Listening to the Reservoir—Interpreting Data From Permanent Downhole Gauges

Abstract

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract The permanent downhole pressure gauge is a class of tool that has become popular in the industry. These tools are installed during the well completion and provide a continuous record of pressure changes during production. Permanent downhole gauges (PDGs) have potential to provide more information than is available with traditional well testing, which is carried out for a relatively short duration. PDGs may provide useful information regarding changes in reservoir properties or well conditions with time as the reservoir is produced. However, interpretation of PDG data is a new problem. Unlike the traditional well test in which "disturbances" in the reservoir (i.e., rate changes) are created and pressure and rates are both known, the changes in rates associated with the record from the PDG may not be known. Moreover, the dynamic changes in the reservoir, along with changes in the flowing temperature or changes in the gauge itself, make the data more complicated to interpret. Introduction Developing petroleum resources in an optimal manner requires making many complex decisions on the basis of expectations of future reservoir performance. Central to forecasting reservoir performance is creation and calibration of a reservoir model. These interrelated tasks generally are known as reservoir description and history matching. Most data used for history matching are in the form of surface-measured rates and cumulative volumes of production (oil, gas, and water) and injection (water and gas). However, improving both the creation of a reservoir model and its calibration to replicate measured reservoir history requires collecting measurements from the reservoir itself. In many cases, these downhole data include measurements of pressure, flow rate, and temperature as functions of time. Traditionally, such measurements were made with wireline gauges. However, during the past 20 years, the application of permanently installed gauges has become increasingly common. As of 2006, the number of permanently installed gauges is probably in excess of 10,000 worldwide [Chorneyko (2006) quotes more than 1,000 for one major oil company alone].