This work presents the development of a data reduction algorithm for non-nulling, multihole pressure probes in compressible, subsonic flowfields. The algorithm is able to reduce data from any 5- or 7-hole probe and generate very accurate predictions of the velocity magnitude and direction, total and static pressures, Mach and Reynolds number and fluid properties like the density and viscosity. The algorithm utilizes a database of calibration data and a local least-squares interpolation technique. It has been tested on four novel miniature 7-hole probes that have been calibrated at NASA Langley Flow Modeling and Control Branch for the entire subsonic regime. Each of the probes had a conical tip with diameter of 1.65 mm. Excellent prediction capabilities are demonstrated with maximum errors in angle prediction less than 0.6 degrees and maximum errors in velocity prediction less than 1 percent, both with 99 percent confidence.

For any production optimisation system to function effectively it must reliably receive quality data on demand. Over the past decade the reservoir monitoring industry has been addressing the issue of reliability including implimentation of a step-change technology - Passive Optical Sensing Systems. Since the first installation of an in-well optical pressure gauge over 10 years ago, the industry has built a substantial track record with over 85 installations of P&T gauges and hundreds of DTS installations - acceptance is growing! Initially Optical Sensing systems were expensive, complicated to install, and could only support limited applications. Today, they are on a par with electronic gauges with respect to performance, cost and installation simplicity. The state- of-the-art in optical sensing technology includes Bragg-grating based Pressure and Temperature sensors, permanent Distributed Temperature Sensing (DTS), Single- and Multiphase Flowmeters, and Seismic sensors. This paper describes the operation of each of the sensing systems mentioned above, the data/information provided, together with details of application case histories. These range from simple single-gauge installations to complex wells with integrated pressure sensing, flow measurements and remotely activated zonal flow control - true Smart or Intelligent Wells. The future direction includes even more complex intelligent completions and subsea deployments. Also high accuracy distributed array temperature sensing, optical distributed pressure sensing, sand detection, and distributed strain (e.g. for riser monitoring), are just a few of the new generation of sensing systems that are described in the paper. As subsea continues to play an important role in our industry, the presentation (not included in this paper) will also include a synopsis from the SPE ATW "In-well Optical Sensing - Subsea Well Applications - Are We Ready"? held February 7th and 8th, 2006 in Galveston. Introduction To manage and optimize well production, operators need in-well monitoring systems that deliver high-performance measurements throughout the life of the well, and reliability without the need for routine maintenance or intervention. In the 1980's, the initial applications for optical sensing were focused on the military and areospace industries. The requirements that drove early development of optical sensing systems were not readily available in comparable electrical systems. These requirements included:Small physical size, allowing simple integration into small locations and embedding in composite structural systems.Multiple sensing point and measurement types on a single fiber, replacing multiple electrical sensors, instrument types and associated electrical wiring. This reduced system complexity and weight is critical in aerospace systems.Silica with high temperature fiber coatings, enabling the development of sensing systems for applications with operating temperatures in excess of 1,000°C.High reliability, maintained by having simple sensing elements at the measurement point and the sensor's instrument in a readily accessible location for servicing or repair.Immunity to interference from local radio or electrical transmission sources.No spark hazard, reducing the risk of fire. Also optical communication systems significantly improve signal performance, data density and transmission distance. These requirements also fit the needs of oil and gas in-well monitoring applications. Subsequently the first in-well optical Pressure and Temperature gauge was installed in a producing land well in the Netherlands in 1993. This initial system operated successfully for a period of more than 5 years. And so began the journey to broader acceptance of the technology in our industry. Through significant investment by service companies and operators in the development of sensor systems, a wider range of commercial optical sensing products and services has been brought to the oil and gas market.

This paper deals with the aerodynamic and performance behavior of a three-stage high pressure research turbine with 3-D curved blades at its design and off-design operating points. The research turbine configuration incorporates six rows beginning with a stator row. Interstage aerodynamic measurements were performed at three stations, namely downstream of the first rotor row, the second stator row, and the second rotor row. Interstage radial and circumferential traversing presented a detailed flow picture of the middle stage. Performance measurements were carried out within a rotational speed range of 75% to 116% of the design speed. The experimental investigations have been carried out on the recently established multi-stage turbine research facility at the Turbomachinery Performance and Flow Research Laboratory, TPFL, of the Texas A&M University.

Innovative technology and measurement methods along with intelligent production optimization processes are important enablers with regards to intelligent fields and real-time reservoir management. Downhole multiphase flow measurement technologies play a major role in monitoring and optimizing well performance especially wells equipped with advanced well completions such as downhole inflow control devices (ICD) or inflow control valves (ICV).This paper builds on a pilot installation and comprehensive assessment of the world's first installation of downhole multiphase flowmeters and optical pressure and temperature sensors in a maximum reservoir contact (MRC) well in Saudi Arabia. One of the major findings from the initial study was that while the optical flowmeter operated successfully at most downhole choke valve settings, it was unable to make sensible readings at specific settings due to excessive acoustic noise. The results from the assessment were instrumental in improving the design of the flowmeter to tolerate higher acoustic noise levels. The initial appraisal and acceptance of this completion technology was closed by having the improved flowmeter manufactured and successfully flow tested under various laboratory conditions. The lessons learned from this experience have provided insights into downhole multiphase flowmeter sensing technologies, its capabilities and limitations. Furthermore, it demonstrates how open collaboration between operator and equipment manufacturer can yield reliable and fit for purpose equipment, a model that can be used to improve other technologies pertaining to intelligent fields and real-time reservoir management.

The adoption rate of optical sensing technology for in-well permanent monitoring has accelerated dramatically since first introduced more than 10 years ago and a number of optical sensor types, including pressure, temperature, distributed temperature, seismic, and flowmeters have been commercialized. Although optical sensing technology has a demonstrated track record and gained industry acceptance, large-scale, field-wide commercial deployment has been slow. This paper describes a recent example of field-wide optical sensing deployment with a planned scope of 27 wells. Multiple in-well sensors were installed in the newly developed Buzzard Field, operated by Nexen Petroleum U.K. Limited in the North Sea. This paper explores the initial results after the first 13 well completions. An assessment of the major project phases from definition, planning, and system selection to project execution, site integration testing, installation, and early life operation of the optical technology is included. A number of lessons in equipment and system design, execution, and data management have been learned and are also discussed in the paper. Whilst field development is ongoing, the initial success rates show that satisfactory performance has been obtained in all key areas including data availability, delivery, and post-processing. This case study demonstrates that innovative optical sensing technology and downhole flow measurement is ready for large-scale adoption with minimal risk. This is an important and timely finding as the industry is introducing optical monitoring into large subsea fields. Acknowledgements The authors gratefully acknowledge Nexen Petroleum U.K. Limited and Weatherford Intl. as well as the Buzzard Field partners PetroCanada Energy North Sea, BG Group, and Edinburgh Oil & Gas Limited, for permission to publish this work. They would also like to acknowledge the efforts of coworkers in Nexen Petroleum U.K. Limited and Weatherford Intl. in the planning, installation, commissioning, and performance evaluation stages. This paper has been jointly prepared by Nexen Petroleum U.K. Limited and Weatherford Intl. for presentation at the SPE Intelligent Energy Conference Amsterdam, 25–27 February 2008. Neither the authors nor their employers shall be liable for any reliance on its contents. Background Since the introduction of fiber-optic based reservoir monitoring systems in 1993 the adoption rate has increased dramatically. Today, most of the common electronic based technology measurements for in-well permanent reservoir monitoring have a commercially available optical equivalent, such as pressure & temperature, and seismic sensors. In fact, optical monitoring has not only equaled but added further functionality to the previously available monitoring toolset through Distributed Temperature Sensing (DTS) and non-intrusive single- and multiphase flowmeters. Currently, the only area that the optical sensing has not penetrated into is the subsea application. Functionally, optical sensing offers a viable alternative to traditional methods of in-well permanent monitoring. However, it has not yet made significant leaps in volume deployment in comparison with these traditional methods. In 2004, this situation changed when Nexen Petroleum U.K. Limited (formerly EnCana) and its partners PetroCanada Energy North Sea, BG Group and Edinburgh Oil and Gas, awarded the Permanent Downhole Monitoring System (PDMS) contract covering the Buzzard field. It was a technologically bold decision to go for an all optical in-well reservoir monitoring system for the Buzzard field development.