Abstract

Permanent downhole pressure gauges supply important information for reservoir surveillance and management. Technology has evolved over the more than 40 years since the first installation. Service companies have made significant improvements to the components of a permanent downhole gauge installation for a well. The components include gauges, housing, cable, connections, and acquisition systems. Installation and use of these gauges has become routine in many situations because of the improved reliability and the value of information that the gauges provide.

Pressures from permanent downhole gauges can be examined almost as soon as they are acquired, depending on communication speed. The data is used for many applications including pressure monitoring, interference testing, water and gas injection monitoring, transient well testing, evaluation of well performance, reducing the flowback time of new wells, monitoring hydraulic fracturing operations, and monitoring pump inlet and outlet pressures for pumping wells.

On the practical side, there are issues associated with the data that these gauges collect. Vast amounts of data are being gathered continuously at intervals down to one second over numbers of years. This data must be communicated from the well to the office. Since the data is an asset, it must be stored and archived. Individuals require access to the data at different times, for different reasons, and at differing resolutions. Interpretation of the data poses new challenges as there is more hidden in the long term pressure record than just a collection of drawdowns and buildups. The data contains information about parameters changing during short and long time intervals both near the well and in the reservoir. As more and more permanent downhole gauges are deployed, maximizing the corporate benefits becomes an asset management issue. Companies are faced with stewardship of the investment, communicating learnings across the organization, developing or acquiring software tools for data management and analysis, proposing and supporting industry-wide standards for consistent data capture and communication, and integrating data into work processes and into applications such as smart wells and smart fields.

Introduction

The earliest mention of permanent downhole gauges in the literature was by Nestlerode(1) in 1963. With eight field cases, he described how pressure data from permanent gauges was being used. ExxonMobil's* first permanent downhole gauge was installed in 1978 in the Beryl Field area(2). The first subsea satellite wells with permanent gauge systems were completed in the UK sector of the North Sea in 1979(3). These wells used a wet connector to link the downhole cable and subsea electronics module in the tree. Gallivan et al(4) document the installation, reliability, reservoir surveillance applications, buildup analysis, and interference test results for permanent downhole gauges in the Beatrice field. Original installation of these gauges occurred from 1981 to 1982. Each well in the Beatrice field was equipped with an ESP so a power cable was already being run downhole. The instrument cable for the permanent downhole gauges was run to surface along with the power cable. Brazilian experience with bottomhole pressure gauges from 1977 to 1991 is outlined in OTC 6991(5). Along with a summary of the technical evolution of permanent downhole gauges over time, the authors published value metrics for permanent downhole pressure gauge installations in terms of increased production and reduced operating costs. Other fields with documented examples of permanent downhole gauge installations and applications include Balmoral(6), Scapa(7), Gullfaks(8), Ivanhoe, Rob Roy, and Hamish(9). The first downhole gauge was run in Balmoral and Scapa in 1985, in Gullfaks in 1987, and in Rob Roy in 1989. As with any new technology, many of the previous references cited problems in deploying the gauges and maintaining operability.

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