. Continuous or Near-Continuous Monitoring. With a meter on each producing well, as shown in Fig. 1b, the measurement of production will be complete and continuous - obviously a very desirable condition. Even if only a single meter is used downstream of the manifold, as shown in Fig. 1c, the frequency of testing is considerably greater than with conventional test system of Fig. 1a. In addition, whereas a conventional testing system might take hours to become stable for measurement, the system in Fig. 1c could yield good test results minutes after a well is switched in. Reduction of Maintenance. Because well-designed multiphase meters must be virtually maintenance-free if they are to be used subsea or on unmanned platforms, their application will significantly reduce operational expenditures (OPEX) over conventional test separation systems. Numerous other advantages of multiphase measurement could be listed, but what is shown above should be sufficient to convince any potential user that they deserve consideration. Having crossed this threshold, whether through one's own experience or that of others, it is apparent that if one chooses to use a multiphase meter, then a test separator is no longer needed - having both "belt and braces" is not required. Unfortunately there are those in the industry who would suggest otherwise. P. 345^

During the last decade there has been an effort to develop new measurement capabilities for ultradeepwater oil and gas production. Beginning in 2005 and continuing through 2011, R&D was conducted on what were perceived to be the most important gaps in deepwater measurement technology.The work was initially sponsored by the DeepStar consortium. Beginning at the end of 2008 a larger effort -Improvements to Deepwater Subsea Measurement -was initiated under the Research Partnership to Secure Energy for America (RPSEA). Key to its success was the active support of a JIP sponsored by seven deepwater operating companies: BHP, BP, Chevron, Conoco Phillips, Shell, Statoil, and Total. In 2012 RPSEA approved a Phase 2 effort to extend the results that had been achieved in the first project.The new project -More Improvements to Deepwater Subsea Measurement -has addressed these five gaps, viewed as the most pressing for multiphase flow measurement by the new JIP (Chevron, Conoco Phillips, GE, Statoil, and Total):• Deepwater Fluid Sampling • Deepwater Metering Technology • Downhole Differential Pressure Sensor Development • Virtual Flow Meter Evaluation • Detection of Meter Fouling These technology developments are significant due to the increasing global importance of subsea production. Improved recovery from deepwater reservoirs could yield millions of barrels of additional reserves, but to achieve this goal requires better, more reliable measurement at the sea floor. Equally important is insuring that royalty assessment and production allocation are precise and equitable.However, a notable application for these new measurement technologies is in the areas of safety and the environment. It should be clear that better, more extensive measurement can be pivotal in preventing the loss of well control and the kinds of events that may ensue. Certain aspects of this new measurement project take dead aim at this goal, as will be explained.The paper and presentation will provide a look at progress that is being achieved in addressing each of the five gaps listed above.

Since the beginning of the last decade efforts have been underway to develop new measurement technologies for ultra-deepwater oil and gas production. Though initial R&D activities were carried out by individual companies, after a few years interested parties began to pool their efforts. The first such endeavor was a project sponsored by the DeepStar consortium, Improved Multiphase Metering for Subsea Tiebacks, performed in 2006 and 2007. Beginning at the end of 2008 a larger effort – Improvements to Deepwater Subsea Measurement – was initiated by the U.S. Department of Energy's National Energy Technology Laboratory under the Research Partnership to Secure Energy for America (RPSEA). RPSEA was a product of the U.S. Energy Policy Act of 2005, and was aimed at encouraging technology development in oilfield exploration and production, of which ultra-deepwater was a major element. Key to the project's success was the active support of a JIP sponsored by seven deepwater operating companies: BHP, BP, Chevron, ConocoPhillips, Shell, Statoil, and Total. After the first project was completed in 2011, RPSEA approved a Phase 2 effort to extend the results that had been achieved in the first project. The new project – More Improvements to Deepwater Subsea Measurement – has addressed those gaps that were viewed as the most pressing for multiphase flow measurement by the new JIP (Chevron, ConocoPhillips, GE, Statoil, and Total): Deepwater Fluid SamplingDeepwater Meter Verification TechnologyEarly Kick DetectionDownhole Differential Pressure Sensor DevelopmentVirtual Flow Meter EvaluationDetection of Meter Fouling These technology developments are significant due to the increasing global importance of subsea production. Improved recovery from deepwater reservoirs could yield millions of barrels of additional reserves, but to achieve this goal requires better, more reliable measurement at the sea floor. Equally important is insuring that royalty assessment and production allocation are precise and equitable. However, a noteworthy application for these new measurement technologies is in the areas of drilling operations. Better, more extensive measurement can be pivotal in preventing the loss of well control. Certain aspects of this new measurement project aim at this goal, as will be explained in the companion papers and presentations to this one. This paper and presentation will provide an overview of these areas of development, with details of the achievements in each of the target areas described in the six papers/presentations that follow.

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